# UNITED	STATES

# SECURITIES	AND	EXCHANGE	COMMISSION

# (Mark	One)

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

# For	the	Fiscal	Year	Ended	December	31,	2003

# TRANSITION	REPORT	PURSUANT	TO	SECTION	13

# OR	15(d)	OF	THE	SECURITIES	EXCHANGE	ACT	OF	1934

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

# 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.

New	York	Stock	Exchange,	Inc. New	York	Stock	Exchange,	Inc.

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

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

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

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

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

# DOCUMENTS	INCORPORATED	BY	REFERENCE

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

# TABLE	OF	CONTENTS

| Definitions |  | i |
| :--- | :--- | :--- |
| Entergy's\tBusiness | Part\tI.\tItem\t1. | 1 |
| \t\t\t\tFinancial\tInformation\tfor\tU.S.\tUtility,\tNon-Utility\tNuclear,\tand\tEnergy\n\t\t\t\tCommodity\tServices |  | 2 |
| \t\t\t\tStrategy |  | 3 |
| Report\tof\tManagement |  | 4 |
| Entergy\tCorporation\tand\tSubsidiaries |  |  |
| \t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\tResults\tof\tOperations |  | 5 |
| \t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 12 |
| \t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 21 |
| \t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 33 |
| \t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 41 |
| \t\t\t\tIndependent\tAuditors'\tReport |  | 42 |
| \t\t\t\tConsolidated\tStatements\tof\tIncome\tFor\tthe\tYears\tEnded\tDecember\t31,\n\t\t\t\t\t2003,\t2002,\tand\t2001 | Part\tII.\tItem\t8. | 43 |
| \t\t\t\tConsolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\n\t\t\t\t\tDecember\t31,\t2003,\t2002,\tand\t2001 | Part\tII.\tItem\t8. | 44 |
| \t\t\t\tConsolidated\tBalance\tSheets,\tDecember\t31,\t2003\tand\t2002 | Part\tII.\tItem\t8. | 46 |
| \t\t\t\tConsolidated\tStatements\tof\tRetained\tEarnings,\tComprehensive\tIncome, | Part\tII.\tItem\t8. | 48 |
| and |  |  |
| \t\t\t\t\tPaid\tin\tCapital\tfor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand |  |  |
| 2001 |  |  |
| \t\t\t\tNotes\tto\tConsolidated\tFinancial\tStatements | Part\tII.\tItem\t8. | 49 |
| \t\tU.S.\tUtility | Part\tI.\tItem\t1. | 104 |
| \t\t\t\tCustomers |  | 104 |
| \t\t\t\tElectric\tEnergy\tSales |  | 104 |
| \t\t\t\tRetail\tRate\tRegulation |  | 106 |
| \t\t\t\tProperty\tand\tOther\tGeneration\tResources |  | 112 |
| \t\t\t\tFuel\tSupply |  | 115 |
| \t\t\t\tWholesale\tRate\tMatters |  | 118 |
| \t\t\t\tService\tCompanies |  | 126 |
| \t\t\t\tEarnings\tRatios |  | 126 |
| \t\tNon-Utility\tNuclear | Part\tI.\tItem\t1. | 127 |
| \t\t\t\tProperty |  | 127 |
| \t\t\t\tEnergy\tand\tCapacity\tSales |  | 128 |
| \t\t\t\tFuel\tSupply |  | 129 |
| \t\t\t\tOther\tBusiness\tActivities |  | 129 |
| \t\t\t\tOther\tMatters |  | 130 |
| \t\tEnergy\tCommodity\tServices | Part\tI.\tItem\t1. | 130 |
| \t\t\t\tEntergy-Koch,\tL.P. |  | 130 |
| \t\t\t\tNon-Nuclear\tWholesale\tAssets\tBusiness |  | 132 |
| \tRegulation\tof\tEntergy's\tBusiness | Part\tI.\tItem\t1. | 133 |
| \t\t\t\tPUHCA |  | 133 |
| \t\t\t\tFederal\tPower\tAct |  | 133 |
| \t\t\t\tState\tRegulation |  | 133 |
| \t\t\t\tRegulation\tof\tthe\tNuclear\tPower\tIndustry |  | 134 |
| \t\t\t\tEnvironmental\tRegulation |  | 137 |
| \t\tOther\tEnvironmental\tMatters |  | 140 |
| \t\tLitigation |  | 141 |
| \t\tResearch\tSpending |  | 146 |
| \t\tEmployees |  | 146 |
| Entergy\tArkansas,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 147 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 151 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 154 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 157 |
| \t\tIndependent\tAuditors'\tReport |  | 162 |
| \t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand | Part\tII.\tItem\t8. | 163 |

| Balance	Sheets,	December	31,	2003	and	2002 | Part	II.	Item	8. | 166 |
| :--- | :--- | :--- |
| \t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 168 |
| 2003, |  |  |
| \t\t\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 169 |
| Entergy\tGulf\tStates,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 170 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 173 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 176 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 184 |
| \t\tIndependent\tAuditors'\tReport |  | 189 |
| \t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand\n\t\t\t2001 | Part\tII.\tItem\t8. | 190 |
| \t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 191 |
| 2002, |  |  |
| \t\t\tand\t2001 |  |  |
| \t\tBalance\tSheets,\tDecember\t31,\t2003\tand\t2002 | Part\tII.\tItem\t8. | 192 |
| \t\tStatements\tof\tRetained\tEarnings\tand\tComprehensive\tIncome\tfor\tthe | Part\tII.\tItem\t8. | 194 |
| Years |  |  |
| \t\t\tEnded\tDecember\t31,\t2003,\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 195 |
| Entergy\tLouisiana,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 196 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 199 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 202 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 206 |
| \t\tIndependent\tAuditors'\tReport |  | 210 |
| \t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand\n\t\t\t2001 | Part\tII.\tItem\t8. | 211 |
| \t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 213 |
| 2002, |  |  |
| \t\t\tand\t2001 |  |  |
| \t\tBalance\tSheets,\tDecember\t31,\t2003\tand\t2002 | Part\tII.\tItem\t8. | 214 |
| \t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 216 |
| 2003, |  |  |
| \t\t\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 217 |
| Entergy\tMississippi,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 218 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 220 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 223 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 225 |
| \t\tIndependent\tAuditors'\tReport |  | 229 |
| \t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand\n\t\t\t2001 | Part\tII.\tItem\t8. | 230 |
| \t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 231 |
| 2002, |  |  |
| \t\t\tand\t2001 |  |  |
| \t\tBalance\tSheets,\tDecember\t31,\t2003\tand\t2002 | Part\tII.\tItem\t8. | 232 |
| \t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 234 |
| 2003, |  |  |
| \t\t\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 235 |
| Entergy\tNew\tOrleans,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 236 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 238 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 241 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 244 |
| \t\tIndependent\tAuditors'\tReport |  | 247 |
| \t\tStatements\tof\tOperations\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 248 |
| 2002, |  |  |
| \t\t\tand\t2001 |  |  |
| \t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 249 |

| Balance	Sheets,	December	31,	2003	and	2002 | Part	II.	Item	8. | 250 |
| :--- | :--- | :--- |
| \t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 252 |
| 2003, |  |  |
| \t\t\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 253 |
| System\tEnergy\tResources,\tInc. |  |  |
| \t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\tResults\tof\tOperations |  | 254 |
| \t\t\t\tLiquidity\tand\tCapital\tResources |  | 255 |
| \t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 257 |
| \t\t\t\tCritical\tAccounting\tEstimates |  | 258 |
| \t\tIndependent\tAuditors'\tReport |  | 262 |
| \t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003,\t2002,\tand\n\t\t\t2001 | Part\tII.\tItem\t8. | 263 |
| \t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2003, | Part\tII.\tItem\t8. | 265 |
| 2002, |  |  |
| \t\t\tand\t2001 |  |  |
| \t\tBalance\tSheets,\tDecember\t31,\t2003\tand\t2002 | Part\tII.\tItem\t8. | 266 |
| \t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 268 |
| 2003, |  |  |
| \t\t\t2002,\tand\t2001 |  |  |
| \t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 269 |
| Notes\tto\tRespective\tFinancial\tStatements\tfor\tthe\tDomestic\tUtility | Part\tII.\tItem\t8. | 270 |
| Companies |  |  |
| \tand\tSystem\tEnergy |  |  |
| Properties | Part\tI.\tItem\t2. | 332 |
| Legal\tProceedings | Part\tI.\tItem\t3. | 332 |
| Submission\tof\tMatters\tto\ta\tVote\tof\tSecurity\tHolders | Part\tI.\tItem\t4. | 332 |
| Directors\tand\tExecutive\tOfficers\tof\tEntergy\tCorporation | Part\tIII.\tItem\t10. | 332 |
| Market\tfor\tRegistrants'\tCommon\tEquity\tand\tRelated\tStockholder\tMatters | Part\tII.\tItem\t5. | 334 |
| Selected\tFinancial\tData | Part\tII.\tItem\t6. | 335 |
| Management's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand | Part\tII.\tItem\t7. | 335 |
| Results\tof |  |  |
| \tOperations |  |  |
| Quantitative\tand\tQualitative\tDisclosures\tAbout\tMarket\tRisk | Part\tII.\tItem\t7A. | 335 |
| Financial\tStatements\tand\tSupplementary\tData | Part\tII.\tItem\t8. | 336 |
| Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand | Part\tII.\tItem\t9. | 336 |
| Financial |  |  |
| \tDisclosure |  |  |
| Controls\tand\tProcedures | Part\tII.\tItem\t9A. | 336 |
| Directors\tand\tExecutive\tOfficers\tof\tthe\tRegistrants | Part\tIII.\tItem\t10. | 337 |
| Executive\tCompensation | Part\tIII.\tItem\t11. | 342 |
| Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement | Part\tIII.\tItem\t12. | 352 |
| Certain\tRelationships\tand\tRelated\tTransactions | Part\tIII.\tItem\t13. | 355 |
| Principal\tAccountant\tFees\tand\tServices | Part\tIV.\tItem\t14 | 356 |
| Exhibits,\tFinancial\tStatement\tSchedules,\tand\tReports\ton\tForm\t8-K | Part\tIV.\tItem\t15. | 359 |
| Signatures |  | 360 |
| Independent\tAuditors'\tConsents |  | 367 |
| Independent\tAuditors'\tReport\ton\tFinancial\tStatement\tSchedules |  | 368 |

# This	combined	Form	10-K	is	separately	filed	by	Entergy	Corporation,	Entergy	Arkansas,	Inc.,	Entergy	Gulf	States,	Inc.,	Entergy	Louisiana,	Inc.,

Entergy	Mississippi,	Inc.,	Entergy	New	Orleans,	Inc.,	and	System	Energy	Resources,	Inc.	Information	contained	herein	relating	to	any	individual company	is	filed	by	such	company	on	its	own	behalf.	Each	company	makes	representations	only	as	to	itself	and	makes	no	other	representations whatsoever	as	to	any	other	company.

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

# FORWARD-LOOKING	INFORMATION

From	time	to	time,	Entergy	makes	statements	concerning	its	expectations,	beliefs,	plans,	objectives,	goals,	strategies,	and	future	events	or	performance.	Such statements	are	"forward-looking	statements"	within	the	meaning	of	the	Private	Securities	Litigation	Reform	Act	of	1995.	Although	Entergy	believes	that

these	forward-looking	statements	and	the	underlying	assumptions	are	reasonable,	it	cannot	provide	assurance	that	they	will	prove	correct.	Except	to	the extent	required	by	the	federal	securities	laws,	Entergy	undertakes	no	obligation	to	publicly	update	or	revise	any	forward-looking	statements,	whether	as	a result	of	new	information,	future	events	or	otherwise.

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

resolution	of	pending	and	future	rate	cases	and	negotiations,	including	various	performance-based	rate	discussions,	and	other	regulatory decisions,	including	those	related	to	Entergy's	System	Agreement	and	utility	supply	plan

Entergy's	ability	to	reduce	its	operation	and	maintenance	costs,	particularly	at	its	Non-Utility	Nuclear	generating	facilities,	including	the uncertainty	of	negotiations	with	unions	to	agree	to	such	reductions

the	performance	of	Entergy's	generating	plants,	and	particularly	the	capacity	factors	at	its	nuclear	generating	facilities

prices	for	power	generated	by	Entergy's	unregulated	generating	facilities,	the	ability	to	extend	or	replace	the	existing	purchased	power agreements	for	those	facilities,	including	the	Non-Utility	Nuclear	plants,	and	the	prices	and	availability	of	power	Entergy	must	purchase	for	its utility	customers

Entergy's	ability	to	develop	and	execute	on	a	point	of	view	regarding	prices	of	electricity,	natural	gas,	and	other	energy-related	commodities Entergy-Koch's	profitability	in	trading	physical	and	financial	natural	gas	and	power	as	well	as	other	energy	and	weather-related	contracts changes	in	the	number	of	participants	in	the	energy	trading	market,	and	in	their	creditworthiness	and	risk	profile

changes	in	the	financial	markets,	particularly	those	affecting	the	availability	of	capital	and	Entergy's	ability	to	refinance	existing	debt	and	to fund	investments	and	acquisitions

actions	of	rating	agencies,	including	changes	in	the	ratings	of	debt	and	preferred	stock

changes	in	inflation	and	interest	rates

Entergy's	ability	to	purchase	and	sell	assets	at	attractive	prices	and	on	other	attractive	terms

changes	in	ownership	of	joint	ventures

volatility	and	changes	in	markets	for	electricity,	natural	gas,	uranium,	and	other	energy-related	commodities

changes	in	utility	regulation,	including	the	beginning	or	end	of	retail	and	wholesale	competition,	the	ability	to	recover	net	utility	assets	and	other potential	stranded	costs,	and	the	establishment	of	a	regional	transmission	organization	that	includes	Entergy's	utility	service	territory

changes	in	regulation	of	nuclear	generating	facilities	and	nuclear	materials	and	fuel,	including	possible	shutdown	of	Indian	Point	or	other nuclear	generating	facilities

resolution	of	pending	or	future	applications	for	license	extensions	of	nuclear	generating	facilities

changes	in	law	resulting	from	proposed	energy	legislation

changes	in	environmental,	tax,	and	other	laws,	including	requirements	for	reduced	emissions	of	sulfur,	nitrogen,	carbon,	mercury,	and	other substances

the	economic	climate,	and	particularly	growth	in	Entergy's	service	territory

variations	in	weather,	hurricanes,	and	other	disasters

advances	in	technology

the	potential	impacts	of	threatened	or	actual	terrorism	and	war

the	success	of	Entergy's	strategies	to	reduce	current	tax	payments

the	effects	of	litigation

changes	in	accounting	standards,	corporate	governance,	and	securities	law	requirements

Entergy's	ability	to	attract	and	retain	talented	management	and	directors.

# DEFINITIONS

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

# ENTERGY'S	BUSINESS

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

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

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

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

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

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

OPERATING	INFORMATION

|  | U.S.	Utility | Non-Utility	Nuclear | Energy	Commodity<br>Services | Entergy<br>Consolidated	(a) |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| 2003 |  |  |  |  |
| Operating\trevenues | $7,584,857 | $1,274,983 | $184,888 | $9,194,920 |
| Operating\texpenses | 6,274,830 | 1,039,614 | 224,567 | 7,710,365 |
| Other\tincome | (35,965) | 33,997 | 337,334 | 325,238 |
| Interest\tand\tother\tcharges | 419,111 | 34,460 | 15,193 | 506,326 |
| Income\ttaxes | 341,044 | 88,619 | 105,903 | 490,074 |
| Cumulative\teffect\tof\taccounting\tchange | (21,333) | 154,512 | 3,895 | 137,074 |
| Net\tincome | 492,574 | 300,799 | 180,454 | 950,467 |
| 2002 |  |  |  |  |
| Operating\trevenues | $6,773,509 | $1,200,238 | $294,670 | $8,305,035 |
| Operating\texpenses | 5,434,694 | 868,288 | 769,834 | 7,163,314 |
| Other\tincome | 47,603 | 48,572 | 249,678 | 347,753 |
| Interest\tand\tother\tcharges | 465,703 | 47,291 | 61,632 | 572,464 |
| Income\ttaxes | 313,752 | 132,726 | (141,288) | 293,938 |
| Net\tincome\t(loss) | 606,963 | 200,505 | (145,830) | 623,072 |
| 2001 |  |  |  |  |
| Operating\trevenues | $7,432,920 | $789,244 | $1,370,485 | $9,620,899 |
| Operating\texpenses | 6,050,534 | 576,510 | 1,361,153 | 8,072,954 |
| Other\tincome | 69,157 | 50,916 | 222,571 | 349,353 |
| Interest\tand\tother\tcharges | 576,705 | 55,717 | 74,953 | 714,580 |
| Income\ttaxes | 300,284 | 80,053 | 74,493 | 455,693 |
| Cumulative\teffect\tof\taccounting\tchange | - | - | 23,482 | 23,482 |
| Net\tincome | 574,554 | 127,880 | 105,939 | 750,507 |

# CASH	FLOW	INFORMATION

|  | U.S.	Utility | Non-Utility	Nuclear | Energy	Commodity<br>Services | Entergy<br>Consolidated	(a) |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| 2003 |  |  |  |  |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\toperating\tactivities | $1,675,069 | $182,524 | ($111,291) | $2,005,820 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (1,441,992) | (184,913) | (78,120) | (1,783,130) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (919,983) | (6,672) | 166,165 | (869,130) |
| 2002 |  |  |  |  |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\toperating\tactivities | $2,341,161 | $281,589 | ($3,714) | $2,181,703 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (1,020,087) | (438,664) | (760) | (1,388,463) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (688,201) | 176,162 | (66,151) | (212,610) |
| 2001 |  |  |  |  |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\toperating\tactivities | $1,647,969 | $263,476 | ($127,938) | $2,215,548 |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tinvesting\tactivities | (1,243,715) | (1,061,820) | 138,351 | (2,224,720) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (303,520) | 292,872 | (148,501) | (622,004) |

# FINANCIAL	POSITION	INFORMATION

|  | U.S.	Utility | Non-Utility	Nuclear | Energy	Commodity<br>Services | Entergy<br>Consolidated	(a) |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| 2003 |  |  |  |  |
| Current\tassets | $2,117,260 | $542,837 | $466,132 | $2,919,244 |
| Other\tproperty\tand\tinvestments | 1,151,538 | 1,326,347 | 1,137,069 | 3,746,926 |
| Property,\tplant\tand\tequipment\t-\tnet | 16,242,775 | 1,557,025 | 463,403 | 18,298,797 |
| Deferred\tdebits\tand\tother\tassets | 2,917,563 | 745,568 | 10,317 | 3,589,243 |
| Current\tliabilities | 1,671,607 | 330,684 | 478,693 | 2,282,223 |
| Non-current\tliabilities | 15,309,482 | 1,891,805 | 41,450 | 17,568,329 |
| Shareholders'\tequity | 5,448,047 | 1,949,288 | 1,614,620 | 8,703,658 |
| 2002 |  |  |  |  |
| Current\tassets | $2,517,001 | $706,056 | $504,836 | $3,205,583 |
| Other\tproperty\tand\tinvestments | 1,089,871 | 1,437,896 | 1,175,842 | 3,468,240 |
| Property,\tplant\tand\tequipment\t-\tnet | 15,594,128 | 1,613,369 | 429,677 | 17,665,003 |
| Deferred\tdebits\tand\tother\tassets | 2,429,523 | 724,987 | 57,117 | 3,165,540 |
| Current\tliabilities | 2,479,783 | 947,731 | 348,200 | 3,172,189 |
| Non-current\tliabilities | 13,755,569 | 2,175,467 | 182,750 | 16,493,940 |
| Shareholders'\tequity | 5,395,171 | 1,359,110 | 1,636,522 | 7,838,237 |

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

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

| Entergy	Arkansas,	Inc. | Entergy	Nuclear	Operations,	Inc. | Entergy-Koch,	LP | Non-Nuclear	Wholesale	Assets |
| :--- | :--- | :--- | :--- |
| \t Entergy\tGulf\tStates,\tInc. | \t Entergy\tNuclear\tFinance,\tInc. | (50%\townership) |  |
| \t Entergy\tLouisiana,\tInc. | \t Entergy\tNuclear\tGeneration\tCo.\t(Pilgrim) |  |  |
| \t Entergy\tMississippi,\tInc. | \t Entergy\tNuclear\tFitzPatrick\tLLC | \t Gulf\tSouth\tPipeline | \t Entergy\tPower\tDevelopment\tCorp. |
| \t Entergy\tNew\tOrleans,\tInc. | \t Entergy\tNuclear\tIndian\tPoint\t2,\tLLC | \t Entergy-Koch\tTrading | \t Entergy\tAsset\tManagement,\tInc. |
| \t System\tEnergy\tResources,\tInc. | \t Entergy\tNuclear\tIndian\tPoint\t3,\tLLC |  |  |
| \t Entergy\tOperations,\tInc. | \t Entergy\tNuclear\tVermont\tYankee,\tLLC |  |  |
| \t Entergy\tServices,\tInc. | \t Entergy\tNuclear,\tInc. |  |  |
| \t System\tFuels,\tInc. | \t Entergy\tNuclear\tFuels\tCompany |  |  |

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

# Strategy

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

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

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

Part	I,	Item	1	is	continued	on	page	104.

# ENTERGY	CORPORATION	AND	SUBSIDIARIES

# REPORT	OF	MANAGEMENT

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

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

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

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

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

# J.	WAYNE	LEONARD

Chief	Executive	Officer	of	Entergy	Corporation

# LEO	P.	DENAULT

# Executive	Vice	President	and	Chief	Financial	Officer	of

Entergy	Corporation

# HUGH	T.	MCDONALD

Chairman,	President,	and	Chief	Executive	Officer	of	Entergy Arkansas,	Inc.

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

DANIEL	F.	PACKER Chairman,	President,	and	Chief	Executive	Officer	of	Entergy New	Orleans,	Inc.

# JOSEPH	F.	DOMINO

Chairman	of	Entergy	Gulf	States,	Inc.,	President	and	Chief Executive	Officer	-	Texas	of	Entergy	Gulf	States,	Inc.

CAROLYN	C.	SHANKS Chairman,	President,	and	Chief	Executive	Officer	of	Entergy Mississippi,	Inc.

GARY	J.	TAYLOR Chairman,	President,	and	Chief	Executive	Officer	of	System Energy	Resources,	Inc.

Inc.,	Entergy	Mississippi,	Inc.,	and	Entergy	New	Orleans,	Inc.

# MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS

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

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	Revenue |  | %	of	Net	Income | %	of	Net	Income |  | %	of	Total	Assets | %	of	Total	Assets |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Segment |  | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 |
| U.S.\tUtility |  | 82 | 82 | 77 | 52 | 97 | 77 | 79 | 79 | 78 |
| Non-Utility\tNuclear | Non-Utility\tNuclear | 14 | 14 | 8 | 32 | 32 | 17 | 15 | 16 | 13 |
| Energy\nServices | Commodity | 2 | 4 | 14 | 19 | (23) | 14 | 7 | 8 | 9 |
| Parent\t&amp;\tOther |  | 2 | - | 1 | (3) | (6) | (8) | (1) | (3) | - |

# Results	of	Operations

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

| Operating	Segment | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| U.S.\tUtility | $469,050 | $583,251 | $550,243 |
| Non-Utility\tNuclear | 300,799 | 200,505 | 127,880 |
| Energy\tCommodity\tServices | 180,454 | (145,830) | 105,939 |
| Parent\t&amp;\tOther | (23,360) | (38,566) | (57,866) |
| \t\tTotal | $926,943 | $599,360 | $726,196 |

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

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

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

# U.S.	Utility

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

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

# Net	Revenue

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.

| 2002	net	revenue | $4,209.6 |
| :--- | :--- |
| Base\trate\tincreases | 66.2 |
| Base\trate\tdecreases | (23.3) |
| Fuel\tprice | 56.2 |
| Asset\tretirement\tobligation | 42.9 |
| Net\twholesale\trevenue | 23.2 |
| March\t2002\tArk.\tsettlement\nagreement | (154.0) |
| Other | (6.3) |
| 2003\tnet\trevenue | $4,214.5 |

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

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

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

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

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

# Gross	operating	revenues	and	regulatory	credits

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

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

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

(In	Millions)

| 2001	net	revenue | $3,873.1 |
| :--- | :--- |
| March\t2002\tArk.\tsettlement\tagreement | 180.7 |
| Volume/weather | 155.7 |
| Fuel\tprice | 94.3 |
| System\tEnergy\trefund\tin\t2001 | (128.9) |
| Other | 34.7 |
| 2002\tnet\trevenue | $4,209.6 |

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

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

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

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

# Gross	operating	revenues

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

# Other	Income	Statement	Variances

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

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

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

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

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

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

an	increase	of	$51.2	million	in	benefit	costs;

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

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

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

lower	nuclear	insurance	refunds	of	$6.7	million.

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

Other	income	decreased	primarily	due	to:

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

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

lower	interest	earned	on	declining	deferred	fuel	balances.

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

# Interest	and	other	charges	decreased	primarily	due	to:

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

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

# Non-Utility	Nuclear

Following	are	key	performance	measures	for	Non-Utility	Nuclear:

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Net\tMW\tin\toperation\tat\tDecember\t31 | 4,001 | 3,955 | 3,445 |
| Average\trealized\tprice\tper\tMWh | $38.54 | $40.49 | $34.90 |
| Generation\tin\tGWh\tfor\tthe\tyear | 32,379 | 29,953 | 22,614 |
| Capacity\tfactor\tfor\tthe\tyear | 92.4% | 92.8% | 92.7% |

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.

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

# Energy	Commodity	Services

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Entergy-Koch\tTrading |  |  |  |
| \t\tGas\tvolatility | 62% | 61% | 72% |
| \t\tElectricity\tvolatility | 59% | 48% | 78% |
| \t\tGas\tmarketed\t(BCF/D)\t(1) | 6.5 | 5.8 | 4.5 |
| \t\tElectricity\tmarketed\t(GWh) | 445,979 | 408,038 | 180,893 |
| \t\tGain/loss\tdays | 1.5 | 1.8 | 2.8 |
| Gulf\tSouth\tPipeline |  |  |  |
| \t\tThroughput\t(BCF/D) | 1.99 | 2.40 | 2.45 |
| \t\tProduction\tcost\t($/MMBtu) | $0.146 | $0.094 | $0.093 |

(1) Previously	reported	volumes,	which	included	only	U.S.	trading,	have	been

adjusted	to	reflect	both	U.S.	and	Europe	volumes	traded.

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

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

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

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

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

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

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

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

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

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

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

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

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

# Parent	&	Other

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

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

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

a	decrease	in	interest	charges	of	$6.0	million.

# Income	Taxes

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

# Liquidity	and	Capital	Resources

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

# Capital	Structure

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Net\tdebt\tto\tnet\tcapital\tat\tthe\tend\tof\tthe\tyear | 45.3% | 47.7% | 51.1% |
| Effect\tof\tsubtracting\tcash\tfrom\tgross\tdebt | 2.2% | 4.1% | 2.2% |
| Debt\tto\tcapital\tat\tthe\tend\tof\tthe\tyear | 47.5% | 51.8% | 53.3% |

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

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

| Long-term	debt	maturities | 2003 | 2004 | 2005 | 2006 | 2007-2008 | after	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| As\tof\tDecember\t31,\t2002 |  |  |  |  |  |  |
| U.S.\tUtility | $1,111 | $855 | $470 | $68 | $654 | $3,718 |
| Non-Utility\tNuclear | $87 | $91 | $95 | $98 | $119 | $193 |
| Energy\tCommodity\tServices | $79 | - | - | - | - | - |
| Parent\tand\tOther | - | $595 | - | - | - | $267 |
| As\tof\tDecember\t31,\t2003 |  |  |  |  |  |  |
| U.S.\tUtility | - | $450 | $355 | $28 | $1,254 | $4,345 |
| Non-Utility\tNuclear | - | $74 | $72 | $76 | $100 | $193 |
| Energy\tCommodity\tServices | - | - | - | - | - | - |
| Parent\tand\tOther | - | - | $60 | - | $272 | $568 |

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

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

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

| Company | Expiration	Date | Amount	of<br>Facility | Amount	Drawn	as	of<br>Dec.	31,	2003 |
| :--- | :--- | :--- | :--- |
| Entergy\tCorporation | May\t2004 | $1.450\tbillion | - |
| Entergy\tArkansas | April\t2004 | $63\tmillion | - |
| Entergy\tLouisiana | May\t2004 | $15\tmillion | - |
| Entergy\tMississippi | May\t2004 | $25\tmillion | - |

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

# Operating	Lease	Obligations	and	Guarantees	of	Unconsolidated	Obligations

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

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

|  | 2004 | 2005 | 2006 | 2007- | after	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | 2008 |  |
|  |  |  | (In\tMillions) |  |  |
| Operating\tlease\tpayments | $99 | $89 | $70 | $93 | $245 |

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

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

In	August	2001,	EntergyShaw	entered	into	a	turnkey	construction	agreement	with	an	Entergy	subsidiary,	Entergy	Power	Ventures,	L.P.	(EPV), and	with	Northeast	Texas	Electric	Cooperative,	Inc.	(NTEC),	providing	for	the	construction	by	EntergyShaw	of	a	550	MW	electric	generating station	to	be	located	in	Harrison	County,	Texas.	Entergy	has	guaranteed	the	obligations	of	EntergyShaw	to	construct	the	plant,	which	is	70%

owned	by	EPV.	Entergy's	maximum	liability	on	the	guarantee	is	$232.5	million,	and	the	guarantee	is	expected	to	remain	outstanding	through June	2004.

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

# Summary	of	Contractual	Obligations	of	Consolidated	Entities

| Contractual	Obligations | 2004 | 2005-2006 | 2007-2008 | after	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(1) | $524 | $591 | $1,626 | $5,106 | $7,847 |
| Capital\tlease\tobligations\t(2) | $165 | $148 | $5 | $3 | $321 |
| Operating\tleases\t(2) | $99 | $159 | $93 | $245 | $596 |
| Purchase\tobligations\t(3) | $925 | $1,007 | $907 | $1,446 | $4,285 |

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

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

(3) As	defined	by	SEC	rule.	For	Entergy,	it	includes	unconditional	fuel	and	purchased	power obligations	and	other	purchase	obligations.	Approximately	97%	of	the	total	pertains	to	fuel	and purchased	power	obligations	that	are	recovered	in	the	normal	course	of	business	through	various fuel	cost	recovery	mechanisms	in	the	U.S.	Utility	business.

# Capital	Funds	Agreement

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

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

permit	the	continued	commercial	operation	of	Grand	Gulf	1;

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

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

# Capital	Expenditure	Plans	and	Other	Uses	of	Capital

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

| U.S.	Utility | $767 | $767 | $759 |
| :--- | :--- | :--- | :--- |
| Non-Utility\tNuclear | 73 | 68 | 76 |
| Energy\tCommodity\tServices | 7 | 2 | 2 |
| Parent\tand\tOther | 7 | 10 | 14 |
|  | 854 | 847 | 851 |
| Capital\tCommitments: |  |  |  |
| U.S.\tUtility | 569 | 295 | 112 |
| Non-Utility\tNuclear | 123 | - | - |
| Energy\tCommodity\tServices | 73 | - | - |
| Parent\tand\tOther | 32 | - | - |
|  | 797 | 295 | 112 |
| Total | $1,651 | $1,142 | $963 |

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

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

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

Purchase	of	the	Perryville	power	plant	in	Louisiana.	In	January	2004,	Entergy	Louisiana	signed	an	agreement	to	acquire	the	718	MW	Perryville power	plant	for	$170	million.	The	plant	is	owned	by	a	subsidiary	of	Cleco	Corporation,	which	subsidiary	submitted	a	bid	in	response	to

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

# Nuclear	power	plant	uprates.

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

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

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

# Dividends	and	Stock	Repurchases

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

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

# PUHCA	Restrictions	on	Uses	of	Capital

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

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

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

# Sources	of	Capital

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

internally	generated	funds;

securities	issuances;

bank	financing	under	new	or	existing	facilities;	and

# sales	of	assets.

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

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

Short-term	borrowings	by	the	domestic	utility	companies	and	System	Energy,	including	borrowings	under	the	intra-company	money	pool,	are	limited	to amounts	authorized	by	the	SEC.	Under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	the	domestic	utility	companies	and	System	Energy	cannot

incur	new	short-term	indebtedness	if	the	issuer's	common	equity	would	comprise	less	than	30%	of	its	capital.	See	Note	4	to	the	consolidated	financial statements	for	further	discussion	of	Entergy's	short-term	borrowing	limits.

# Cash	Flow	Activity

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

| Cash	and	cash	equivalents	at	beginning	of	period | Cash	and	cash	equivalents	at	beginning	of	period | Cash	and	cash	equivalents	at	beginning	of	period | Cash	and	cash	equivalents	at	beginning	of	period | Cash	and	cash	equivalents	at	beginning	of	period | Cash	and	cash	equivalents	at	beginning	of	period |  | $1,335 | $752 | $1,382 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |  |  |  |  |  |  |
| \t\t\tOperating\tactivities | \t\t\tOperating\tactivities |  |  |  |  |  | 2,006 | 2,181 | 2,216 |
| \t\t\tInvesting\tactivities | \t\t\tInvesting\tactivities |  |  |  |  |  | (1,783) | (1,388) | (2,224) |
| \t\t\tFinancing\tactivities | \t\t\tFinancing\tactivities |  |  |  |  |  | (869) | (213) | (622) |
| Effect\t of\nequivalents | exchange | rates | on | cash | and | cash | 3 | 3 | - |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (643) | 583 | (630) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod |  |  | $692 | $1,335 | $752 |

# Operating	Cash	Flow	Activity

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

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

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

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

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

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

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

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

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

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

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

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

# Tax	Election

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

In	a	September	2002	settlement	of	an	LPSC	proceeding	that	concerned	the	Vidalia	contract,	the	LPSC	approved	Entergy	Louisiana's	proposed	treatment	of the	regulatory	impact	of	the	tax	accounting	election.	In	general,	the	settlement	permits	Entergy	Louisiana	to	keep	a	portion	of	the	tax	benefit	in	exchange	for bearing	the	risk	associated	with	sustaining	the	tax	treatment.	The	LPSC	settlement	divided	the	term	of	the	Vidalia	contract	into	two	segments:	2002-2012

and	2013-2031.	During	the	first	eight	years	of	the	2002-2012	segment,	Entergy	Louisiana	agreed	to	credit	rates	by	flowing	through	its	fuel	adjustment calculation	$11	million	each	year,	beginning	monthly	in	October	2002.	Entergy	Louisiana	must	credit	rates	in	this	way	and	by	this	amount	even	if	Entergy Louisiana	is	unable	to	sustain	the	tax	deduction.	Entergy	Louisiana	also	must	credit	rates	by	$11	million	each	year	for	an	additional	two	years	unless	either the	tax	accounting	method	elected	is	retroactively	repealed	or	the	Internal	Revenue	Service	denies	the	entire	deduction	related	to	the	tax	accounting	method. Entergy	Louisiana	agreed	to	credit	ratepayers	additional	amounts	unless	the	tax	accounting	election	is	not	sustained	if	it	is	challenged.	During	2013-2031, Entergy	Louisiana	and	its	ratepayers	would	share	the	remaining	benefits	of	this	tax	accounting	election.

# Investing	Activities

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

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

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

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

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

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

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

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

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

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

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

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

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

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

# Financing	Activities

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.

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

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

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

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

outstanding	on	the	Saltend	credit	facility	when	the	plant	was	sold.

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

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

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

# Significant	Factors	and	Known	Trends

# Rate	Regulation	and	Fuel-Cost	Recovery

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

(1) Entergy	Louisiana's	formula	rate	plan	expired	with	the	2001	test	year.	Under	the	expired	formula, if	 Entergy	 Louisiana	 earned	 outside	 of	 the	 bandwidth	 range,	 rates	 would	 be	 adjusted	 on	 a prospective	 basis.	If	earnings	were	above	 the	bandwidth	range,	rates	would	be	reduced	by	60 percent	of	the	overage,	and	if	below,	increased	by	60	percent	of	the	shortfall.

# (2) Under	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	if	Entergy	Mississippi's	earned

ROE	 is	 above	 the	 top	 of	 the	 range-of-no-change	 at	 the	 top	 of	 the	 bandwidth,	 then	 Entergy Mississippi's	rates	are	reduced	by	50	percent	of	the	difference	between	the	earned	ROE	and	the	top of	the	bandwidth.	In	such	circumstance,	Entergy	Mississippi's	'Allowed	ROE'	for	the	next	twelve- month	period	is	the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth	-- Entergy	Mississippi's	retail	rates	are	set	at	that	halfway-point	ROE	level.	(Before	the	comparison is	made	of	the	earned	ROE	to	the	bandwidth,	the	bandwidth	can	be	adjusted	for	performance measures	by	as	much	as	1%.	Rates	are	adjusted	pursuant	to	Entergy	Mississippi's	formula	rate	plan on	a	prospective	basis	only.)	In	the	situation	where	Entergy	Mississippi's	earned	ROE	is	not	above the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth,	then	Entergy	Mississippi's	'Allowed ROE'	for	 the	next	 twelve-month	period	 is	 the	 top	of	 the	range-of-no-change	at	 the	 top	of	 the bandwidth.	If	earnings	are	below	the	bandwidth	range,	rates	are	increased	by	50	percent	of	the difference	between	the	earned	ROE	and	the	bottom	of	the	bandwidth.	Under	the	provisions	of Entergy	Mississippi's	formula	rate	plan,	each	annual	formula	rate	plan	filing	incorporates	a	revised calculation	of	the	benchmark	ROE.	The	benchmark	ROE	set	out	in	the	March	15,	2004,	formula rate	plan	filing	likely	will	differ	from	the	last	approved	ROE.	Entergy	Mississippi	anticipates	the March	15,	2004,	filing	will	show	an	allowed	regulatory	earnings	range	of	9.3%	to	12.2%.	Entergy Mississippi	does	not	anticipate	a	reduction	in	revenues	going	forward.

(3) If	 Entergy	 New	 Orleans	 earns	 outside	 of	 the	 bandwidth	 range,	 rates	 will	 be	 adjusted	 on	 a prospective	 basis.	Under	the	gas	formula	rate	plan,	if	earnings	are	above	the	bandwidth	range, rates	are	reduced	by	100	percent	of	the	overage,	and	if	below,	increased	by	100	percent	of	the shortfall.	In	addition,	if	the	ROE	falls	between	11.5%	and	12.25%,	rates	are	reduced	by	60	percent of	the	difference,	and	if	the	ROE	falls	between	10.25%	and	11%,	rates	are	increased	by	40	percent of	 the	 differential.	Under	 the	electric	formula	rate	plan,	rates	are	adjusted	accordingly	by	100

percent	of	the	amount	of	any	overage	or	shortfall.	Entergy	New	Orleans	may	earn	up	to	13.25%

under	the	electric	formula	rate	plan	provided	that	the	increase	is	caused	by	its	share	of	energy	cost

savings	under	the	generation	performance-based	recovery	plan	discussed	below.

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

# System	Agreement	Litigation

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

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

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

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

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

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

# Market	and	Credit	Risks

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

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

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

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

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

# Commodity	Price	Risk

# Power	Generation

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

|  | 2004 | 2005 | 2006 | 2007 | 2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Non-Utility\tNuclear: |  |  |  |  |  |
| %\tof\tplanned\tgeneration\tsold\nforward | 100% | 52% | 32% | 16% | 4% |
| Planned\tgeneration\t(GWh) | 32,787 | 34,164 | 34,853 | 34,517 | 34,513 |
| Average\tprice\tper\tMWh | $38 | $37 | $35 | $34 | $38 |

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

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

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

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

|  | 2004 | 2005 | 2006 | 2007 | 2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Non-Utility\tNuclear: |  |  |  |  |  |
| Percent\tof\tcapacity\tsold\tforward: |  |  |  |  |  |
| \t\tBundled\tcapacity\tand\tenergy\tcontracts | 55% | 15% | 12% | 13% | 13% |
| \t\tCapacity\tcontracts | 28% | 15% | 6% | 3% | 0% |
| \t\tTotal | 83% | 30% | 18% | 16% | 13% |
| Planned\tMW\tin\toperation | 4,111 | 4,203 | 4,203 | 4,203 | 4,203 |
| Average\tcapacity\tcontract\tprice\tper\tkW\tper\tmonth | $2.4 | $1.3 | $0.6 | $0.7 | N/A |
| Blended\tCapacity\tand\tEnergy\t(based\ton\trevenues) |  |  |  |  |  |
| %\tof\tplanned\tgeneration\tand\tcapacity\tsold\tforward | 99% | 49% | 28% | 13% | 4% |
| Average\tcontract\trevenue\tper\tMWh | $39 | $37 | $35 | $34 | $38 |

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

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

|  | 2004 | 2005 | 2006 | 2007 | 2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy\tCommodity\tServices: |  |  |  |  |  |
| Capacity |  |  |  |  |  |
| Planned\tMW\tin\toperation | 1,911 | 1,911 | 1,911 | 1,911 | 1,911 |
| %\tof\tcapacity\tsold\tforward | 43% | 43% | 34% | 31% | 26% |
| Energy |  |  |  |  |  |
| Planned\tgeneration\t(GWh) | 3,321 | 3,348 | 3,337 | 3,545 | 4,015 |
| %\tof\tplanned\tgeneration\tsold\tforward | 64% | 67% | 52% | 42% | 39% |

| %	of	planned	energy	and	capacity	sold	forward | 62% | 66% | 50% | 41% | 35% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Average\tcontract\trevenue\tper\tMWh | $26 | $25 | $27 | $31 | $28 |

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

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

# Marketing	and	Trading

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

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

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

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

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

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

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

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  |  | (in |  |
|  |  | millions) |  |
| DE@R\tat\tend\tof\tthe\tyear | $9.6 | $15.2 | $5.5 |
| Average\tDE@R\tfor\tthe\tyear | 13.6 | 10.8 | 6.4 |
| Low\tDE@R\tfor\tthe\tyear | 5.9 | 6.6 | 3.6 |
| High\tDE@R\tfor\tthe\tyear | 35.2 | 16.9 | 8.0 |

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

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

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

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

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

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

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

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

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

# Maturities	and	Sources	for	Fair

# Value	of	Trading	Contracts	at

| December	31,	2003 | 0-12	months | 13-24	months | 25+	months | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Prices\tactively\tquoted | $126.3 | ($87.1) | ($14.6) | $24.6 |
| Prices\tprovided\tby\tother\tsources | 4.8 | (10.1) | 5.6 | 0.3 |
| Prices\tbased\ton\tmodels | (28.0) | 14.2 | 4.9 | (8.9) |
| Total | $103.1 | ($83.0) | ($4.1) | $16.0 |

| Fair	value	of	contracts	outstanding	at	December	31,	2002	after	implementation	of	EITF	02-03 | $90.9 |
| :--- | :--- |
| (Gain)/loss\tfrom\tcontracts\trealized/settled\tduring\tthe\tyear | (580.0) |
| Net\toption\tpremiums\treceived\tduring\tthe\tyear | 275.7 |
| Change\tin\tfair\tvalue\tof\tcontracts\tattributable\tto\tmarket\tmovements\tduring\tthe\tyear | 229.4 |
| Net\tchange\tin\tcontracts\toutstanding\tduring\tthe\tyear | (74.9) |
| Fair\tvalue\tof\tcontracts\toutstanding\tat\tDecember\t31,\t2003 | $16.0 |

# Foreign	Currency	Exchange	Rate	Risk

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

# Interest	Rate	and	Equity	Price	Risk	-	Decommissioning	Trust	Funds

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

# Utility	Restructuring

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

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

# Transmission

In	2000,	FERC	issued	an	order	encouraging	utilities	to	voluntarily	place	their	transmission	facilities	under	the	control	of	independent	RTOs	(regional transmission	organizations)	by	December	15,	2001.	Delays	in	implementing	the	FERC	order	have	occurred	due	to	a	variety	of	reasons,	including	the	fact	that utility	companies,	other	stakeholders,	and	federal	and	state	regulators	continue	to	work	to	resolve	various	issues	related	to	the	establishment	of	such	RTOs. Entergy's	domestic	utility	companies	were	participating	with	other	transmission	owners	within	the	southeastern	United	States	to	establish	an	RTO,	the proposed	SeTrans	RTO,	but	the	sponsors	determined	that	the	regulatory	approvals	necessary	for	the	development	of	the	SeTrans	RTO	were	unlikely	to	be obtained	at	the	present	time	and	in	December	2003	suspended	further	development	activity.	Although	SeTrans	development	is	suspended,	Entergy	continues to	focus	its	efforts	on	reforms	that	can	further	the	core	objectives	of	FERC's	2000	order:	achieving	greater	independence	in	the	provision	of	transmission service	and	a	more	efficient	method	of	pricing	that	service.	Entergy	intends	to	work	with	FERC	and	Entergy's	retail	regulators	on	certain	voluntary	steps	to further	those	objectives.

As	currently	contemplated,	and	assuming	applicable	regulatory	support	and	approvals	can	be	obtained,	Entergy	plans	to	contract	with	an	independent transmission	entity	to	oversee	the	granting	of	transmission	service	on	the	Entergy	system	as	well	as	the	implementation	of	the	weekly	procurement	process

that	 Entergy	 has	 proposed.	Entergy	 will	 submit	 to	 the	 FERC	 for	 its	 approval	 the	 proposed	 contract	 setting	 forth	 the	 independent	 entity's	 duties	 and obligations	as	well	as	other	documents	necessary	 to	 implement	 this	proposed	structure.	The	proposed	structure	does	not	 transfer	control	of	Entergy's transmission	system	to	the	independent	entity,	but	rather	will	vest	with	the	independent	entity	broad	oversight	authority	over	transmission	planning	and operations.

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

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

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

# FERC's	Supply	Margin	Assessment

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

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

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

# Interconnection	Orders

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

In	July	2003,	the	FERC	issued	its	final	rule	on	the	standardization	of	generation	interconnection	agreements	and	procedures	(Order	2003).	Among	other things,	Order	2003	incorporates	pricing	policies	that	require	the	transmission	provider's	other	customers	to	bear	the	vast	majority	of	costs	required	when	a new	generator	interconnects	to	its	transmission	system	or	requests	transmission	upgrades	necessary	for	the	generator	to	be	considered	a	network	resource	for load	serving	entities	within	the	transmission	provider's	control	area.	Order	2003	also	requires	that	generators	that	fund	upgrades	receive	their	money	back, with	interest,	in	no	more	than	five	years.	Order	2003,	which	the	FERC	has	indicated	is	to	be	applied	only	to	prospective	interconnection	agreements,	became effective	on	January	20,	2004.	Consistent	with	their	past	practices,	the	generators	that	had	previously	executed	interconnection	agreements	with	Entergy	and that	have	transmission	credits	outstanding	have	filed	complaints	at	the	FERC	seeking	to	avail	themselves	of	the	more	beneficial	crediting	aspects	of	the FERC's	final	rule.	Entergy	has	opposed	such	relief	and	the	proceedings	are	pending.	On	March	5,	2004,	the	FERC	issued	an	order	on	rehearing	responding

to	certain	issues	raised	with	respect	to	Order	2003.	While	management	is	still	analyzing	the	order	on	rehearing,	it	appears	that	the	FERC	has	modified	Order 2003	to,	among	other	things,	eliminate	the	requirement	that	the	generators	receive	their	money	back	in	no	more	than	five	years	and	include	a	requirement that	the	generators	receive	credits	only	when	transmission	service	is	taken	from	the	specific	generating	facility	served	by	the	interconnection	or	upgrade. Because	the	order	on	rehearing	was	just	issued,	however,	management's	analysis	of	the	effects	of	the	order	is	ongoing.

# Retail

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

# Federal	Legislation

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

# Nuclear	Matters

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

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

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

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

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

# Litigation

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

# Critical	Accounting	Estimates

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

# Nuclear	Decommissioning	Costs

Entergy	owns	a	significant	number	of	nuclear	generation	facilities	in	both	its	U.S.	Utility	and	Non-Utility	Nuclear	business	units.	Regulations	require	that

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

For	the	U.S.	Utility	business,	the	implementation	of	SFAS	143	for	the	rate-regulated	business	of	the	domestic	utility	companies	and	System Energy	was	recorded	as	a	regulatory	asset,	with	no	resulting	impact	on	Entergy's	net	income.	Entergy	recorded	these	regulatory	assets	because existing	rate	mechanisms	in	each	jurisdiction	are	based	on	the	original	or	historical	cost	standard	that	allows	Entergy	to	recover	all	ultimate costs	of	decommissioning	existing	assets	from	current	and	future	customers.	As	a	result	of	this	treatment,	SFAS	143	is	expected	to	be	earnings neutral	to	the	rate-regulated	business	of	the	domestic	utility	companies	and	System	Energy.	Assets	and	liabilities	increased	by	approximately

$1.1	billion	in	2003	for	the	domestic	utility	companies	and	System	Energy	as	a	result	of	recording	the	asset	retirement	obligations	at	their	fair values	of	$1.1	billion	as	determined	under	SFAS	143,	increasing	utility	plant	by	$288	million,	reducing	accumulated	depreciation	by	$361 million	and	recording	the	related	regulatory	assets	of	$422	million.	The	implementation	of	SFAS	143	for	the	portion	of	River	Bend	not	subject to	cost-based	ratemaking	decreased	earnings	by	approximately	$21	million	net-of-tax	($0.09	per	share)	as	a	result	of	a	one-time	cumulative effect	of	accounting	change.	In	accordance	with	ratemaking	treatment	and	as	required	by	SFAS	71,	the	depreciation	provisions	for	Entergy's utility	subsidiaries	include	a	component	for	removal	costs	that	are	not	asset	retirement	obligations	under	SFAS	143.	Approximately	6%	of	the U.S.	Utility's	current	depreciation	rates,	on	a	weighted-average	basis,	represents	a	component	for	the	net	of	salvage	value	and	removal	costs.

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

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

# Impairment	of	Long-lived	Assets

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

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

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

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

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

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

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

# Mark-to-market	Accounting

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

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

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

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

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

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

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

forward	contracts	that	will	result	in	physical	delivery.

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

# Pension	and	Other	Postretirement	Benefits

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

# Assumptions

# Key	actuarial	assumptions	utilized	in	determining	these	costs	include:

Discount	rates	used	in	determining	the	future	benefit	obligations;

Projected	health	care	cost	trend	rates;

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

# Rate	of	increase	in	future	compensation	levels.

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

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

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

# Cost	Sensitivity

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

|  | Change	in | Impact	on	2003 | Impact	on |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Projected |
|  |  |  | Benefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $4,882 | $83,651 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $4,346 | - |
| Rate\tof\tincrease\tin | 0.25% | $4,039 | $28,101 |

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

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit<br>Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $5,206 | $25,979 |
| Discount\trate | (0.25%) | $3,278 | $29,500 |

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

# Accounting	Mechanisms

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

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

# Costs	and	Funding

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

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

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

# Other	Contingencies

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

# Environmental

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

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

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

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

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

# Sales	Warranty	and	Tax	Reserves

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

# SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON

| Operating	revenues | $9,194,920 | $8,305,035 | $9,620,899 | $10,022,129 | $8,765,635 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tbefore\tcumulative\neffect\tof\taccounting\tchange | $813,393 | $623,072 | $727,025 | $710,915 | $595,026 |
| Earnings\tper\tshare\tbefore |  |  |  |  |  |
| cumulative\teffect\tof\taccounting |  |  |  |  |  |
| change |  |  |  |  |  |
| Basic | $3.48 | $2.69 | $3.18 | $3.00 | $2.25 |
| Diluted | $3.42 | $2.64 | $3.13 | $2.97 | $2.25 |
| Dividends\tdeclared\tper\tshare | $1.60 | $1.34 | $1.28 | $1.22 | $1.20 |
| Return\ton\taverage\tcommon\tequity | 11.21% | 7.85% | 10.04% | 9.62% | 7.77% |
| Book\tvalue\tper\tshare,\tyear-end | $38.02 | $35.24 | $33.78 | $31.89 | $29.78 |
| Total\tassets | $28,554,210 | $27,504,366 | $25,910,311 | $25,451,896 | $22,969,940 |
| Long-term\tobligations\t(1) | $7,497,690 | $7,488,919 | $7,743,298 | $8,214,724 | $7,252,697 |

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

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

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

# INDEPENDENT	AUDITORS'	REPORT

To	the	Board	of	Directors	and	Shareholders	of Entergy	Corporation:

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

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

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

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

DELOITTE	&	TOUCHE	LLP

New	Orleans,	Louisiana March	9,	2004

See	Notes	to	Consolidated	Financial	Statements.

# Cash	and	cash	equivalents:

			ACCUMULATED	OTHER	COMPREHENSIVE	INCOME	(LOSS)

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# NOTE	1.	SUMMARY	OF	SIGNIFICANT	ACCOUNTING	POLICIES

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

# Use	of	Estimates	in	the	Preparation	of	Financial	Statements

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

# Revenues	and	Fuel	Costs

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

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

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

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

# Property,	Plant,	and	Equipment

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

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

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

|  |  |  |  |  | Energy |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | U.S. | Non-Utility Commodity | Non-Utility Commodity | Parent\tand |
|  | 2003 | Entergy | Utility | Nuclear | Services | Other |
|  |  |  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |  |  |
| \t\tNuclear |  | $7,056 | $6,112 | $944 | $- | $- |
| \t\tOther |  | 1,816 | 1,359 | - | 457 | - |

| Transmission | 2,067 | 2,067 | - | - | - |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Distribution | 4,231 | 4,231 | - | - | - |
| Other | 1,079 | 1,069 | - | - | 10 |
| Construction\twork\tin\tprogress | 1,381 | 954 | 398 | - | 29 |
| Nuclear\tfuel |  |  |  |  |  |
| \t\t(leased\tand\towned) | 513 | 298 | 215 | - | - |
| Asset\tretirement\tobligation\t(1) | 156 | 155 | - | 1 | - |
| Property,\tplant,\tand\tequipment\t- | $18,299 | $16,245 | $1,557 | $458 | $39 |

| 2002 | Entergy | U.S.<br>Utility | Non-Utility<br>Nuclear | Commodity<br>Services | Parent	and<br>Other |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |  |
| \t\tNuclear | $7,472 | $6,314 | $1,158 | $- | $- |
| \t\tOther | 1,616 | 1,382 | - | 234 | - |
| Transmission | 1,851 | 1,851 | - | - | - |
| Distribution | 4,037 | 4,037 | - | - | - |
| Other | 933 | 929 | - | - | 4 |
| Construction\twork\tin\tprogress | 1,233 | 797 | 216 | 192 | 28 |
| Nuclear\tfuel |  |  |  |  |  |
| \t\t(leased\tand\towned) | 523 | 284 | 239 | - | - |
| Property,\tplant,\tand\tequipment\t- | $17,665 | $15,594 | $1,613 | $426 | $32 |

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

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

# Jointly-Owned	Generating	Stations

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

| Generating	Stations | Generating	Stations | Fuel-Type | Total<br>Megawatt<br>Capability	(1) | Ownership | Investment | Accumulated<br>Depreciation |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  | (In\tMillions) |  |
| Grand\tGulf | Unit\t1 | Nuclear | 1,207 | 90.00%\t(2) | $3,672 | $1,673 |
| Independence | Units\t1\tand\t2 | Coal | 1,630 | 47.90% | 459 | 240 |
| White\tBluff | Units\t1\tand\t2 | Coal | 1,635 | 57.00% | 423 | 256 |
| Roy\tS.\tNelson | Unit\t6 | Coal | 550 | 70.00% | 404 | 234 |
| Big\tCajun\t2 | Unit\t3 | Coal | 575 | 42.00% | 233 | 123 |
| Harrison\tCounty |  | Gas | 550 | 70.00% | 230 | 3 |

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

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

# Goodwill

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

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

# For	the	Years	Ended	December

| Reported	earnings	applicable	to	common	stock | $926,943 | $599,360 | $726,196 |
| :--- | :--- | :--- | :--- |
| Add\tback:\tGoodwill\tamortization | - | - | 16,265 |
| Adjusted\tearnings\tapplicable\tto\tcommon\tstock\twithout |  |  |  |
| \t\tgoodwill\tamortization | $926,943 | $599,360 | $742,461 |
| Basic\tearnings\tper\taverage\tcommon\tshare: |  |  |  |
| Reported\tearnings\tapplicable\tto\tcommon\tstock | $4.09 | $2.69 | $3.29 |
| Goodwill\tamortization | - | - | 0.07 |
| Adjusted\tearnings\tapplicable\tto\tcommon\tstock\twithout |  |  |  |
| \t\tgoodwill\tamortization | $4.09 | $2.69 | $3.36 |
| Diluted\tearnings\tper\taverage\tcommon\tshare: |  |  |  |
| Reported\tearnings\tapplicable\tto\tcommon\tstock | $4.01 | $2.64 | $3.23 |
| Goodwill\tamortization | - | - | 0.07 |
| Adjusted\tearnings\tapplicable\tto\tcommon\tstock\twithout |  |  |  |
| \t\tgoodwill\tamortization | $4.01 | $2.64 | $3.30 |

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

# Nuclear	Refueling	Outage	Costs

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

# Allowance	for	Funds	Used	During	Construction

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

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

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

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

# Earnings	per	Share

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

|  |  | $/share |  | $/share |  | $/share |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tbefore\tcumulative\teffect\tof\taccounting\tchange | $\t789.9 |  | $599.4 |  | $\t702.7 |  |
| Average\tnumber\tof\tcommon\tshares\toutstanding\t-\tbasic | 226.8 | $\t3.48 | 223.0 | $\t2.69 | 220.9 | $\t3.18 |
| Average\tdilutive\teffect\tof: |  |  |  |  |  |  |
| Stock\tOptions\t(1) | 4.1 | (0.062) | 3.9 | (0.046) | 3.6 | (0.052) |
| Equity\tAwards | 0.2 | (0.004) | 0.4 | (0.005) | 0.2 | (0.002) |
| Average\tnumber\tof\tcommon\tshares\toutstanding\t-\tdiluted | 231.1 | $\t3.42 | 227.3 | $\t2.64 | 224.7 | $\t3.13 |
| Earnings\tapplicable\tto\tcommon\tstock | $\t926.9 |  | $599.4 |  | $\t726.2 |  |
| Average\tnumber\tof\tcommon\tshares\toutstanding\t-\tbasic | 226.8 | $\t4.09 | 223.0 | $\t2.69 | 220.9 | $\t3.29 |

| Stock	Options	(1) | 4.1 | (0.073) | 3.9 | (0.046) | 3.6 | (0.054) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Equity\tAwards | 0.2 | (0.004) | 0.4 | (0.005) | 0.2 | (0.002) |
| Average\tnumber\tof\tcommon\tshares\toutstanding\t-\tdiluted | 231.1 | $\t4.01 | 227.3 | $\t2.64 | 224.7 | $\t3.23 |

(1) Options	to	purchase	approximately	15,231	shares	in	2003,	109,897	shares	in	2002,	and	148,500 shares	in	2001	of	common	stock	at	various	prices	were	outstanding	at	the	end	of	those	years	that were	not	included	in	the	computation	of	diluted	earnings	per	share	because	the	exercise	prices were	greater	than	the	average	market	price	of	the	common	shares	at	the	end	of	each	of	the	years presented.

# Stock-based	Compensation	Plans

Entergy	has	two	plans	that	grant	stock	options,	which	are	described	more	fully	in	Note	8	to	the	consolidated	financial	statements.	Prior	to	2003,	Entergy applied	 the	recognition	and	measurement	principles	of	APB	Opinion	25,	"Accounting	for	Stock	Issued	 to	Employees,"	and	related	Interpretations	 in accounting	for	those	plans.	No	stock-based	employee	compensation	expense	is	reflected	in	2002	and	2001	net	income	as	all	options	granted	under	those plans	 have	 an	 exercise	 price	 equal	 to	 the	 market	 value	 of	 the	 underlying	 common	 stock	 on	 the	 date	 of	 grant.	Effective	 January	 1,	 2003,	 Entergy prospectively	adopted	the	fair	value	based	method	of	accounting	for	stock	options	prescribed	by	SFAS	123,	"Accounting	for	Stock-Based	Compensation." Awards	under	Entergy's	plans	vest	over	three	years.	Therefore,	the	cost	related	to	stock-based	employee	compensation	included	in	the	determination	of	net income	for	2003	is	less	than	that	which	would	have	been	recognized	if	the	fair	value	based	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.

# 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	of	Entergy's	regulatory	assets,	net	of	related	regulatory	and	deferred	tax	liabilities,	earn	a	return	on	investment during	their	recovery	periods.	SFAS	71	requires	that	rate-regulated	enterprises	assess	the	probability	of	recovering	their	regulatory	assets	at	each	balance sheet	date.	When	an	enterprise	concludes	that	recovery	of	a	regulatory	asset	is	no	longer	probable,	the	regulatory	asset	must	be	removed	from	the	entity's balance	sheet.

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

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

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

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

Investments

Entergy	applies	 the	provisions	of	SFAS	115,	"Accounting	for	Investments	for	Certain	Debt	and	Equity	Securities,"	 in	accounting	for	 investments	 in decommissioning	 trust	funds.	As	a	result,	Entergy	records	the	decommissioning	trust	funds	at	their	fair	value	on	the	consolidated	balance	sheet.	As	of December	31,	2003	and	2002,	the	fair	value	of	the	securities	held	in	such	funds	differs	from	the	amounts	deposited	plus	the	earnings	on	the	deposits	by	$94 million	and	($24)	million,	respectively.	Because	of	the	ability	of	the	domestic	utility	companies	and	System	Energy	to	recover	decommissioning	costs	in rates	and	in	accordance	with	the	regulatory	treatment	for	decommissioning	trust	funds,	the	domestic	utility	companies	and	System	Energy	have	recorded	an offsetting	amount	of	unrealized	gains/(losses)	on	investment	securities	in	other	regulatory	liabilities/assets.	Prior	to	the	implementation	of	SFAS	143,	the offsetting	amount	of	unrealized	gains/(losses)	on	investment	securities	was	recorded	in	accumulated	depreciation	for	Entergy	Arkansas,	Entergy	Gulf	States (for	the	regulated	portion	of	River	Bend),	and	for	Entergy	Louisiana.	For	the	nonregulated	portion	of	River	Bend,	Entergy	Gulf	States	has	recorded	an offsetting	amount	of	unrealized	gains/(losses)	in	other	deferred	credits.	Decommissioning	trust	funds	for	Pilgrim,	Indian	Point	2,	and	Vermont	Yankee	do not	receive	regulatory	treatment.	Accordingly,	unrealized	gains	and	losses	recorded	on	the	assets	in	these	trust	funds	are	recognized	in	the	accumulated	other income	component	of	shareholders'	equity	because	these	assets	are	classified	as	available	for	sale.

# Equity	Method	Investees

Entergy	owns	investments	that	are	accounted	for	under	the	equity	method	of	accounting	because	Entergy's	ownership	level	results	in	significant	influence, but	not	control,	over	the	investee	and	its	operations.	Entergy	records	its	share	of	earnings	or	losses	of	the	investee	based	on	the	change	during	the	period	in the	estimated	liquidation	value	of	the	investment,	assuming	that	the	investee's	assets	were	to	be	liquidated	at	book	value.	The	equity	earnings	for	Entergy- Koch,	LP	recorded	by	Entergy	are	dictated	by	the	terms	of	the	partnership	agreement	in	accordance	with	the	hypothetical	liquidation	at	book	value	(HLBV) method.	In	accordance	with	the	HLBV	method,	earnings	are	allocated	to	members	based	on	what	each	partner	would	receive	from	their	capital	account	if, hypothetically,	liquidation	were	to	occur	at	the	balance	sheet	date	and	amounts	distributed	were	based	on	recorded	book	values.	Entergy	discontinues	the recognition	 of	 losses	 on	 equity	 investments	 when	 its	 share	 of	 losses	 equals	 or	 exceeds	 its	 carrying	 amount	 of	 investee	 plus	 any	 advances	 made	 or commitments	to	provide	additional	financial	support.	See	Note	13	to	the	consolidated	financial	statements	for	additional	information	regarding	Entergy's equity	method	investments.

# Derivative	Financial	Instruments	and	Commodity	Derivatives

Entergy	implemented	SFAS	133,	"Accounting	for	Derivative	Instruments	and	Hedging	Activities"	on	January	1,	2001.	The	statement	requires	that	all derivatives	be	recognized	in	the	balance	sheet,	either	as	assets	or	liabilities,	at	fair	value,	unless	they	meet	the	normal	purchase,	normal	sales	criteria.	The changes	in	the	fair	value	of	recognized	derivatives	are	recorded	each	period	in	current	earnings	or	other	comprehensive	income,	depending	on	whether	a derivative	is	designated	as	part	of	a	hedge	transaction	and	the	type	of	hedge	transaction.

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

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

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

Entergy	periodically	reviews	long-lived	assets	held	in	all	of	its	business	segments	whenever	events	or	changes	in	circumstances	indicate	that	recoverability of	 these	 assets	 is	 uncertain.	Generally,	 the	determination	of	recoverability	 is	based	on	 the	undiscounted	net	cash	flows	expected	 to	result	from	such operations	and	assets.	Projected	net	cash	flows	depend	on	the	future	operating	costs	associated	with	the	assets,	the	efficiency	and	availability	of	the	assets and	generating	units,	and	the	future	market	and	price	for	energy	over	the	remaining	life	of	the	assets.	See	Note	12	to	the	consolidated	financial	statements	for discussion	of	asset	impairments	recognized	in	2002	in	the	Energy	Commodity	Services	segment.

# River	Bend	AFUDC

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

# Transition	to	Competition	Liabilities

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

# Reacquired	Debt

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

# Foreign	Currency	Translation

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

# New	Accounting	Pronouncements

During	2003,	Entergy	adopted	the	provisions	of	the	following	accounting	standards:	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	which	is discussed	further	in	Note	9;	FIN	46,	Consolidation	of	Variable	Interest	Entities,"	which	is	discussed	further	in	Note	6;	and	SFAS	150,	"Accounting	for

Certain	Financial	Instruments	with	Characteristics	of	both	Liabilities	and	Equity."	SFAS	150,	which	became	effective	July	1,	2003,	requires	mandatorily redeemable	financial	instruments	to	be	classified	and	treated	as	liabilities	in	the	presentation	of	financial	position	and	results	of	operations.	The	only	effect	of implementing	SFAS	150	for	Entergy	is	the	inclusion	of	long-term	debt	and	preferred	stock	with	sinking	fund	under	the	liabilities	caption	in	Entergy's balance	sheet.	Entergy's	results	of	operations	and	cash	flows	were	not	affected	by	this	standard.

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

# NOTE	2.	RATE	AND	REGULATORY	MATTERS

# Electric	Industry	Restructuring	and	the	Continued	Application	of	SFAS	71

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

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

the	recommendation	that	retail	open	access	in	Entergy	Gulf	States'	Texas	service	territory,	including	corporate	unbundling,	occur	by	January	1,	2004, or	else	be	delayed	until	at	least	January	1,	2007.	If	retail	open	access	is	delayed	past	January	1,	2004,	Entergy	Gulf	States	seeks	authorization	to separate	into	two	bundled	utilities,	one	subject	to	the	retail	jurisdiction	of	the	PUCT	and	one	subject	to	the	retail	jurisdiction	of	the	LPSC.

the	recommendation	that	Entergy's	transmission	organization,	possibly	with	the	oversight	of	another	entity,	will	continue	to	serve	as	the	transmission authority	for	purposes	of	retail	open	access	in	Entergy	Gulf	States'	service	territory.

the	recommendation	that	the	decision	points	be	identified	that	would	require	prior	to	January	1,	2004,	the	PUCT's	determination,	based	upon	objective criteria,	whether	to	proceed	with	further	efforts	toward	retail	open	access	in	Entergy	Gulf	States'	Texas	service	territory.

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

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

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

# Regulatory	Assets

# Other	Regulatory	Assets

The	domestic	utility	companies	and	System	Energy	are	subject	to	the	provisions	of	SFAS	71,	"Accounting	for	the	Effects	of	Certain	Types	of	Regulation." Regulatory	assets	represent	probable	future	revenues	associated	with	certain	costs	that	are	expected	to	be	recovered	from	customers	through	the	ratemaking process.	In	addition	to	the	regulatory	assets	that	are	specifically	disclosed	on	the	face	of	the	balance	sheets,	the	table	below	provides	detail	of	"Other regulatory	assets"	that	are	included	on	the	balance	sheets	as	of	December	31,	2003	and	2002.

| DOE	Decommissioning	and	Decontamination	Fees	-	recovered	through	fuel	rates	until | $32.9 | $40.3 |
| :--- | :--- | :--- |
| \t\tDecember\t2006\t(Note\t9) |  |  |
| Asset\tRetirement\tObligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\n\t\t(Note\t9) | 464.9 | - |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates | 72.4 | 79.6 |
| Provisions\tfor\tstorm\tdamages\t-\trecovered\tthrough\tcost\tof\tservice | 123.3 | 93.9 |
| Postretirement\tbenefits\t-\trecovered\tthrough\t2013\t(Note\t11) | 21.5 | 23.9 |
| Pension\tcosts\t(Note\t11) | 134.0 | 157.8 |
| Depreciation\tre-direct\t-\trecovery\tbegins\tat\tstart\tof\tretail\topen\taccess\t(Note\t1) | 79.1 | 79.1 |
| River\tBend\tAFUDC\t-\trecovered\tthrough\tAugust\t2025\t(Note\t1) | 39.4 | 41.3 |
| Spindletop\tgas\tstorage\tlease\t-\trecovered\tthrough\tDecember\t2032 | 38.0 | 35.0 |
| Low-level\tradwaste\t-\trecovery\ttiming\tdependent\tupon\tpending\tlawsuit | 19.4 | 19.4 |
| 1994\tFERC\tSettlement\t-\trecovered\tthrough\tJune\t2004\t(Note\t2) | 4.0 | 12.1 |
| Sale-leaseback\tdeferral\t-\trecovered\tthrough\tJune\t2014\t(Note\t10) | 131.7 | 123.9 |
| Deferred\tfuel\t-\tnon-current\t-\trecovered\tthrough\trate\triders\tredetermined\tannually | 28.2 | 17.3 |
| Unamortized\tloss\ton\treaquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 164.4 | 155.2 |
| Other\t-\tvarious | 71.9 | 94.4 |
| Total | $1,425.1 | $973.2 |

# Deferred	fuel	costs

The	domestic	utility	companies	are	allowed	to	recover	certain	fuel	and	purchased	power	costs	through	fuel	mechanisms	included	in	electric	rates	that	are recorded	as	fuel	cost	recovery	revenues.	The	difference	between	revenues	collected	and	the	current	fuel	and	purchased	power	costs	is	recorded	as	"Deferred fuel	costs"	on	the	domestic	utility	companies'	financial	statements.	The	table	below	shows	the	amount	of	deferred	fuel	costs	as	of	December	31,	2003	and 2002	that	has	been	or	will	be	recovered	or	(refunded)	through	the	fuel	mechanisms	of	the	domestic	utility	companies.

| Entergy	Arkansas |  | $10.6 | $(42.6) |
| :--- | :--- | :--- | :--- |
| Entergy\tGulf\tStates | Entergy\tGulf\tStates | $118.4 | $100.6 |
| Entergy\tLouisiana | Entergy\tLouisiana | $30.6 | $(25.6) |
| Entergy\tMississippi | Entergy\tMississippi | $89.1 | $38.2 |
| Entergy | New | $(2.7) | $(14.9) |

# Entergy	Arkansas

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

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

# Entergy	Gulf	States

In	the	Texas	jurisdiction,	Entergy	Gulf	States'	rate	schedules	include	a	fixed	fuel	factor	to	recover	fuel	and	purchased	power	costs,	including	carrying charges,	not	recovered	in	base	rates.	Under	current	methodology,	semi-annual	revisions	of	the	fixed	fuel	factor	may	be	made	in	March	and	September	based on	the	market	price	of	natural	gas.	Entergy	Gulf	States	will	likely	continue	to	use	this	methodology	until	the	start	of	retail	open	access.	The	amounts collected	under	Entergy	Gulf	States'	fixed	fuel	factor	and	any	interim	surcharge	implemented	until	the	date	retail	open	access	commences	are	subject	to	fuel reconciliation	proceedings	before	the	PUCT.	In	the	Texas	jurisdiction,	Entergy	Gulf	States'	deferred	electric	fuel	costs	are	$116.6	million	as	of	December 31,	2003,	which	includes	the	following:

| Interim	surcharge | $87.0	million |
| :--- | :--- |
| Items\tto\tbe\taddressed\tas\tpart\tof\tunbundling | $29.0\tmillion |
| Imputed\tcapacity\tcharges | $9.3\tmillion |
| Other\t(includes\tover-recovery\tfor\tthe\tperiod\t9/03\t-\t12/03) | $(8.7)\tmillion |

The	PUCT	has	ordered	that	the	imputed	capacity	charges	be	excluded	from	fuel	rates	and	therefore	recovered	through	base	rates.	It	is	uncertain,	however,	as to	when	and	if	Entergy	Gulf	States	will	initiate	a	base	rate	proceeding	before	the	PUCT.	The	current	PUCT-approved	settlement	agreement	delaying	retail open	 access	 in	Texas	 requires	 a	 rate	 freeze	 during	 the	 delay	 period.	If	Entergy	Gulf	States	 implements	retail	open	access	without	a	Texas	base	rate proceeding,	it	is	possible	that	Entergy	Gulf	States	will	not	be	allowed	to	recover	imputed	capacity	charges	in	Texas	retail	rates	in	the	future.

In	January	2001,	Entergy	Gulf	States	filed	a	fuel	reconciliation	case	covering	the	period	from	March	1999	through	August	2000.	Entergy	Gulf	States	was

reconciling	approximately	$583	million	of	fuel	and	purchased	power	costs.	As	part	of	this	filing,	Entergy	Gulf	States	requested	authority	to	collect	$28 million,	plus	interest,	of	under-recovered	fuel	and	purchased	power	costs.	The	PUCT	decided	in	August	2002	to	reduce	Entergy	Gulf	States'	request	to approximately	$6.3	million,	including	interest	through	July	31,	2002.	Approximately	$4.7	million	of	the	total	reduction	to	the	requested	surcharge	relates	to nuclear	fuel	costs	that	the	PUCT	deferred	ruling	on	at	this	time.	In	October	2002,	Entergy	Gulf	States	appealed	the	PUCT's	final	order	in	Texas	District Court.	In	its	appeal,	Entergy	Gulf	States	is	challenging	the	PUCT's	disallowance	of	approximately	$4.2	million	related	to	imputed	capacity	costs	and	its disallowance	related	to	costs	for	energy	delivered	from	the	30%	non-regulated	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.

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

In	March	2004,	Entergy	Gulf	States	filed	with	the	PUCT	a	fuel	reconciliation	case	covering	the	period	September	2000	through	August	2003.	Entergy	Gulf States	is	reconciling	$1.43	billion	of	fuel	and	purchased	power	costs	on	a	Texas	retail	basis.	The	reconciliation	includes	$8.6	million	of	under-recovered costs	that	Entergy	Gulf	States	is	asking	to	roll	into	its	fuel	over/under-recovery	balance	to	be	addressed	in	the	next	appropriate	fuel	proceeding.	Hearings	are expected	to	occur	in	the	third	quarter	2004	with	a	final	PUCT	decision	expected	in	early	2005.

# Entergy	Gulf	States	(Louisiana)	and	Entergy	Louisiana

The	Louisiana	jurisdiction	of	Entergy	Gulf	States	and	Entergy	Louisiana	recover	electric	fuel	and	purchased	power	costs	for	the	upcoming	month	based upon	the	level	of	such	costs	from	the	prior	month.	Entergy	Gulf	States'	gas	rate	schedules	include	estimates	for	the	billing	month	adjusted	by	a	surcharge	or credit	for	deferred	fuel	expense	arising	from	monthly	reconciliations.

In	August	2000,	the	LPSC	authorized	its	staff	to	initiate	a	proceeding	to	audit	the	fuel	adjustment	clause	filings	of	Entergy	Louisiana	pursuant	to	a	November 1997	LPSC	general	order.	The	time	period	that	is	the	subject	of	the	audit	is	January	1,	2000	through	December	31,	2001.	In	September	2003,	the	LPSC	staff issued	its	audit	report	and	recommended	a	disallowance	with	regard	to	one	item.	The	issue	relates	to	the	alleged	failure	to	uprate	Waterford	3	in	a	timely manner.	The	LPSC	staff	has	quantified	the	possible	disallowance	as	between	$7.6	and	$14	million.	Entergy	Louisiana	is	currently	evaluating	the	LPSC	staff report	and	expects	to	contest	the	recommendation.	A	procedural	schedule	has	been	adopted	and	hearings,	which	also	will	address	issues	relating	to	the reasonableness	of	transmission	planning	and	purchases	of	power	from	affiliates,	the	potential	value	of	which	issues	cannot	yet	be	quantified,	are	scheduled to	begin	in	September	2004,	but	the	LPSC	staff	has	requested	a	delay	until	April	2005.

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

# Entergy	Mississippi

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

# Entergy	New	Orleans

Effective	June	2003,	Entergy	New	Orleans	electric	rate	schedules	 include	a	fuel	adjustment	 tariff	designed	 to	reflect	no	more	 than	 targeted	fuel	and purchased	power	costs	adjusted	by	a	surcharge	or	credit	for	deferred	fuel	expense	arising	from	monthly	reconciliations,	including	carrying	charges.	Entergy New	Orleans'	gas	rate	schedules	include	estimates	for	the	billing	month	adjusted	by	a	surcharge	or	credit	for	deferred	fuel	expense	arising	from	monthly reconciliations,	including	carrying	charges.

# Retail	Rate	Proceedings

# Filings	with	the	APSC	(Entergy	Arkansas)

# Retail	Rates

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

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

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

# Recovery	of	River	Bend	Costs

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

In	April	2002,	the	Travis	County	District	Court	issued	an	order	affirming	the	PUCT's	order	on	remand	disallowing	recovery	of	the	abeyed	plant	costs. Entergy	Gulf	States	appealed	this	ruling	to	the	Third	District	Court	of	Appeals.	In	July	2003,	the	Third	District	Court	of	Appeals	unanimously	affirmed	the judgment	of	the	Travis	County	District	Court.	After	considering	the	progress	of	the	proceeding	in	light	of	the	decision	of	the	Court	of	Appeals,	management has	concluded	that	it	is	prudent	to	accrue	for	the	loss	that	would	be	associated	with	a	final,	non-appealable	decision	disallowing	the	abeyed	plant	costs.	The net	carrying	value	of	the	abeyed	plant	costs	was	$107.7	million	as	of	June	30,	2003,	and	after	this	accrual	Entergy	Gulf	States	provided	for	all	potential	loss related	to	current	or	past	contested	costs	of	construction	of	the	River	Bend	plant.	Accrual	of	the	loss	was	recorded	in	the	second	quarter	2003	and	reduced net	income	by	$65.6	million.	In	January	2004,	the	Texas	Supreme	Court	asked	for	full	briefing	on	the	merits	of	the	case	in	response	to	Entergy	Gulf	States'

# petition	for	review.

# Filings	with	the	LPSC

# Annual	Earnings	Reviews	(Entergy	Gulf	States)

In	December	2002,	the	LPSC	approved	a	settlement	between	Entergy	Gulf	States	and	the	LPSC	staff	pursuant	to	which	Entergy	Gulf	States	agreed	to	make a	base	rate	refund	of	$16.3	million,	 including	 interest,	and	 to	 implement	a	$22.1	million	prospective	base	rate	reduction	effective	January	2003.	The settlement	discharged	any	potential	liability	for	claims	that	relate	to	Entergy	Gulf	States'	fourth,	fifth,	sixth,	seventh,	and	eighth	post-merger	earnings reviews.	Entergy	Gulf	States	made	the	refund	in	February	2003.	In	addition	to	resolving	and	discharging	all	liability	associated	with	the	fourth	through eighth	earnings	reviews,	the	settlement	provides	that	Entergy	Gulf	States	shall	be	authorized	to	continue	to	reflect	in	rates	a	ROE	of	11.1%	until	a	different ROE	is	authorized	by	a	final	resolution	disposing	of	all	issues	in	the	proceeding	that	was	commenced	with	Entergy	Gulf	States'	May	2002	filing.

In	May	2002,	Entergy	Gulf	States	filed	its	ninth	and	last	required	post-merger	analysis	with	the	LPSC.	The	filing	included	an	earnings	review	filing	for	the 2001	test	year	that	resulted	in	a	rate	decrease	of	$11.5	million,	which	was	implemented	effective	June	2002.	In	April	2003,	the	LPSC	staff	filed	testimony	in which	it	recommended	that	the	LPSC	require	a	rate	refund	of	$30.3	million	and	a	prospective	rate	reduction	of	$75.9	million,	before	taking	into	account	the $11.5	million	rate	reduction	that	Entergy	Gulf	States	implemented	effective	June	2002.	In	July	2003,	Entergy	Gulf	States	filed	testimony	rebutting	the	LPSC staff's	testimony	and	supporting	the	filing.	During	discovery,	the	LPSC	staff	requested	that	Entergy	Gulf	States	provide	updated	cost	of	service	data	to reflect	 changes	 in	 costs,	 revenues,	 and	 rate	 base	 through	 December	 31,	 2002.	In	 September	 2003,	 Entergy	 Gulf	 States	 supplied	 the	 updated	 data.	In December	2003,	the	LPSC	staff	recommended	a	rate	refund	of	$30.6	million	and	a	prospective	rate	reduction	of	approximately	$50	million.	Hearings	are scheduled	to	begin	in	April	2004.	Entergy	Gulf	States	cannot	predict	the	ultimate	outcome	of	this	proceeding.

# Retail	Rates	(Entergy	Louisiana)

In	January	2004,	Entergy	Louisiana	made	a	rate	filing	with	the	LPSC	requesting	a	base	rate	increase	of	approximately	$167	million.	In	that	filing,	Entergy Louisiana	noted	that	approximately	$73	million	of	the	base	rate	increase	was	attributable	to	certain	power	purchase	agreements,	the	implementation	of	which would,	based	on	current	natural	gas	prices,	produce	fuel	savings	for	customers	that	substantially	mitigate	the	impact	of	the	requested	base	rate	increase.	The filing	 also	 requested	 an	 allowed	 ROE	 of	 11.4%.	Entergy	Louisiana's	previously	authorized	ROE	midpoint	currently	 in	effect	 is	10.5%.	Hearings	are currently	set	for	September	2004.

# Filings	with	the	MPSC	(Entergy	Mississippi)

# Formula	Rate	Plan	Filings

In	December	2002,	the	MPSC	issued	a	final	order	approving	a	joint	stipulation	entered	into	by	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff in	October	2002.	The	final	order	results	in	a	$48.2	million	rate	increase,	or	about	a	5.3%	increase	in	overall	retail	revenues,	which	is	based	on	an	ROE	of 11.75%.	The	rate	increase	began	in	January	2003.	The	order	endorsed	a	new	power	management	rider	schedule	designed	to	more	efficiently	collect	capacity portions	of	purchased	power	costs.	Also,	the	order	provides	for	improvements	in	the	return	on	equity	formula	and	more	robust	performance	measures	for Entergy	Mississippi's	formula	rate	plan.	Under	the	provisions	of	Entergy	Mississippi's	formula	rate	plan,	a	bandwidth	is	placed	around	the	benchmark	ROE, and	 if	Entergy	Mississippi	earns	outside	of	 the	bandwidth	(as	well	as	outside	of	a	range-of-no-change	at	each	edge	of	 the	bandwidth),	 then	Entergy Mississippi's	rates	will	be	adjusted,	though	on	a	prospective	basis	only.	Under	the	provisions	of	the	order,	Entergy	Mississippi	will	make	its	next	formula rate	plan	filing	during	March	2004.	The	"benchmark	ROE"	set	out	in	Entergy	Mississippi's	March	2004	annual	formula	rate	plan	filing	likely	will	differ from	the	last	approved	ROE.	Under	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	however,	if	Entergy	Mississippi's	earned	ROE	is	above	the top	of	the	range-of-no-change	at	the	top	of	the	formula	rate	plan	bandwidth,	then	Entergy	Mississippi's	"Allowed	ROE"	for	the	next	twelve-month	period	is the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth;	and	Entergy	Mississippi's	retail	rates	are	set	at	that	halfway-point	ROE	level.	In the	situation	where	Entergy	Mississippi's	earned	ROE	is	not	above	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth,	then	Entergy	Mississippi's "Allowed	ROE"	for	the	next	twelve-month	period	is	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth.

# Grand	Gulf	Accelerated	Recovery	Tariff	(GGART)

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

# Filings	with	the	Council	(Entergy	New	Orleans)

# Rate	Proceedings

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

# Fuel	Adjustment	Clause	Litigation

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

Plaintiffs	also	filed	this	complaint	with	the	City	Council	in	order	to	initiate	a	review	by	the	City	Council	of	the	plaintiffs'	allegations	and	to	force	restitution to	ratepayers	of	all	costs	they	allege	were	improperly	and	imprudently	included	in	the	fuel	adjustment	filings.	Testimony	was	filed	on	behalf	of	the	plaintiffs

in	this	proceeding	asserting,	among	other	things,	that	Entergy	New	Orleans	and	other	defendants	have	engaged	in	fuel	procurement	and	power	purchasing practices	and	included	costs	in	Entergy	New	Orleans'	fuel	adjustment	that	could	have	resulted	in	New	Orleans	customers	being	overcharged	by	more	than $100	million	over	a	period	of	years.	Hearings	were	held	in	February	and	March	2002.	In	February	2004,	the	City	Council	approved	a	resolution	that	results in	a	refund	to	customers	of	$11.3	million,	including	interest	during	the	months	of	June	through	September	2004.	Entergy	New	Orleans	has	accrued	for	this liability	as	of	December	31,	2003.	The	resolution	concludes,	among	other	things,	that	the	record	does	not	support	an	allegation	that	Entergy	New	Orleans' actions	or	inactions,	either	alone	or	in	concert	with	Entergy	or	any	of	its	affiliates,	constituted	a	misrepresentation	or	a	suppression	of	the	truth	made	in	order to	obtain	an	unjust	advantage	of	Entergy	New	Orleans,	or	to	cause	loss,	inconvenience,	or	harm	to	its	ratepayers.		The	plaintiffs	have	appealed	the	City Council	resolution	to	the	state	court	in	Orleans	Parish.

# System	Energy's	1995	Rate	Proceeding

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

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

# FERC	Settlement

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

# NOTE	3.	INCOME	TAXES

(a) The	actual	cash	taxes	paid/(received)	were	$188,709	in	2003,	$57,856	in	2002,	and	($113,466)	in 2001.	Entergy	Louisiana's	mark-to-market	tax	accounting	election	significantly	reduced	taxes paid	in	2001	and	2002.	In	2001,	Entergy	Louisiana	changed	its	method	of	accounting	for	tax purposes	related	 to	 the	contract	 to	purchase	power	from	 the	Vidalia	project	(the	contract	 is discussed	in	Note	9	to	the	consolidated	financial	statements).	The	new	tax	accounting	method has	provided	a	cumulative	cash	flow	benefit	of	approximately	$805	million	through	2003,	which is	expected	to	reverse	in	the	years	2005	through	2031.	The	election	did	not	reduce	book	income tax	expense.	The	timing	of	the	reversal	of	this	benefit	depends	on	several	variables,	including	the price	of	power.	Approximately	half	of	the	consolidated	cash	flow	benefit	of	the	election	occurred in	2001	and	the	remainder	occurred	in	2002.

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

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

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

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

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

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

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

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

# maturity	date	may	occur.

The	short-term	borrowings	of	Entergy's	subsidiaries	are	limited	to	amounts	authorized	by	the	SEC.	The	current	limits	authorized	are	effective	through November	30,	2004.	Also,	under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	the	domestic	utility	companies	and	System	Energy	cannot	incur new	short-term	indebtedness	if	the	issuer's	common	equity	would	comprise	less	than	30%	of	its	capital.	In	addition	to	borrowing	from	commercial	banks, Entergy's	subsidiaries	are	authorized	 to	borrow	from	 the	Entergy	System	Money	Pool	(money	pool).	The	money	pool	 is	an	 inter-company	borrowing arrangement	designed	 to	reduce	Entergy's	subsidiaries'	dependence	on	external	short-term	borrowings.	Borrowings	from	 the	money	pool	and	external borrowings	combined	may	not	exceed	the	SEC	authorized	limits.	As	of	December	31,	2003,	Entergy's	subsidiaries'	authorized	limit	was	$1.6	billion	and	the outstanding	borrowing	from	the	money	pool	was	$147.1	million.	There	were	no	borrowings	outstanding	from	external	sources.	There	is	further	discussion	of commitments	for	long-term	financing	arrangements	in	Note	5	to	the	consolidated	financial	statements.

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

| Company | Expiration	Date | Amount	of<br>Facility | Amount	Drawn	as<br>of	Dec.	31,	2003 |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | April\t2004 | $63\tmillion | - |
| Entergy\tLouisiana | May\t2004 | $15\tmillion | - |
| Entergy\tMississippi | May\t2004 | $25\tmillion | - |

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

# NOTE	5.	LONG	-	TERM	DEBT

| 6.25%	Series	due	February	2003	-	Entergy	Mississippi | $- | $70,000 |
| :--- | :--- | :--- |
| 7.75%\tSeries\tdue\tFebruary\t2003\t-\tEntergy\tMississippi | - | 120,000 |
| 6.75%\tSeries\tdue\tMarch\t2003\t-\tEntergy\tGulf\tStates | - | 33,000 |
| 7.72%\tSeries\tdue\tMarch\t2003\t-\tEntergy\tArkansas | - | 100,000 |
| 8.5%\tSeries\tdue\tJune\t2003\t-\tEntergy\tLouisiana | - | 150,000 |
|  | - | 260,000 |
| 6.0%\tSeries\tdue\tOctober\t2003\t-\tEntergy\tArkansas | - | 155,000 |
| 6.625%\tSeries\tdue\tNovember\t2003\t-\tEntergy\tMississippi | - | 65,000 |
| 6.65%\tSeries\tdue\tMarch\t2004\t-\tEntergy\tNew\tOrleans | - | 30,000 |
| 8.25%\tSeries\tdue\tApril\t2004\t-\tEntergy\tGulf\tStates | 292,000 | 292,000 |
| 6.2%\tSeries\tdue\tMay\t2004\t-\tEntergy\tMississippi | 75,000 | 75,000 |
| Libor\t+\t0.65%\tSeries\tdue\tMay\t2004\t-\tEntergy\tMississippi | - | 50,000 |
| 8.25%\tSeries\tdue\tJuly\t2004\t-\tEntergy\tMississippi | - | 25,000 |
| Libor\t+\t1.3%\tSeries\tdue\tSeptember\t2004\t-\tEntergy\tGulf\nStates | - | 300,000 |
| 6.125%\tSeries\tdue\tJuly\t2005\t-\tEntergy\tArkansas | 100,000 | 100,000 |
| 8.125%\tSeries\tdue\tJuly\t2005\t-\tEntergy\tNew\tOrleans | 30,000 | 30,000 |
| 6.65%\tSeries\tdue\tAugust\t2005\t-\tEntergy\tArkansas | - | 115,000 |
| 6.77%\tSeries\tdue\tAugust\t2005\t-\tEntergy\tGulf\tStates | 98,000 | 98,000 |
| 8.0%\tSeries\tdue\tMarch\t2006\t-\tEntergy\tNew\tOrleans | - | 40,000 |
|  | 275,000 | - |
| 7.5%\tSeries\tdue\tAugust\t2007\t-\tEntergy\tArkansas | - | 100,000 |
| 4.875%\tSeries\tdue\tOctober\t2007\t-\tSystem\tEnergy | 70,000 | 70,000 |
| 5.2%\tSeries\tdue\tDecember\t2007\t-\tEntergy\tGulf\tStates | 200,000 | 200,000 |
| 6.5%\tSeries\tdue\tMarch\t2008\t-\tEntergy\tLouisiana | 115,000 | 115,000 |
| 4.35%\tSeries\tdue\tApril\t2008\t-\tEntergy\tMississippi | 100,000 | - |
| 6.45%\tSeries\tdue\tApril\t2008\t-\tEntergy\tMississippi | 80,000 | 80,000 |
| 3.6%\tSeries\tdue\tJune\t2008\t-\tEntergy\tGulf\tStates | 325,000 | - |
| 7.0%\tSeries\tdue\tJuly\t2008\t-\tEntergy\tNew\tOrleans | - | 30,000 |
| 3.875%\tSeries\tdue\tAugust\t2008\t-\tEntergy\tNew\tOrleans | 30,000 | - |
| 6.0%\tSeries\tdue\tDecember\t2012\t-\tEntergy\tGulf\tStates | 140,000 | 140,000 |
| 5.15%\tSeries\tdue\tFebruary\t2013\t-\tEntergy\tMississippi | 100,000 | - |
| 5.25%\tSeries\tdue\tAugust\t2013\t-\tEntergy\tNew\tOrleans | 70,000 | - |
| 5.25%\tSeries\tdue\tAugust\t2015\t-\tEntergy\tGulf\tStates | 200,000 | - |
| 6.75%\tSeries\tdue\tOctober\t2017\t-\tEntergy\tNew\tOrleans | 25,000 | 25,000 |
| 5.4%\tSeries\tdue\tMay\t2018\t-\tEntergy\tArkansas | 150,000 | - |

|  | 55,000 | 55,000 |
| :--- | :--- | :--- |
| Total\tgovernmental\tbonds | 1,532,430 | 1,643,380 |
| Other\tLong-Term\tDebt: |  |  |
| Note\tPayable\tto\tNYPA,\tnon-interest\tbearing,\t4.8%\timplicit\trate | $514,708 | $683,640 |
| Bank\tCredit\tFacility\t(Entergy\tCorporation\tand\tSubsidiaries,\tNote |  |  |
| 4) | - | 535,000 |
| Bank\tterm\tloan,\tEntergy\tCorporation,\tavg\trate\t2.98%,\tdue\t2005 | 60,000 | 60,000 |
| Bank\tterm\tloan,\tEntergy\tCorporation,\tavg\trate\t3.08%,\tdue\t2008 | 35,000 | - |
| 6.17%\tNotes\tdue\tMarch\t2008,\tEntergy\tCorporation | 72,000 | - |
| 6.23%\tNotes\tdue\tMarch\t2008,\tEntergy\tCorporation | 15,000 | - |
| 6.13%\tNotes\tdue\tSeptember\t2008,\tEntergy\nCorporation | 150,000 | - |
| 7.75%\tNotes\tdue\tDecember\t2009,\tEntergy\nCorporation | 267,000 | 267,000 |
| 6.58%\tNotes\tdue\tMay\t2010,\tEntergy\tCorporation | 75,000 | - |
| 6.9%\tNotes\tdue\tNovember\t2010,\tEntergy\tCorporation | 140,000 | - |
| 7.06%\tNotes\tdue\tMarch\t2011,\tEntergy\tCorporation | 86,000 | - |
| Long-term\tDOE\tObligation\t(g) | 154,409 | 152,804 |
| Waterford\t3\tLease\tObligation |  |  |
| 7.45%\t(Entergy\tCorporation\tand\tSubsidiaries,\tNote\t10) | 262,534 | 297,950 |
| Grand\tGulf\tLease\tObligation |  |  |
| 7.02%\t(Entergy\tCorporation\tand\tSubsidiaries,\tNote\t10) | 403,468 | 414,843 |
| Unamortized\tPremium\tand\tDiscount\t-\tNet | (11,853) | (13,741) |
|  | - | 79,029 |
| 8.5%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| Due\t2045\t-\tEntergy\tArkansas | 61,856 | 61,856 |
| 8.75%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| Due\t2046\t-\tEntergy\tGulf\tStates | 87,629 | 87,629 |
| 9.0%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| Due\t2045\t-\tEntergy\tLouisiana | 72,165 | 72,165 |
| Other | 9,966 | 10,464 |
| Total\tLong-Term\tDebt | 7,847,312 | 8,499,969 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 524,372 | 1,191,320 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $7,322,940 | $7,308,649 |
| Fair\tValue\tof\tLong-Term\tDebt\t(h) | $7,113,740 | $7,546,996 |

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

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

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

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

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

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

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

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

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

(In	Thousands)

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

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

# NOTE	6.	COMPANY-OBLIGATED	REDEEMABLE	PREFERRED	SECURITIES

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

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

# NOTE	7.	PREFERRED	STOCK

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

|  | Shares |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Authorized |  |  |  |
|  | and\tOutstanding | and\tOutstanding |  |  |
|  | 2003 | 2002 | 2003 | 2002 |
|  |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |
| Entergy\tCorporation |  |  |  |  |
| U.S.\tUtility\tPreferred\tStock: |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |
| Entergy\tArkansas,\t4.32%\t-\t7.88%\tSeries | 1,613,500 | 1,613,500 | $116,350 | $116,350 |
| Entergy\tGulf\tStates,\t4.20%\t-\t7.56%\tSeries | 473,268 | 473,268 | 47,327 | 47,327 |
| Entergy\tLouisiana,\t4.16%\t-\t8.00%\tSeries | 2,115,000 | 2,115,000 | 100,500 | 100,500 |
| Entergy\tMississippi,\t4.36%\t-\t8.36%\tSeries | 503,807 | 503,807 | 50,381 | 50,381 |
| Entergy\tNew\tOrleans,\t4.36%\t-\t5.56%\tSeries | 197,798 | 197,798 | 19,780 | 9,780 |
| Total\twithout\tsinking\tfund | 4,903,373 | 4,903,373 | $334,337 | $334,337 |

| Entergy	Gulf	States,	Adjustable	Rate	7.0%	(a) | 208,519 | 243,269 | $20,852 | $24,327 |
| :--- | :--- | :--- | :--- | :--- |
| Total\twith\tsinking\tfund | 208,519 | 243,269 | $20,852 | $24,327 |
| Fair\tValue\tof\tPreferred\tStock\nwith\tsinking\tfund\t(b) |  |  | $15,354 | $20,792 |

(a) Represents	weighted-average	annualized	rate	for	2003.

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

# All	outstanding	preferred	stock	is	cumulative.

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

|  | 2003 | Number	of	Shares<br>2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Preferred\tstock\tretirements |  |  |  |
| Entergy\tGulf\tStates |  |  |  |
| $100\tpar\tvalue | (34,500) | (18,579) | (49,237) |
| Entergy\tLouisiana |  |  |  |
| $100\tpar\tvalue | - | - | (350,000) |

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

# NOTE	8.	COMMON	EQUITY

# Common	Stock

# Treasury	Stock

Treasury	stock	activity	for	Entergy	for	2003	and	2002:

| Beginning	Balance,	January	1 | 25,752,410 | $747,331 | 27,441,384 | $758,820 |
| :--- | :--- | :--- | :--- | :--- |
| \t\tRepurchases | 155,000 | 8,135 | 2,885,000 | 118,499 |
| \t\tIssuances: |  |  |  |  |
| \t\tEquity\tOwnership/Equity\tAwards\tPlans | (6,622,095) | (194,057) | (4,567,054) | (129,748) |
| \t\tDirectors'\tPlan | (8,870) | (257) | (6,920) | (240) |
| Ending\tBalance,\tDecember\t31 | 19,276,445 | $561,152 | 25,752,410 | $747,331 |

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

# Equity	Compensation	Plan	Information

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

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

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

| Stock	price	volatility | 26.3% | 27.2% | 26.3% |
| :--- | :--- | :--- | :--- |
| Expected\tterm\tin\tyears | 6.2 | 5.0 | 5.0 |
| Risk-free\tinterest\trate | 3.3% | 4.2% | 4.9% |
| Dividend\tyield | 3.3% | 3.2% | 3.4% |
| Dividend\tpayment | $1.40 | $1.32 | $1.26 |

|  | 2003<br>Number<br>of	Options | Average<br>Exercise<br>Price | 2002<br>Number<br>of	Options | Average<br>Exercise<br>Price | 2001<br>Number<br>of	Options | Average<br>Exercise<br>Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Beginning-of-year\tbalance | 19,943,114 | $\t35.85 | 17,316,816 | $\t31.06 | 11,468,316 | $\t25.52 |
| Options\tgranted | 2,936,236 | 44.98 | 8,168,025 | 41.72 | 8,602,300 | 36.96 |
| Options\texercised | (6,927,000) | 33.12 | (4,877,688) | 28.62 | (2,407,783) | 25.85 |
| Options\tforfeited | (522,967) | 40.98 | (664,039) | 36.36 | (346,017) | 30.35 |
| End-of-year\tbalance | 15,429,383 | $\t38.64 | 19,943,114 | $\t35.85 | 17,316,816 | $\t31.06 |
| Options\texercisable\tat\tyear-\nend | 6,153,043 | $\t34.82 | 4,837,511 | $\t31.39 | 2,923,452 | $\t27.35 |
| Weighted-average\tfair\tvalue\nof |  |  |  |  |  |  |
| options\tat\ttime\tof\tgrant | $\t6.86 |  | $\t9.22 |  | $\t8.14 |  |

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

# Retained	Earnings	and	Dividend	Restrictions

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

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

# NOTE	9.	COMMITMENTS	AND	CONTINGENCIES

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

# Sales	Warranties	and	Indemnities

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

# Vidalia	Purchased	Power	Agreement

Entergy	Louisiana	has	an	agreement	extending	through	the	year	2031	to	purchase	energy	generated	by	a	hydroelectric	facility	known	as	the	Vidalia	project. Entergy	Louisiana	made	payments	under	the	contract	of	approximately	$112.6	million	in	2003,	$104.2	million	in	2002,	and	$86.0	million	in	2001.	If	the maximum	percentage	(94%)	of	the	energy	is	made	available	to	Entergy	Louisiana,	current	production	projections	would	require	estimated	payments	of approximately	$116.5	million	in	2004,	and	a	total	of	$3.6	billion	for	the	years	2005	through	2031.	Entergy	Louisiana	currently	recovers	the	costs	of	the

purchased	energy	through	its	fuel	adjustment	clause.	In	an	LPSC-approved	settlement	related	to	tax	benefits	from	the	tax	treatment	of	the	Vidalia	contract, Entergy	Louisiana	agreed	to	credit	rates	by	$11	million	each	year	for	up	to	ten	years,	beginning	in	October	2002.

# Nuclear	Insurance

# Third	Party	Liability	Insurance

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

1. The	primary	level	is	private	insurance	underwritten	by	American	Nuclear	Insurers	and	provides	liability	insurance	coverage	of	$300	million.	If	this amount	is	not	sufficient	to	cover	claims	arising	from	the	accident,	the	second	level,	Secondary	Financial	Protection,	applies.	An	industry-wide aggregate	limitation	of	$300	million	exists	for	domestically-sponsored	terrorist	acts.	There	is	no	limitation	for	foreign-sponsored	terrorist	acts.

2. Within	the	Secondary	Financial	Protection	level,	each	nuclear	plant	must	pay	a	retrospective	premium,	equal	to	its	proportionate	share	of	the	loss	in excess	of	the	primary	level,	up	to	a	maximum	of	$100.6	million	per	reactor	per	incident.	This	consists	of	a	$95.8	million	maximum	retrospective premium	plus	a	five	percent	surcharge	that	may	be	applied,	if	needed,	at	a	rate	that	is	presently	set	at	$10	million	per	year	per	nuclear	power	reactor. There	are	no	domestically-	or	foreign-sponsored	terrorism	limitations.

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

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

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

# Property	Insurance

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

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

# Primary	Layer	(per	plant)	-	$500	million	per	occurrence

Excess	Layer	(per	plant)	-	$100	million	per	occurrence

Blanket	Layer	(shared	among	all	plants)	-	$1.0	billion	per	occurrence

Total	limit	-	$1.6	billion	per	occurrence Deductibles:

$1.0	million	per	occurrence	-	Equipment	breakdown/failure $2.5	million	per	occurrence	-	Other	than	equipment	breakdown/failure

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

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

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

Deductibles:

$1.0	million	per	occurrence	-	Equipment	breakdown/failure

$1.0	million	per	occurrence	(all	plants	except	Vermont	Yankee	which	is	$500,000)	-	Other	than	equipment	breakdown/failure

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

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

Indian	Point	2	and	3,	FitzPatrick,	and	Pilgrim	(each	plant	has	an	individual	policy	with	the	noted	parameters):

$4.5	million	weekly	indemnity

$490	million	maximum	indemnity

Deductible:	12	week	waiting	period

Vermont	Yankee

$4.0	million	weekly	indemnity

$435	million	maximum	indemnity

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

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

licensees.	NRC	regulations	provide	that	the	proceeds	of	this	insurance	must	be	used,	first,	to	render	the	reactor	safe	and	stable,	and	second,	to	complete decontamination	 operations.	Only	after	proceeds	are	dedicated	for	such	use	and	regulatory	approval	is	secured	would	any	remaining	proceeds	be	made available	for	the	benefit	of	plant	owners	or	their	creditors.

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

# Nuclear	Decommissioning	and	Other	Retirement	Costs

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

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

Assets	and	liabilities	increased	approximately	$1.1	billion	for	the	domestic	utility	companies	and	System	Energy	as	a	result	of	recording	the	asset	retirement obligations	at	their	fair	values	of	$1.1	billion	as	determined	under	SFAS	143,	increasing	utility	plant	by	$287	million,	reducing	accumulated	depreciation	by $361	million	and	recording	the	related	regulatory	assets	of	$422	million.	The	implementation	of	SFAS	143	for	the	portion	of	River	Bend	not	subject	to	cost- based	ratemaking	decreased	earnings	by	approximately	$21	million	net-of-tax	($0.09	per	share)	as	a	result	of	a	one-time	cumulative	effect	of	accounting change.	In	accordance	with	ratemaking	treatment	and	as	required	by	SFAS	71,	the	depreciation	provisions	for	the	domestic	utility	companies	and	System Energy	 include	 a	 component	 for	 removal	 costs	 that	 are	 not	 asset	 retirement	 obligations	 under	 SFAS	 143.	 In	 accordance	 with	 regulatory	 accounting principles,	Entergy	has	recorded	a	regulatory	asset	for	certain	of	its	domestic	utility	companies	and	System	Energy	of	approximately	$72.4	million	as	of December	31,	2003	and	approximately	$79.6	million	as	of	December	31,	2002	to	reflect	an	estimate	of	incurred	but	uncollected	removal	costs	previously recorded	as	a	component	of	accumulated	depreciation.	The	decommissioning	and	retirement	cost	liability	for	certain	of	the	domestic	utility	companies	and System	Energy	includes	a	regulatory	liability	of	approximately	$26.8	million	as	of	December	31,	2003	and	approximately	$25.5	million	as	of	December	31, 2002	representing	an	estimate	of	collected	but	not	yet	incurred	removal	costs.	For	the	Non-Utility	Nuclear	business,	the	implementation	of	SFAS	143 resulted	in	a	decrease	in	liabilities	of	approximately	$595	million	due	to	reductions	in	decommissioning	liabilities,	a	decrease	in	assets	of	approximately	$340 million,	including	a	decrease	in	electric	plant	in	service	of	$315	million,	and	an	increase	in	earnings	in	the	first	quarter	of	2003	of	approximately	$155	million net-of-tax	($0.67	per	share)	as	a	result	of	a	one-time	cumulative	effect	of	accounting	change.

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

|  | Liabilities	as	of | SFAS	143 |  |  | Liabilities	as	of |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | December\t31,\t2002 | Adoption | Accretion | Spending | December\t31,\t2003 |
|  |  |  | (In\tMillions) |  |  |
| ANO\t1\t&amp;\tANO\t2 | $310.7 | $221.0 | $35.8 | $\t- | $567.5 |
| River\tBend | 237.0 | 41.2 | 20.6 | - | 298.8 |
| Waterford\t3 | 125.3 | 179.4 | 20.6 | - | 325.3 |
| Grand\tGulf\t1 | 153.5 | 137.2 | 21.8 | - | 312.5 |
| Pilgrim | 490.2 | (292.6) | 15.8 | - | 213.4 |
| Indian\tPoint\t1\t&amp;\t2 | 456.9 | (207.3) | 19.9 | 11.8 | 257.7 |
| Vermont\tYankee | 316.7 | (95.1) | 17.7 | - | 239.3 |
|  | $2,090.3 | ($16.2) | $152.2 | $\t11.8 | $2,214.5 |

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

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

|  | Year	Ended<br>December	31,<br>2002 | Year	Ended<br>December	31,<br>2001 |
| :--- | :--- | :--- |
| Asset\tretirement\tobligations\tactually\trecorded | $2,090,269 | $1,679,738 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $(46,041) | $28,512 |
| Asset\tretirement\tobligations\t-\tpro\tforma | $2,044,228 | $1,708,250 |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tas\treported | $599,360 | $726,196 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $14,119 | $9,613 |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tpro\tforma | $613,479 | $735,809 |
| Basic\tearnings\tper\taverage\tcommon\tshare\t-\tas\treported | $2.69 | $3.29 |

| Pro	forma	effect	of	SFAS	143 | $0.06 | $0.04 |
| :--- | :--- | :--- |
| Basic\tearnings\tper\taverage\tcommon\tshare\t-\tpro\tforma | $2.75 | $3.33 |
| Diluted\tearnings\tper\taverage\tcommon\tshare\t-\tas\treported | $2.64 | $3.23 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $0.06 | $0.04 |
| Diluted\tearnings\tper\taverage\tcommon\tshare\t-\tpro\tforma | $2.70 | $3.27 |

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

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

| ANO	1	&amp;	ANO	2 | $360.5 | $203.7 |
| :--- | :--- | :--- |
| River\tBend | 267.9 | 36.2 |
| Waterford\t3 | 152.0 | 132.3 |
| Grand\tGulf\t1 | 172.9 | 92.7 |
| Pilgrim | 491.9 | - |
| Indian\tPoint\t1\t&amp;\t2 | 485.9 | - |
| Vermont\tYankee | 347.4 | - |
|  | $2,278.5 | $464.9 |

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

# Employment	Litigation

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

# NOTE	10.	LEASES

# General

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

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

# Nuclear	Fuel	Leases

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

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

# Sale	and	Leaseback	Transactions

# Waterford	3	Lease	Obligations

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

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

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

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

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

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

# Grand	Gulf	1	Lease	Obligations

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

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

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

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

# Pension	Plans

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

# Components	of	Net	Pension	Cost

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

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

# Other	Postretirement	Benefits

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

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

# Components	of	Net	Postretirement	Benefit	Cost

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe | $37,799 | $29,199 | $24,225 |
| period |  |  |  |
| Interest\tcost\ton\tAPBO | 52,746 | 44,819 | 38,811 |
| Expected\treturn\ton\tassets | (15,810) | (14,066) | (12,578) |
| Amortization\tof\ttransition\tobligation | 15,193 | 17,874 | 17,874 |
| Amortization\tof\tprior\tservice\tcost | (925) | 992 | 992 |
| Recognized\tnet\t(gain)/loss | 12,369 | 1,874 | (1,506) |
| Curtailment\tloss | 57,958 | - | - |
| Special\ttermination\tbenefits | 5,444 | - | - |
| Net\tother\tpostretirement\tbenefit\tcost | $164,774 | $80,692 | $67,818 |

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

| Balance	at	beginning	of	year | $799,506 | $590,731 |
| :--- | :--- | :--- |
| Service\tcost | 37,799 | 29,199 |
| Interest\tcost | 52,746 | 44,819 |
| Actuarial\tloss | 115,966 | 159,143 |
| Benefits\tpaid | (48,379) | (35,861) |
| Plan\tamendments\t(a) | (84,722) | - |
| Plan\tparticipant\tcontributions | 7,074 | - |
| Curtailment | 56,369 | - |
| Special\ttermination\tbenefits | 5,444 | - |
| Acquisition\tof\tsubsidiary | - | 11,475 |
| Balance\tat\tend\tof\tyear | $941,803 | $799,506 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tbegininning\tof\tyear | $182,692 | $158,190 |
| Actual\treturn\ton\tplan\tassets | 22,794 | (11,559) |
| Employer\tcontributions | 63,265 | 59,542 |
| Plan\tparticipant\tcontributions | 7,074 | - |
| Benefits\tpaid | (48,379) | (35,861) |
| Acquisition\tof\tsubsidiary | - | 12,380 |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $227,446 | $182,692 |
| Funded\tstatus | ($714,357) | ($616,814) |
| Amounts\tnot\tyet\trecognized\tin\tthe\tbalance\tsheet: |  |  |
| Unrecognized\ttransition\tobligation | 44,815 | 114,724 |
| Unrecognized\tprior\tservice\tcost | (20,746) | 3,522 |
| Unrecognized\tnet\tloss | 336,005 | 245,795 |
| Accrued\tother\tpostretirement\tbenefit\tcost\trecognized\tin\tthe\tbalance\tsheet | ($354,283) | ($252,773) |

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

# Pension	and	Other	Postretirement	Plans'	Assets

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

|  | Pension |  | Postretirement | Postretirement |
| :--- | :--- | :--- | :--- | :--- |
|  | 2003 | 2002 | 2003 | 2002 |
| Domestic\tEquity\tSecurities | 56% | 50% | 37% | 34% |
| International\tEquity\tSecurities | 14% | 10% | 0% | 1% |
| Fixed\tIncome\tSecurities | 28% | 37% | 60% | 64% |
| Other | 2% | 3% | 3% | 1% |

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

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

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

|  | Pension | Postretirement |
| :--- | :--- | :--- |
| Domestic\tEquity\tSecurities | 54% | 37% |
| International\tEquity\tSecurities | 12% | 8% |
| Fixed\tIncome\tSecurities | 30% | 55% |
| Other\t(Cash\tand\tGACs) | 4% | 0% |

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

expected	return	on	assets	of	8.75%	(non-taxable	assets)	and	5.5%	(taxable	assets).

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

| Domestic	Equity	Securities | 49	%	to	59% | 32	%	to	42% |
| :--- | :--- | :--- |
| International\tEquity\tSecurities | 7%\tto\t17% | 3%\tto\t12% |
| Fixed\tIncome\tSecurities | 25%\tto\t35% | 50%\tto\t60% |
| Other | 0%\tto\t10% | 0%\tto\t5% |

# Accumulated	Pension	Benefit	Obligation

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

# Estimated	Future	Benefit	Payments

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

| 2004 | $96,764 | $53,666 |
| :--- | :--- | :--- |
| 2005 | $98,378 | $57,271 |
| 2006 | $100,411 | $58,389 |
| 2007 | $103,225 | $61,171 |
| 2008 | $107,120 | $63,393 |
| 2009\t-\t2013 | $631,594 | $358,648 |

# Contributions

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

# Additional	Information

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

| Other	comprehensive	income | ($1,639) | $17,016 |
| :--- | :--- | :--- |
| \t\t\t\t\tRegulatory\tassets | ($23,768) | $157,789 |

# Actuarial	Assumptions

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

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| \t\t\tPension | 6.25% | 6.75% | 7.50% |
| \t\t\tOther\tpostretirement | 6.71% | 6.75% | 7.50% |

| in	future	compensation	levels | 3.25% | 3.25% | 4.60% |
| :--- | :--- | :--- | :--- |
| Expected\tlong-term\trate\tof |  |  |  |
| \t\t\treturn\ton\tplan\tassets: |  |  |  |
| \t\t\t\t\t\tTaxable\tassets | 5.5% | 5.50% | 5.50% |
| \t\t\t\t\t\tNon-taxable\tassets | 8.75% | 8.75% | 9.00% |

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate | 6.75% | 7.5% | 7.5% |
| Weighted-average\trate\tof\nincrease |  |  |  |
| \t\t\tin\tfuture\tcompensation\tlevels | 3.25% | 4.6% | 4.6% |
| Expected\tlong-term\trate\tof |  |  |  |
| \t\t\treturn\ton\tplan\tassets: |  |  |  |
| \t\t\t\t\t\t\tTaxable\tassets | 5.5% | 5.5% | 5.5% |
| \t\t\t\t\t\t\tNon-taxable\tassets | 8.75% | 9.0% | 9.0% |

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

# Voluntary	Severance	Program

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

# Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003

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

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

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

# Defined	Contribution	Plans

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

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

make	matching	contributions	in	the	amount	of	50%	of	the	participants'	basic	contributions,	up	to	6%	of	their	eligible	earnings,	if	the	employees direct	their	company-matching	contribution	to	other	investment	funds.

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

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

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

# NOTE	12.	BUSINESS	SEGMENT	INFORMATION

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

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

# businesses.

# Entergy's	segment	financial	information	is	as	follows:

|  | U.S.	Utility | Non-Utility<br>Nuclear* | Energy<br>Commodity<br>Services* | All	Other* | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2003 |  |  |  |  |  |  |
| Operating\trevenues | $7,584,857 | $1,274,983 | $184,888 | $188,228 | ($38,036) | $9,194,920 |
| Deprec.,\tamort.\t&amp;\tdecomm. | 890,092 | 87,825 | 13,681 | 5,005 | - | 996,603 |
| Interest\tincome | 43,035 | 36,874 | 18,128 | 27,575 | (38,226) | 87,386 |
| Equity\tin\tearnings\t(loss)\tof |  |  |  |  |  |  |
| unconsolidated\tequity\taffiliates | (3) | - | 271,650 | - | - | 271,647 |
| Interest\tcharges | 419,111 | 34,460 | 15,193 | 75,787 | (38,225) | 506,326 |
| Income\ttaxes\t(credits) | 341,044 | 88,619 | 105,903 | (45,492) | - | 490,074 |
| Cumulative\teffect\tof\taccounting\nchange | (21,333) | 154,512 | 3,895 | - | - | 137,074 |
| Net\tincome\t(loss) | 492,574 | 300,799 | 180,454 | (23,360) | - | 950,467 |
| Total\tassets | 22,429,136 | 4,171,777 | 2,076,921 | 1,495,903 | (1,619,527) | 28,554,210 |
| Investment\tin\taffiliates\t-\tat\tequity | 211 | - | 1,081,462 | - | (28,345) | 1,053,328 |
| Cash\tpaid\tfor\tlong-lived\tasset | 1,233,208 | 281,377 | 44,284 | 10,074 | - | 1,568,943 |

|  | U.S.	Utility | Non-Utility<br>Nuclear* | Energy<br>Commodity<br>Services* | All	Other* | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2002 |  |  |  |  |  |  |
| Operating\trevenues | $6,773,509 | $1,200,238 | $294,670 | $40,729 | ($4,111) | $8,305,035 |
| Deprec.,\tamort.\t&amp;\tdecomm. | 800,257 | 88,733 | 21,465 | 5,143 | - | 915,598 |
| Interest\tincome | 23,231 | 71,262 | 26,140 | 35,433 | (37,741) | 118,325 |
| Equity\tin\tearnings\tof |  |  |  |  |  |  |
| unconsolidated\tequity\taffiliates | (2) | - | 183,880 | - | - | 183,878 |
| Interest\tcharges | 465,703 | 47,291 | 61,632 | 35,579 | (37,741) | 572,464 |
| Income\ttaxes\t(credits) | 313,752 | 132,726 | (141,288) | (11,252) | - | 293,938 |
| Net\tincome\t(loss) | 606,963 | 200,505 | (145,830) | (38,566) | - | 623,072 |
| Total\tassets | 21,630,523 | 4,482,308 | 2,167,472 | 1,327,354 | (2,103,291) | 27,504,366 |
| Investment\tin\taffiliates\t-\tat\tequity | 214 | - | 823,995 | - | - | 824,209 |
| Cash\tpaid\tfor\tlong-lived\tasset | 1,131,734 | 169,756 | 210,297 | 18,514 | - | 1,530,301 |

|  | U.S.	Utility | Non-Utility<br>Nuclear* | Energy<br>Commodity<br>Services* | All	Other* | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2001 |  |  |  |  |  |  |
| Operating\trevenues | $7,432,920 | $789,244 | $1,370,485 | $34,603 | ($6,353) | $9,620,899 |
| Deprec.,\tamort.\t&amp;\tdecomm. | 667,333 | 43,103 | 34,667 | 4,516 | - | 749,619 |
| Interest\tincome | 79,702 | 54,053 | 23,169 | 37,235 | (34,354) | 159,805 |
| Equity\tin\tearnings\tof |  |  |  |  |  |  |
| unconsolidated\tequity\taffiliates | - | - | 162,882 | - | - | 162,882 |
| Interest\tcharges | 576,705 | 55,717 | 74,953 | 41,558 | (34,353) | 714,580 |
| Income\ttaxes | 300,284 | 80,053 | 74,493 | 863 | - | 455,693 |
| Cumulative\teffect\tof\taccounting\nchange | - | - | 23,482 | - | - | 23,482 |
| Net\tincome\t(loss) | 574,554 | 127,880 | 105,939 | (57,866) | - | 750,507 |
| Total\tassets | 20,309,695 | 3,449,156 | 2,377,733 | 863,906 | (1,090,179) | 25,910,311 |
| Investment\tin\taffiliates\t-\tat\tequity | 214 | - | 765,889 | - | - | 766,103 |
| Cash\tpaid\tfor\tlong-lived\tasset | 1,110,484 | 126,880 | 199,387 | 599,886 | - | 2,036,637 |

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

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

The	power	development	business	obtained	contracts	in	October	1999	to	acquire	36	turbines	from	General	Electric.	Entergy's	rights	and	obligations under	the	contracts	for	22	of	the	turbines	were	sold	to	an	independent	special-purpose	entity	in	May	2001.	$178.0	million	of	the	charges,	including	an offsetting	benefit	of	$28.5	million	($18.5	million	net	of	tax)	related	to	the	sale	of	four	turbines	to	a	third	party,	is	a	provision	for	the	net	costs	resulting from	cancellation	or	sale	of	the	turbines	subject	to	purchase	commitments	with	the	special-purpose	entity.

$204.4	million	of	the	charges	result	from	the	write-off	of	Entergy	Power	Development	Corporation's	equity	investment	in	the	Damhead	Creek	project and	the	impairment	of	the	values	of	the	Warren	Power	power	plant,	the	Crete	project,	and	the	RS	Cogen	project.	This	portion	of	the	charges	reflects Entergy's	estimate	of	the	effects	of	reduced	spark	spreads	in	the	United	States	and	the	United	Kingdom.	These	estimates	are	based	on	various	sources of	information,	including	discounted	cash	flow	projections	and	current	market	prices.

$39.1	million	of	the	charges	relate	to	the	restructuring	of	the	non-nuclear	wholesale	assets	business,	including	impairments	of	administrative	fixed assets,	estimated	sublease	losses,	and	employee-related	costs	for	approximately	135	affected	employees.	These	restructuring	costs	are	included	in	the "Provision	for	turbine	commitments,	asset	impairments	and	restructuring	charges"	in	the	accompanying	consolidated	statement	of	income	were comprised	of	the	following:

|  | Restructuring<br>Costs | Paid	in<br>Cash | Non-Cash<br>Portion | Remaining<br>Accrual |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |  |
| Fixed\tasset\timpairments | $22.5 | $\t- | $22.5 | $\t- |
| Sublease\tlosses | 10.7 | 5.6 | - | 5.1 |
| Severance\tand\trelated\tcosts | 5.9 | 5.9 | - | - |
| Total | $39.1 | $11.5 | $22.5 | $5.1 |

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

# Geographic	Areas

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

| Domestic | $9,122,827 | $8,051,992 | $9,098,861 |
| :--- | :--- | :--- | :--- |
| Foreign | 72,093 | 253,043 | 522,038 |
| Consolidated | $9,194,920 | $8,305,035 | $9,620,899 |

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

| Domestic | $18,296,934 | $17,664,230 | $16,468,059 |
| :--- | :--- | :--- | :--- |
| Foreign | 1,863 | 773 | 421,870 |
| Consolidated | $18,298,797 | $17,665,003 | $16,889,929 |

# NOTE	13.	EQUITY	METHOD	INVESTMENTS

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

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

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

| Beginning	of	year | $824,209 | $766,103 | $136,487 |
| :--- | :--- | :--- | :--- |
| Additional\tinvestments | 4,668 | 36,372 | 471,102 |
| Income\tfrom\tthe\tinvestments | 271,647 | 183,878 | 162,882 |
| Other\tincome | 45,583 | 21,462 | 18,074 |
| Dividends\treceived | (105,142) | (73,902) | (21,191) |
| Currency\ttranslation\tadjustments | - | - | 138 |
| Dispositions\tand\tother\nadjustments | 12,363 | (109,704) | (1,389) |
| End\tof\tyear | $1,053,328 | $824,209 | $766,103 |

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

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

| Operating	revenues | $585,404 | $551,853 | $693,400 |
| :--- | :--- | :--- | :--- |
| Operating\tincome | $207,301 | $159,342 | $309,752 |
| Net\tincome | $172,595 | $68,095 | $226,039 |
| Balance\tSheet\tItems |  |  |  |
| Current\tassets | $2,576,630 | $2,334,133 |  |
| Noncurrent\tassets | $1,675,334 | $1,490,355 |  |
| Current\tliabilities | $1,757,663 | $1,782,385 |  |
| Noncurrent\tliabilities | $1,166,540 | $729,817 |  |

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

# Related-party	transactions	and	guarantees

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

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

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

# NOTE	14.	ACQUISITIONS	AND	DISPOSITIONS

# Asset	Acquisitions

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

The	acquisition	was	accounted	for	using	the	purchase	method.	The	results	of	operations	of	Vermont	Yankee	subsequent	to	the	purchase	date	have	been

included	in	Entergy's	consolidated	results	of	operations.	The	purchase	price	has	been	allocated	to	the	assets	acquired	and	liabilities	assumed	based	on	their estimated	fair	values	on	the	purchase	date.

# Indian	Point	2

In	September	2001,	Entergy's	Non-Utility	Nuclear	business	acquired	the	970	MW	Indian	Point	2	nuclear	power	plant	located	in	Westchester	County,	New York	 from	 Consolidated	 Edison.	Entergy	paid	approximately	$600	million	in	cash	at	the	closing	of	the	purchase	and	received	the	plant,	nuclear	fuel, materials	and	supplies,	a	purchase	power	agreement	(PPA),	and	assumed	certain	liabilities.	On	the	second	anniversary	of	the	Indian	Point	2	acquisition, Entergy's	nuclear	business	will	also	begin	to	pay	NYPA	$10	million	per	year	for	up	to	10	years	in	accordance	with	the	Indian	Point	3	purchase	agreement. Under	 the	 PPA,	 Consolidated	 Edison	 will	 purchase	 100%	 of	 Indian	 Point	 2's	 output	 through	 2004.	Consolidated	 Edison	 transferred	 a	 $430	 million decommissioning	trust	fund,	along	with	the	liability	to	decommission	Indian	Point	2	and	Indian	Point	1,	to	Entergy.	Entergy	acquired	Indian	Point	1	in	the transaction,	a	plant	that	has	been	shut	down	and	in	safe	storage	since	the	1970s.

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

# Asset	Dispositions

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

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

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

# NOTE	15.	RISK	MANAGEMENT	AND	FAIR	VALUES

# Market	and	Commodity	Risks

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

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

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

# Hedging	Derivatives

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

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

2003	is	approximately	five	years.	The	ineffective	portion	of	the	change	in	the	value	of	Entergy's	cash	flow	hedges	during	2003	was	insignificant.

# Fair	Values

# Commodity	Instruments

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

|  | 2003 |  | 2002 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Assets | Liabilities | Assets | Liabilities |
|  |  | (In\tThousands) |  |  |
| Consolidated\tsubsidiaries | $- | $- | $4,071 | $8,395 |
| Equity\tmethod\tinvestees\t(1) | $872,959 | $866,412 | $754,678 | $663,765 |

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

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

# Financial	Instruments

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

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

# NOTE	16.	QUARTERLY	FINANCIAL	DATA	(UNAUDITED)

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

| First	Quarter | $2,037,723 | $363,403 | $400,923(a) |
| :--- | :--- | :--- | :--- |
| \t\t\tSecond\tQuarter | 2,353,909 | 461,576 | 211,517 |
| \t\t\tThird\tQuarter | 2,700,125 | 619,005 | 371,650 |
| \t\t\tFourth\tQuarter | 2,103,163 | 40,571 | (33,623) |
| 2002: |  |  |  |
| \t\t\tFirst\tQuarter | $1,860,834 | $(55,670) | $(72,983) |
| \t\t\tSecond\tQuarter | 2,096,581 | 486,159 | 247,585 |
| \t\t\tThird\tQuarter | 2,468,875 | 653,695 | 366,800 |

# (a) Net	income	before	the	cumulative	effect	of	accounting	change	for	the	first	quarter

# Earnings	per	Average	Common	Share

|  | Basic | Diluted | Basic | Diluted |
| :--- | :--- | :--- | :--- | :--- |
| First\tQuarter | $1.77(b) | $1.73(b) | $(0.36) | $(0.36) |
| Second\tQuarter | $0.91 | $0.89 | $1.08 | $1.06 |
| Third\tQuarter | $1.60 | $1.57 | $1.61 | $1.59 |
| Fourth\tQuarter | $(0.19) | $(0.18) | $0.36 | $0.35 |

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

# ENTERGY'S	BUSINESS	(continued)

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

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

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

# Customers

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

|  |  | Electric	Customers | Electric	Customers | Gas	Customers |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Area\tServed | (In\tThousands) | (%) | (In\tThousands) | (%) |
| Entergy\tArkansas | Portions\tof\tArkansas | 660 | 25% |  |  |
| Entergy\tGulf\tStates | Portions\tof\tTexas\tand\tLouisiana | 709 | 27% | 90 | 38% |
| Entergy\tLouisiana | Portions\tof\tLouisiana | 657 | 25% |  |  |
| Entergy\tMississippi | Portions\tof\tMississippi | 416 | 16% |  |  |
| Entergy\tNew\tOrleans | City\tof\tNew\tOrleans* | 189 | 7% | 147 | 62% |
| Total\tcustomers |  | 2,631 | 100% | 237 | 100% |

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

# Electric	Energy	Sales

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

Selected	2003	Electric	Energy	Sales	Data

Entergy

System

|  | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy | Entergy	(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tGWh) |  |  |  |
| Electric\tDepartment: |  |  |  |  |  |  |  |
| \t\tSales\tto\tretail |  |  |  |  |  |  |  |
| \t\t\tcustomers | 19,650 | 33,805 | 27,778 | 12,891 | 5,844 | - | 99,968 |
| Sales\tfor\tresale: |  |  |  |  |  |  |  |
| \t\tAffiliates | 7,036 | 1,185 | 1,344 | 112 | 1,312 | 9,812 | - |
| \t\tOthers | 5,399 | 3,358 | 132 | 331 | 28 | - | 9,248 |
| \t\t\t\t\tTotal | 32,085 | 38,348 | 29,254 | 13,334 | 7,184 | 9,812 | 109,216 |
| Average\tuse\tper |  |  |  |  |  |  |  |
| \tresidential\tcustomer |  |  |  |  |  |  |  |
| \t(KWh) | 12,669 | 15,791 | 15,382 | 14,631 | 12,556 | - | 14,498 |

(a) Includes	the	effect	of	intercompany	eliminations.

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

| Customer	Class | %	of	Sales	Volume | %	of	Revenue |
| :--- | :--- | :--- |
| Residential | 30.0 | 36.3 |
| Commercial | 23.7 | 25.5 |
| Industrial\t(a) | 35.4 | 28.1 |
| Wholesale | 8.5 | 7.5 |
| Governmental | 2.4 | 2.6 |

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

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

# Selected	2003	Natural	Gas	Sales	Data

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

| Entergy	New	Orleans | Electric	Operating<br>Revenue | Natural	Gas<br>Revenue |
| :--- | :--- | :--- |
| Residential | 41% | 54% |
| Commercial | 37% | 21% |
| Industrial | 6% | 11% |
| Governmental/Municipal | 16% | 14% |

# Retail	Rate	Regulation

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

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

# Mississippi 	 The	MPSC	has	recommended	not	pursuing	open	access	at	this	time. 13.0%

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.

(2) Under	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	if	Entergy	Mississippi's	earned ROE	 is	 above	 the	 top	 of	 the	 range-of-no-change	 at	 the	 top	 of	 the	 bandwidth,	 then	 Entergy Mississippi's	rates	are	reduced	by	50	percent	of	the	difference	between	the	earned	ROE	and	the	top of	the	bandwidth.	In	such	circumstance,	Entergy	Mississippi's	'Allowed	ROE'	for	the	next	twelve- month	period	is	the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth	-- Entergy	Mississippi's	retail	rates	are	set	at	that	halfway-point	ROE	level.	(Before	the	comparison is	made	of	the	earned	ROE	to	the	bandwidth,	the	bandwidth	can	be	adjusted	for	performance measures	by	as	much	as	1%.	Rates	are	adjusted	pursuant	to	the	Entergy	Mississippi's	formula	rate plan	on	a	prospective	basis	only.)	In	the	situation	where	Entergy	Mississippi's	earned	ROE	is	not above	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth,	then	Entergy	Mississippi's 'Allowed	ROE'	for	the	next	twelve-month	period	is	the	top	of	the	range-of-no-change	at	the	top	of the	bandwidth.	If	earnings	are	below	the	bandwidth	range,	rates	are	increased	by	50	percent	of	the difference	between	the	earned	ROE	and	the	bottom	of	the	bandwidth.	Under	the	provisions	of Entergy	Mississippi's	formula	rate	plan,	each	annual	formula	rate	plan	filing	incorporates	a	revised calculation	of	the	benchmark	ROE.	The	benchmark	ROE	set	out	in	the	March	15,	2004,	formula rate	plan	filing	likely	will	differ	from	the	last	approved	ROE.	Entergy	Mississippi	anticipates	that the	March	15,	2004,	filing	will	show	an	allowed	regulatory	earnings	range	of	9.3%	to	12.2%. Entergy	Mississippi	does	not	anticipate	a	reduction	in	revenues	going	forward.

(3) If	Entergy	New	Orleans	earns	outside	the	bandwidth	range,	rates	will	be	adjusted	on	a	prospective basis.	Under	 the	 gas	 formula	 rate	 plan,	 if	 earnings	 are	 above	 the	 bandwidth	 range,	 rates	 are reduced	by	100	percent	of	the	overage,	and	if	below,	increased	by	100	percent	of	the	shortfall.	In addition,	if	the	ROE	falls	between	11.5%	and	12.25%,	rates	are	reduced	by	60	percent	of	the difference,	and	if	the	ROE	falls	between	10.25%	and	11%,	rates	are	increased	by	40	percent	of	the differential.	Under	the	electric	formula	rate	plan,	rates	are	adjusted	accordingly	by	100	percent	of the	amount	of	any	overage	or	shortfall.	Entergy	New	Orleans	may	earn	up	to	13.25%	under	the electric	formula	rate	plan	provided	that	the	increase	is	caused	by	its	share	of	energy	cost	savings under	the	generation	performance-based	recovery	plan	discussed	below.

# 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.

# Performance-Based	Rate	Plan

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

# Texas	Jurisdiction	-	River	Bend	Costs

In	March	1998,	the	PUCT	issued	an	order	disallowing	recovery	of	$1.4	billion	of	company-wide	River	Bend	plant	costs	which	have	been	held	in	abeyance since	1988.	Entergy	Gulf	States	appealed	the	PUCT's	decision	on	this	matter	to	a	Texas	District	Court.	A	June	1999	settlement	agreement	addresses	the treatment	of	abeyed	plant	costs,	and,	as	a	result,	Entergy	Gulf	States	removed	the	reserve	for	these	costs	and	reduced	the	carrying	value	of	the	plant	asset	in 1999.	In	another	settlement,	Entergy	Gulf	States	agreed	not	to	prosecute	its	appeal	before	January	1,	2002	and	agreed	to	cap	the	recovery	of	Entergy	Gulf States'	 River	 Bend	 abeyed	 investment	 at	 $115	 million	 net	 plant	 in	 service,	 less	 depreciation.	The	Texas	 District	 Court	 affirmed	 the	 PUCT	 decision disallowing	recovery	of	the	abeyed	plant	costs	in	April	2002,	and	Entergy	Gulf	States	appealed	that	ruling	to	the	Third	District	Court	of	Appeals.	In	July 2003,	the	Third	District	Court	of	Appeals	unanimously	affirmed	the	judgment	of	the	Travis	County	District	Court.	After	considering	the	progress	of	the proceeding	in	light	of	the	decision	of	the	Court	of	Appeals,	management	has	concluded	that	it	is	prudent	to	accrue	for	the	loss	that	would	be	associated	with a	final,	non-appealable	decision	disallowing	the	abeyed	plant	costs.	The	net	carrying	value	of	the	abeyed	plant	costs	was	$107.7	million	as	of	June	30,	2003, and	after	this	accrual	Entergy	Gulf	States	has	provided	for	all	potential	loss	related	to	current	or	past	contested	costs	of	construction	of	the	River	Bend	plant. Accrual	of	the	loss	was	recorded	in	the	second	quarter	2003	and	reduced	net	income	by	$65.6	million.	In	January	2004,	the	Texas	Supreme	Court	asked	for full	briefing	on	the	merits	of	the	case	in	response	to	Entergy	Gulf	States'	petition	for	review.	The	abeyed	plant	costs	are	discussed	in	more	detail	in	Note	2	to the	domestic	utility	companies	and	System	Energy	financial	statements.

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

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

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

Entergy	Louisiana

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

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

In	September	2002,	Entergy	Louisiana	settled	a	proceeding	that	concerned	a	contract	entered	into	by	Entergy	Louisiana	to	purchase	through	the	year	2031 energy	generated	by	a	hydroelectric	facility	known	as	the	Vidalia	project.	In	the	settlement,	the	LPSC	approved	Entergy	Louisiana's	proposed	treatment	of the	regulatory	impact	of	a	tax	accounting	election	related	to	that	project.	In	general,	the	settlement	permits	Entergy	Louisiana	to	keep	a	portion	of	the	tax benefit	in	exchange	for	bearing	the	risk	associated	with	sustaining	the	tax	treatment.	The	LPSC	settlement	divided	the	term	of	the	Vidalia	contract	into	two segments:	2002-2012	and	2013-2031.	During	the	first	eight	years	of	the	2002-2012	segment,	Entergy	Louisiana	agreed	to	credit	rates	by	flowing	through	its fuel	adjustment	calculation	$11	million	each	year,	beginning	monthly	in	October	2002.	Entergy	Louisiana	must	credit	rates	in	this	way	and	by	this	amount even	if	Entergy	Louisiana	is	unable	to	sustain	the	tax	deduction.	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	9	to	the	domestic utility	companies	and	System	Energy	financial	statements	contains	further	discussion	of	the	obligations	related	to	the	Vidalia	project.

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

# Performance-Based	Formula	Rate	Plan

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

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

In	May	2003,	Entergy	Mississippi	filed	and	the	MPSC	approved	a	change	in	Entergy	Mississippi's	energy	cost	recovery	rider.	Under	the	MPSC's	order, Entergy	Mississippi	has	deferred	until	2004	the	collection	of	fuel	under-recoveries	for	the	first	and	second	quarters	of	2003	that	would	have	been	collected in	the	third	and	fourth	quarters	of	2003,	respectively.	The	deferred	amount	of	$77.6	million	plus	carrying	charges	will	be	collected	through	the	energy	cost recovery	rider	over	a	twelve-month	period	that	began	in	January	2004.

# Formula	Rate	Plans

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

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

Entergy	New	Orleans'	electric	rate	schedules	include	a	fuel	adjustment	tariff	designed	to	reflect	no	more	than	targeted	fuel	and	purchased	power	costs, adjusted	by	a	surcharge	or	credit	for	deferred	fuel	expense	arising	from	the	monthly	reconciliation	of	actual	fuel	and	purchased	power	costs	incurred	with fuel	cost	revenues	billed	to	customers,	including	carrying	charges.	The	adjustment	also	includes	the	difference	between	non-fuel	Grand	Gulf	1	costs	paid	by Entergy	New	Orleans	and	the	estimate	of	such	costs,	which	are	included	in	base	rates,	as	provided	in	Entergy	New	Orleans'	Grand	Gulf	1	rate	settlements. Entergy	New	Orleans'	gas	rate	schedules	include	an	adjustment	to	reflect	estimated	gas	costs	for	the	billing	month,	adjusted	by	a	surcharge	or	credit	similar to	that	included	in	the	electric	fuel	adjustment	clause,	including	carrying	charges.	In	November	2003,	the	Council	passed	a	resolution	implementing	a package	of	measures	developed	by	Entergy	New	Orleans	and	the	Council	Advisors	to	protect	customers	from	potential	gas	price	spikes	during	the	2003	- 2004	winter	heating	season.	These	measures	include:	expansion	of	Entergy	New	Orleans'	financial	hedging	plan	for	its	purchase	of	wholesale	gas,	and deferral	of	collection	of	up	to	$4	million	of	gas	costs	in	the	event	that	the	average	residential	customer's	gas	bill	were	to	exceed	a	threshold	level,	which management	does	not	expect.

# Franchises

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

In	 Louisiana,	 Entergy	 Gulf	 States	 holds	 non-exclusive	 franchises,	 permits,	 or	 certificates	 of	 convenience	 and	 necessity	 to	 provide	 electric	 service	 in approximately	55	incorporated	municipalities	and	the	unincorporated	areas	of	approximately	19	parishes,	and	to	provide	gas	service	in	the	City	of	Baton Rouge	and	the	unincorporated	areas	of	two	parishes.	In	Texas,	Entergy	Gulf	States	holds	a	certificate	of	convenience	and	necessity	from	the	PUCT	to

provide	electric	service	 to	areas	within	approximately	24	counties	 in	eastern	Texas,	and	holds	non-exclusive	franchises	 to	provide	electric	service	 in approximately	65	incorporated	municipalities.	Entergy	Gulf	States	typically	is	granted	50-year	franchises	in	Texas	and	60-year	franchises	in	Louisiana. Entergy	Gulf	States'	current	electric	franchises	will	expire	during	2007	-	2045	in	Texas	and	during	2015	-	2046	in	Louisiana.

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

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

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

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

# Property	and	Other	Generation	Resources

# Generating	Stations

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

# Owned	and	Leased	Capability	MW(1)

| Company | Total | Gas/Oil | Nuclear | Coal | Internal<br>Combustion | Hydro |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | 4,552 | 1,524 | 1,694 | 1,189 | 75 | 70 |
| Entergy\tGulf\tStates | 6,483 | 4,890 | 966 | 627 | - | - |
| Entergy\tLouisiana | 5,357 | 4,270 | 1,075 | - | 12 | - |
| Entergy\tMississippi | 2,908 | 2,493 | - | 408 | 7 | - |
| Entergy\tNew\tOrleans | 886 | 875 | - | - | 11 | - |
| System\tEnergy | 1,086 | - | 1,086 | - | - | - |
| Total | 21,272 | 14,052 | 4,821 | 2,224 | 105 | 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	in light	of	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,	which	until	recently	it	made	up	almost	entirely	with	purchases	from	the	spot	market	as	needed.	In	the	fall	of	2002,	Entergy began	a	process	of	issuing	requests	for	proposal	for	supply-side	resources.	The	first	request	for	proposal	sought	resources	to	meet	both	the	domestic	utility companies'	summer	2003	and	longer-term	resource	needs	through	a	broad	range	of	wholesale	power	products,	including	short-term	(less	than	one	year), limited-term	(1	to	3	years)	and	long-term	contractual	products	and	asset	acquisitions.	The	following	table	illustrates	the	results	of	the	request	for	proposal process	for	limited	and	short-term	products.	All	of	the	signed	contracts	were	with	non-affiliates,	with	the	exception	of	185	MW	from	RS	Cogen	contracted through	the	Fall	2002	request	for	proposal.

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

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	as	a	result	of	the	proposal	process	seeking	approval	to	enter	into	transactions	with	affiliates	as	shown	in	the	following	table:

customer	protection

mechanisms.

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 proceeding	is	set	for	hearing	in	June	2004.

In	October	2003,	the	LPSC	approved	on	an	interim	basis	a	method	of	calculating	the	avoided	cost	payments	for	energy	that	Entergy	Gulf	States	and	Entergy Louisiana	make	to	qualified	facilities	pursuant	to	PURPA.	Up	to	2,220	MW	of	qualifying	facility	power	is	now	being	put	to	Entergy	in	Louisiana,	much	of	it during	off-peak	periods	when	wholesale	power	prices	are	typically	lower	than	the	avoided	cost	price	calculated	under	the	prior	method	for	that	same	hour. On	an	interim	basis,	the	LPSC	approved	calculating	the	payments	in	a	manner	that	more	accurately	reflects	the	market	price	of	energy.	The	LPSC-approved calculation	is	expected	to	reduce	the	amount	that	Entergy	Gulf	States	and	Entergy	Louisiana	customers	pay	for	fuel	and	purchased	power.	Entergy's	RS Cogen	joint	venture	operates	a	qualified	facility,	and	management	expects	its	results	to	be	negatively	affected	by	the	LPSC-approved	calculation.	During	the interim	period,	the	LPSC	will	require	Entergy	to	keep	records	of	the	required	payments	calculated	under	both	the	interim	method	and	the	previous	method,

and	if	the	LPSC	decides	to	go	back	to	the	previous	methodology,	additional	payments	to	the	qualified	facilities	will	be	required.	If	such	additional	payments are	required	to	be	made,	they	will	be	recoverable	through	the	fuel	adjustment	charges	billed	by	Entergy	Gulf	States	and	Entergy	Louisiana	to	their	retail customers.

# Interconnections

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

# Gas	Property

As	of	December	31,	2003,	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,	1,482	miles	of	gas	distribution	pipeline,	and	1,031	miles	of	gas	service	pipeline	from	the	distribution	mains	to the	customers.	As	of	December	31,	2003,	the	gas	properties	of	Entergy	Gulf	States,	which	are	located	in	and	around	Baton	Rouge,	Louisiana,	were	not material	to	Entergy	Gulf	States'	financial	position.

# Titles

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

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

# Fuel	Supply

The	generation	portfolio	of	the	U.S.	Utility	contains	a	high	percentage	of	natural	gas	and	nuclear	generation.	The	sources	of	generation	and	average	fuel	cost per	kWh	for	the	domestic	utility	companies	and	System	Energy	for	the	years	2001-2003	were:

Actual	2003	and	projected	2004	sources	of	generation	for	the	domestic	utility	companies	and	System	Energy,	including	proposed	power	purchases	from affiliates	under	power	purchase	agreements	in	2004,	are:

|  |  | Natural	Gas<br>2003 | 2004 | Fuel	Oil<br>2003 | 2004 | Nuclear<br>2003 | 2004 | Coal<br>2003 | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas\t(a) | Entergy\tArkansas\t(a) | 2% | - | - | - | 64% | 66% | 34% | 33% |
| Entergy\tGulf\tStates | Entergy\tGulf\tStates | 44% | 31% | 1% | - | 36% | 40% | 19% | 29% |
| Entergy\tLouisiana | Entergy\tLouisiana | 43% | 35% | 5% | 2% | 51% | 61% | 1% | 2% |
| Entergy\tMississippi | Entergy\tMississippi | 22% | 12% | 31% | 27% | - | - | 47% | 61% |
| Entergy\nOrleans | New | 65% | 47% | - | - | 24% | 38% | 11% | 15% |
| System\tEnergy |  | - | - | - | - | 100%(b) | 100%(b) | - | - |
| U.S.\tUtility\t(a) |  | 26% | 18% | 4% | 2% | 52% | 59% | 18% | 21% |

(a) Hydroelectric	power	provided	less	than	1%	of	Entergy	Arkansas'	generation	in	2003	and	is expected	to	provide	approximately	1%	of	its	generation	in	2004.

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

Many	factors,	including	wellhead	deliverability,	storage	and	pipeline	capacity,	and	demand	requirements	of	end	users,	influence	the	availability	and	price	of natural	gas	supplies	for	power	plants.	Demand	is	tied	to	weather	conditions	as	well	as	to	the	prices	of	other	energy	sources.	Entergy's	supplies	of	natural	gas are	expected	to	be	adequate	in	2004.	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.

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	2004.	Entergy	Arkansas	has	entered	into	three	medium	term	(three	year)	contracts	for	approximately 52%	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	20%	of its	2004	coal	requirement	committed	in	a	number	of	one-	to	two-year	contracts.	Additional	coal	requirements	for	both	Independence	and	White	Bluff	are satisfied	by	spot	market	or	over	the	counter	purchases.	Additionally,	Entergy	Arkansas	has	a	long-term	railroad	transportation	contract	for	the	delivery	of coal	to	both	White	Bluff	and	Independence	that	expires	in	2011.	A	second	carrier	now	delivers	a	portion	of	White	Bluff's	coal	requirements	under	a	long- term	transportation	agreement	that	began	in	2002	and	expires	on	December	31,	2006.

Entergy	Gulf	States	has	a	test	burn	agreement	for	the	supply	of	low-sulfur	Wyoming	coal	for	Nelson	Unit	6.	The	company	is	negotiating	with	this	supplier for	an	agreement	that	would	be	sufficient	to	satisfy	its	2004	requirements	for	that	unit	at	current	consumption	rates.	The	operator	of	Big	Cajun	2,	Unit	3, Louisiana	Generating	LLC,	has	advised	Entergy	Gulf	States	that	it	has	coal	supply	and	transportation	contracts	that	should	provide	an	adequate	supply	of coal	for	the	operation	of	Big	Cajun	2,	Unit	3	for	the	foreseeable	future.	Additionally,	Entergy	Gulf	States	has	transportation	requirements	contracts	with railroads	to	deliver	coal	to	Nelson	Unit	6	through	December	31,	2004.	Each	of	the	two	contracts	governs	the	movement	of	about	half	of	the	plant's requirements	and	the	base	contract	provides	flexibility	for	shipping	up	to	all	of	the	plant's	requirements.

# Nuclear	Fuel

The	nuclear	fuel	cycle	consists	of	the	following:

mining	and	milling	of	uranium	ore	to	produce	a	concentrate;

conversion	of	the	concentrate	to	uranium	hexafluoride	gas;

enrichment	of	the	hexafluoride	gas;

fabrication	of	nuclear	fuel	assemblies	for	use	in	fueling	nuclear	reactors;	and

disposal	of	spent	fuel.

System	Fuels,	a	company	owned	by	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans,	is	responsible	for	contracts	to acquire	nuclear	material	to	be	used	in	fueling	Entergy's	utility	nuclear	units,	except	for	River	Bend.	System	Fuels	also	maintains	inventories	of	such materials	during	the	various	stages	of	processing.	The	domestic	utility	companies	purchase	enriched	uranium	hexafluoride	from	System	Fuels,	but	contract separately	for	the	fabrication	of	their	own	nuclear	fuel.	The	requirements	for	River	Bend	are	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 that	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	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	10	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	discussion	of	nuclear	fuel	leases.

# Natural	Gas	Purchased	for	Resale

Entergy	New	Orleans	has	several	suppliers	of	natural	gas.	Its	system	is	interconnected	with	three	interstate	and	three	intrastate	pipelines.	Entergy	New Orleans'	primary	suppliers	currently	are	Bridgeline	Gas	Distributors	and	Louisiana	Gas	Services.	Entergy	New	Orleans	has	a	"no-notice"	service	gas purchase	contract	with	Bridgeline	Gas	Marketing,	LLC	which	guarantees	Entergy	New	Orleans	gas	delivery	at	specific	delivery	points	and	at	any	volume within	the	minimum	and	maximum	set	forth	in	the	contract	amounts.	The	Bridgeline	Gas	Marketing,	LLC	gas	supply	is	transported	to	Entergy	New	Orleans pursuant	to	a	transportation	service	agreement	with	Entergy-Koch's	Gulf	South	Pipeline	Co.	This	service	is	subject	to	FERC-approved	rates.	Entergy	New Orleans	has	firm	contracts	with	its	two	intrastate	suppliers	and	also	makes	interruptible	spot	market	purchases.	In	recent	years,	natural	gas	deliveries	to Entergy	New	Orleans	have	been	subject	primarily	to	weather-related	curtailments.	However,	Entergy	New	Orleans	experienced	no	such	curtailments	in 2003.

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	spanning	five	years.	The	contract	will	continue	annually	at	the	end	of	the	term	unless	prior	notice	is	given	by	Entergy	Gulf States.

# Wholesale	Rate	Matters

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	1	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.

In	June	2001,	the	domestic	utility	companies,	the	LPSC,	and	the	City	Council	filed	the	following	amendments	to	the	System	Agreement	pursuant	to	a settlement	agreement:

the	Texas	retail	jurisdictional	division	of	Entergy	Gulf	States	will	terminate	its	participation	in	the	System	Agreement,	except	for	the	aspects related	to	transmission	equalization,	when	Texas	implements	retail	open	access	for	Entergy	Gulf	States,	and	that	division	will	sell	up	to	five percent	of	its	generation	to	those	other	domestic	utility	companies	who	choose	to	purchase	their	share	of	the	five	percent;	and

the	service	schedule	developed	to	track	changes	in	energy	costs	resulting	from	the	Entergy-Gulf	States	Utilities	merger	is	modified	to	include one	final	true-up	of	fuel	costs	when	the	Texas	retail	jurisdictional	division	of	Entergy	Gulf	States	ceases	participation	in	the	System	Agreement, after	which	the	service	schedule	will	no	longer	be	applicable	for	any	purpose.

The	LPSC	and	the	City	Council	commenced	a	proceeding	at	FERC	in	June	2001.	Pursuant	to	a	settlement	agreement	approved	by	the	City	Council	in	May 2003,	the	City	Council	withdrew	as	a	complainant	from	the	proceeding,	but	continues	to	participate	as	an	intervenor.	In	this	proceeding,	the	LPSC	alleges that	the	rough	production	cost	equalization	required	by	FERC	under	the	System	Agreement	and	the	Unit	Power	Sales	Agreement	has	been	disrupted	by changed	circumstances.	The	LPSC	requests	that	FERC	amend	the	System	Agreement	or	the	Unit	Power	Sales	Agreement	or	both	to	achieve	full	production cost	equalization	or	to	restore	rough	production	cost	equalization.	The	complaint	does	not	seek	a	change	in	the	total	amount	of	the	costs	allocated	by	either the	System	Agreement	or	the	Unit	Power	Sales	Agreement.	In	addition	the	LPSC	alleges	that	provisions	of	the	System	Agreement	relating	to	minimum-run and	must-run	units,	the	methodology	of	billing	versus	dispatch,	and	the	use	of	a	rolling	twelve-month	average	of	system	peaks	(12	CP),	increase	costs	paid by	ratepayers	 in	 the	LPSC's	 jurisdiction.	Several	parties	intervened	in	the	proceeding,	including	the	APSC	and	the	MPSC.	The	APSC	and	the	MPSC responses	opposed	the	relief	sought	by	the	LPSC.

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

In	February	2002,	 the	FERC	established	a	refund	effective	period	for	 the	proceeding	consisting	of the	15	months	following	September	13,	2001.	A subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

In	January	2003,	the	domestic	utility	companies	filed	testimony	in	the	case,	showing	that	over	the	life	of	the	System	Agreement	the	relative	total	production costs	of	the	domestic	utility	companies	are	roughly	equal,	and	suggesting	that	no	changes	to	the	System	Agreement	such	as	those	sought	by	the	LPSC	are appropriate.	In	April	2003,	witnesses	on	behalf	of	the	FERC	staff	filed	testimony	in	the	proceeding	suggesting	that	full	production	cost	equalization	should not	be	adopted	by	the	FERC	in	this	case,	and	that	when	measured	over	a	suitably	long	period,	the	total	production	costs	of	the	domestic	utility	companies were	roughly	equal	and	were	likely	to	remain	so,	given	the	Entergy	System's	proposed	resource	plan.	Hearings	in	the	proceeding	ended	in	late-August	2003. The	 Initial	 Decision	 of	 the	 FERC	ALJ	 was	 released	 on	 February	 6,	 2004.	The	ALJ	 concludes	 that	 full	 production	 cost	 equalization	 should	 not	 be implemented;	that	the	Entergy	System	currently	is	not	in	rough	production	cost	equalization	and	is	not	likely	to	be	in	rough	production	cost	equalization	for the	foreseeable	future;	and	that	the	appropriate	remedy	to	achieve	rough	equalization	is	to	have	the	low	cost	companies	compensate	the	high	cost	companies whenever	one	or	more	companies'	annual	total	production	costs	from	2003	forward	differ	by	more	than	+/-	7.5%	from	the	Entergy	System	average	annual total	production	costs,	or	whenever	the	three	year	average	of	one	or	more	companies'	total	production	costs	(commencing	with	the	three	years	2004	through 2006,	and	yearly	 thereafter)	differ	by	more	 than	+/-	5%	from	 the	Entergy	System	average	 total	production	costs	during	any	 three	year	cycle.	In	 the calculation	of	what	each	company's	total	production	costs	are,	the	ALJ	determined	that	the	full	cost	of	Vidalia	project	power	purchases	by	Entergy	Louisiana should	be	included,	but	the	ALJ	rejected	other	adjustments	proposed	by	the	LPSC.	Also,	the	ALJ	determined	that	the	average	of	the	four	highest	monthly demand	peaks	for	the	year	(4	CP)	should	be	used	for	calculating	reserve	sharing	costs,	rather	than	the	current	12	CP	method.	Finally,	the	ALJ	determined that	there	is	no	valid	issue	concerning	"billing	versus	dispatch"	in	the	rate	schedule	by	which	exchange	energy	is	priced,	MSS-3,	that	MSS-3	has	not	been misapplied	or	misinterpreted	by	Entergy,	and	that	MSS-3	should	not	be	changed.		The	ALJ's	Initial	Decision	did	not	specifically	address	refund	exposure.

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

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	pre-empted	by	federal	law	from	reviewing	and interpreting	FERC	rate	schedules	that	are	part	of	the	System	Agreement,	and	from	subsequently	enforcing	that	interpretation.	The	LPSC	interpreted	a System	Agreement	rate	schedule	in	the	unrelated	case,	and	then	sought	to	enforce	its	interpretation.	The	Louisiana	Supreme	Court	affirmed.	In	2003,	the U.S.	Supreme	Court	ruled	in	Entergy	Louisiana's	favor	and	reversed	the	decisions	of	the	LPSC	and	the	Louisiana	Supreme	Court.

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

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

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

generation	resources	in	its	service	territory,	such	as	the	pending	purchase	of	the	Perryville	power	plant	by	Entergy	Louisiana.

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

# FERC	Notice	of	Proposed	Rulemaking	-	Standard	Market	Design

In	July	2002,	FERC	issued	a	notice	of	proposed	rulemaking	to	establish	a	standardized	transmission	service	and	wholesale	electric	market	design	(SMD NOPR).	The	proposed	rule	would	have	required,	among	other	things,	that	all	transmission	owners	turn	control	of	their	facilities	over	to	an	independent transmission	provider.	Comments	on	the	proposed	rule	were	filed	in	2002	and	2003.	Several	technical	conferences	on	the	issues	contained	in	the	SMD NOPR	 were	 also	 held	 during	 November	 and	 December	 2002.	Certain	 retail	 regulators	 within	 Entergy's	 service	 territory	 expressed	 opposition	 to	 the proposed	rulemaking.	In	a	letter	sent	to	the	Chairman	of	the	FERC,	retail	regulators	from	Alabama,	Arkansas,	Florida,	Georgia,	Kentucky,	Louisiana,	North Carolina	South	Carolina,	Tennessee,	and	Virginia	expressed	their	belief	that	an	"incremental	and	voluntary	approach"	to	RTO	formation	and	wholesale market	development	is	necessary	and	appropriate	for	the	Southeast.	In	the	letter,	the	retail	regulators	identified	certain	threshold	issues	that	FERC	must commit	to	(including,	among	other	things,	that	the	FERC	would	not	assert	jurisdiction	over	the	transmission	component	of	bundled	retail	service,	that	native load	customers	would	retain	the	same	or	equivalent	rights	to	use	the	transmission	system	as	they	have	today,	the	immediate	implementation	of	participant funding,	and	that	RTO	formation	should	be	supported	by	evidence	that	the	costs	of	RTO	formation	are	outweighed	by	the	benefits)	prior	to	further	detailed discussions	between	the	FERC	and	retail	regulators	concerning	the	development	of	RTOs	and	SMD.	A	similar	letter	was	submitted	separately	by	retail regulators	from	Mississippi.	In	response	to	the	comments	received	by	all	market	participants,	in	April	2003	the	FERC	issued	a	white	paper	on	the	SMD issues.	While	the	white	paper	responded	to	many	of	the	concerns	raised	by	members	of	the	industry	as	well	as	the	retail	regulators,	the	white	paper continued	to	require	utilities	to	turn	control	of	their	transmission	system	over	to	an	independent	entity	and	did	not	eliminate	the	jurisdictional	issues	raised	by such	a	transfer	of	control.

Additionally,	in	November	2003,	the	FERC	issued	an	order	making	a	preliminary	finding	that	"the	laws,	rules,	and	regulations	of	Virginia	and	Kentucky	are preventing	AEP	from	fulfilling	both	its	voluntary	commitment	in	1999,	as	part	of	merger	proceedings,	to	join	an	RTO	and	its	application	to	join	an	RTO pursuant	to	the	Commission's	Order	No.	2000"	and	that,	pursuant	to	Section	205(a)	of	the	Public	Utility	Regulatory	Policies	Act	(PURPA),	the	Commission "may	exempt	AEP	from	those	provisions	of	Kentucky	and	Virginia	law	or	rule	or	regulation."	 Based	on	these	preliminary	findings,	the	FERC	then	set	the matter	for	hearing.	A	hearing	was	held	in	late	January/early	February	2004	and	the	Administrative	Law	Judge	is	scheduled	to	issue	his	initial	decision	during March	2004.

Separately,	the	conference	report	on	the	Fiscal	Year	2003	Omnibus	Appropriations	bill	signed	into	law	contains	language	directing	the	Department	of Energy	to	prepare	an	independent	analysis	of	the	effect	of	the	proposed	SMD	rule	on	wholesale	and	retail	electric	prices,	the	safety	and	reliability	of generation	and	transmission	facilities,	and	state	utility	regulation.

# System	Energy	and	Related	Agreements

System	Energy	recovers	costs	related	to	its	interest	in	Grand	Gulf	1	through	rates	charged	to	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and Entergy	New	Orleans	for	capacity	and	energy	under	the	Unit	Power	Sales	Agreement	(described	below).	In	December	1995,	System	Energy	implemented	a $65.5	million	rate	increase,	subject	to	refund.	In	July	2001,	the	rate	increase	proceeding	became	final,	with	FERC	approving	a	prospective	10.94%	return	on equity,	which	is	less	than	System	Energy	sought.	FERC's	decision	also	affected	other	aspects	of	System	Energy's	charges	to	the	domestic	utility	companies that	it	supplies	with	power.	In	1998,	FERC	approved	requests	by	Entergy	Arkansas	and	Entergy	Mississippi	to	accelerate	a	portion	of	their	Grand	Gulf purchased	power	obligations.	Entergy	Arkansas'	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	1	to	Entergy	Arkansas	(36%),	Entergy	Louisiana	(14%),	Entergy	Mississippi	(33%),	and	Entergy	New	Orleans	(17%).	Each	of	these	companies	is obligated	to	make	payments	to	System	Energy	for	its	entitlement	of	capacity	and	energy	on	a	full	cost-of-service	basis	regardless	of	the	quantity	of	energy delivered,	so	long	as	Grand	Gulf	1	remains	in	commercial	operation.	Payments	under	the	Unit	Power	Sales	Agreement	are	System	Energy's	only	source	of operating	revenue.	The	financial	condition	of	System	Energy	depends	upon	the	continued	commercial	operation	of	Grand	Gulf	1	and	the	receipt	of	such payments.	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	generally	recover	payments	made	under	the	Unit	Power Sales	Agreement	through	rates	charged	to	their	customers.

In	the	case	of	Entergy	Arkansas	and	Entergy	Louisiana,	payments	are	also	recovered	through	sales	of	electricity	from	their	respective	retained	shares	of

Grand	Gulf	1.	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	1-related	costs	and	recovers	the	remaining	78%	of	its	share	in	rates.	In	the	event	that	Entergy	Arkansas	is	not	able	to	sell	its	retained	share	to third	parties,	it	may	sell	such	energy	to	its	retail	customers	at	a	price	equal	to	its	avoided	cost,	which	is	currently	less	than	Entergy	Arkansas'	cost	from	its retained	share.	Entergy	Arkansas	has	life-of-resources	purchased	power	agreements	with	Entergy	Louisiana	and	Entergy	New	Orleans	pending	regulatory approvals	that	sell	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	1,	subject	to	certain	terms	and	conditions.	Entergy	Louisiana	retains	and	does	not	recover	from	retail	ratepayers,	18%	of	its	14% share	of	the	costs	of	Grand	Gulf	1	capacity	and	energy	and	recovers	the	remaining	82%	of	its	share	in	rates.	Entergy	Louisiana	is	allowed	to	recover	through the	fuel	adjustment	clause	4.6	cents	per	kWh	for	the	energy	related	to	its	retained	portion	of	these	costs.	Non-fuel	operation	and	maintenance	costs	for	Grand Gulf	1	are	recovered	through	Entergy	Louisiana's	base	rates.	Alternatively,	Entergy	Louisiana	may	sell	such	energy	to	non-affiliated	parties	at	prices	above the	fuel	adjustment	clause	recovery	amount,	subject	to	the	LPSC's	approval.

# Availability	Agreement

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

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

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

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

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

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

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

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

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

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

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

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	1,	subject	to	the	owner	oversight	of	Entergy Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy,	respectively.	Entergy	Services	and	Entergy	Operations	provide	their	services	to	the domestic	utility	companies	and	System	Energy	on	an	"at	cost"	basis,	pursuant	to	service	agreements	approved	by	the	SEC	under	PUHCA.

# 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

|  |  | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | 2003 | 2002 | 2001 | 2000 | 1999 |
| Entergy\tArkansas | Entergy\tArkansas | 3.17 | 2.79 | 3.29 | 3.01 | 2.08 |
| Entergy\tGulf\tStates | Entergy\tGulf\tStates | 1.51 | 2.49 | 2.36 | 2.60 | 2.18 |
| Entergy\tLouisiana | Entergy\tLouisiana | 3.93 | 3.14 | 2.76 | 2.33 | 3.48 |
| Entergy\tMississippi | Entergy\tMississippi | 3.06 | 2.48 | 2.14 | 2.33 | 2.44 |
| Entergy\nOrleans | New | 1.73 | (b) | (c) | 2.66 | 3.00 |
| System\tEnergy |  | 3.66 | 3.25 | 2.12 | 2.41 | 1.90 |

# Ratios	of	Earnings	to	Combined	Fixed

# Charges	and	Preferred	Dividends

# Years	Ended	December	31,

|  | Ratios	of	Earnings	to	Combined	Fixed | Ratios	of	Earnings	to	Combined	Fixed | Ratios	of	Earnings	to	Combined	Fixed | Ratios	of	Earnings	to	Combined	Fixed |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Charges\tand\tPreferred\tDividends\nYears\tEnded\tDecember\t31, | Charges\tand\tPreferred\tDividends\nYears\tEnded\tDecember\t31, | Charges\tand\tPreferred\tDividends\nYears\tEnded\tDecember\t31, |  |
|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| Entergy\tArkansas | 2.79 | 2.53 | 2.99 | 2.70 | 1.80 |
| Entergy\tGulf\tStates\t(a) | 1.45 | 2.40 | 2.21 | 2.39 | 1.86 |
| Entergy\tLouisiana | 3.46 | 2.86 | 2.51 | 2.93 | 3.09 |
| Entergy\tMississippi | 2.77 | 2.27 | 1.96 | 2.09 | 2.18 |
| Entergy\tNew\tOrleans | 1.59 | (b) | (c) | 2.43 | 2.74 |

(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.

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.

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

# Property

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

| Power	Plant | Acquired | Location | Maximum<br>Capacity | Reactor	Type | License<br>Expiration<br>Date |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Pilgrim | July\t1999 | \t Plymouth,\tMA | \t 688\tMW | \t Boiling\tWater\tReactor | 2012 |
| FitzPatrick | \t Nov.\t2000 | \t Oswego,\tNY | \t 825\tMW | \t Boiling\tWater\tReactor | 2014 |
| Indian\tPoint\t3 | \t Nov.\t2000 | \t Westchester | \t 994\tMW | \t Pressurized\tWater\tReactor | 2015 |
|  |  | County,\tNY |  |  |  |
| Indian\tPoint\t2 | Sept.\t2001 | \t Westchester | \t 984\tMW | \t Pressurized\tWater\tReactor | 2013 |
|  |  | County,\tNY |  |  |  |
| Vermont | July\t2002 | \t Vernon,\tVT | \t 510\tMW | \t Boiling\tWater\tReactor | 2012 |

Non-Utility	Nuclear	added	46	MW	of	capacity	in	2003	through	uprates,	and	plans	an	additional	202	MW	of	uprates	through	2005.	Planned	uprates	totaling 95	MW	for	Vermont	Yankee	are	currently	pending	approval	by	the	NRC	and	the	Public	Service	Board	of	Vermont.

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

# Energy	and	Capacity	Sales

Entergy's	 Non-Utility	 Nuclear	 business	 has	 entered	 into	 unit-contingent	 power	 purchase	 agreements	 (PPAs),	 with	 the	 exception	 noted	 below,	 with creditworthy	counterparties	to	sell	the	energy	produced	by	its	power	plants	at	prices	established	in	the	PPAs.	Following	is	a	summary	of	the	amount	of	the Non-Utility	Nuclear	business'	output	that	is	currently	sold	forward	under	physical	or	financial	contracts	at	fixed	prices:

Percent	of	capacity	sold	forward:

| Bundled	capacity	and	energy	contracts | 55% | 15% | 12% | 13% | 13% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \t\tCapacity\tcontracts | 28% | 15% | 6% | 3% | 0% |
| Total | 83% | 30% | 18% | 16% | 13% |
| Planned\tMW\tin\toperation | 4,111 | 4,203 | 4,203 | 4,203 | 4,203 |
| Average\tcapacity\tcontract\tprice\tper\tkW\tper\tmonth | $2.4 | $1.3 | $0.6 | $0.7 | N/A |
| Blended\tCapacity\tand\tEnergy\t(based\ton\trevenues) |  |  |  |  |  |
| %\tof\tplanned\tgeneration\tand\tcapacity\tsold\tforward | 99% | 49% | 28% | 13% | 4% |
| Average\tcontract\trevenue\tper\tMWh | $39 | $37 | $35 | $34 | $38 |

Power	and	capacity	not	sold	forward	under	contracts	with	fixed	prices	are	subject	to	price	fluctuations	in	the	market.	Entergy	may	be	required	to	provide credit	support	in	the	form	of	guarantees	in	order	to	secure	PPAs.

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.

# 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	$12	million	in	2004, $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	top	decile	in	the	industry	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.

# Other	Matters

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

On	July	25,	2003,	FEMA	issued	its	notice	of	certification	of	the	Indian	Point	Emergency	Plan.	NRC	followed	soon	thereafter	with	its	endorsement.	On August	22,	2003,	Westchester	County	filed	an	administrative	appeal	of	the	FEMA	ruling	that	the	Emergency	Plans	are	adequate	to	protect	the	public	health and	 safety.	FEMA	regulations	on	emergency	plans	provide	for	appeals	 in	only	 two	situations:	(1)	FEMA's	approval	or	disapproval	of	a	radiological emergency	response	plan	(RERP)	for	a	nuclear	power	facility;	and	(2)	FEMA's	determination	to	withdraw	approval	for	a	state	or	local	RERP.	In	both	cases, the	appeal	process	is	the	same.

The	Energy	Commodity	Services	segment	includes	the	operations	of	Entergy-Koch	(50%	owned	by	Entergy)	and	Entergy's	non-nuclear	wholesale	assets business.	Entergy-Koch	is	engaged	in	two	major	businesses:	energy	commodity	marketing	and	trading	that	includes	physical	and	financial	natural	gas	and power	as	well	as	other	energy	and	weather-related	contracts	through	Entergy-Koch	Trading	and	gas	transportation	and	storage	through	Gulf	South	Pipeline. Entergy's	non-nuclear	wholesale	assets	business	owns	power	plants	capable	of	generating	about	1,800	MW	of	electricity	for	sale	in	the	wholesale	market. Previously,	Entergy's	Energy	Commodity	Services	business	also	engaged	in	power	development	activities	through	Entergy	Wholesale	Operations,	but	these activities	were	discontinued	in	early	2002.

# Entergy-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.

Entergy-Koch	is	engaged	in	two	major	businesses:	Entergy-Koch	Trading	and	Gulf	South	Pipeline.	Each	of	these	businesses	targets	contributions	from	40- 60%	of	Entergy-Koch's	earnings.	Entergy-Koch	currently	has	over	700	employees	and	over	$3.7	billion	in	assets.

# Entergy-Koch	Trading

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

# Regulatory	Investigations	Relating	to	Trading	Business

In	April	2003,	Entergy-Koch	Trading	received	a	subpoena	from	the	Commodity	Futures	Trading	Commission	(CFTC)	seeking	information	on	gas	and power	trading	activities	of	Entergy-Koch	Trading	and	affiliated	companies,	which	would	include	Entergy	Power	Marketing	Corp.	(in	operation	prior	to	the formation	of	Entergy-Koch	on	February	1,	2001),	including	information	about	trading	activities	relating	to	"wash	trades"	as	well	as	information	furnished	to energy	industry	publications	in	2001	and	2002.

In	January	2004,	the	CFTC	filed	and	approved	an	order	settling	the	administrative	action	against	Entergy-Koch	Trading.	Entergy-Koch	Trading	agreed	to pay	 a	 civil	 penalty	 of	 $3	 million	 without	 admitting	 or	 denying	 the	 CFTC's	 findings.	The	order	cites	Entergy-Koch	Trading	for	reporting	false	price information.	The	CFTC	has	notified	Entergy-Koch	Trading	and	Entergy	that	this	settlement	concludes	the	issues	that	were	the	subject	of	their	investigation.

# Gulf	South	Pipeline

Gulf	South	Pipeline	owns	and	operates	an	interstate	natural	gas	pipeline	system	in	the	Gulf	Coast	region	and	provides	critical	links	to	many	major	markets nationwide.	Gulf	South	Pipeline	gathers	natural	gas	from	the	Gulf	South	region	and	transports	it	to	local	distribution	companies,	industrial	facilities,	power generators,	utility	companies,	other	pipelines,	and	natural	gas	marketing	companies.	The	Gulf	South	Pipeline's	existing	system	comprises	approximately 8,000	miles	of	pipeline,	including	both	transmission	and	gathering	systems,	with	connections	to	more	than	100	pipelines	including	Texas	Eastern,	Transco and	Florida	Gas	Transmission.	The	pipeline	system	covers	parts	of	Texas,	Louisiana,	Mississippi,	Alabama,	and	Florida	and	connects	to	the	Henry	Hub, located	in	Vermilion	Parish,	Louisiana.

Gulf	South's	operational	flexibility	is	enhanced	by	its	Bistineau	and	Jackson	storage	facilities	with	total	working	storage	capacity	of	68.5	Bcf.	Additionally, Gulf	South	Pipeline	is	developing	a	natural	gas	salt	dome	storage	facility	-	Magnolia	Gas	Storage	located	near	Napoleonville,	Louisiana.	This	new	facility, which	was	expected	to	be	in	service	by	early	2004,	complements	the	existing	storage	at	Bistineau	and	Jackson,	and	offers	multiple	pipeline	interconnects providing	increased	reliability	for	customers	and	opportunities	for	Gulf	South	to	improve	gas	flows	across	its	system.	The	facility	is	expected	to	have	an initial	working	capacity	of	approximately	4.1	Bcf	and	be	expanded	to	6.5	Bcf	in	2007.	In	December	2003,	natural	gas	bubbling	occurred	at	the	site.	Gulf South	has	been	involved	in	mitigating	the	effects	of	the	incident,	and	is	still	evaluating	how	the	incident	will	affect	its	plans	to	provide	storage	services	at Magnolia,	but	the	facility	will	not	be	in	service	early	in	2004	as	originally	planned.

# Entergy-Koch,	LP	Agreement	Details

Although	the	ownership	interests	of	Entergy	and	Koch	Industries	are	equal,	the	capital	accounts	are	different.	As	described	above,	each	contributed	different assets	to	the	partnership	with	those	contributed	by	Koch	valued	at	more	than	those	contributed	by	Entergy.	Through	the	end	of	2003,	substantially	all	of	the partnership	profits	were	allocated	to	Entergy	to	allow	the	capital	accounts	to	equalize.	In	all	years,	losses	and	distributions	from	operations	are	allocated equally	to	the	capital	accounts	based	on	ownership	interest.	Distributions	in	the	event	of	liquidation	are	shared	based	on	capital	accounts,	as	revalued	at	the time	of	the	liquidation.

In	January	2004,	at	the	time	Entergy	made	its	additional	cash	contribution	to	the	partnership,	Entergy-Koch's	assets	were	revalued	for	capital	account purposes.	After	this	revaluation	the	capital	accounts	of	Entergy	and	Koch	Industries	are	approximately	equal	and	future	profit	allocations	other	than	for weather	trading	and	international	trading	will	be	equal.	The	weather	trading	and	international	trading	allocations	are	unequal	only	within	a	specified	range, such	that	the	overall	earnings	allocation	should	not	materially	differ	from	50/50.

Beginning	in	2004,	a	partner	may	transfer	its	interest	to	a	third	party,	only	if	it	has	first	offered	to	sell	its	interest	to	the	other	partner	at	the	approximate	sales price	and	the	other	partner	has	not	accepted	the	offer.	Certain	buy/sell	rights	are	triggered	(a)	at	the	option	of	the	non-defaulting	partner,	upon	a	change	of control	of,	or	material	breach	of	the	agreement	by,	either	partner	or	(b)	at	the	option	of	either	partner.	Under	the	buy/sell	rights,	the	initiating	partner	may offer	to	sell	all	its	partnership	interest	at	a	specified	price	and	other	terms	or	to	buy	all	of	the	other	partner's	partnership	interest	at	the	same	price	and	same other	terms.	The	non-initiating	partner	then	may	elect	either	to	sell	its	partnership	interest	to	the	other	partner	or	to	buy	the	partnership	interest	of	the	other partner	on	the	offered	terms.

# Non-Nuclear	Wholesale	Assets	Business

The	capacity	of	the	generating	stations	owned	in	Entergy's	non-nuclear	wholesale	assets	business	as	of	December	31,	2003	is	indicated	below:

| Plant | Location | Ownership | Net	Owned<br>Capacity(1) | Type |
| :--- | :--- | :--- | :--- | :--- |
| Ritchie\tUnit\t2,\t544\tMW | \t Helena,\tAR | 100% | 544\tMW | \t Gas/Oil |
| Independence\tUnit\t2,\t842\tMW \t Newark,\tAR | Independence\tUnit\t2,\t842\tMW \t Newark,\tAR | 14% | 121\tMW(2) | \t Coal |
| Warren\tPower,\t300\tMW | \t Vicksburg,\tMS | 100% | 300\tMW | \t Gas\tTurbine |
| Top\tof\tIowa,\t80\tMW | \t Worth\tCounty, | 99% | 80\tMW | \t Wind |
|  | IA |  |  |  |
| Crete,\t320\tMW | Crete,\tIL | 50% | 160\tMW | \t Gas\tTurbine |
| RS\tCogen,\t425\tMW | Lake\tCharles,\tLA | 50% | 212\tMW | \t Gas/Steam |
| Harrison\tCounty,\t550\tMW | \t Marshall,\tTX | 70% | 385\tMW | \t Gas\tTurbine |

(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	Power.	For	a complete	 listing	 of	 Entergy's	 joint-owned	 generating	 stations,	 refer	 to "Jointly-Owned Generating Stations" in	 Note 1 to	 the	 Entergy	 Corporation	 and Subsidiaries financial statements.

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

|  | 2003 | 2004 | 2005 | 2006 | 2007 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy\tCommodity\tServices: |  |  |  |  |  |
| Capacity |  |  |  |  |  |
| Planned\tMW\tin\toperation | 1,911 | 1,911 | 1,911 | 1,911 | 1,911 |
| %\tof\tcapacity\tsold\tforward | 43% | 43% | 34% | 31% | 26% |
| Energy |  |  |  |  |  |
| Planned\tgeneration\t(GWh) | 3,321 | 3,348 | 3,337 | 3,545 | 4,015 |
| %\tof\tplanned\tgeneration\tsold\tforward | 64% | 67% | 52% | 42% | 39% |
| Blended\tCapacity\tand\tEnergy\t(based\ton\trevenues) |  |  |  |  |  |
| %\tof\tplanned\tenergy\tand\tcapacity\tsold\tforward | 62% | 66% | 50% | 41% | 35% |
| Average\tcontract\trevenue\tper\tMWh | $26 | $25 | $27 | $31 | $28 |

The	increase	in	the	planned	generation	sold	forward	percentages	from	the	percentages	reported	in	the	2002	Form	10-K	is	attributable	to	the	Entergy Louisiana	and	Entergy	New	Orleans	contracts	involving	RS	Cogen	and	Independence	2	entered	into	in	2003	that	are	described	more	fully	in	Part	I,	Item	1, "Generation."	These	contracts	are	still	subject	to	a	FERC	review	proceeding	scheduled	for	hearing	later	in	2004.

# 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	1	capacity	and	energy	provided	to	Entergy Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	and	over	some	of	the	rates	charged	by	Entergy	Arkansas	and	Entergy	Gulf States.	FERC	also	regulates	the	rates	charged	for	intrasystem	sales	pursuant	to	the	System	Agreement.

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

retail	rates	and	service	in	rural	areas;

customer	service	standards;

certification	of	new	transmission	lines;	and

extensions	of	service	into	new	areas.

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

utility	service;

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:

service	areas;

facilities;	and

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:

standards	of	service;

depreciation,	accounting,	and	issuance	and	sale	of	certain	securities;	and

# 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	1,	respectively,	and	Entergy	Operations,	as	the	licensee	and	operator of	these	units,	are	subject	to	the	jurisdiction	of	the	NRC.	Entergy	has	made	substantial	capital	expenditures	at	these	nuclear	plants	because	of	revised	safety requirements	of	the	NRC	in	the	past,	and	additional	expenditures	could	be	required	in	the	future.	Entergy's	Non-Utility	Nuclear	business	is	subject	to	the NRC's	jurisdiction	as	the	owner	and	operator	of	Pilgrim,	Indian	Point	Energy	Center,	FitzPatrick,	and	Vermont	Yankee.	 Substantial	capital	expenditures	at these	nuclear	plants	because	of	revised	safety	requirements	of	the	NRC	could	be	required	in	the	future.

# Nuclear	Waste	Policy	Act	of	1982

Under	the	Nuclear	Waste	Policy	Act	of	1982,	the	DOE	is	required,	for	a	specified	fee,	to	construct	storage	facilities	for,	and	to	dispose	of,	all	spent	nuclear fuel	and	other	high-level	radioactive	waste	generated	by	domestic	nuclear	power	reactors.	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,	2003	of	$154	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.

The	permanent	spent	fuel	repository	in	the	U.S.	has	been	legislated	to	be	Yucca	Mountain,	Nevada.	DOE	will	now	proceed	with	the	licensing	and,	if	the license	is	granted	by	the	NRC,	eventual	construction	of	the	repository	will	begin	and	receipt	of	spent	fuel	may	begin	as	early	as	approximately	2010, according	to	the	DOE.	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,	and	could	be	several	years	after	2015.	As	a	result,	future	expenditures	will	be	required	to	increase	spent	fuel	storage capacity	at	Entergy's	nuclear	plant	sites.

As	a	result	of	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	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	and	River	Bend	is	estimated	to	be	sufficient	until	approximately	2007	and	2004,	respectively,	at	which	time	dry cask	storage	facilities	will	be	placed	into	service.	The	spent	fuel	pool	at	Waterford	3	was	recently	expanded	through	the	replacement	of	the	existing	storage racks	with	higher	density	storage	racks.	This	expansion	should	provide	sufficient	storage	for	Waterford	3	until	after	2015.	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,	at	which	time management	expects	planned	additional	dry	cask	storage	capacity	to	begin	operation.

# 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	1,	respectively.	 These	amounts	are deposited	in	trust	funds	that	can	only	be	used	for	future	decommissioning	costs.	Entergy	periodically	reviews	and	updates	estimated	decommissioning	costs to	reflect	inflation	and	changes	in	regulatory	requirements	and	technology,	and	then	makes	applications	to	the	regulatory	authorities	to	reflect,	in	rates,	the changes	in	projected	decommissioning	costs.

In	June	2001,	Entergy	Arkansas	received	notification	from	the	NRC	of	approval	for	a	renewed	operating	license	authorizing	operations	at	ANO	1	through May	2034.	In	October	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	1,	Pilgrim,	Indian	Point	1,	Indian	Point	2, Indian	Point	3,	and	FitzPatrick	is	found	in	Note	9	to	the	financial	statements.

# Energy	Policy	Act	of	1992

The	Energy	Policy	Act	of	1992	requires	all	electric	utilities	(including	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy)	that purchased	uranium	enrichment	services	from	the	DOE	to	contribute	up	to	a	total	of	$150	million	annually	over	approximately	15	years	(adjusted	for inflation,	up	to	a	total	of	$2.25	billion)	for	decontamination	and	decommissioning	of	enrichment	facilities.	At	December	31,	2003,	three	years	of	assessments remain.	In	accordance	with	the	Energy	Policy	Act	of	1992,	contributions	to	decontamination	and	decommissioning	funds	are	recovered	through	rates	in	the same	manner	as	other	fuel	costs.	The	estimated	annual	contributions	by	Entergy	for	decontamination	and	decommissioning	fees	are	discussed	in	Note	9	to the	financial	statements.

# Price	Anderson	Act

The	Price-Anderson	Act	limits	public	liability	for	a	single	nuclear	incident	to	approximately	$100.6	million	per	reactor	(with	currently	105	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	9	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;

Ozone	non-attainment	area	program	for	control	of	NO x 	and	volatile	organic	compounds;

# Hazardous	air	pollutant	emissions	reduction	program;	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	judgments	regarding	what	modifications	are	considered	routine.	EPA	recently	has promulgated	a	regulation	to	attempt	to	clarify	this	issue,	but	the	regulation	has	been	challenged,	and	its	effectiveness	has	been	stayed	by	the	federal	court hearing	the	case.	Because	of	the	conflicting	and	changing	definitions	from	courts	and	the	EPA,	several	industries,	including	the	electric	generation	industry, have	exposure	in	this	area.

# Acid	Rain	Program

The	 Act	 provides	 SO 2 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	SO 2 	per	year.	Utilities	are	required	to	possess	allowances	for	SO 2 	emissions	from affected	 generating	 units.	Virtually	all	Entergy	fossil-fueled	generating	units	are	subject	to	SO 2 	 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	and	on	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	Entergy	Gulf	States	the	areas	are	the	Houston-Galveston,	Texas	area	and	the	Beaumont-Port	Arthur,	Texas	area. For	Entergy	Louisiana	the	area	is	the	Baton	Rouge,	Louisiana	area.	Areas	in	non-attainment	are	classified	as	"moderate,"	"serious,"	or	"severe."	When	an area	is	in	noncompliance,	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.	EPA	initially	approved	these	plans	and	the	deadline	extensions,	but	through	litigation	and	a	decision of	the	United	States	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.

EPA	now	is	proposing	that	the	Beaumont-Port	Arthur	area	should	be	reclassified	from	"moderate"	to	"serious"	or	"severe"	and	has	reclassified	the	Baton Rouge	area	from	"serious"	to	"severe"	effective	June	2003.	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	(the	Louisiana	plan	must	be	submitted	to	EPA	by	June	2004).	The content	and	impact	on	Entergy	companies	of	these	developing	state	plans	is	unknown,	but	Entergy	Gulf	States	and	Entergy	Louisiana	continue	to	monitor events	in	their	respective	areas.	If	new	NOx	control	equipment	is	required	to	be	installed,	the	cost	could	be	as	much	as	$5	million	for	the	facilities	in Louisiana	in	2004	and	early	2005.	Entergy	Gulf	States	continues	to	assess	possible	costs	for	the	Texas	facilities.

In	April	and	December	2004,	EPA	is	expected	to	begin	designating	new	non-attainment	areas	that	correspond	to	more	stringent	standards	for	ozone	and particulate	matter	first	adopted	by	EPA	in	1997.	Areas	in	which	Entergy	operates	that	have	never	been	designated	as	"non-attainment"	may	be	so	designated under	these	new	standards.	The	states	involved	will	then	be	required	to	develop	implementation	plans	to	return	the	areas	to	attainment,	choosing	between regulatory	options	that	can	vary	greatly	from	region	to	region.	These	plans	could	require	operational	or	equipment	changes	at	Entergy	company	facilities. Entergy	continues	to	monitor	these	regulatory	activities	and	to	plan	for	necessary	future	action	at	its	facilities.

# 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.	EPA	has proposed	regulations	for	these	sources	and	has	set	a	deadline	of	December	2004	for	finalizing	the	rules.	Entergy	owns	units	that	would	be	subject	to	these regulations.	The	regulations	may	require	coal	and	oil-fired	units	to	reduce	mercury	and	nickel	emissions	through	various	methods,	including	installation	of controls,	switching	fuels	or	fuel	suppliers,	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	and	the	work	could	take	up	to	three	years.	Entergy	currently estimates	that	pollution	control	capital	projects	at	its	five	coal	units	to	comply	with	the	rules	could	be	as	much	as	$130	million.	These	costs	should	be	offset by	advances	in	control	technology	or	in	proposed	cap	and	trade	provisions	which	are	not	final	at	this	time.

# 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	interstate	transport	of	pollutants	and	their	impacts	on	fine	particulates	and	regional	haze;

introduction	of	several	bills	in	Congress	proposing	further	limits	on	NO x ,	SO 2, 	mercury,	or	limits	on	carbon	dioxide	(CO 2 )	emissions;	and

pursuit	by	the	Bush	administration	of	a	voluntary	program	intended	to	reduce	CO 2 	emissions.

Entergy	continues	to	monitor	these	actions	in	order	to	analyze	their	potential	operational	and	cost	implications.	In	anticipation	of	the	potential	imposition	of CO 	emission	limits	on	the	electric	industry	in	the	future,	Entergy	has	initiated	actions	designed	to	reduce	its	exposure	to	potential	new	governmental 2 requirements	related	to	CO 2 	emissions.	These	actions	include	establishment	of	a	formal	program	to	stabilize	power	plant	CO 2 	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	CO 2 emission	"intensity,"	or	rate	of	CO 2 	emitted	per	kilowatt-hour	of	electricity	generated,	is	already	among	the	lowest	in	the	industry.	Total	CO 2 	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,	and	36.78	million	tons	in	2003.

In	January	2004,	the	EPA	proposed	the	Interstate	Air	Quality	Rule	which	intends	to	reduce	SO 2 	and	NO x 	emissions	from	plants	in	order	to	improve	air quality	in	the	northeastern	United	States.	The	impact	of	this	proposed	rule	is	unclear	at	this	time,	but	the	rule	has	the	potential	to	require	significant	pollution control	capital	costs.	The	financial	impact	could	be	offset	by	proposed	emission	markets;	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.

# 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	issued	new	regulations	in	February	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.	The	rule	was	the	subject	of	extensive	comment	during	promulgation	and	is likely	to	be	challenged	in	court.	Entergy	will	continue	to	evaluate	the	rule,	including	consideration	of	options	for	complying	with	the	rule	if	it	remains substantially	in	its	current	form.	Those	options	considered	may	include	operational	controls,	the	installation	of	equipment	to	address	perceived	aquatic impacts,	other	mitigation	measures,	or	combinations	of	these	alternatives.

Entergy's	Non-Utility	Nuclear	business	is	currently	in	negotiations	with	EPA	for	renewal	of	the	Pilgrim	NPDES	permit	and	is	involved	in	an	administrative permitting	process	with	the	New	York	environmental	authority	for	renewal	of	the	Indian	Point	2	and	3	discharge	permit.	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,	if	Entergy	moves	forward	to	obtain	license	extensions	for	these	facilities.	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	an	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	begin	annual	forced	outages	at	Indian	Point	2	and	3.

# Oil	Pollution	Prevention	Regulation

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

# Comprehensive	Environmental	Response,	Compensation,	and	Liability	Act	of	1980

The	Comprehensive	Environmental	Response,	Compensation,	and	Liability	Act	of	1980,	as	amended	(CERCLA),	authorizes	the	EPA	and,	indirectly,	the states,	to	mandate	clean-up,	or	reimbursement	of	clean-up	costs,	by	owners	or	operators	of	sites	from	which	hazardous	substances	may	be	or	have	been released.	Parties	that	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	of	Entergy's	disposal	sites	have	been	the	subject	of	governmental	action	under	CERCLA,	resulting	in site	clean-up	activities.	The	domestic	utility	companies	have	participated	to	various	degrees	in	accordance	with	their	respective	potential	liabilities	in	such site	clean-ups	and	have	developed	experience	with	clean-up	costs.	The	affected	companies	have	established	reserves	for	such	environmental	clean-up	and restoration	activities.

# Other	Environmental	Matters

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	(AOC)	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	EPA.	EPA	is	expected	to	issue	the	order	in	early	2004.	Entergy	Gulf	States	believes	that	its	ultimate	responsibility	for	this site	will	not	materially	exceed	its	existing	clean-up	provision	of	$11.6	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,	2003	for	this	site	was	$6.5	million.	Future costs	are	not	expected	to	exceed	the	existing	provision	of	$1	million.

Entergy	Louisiana	and	Entergy	New	Orleans

Several	class	action	and	other	suits	have	been	filed	in	state	and	federal	courts	seeking	relief	from	Entergy	Louisiana	and	Entergy	New	Orleans	and	others	for

damages	caused	by	the	disposal	of	hazardous	waste	and	for	asbestos-related	disease	allegedly	resulting	from	exposure	on	Entergy	Louisiana's	and	Entergy New	Orleans'	premises	(see	"Litigation"	below).

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

During	1993,	the	LDEQ	issued	new	rules	for	solid	waste	regulation,	including	regulation	of	wastewater	impoundments.	Entergy	Louisiana	and	Entergy	New Orleans	have	determined	that	certain	of	their	power	plant	wastewater	impoundments	were	affected	by	these	regulations	and	chose	to	remediate	and	repair	or close	them.	Completion	of	this	work	is	pending	LDEQ	approval.	LDEQ	has	issued	notices	of	deficiencies	for	certain	of	these	sites.	As	a	result,	recorded liabilities	in	the	amounts	of	$5.8	million	for	Entergy	Louisiana	and	$0.5	million	for	Entergy	New	Orleans	existed	at	December	31,	2003	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	groundwater	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.	An	estimate	of liability	cannot	be	provided	at	this	time.

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

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

# Entergy	New	Orleans	Rate	of	Return	Lawsuit

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

In	October	2002,	plaintiffs	moved	to	stay	the	entire	regulatory	proceeding	pending	resolution	of	their	appeal	in	state	court	of	the	Council's	denial	of	a	motion in	which	they	had	sought	to	force	the	Council	to	recuse	itself	and	to	have	the	Council	Advisors	disqualified	from	representing	the	Council.	In	their	motion	to stay,	plaintiffs	also	requested	that	the	proceeding	be	stayed	until	the	final	resolution	of	a	separate	lawsuit	filed	by	the	Alliance	for	Affordable	Energy	against the	Council	seeking	to	force	the	Council	to	join	the	proceeding	as	a	party-litigant.	On	January	24,	2003,	a	Louisiana	State	court	judge	dismissed	both	the plaintiffs'	appeal	and	the	Alliance's	separate	lawsuit	on	the	ground	that	she	did	not	have	jurisdiction	to	adjudicate	the	claims.	The	plaintiffs	appealed	the ruling	and	in	October	2003,	the	court	of	appeal	affirmed	the	decision	of	the	trial	court.	In	November	2003,	the	plaintiffs	filed	a	writ	application	seeking relief	 at	 the	 Louisiana	 Supreme	 Court,	 which	 was	 denied	 in	 February	 2004.	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.	No	ruling	has	yet	been	made	with	respect	to the	motion	to	bifurcate.

# 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.

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.	Management	cannot	predict	the	outcome	of	this	litigation	at	this	time.

# Entergy	Gulf	States	Merger	Savings	Lawsuit

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

# Entergy	Louisiana	Formula	Ratemaking	Plan	Lawsuit

In	May	1998,	a	group	of	ratepayers	filed	a	complaint	against	Entergy	Louisiana	and	the	LPSC	in	state	court	in	East	Baton	Rouge	Parish	purportedly	on behalf	of	all	Entergy	Louisiana	ratepayers.	The	plaintiffs	allege	that	the	formula	ratemaking	plan	authorized	by	the	LPSC	has	allowed	Entergy	Louisiana	to earn	amounts	in	excess	of	a	fair	return.	The	plaintiffs	seek,	among	other	things,	(i)	a	declaratory	judgment	that	the	formula	ratemaking	plan	is	an	improper ratemaking	practice;	and	(ii)	a	refund	of	 the	amounts	allegedly	charged	 in	excess	of	proper	ratemaking	practices.	This	case	has	not	been	active,	and abandonment	issues	are	being	evaluated.	At	this	time,	management	cannot	determine	the	amount	of	damages	being	sought.

# Street	Lighting	Lawsuit	(Entergy	New	Orleans)

In	February	2002,	the	City	of	New	Orleans	(City)	filed	a	petition	against	Entergy	New	Orleans	in	state	court	in	Orleans	Parish,	seeking	declaratory	relief, injunctive	relief,	an	unspecified	amount	of	monetary	damages,	and	attorney	and	consulting	fees	and	costs.	The	City's	petition	alleged	that	Entergy	New Orleans	had	breached	its	obligations	to	the	City	related	to	the	provision	of	street	lighting	maintenance	services.	After	mediation,	the	City	dismissed	its lawsuit	with	prejudice	in	October	2002	and	the	parties	agreed	that	any	amounts	that	may	be	owed	by	Entergy	New	Orleans	will	be	determined	by	an independent	third	party	audit.	In	December	2003	the	audit	concluded,	and	Entergy	New	Orleans	paid	the	City	$6.7	million	to	resolve	the	proceeding	and terminate	the	contract	with	the	City	to	provide	street	lighting	services.

# Murphy	Oil	Lawsuit	(Entergy	Corporation	and	Entergy	Louisiana)

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

Murphy	Oil	and	other	defendants	settled	with	the	plaintiffs	for	$8.8	million,	but	Entergy	Louisiana	did	not	participate	in	the	settlement.	Entergy	Louisiana continues	to	defend	itself	in	the	proceeding.	Entergy	Louisiana	also	has	insurance	in	place	for	claims	of	this	type.	A	trial	for	the	remaining	parties	in	the proceeding	was	held	in	September	2003	and	a	decision	is	pending.

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

In	1998,	a	group	of	property	owners	filed	a	class	action	suit	against	Entergy	Corporation,	Entergy	Gulf	States,	Entergy	Services	and	ETHC	in	state	court	in Jefferson	County,	Texas	purportedly	on	behalf	of	all	property	owners	 in	each	of	 the	states	 throughout	 the	Entergy	service	area	who	have	conveyed easements	to	the	defendants.	The	lawsuit	alleged	that	Entergy	installed	fiber	optic	cable	across	their	property	without	obtaining	appropriate	easements.	The plaintiffs	sought	actual	damages	for	the	use	of	the	land	and	a	share	of	the	profits	made	through	use	of	the	fiber	optic	cables	and	punitive	damages.	The	state court	petition	was	voluntarily	dismissed,	and	the	plaintiffs	commenced	a	class	action	suit	with	the	same	claims	in	the	United	States	District	Court	in Beaumont,	Texas.	Both	sides	have	filed	motions	for	summary	judgment,	which	were	heard	by	the	court	in	late	2001.	In	2003,	the	district	judge	ruled	that	as a	matter	of	law,	all	of	the	Texas	easements	permit	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.	The	Court	has	scheduled	a	class certification	hearing	for	March	17,	2004.	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.	Entergy	is	appealing	this	ruling.	On	December	23,	2003,	the	state	court	held	a class	certification	hearing.	In	January	2004	the	judge	advised	the	parties	that	he	would	certify	a	class,	but,	to	date,	he	has	not	entered	his	judgment.	Once	the judgment	is	entered,	Entergy	will	appeal	the	decision.	At	this	time,	management	cannot	determine	the	specific	amount	of	damages	being	sought.

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	419	lawsuits	involving	just	over	7,000	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,	and/or	sex.	Entergy	Corporation	and	the	domestic	utility	companies	are vigorously	defending	these	suits	and	deny	any	liability	to	the	plaintiffs.	However,	no	assurance	can	be	given	as	to	the	outcome	of	these	cases,	and	at	this time	management	cannot	estimate	the	total	amount	of	damages	sought.

Included	in	the	employment	litigation	are	two	cases	filed	in	state	court	in	Claiborne	County,	Mississippi	in	December	2002.	The	two	cases	were	filed	by former	employees	of	Entergy	Operations	who	were	based	at	Grand	Gulf.	Entergy	Operations	and	Entergy	employees	are	named	as	defendants.	The	cases make	employment-related	claims,	and	seek	in	total	$53	million	in	alleged	actual	damages	and	$168	million	in	punitive	damages.	Entergy	cannot	predict	the ultimate	outcome	of	this	proceeding.

# Power	Generation	Mexico,	Inc.	Lawsuit

Power	Generation	Mexico,	Inc.	(PGI)	filed	suit	against	Entergy	Power	Development	Corporation	(EPDC),	Entergy	Power	Netherlands	Company,	B.V.,	and Entergy	Corporation	in	the	San	Francisco	Superior	Court	in	May	2001.	PGI	asserts	that	EPDC	agreed	to	develop	several	power	projects	and	to	receive certain	fees	and	equity	interest	for	its	efforts,	and	that	EPDC	failed	to	fulfill	its	obligations	and	deliberately	frustrated	development	of	the	projects,	allegedly to	PGI's	detriment.	PGI	seeks	damages	that	in	the	discovery	process	it	claims	to	be	approximately	$21	million.	Entergy	has	filed	a	cross	complaint	alleging fraud	and	breach	of	the	development	agreement.	Trial	is	set	to	commence	in	April	2004.	Entergy	cannot	predict	the	ultimate	outcome	of	this	proceeding.

# Futures	and	Options	Trading	Lawsuit

On	August	18,	2003,	Cornerstone	Propane	Partners,	L.P.	filed	a	lawsuit	in	the	United	States	District	Court	for	the	Southern	District	of	New	York	against	40 named	defendants,	including	Entergy-Koch	Trading	and	Entergy	Corporation.	The	lawsuit	was	filed	on	behalf	of	a	purported	class	of	all	persons	who purchased	and/or	sold	natural	gas	futures	and	options	contracts	traded	on	the	New	York	Mercantile	Exchange	(NYMEX)	between	January	1,	2000	and December	31,	2002	and	who	suffered	losses	by	reason	of	the	defendants'	alleged	manipulation	of	the	natural	gas	market.	The	plaintiffs	amended	their complaint	in	January	2004	and	did	not	rename	Entergy	Corporation	as	a	defendant.	Entergy	Corporation	was	dismissed	as	a	defendant	in	the	proceeding	in February	2004.	Entergy-Koch	Trading	remains	a	defendant	in	the	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	$1.5	million	in	2003,	$2.1	million	in	2002,	and	$4	million	in	2001	to	EPRI.	The	Non-Utility	Nuclear	business	contributed	$3	million	in	2003	and 2002	and	$2	million	in	2001	to	EPRI.

# Employees

Employees	are	an	integral	part	of	Entergy's	commitment	to	serving	its	customers.	As	of	December	31,	2003,	Entergy	employed	14,773	people.

| Entergy	Arkansas | 1,516 |
| :--- | :--- |
| Entergy\tGulf\tStates | 1,676 |
| Entergy\tLouisiana | 918 |
| Entergy\tMississippi | 810 |
| Entergy\tNew\tOrleans | 375 |
| System\tEnergy | - |
| Entergy\tOperations | 2,902 |
| Entergy\tServices | 2,755 |
| Entergy\tNuclear\tOperations | 3,357 |
| Other\tsubsidiaries | 255 |
| Total\tFull-time | 14,564 |
| Part-time | 209 |
| Total\tEntergy | 14,773 |

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.

Net	Income

Net	income	decreased	$9.6	million	due	to	a	decrease	in	net	revenue,	an	increase	in	depreciation	and	amortization	expenses,	and	an	increase	in	the	effective income	tax	rate	for	2003	compared	to	2002.	The	decrease	was	substantially	offset	by	a	decrease	in	other	operation	and	maintenance	expenses,	an	increase	in other	income,	and	decreased	interest	charges.

Net	income	decreased	$42.5	million	due	to	increases	in	other	operation	and	maintenance	expenses	and	depreciation	and	amortization	expenses	and	a decrease	in	other	income.	The	decrease	was	partially	offset	by	an	increase	in	net	revenue	and	decreased	interest	charges.

| 2002	net	revenue | $1,095.9 |
| :--- | :--- |
| March\t2002\tsettlement\tagreement | (154.0) |
| Volume/weather | (7.7) |
| Asset\tretirement\tobligation | 30.1 |
| Net\twholesale\trevenue | 16.6 |
| Energy\tcost\trecovery\ttrue-up | 10.2 |
| Other | 7.6 |
| 2003\tnet\trevenue | $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	May	2002,	Entergy	Arkansas	filed	its	2001	earnings	evaluation	report with	the	APSC.	In	June	2002,	the	APSC	approved	a	final	contribution	of	$5.9	million	to	the	TCA.

In	mid-	and	late	December	2000,	two	separate	ice	storms	left	226,000	and	212,500	Entergy	Arkansas	customers,	respectively,	without	electric	power	in	its service	area.	Entergy	Arkansas	filed	a	proposal	to	recover	costs	plus	carrying	charges	associated	with	power	restoration	caused	by	the	ice	storms.	In	an	order issued	in	June	2001,	the	APSC	decided	not	to	give	final	approval	to	Entergy's	proposed	storm	cost	recovery	at	that	time.	The	APSC	action	resulted	in	the deferral	in	2001	of	storm	damage	costs	expensed	in	2000	as	reflected	in	Entergy	Arkansas'	financial	statements.	Entergy	Arkansas	then	filed	its	final	storm damage	cost	determination,	which	reflected	costs	of	approximately	$195	million.	In	May	2002,	the	APSC	approved	a	settlement	agreement	submitted	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	allocated	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,	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	is	a	$2.2	million	increase	in	2003,	because	of	the	offsetting 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	is	due	to	the	implementation	of	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	adopted	in	January 2003.	See	"Critical	Accounting	Estimates"	for	more	details	on	SFAS	143.	The	increase	is	offset	by	an	increase	in	decommissioning	expense	and	has	no effect	on	net	income.

The	net	wholesale	revenue	variance	is	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.

The	energy	cost	recovery	true-up	refers	to	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	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	cost	recovery revenues	are	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements).

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	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	regulatory	credits	in	2003	to	offset	the	increase	in	decommissioning expense.

| 2001	net	revenue | $982.5 |
| :--- | :--- |
| March\t2002\tsettlement\tagreement | 180.7 |
| Volume/weather | 20.3 |
| System\tEnergy\trefund\tin\t2001 | (62.7) |
| Net\twholesale\trevenue | (22.9) |
| Other | (2.0) |
| 2002\tnet\trevenue | $1,095.9 |

The	March	2002	settlement	agreement	is	discussed	above.	The	effect	on	net	income	in	2002	is	a	decrease	of	$2.2	million.

The	volume/weather	variance	is	due	to	an	increase	in	electricity	usage	in	the	service	territory.	Billed	usage	increased	a	total	of	191	GWh	in	the	residential and	commercial	sectors.

The	effect	of	the	System	Energy	refund	resulted	from	System	Energy's	application	to	FERC	in	May	1995	for	a	rate	increase,	which	it	implemented	in December	1995,	subject	to	refund.	The	request	sought	changes	to	System	Energy's	rate	schedule,	including	increases	in	the	revenue	requirement	associated with	decommissioning	costs,	the	depreciation	rate,	and	the	rate	of	return	on	common	equity.	In	July	2000,	FERC	approved	a	lower	rate	of	return	than	the rate	sought	by	System	Energy.	Upon	receipt	of	a	final	FERC	order	in	July	2001,	Entergy	Arkansas	recorded	entries	to	spread	the	impacts	of	FERC's	order	to the	various	revenue,	expense,	asset,	and	 liability	accounts	affected,	as	 if	 the	order	had	been	 in	place	since	commencement	of	 the	case	 in	1995.	The accounting	entries	necessary	to	record	the	effects	of	the	order	reduced	Entergy	Arkansas'	purchased	power	expenses	by	$62.7	million	in	2001,	which resulted	in	a	corresponding	increase	in	net	revenue	in	2001.

The	net	wholesale	revenue	variance	is	primarily	due	to	a	decrease	in	volume	and	revenue	related	to	sales	to	municipalities	and	co-operatives,	partially	due	to the	expiration	of	a	municipal	wholesale	customer	contract	in	June	2002.

Gross	operating	revenues	decreased	primarily	due	to	a	decrease	of	$120.9	million	in	gross	wholesale	revenue	due	to	the	same	factors	that	decreased	net wholesale	revenue,	as	well	as	a	decrease	in	the	average	price	of	energy	sold	to	affiliated	wholesale	customers.	The	decrease	was	also	due	to	a	decrease	of $91.8	million	in	fuel	cost	recovery	revenues	due	to	decreases	in	the	annual	recovery	rider	in	April	2002	and	again	in	October	2002.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	a	decrease	in	the	market	prices	of	natural	gas	and	purchased	power.

Other	regulatory	credits	increased	primarily	due	to	the	March	2002	settlement	agreement	and	2001	earnings	review	discussed	above.

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	 is	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	is	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	is	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	is	now	terminated	as	a	result	of	the	March	2002	settlement	agreement;	and

an	increase	of	$3.0	million	in	the	allowance	for	borrowed	funds	used	during	construction	due	to	an	increase	in	construction	work	in	progress.

Other	operation	and	maintenance	expenses	increased	primarily	due	to:

increased	expenses	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	(offset by	an	increase	in	other	regulatory	credits	and	has	no	effect	on	operating	income);

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

an	increase	of	$10.3	million	in	benefit	costs;	and

an	increase	in	expense	of	$6.6	million	to	reflect	the	current	estimate	of	the	liability	for	the	future	disposal	of	low-level	radioactive	waste

materials.

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

Depreciation	and	amortization	expenses	increased	due	to	an	increase	in	plant	in	service	combined	with	revisions	made	to	the	useful	lives	of	certain	intangible plant	assets	to	more	appropriately	reflect	their	actual	lives,	which	lowered	expense	in	2001	in	accordance	with	regulatory	treatment.

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

a	decrease	of	$3.3	million	due	to	a	lower	interest	rate	on	spent	nuclear	fuel	disposal	costs;

decreased	interest	of	$2.8	million	on	intercompany	money	pool	borrowings	due	to	Entergy	Arkansas	being	in	a	lending	position	in	2002;	and

interest	expense	of	$2.7	million	in	2001	on	a	$63	million	credit	facility	that	was	outstanding	in	2001	but	not	in	2002.

The	effective	income	tax	rates	for	2003,	2002,	and	2001	were	45.5%,	34.5%,	and	37.3%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and System	Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rate.

# Cash	Flow

| Cash	and	cash	equivalents	at	beginning	of	period | $95,513 | $103,466 | $7,838 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 437,520 | 357,421 | 413,178 |
| Investing\tactivities | (337,509) | (249,438) | (326,602) |
| Financing\tactivities | (186,690) | (115,936) | 9,052 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (86,679) | (7,953) | 95,628 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $8,834 | $95,513 | $103,466 |

# Operating	Activities

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	versus	income taxes	paid	of	$83.9	million	in	2002,	and	money	pool	activity.	The	increase	in	cash	flow	from	operations	was	partially	offset	by	an	increase	in	deferred	fuel costs	in	2003	versus	a	decrease	in	2002.

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

Money	pool	activity	provided	$73.4	million	of	Entergy	Arkansas'	operating	cash	flow	in	2003,	provided	$19.5	million	in	2002,	and	used	$54.5	million	in 2001.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

Cash	flow	from	operations	decreased	$55.8	million	in	2002	compared	to	2001	primarily	due	to	an	increase	in	income	taxes	paid.

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	primarily due	to	the	following:

a	FERC	ruling	that	shifted	responsibility	for	transmission	upgrade	work	performed	for	independent	power	producers	to	Entergy	Arkansas;	and

ANO	1	steam	generator,	reactor	vessel	head	and	transformer	replacement	projects.

The	decrease	of	$77.2	million	in	net	cash	used	in	investing	activities	in	2002	was	primarily	due	to	the	aforementioned	$38.4	million	of	other	temporary investments	made	in	2001	that	provided	cash	in	2002	upon	maturity.

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.

Entergy	Arkansas	used	$115.9	million	of	cash	in	financing	activities	in	2002	compared	to	providing	$9.1	million	of	cash	in	2001	primarily	due	to	a	net

issuance	of	$18.4	million	of	long-term	debt	in	2002	compared	to	a	net	issuance	of	$97.4	million	in	2001.	An	increase	of	$43.4	million	in	common	stock dividends	paid	to	Entergy	Corporation	also	contributed	to	the	decrease	in	net	cash	provided.

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:

|  | 2004 | 2005-2006 	 2007-2008 	 after	2008 | 2005-2006 	 2007-2008 	 after	2008 | 2005-2006 	 2007-2008 	 after	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| \t\tcapital\tinvestment\t(1) | $285 | $614 | N/A | N/A | $899 |
| Long-term\tdebt | $- | $147 | $- | $1,191 | $1,338 |
| Capital\tlease\tobligations | $10 | $15 | $5 | $3 | $33 |
| Operating\tleases | $21 | $34 | $23 | $62 | $140 |
| Purchase\tobligations\t(2) | $504 | $837 | $836 | $3,352 | $5,529 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $52 | $51 | N/A | N/A | $103 |

	(1) Includes	$190	million	each	year	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) As	defined	by	SEC	rule.	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	 9	 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.

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	$135	million	will	be incurred	through	2004.	Management	expects	that	the	replacement	will	occur	during	a	planned	refueling	outage	in	2005.	Entergy	Arkansas	filed	in	January 2003	a	request	for	a	declaratory	order	by	the	APSC	that	the	investment	in	the	replacement	is	in	the	public	interest	analogous	to	the	order	received	in	1998 prior	to	the	replacement	of	the	steam	generators	for	ANO	2.	The	APSC	found	that	the	replacement	is	in	the	public	interest	in	a	declaratory	order	issued	in May	2003.	See	''Nuclear	Matters''	below	for	further	discussion	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	construction	expenditures	and	long-term	debt	and	preferred	stock	maturities	in	Notes	5,	7,	and	9	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	is	restricted	by	long-term	debt	indentures	in	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred	stock.	As	of December	31,	2003,	Entergy	Arkansas	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$309.4	million.

Entergy	Arkansas'	sources	to	meet	its	capital	requirements	include:

cash	on	hand;

debt	issuances;	and

bank	financing	under	new	or	existing	facilities.

In	2003,	Entergy	Arkansas	issued	$365	million	of	long-term	debt	and	used	the	net	proceeds,	combined	with	the	proceeds	from	a	$100	million	November 2002	 issuance,	 to	 redeem	 outstanding	 debt	 of	 $470	 million.	Entergy	Arkansas	 is	expected	 to	continue	refinancing	or	redeeming	higher-cost	debt	and preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Arkansas	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also subject	to	issuance	tests	set	forth	in	corporate	charters,	bond	indentures,	and	other	agreements.	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	the	SEC	order	authorizing	the	short-term	borrowing	limits,	Entergy	Arkansas	cannot	incur	new	short-term	indebtedness	if	its	common	equity would	comprise	less	than	30%	of	its	capital.	Entergy	Arkansas	has	a	364-day	credit	facility	available	with	an	expiration	date	of	April	2004	in	the	amount	of $63	million,	of	which	none	was	drawn	at	December	31,	2003.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for further	discussion	of	Entergy	Arkansas'	short-term	borrowing	limits.

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

At	FERC,	restructuring	at	the	wholesale	level	has	begun	but	has	been	delayed.	It	is	too	early	to	predict	the	ultimate	effects	of	changes	in	U.S.	energy markets.	Restructuring	issues	are	complex	and	are	continually	affected	by	events	at	the	national,	regional,	state,	and	local	levels.	However,	these	changes may	result,	in	the	long	term,	in	fundamental	changes	in	the	way	traditional	integrated	utilities	and	holding	company	systems,	like	the	Entergy	system, conduct	their	business.	Some	of	these	changes	may	be	positive	for	Entergy,	while	others	may	not	be.

# System	Agreement	Proceedings

The	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.

The	LPSC	and	the	Council	commenced	a	proceeding	at	FERC	in	June	2001.	Pursuant	to	a	settlement	agreement	approved	by	the	City	Council	in	May	2003, the	City	Council	withdrew	as	a	complainant	from	the	proceeding,	but	continues	to	participate	as	an	intervenor.	In	this	proceeding,	the	LPSC	alleges	that	the rough	production	cost	equalization	required	by	FERC	under	the	System	Agreement	and	the	Unit	Power	Sales	Agreement	has	been	disrupted	by	changed circumstances.	The	LPSC	requests	that	FERC	amend	the	System	Agreement	or	the	Unit	Power	Sales	Agreement	or	both	to	achieve	full	production	cost equalization	or	to	restore	rough	production	cost	equalization.	The	complaint	does	not	seek	a	change	in	the	total	amount	of	the	costs	allocated	by	either	the System	Agreement	or	the	Unit	Power	Sales	Agreement.	In	addition	the	LPSC	alleges	that	provisions	of	the	System	Agreement	relating	to	minimum-run	and must-run	units,	the	methodology	of	billing	versus	dispatch,	and	the	use	of	a	rolling	twelve-month	average	of	system	peaks,	increase	costs	paid	by	ratepayers in	the	LPSC's	jurisdiction.	Several	parties	intervened	in	the	proceeding,	including	the	APSC	and	the	MPSC.	The	APSC	and	the	MPSC	responses	opposed the	relief	sought	by	the	LPSC.

In	its	complaint,	the	LPSC	alleges	that	Entergy	Arkansas'	annual	production	costs	over	the	period	2002	to	2007	will	be	$130	million	to	$278	million	under the	average	for	the	domestic	utility	companies.	This	range	of	results	is	a	function	of	assumptions	regarding	such	things	as	future	natural	gas	prices,	the	future market	price	of	electricity,	and	other	factors.	If	FERC	grants	the	relief	requested	by	the	LPSC,	the	relief	may	result	in	a	material	increase	in	production	costs allocated	to	companies	whose	costs	currently	are	projected	to	be	less	than	the	average	and	a	material	decrease	in	production	costs	allocated	to	companies whose	costs	currently	are	projected	to	exceed	the	average.	Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	a FERC	decision	should	result	in	similar	rate	changes	for	retail	customers.	Therefore,	management	does	not	believe	that	this	proceeding	will	have	a	material effect	on	the	financial	condition	of	Entergy	Arkansas,	although	neither	the	timing	nor	the	outcome	of	the	proceedings	at	FERC	can	be	predicted	at	this	time. In	February	2002,	the	FERC	set	the	matter	for	hearing	and	established	a	refund	effective	period	consisting	of	the	15	months	following	September	13,	2001. A	subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

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.

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

# State	and	Local	Rate	Regulatory	Risks

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

Entergy	Arkansas	owns	and	operates,	through	an	affiliate,	ANO	1	and	2.	Entergy	Arkansas	is,	therefore,	subject	to	the	risks	related	to	owning	and	operating nuclear	plants.	These	include	risks	from	the	use,	storage,	handling	and	disposal	of	high-level	and	low-level	radioactive	materials,	limitations	on	the	amounts and	types	of	insurance	commercially	available	for	losses	in	connection	with	nuclear	operations,	and	technological	and	financial	uncertainties	related	to decommissioning	 nuclear	 plants	 at	 the	 end	 of	 their	 licensed	 lives,	 including	 the	 sufficiency	 of	 funds	 in	 decommissioning	 trusts.	In	 the	 event	 of	 an unanticipated	early	shutdown	of	either	ANO	1	or	2,	Entergy	Arkansas	may	be	required	to	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	2	are	pressurized	water	reactors.	In	March	2001,	an	inspection	of	ANO	1	revealed	one	leaking	control	rod drive	mechanism	nozzle,	which	was	subsequently	repaired.	During	a	planned	refueling	outage	that	began	in	October	2002,	visual	inspection	of	the	reactor vessel	head	at	ANO	1	revealed	one	nozzle	leak.	Further	ultrasonic	testing	showed	the	presence	of	seven	additional	minor	indications	that	could	potentially develop	 into	 leaks.	Entergy	Arkansas	made	repairs	during	the	outage.	Entergy	Arkansas	has	received	favorable	responses	from	the	NRC	for	continued operations	of	ANO	1	and	2.

Inspections	of	the	ANO	1	steam	generators	during	planned	outages	also	have	revealed	cracks	in	certain	steam	generator	tubes,	which	have	been	repaired, plugged,	or	left	in-service	using	a	NRC	approved	alternate	repair	criteria.	The	current	condition	and	number	of	cracks	are	within	acceptable	NRC	criteria	to allow	the	unit	to	remain	in	operation	and	ANO	1	output	has	not	been	affected	to	date.	Using	current	projections	of	steam	generator	tube	plugging,	the	current best	estimate	is	that	replacement	of	the	ANO	Unit	1	steam	generators	will	be	required	by	2013,	but	management	decided	that	replacement	of	the	generators during	a	scheduled	refueling	outage	in	September	2005	was	prudent.	Entergy	Operations	currently	does	not	expect	ANO	Unit	1	to	have	to	conduct	mid-cycle outages	for	steam	generator	inspection	before	2005.	ANO	2's	steam	generators	were	replaced	during	a	refueling	outage	in	the	second	half	of	2000.

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.	In	January	2003,	Entergy	Arkansas filed	a	Petition	for	Declaratory	Order	to	request	a	finding	by	the	APSC	that	replacement	of	the	steam	generators	and	reactor	vessel	closure	head	at	ANO	1	is in	the	public	interest.	The	APSC	found	that	the	replacement	is	in	the	public	interest	in	a	declaratory	order	issued	in	May	2003.

# 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.

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

Regulations	require	that	ANO	1	and	ANO	2	be	decommissioned	after	the	facilities	are	taken	out	of	service,	and	funds	are	collected	and	deposited	in	trust funds	 during	 the	 facilities'	 operating	 lives	 in	 order	 to	 provide	 for	 this	 obligation.	Entergy	Arkansas	 conducts	 periodic	 decommissioning	 cost	 studies (typically	updated	every	five	years)	to	estimate	the	costs	that	will	be	incurred	to	decommission	the	facilities.	See	Note	9	to	the	domestic	utility	companies and	 System	 Energy	 financial	 statements	 for	 details	 regarding	 Entergy	Arkansas'	 obligation	 recorded	 for	 its	 estimated	 decommissioning	 liability.	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	impact	of	these	assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a

"safestore"	status	can	significantly	decrease	the	present	value	of	these	obligations.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	Department	of	Energy	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear fuel,	and	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).	These	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening	of	the	Yucca Mountain	facility,	the	schedule	for	shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

Through	2001,	Entergy	Arkansas	collected	the	projected	costs	of	decommissioning	ANO	1	and	ANO	2	through	rates	charged	to	customers.	Now,	based	on assumptions	approved	by	the	APSC,	including	an	assumed	license	extension	for	ANO	2	(ANO	1's	license	has	actually	been	extended)	and	the	sufficiency	of previously	collected	funds,	Entergy	Arkansas	is	not	collecting	the	cost	to	decommission	ANO	1	and	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.

Prior	 to	 the	 implementation	 of	 SFAS	 143,	 the	 obligations	 recorded	 by	 Entergy	 Arkansas	 for	 decommissioning	 were	 classified	 as	 a	 component	 of accumulated	depreciation.	The	amounts	recorded	for	these	obligations	were	comprised	of	collections	from	customers	and	earnings	on	the	trust	funds.

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	approximately	$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.

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

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Pension	Cost | Impact	on	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $953 | $18,603 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,106 | - |
| Rate\tof\tincrease\tin | 0.25% | $654 | $4,917 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $914 | $4,696 |
| Discount\trate | (0.25%) | $511 | $5,333 |

Total	pension	cost	for	Entergy	Arkansas	in	2003	was	$18.3	million,	including	a	$10.8	million	charge	related	to	the	Voluntary	Severance	Program.	 Entergy Arkansas	is	projecting	2004	pension	cost	to	be	$14.6	million	due	to	a	decrease	in	the	discount	rate	from	6.75%	to	6.25%	and	the	phased-in	effect	of	poor asset	performance.	Entergy	Arkansas	was	not	required	to	make	contributions	to	its	pension	plan	in	2003,	however	it	anticipates	making	$5.3	million	in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	Entergy	Arkansas'	accumulated	benefit	obligation	at	December	31,	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,	2003 Entergy	Arkansas	increased	its	additional	minimum	liability	to	$54.9	million	from	$29.6	million	at	December	31,	2002.	Entergy	Arkansas	increased	its intangible	asset	for	the	unrecognized	prior	service	cost	to	$13.3	million	at	December	31,	2003	from	$10.6	million	at	December	31,	2002.	Entergy	Arkansas also	increased	the	regulatory	asset	to	$41.6	million	at	December	31,	2003	from	$19	million	at	December	31,	2002.	Net	income	for	2003	and	2002	were	not impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Arkansas	in	2003	were	$29.4	million,	including	a	$10.1	million	charge	related	to the	Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	Entergy Arkansas	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$18.2	million.

To	the	Board	of	Directors	and	Shareholders	of

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Arkansas,	Inc.	as	of	December	31,	2003	and	2002,	and	the	related	statements	of	income, retained	earnings,	and	cash	flows	(pages	163	through	168	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three	years	in	the	period	ended December	31,	2003.	These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these financial	statements	based	on	our	audits.

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

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Arkansas,	Inc.	as	of	December	31,	2003	and 2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with	accounting principles	generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	1	and	Note	9	to	the	notes	to	respective	financial	statements,	Entergy	Arkansas,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting Standards	 No. 143,	Accounting for	 Asset	 Retirement	 Obligations, and	 Financial	 Accounting	 Standards	 Board Interpretation	 No. 46, Consolidation	of	Variable	Interest	Entities,	in	2003.

# New	Orleans,	Louisiana

# Operation	and	Maintenance:

See	Notes	to	Respective	Financial	Statements.

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,589,670 | $1,561,110 | $1,776,776 | $1,762,635 | $1,541,894 |
| Net\tincome | $126,009 | $135,643 | $178,185 | $137,047 | $69,313 |
| Total\tassets | $5,058,078 | $4,569,511 | $4,451,580 | $4,228,211 | $3,917,111 |
| Long-term\tobligations\t(1) | $1,406,026 | $1,246,567 | $1,417,262 | $1,401,062 | $1,265,846 |

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

obligations.

# ENTERGY	GULF	STATES,	INC.

Entergy	Gulf	States	experienced	a	significant	decline	in	net	income	in	2003	compared	to	2002	primarily	due	to	the	following:

$107.7	million	accrual	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;

$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	in	net	revenue	of	$20.6	million;	and

an	increase	in	operation	and	maintenance	expenses	of	$19.2	million.

This	was	partially	offset	by	a	lower	effective	income	tax	rate.

Net	income	decreased	slightly	in	2002	compared	to	2001	primarily	due	to	decreased	net	revenue,	increased	other	operation	and	maintenance	expenses, increased	depreciation	and	amortization	expenses,	and	decreased	other	income,	partially	offset	by	decreased	interest	charges	and	a	lower	effective	income tax	rate.

| 2002	net	revenue | $1,130.7 |
| :--- | :--- |
| Volume/weather | 17.8 |
| Fuel\twrite-offs\tin\t2002 | 15.3 |
| Net\twholesale\trevenue | 10.2 |
| Base\trate\tdecreases | (23.3) |
| NISCO\tgain\trecognized\tin\t2002 | (15.2) |
| Rate\trefund\tprovisions | (11.3) |
| Other | (14.1) |
| 2003\tnet\trevenue | $1,110.1 |

The	volume/weather	variance	is	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.	Entergy	Gulf	States	expects	to	lose	one	additional customer	 to	cogeneration	 in	2005.	Current	sales	to	that	customer	account	for	approximately	$11	million	of	Entergy	Gulf	States'	net	revenue	annually. 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.

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	deferred	asset	plan	percentage	as	the	result	of	uprates	at	River	Bend.

The	increase	in	net	wholesale	revenue	is	primarily	due	to	an	increase	in	sales	volume	to	municipal	and	co-op	customers	and	also	to	affiliated	systems	related to	Entergy	Louisiana	and	Entergy	New	Orleans	generation	resource	planning	coupled	with	an	increase	in	the	market	price	of	natural	gas.

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	decreased	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	increased	fuel	cost	recovery	revenues	of	$440.2	million	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.

| 2001	net	revenue | $1,147.1 |
| :--- | :--- |
| Fuel\tPrice | 37.3 |
| Volume/weather | 36.5 |
| Net\twholesale\trevenue | (38.6) |
| Regulatory\titems\t-\tnet | (21.2) |
| Fuel\twrite-offs | (15.3) |
| Other | (15.1) |
| 2002\tnet\trevenue | $1,130.7 |

The	price	variance	is	due	to	an	increase	in	the	fuel	price	applied	to	unbilled	sales	in	the	Louisiana	jurisdiction.

The	 volume/weather	 variance is	 due to	 more	 favorable	 sales	 volume	 and	 weather.	Billed	usage increased	a total	of	669	GWh in the	residential	and commercial	sectors.

The	decrease	in	net	wholesale	revenue	is	due	to	a	decrease	in	sales	volume.

The	decrease	in	regulatory	items	-	net	is	primarily	due	to	the	following:

$14.3	million	decrease	related	to	the	settlement	of	the	fourth	through	eighth	post-merger	earnings	reviews	in	Louisiana;

$24.0	million	decrease	relating	the	deferral	in	2001	of	capacity	charges	included	in	purchased	power	costs	for	the	summers	of	2000	and	2001 and	the	amortization	of	these	capacity	charges	in	2002.	The	amortization	of	the	summer	2000	capacity	charges	ended	in	May	2002.	The amortization	of	the	capacity	charges	for	the	summer	of	2001	began	in	June	2002	and	ended	in	May	2003;	and

$15.2	million	increase	due	to	the	gain	recognition	of	the	Louisiana	portion	of	the	1988	Nelson	Units	1	and	2	sale.

Fuel	write-offs	represent	deferred	fuel	costs	of	$8.9	million	related	to	the	Texas	fuel	reconciliation	case	that	were	written	off	and	a	$6.5	million	adjustment	in the	deferred	asset	plan	percentage	as	the	result	of	uprates	at	River	Bend.

Gross	operating	revenues	decreased	primarily	due	to	decreased	fuel	cost	recovery	revenues	of	$456.7	million	as	a	result	of	lower	fuel	rates	in	both	the Louisiana	and	Texas	jurisdictions.

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

Other	operation	and	maintenance	expenses	increased	primarily	due	to	voluntary	severance	accruals	of	$22.5	million.

Decommissioning	expense	increased	primarily	due	to	the	implementation	of	SFAS	143.	The	increase	in	decommissioning	expense	is	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	is	offset	by	the	January	2003	base	rate	decrease	discussed	in	"Net	Income"	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.

an	increase	of	$9.5	million	in	maintenance	outage	costs	at	several	plants;	and

an	increase	of	$2	million	in	higher	nuclear	expenses.

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

Depreciation	and	amortization	expenses	increased	$13.1	million	due	to	an	increase	in	plant	in	service	combined	with	revisions	made	to	the	useful	lives	of certain	intangible	plant	assets	to	more	appropriately	reflect	their	actual	lives,	which	lowered	expense	in	2001	in	accordance	with	regulatory	treatment.

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

lower	interest	expense	of	$12.2	million	as	a	result	of	the	retirement	of	$148	million	of	First	Mortgage	Bonds	in	January	2002;

lower	interest	expense	of	$9.3	million	on	variable-rate	First	Mortgage	Bonds;	and

an	adjustment	of	$5.5	million	in	2001	to	the	liability	for	deferred	compensation	for	certain	former	Entergy	Gulf	States	employees	in	accordance with	an	actuarial	study.

| Cash	and	cash	equivalents	at	beginning	of	period | $318,404 | $123,728 | $68,279 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 425,963 | 500,654 | 338,486 |
| Investing\tactivities | (446,639) | (351,456) | (363,416) |
| Financing\tactivities | (91,698) | 45,478 | 80,379 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (112,374) | 194,676 | 55,449 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $206,030 | $318,404 | $123,728 |

Cash	flow	from	operations	decreased	$74.6	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.

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

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

| 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $69,354 | $18,131 | $27,665 | $23,437 |

Money	pool	activity	used	$51.2	million	of	Entergy	Gulf	States'	operating	cash	flows	in	2003,	provided	$9.5	million	in	2002,	and	used	$4.2	million	in	2001. See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

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.

Net	cash	used	in	investing	activities	decreased	slightly	in	2002	compared	to	2001	because	of	the	maturity	in	2002	of	$44.6	million	of	other	temporary investments	made	in	2001.	The	decrease	in	net	cash	used	was	almost	entirely	offset	by	an	increase	of	$39.4	million	in	other	regulatory	investments,	which are	deferred	fuel	costs	expected	to	be	collected	over	a	period	greater	than	twelve	months,	and	capital	expenditures.	Capital	expenditures	increased	$37.6 million	primarily	due	to	increased	spending	on	environmental	projects.

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 retirement	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	in	dividends	paid	of	$23.3	million.

In	2003,	Entergy	Gulf	States	implemented	a	planned	financing	program	to	address	its	2003	and	2004	long-term	debt	maturities	and	to	restructure	its	debt portfolio,	which	resulted	in	extended	maturities,	lowered	rates,	and	sufficient	flexibility	in	its	portfolio	to	allow	Entergy	Gulf	States	to	economically	manage the	expected	implementation	of	retail	open	access	in	Texas	and	the	subsequent	unbundling	of	Entergy	Gulf	States	to	the	extent	it	affects	Entergy	Gulf	States' debt	portfolio.

The	following	table	lists	First	Mortgage	Bonds	issued	by	Entergy	Gulf	States	in	2003:

| June	2003 | 3.6%	Series | June	2008 | $325,000 |
| :--- | :--- | :--- | :--- |
| June\t2003 | Libor\t+\t0.90%\tSeries | June\t2007 | 275,000 |
| July\t2003 | 6.2%\tSeries | July\t2033 | 240,000 |
| July\t2003 | 5.25%\tSeries | August\t2015 | 200,000 |

The	following	table	lists	First	Mortgage	Bonds	retired	by	Entergy	Gulf	States	in	2003:

| March	2003 | Libor	+	1.2%	Series | June	2003 | 260,000 |
| :--- | :--- | :--- | :--- |
| July\t2003 | 8.94%\tSeries | January\t2022 | 150,000 |
| August\t2003 | 8.7%\tSeries | April\t2024 | 294,950 |
| September\t2003 | Libor\t+\t1.3%\tSeries | September\t2004 | 300,000 |

Entergy	Gulf	States	plans	to	retire,	at	maturity,	$292	million	of	8.25%	Series	First	Mortgage	Bonds	due	April	1,	2004	using	cash	on	hand	and	internally generated	funds.

Net	cash	provided	by	financing	activities	decreased	$34.9	million	in	2002	compared	to	2001	primarily	due	to	a	decrease	of	$30.3	million	in	net	issuances	of long-term	debt.

Entergy	Gulf	States	requires	capital	resources	for:

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

|  | 2004 | 2005-2006 | 2007-2008 | after	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| \t\tcapital\tinvestment\t(1) | $357 | $527 | N/A | N/A | $884 |
| Long-term\tdebt | $354 | $98 | $800 | $1,092 | $2,344 |
| Capital\tleases | $9 | - | - | - | $9 |
| Operating\tleases | $28 | $48 | $27 | $130 | $233 |
| Purchase\tobligations\t(2) | $54 | $10 | $6 | $32 | $102 |
| Other\tlong-term\tliabilities | $3 | $7 | $7 | - | $17 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $27 | $37 | N/A | N/A | $64 |

	(1) Includes	 approximately $220	 million each	 year	 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) As	defined	by	SEC	rule.	For	Entergy	Gulf	States	it	includes	unconditional	fuel	and	purchased power	obligations	and	other	purchase	obligations.

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

As	a	wholly-owned	subsidiary,	Entergy	Gulf	States	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.	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.

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

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.

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

# Transition	to	Retail	Competition

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

the	recommendation	that	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;	and

# Business	Separation	Plan

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

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

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

The	plan	approved	by	the	LPSC	in	September	2001,	as	described	above,	provides	that	Entergy	Gulf	States	will	be	separated	into	the	following	principal companies:

a	Texas	distribution	company,	which	will	own	and	operate	Entergy	Gulf	States'	electric	distribution	system	in	Texas;

an	intermediate	transmission	company;

a	Texas	generation	company	(which	may	be	more	than	one	legal	entity),	which	initially	will	purchase	capacity	and	energy	from	the	generating assets	allocated	to	Texas	load	(Texas	generating	assets),	and	eventually	will	own	those	assets;

Texas	retail	electric	providers,	which	will	provide	competitive	retail	electric	service	in	Texas;	and

Entergy	Gulf	States-Louisiana.

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.

Under	the	LPSC-approved	plan,	Entergy	Gulf	States'	assets	and	liabilities	(other	than	its	long-term	debt	and	liabilities)	would	be	allocated	among	these companies	generally	based	upon	categorizing	them	by	function.	Entergy	Gulf	States	would	allocate	assets	and	liabilities	not	associated	with	a	single	function based	upon	specified	factors.	In	an	April	2001	filing	with	the	LPSC	discussing	its	separation	methodology,	Entergy	Gulf	States	included	a	balance	sheet

separated	by	jurisdiction	and	function.	The	balance	sheet	was	based	on	September	30,	1999	balances.	In	this	balance	sheet,	Entergy	Gulf	States	allocated approximately	27%	of	the	net	utility	plant	balance	to	Texas	generation,	approximately	12%	to	Texas	distribution,	approximately	6%	to	Texas	transmission, approximately	7%	to	Louisiana	transmission,	and	less	than	1%	to	Texas	retail.	Applying	these	percentages	to	Entergy	Gulf	States'	December	31,	2003	net utility	plant	book	value	of	$4.7	billion,	for	 illustrative	purposes	only,	results	 in	net	book	values	of	approximately	$1.3	billion	for	Texas	generation, approximately	 $560	 million	 for	 Texas	 distribution,	 approximately	 $280	 million	 for	 Texas	 transmission,	 approximately	 $330	 million	 for	 Louisiana transmission,	approximately	$20	million	for	Texas	retail,	and	approximately	$2.2	billion	for	the	remainder	of	Entergy	Gulf	States-Louisiana.	The	actual allocations	could	materially	differ	from	these	figures	because	of	a	number	of	factors,	including	changes	to	the	plan	and	the	allocation	methodology.	In addition,	the	actual	allocations	will	be	based	on	allocation	factors	and	account	balances	as	of	a	different	date.

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

After	the	transfer	of	the	Texas	distribution	and	transmission	assets	contemplated	by	the	LPSC-approved	business	separation	plan,	the	distribution	and transmission	businesses	conducted	by	the	Texas	distribution	company	and	 the	 intermediate	 transmission	company,	respectively,	would	continue	 to	be regulated	as	to	rates	by	the	PUCT	and	the	FERC,	respectively

# Generation-related	Issues

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

When	the	Texas	generating	assets	are	transferred	to	the	Texas	generation	company,	the	Texas	generation	company	is	expected	to	sell	most	of	this	capacity and	energy	to	Entergy's	affiliated	Texas	retail	electric	providers	at	a	negotiated	rate	and	sell	any	remainder	to	the	market.	Entergy's	affiliated	Texas	retail electric	providers	will	use	the	capacity	and	energy	to	provide	retail	electric	service	to	retail	customers	in	Texas,	including	Entergy's	price-to-beat	obligation, which	requires	it	to	sell	electricity	to	residential	and	small	commercial	customers	in	the	service	territory	of	the	Texas	distribution	company	at	a	rate	equal	to the	existing	base	rates	plus	a	fuel	component.

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

Under	the	Texas	restructuring	legislation	and	a	stipulation,	Entergy	Gulf	States	offered	to	sell	at	auction	entitlements	to	approximately	15% (approximately	425MW)	of	its	Texas-jurisdictional	installed	generation	capacity.	Auctions	occurred	in	September	2001,	but	because	of	the delay	in	retail	open	access,	Entergy	has	unwound	the	auction	transactions,	and	no	liability	exists	for	them.	Additional	capacity	auctions	are suspended	until	at	least	60	days	prior	to	the	introduction	of	retail	open	access.	The	obligation	to	auction	capacity	entitlements	continues	for	up	to 60	months	after	retail	open	access	occurs,	or	until	40%	of	current	customers	have	chosen	an	alternative	supplier,	whichever	comes	first.

Under	the	settlement	of	proceedings	affecting	the	System	Agreement,	which	are	described	in	Item	I.	Part	1.	"U.S.	Utility	-	Rate	Matters	- Wholesale	Rate	Matters	-	System	Agreement,"	Entergy's	domestic	utility	companies	have	the	option	to	purchase	up	to	5%	of	the	megawatt capacity	of	the	Texas	generating	assets.	If	the	capacity	purchase	is	elected,	it	will	be	for	the	period	from	the	inception	of	retail	open	access	in Texas	for	Entergy	Gulf	States	through	June	2008.

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

# Resumption	of	Business	Separation	Proceedings	at	the	LPSC

In	January	2004,	the	LPSC	Staff	and	Entergy	Gulf	States	filed	a	joint	motion	in	the	LPSC	docket	to	convene	a	status	conference	for	the	purpose	of establishing	a	procedural	schedule	to	address	primarily	the	separation	of	Entergy	Gulf	States'	generation	resources.	The	status	conference	was	conducted	in February	2004.	The	presiding	Administrative	Law	Judge	established	a	procedural	schedule	that,	among	other	things,	calls	for	Entergy	Gulf	States	to	file testimony	on	March	1,	2004,	and	sets	this	case	for	hearing	on	September	13-17,	2004.	In	its	March	1,	2004	filing,	Entergy	Gulf	States	proposed	two significant	modifications	to	the	plan	previously	approved	by	the	LPSC.

First,	Entergy	Gulf	States	proposed	to	separate	the	Texas-jurisdictional	generation	resources	immediately	upon	unbundling,	resulting	in	the	co-ownership	of all	Entergy	Gulf	States'	generating	plants	by	Entergy	Gulf	States-Louisiana	and	the	Texas	generation	company,	unless	an	agreement	can	be	reached	and approved	by	the	LPSC	on	the	allocation	of	certain	generating	assets	by	specific	plant.	The	Texas	generation	company	would	assume	the	long-term	debt allocable	to	the	Texas	jurisdictional	generation	assets	through	a	Debt	Assumption	Agreement.	The	Debt	Assumption	Agreement	would	be	secured	by	a	first priority	lien	in	favor	of	Entergy	Gulf	States-Louisiana	on	all	the	assets	separated	to	the	Texas	generation	company,	and	the	Texas	generation	company	would provide	the	funds	necessary	to	retire	the	assumed	long-term	debt	no	later	than	three	years	after	the	commencement	of	retail	open	access	in	Entergy	Gulf States'	Texas	service	territory.	In	addition,	this	Debt	Assumption	Agreement	would	be	supported	by	an	Entergy	Corporation	indemnity,	which	would	be executed	 simultaneously	 with	 the	 Debt	Assumption	Agreement,	 on	 terms	 similar	 to	 the	 contingent	 indemnity	 previously	 approved	 by	 the	 LPSC	 in connection	with	the	separation	of	transmission	assets.	The	indemnity	would	terminate	at	the	same	time	as	the	Debt	Assumption	Agreement.

Second,	 Entergy	 Gulf	 States	 proposed	 that	 its	 Texas	 jurisdictional	 transmission	 and	 distribution	 assets	 would	 be	 immediately	 separated	 to	 a	 Texas transmission	and	distribution	company	providing	transmission	and	distribution	services	to	Entergy	Gulf	States'	Texas	customers.	The	Texas	transmission and	distribution	company	would	own	the	distribution	assets	located	in	Texas	and	would	co-own	Entergy	Gulf	States'	transmission	assets	with	Entergy	Gulf States-Louisiana.	The	Texas	transmission	and	distribution	company	would	assume	the	long-term	debt	allocable	to	the	Texas	jurisdictional	transmission	and distribution	assets	through	a	Debt	Assumption	Agreement.	The	Debt	Assumption	Agreement	would	be	secured	by	a	first	priority	lien	in	favor	of	Entergy Gulf	States-Louisiana	on	all	of	the	assets	separated	to	the	Texas	transmission	and	distribution	company.	The	Texas	transmission	and	distribution	company will	provide	the	funds	necessary	to	retire	the	assumed	long-term-debt	within	one	year.	If	the	long-term	debt	is	not	retired	by	that	time,	Entergy	Corporation will	grant	a	contingent	indemnity	in	favor	of	Entergy	Gulf	States-Louisiana	until	such	time	as	the	long-term	debt	is	retired,	which	is	not	to	be	later	than	three

years	after	the	commencement	of	retail	open	access	in	Entergy	Gulf	States'	Texas	service	territory.

# Other	PUCT	Restructuring-related	Proceedings

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

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

In	July	2001,	Entergy	Gulf	States	filed	an	application	for	approval	of	the	fuel	factor	portion	of	Entergy's	affiliated	Texas	retail	electric	provider's	price-to- beat	rates,	and	the	gas	prices	included	in	that	filing	were	updated	in	October	2001.	After	the	gas	price	update,	Entergy	Gulf	States	recommended	that	the PUCT	approve	an	average	fuel	factor	of	approximately	$29/MWh	adjusted,	if	necessary,	to	maintain	an	adequate	competitive	margin.	After	hearing,	an	ALJ recommended	in	November	2002	a	lower	fuel	factor	than	Entergy	Gulf	States	requested.	In	September	2003,	the	PUCT	issued	a	written	order	that	approved the	Price	to	Beat	(PTB)	fuel	factor	for	Entergy	Gulf	States,	which	is	to	be	implemented	upon	the	commencement	of	retail	open	access	in	its	Texas	service territory.	This	PTB	fuel	factor	is	subject	to	revision	based	on	PUCT	rules.	The	PUCT	declined	consideration	of	a	request	for	rehearing	sought	by	certain cities	in	Texas	served	by	Entergy	Gulf	States	and	the	Office	of	Public	Utility	Counsel.	The	Office	of	Public	Utility	Counsel	has	appealed	this	decision	to	the Texas	courts.	Management	cannot	predict	the	ultimate	outcome	of	the	proceeding	at	this	time.

In	June	2001,	Entergy	Gulf	States	filed	tariffs	for	the	non-fuel	component	of	the	price-to-beat	rates.	The	tariffs	are	based	on	Entergy	Gulf	States'	current	base rates.	In	September	2001,	Entergy	Gulf	States	entered	into	a	unanimous	settlement	regarding	the	non-fuel	component	of	price-to-beat	rates.	In	February 2002,	the	PUCT	voted	to	approve	the	settlement.	In	May	2002,	certain	Texas	cities	served	by	Entergy	Gulf	States	Texas	appealed	the	PUCT	order.	 The appeal	is	currently	pending	in	state	district	court	in	Texas	County.

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

In	December	2002,	the	LPSC	approved	a	settlement	between	Entergy	Gulf	States	and	the	LPSC	staff	pursuant	to	which	Entergy	Gulf	States	agreed	to	make a	base	rate	refund	of	$16.3	million,	 including	 interest,	and	 to	 implement	a	$22.1	million	prospective	base	rate	reduction	effective	January	2003.	The settlement	discharged	any	potential	liability	for	claims	that	relate	to	Entergy	Gulf	States'	fourth,	fifth,	sixth,	seventh,	and	eighth	earnings	reviews.	Entergy Gulf	States	made	the	refund	in	February	2003.	In	addition	to	resolving	and	discharging	all	liability	associated	with	the	fourth	through	eighth	earnings reviews,	the	settlement	provides	that	Entergy	Gulf	States	shall	be	authorized	to	continue	to	reflect	in	rates	a	ROE	of	11.1%	until	a	different	ROE	is authorized	by	a	final	resolution	disposing	of	all	issues	in	the	proceeding	that	was	commenced	with	Entergy	Gulf	States'	May	2002	filing.

In	May	2002,	Entergy	Gulf	States	filed	its	ninth	and	last	required	post-merger	analysis	with	the	LPSC.	The	filing	includes	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	filed	in	December	2003, the	LPSC	staff	recommended	a	rate	refund	of	$30.6	million	and	a	prospective	rate	reduction	of	approximately	$50	million.	Hearings	are	scheduled	to	begin in	April	2004.

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.

In	its	complaint,	the	LPSC	alleges	that	Entergy	Gulf	States'	Louisiana	annual	production	costs	over	the	period	2002	to	2007	will	be	$11	million	to	$87 million	over	the	average	for	the	domestic	utility	companies.	This	range	of	results	is	a	function	of	assumptions	regarding	such	things	as	future	natural	gas prices,	the	future	market	price	of	electricity,	and	other	factors.	If	FERC	grants	the	relief	requested	by	the	LPSC,	the	relief	may	result	in	a	material	increase	in production	costs	allocated	to	companies	whose	costs	currently	are	projected	to	be	less	than	the	average	and	a	material	decrease	in	production	costs	allocated

to	companies	whose	costs	currently	are	projected	 to	exceed	 the	average.	Management	believes	that	any	changes	in	the	allocation	of	production	costs resulting	from	a	FERC	decision	should	result	in	similar	rate	changes	for	retail	customers.	Therefore,	management	does	not	believe	that	this	proceeding	will have	a	material	effect	on	the	financial	condition	of	Entergy	Gulf	States,	although	neither	the	timing	nor	the	outcome	of	the	proceedings	at	FERC	can	be predicted	at	this	time.	In	February	2002,	the	FERC	established	a	refund	effective	period	consisting	of	the	15	months	following	September	13,	2001.	A subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

# 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	lost	two	large	industrial	customers	to	cogeneration	in	2002.	The	customers	accounted	for	approximately	1%	of	Entergy	Gulf	States'	net	revenue in	2002.	Entergy	Gulf	States	expects	to	lose	one	additional	customer	to	cogeneration	in	2005.	Current	sales	to	that	customer	account	for	approximately	$11 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.	As	a	result	of	those	efforts,	one	large	industrial customer	is	in	the	process	of	shutting	down	its	cogeneration	unit	and	is	under	contract	to	receive	100%	of	its	electric	power	from	Entergy	Gulf	States	and	an agreement	has	been	executed	to	provide	service	to	a	new	large	industrial	customer	locating	in	Louisiana.	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.

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.

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

Entergy	Gulf	States	entered	into	a	foreign	currency	forward	contract	to	hedge	the	Euro-denominated	payments	due	under	certain	purchase	contracts.	As	of December	31,	2003,	the	total	notional	amount	of	the	foreign	currency	forward	contracts	is	17.2	million	Euro	and	the	forward	currency	rate	is	.8742.	This forward	contract	matures	in	July	2004	and	the	mark-to-market	valuation	at	December	31,	2003	was	a	net	asset	of	$6.5	million.	The	counterparty	bank obligated	on	this	agreement	is	rated	by	Standard	&	Poor's	Rating	Services	at	AA	on	its	senior	debt	obligations	as	of	December	31,	2003.

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

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

# Litigation	Risks

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

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

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

Cost	Escalation	Factors	-	Entergy	Gulf	States'	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over present	cost	levels	by	an	annual	factor	averaging	approximately	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.	Entergy	Gulf	States'	decommissioning	studies	for	River	Bend	assume	immediate	decommissioning	upon	expiration	of	the	original plant	license.	While	the	impact	of	these	assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a "safestore"	status	can	significantly	decrease	the	present	value	of	these	obligations.

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

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

Entergy	Gulf	States	collects	the	projected	costs	of	decommissioning	River	Bend	through	rates	charged	to	customers	for	the	portion	of	the	plant	subject	to cost-based	ratemaking.	The	amounts	collected	through	rates,	which	are	based	upon	decommissioning	cost	studies,	are	deposited	in	decommissioning	trust funds.	In	December	2002,	decommissioning	collections	from	customers	for	the	Louisiana-regulated	portion	of	River	Bend	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	were	changed	and approved	by	regulators,	collections	from	customers	would	also	change.

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

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

Entergy	Gulf	States	implemented	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	effective	January	1,	2003.	Nuclear	decommissioning	costs comprise	substantially	all	of	Entergy	Gulf	States'	asset	retirement	obligations,	and	the	measurement	and	recording	of	Entergy	Gulf	States'	decommissioning obligations	outlined	above	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	to	date	have	been	based	on	Entergy	Gulf	States	performing	the	work,	and	have	not	included	any	such	margins or	premiums.	Inclusion	of	these	items	increases	cost	estimates.

The	net	effect	of	implementing	this	standard	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,	assets	and	liabilities	increased	in	2003	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.	Applying	SFAS	143	is	not	expected	to	have	a	material	effect	on	Entergy	Gulf	States' earnings	on	an	ongoing	basis	after	its	implementation.

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

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

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

Retail	open	access	legislation	is	in	place	in	Texas,	but	the	implementation	of	retail	open	access	in	Entergy	Gulf	States'	territory	is	likely	delayed	until	at	least the	first	quarter	of	2005.	Several	proceedings	necessary	to	implement	retail	open	access	are	still	pending,	including	proceedings	to	implement	Entergy	Gulf States'	business	separation	plan	and	to	pursue	retail	open	access	in	the	absence	of	an	RTO	in	Entergy	Gulf	States'	Texas	service	area.	In	addition,	the	LPSC has	not	approved	for	the	Louisiana	jurisdictional	operations	the	transfer	of	generation	assets	to	Entergy's	Texas	generation	company.	Therefore,	neither	the necessary	regulatory	actions	nor	the	opportunity	for	a	reasonable	determination	of	the	effect	of	deregulation	has	occurred	that	are	prerequisites	for	Entergy Gulf	States	to	discontinue	the	application	of	regulatory	accounting	principles	to	its	Texas	generation	operation.

In	selecting	an	assumed	discount	rate,	Entergy	reviews	market	yields	on	high-quality	corporate	debt.	Based	on	recent	market	trends,	Entergy	reduced	its discount	rate	from	7.5%	in	2001	and	6.75%	in	2002	to	6.25%	in	2003.	Entergy	reviews	actual	recent	cost	trends	and	projected	future	trends	in	establishing health	care	cost	trend	rates.	Based	on	this	review,	Entergy	increased	its	health	care	cost	trend	rate	assumption	used	in	calculating	the	2003	accumulated

postretirement	benefit	obligation.	The	assumed	health	care	cost	trend	rate	is	a	10%	increase	in	health	care	costs	in	2004	gradually	decreasing	each	successive year	until	it	reaches	a	4.5%	annual	increase	in	health	care	costs	in	2010	and	beyond.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Pension	Cost | Impact	on	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $631 | $15,172 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,194 | - |
| Rate\tof\tincrease\tin | 0.25% | $495 | $3,896 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $942 | $5,028 |
| Discount\trate | (0.25%) | $533 | $5,449 |

Total	pension	cost	for	Entergy	Gulf	States	in	2003	was	$1.8	million,	including	a	$5	million	charge	related	to	the	Voluntary	Severance	Program.	 Entergy Gulf	States	is	projecting	2004	pension	cost	to	be	$3.1	million	due	to	a	decrease	in	the	discount	rate	from	6.75%	to	6.25%	and	the	phased-in	effect	of	poor asset	performance.	Entergy	Gulf	States	was	not	required	to	make	contributions	to	its	pension	plan	in	2003,	however,	it	anticipates	making	$37	thousand	in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	Entergy	Gulf	States'	accumulated	benefit	obligation	at	December	31,	2002	exceeded	plan assets.	As	a	result,	Entergy	Gulf	States	was	required	to	recognize	an	additional	minimum	liability	as	prescribed	by	SFAS	87.	At	December	31,	2003	Entergy Gulf	States	reversed	its	additional	minimum	liability	and	offsetting	intangible	asset	of	$7.1	million	that	were	recorded	at	December	31,	2002.	Net	income	for 2003	and	2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Gulf	States	in	2003	were	$26.5	million,	including	a	$6.8	million	charge	related	to the	Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	Entergy Gulf	States	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	be	approximately	$20.1	million.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Gulf	States,	Inc.	as	of	December	31,	2003	and	2002,	and	the	related	statements	of	income, retained	earnings	and	comprehensive	income,	and	cash	flows	(pages	190	through	194	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three years	in	the	period	ended	December	31,	2003.	These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to express	an	opinion	on	these	financial	statements	based	on	our	audits.

We	conducted	our	audits	in	accordance	with	auditing	standards	generally	accepted	in	the	United	States	of	America.	Those	standards	require	that	we	plan	and perform	the	audit	to	obtain	reasonable	assurance	about	whether	the	financial	statements	are	free	of	material	misstatement.	An	audit	includes	examining,	on	a

test	basis,	evidence	supporting	the	amounts	and	disclosures	in	the	financial	statements.	An	audit	also	includes	assessing	the	accounting	principles	used	and significant	estimates	made	by	management,	as	well	as	evaluating	the	overall	financial	statement	presentation.	We	believe	that	our	audits	provide	a	reasonable basis	for	our	opinion.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Gulf	States,	Inc.	as	of	December	31,	2003 and	2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	1	and	Note	9	to	the	notes	to	respective	financial	statements,	Entergy	Gulf	States,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	 Standards	 No. 143,	Accounting for Asset Retirement	 Obligations,	and	 Financial	 Accounting	 Standards	 Board	 Interpretation	 No. 46, Consolidation	of	Variable	Interest	Entities,	in	2003.

			(Page	left	blank	intentionally)

Noncash	items	included	in	net	income:

Commitments	and	Contingencies

# 								STATEMENTS	OF	RETAINED	EARNINGS	AND	COMPREHENSIVE	INCOME

Balance	at	beginning	of	period:

# Net	derivative	instrument	fair	value	changes

# ENTERGY	GULF	STATES,	INC.	AND	SUBSIDIARIES

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,639,737 | $2,183,879 | $2,648,560 | $2,511,240 | $2,127,208 |
| Net\tincome | $42,562 | $174,078 | $179,444 | $180,343 | $125,000 |
| Total\tassets | $6,854,862 | $6,599,533 | $6,209,741 | $6,134,017 | $5,733,022 |
| Long-term\tobligations\t(1) | $2,051,083 | $2,096,329 | $2,130,245 | $1,978,149 | $1,966,269 |

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

# ENTERGY	LOUISIANA,	INC.

Net	income	increased	slightly	primarily	due	to	increased	net	revenue	and	decreased	interest	charges,	almost	entirely	offset	by	increased	other	operation	and maintenance	expenses,	increased	depreciation	and	amortization	expenses,	and	increased	taxes	other	than	income	taxes.

Net	income	increased	$12.2	million	primarily	due	to	increased	net	revenue,	decreased	taxes	other	than	income	taxes,	and	decreased	interest	charges,	partially offset	by	increased	other	operation	and	maintenance	expenses	and	increased	depreciation	and	amortization	expenses.

| 2002	net	revenue | $922.9 |
| :--- | :--- |
| Fuel\tprice | 59.1 |
| Asset\tretirement\tobligation | 8.2 |
| Volume | (16.2) |
| Vidalia\tsettlement | (9.2) |
| Other | 8.9 |
| 2003\tnet\trevenue | $973.7 |

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

The	volume	variance	is	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.

The	$9.2	million	decrease	is	due	to	the	September	2002	settlement	related	to	the	Vidalia	contract.	See	"Liquidity	and	Capital	Resources"	below	for	more details.

Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	charges

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	charges	decreased	primarily	due	to:

a	decrease	of	$8.2	million	due	to	the	change	in	accounting	for	asset	retirement	obligations	in	compliance	with	SFAS	143,	adopted	in	January 2003.	This	decrease	has	no	effect	on	net	income;	and

a	decrease	of	$5.9	million	due	to	deferred	capacity	charges	recorded	in	the	third	quarter	as	allowed	by	the	LPSC	related	to	generation	resource planning.

| 2001	net	revenue | $895.8 |
| :--- | :--- |
| Fuel\tprice | 45.0 |
| Volume | 79.5 |
| System\tEnergy\trefund\tin\t2001 | (68.1) |
| Summer\tcapacity\tcharges | (23.0) |
| Other | (6.3) |
| 2002\tnet\trevenue | $922.9 |

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

The	volume	variance	is	due	to	an	increase	in	electricity	usage	in	the	service	territory.	Billed	usage	increased	a	total	of	1,042	GWh	primarily	in	the	residential and	industrial	sectors.

The	effect	of	the	System	Energy	refund	resulted	from	System	Energy's	application	to	FERC	in	May	1995	for	a	rate	increase,	which	it	implemented	in December	1995,	subject	to	refund.	The	request	sought	changes	to	System	Energy's	rate	schedule,	including	increases	in	the	revenue	requirement	associated with	decommissioning	costs,	the	depreciation	rate,	and	the	rate	of	return	on	common	equity.	In	July	2000,	FERC	approved	a	lower	rate	of	return	than	the rate	sought	by	System	Energy.	Upon	receipt	of	a	final	FERC	order	in	July	2001,	Entergy	Louisiana	recorded	entries	to	spread	the	impacts	of	FERC's	order	to the	various	revenue,	expense,	asset,	and	 liability	accounts	affected,	as	 if	 the	order	had	been	 in	place	since	commencement	of	 the	case	 in	1995.	The accounting	entries	necessary	to	record	the	effects	of	the	order	reduced	Entergy	Louisiana's	purchased	power	expenses	by	$68.1	million	in	2001,	which resulted	in	a	corresponding	increase	in	net	revenue	in	2001.

Summer	capacity	charges	decreased	net	revenue	due	to	the	deferral	in	2001	of	capacity	charges	included	in	purchased	power	costs	for	the	summers	of	2000 and	 2001	 and	 the	 amortization	 of	 these	 capacity	 charges	 in	 2002.	The	 amortization	 of	 the	 summer	 2000	 capacity	 charges	 ended	 in	 July	 2002.	The amortization	of	the	capacity	charges	for	the	summer	of	2001	began	in	August	2002	and	ended	in	July	2003.

Gross	operating	revenues	decreased	primarily	due	to	a	decrease	in	fuel	cost	recovery	revenues	of	$202.9	million	due	to	lower	fuel	rates,	partially	offset	by	an increase	in	price	applied	to	unbilled	sales	of	$45	million	and	an	increase	in	sales	volume	of	$79.5	million,	as	discussed	above.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to:

the	decline	in	natural	gas	prices	in	2002;

a	decrease	in	the	average	price	of	purchased	power;	and

a	decrease	in	deferred	fuel	expense	due	to	lower	fuel	revenues.

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

Other	regulatory	charges	increased	primarily	due	to	the	deferred	capacity	charges	discussed	above.

voluntary	severance	program	accruals	of	$19.7	million;	and

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	is	offset	by regulatory	credits	and	interest	and	dividend	income	and	has	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.

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.

an	increase	of	$13.3	million	in	fossil	expenses	due	to	maintenance	outages	at	the	Ninemile	Point,	Little	Gypsy,	and	Waterford	fossil	plants	and turbine	inspection	costs	at	the	Sterlington	fossil	plant;

an	increase	of	$4.4	million	in	outside	services	employed;	and

an	increase	of	$4.4	million	in	transportation	costs.

Taxes	other	than	income	taxes	decreased	due	to	franchise	tax	adjustments	of	$10.8	million	as	a	result	of	a	favorable	court	decision	which	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	combined	with	revisions	made	to	the	useful	lives	of	certain intangible	plant	assets	to	more	appropriately	reflect	their	actual	lives,	which	lowered	expense	in	2001	in	accordance	with	regulatory	treatment.

Interest	charges	decreased	primarily	due	to	the	following:

adjustments	of	$3.5	million	to	interest	expense	previously	recorded	on	franchise	tax	accruals	as	a	result	of	the	franchise	tax	adjustment discussed	above;

a	decrease	of	$5.9	million	in	interest	on	long-term	debt	due	to	the	refinancing	and	net	redemption	of	First	Mortgage	Bonds	in	the	amounts	of $18.7	million	in	2001	and	$140	million	in	2002;	and

interest	of	$4.6	million	accrued	in	2001	on	reserves	provided	for	fuel-related	refunds	that	were	made	in	the	summer	of	2001.

The	effective	income	tax	rates	for	2003,	2002,	and	2001	were	40.0%,	36.9%,	and	39.4%.	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.

| Cash	and	cash	equivalents	at	beginning	of	period | $311,800 | $42,408 | $43,959 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 413,939 | 1,035,777 | 430,515 |
| Investing\tactivities | (268,372) | (212,333) | (218,331) |
| Financing\tactivities | (448,580) | (554,052) | (213,735) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (303,013) | 269,392 | (1,551) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $8,787 | $311,800 | $42,408 |

Cash	flow	from	operations	decreased	$621.8	million	in	2003	and	increased	$605.3	million	in	2002	as	a	result	of	Entergy	Louisiana	changing	its	method	of accounting	for	tax	purposes	related	to	the	contract	to	purchase	power	from	the	Vidalia	project	(the	contract	is	discussed	in	Note	9	to	the	domestic	utility companies	and	System	Energy	financial	statements).	The	new	tax	accounting	method	provided	a	cumulative	cash	flow	benefit	of	approximately	$867	million in	2002,	which	is	expected	to	reverse	in	the	years	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	I	for	additional	details concerning	the	settlement.

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

| 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| ($41,317) | $18,854 | $3,812 | $22,907 |

Money	pool	activity	provided	$60.2	million	of	Entergy	Louisiana's	operating	cash	flow	in	2003,	used	$15.0	million	in	2002,	and	provided	$19.1	million	in 2001.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

The	increase	of	$56.0	million	in	net	cash	used	by	investing	activities	in	2003	was	primarily	due	to	increased	spending	of	$47.9	million	on	customer	service, transmission,	and	nuclear	projects.

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	was	partially	offset	by	the	following:

the	retirement	in	2003,	at	maturity,	of	$150	million	of	8.5%	Series	First	Mortgage	Bonds	using	cash	on	hand	and	the	retirement	of	$110.95 million	of	5.35%	Series	St.	Charles	Parish	Bonds	using	a	combination	of	cash	on	hand	and	short-term	borrowings	compared	to	the	net retirement	of	$134.6	million	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.

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

the	net	retirement	of	an	additional	$120.9	million	of	first	mortgage	bonds	in	2002;

an	increase	in	common	stock	dividends	paid	of	$136.8	million;	and

the	repurchase	of	$120	million	of	common	stock	from	Entergy	Corporation.

See	Note	5	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	details	of	long-term	debt.

# Entergy	Louisiana	requires	capital	resources	for:

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

|  | 2004 | 2005-2006 | 2007-2008 | After	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| \t\tcapital\tinvestment\t(1) | $454 | $375 | N/A | N/A | $829 |
| Long-term\tdebt | $15 | $55 | $115 | $717 | $902 |
| Operating\tleases | $13 | $12 | $4 | $2 | $31 |
| Purchase\tobligations\t(2) | $1,062 | $821 | $580 | $1,649 | $4,112 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $36 | $30 | N/A | N/A | $66 |

(2) As	defined	by	SEC	rule.	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	9	to	the domestic	utility	companies	and	System	Energy	financial	statements.

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 construction	expenditures	and	long-term	debt	and	preferred	stock	maturities	in	Notes	5,	7,	and	9	to	the	domestic	utility	companies	and	System	Energy financial	statements.

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

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

bank	financing	under	new	and	existing	facilities.

In	2002,	Entergy	Louisiana	issued	$150	million	of	long-term	debt	and	used	a	portion	of	the	proceeds	to	redeem	$115	million	of	outstanding	debt.	The remaining	net	proceeds	were	used	to	reduce	short-term	indebtedness	incurred	for	working	capital	and	other	purposes.	Entergy	Louisiana	is	expected	to continue	refinancing	or	redeeming	higher-cost	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Louisiana	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also subject	to	issuance	tests	set	forth	in	corporate	charters,	bond	indentures,	and	other	agreements.	Entergy	Louisiana	has	sufficient	capacity	under	these	tests	to meet	its	foreseeable	capital	needs.

Short-term	borrowings	by	Entergy	Louisiana,	including	borrowings	under	the	money	pool,	are	limited	to	an	amount	authorized	by	the	SEC,	$225	million. Under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	Entergy	Louisiana	cannot	incur	new	short-term	indebtedness	if	its	common	equity	would comprise	less	than	30%	of	its	capital.	In	addition,	Entergy	Louisiana	is	restricted	from	publicly	issuing	new	long-term	debt	unless	its	senior	secured	debt	will

be	rated	as	investment	grade.	Entergy	Louisiana	has	a	364-day	credit	facility	available	expiring	May	2004	in	the	amount	of	$15	million	of	which	none	was drawn	at	December	31,	2003.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	Entergy Louisiana's	short-term	borrowing	limits.

Major	changes	are	occurring	in	the	wholesale	and	retail	electric	utility	business,	including	in	the	electric	transmission	business.	In	a	July	2001	report	to	the LPSC,	the	LPSC	staff	concluded	that	retail	competition	is	not	in	the	public	interest	at	this	time	for	any	customer	class.	Nevertheless,	the	LPSC	staff recommended	that	retail	open	access	be	made	available	for	certain	large	industrial	customers	as	early	as	January	2003.	An	eligible	customer	choosing	to	go to	competition	would	be	required	to	provide	its	utility	with	a	minimum	of	six	months	notice	prior	to	the	date	of	retail	open	access.	The	LPSC	staff	report	also recommended	that	all	customers	who	do	not	currently	co-	or	self-generate,	or	have	co-	or	self-generation	under	construction	as	of	a	date	to	be	specified	by the	LPSC,	remain	liable	for	their	share	of	stranded	costs.	During	its	October	2001	meeting,	the	LPSC	adopted	dates	by	which	a	total	of	800	MW	of	co-	or self-generation	could	be	developed	in	Louisiana	without	being	affected	by	stranded	costs.	During	its	November	2001	meeting,	the	LPSC	decided	not	to adopt	a	plan	for	retail	open	access	at	this	time,	but	to	have	collaborative	group	meetings	concerning	open	access	from	time	to	time,	and	to	have	the	LPSC staff	monitor	developments	in	neighboring	states	and	to	report	to	the	LPSC	regarding	the	progress	of	retail	access	developments	in	those	states.	No	further action	has	been	taken	by	the	LPSC	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	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	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	midpoint currently	in	effect	is	10.5%.	A	procedural	schedule	has	not	yet	been	established.

Performance-based	formula	rate	plan	filings	expired	in	2001	for	Entergy	Louisiana.	In	conjunction	with	the	LPSC	staff,	Entergy	Louisiana	continues	to pursue	development	of	a	generation	incentive	structure.

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.

In	its	complaint,	the	LPSC	alleges	that	Entergy	Louisiana's	annual	production	costs	over	the	period	2002	to	2007	will	be	$132	million	to	$139	million	over the	average	for	the	domestic	utility	companies.	This	range	of	results	is	a	function	of	assumptions	regarding	such	things	as	future	natural	gas	prices,	the	future market	price	of	electricity,	and	other	factors.	If	FERC	grants	the	relief	requested	by	the	LPSC,	the	relief	may	result	in	a	material	increase	in	production	costs allocated	to	companies	whose	costs	currently	are	projected	to	be	less	than	the	average	and	a	material	decrease	in	production	costs	allocated	to	companies whose	costs	currently	are	projected	to	exceed	the	average.	Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	a FERC	decision	should	result	in	similar	rate	changes	for	retail	customers.	Therefore,	management	does	not	believe	that	this	proceeding	will	have	a	material effect	on	the	financial	condition	of	Entergy	Louisiana,	although	neither	the	timing	nor	the	outcome	of	the	proceedings	at	FERC	can	be	predicted	at	this	time. In	February	2002,	the	FERC	set	the	matter	for	hearing	and	established	a	refund	effective	period	consisting	of	the	15	months	following	September	13,	2001. A	subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

In	January	2003	the	domestic	utility	companies	filed	testimony	in	the	case,	showing	that	over	the	life	of	the	System	Agreement	the	relative	total	production costs	of	the	domestic	utility	companies	are	roughly	equal,	and	suggesting	that	no	changes	to	the	System	Agreement	such	as	those	sought	by	the	LPSC	are appropriate.	In	April	2003,	witnesses	on	behalf	of	the	FERC	staff	filed	testimony	in	the	proceeding	suggesting	that	full	production	cost	equalization	should not	be	adopted	by	the	FERC	in	this	case,	and	that	when	measured	over	a	suitably	long	period,	the	total	production	costs	of	the	domestic	utility	companies were	roughly	equal	and	were	likely	to	remain	so,	given	the	Entergy	System's	proposed	resource	plan.	Hearings	in	the	proceeding	ended	in	late-August	2003. The	 Initial	 Decision	 of	 the	 FERC	ALJ	 was	 released	 on	 February	 6,	 2004.	The	ALJ	 concludes	 that	 full	 production	 cost	 equalization	 should	 not	 be implemented;	that	the	Entergy	System	currently	is	not	in	rough	production	cost	equalization	and	is	not	likely	to	be	in	rough	production	cost	equalization	for

the	foreseeable	future;	and	that	the	appropriate	remedy	to	achieve	rough	equalization	is	to	have	the	low	cost	companies	compensate	the	high	cost	companies whenever	one	or	more	companies'	annual	total	production	costs	from	2003	forward	differ	by	more	than	+/-	7.5%	from	the	Entergy	System	average	annual total	production	costs,	or	whenever	the	three	year	average	of	one	or	more	companies'	total	production	costs	(commencing	with	the	three	years	2004	through 2006,	and	yearly	 thereafter)	differ	by	more	 than	+/-	5%	from	 the	Entergy	System	average	 total	production	costs	during	any	 three	year	cycle.	In	 the calculation	of	what	each	company's	total	production	costs	are,	the	ALJ	determined	that	the	full	cost	of	Vidalia	project	power	purchases	by	Entergy	Louisiana should	be	included,	but	the	ALJ	rejected	other	adjustments	proposed	by	the	LPSC.	Also,	the	ALJ	determined	that	the	average	of	the	four	highest	monthly demand	peaks	for	the	year	(4	CP)	should	be	used	for	calculating	reserve	sharing	costs,	rather	than	the	current	12	CP	method.	Finally,	the	ALJ	determined that	there	is	no	valid	issue	concerning	"billing	versus	dispatch"	in	the	rate	schedule	by	which	exchange	energy	is	priced,	MSS-3,	that	MSS-3	has	not	been misapplied	or	misinterpreted	by	Entergy,	and	that	MSS-3	should	not	be	changed.		The	ALJ's	Initial	Decision	did	not	specifically	address	refund	exposure.

# 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	marketing	efforts	in	retaining	industrial	customers.

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.

Entergy	Louisiana's	nuclear	decommissioning	trust	funds	expose	it	to	fluctuations	in	equity	prices	and	interest	rates.	The	NRC	requires	Entergy	Louisiana	to maintain	trusts	to	fund	the	costs	of	decommissioning	Waterford	3.	The	funds	are	invested	primarily	in	equity	securities;	fixed-rate,	fixed-income	securities; and	cash	and	cash	equivalents.	Management	believes	that	its	exposure	to	market	fluctuations	will	not	affect	results	of	operations	for	the	Waterford	3	trust funds	because	of	the	application	of	regulatory	accounting	principles.	The	decommissioning	trust	funds	are	discussed	more	thoroughly	in	Notes	1	and	9	to	the domestic	utility	companies	and	System	Energy	financial	statements.

Entergy	Louisiana	owns	and	operates,	through	an	affiliate,	Waterford	3.	Entergy	Louisiana	is,	therefore,	subject	to	the	risks	related	to	owning	and	operating a	nuclear	plant.	These	include	risks	from	the	use,	storage,	handling	and	disposal	of	high-level	and	low-level	radioactive	materials,	limitations	on	the	amounts and	types	of	insurance	commercially	available	for	losses	in	connection	with	nuclear	operations,	and	technological	and	financial	uncertainties	related	to decommissioning	 nuclear	 plants	 at	 the	 end	 of	 their	 licensed	 lives,	 including	 the	 sufficiency	 of	 funds	 in	 decommissioning	 trusts.	In	 the	 event	 of	 an unanticipated	 early	 shutdown	 of	Waterford	 3,	 Entergy	 Louisiana	 may	 be	 required	 to	 provide	 additional	 funds	 or	 credit	 support	 to	 satisfy	 regulatory requirements	for	decommissioning.

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.

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

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

Regulations	require	that	Waterford	3	be	decommissioned	after	the	facility	is	taken	out	of	service,	and	funds	are	collected	and	deposited	in	trust	funds	during the	facility's	operating	life	in	order	to	provide	for	this	obligation.	Entergy	Louisiana	conducts	periodic	decommissioning	cost	studies	(typically	updated every	three	to	five	years)	to	estimate	the	costs	that	will	be	incurred	to	decommission	the	facility.	See	Note	9	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	details	regarding	Entergy	Louisiana's	most	recent	study	and	 the	obligations	recorded	by	Entergy	Louisiana	related	 to decommissioning.	The	following	key	assumptions	have	a	significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	Entergy	Louisiana's	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over present	cost	levels	by	an	annual	factor	averaging	approximately	4.4%.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost of	decommissioning	a	facility	by	as	much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin immediately	upon	plant	retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable regulations.	Entergy	Louisiana's	decommissioning	studies	for	Waterford	3	assume	immediate	decommissioning	upon	expiration	of	the	original plant	license.	While	the	impact	of	these	assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a "safestore"	status	can	significantly	decrease	the	present	value	of	these	obligations.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	Department	of	Energy	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear fuel,	and	recent	legislation	has	been	passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	However,	until	this	site	is available,	nuclear	plant	operators	must	provide	for	interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs	of	developing	and	maintaining	these	facilities	can	have	a	significant	impact (as	much	as	16%	of	estimated	decommissioning	costs).	Entergy	Louisiana's	decommissioning	studies	include	cost	estimates	for	spent	fuel storage.	However,	these	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening	of	the	Yucca	Mountain	facility,	the	schedule for	shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

Entergy	Louisiana	collects	substantially	all	of	 the	projected	costs	of	decommissioning	Waterford	3	 through	rates	charged	 to	customers.	The	amounts collected	through	rates,	which	are	based	upon	decommissioning	cost	studies,	are	deposited	in	decommissioning	trust	funds.	These	collections	plus	earnings on	the	trust	fund	investments	are	estimated	to	be	sufficient	to	fund	the	future	decommissioning	costs.	If	decommissioning	cost	study	estimates	were	changed and	approved	by	regulators,	collections	from	customers	would	also	change.

Prior	 to	 the	 implementation	 of	 SFAS	 143,	 the	 obligations	 recorded	 by	 Entergy	 Louisiana	 for	 decommissioning	 were	 classified	 as	 a	 component	 of accumulated	depreciation.	The	amounts	recorded	for	these	obligations	were	comprised	of	collections	from	customers	and	earnings	on	the	trust	funds.

Entergy	Louisiana	implemented	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	effective	January	1,	2003.	Nuclear	decommissioning	costs comprise	substantially	all	of	Entergy	Louisiana's	asset	retirement	obligations,	and	the	measurement	and	recording	of	Entergy	Louisiana's	decommissioning obligations	outlined	above	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	to	date	have	been	based	on	Entergy	Louisiana	performing	the	work,	and	have	not	included	any	such margins	or	premiums.	Inclusion	of	these	items	increases	cost	estimates.

The	net	effect	of	implementing	this	standard	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,	assets	and liabilities	increased	by	approximately	$305	million	in	2003	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.

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

is	a	critical	accounting	estimate.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Pension	Cost | Impact	on	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $215 | $11,016 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $826 | - |
| Rate\tof\tincrease\tin | 0.25% | $287 | $2,756 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $540 | $2,763 |
| Discount\trate | (0.25%) | $321 | $3,191 |

Total	pension	cost	for	Entergy	Louisiana	in	2003	was	$3.6	million,	including	a	$5.4	million	charge	related	to	the	Voluntary	Severance	Program.	 Entergy Louisiana	is	projecting	2004	pension	cost	to	be	$2.3	million	due	to	a	decrease	in	the	discount	rate	from	6.75%	to	6.25%	and	the	phased-in	effect	of	poor	asset performance.	Entergy	 Louisiana	 was	 not	 required	 to	 make	 contributions	 to	 its	 pension	 plan	 in	 2003,	 however	 it	 anticipates	 making	 $8.6	 million	 in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	Entergy	Louisiana's	accumulated	benefit	obligation	at	December	31,	2002	exceeded	plan assets.	As	a	result,	Entergy	Louisiana	was	required	to	recognize	an	additional	minimum	liability	as	prescribed	by	SFAS	87.	At	December	31,	2003	Entergy Louisiana	reversed	its	additional	minimum	liability	of	$44.2	and	the	offsetting	intangible	asset	of	$5.4	million	and	regulatory	asset	of	$38.8	million	that	were recorded	at	December	31,	2002.	Net	income	for	2003	and	2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Louisiana	in	2003	were	$19.4	million,	including	a	$5.5	million	charge	related	to the	Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act

introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	Entergy Louisiana	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$13.1	million.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Louisiana,	Inc.	as	of	December	31,	2003	and	2002,	and	the	related	statements	of	income, retained	earnings,	and	cash	flows	(pages	211	through	216	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three	years	in	the	period	ended December	31,	2003.	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.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Louisiana,	Inc.	as	of	December	31,	2003	and 2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with	accounting principles	generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	1	and	Note	9	to	the	notes	to	respective	financial	statements,	Entergy	Louisiana,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	 Standards	 No. 143,	Accounting for Asset Retirement	 Obligations,	and	 Financial	 Accounting	 Standards	 Board	 Interpretation	 No. 46, Consolidation	of	Variable	Interest	Entities,	in	2003.

# 		Temporary	cash	investments	-	at	cost,

# 			STATEMENTS	OF	RETAINED	EARNINGS

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,165,570 | $1,815,352 | $1,901,913 | $2,062,437 | $1,806,594 |
| Net\tincome | $146,154 | $144,709 | $132,550 | $162,679 | $191,770 |
| Total\tassets | $4,674,539 | $4,753,704 | $4,149,701 | $4,289,409 | $4,084,650 |
| Long-term\tobligations\t(1) | $917,247 | $919,319 | $1,197,473 | $1,411,345 | $1,274,006 |

# ENTERGY	MISSISSIPPI,	INC.

Net	income	increased	$14.7	million	primarily	due	to	an	increase	in	net	revenue,	partially	offset	by	an	increase	in	depreciation	and	amortization	expenses, decreased	interest	income,	and	increased	other	operation	and	maintenance	expenses.

Net	income	increased	$12.8	million	primarily	due	to	an	increase	in	net	revenue	and	decreased	interest	charges,	partially	offset	by	a	decrease	in	interest income,	an	increase	in	depreciation	and	amortization	expenses,	and	an	increase	in	other	operation	and	maintenance	expenses.

| 2002	net	revenue | $380.2 |
| :--- | :--- |
| Base\trates | 48.3 |
| Other | (1.9) |
| 2003\tnet\trevenue | $426.6 |

The	increase	in	base	rates	was	effective	January	2003.	The	rate	increase	is	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy's financial	statements.

Gross	operating	revenue,	fuel	and	fuel-related	expenses,	and	other	regulatory	charges	(credits)

the	base	rate	increase	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	increases	in	market	prices	of natural	gas	and	purchased	power.

The	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	under-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	(credits)	have	no	material	effect	on	net	income	due	to	recovery	and/or	refund	of	such	expenses.	Other	regulatory	charges	increased primarily	due	to	an	over-recovery	of	deferred	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.

| 2001	net	revenue | $342.8 |
| :--- | :--- |
| Volume/weather | 10.1 |
| Forfeiture\tand\tservice\trevenue | 9.1 |
| Price | 3.1 |
| Other | 15.1 |
| 2002\tnet\trevenue | $380.2 |

The	volume/weather	variance	is	due	to	increased	electricity	usage	in	the	service	territory	and	the	effect	of	more	favorable	weather.	Billed	usage	increased	a total	of	208	GWh	in	all	sectors.

Forfeiture	and	service	revenue	increased	due	to	new	customer	fees	and	late	charges.

The	price	variance	increase	is	a	result	of	a	formula	rate	plan	revenue	increase	effective	May	2002.

Gross	operating	revenue,	fuel	and	purchased	power	expenses,	and	other	regulatory	credits

Gross	operating	revenues	decreased	primarily	due	to:

a	decrease	of	$64.5	million	in	fuel	recovery	revenues	primarily	due	to	lower	fuel	factors	resulting	from	decreases	in	the	market	prices	of	natural gas	and	purchased	power;	and

a	decrease	of	$47.3	million	in	gross	wholesale	revenue	as	a	result	of	decreased	generation	and	purchases	that	resulted	in	less	energy	available for	resale	sales.

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

a	decrease	in	generation;	and

a	decrease	in	the	average	market	price	of	purchased	power.

Other	regulatory	credits	decreased	primarily	due to the	settlement	of	 the	System	Energy	rate	proceeding in	2001	which	ceased the	deferral	of	costs associated	with	purchases	from	System	Energy.

Other	operation	and	maintenance	expenses	increased	due	to:

These	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	during	2002.

an	increase	of	$5.5	million	in	plant	maintenance	expenses	due	to	unscheduled	outage	costs	at	a	fossil	plant;	and

an	increase	of	$5.0	million	in	benefit	costs.

Depreciation	and	amortization	expenses	increased	due	to	increased	plant	in	service	combined	with	revisions	made	to	the	useful	lives	of	certain	intangible plant	assets	to	more	appropriately	reflect	their	actual	lives,	which	lowered	expense	in	2001	in	accordance	with	regulatory	treatment.

Interest	and	dividend	income	decreased	due	to	the	System	Energy	refund	in	2001	eliminating	the	need	to	accrue	interest	on	the	deferred	System	Energy	costs that	Entergy	Mississippi	was	not	recovering	currently	through	rates.

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

| Cash	and	cash	equivalents	at	beginning	of	period | $147,721 | $54,048 | $5,113 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 253,288 | 156,868 | 178,110 |
| Investing\tactivities | (264,495) | (135,122) | (175,822) |
| Financing\tactivities | (72,676) | 71,927 | 46,647 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (83,883) | 93,673 | 48,935 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $63,838 | $147,721 | $54,048 |

Cash	flow	from	operations	increased	by	$96.4	million	in	2003	primarily	due	to	a	$78	million	tax	refund	and	increased	net	income,	partially	offset	by	money pool	activity.	Money	pool	activity	decreased	operating	cash	flow	due	to	Entergy	Mississippi's	lending	position	in	the	money	pool.

Cash	flow	from	operations	decreased	by	$21.2	million	in	2002	due	to	the	net	effect	of	the	System	Energy	refund,	partially	offset	by	increased	net	income	and money	pool	activity.

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

| 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $22,076 | $8,702 | $11,505 | ($30,719) |

Money	pool	activity	used	$13.4	million	of	Entergy	Mississippi's	operating	cash	flows	in	2003,	provided	$2.8	million	of	its	operating	cash	flows	in	2002,	and used	$42.2	million	of	its	operating	cash	flows	in	2001.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description of	the	money	pool.

The	increase	of	$129.4	million	in	net	cash	flow	used	in	investing	activities	in	2003	was	primarily	due	to	cash	used	for	other	regulatory	investments	of	$72.6 million	as	a	result	of	under-recovered	fuel	and	purchased	power	costs.

In	May	2003,	Entergy	Mississippi	filed	and	the	MPSC	approved	a	change	in	Entergy	Mississippi's	energy	cost	recovery	rider.	Under	the	MPSC's	order, Entergy	Mississippi	has	deferred	until	2004	the	collection	of	fuel	under-recoveries	for	the	first	and	second	quarters	of	2003	that	would	have	been	collected in	the	third	and	fourth	quarters	of	2003.	The	deferred	amount	of	$77.6	million	plus	carrying	charges	will	be	collected	over	a	twelve-month	period	beginning January	2004.

The	increase	was	also	due	to	other	temporary	cash	investments	of	$18.6	million	that	provided	cash	in	2002	upon	maturity.

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

The	increase	of	$144.6	million	in	net	cash	flow	used	in	financing	activities	in	2003	was	primarily	due	to	a	decrease	in	net	issuances	of	long-term	debt.

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

Entergy	Mississippi	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Mississippi's	planned	construction	and	other	capital	investments,	and	existing	debt	obligations:

|  | 2004 | 2005-2006 | 2007-2008 | After	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| \t\tcapital\tinvestment\t(1) | $150 | $263 | N/A | N/A | $413 |
| Long-term\tdebt | $75 | - | $180 | $475 | $730 |
| Operating\tleases | $7 | $10 | $2 | $1 | $20 |
| Purchase\tobligations\t(2) | $203 | $390 | $389 | $2,587 | $3,569 |

(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) As	defined	by	SEC	rule.	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	9	to	the	domestic	utility	companies	and	System	Energy financial	statements.

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

As	a	wholly-owned	subsidiary,	Entergy	Mississippi	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.	Entergy	Mississippi is	restricted	by	its	long-term	debt	indentures	in	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred	stock.	As	of	December	31, 2003,	Entergy	Mississippi	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$41.9	million.

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

Entergy	Mississippi	issued	$295	million	of	First	Mortgage	Bonds	in	2003	as	follows:

Proceeds	from	the	$100	million	issuance	in	March	2003	were	used	for	general	corporate	purposes,	including	the	retirement	of	short-term	indebtedness	and working	capital	needs.	Higher	fuel	costs	in	the	first	quarter	of	2003	contributed	to	the	working	capital	needs.	A	portion	of	the	proceeds	from	the	other issuances,	together	with	proceeds	from	the	issuances	of	First	Mortgage	Bonds	in	October	and	November	2002	were	used	to	redeem	the	following:

Entergy	Mississippi	also	has	$75	million	of	currently	maturing	long-term	debt	due	May	2004,	a	portion	of	which	Entergy	Mississippi	expects	to	repay	at maturity	using	a	portion	of	the	proceeds	from	the	May	2003	issuance.	Entergy	Mississippi	is	expected	to	continue	refinancing	or	redeeming	higher-cost	debt and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Mississippi	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also subject	to	issuance	tests	set	forth	in	corporate	charters,	bond	indentures,	and	other	agreements.	Entergy	Mississippi	has	sufficient	capacity	under	these	tests	to meet	its	foreseeable	capital	needs.

Short-term	borrowings	by	Entergy	Mississippi,	including	borrowings	under	the	money	pool,	are	limited	to	an	amount	authorized	by	the	SEC,	of	$160 million.	Under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	Entergy	Mississippi	cannot	incur	new	short-term	indebtedness	if	the	issuer's common	equity	would	comprise	less	than	30%	of	its	capital.	Entergy	Mississippi	has	a	364-day	credit	facility	available	expiring	May	2004	in	the	amount	of $25	million	of	which	none	was	drawn	at	December	31,	2003.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for further	discussion	of	Entergy	Mississippi's	short-term	borrowing	limits.

Major	 changes	 are	 occurring	 in	 the	 wholesale	 and	 retail	 electric	 utility	 business,	 including	 in	 the	 electric	 transmission	 business.	The	 MPSC	 has recommended	not	pursuing	open	access	at	this	time.	At	FERC,	the	pace	of	restructuring	at	the	wholesale	level	has	begun	but	has	been	delayed.	It	is	too	early to	predict	the	ultimate	effects	of	changes	in	U.S.	energy	markets.	Restructuring	issues	are	complex	and	are	continually	affected	by	events	at	the	national, regional,	state,	and	local	levels.	However,	these	changes	may	result,	in	the	long-term,	in	fundamental	changes	in	the	way	traditional	integrated	utilities	and holding	company	systems,	like	the	Entergy	system,	conduct	their	business.	Some	of	these	changes	may	be	positive	for	Entergy,	while	others	may	not	be.

# State	and	Local	Rate	Regulation

The	rates	that	Entergy	Mississippi	charges	for	its	services	are	an	important	item	influencing	its	financial	position,	results	of	operations,	and	liquidity. Entergy	Mississippi	is	closely	regulated	and	the	rates	charged	to	its	customers	are	determined	in	regulatory	proceedings.	A	governmental	agency,	the	MPSC, is	primarily	responsible	for	approval	of	the	rates	charged	to	customers.	Entergy	Mississippi	did	not	have	any	new	rate	proceedings	in	2003.

As	approved	by	the	MPSC,	Entergy	Mississippi	implemented	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.

In	its	complaint,	the	LPSC	alleges	that	Entergy	Mississippi's	annual	production	costs	over	the	period	2002	to	2007	will	be	$27	million	under	to	$13	million over	the	average	for	the	domestic	utility	companies.	This	range	of	results	is	a	function	of	assumptions	regarding	such	things	as	future	natural	gas	prices,	the future	 market	 price	 of	 electricity,	 and	 other	 factors.	If	FERC	grants	 the	relief	requested	by	 the	LPSC,	 the	relief	may	result	 in	a	material	 increase	 in production	costs	allocated	to	companies	whose	costs	currently	are	projected	to	be	less	than	the	average	and	a	material	decrease	in	production	costs	allocated to	companies	whose	costs	currently	are	projected	 to	exceed	 the	average.	Management	believes	that	any	changes	in	the	allocation	of	production	costs resulting	from	a	FERC	decision	should	result	in	similar	rate	changes	for	retail	customers.	Therefore,	management	does	not	believe	that	this	proceeding	will have	a	material	effect	on	the	financial	condition	of	Entergy	Mississippi,	although	neither	the	timing	nor	the	outcome	of	the	proceedings	at	FERC	can	be predicted	at	this	time.	In	February	2002,	the	FERC	set	the	matter	for	hearing	and	established	a	refund	effective	period	consisting	of	the	15	months	following September	13,	2001.	A	subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

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.

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

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

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Pension	Cost | Impact	on	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $252 | $5,727 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $441 | - |
| Rate\tof\tincrease\tin | 0.25% | $190 | $1,410 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $276 | $1,422 |
| Discount\trate | (0.25%) | $150 | $1,626 |

Total	pension	cost	for	Entergy	Mississippi	in	2003	was	$1.9	million,	including	a	$1.9	million	charge	related	to	the	Voluntary	Severance	Program.	 Entergy Mississippi	is	projecting	2004	pension	cost	to	$2.3	million	due	to	a	decrease	in	the	discount	rate	from	6.75%	to	6.25%	and	the	phased-in	effect	of	poor	asset performance.	Entergy	 Mississippi	 was	 not	 required	 to	 make	 contributions	 to	 its	 pension	 plan	 in	 2003,	 however,	 it	 anticipates	 making	 $3	 million	 in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	Entergy	Mississippi's	accumulated	benefit	obligation	at	December	31,	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,	 2003	 Entergy	 Mississippi	 reduced	 its	 additional	 minimum	 liability	 to	 $7.3	 million	 from	 $13	 million	 at	 December	 31,	 2002.	Entergy	 Mississippi decreased	its	intangible	asset	for	the	unrecognized	prior	service	cost	to	$0.9	million	at	December	31,	2003	from	$3.2	million	at	December	31,	2002.	Entergy Mississippi	also	decreased	the	regulatory	asset	to	$6.4	million	at	December	31,	2003	from	$9.8	million	at	December	31,	2002.	Net	income	for	2003	and 2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Mississippi	in	2003	were	$7	million,	including	a	$1.3	million	charge	related	to the	Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	Entergy Mississippi	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$5.2	million.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Mississippi,	Inc.	as	of	December	31,	2003	and	2002,	and	the	related	statements	of	income, retained	earnings,	and	cash	flows	(pages	230	through	234	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three	years	in	the	period	ended December	31,	2003.	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.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Mississippi,	Inc.	as	of	December	31,	2003 and	2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

SUPPLEMENTAL	DISCLOSURE	OF	CASH	FLOW	INFORMATION:

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,035,360 | $991,095 | $1,093,741 | $937,371 | $832,819 |
| Net\tincome | $67,058 | $52,408 | $39,620 | $38,973 | $41,588 |
| Total\tassets | $1,949,299 | $1,832,372 | $1,683,026 | $1,683,939 | $1,460,017 |
| Long-term\tobligations\t(1) | $655,051 | $510,240 | $589,937 | $584,678 | $464,756 |

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

# ENTERGY	NEW	ORLEANS,	INC.

# Net	Income	(Loss)

Entergy	New	Orleans	had	net	income	of	$7.9	million	in	2003	compared	to	a	net	loss	in	2002.	The	increase	is	due	to	an	increase	in	net	revenue	and	a	decrease in	interest	expense,	partially	offset	by	increases	in	other	operation	and	maintenance	expenses	and	depreciation	and	amortization	expenses.

Entergy	New	Orleans	experienced	a	smaller	net	loss	in	2002	compared	to	2001.	The	decreased	net	loss	is	primarily	due	to	an	increase	in	net	revenue	and	a decrease	 in	 taxes	other	 than	 income	 taxes,	partially	offset	by	 increases	 in	other	operation	and	maintenance	expenses,	 interest	and	other	charges,	and depreciation	and	amortization	expenses.

Net	revenue,	which	is	Entergy's	measure	of	gross	margin,	consists	of	operating	revenues	net	of:	1)	fuel,	fuel-related,	and	purchased	power	expenses,	2)	other regulatory	credits,	and	3)	amortization	of	rate	deferrals.	Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2003	to	2002.

| 2002	net	revenue | $183.7 |
| :--- | :--- |
| Base\trates | 15.9 |
| Rate\trefund\tprovisions | 9.1 |
| Other | (0.4) |
| 2003\tnet\trevenue | $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.

an	increase	of	$78.4	million	in	gross	wholesale	revenue	primarily	due	to	increased	sales	to	affiliated	systems;

an	increase	of	$43.0	million	in	gross	natural	gas	revenue	primarily	due	to	an	increase	in	the	market	price	of	natural	gas	and	an	increase	in	base rate	revenue;	and

an	increase	of	$19.8	million	in	gross	retail	electric	revenue	primarily	due	to	an	increase	in	base	rate	revenue	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.

| 2001	net	revenue | $170.9 |
| :--- | :--- |
| Volume/weather | 6.9 |
| Fuel\tprice | 11.0 |
| Rate\trefund\tprovisions | (7.3) |
| Other | 2.2 |
| 2002\tnet\trevenue | $183.7 |

The	volume/weather	variance	is	due	to	increased	electricity	usage	in	the	service	territory.	Billed	usage	increased	a	total	of	258	GWh	in	the	residential, commercial,	and	governmental	sectors	after	adjusting	for	the	effects	of	weather.

The	fuel	price	variance	is	due	to	an	increase	in	the	price	applied	to	unbilled	sales.

Rate	refund	provisions	decreased	net	revenue	due	to	an	increase	in	accruals	for	potential	rate	actions	and	refunds.

Gross	operating	revenues	decreased	primarily	due	to	decreased	electric	fuel	cost	recovery	revenues	of	$81.4	million	and	decreased	gas	revenues	of	$44.8 million,	both	due	to	a	decrease	in	the	market	price	of	natural	gas.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	decreases	in	the	market	price	of	natural	gas	and	purchased	power.

Other	regulatory	credits	decreased	primarily	due	to	the	following	decreases:

$5.5	million	as	a	result	of	the	completion	of	the	Grand	Gulf	1	Rate	Deferral	Plan	in	2001;

$3.7	million	as	a	result	of	an	over-recovery	of	Grand	Gulf	1-related	costs	in	2002	compared	to	an	under-recovery	in	2001;	and

$3.3	million	as	a	result	of	the	deferral	in	2001	of	capacity	charges	included	in	purchased	power	costs	for	summer	capacity	that	Entergy	New Orleans	expected	to	recover	in	the	future.

Other	operation	and	maintenance	expenses	increased	primarily	due	to	the	following:

voluntary	severance	program	accruals	of	$4.7	million;

an	increase	of	$2.2	million	in	billing,	customer	inquiry,	and	collection	costs;	and

an	increase	of	$2.0	million	in	maintenance	outage	costs	at	a	fossil	plant.

Depreciation	and	amortization	expenses	increased	due	to	an	increase	in	plant	in	service.

Miscellaneous	-	net	decreased	primarily	due	to	a	gain	on	the	sale	of	a	parcel	of	property	at	a	non-operating	plant	site	in	2002.

Interest	and	other	charges	decreased	primarily	due	to	interest	accrued	in	2002	for	potential	rate	actions	and	refunds	and	a	true-up	of	those	accruals	in	May 2003.

an	increase	of	$2.4	million	in	rate	proceedings	costs;	and

an	increase	of	$2.1	million	in	fossil	plant	expenses	due	to	increased	asbestos	litigation	reserves	in	2002	and	the	write-off	of	obsolete	materials.

Taxes	other	than	income	taxes	decreased	primarily	due	to	a	decrease	in	local	franchise	taxes	of	$5.9	million	due	to	lower	retail	revenue.

Miscellaneous	-	net	increased	primarily	due	to	a	gain	on	the	sale	of	a	parcel	of	property	at	a	non-operating	plant	site	in	2002.

Interest	charges	increased	$3.2	million	primarily	due	to	interest	recorded	for	potential	rate	actions	and	refunds.

| Operating	activities | 7,194 | 72,143 | 77,706 |
| :--- | :--- | :--- | :--- |
| Investing\tactivities | (64,806) | (41,647) | (74,061) |
| Financing\tactivities | (3,966) | (2,433) | 28,237 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (61,578) | 28,063 | 31,882 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $4,669 | $66,247 | $38,184 |

Cash	flow	from	operations	decreased	by	$64.9	million	in	2003	compared	to	2002	primarily	due	to	decreased	fuel	cost	recoveries	and	the	timing	of	collection of	receivables	due	to	an	increase	in	retail	customer	receivables	days	outstanding.

Cash	flow	from	operations	decreased	by	$5.6	million	in	2002	compared	to	2001	primarily	due	to	the	payment	of	the	System	Energy	refund	to	customers	in the	first	quarter	of	2002	partially	offset	by	an	increase	in	payables	in	2002	compared	to	2001	due	to	the	timing	of	fuel	payments.

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

| 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $1,783 | $3,500 | $9,208 | ($5,734) |

Money	pool	activity	provided	$1.7	million	of	Entergy	New	Orleans'	operating	cash	flow	in	2003,	provided	$5.7	million	in	2002,	and	used	$14.9	million	in 2001.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

The	increase	of	$23.2	million	in	net	cash	used	in	investing	activities	in	2003	was	primarily	due	to	the	maturity	of	$14.9	million	of	other	temporary investments	in	2002	and	increased	construction	expenditures	due	to	customer	service	spending.

The	decrease	of	$32.4	million	in	net	cash	used	in	investing	activities	in	2002	was	primarily	due	to	other	temporary	investments	made	in	2001	that	provided cash	when	they	matured	in	2002.

The	increase	of	$1.5	million	in	net	cash	used	in	financing	activities	in	2003	was	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.

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

Entergy	New	Orleans	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	New	Orleans'	planned	construction	and	other	capital	investments	and	existing	debt	obligations:

| capital	investment	(1) | $48 | $86 | N/A | N/A | $134 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Long-term\tdebt | - | $30 | $30 | $169 | $229 |
| Purchase\tobligations\t(2) | $149 | $257 | $222 | $1,312 | $1,940 |

(2) As	defined	by	SEC	rule.	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	9	to	the	domestic	utility	companies	and	System	Energy financial	statements.

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	construction	expenditures	and	long-term	debt	and preferred	stock	maturities	in	Notes	5,	7,	and	9	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

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

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

cash	on	hand;	and

debt	issuances.

The	net	proceeds	of	Entergy	New	Orleans'	debt	issuance	in	2002	were	used	to	redeem,	prior	to	maturity,	$25	million	of	7%	Series	First	Mortgage	Bonds	due March	1,	2003.	In	2003,	Entergy	New	Orleans	refinanced	$100	million	of	long-term	debt.	Entergy	New	Orleans	is	expected	to	continue	refinancing	or redeeming	higher-cost	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	New	Orleans	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also subject	to	issuance	tests	set	forth	in	corporate	charters,	bond	indentures,	and	other	agreements.	Entergy	New	Orleans	has	sufficient	capacity	under	these	tests to	meet	its	foreseeable	capital	needs.

As	shown	in	the	Earnings	Ratios	presented	in	Item	1	of	this	Form	10-K,	Entergy	New	Orleans'	earnings	for	the	twelve	months	ended	December	31,	2002 and	2001	were	not	adequate	to	cover	its	fixed	charges	and	preferred	dividends.	Under	its	mortgage	covenants,	Entergy	New	Orleans	did	not	currently	have the	capacity	to	issue	new	incremental	mortgage-backed	debt.	Entergy	New	Orleans'	financial	results	improved	in	2003,	after	the	City	Council's	approval	of the	settlement	of	its	rate	filing,	and	it	now	has	limited	capacity	to	issue	new	incremental	mortgage-backed	debt.	In	an	October	2002	report,	Moody's Investors	Service	states	that	its	rating	outlook	for	Entergy	New	Orleans	is	negative	due	to	the	declining	credit	measures	and	the	uncertainty	of	Entergy	New Orleans'	pending	rate	case.	The	rate	case	has	now	been	settled,	but	Moody's	has	retained	the	negative	outlook	at	this	time.	Moody's	currently	rates	Entergy New	Orleans	senior	secured	debt	at	Baa2.

Short-term	borrowings	by	Entergy	New	Orleans,	including	borrowings	under	the	money	pool,	are	limited	to	an	amount	authorized	by	the	SEC,	$100	million. Under	restrictions	contained	in	its	articles	of	incorporation,	Entergy	New	Orleans	could	incur	approximately	$38	million	of	new	unsecured	debt	as	of December	31,	2003.	Under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	Entergy	New	Orleans	cannot	incur	new	short-term	indebtedness	if	its common	equity	would	comprise	less	than	30%	of	its	capital.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for further	discussion	of	Entergy	New	Orleans'	short-term	borrowing	limits.

In	its	complaint,	the	LPSC	alleges	that	Entergy	New	Orleans'	annual	production	costs	over	the	period	2002	to	2007	will	be	$7	million	to	$46	million	over	the average	for	the	domestic	utility	companies.	This	range	of	results	is	a	function	of	assumptions	regarding	such	things	as	future	natural	gas	prices,	the	future market	price	of	electricity,	and	other	factors.	If	FERC	grants	the	relief	requested	by	the	LPSC,	the	relief	may	result	in	a	material	increase	in	production	costs allocated	to	companies	whose	costs	currently	are	projected	to	be	less	than	the	average	and	a	material	decrease	in	production	costs	allocated	to	companies whose	costs	currently	are	projected	to	exceed	the	average.	Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	a FERC	decision	should	result	in	similar	rate	changes	for	retail	customers.	Therefore,	management	does	not	believe	that	this	proceeding	will	have	a	material effect	on	the	financial	condition	of	Entergy	New	Orleans,	although	neither	the	timing	nor	the	outcome	of	the	proceedings	at	FERC	can	be	predicted	at	this time.	In	February	2002,	the	FERC	set	the	matter	for	hearing	and	established	a	refund	effective	period	consisting	of	the	15	months	following	September	13, 2001.	A	subsequent	extension	of	the	procedural	schedule	extended	the	refund	effective	period	by	120	days.

In	January	2003	the	domestic	utility	companies	filed	testimony	in	the	case,	showing	that	over	the	life	of	the	System	Agreement	the	relative	total	production costs	of	the	domestic	utility	companies	are	roughly	equal,	and	suggesting	that	no	changes	to	the	System	Agreement	such	as	those	sought	by	the	LPSC	are appropriate.	In	April	2003,	witnesses	on	behalf	of	the	FERC	staff	filed	testimony	in	the	proceeding	suggesting	that	full	production	cost	equalization	should not	be	adopted	by	the	FERC	in	this	case,	and	that	when	measured	over	a	suitably	long	period,	the	total	production	costs	of	the	domestic	utility	companies were	roughly	equal	and	were	likely	to	remain	so,	given	the	Entergy	System's	proposed	resource	plan.	Hearings	in	the	proceeding	ended	in	late-August	2003.

The	 Initial	 Decision	 of	 the	 FERC	ALJ	 was	 released	 on	 February	 6,	 2004.	The	ALJ	 concludes	 that	 full	 production	 cost	 equalization	 should	 not	 be implemented;	that	the	Entergy	System	currently	is	not	in	rough	production	cost	equalization	and	is	not	likely	to	be	in	rough	production	cost	equalization	for the	foreseeable	future;	and	that	the	appropriate	remedy	to	achieve	rough	equalization	is	to	have	the	low	cost	companies	compensate	the	high	cost	companies whenever	one	or	more	companies'	annual	total	production	costs	from	2003	forward	differ	by	more	than	+/-	7.5%	from	the	Entergy	System	average	annual total	production	costs,	or	whenever	the	three	year	average	of	one	or	more	companies'	total	production	costs	(commencing	with	the	three	years	2004	through 2006,	and	yearly	 thereafter)	differ	by	more	 than	+/-	5%	from	 the	Entergy	System	average	 total	production	costs	during	any	 three	year	cycle.	In	 the calculation	of	what	each	company's	total	production	costs	are,	the	ALJ	determined	that	the	full	cost	of	Vidalia	project	power	purchases	by	Entergy	Louisiana should	be	included,	but	the	ALJ	rejected	other	adjustments	proposed	by	the	LPSC.	Also,	the	ALJ	determined	that	the	average	of	the	four	highest	monthly demand	peaks	for	the	year	(4	CP)	should	be	used	for	calculating	reserve	sharing	costs,	rather	than	the	current	12	CP	method.	Finally,	the	ALJ	determined that	there	is	no	valid	issue	concerning	"billing	versus	dispatch"	in	the	rate	schedule	by	which	exchange	energy	is	priced,	MSS-3,	that	MSS-3	has	not	been misapplied	or	misinterpreted	by	Entergy,	and	that	MSS-3	should	not	be	changed.		The	ALJ's	Initial	Decision	did	not	specifically	address	refund	exposure.

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.

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

In	March	2003,	Entergy	New	Orleans	and	the	Advisors	to	the	City	Council	presented	to	the	City	Council	an	agreement	in	principle	and	the	City	Council approved	 that	 agreement	 in	 May	 2003	 allowing	 for	 a	 $30.2	 million	 increase	 in	 base	 rates	 effective	 June	 1,	 2003.	The	 City	 Council	 also	 approved implementation	of	formula	rate	plans	for	electric	and	gas	service	that	will	be	evaluated	annually	until	2005.	The	midpoint	return	on	equity	of	both	plans	is 11.25%,	with	a	target	equity	component	of	42%.	The	electric	plan	provides	for	a	bandwidth	of	10.25%	to	12.25%	and	the	gas	plan	provides	for	a	bandwidth of	11%	to	11.5%,	with	earnings	within	those	ranges	not	resulting	in	a	change	in	rates.	In	addition,	the	City	Council	approved	implementation	of	a	generation performance-based	rate	calculation	in	the	fuel	adjustment	clause	under	which	Entergy	New	Orleans	will	receive	10%	of	calculated	fuel	and	purchased	power cost	savings	in	excess	of	$20	million,	subject	to	a	13.25%	return	on	equity	limitation	for	electric	operations	as	provided	for	in	the	electric	formula	rate	plan. Entergy	New	Orleans	will	bear	10%	of	any	"negative"	fuel	and	purchased	power	cost	savings.	Certain	intervenors	in	the	proceeding	have	appealed	the	City Council's	approval	to	the	Civil	District	Court	for	the	Parish	of	Orleans.	Entergy	New	Orleans	and	the	City	Council	will	oppose	the	appeal,	but	the	outcome cannot	be	predicted.

In	approving	the	agreement	in	principle,	the	City	Council	indicated	that	if	it	decides	in	favor	of	the	plaintiffs	in	either	of	the	lawsuits	described	in	Part	I,	Item 1	of	the	Form	10-K	in	the	paragraphs	entitled	"Entergy	New	Orleans	Fuel	Clause	Lawsuit"	and	"Entergy	New	Orleans	Rate	of	Return	Lawsuit,	"	the	effect of	that	decision	on	the	rate	agreement	would	have	to	be	determined.	The	City	Council	also	indicated	that	the	Entergy	New	Orleans	purchased	power agreements	described	in	Part	I,	Item	1,	"Generating	Stations"	in	this	report	are	fundamental	to	the	rate	agreement,	and	a	FERC	decision	or	order	requiring	a material	change	in	the	purchased	power	agreements	may	result	in	a	City	Council	investigation	to	determine	what	prospective	action,	if	any,	would	be warranted	by	any	such	FERC	decision	or	order	to	preserve	the	benefits	that	were	otherwise	projected	to	accrue	to	customers	under	the	rate	settlement.

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.

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.

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.

The	preparation	of	Entergy	New	Orleans'	financial	statements	in	conformity	with	generally	accepted	accounting	principles	requires	management	to	make estimates	and	judgments	that	can	have	a	significant	effect	on	reported	financial	position,	results	of	operations,	and	cash	flows.	Management	has	identified	the

following	estimates	as	critical	accounting	estimates	because	they	are	based	on	assumptions	and	measurements	that	involve	an	unusual	degree	of	uncertainty, and	there	is	the	potential	that	different	assumptions	and	measurements	could	produce	estimates	that	are	significantly	different	than	those	recorded	in	Entergy New	Orleans'	financial	statements.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Pension	Cost | Impact	on	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $64 | $2,427 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $75 | - |
| Rate\tof\tincrease\tin | 0.25% | $69 | $709 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $205 | $1,124 |
| Discount\trate | (0.25%) | $82 | $1,340 |

Total	pension	cost	for	Entergy	New	Orleans	in	2003	was	$3.6	million,	including	a	$0.5	million	charge	related	to	the	Voluntary	Severance	Program.	 Entergy

New	Orleans	is	projecting	2004	pension	cost	to	be	$2.6	million	due	to	a	decrease	in	the	discount	rate	from	6.75%	to	6.25%	and	the	phased-in	effect	of	poor asset	performance.	Entergy	New	Orleans	was	not	required	to	make	contributions	to	its	pension	plan	in	2003,	however	it	anticipates	making	$4.7	million	in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	Entergy	New	Orleans'	accumulated	benefit	obligation	at	December	31,	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,	2003	Entergy	New	Orleans	increased	its	additional	minimum	liability	to	$13.1	million	from	$4.8	million	at	December	31,	2002.	Entergy	New	Orleans increased	its	intangible	asset	for	the	unrecognized	prior	service	cost	to	$2.8	million	at	December	31,	2003	from	$1.8	million	at	December	31,	2002.	Entergy New	Orleans	also	increased	the	regulatory	asset	to	$10.3	million	at	December	31,	2003	from	$3	million	at	December	31,	2002.	Net	income	for	2003	and 2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	New	Orleans	in	2003	were	$6.4	million,	including	a	$1	million	charge	related	to the	Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	Entergy New	Orleans	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$4.6	million.

We	have	audited	 the	accompanying	balance	sheets	of	Entergy	New	Orleans,	Inc.	as	of	December	31,	2003	and	2002,	and	 the	related	statements	of operations,	retained	earnings,	and	cash	flows	(pages	248	through	252	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three	years	in	the	period ended	December	31,	2003.	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.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	New	Orleans,	Inc.	as	of	December	31,	2003 and	2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $654,016 | $507,874 | $630,850 | $640,290 | $507,788 |
| Net\tincome\t(loss) | $7,859 | ($230) | ($2,195) | $16,518 | $18,961 |
| Total\tassets | $619,819 | $584,705 | $566,037 | $559,231 | $485,746 |
| Long-term\tobligations\t(1) | $229,217 | $229,191 | $299,097 | $199,031 | $169,083 |

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

# SYSTEM	ENERGY	RESOURCES,	INC.

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

Net	income	increased	by	$2.7	million	in	2003	primarily	due	to	decreased	interest	charges	primarily	resulting	from	decreased	interest	expense	associated	with the	Grand	Gulf	1	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	1.

Net	income	decreased	by	$13.0	million	in	2002	primarily	due	to:

the	effect	of	the	final	resolution	of	System	Energy's	1995	rate	proceeding	increasing	net	income	in	2001,	as	discussed	below;

a	decrease	of	$13.1	million	in	interest	earned	on	System	Energy's	investments	in	the	money	pool	due	to	lower	advances	to	the	money	pool	in 2002	compared	to	2001.	The	money	pool	is	discussed	in	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements;	and

increased	interest	on	long-term	debt	of	$5.1	million	primarily	due	to	an	increase	in	interest	expense	of	$13.8	million	associated	with	the	sale- leaseback	of	Grand	Gulf	1,	partially	offset	by	a	decrease	in	interest	expense	of	$8.0	million	due	to	the	retirement	of	$135	million	of	first mortgage	bonds	in	August	2001.

As	a	result	of	the	issuance	of	the	final	resolution	related	to	System	Energy's	1995	rate	proceeding,	decommissioning	expenses,	depreciation	expenses,	and income	tax	expenses	decreased.	Also,	interest	income	increased	due	to	interest	recognized	on	decommissioning	trust	funds.	Partially	offsetting	the	increase in	net	income	was	a	decrease	in	operating	revenues	as	a	result	of	an	increase	in	the	provision	for	rate	refund	and	an	increase	in	interest	charges	due	to	interest recorded	on	System	Energy's	reserve	for	rate	refund.

| Cash	and	cash	equivalents	at	beginning	of	period | $113,159 | $49,579 | $202,218 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 100,817 | 225,639 | 165,895 |
| Investing\tactivities | (45,065) | (28,873) | (47,634) |
| Financing\tactivities | (116,375) | (133,186) | (270,900) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\nequivalents | (60,623) | 63,580 | (152,639) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $52,536 | $113,159 | $49,579 |

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.

Cash	flow	from	operations	increased	by	$59.7	million	in	2002	primarily	due	to	the	effects	in	2001	of	the	final	resolution	of	the	System	Energy	rate proceeding.

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

Money	pool	activity	used	$12.0	million	of	System	Energy's	operating	cash	flows	in	2003,	provided	$6.8	million	in	2002,	and	provided	$141.4	million	in 2001.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

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.

The	decrease	of	$18.8	million	in	net	cash	used	in	investing	activities	in	2002	was	primarily	due	to	the	maturity	of	$22.4	million	of	other	temporary investments	that	had	been	made	in	2001.

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	1	sale-leaseback	compared	to	the	January	2002	principal	payment.

The	decrease	of	$137.7	million	in	net	cash	used	in	financing	activities	in	2002	was	primarily	due	to	the	retirement	of	$135.0	million	of	first	mortgage	bonds in	2001.	There	was	no	net	reduction	of	first	mortgage	bonds	in	2002.

System	Energy	requires	capital	resources	for:

debt	maturities;

working	capital	purposes,	including	the	financing	of	fuel	costs;	and

Following	are	the	amounts	of	System	Energy's	planned	construction	and	other	capital	investments,	existing	debt	and	lease	obligations,	and	other	purchase obligations:

|  | 2004 | 2005-2006 | 2007-2008 | After	2008 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| \t\tcapital\tinvestment\t(1) | $17 | $37 | N/A | N/A | $54 |
| Long-term\tdebt | $6 | $53 | $129 | $701 | $889 |
| Nuclear\tfuel\tlease\tobligations\t(2) | $31 | $16 | N/A | N/A | $47 |

(1) Includes	$13	million	each	year	for	maintenance	capital,	which	is	planned	spending	on	routine capital	projects	that	are	necessary	to	support	reliability	of	service,	equipment	or	systems.

(2) It	is	expected	that	additional	financing	under	the	leases	will	be	arranged	as	needed	to	acquire additional	fuel,	to	pay	interest,	and	to	pay	maturing	debt.	If	such	additional	financing	cannot	be arranged,	however,	the	lessee	in	each	case	must	repurchase	sufficient	nuclear	fuel	to	allow	the

lessor	to	meet	its	obligations.

The	planned	capital	 investment	estimate	for	System	Energy	reflects	capital	required	 to	support	 the	existing	business	of	System	Energy.	Management provides	more	information	on	construction	expenditures	and	long-term	debt	and	preferred	stock	maturities	in	Notes	5,	7,	and	9	to	the	domestic	utility companies	and	System	Energy	financial	statements.

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

System	Energy's	sources	to	meet	its	capital	requirements	include:

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	1.	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	that	expire	in	May	2007.

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

# Market	Risks

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

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

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.

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.

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

Regulations	require	that	Grand	Gulf	1	be	decommissioned	after	the	facility	is	taken	out	of	service,	and	funds	are	collected	and	deposited	in	trust	funds	during the	facility's	operating	life	in	order	to	provide	for	this	obligation.	System	Energy	conducts	periodic	decommissioning	cost	studies	(typically	updated	every three	to	five	years)	to	estimate	the	costs	that	will	be	incurred	to	decommission	the	facility.	See	Note	9	to	the	domestic	utility	companies	and	System	Energy financial	statements	for	details	regarding	System	Energy's	most	recent	study	and	the	obligations	recorded	by	System	Energy	related	to	decommissioning. The	following	key	assumptions	have	a	significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	System	Energy's	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over present	cost	levels	by	an	annual	factor	averaging	approximately	5.5%.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost of	decommissioning	a	facility	by	as	much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin immediately	upon	plant	retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable regulations.	System	Energy's	decommissioning	studies	for	Grand	Gulf	1	assume	immediate	decommissioning	upon	expiration	of	the	original plant	license.	While	the	impact	of	these	assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a "safestore"	status	can	significantly	decrease	the	present	value	of	these	obligations.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	Department	of	Energy	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear fuel,	and	recent	legislation	has	been	passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	However,	until	this	site	is available,	nuclear	plant	operators	must	provide	for	interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs	of	developing	and	maintaining	these	facilities	can	have	a	significant	impact (as	much	as	16%	of	estimated	decommissioning	costs).	System	Energy's	decommissioning	studies	include	cost	estimates	for	spent	fuel	storage. However,	these	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening	of	the	Yucca	Mountain	facility,	the	schedule	for shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

System	Energy	collects	the	projected	costs	of	decommissioning	Grand	Gulf	1	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.

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.

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	approximately	$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.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2003<br>Postretirement	Benefit	Cost | Impact	on	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $172 | $788 |
| Discount\trate | (0.25%) | $127 | $889 |

Total	pension	cost	for	System	Energy	in	2003	was	$5.8	million,	including	a	$2.7	million	charge	related	to	the	Voluntary	Severance	Program.	 System	Energy is	 projecting	 2004	 pension	 cost	 to	 $4.4	 million	 due	 to	 a	 decrease	 in	 the	 discount	 rate	 from	 6.75%	 to	 6.25%	 and	 the	 phased-in	 effect	 of	 poor	 asset performance.	System	Energy	was	not	required	to	make	contributions	to	its	pension	plan	in	2003,	however,	System	Energy	anticipates	making	$5.4	million	in contributions	in	2004.

Due	to	negative	pension	plan	asset	returns	from	2000	to	2002,	System	Energy's	accumulated	benefit	obligation	at	December	31,	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,	2003	System Energy	increased	its	additional	minimum	liability	to	$7.4	million	from	$0.4	million	at	December	31,	2002.	System	Energy	did	not	adjust	its	intangible	asset for	the	unrecognized	prior	service	cost	of	$0.4	million.	System	Energy	recorded	a	regulatory	asset	of	$7	million	at	December	31,	2003.	Net	income	for	2003 and	2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	System	Energy	in	2003	were	$5	million,	including	a	$2.8	million	charge	related	to	the Voluntary	Severance	Program.	In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.	The	Act introduces	a	prescription	drug	benefit	under	Medicare	(Part	D)	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that is	at	least	actuarially	equivalent	to	Medicare	Part	D.	Currently,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	is	pending.	System Energy	expects	2004	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$2	million.

To	the	Board	of	Directors	and	Shareholder	of

We	have	audited	the	accompanying	balance	sheets	of	System	Energy	Resources,	Inc.	as	of	December	31,	2003	and	2002,	and	the	related	statements	of income,	retained	earnings,	and	cash	flows	(pages	263	through	268	and	applicable	items	in	pages	270	through	331)	for	each	of	the	three	years	in	the	period ended	December	31,	2003.	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.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	System	Energy	Resources,	Inc.	as	of	December	31, 2003	and	2002,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2003	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	1	and	Note	9	to	the	notes	to	respective	financial	statements,	System	Energy	Resources,	Inc.	adopted	the	provisions	of	Statement	of Financial	Accounting	Standards	No.	143,	Accounting	for	Asset	Retirement	Obligations,	and	Financial	Accounting	Standards	Board	Interpretation	No.	46,

Consolidation	of	Variable	Interest	Entities,	in	2003.

# 			Fuel,	fuel-related	expenses,	and

|  | 2003 | 2002 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $583,820 | $602,486 | $535,027 | $656,749 | $620,032 |
| Net\tincome | $106,003 | $103,352 | $116,355 | $93,745 | $82,372 |
| Total\tassets | $2,880,724 | $2,915,898 | $2,964,041 | $3,274,550 | $3,369,048 |
| Long-term\tobligations\t(1) | $898,377 | $942,701 | $865,439 | $947,991 | $1,122,178 |
| Electric\tenergy\tsales\t(GWh) | 9,812 | 9,053 | 8,921 | 9,621 | 7,567 |

(1) Includes	long-term	debt	(excluding	currently	maturing),	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,	Entergy	New	Orleans, and	System	Energy	are	included	in	this	document	and	result	from	these	companies	having	registered	securities	with	the	SEC.	These	companies	maintain accounts	 in	accordance	with	FERC	and	other	regulatory	guidelines.	Certain	previously	reported	amounts	have	been	reclassified	to	conform	to	current classifications,	with	no	effect	on	net	income	or	shareholders'	equity.

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.

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.

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.

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

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:

|  | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy	(1) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 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% |
| 2001 | 3.1% | 2.5% | 2.9% | 2.4% | 3.0% | 2.8% |

(1) Per	a	FERC	order	in	2001,	the	depreciation	rate	for	System	Energy	was	changed	from	3.3%	to 2.8%,	retroactive	to	December	1995.	The	retroactive	effect	of	the	change	is	reflected	in	the	2001 financial	statements.

|  | Generating	Stations | Fuel-Type | Total<br>Megawatt<br>Capability	(1) | Ownership | Investment | Accumulated<br>Depreciation |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  | (In\tMillions) |  |
| Entergy\tArkansas\t-\nIndependence | Unit\t1 | Coal | 815 | 31.50% | $117 | $71 |
|  | Common | Coal |  | 15.75% | 31 | 17 |
|  | Facilities |  |  |  |  |  |
| White\tBluff | Units\t1\tand\t2 | Coal | 1,635 | 57.00% | 423 | 256 |
| Entergy\tGulf\tStates\t- |  |  |  |  |  |  |
| Roy\tS.\tNelson | Unit\t6 | Coal | 550 | 70.00% | 404 | 234 |
| Big\tCajun\t2 | Unit\t3 | Coal | 575 | 42.00% | 233 | 123 |
| Entergy\tMississippi\t- |  |  |  |  |  |  |
| Independence | Units\t1\tand\t2\tand | Coal | 1,630 | 25.00% | 230 | 111 |
|  | Common |  |  |  |  |  |
|  | Facilities |  |  |  |  |  |
| System\tEnergy\t-\nGrand\tGulf | Unit\t1 | Nuclear | 1,207 | 90.00%(2) | 3,672 | 1,673 |

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

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

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.

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.

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.

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.

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

Entergy	applies	 the	provisions	of	SFAS	115,	"Accounting	for	Investments	for	Certain	Debt	and	Equity	Securities,"	 in	accounting	for	 investments	 in decommissioning	 trust	funds.	As	a	result,	Entergy	records	the	decommissioning	trust	funds	at	their	fair	value	on	the	consolidated	balance	sheet.	As	of December	31,	2003	and	2002,	the	fair	value	of	the	securities	held	in	such	funds	differs	from	the	amounts	deposited	plus	the	earnings	on	the	deposits	by	the following:

| Entergy	Arkansas | $52.9 | $35.3 |
| :--- | :--- | :--- |
| Entergy\tGulf\tStates | $17.2 | $1.4 |
| Entergy\tLouisiana | $9.2 | ($0.3) |
| System\tEnergy | ($2.1) | ($14.5) |

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.	Prior	 to	 the implementation	of	SFAS	143,	the	offsetting	amount	of	unrealized	gains/(losses)	on	investment	securities	was	recorded	in	accumulated	depreciation	for Entergy	Arkansas,	Entergy	Gulf	States	(for	the	regulated	portion	of	River	Bend),	and	for	Entergy	Louisiana.

# Derivatives	and	Hedging

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	7	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

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.

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.

# 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,	2003,	2002,	and	2001	are	as	follows:

The	net	investment	associated	with	these	deregulated	operations	as	of	December	31,	2003	and	2002	was	approximately	$798	million	and	$805	million, respectively.

During	2003,	Entergy	adopted	the	provisions	of	the	following	accounting	standards:	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	which	is discussed	further	in	Note	9;	FIN	46,	Consolidation	of	Variable	Interest	Entities,"	which	is	discussed	further	in	Note	6;	and	SFAS	150,	"Accounting	for Certain	Financial	Instruments	with	Characteristics	of	both	Liabilities	and	Equity."	SFAS	150,	which	became	effective	July	1,	2003,	requires	mandatorily redeemable	financial	instruments	to	be	classified	and	treated	as	liabilities	in	the	presentation	of	financial	position	and	results	of	operations.	The	only	effect	of implementing	SFAS	150	for	Entergy	is	the	inclusion	of	long-term	debt	and	preferred	stock	with	sinking	fund	under	the	liabilities	caption	in	Entergy's balance	sheet.	Entergy's	results	of	operations	and	cash	flows	were	not	affected	by	this	standard.

During	 2003,	 Entergy	 also	 adopted	 the	 provisions	 of	 the	 following	 accounting	 standards:	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.

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

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

Retail	open	access	commenced	in	portions	of	Texas	on	January	1,	2002.	The	staff	of	the	PUCT	filed	a	petition	to	delay	retail	open	access	in	Entergy	Gulf

States'	service	area,	and	Entergy	Gulf	States	reached	a	settlement	agreement	with	the	PUCT	to	delay	retail	open	access	until	at	least	September	15,	2002.	In September	2002,	the	PUCT	ordered	Entergy	Gulf	States	to	file	on	January	24,	2003	a	proposal	for	an	interim	solution	(retail	open	access	without	a	FERC- approved	RTO)	if	it	appeared	by	January	15,	2003	that	a	FERC-approved	RTO	would	not	be	functional	by	January	1,	2004.	On	January	24,	2003,	Entergy Gulf	States	filed	its	proposal,	which	among	other	elements,	included:

# Louisiana

# (Entergy	Gulf	States	and	Entergy	Louisiana)

In	March	1999,	the	LPSC	deferred	making	a	decision	on	whether	competition	in	the	electric	utility	industry	is	in	the	public	interest.	However,	the	LPSC directed	the	LPSC	staff,	outside	consultants,	and	counsel	to	work	together	to	analyze	and	resolve	issues	related	to	competition	and	to	recommend	a	plan	for consideration	 by	 the	 LPSC.	In	 July	 2001,	 the	 LPSC	 staff	 submitted	 a	 final	 response	 to	 the	 LPSC.	In	 its	report	 the	LPSC	staff	concluded	 that	retail competition	is	not	in	the	public	interest	at	this	time	for	any	customer	class.	Nevertheless,	the	LPSC	staff	recommended	that	retail	open	access	be	made available	for	certain	large	industrial	customers	as	early	as	January	2003.	An	eligible	customer	choosing	to	go	to	competition	would	be	required	to	provide	its utility	with	a	minimum	of	six	months	notice	prior	to	the	date	of	retail	open	access.	The	LPSC	staff	report	also	recommended	that	all	customers	who	do	not currently	co-	or	self-generate,	or	have	co-	or	self-generation	under	construction	as	of	a	date	to	be	specified	by	the	LPSC,	remain	liable	for	their	share	of stranded	costs.	During	its	October	2001	meeting,	the	LPSC	adopted	dates	by	which	a	total	of	800	MW	of	co-	or	self-generation	could	be	developed	in Louisiana	without	being	affected	by	stranded	costs.	During	its	November	2001	meeting,	the	LPSC	decided	not	to	adopt	a	plan	for	retail	open	access	for	any customers	at	this	time,	but	to	have	collaborative	group	meetings	concerning	open	access	from	time	to	time,	and	to	have	the	LPSC	staff	monitor	developments in	neighboring	states	and	to	report	to	the	LPSC	regarding	the	progress	of	retail	access	developments	in	those	states.	No	further	action	has	been	taken	by	the LPSC	at	this	time.

# 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	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.

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,	2003	and	2002	(in	millions).

| Provisions	for	storm	damages	- | 25.3 | 57.4 | 40.9 | 3.5 | - | - |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| recovered\tthrough\tcost\tof\tservice |  |  |  |  |  |  |
| Postretirement\tbenefits\t-\trecovered\nthrough\t2013\t(Note\t11) | 21.5 | - | - | - | - | - |
| Pension\tcosts\t(Note\t11) | 41.7 | - | - | 6.4 | 10.4 | 7.1 |
| Incremental\tice\tstorm\tcosts\t-\nrecovered\tuntil\t2032 | 14.7 | - | - | - | - | - |
| Depreciation\tre-direct\t-\trecovery\nbegins\tat\tstart\tof\tretail\topen\taccess\n(Note\t1) | - | 79.1 | - | - | - | - |
| River\tBend\tAFUDC\t-\trecovered\nthrough\tAugust\t2025\t(Note\t1) | - | 39.4 | - | - | - | - |
| Spindletop\tgas\tstorage\tlease\t-\nrecovered\tthrough\t2032 | - | 38.0 | - | - | - | - |
| 1994\tFERC\tSettlement\t-\trecovered\nthrough\tJune\t2004\t(Note\t2) | - | - | - | - | - | 4.0 |
| Sale-leaseback\tdeferral\t-\trecovered\nthrough\tJune\t2014\t(Note\t10) | - | - | - | - | - | 131.7 |
| Resource\tplanning\t-\trecovery\ttiming\nwill\tbe\tdetermined\tby\tthe\tLPSC\tin\ta\nbase\trate\tproceeding\t(Note\t2) | - | - | 5.8 | - | - | - |
| Low-level\tradwaste\t-\trecovery\ntiming\tdependent\tupon\tpending\nlawsuit | 16.2 | 3.1 | - | - | - | - |
| Deferred\tfuel\t-\tnon-current\t-\nrecovered\tthrough\trate\triders\twhen\nrates\tare\tredetermined\tannually | 17.1 | - | - | 11.1 | - | - |
| Unamortized\tloss\ton\treaquired\tdebt\n-\trecovered\tover\tterm\tof\tdebt | 38.3 | 46.6 | 24.0 | 11.8 | 1.7 | 41.9 |
| Other\t-\tvarious | 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 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
| DOE\tDecommissioning\tand\nDecontamination\tFees\t(Note\t9) | $20.9 | $3.7 | $8.0 | $- | $- | $7.8 |
| Removal\tcosts\t(Note\t9) | 35.2 | - | - | 28.6 | - | 15.8 |
| Provisions\tfor\tstorm\tdamages | 13.8 | 45.3 | 39.0 | 2.9 | - | - |
| Postretirement\tbenefits\t(Note\t11) | 23.9 | - | - | - | - | - |
| Pension\tcosts\t(Note\t11) | 19.1 | - | 38.8 | 9.8 | 3.0 | - |
| Incremental\tice\tstorm\tcosts | 15.3 | - | - | - | - | - |
| Imputed\tcapacity\tcharges | - | 5.5 | 11.8 | - | - | - |
| Depreciation\tre-direct\t(Note\t1) | - | 79.1 | - | - | - | - |
| River\tBend\tAFUDC\t(Note\t1) | - | 41.3 | - | - | - | - |
| Spindletop\tgas\tstorage\tlease | - | 35.0 | - | - | - | - |
| 1994\tFERC\tSettlement\t(Note\t2) | - | - | - | - | - | 12.1 |
| Sale-leaseback\tdeferral\t(Note\t10) | - | - | - | - | - | 123.9 |
| SFAS\t115\tdecommissioning\t(Note\t1) | - | - | - | - | - | 14.5 |
| Low-level\tradwaste | 16.2 | 3.1 | - | - | - | - |
| Deferred\tfuel\t-\tnon-current | - | - | 13.2 | - | - | - |
| Unamortized\tloss\ton\treaquired\tdebt | 39.8 | 31.2 | 25.8 | 12.7 | 0.6 | 45.0 |
| Other | 21.5 | 13.5 | 8.6 | 11.1 | 10.9 | 0.3 |
| Total | $205.7 | $257.7 | $145.2 | $65.1 | $14.5 | $219.4 |

| Entergy	Arkansas | $10.6 | $(42.6) |
| :--- | :--- | :--- |
| Entergy\tGulf\tStates | $118.4 | $100.6 |
| Entergy\tLouisiana | $30.6 | $(25.6) |

| Entergy	Mississippi | $89.1 | $38.2 |
| :--- | :--- | :--- |
| Entergy\tNew\tOrleans | $(2.7) | $(14.9) |

Interim	surcharge

Items	to	be	addressed	as	part	of	unbundling $	29.0	million

Imputed	capacity	charges $	9.3	million

The	PUCT	has	ordered	that	the	imputed	capacity	charges	be	excluded	from	fuel	rates	and	therefore	recovered	through	base	rates.	It	is	uncertain,	however,	as to	when	and	if	Entergy	Gulf	States	will	initiate	a	base	rate	proceeding	before	the	PUCT.	The	current	PUCT-approved	settlement	agreement	delaying	retail open	access	in	Texas	requires	a	rate	freeze	during	the	delay	period.	If	Entergy	Gulf	States	goes	to	retail	open	access	without	a	Texas	base	rate	proceeding,	it is	possible	that	Entergy	Gulf	States	will	not	be	allowed	to	recover	imputed	capacity	charges	in	Texas	retail	rates	in	the	future.

In	January	2001,	Entergy	Gulf	States	filed	a	fuel	reconciliation	case	covering	the	period	from	March	1999	through	August	2000.	Entergy	Gulf	States	was reconciling	approximately	$583	million	of	fuel	and	purchased	power	costs.	As	part	of	this	filing,	Entergy	Gulf	States	requested	authority	to	collect	$28 million,	plus	interest,	of	under-recovered	fuel	and	purchased	power	costs.	The	PUCT	decided	in	August	2002	to	reduce	Entergy	Gulf	States'	request	to approximately	$6.3	million,	including	interest	through	July	31,	2002.	Approximately	$4.7	million	of	the	total	reduction	to	the	requested	surcharge	relates	to nuclear	fuel	costs	that	the	PUCT	deferred	ruling	on	at	this	time.	In	October	2002,	Entergy	Gulf	States	appealed	the	PUCT's	final	order	in	Texas	District Court.	In	its	appeal,	Entergy	Gulf	States	is	challenging	the	PUCT's	disallowance	of	approximately	$4.2	million	related	to	imputed	capacity	costs	and	its disallowance	related	to	costs	for	energy	delivered	from	the	30%	non-regulated	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.

The	Louisiana	jurisdiction	of	Entergy	Gulf	States	and	Entergy	Louisiana	recover	electric	fuel	and	purchased	power	costs	for	the	upcoming	month	based upon	the	level	of	such	costs	from	the	prior	month.	The	Louisiana	jurisdiction	of	Entergy	Gulf	States'	gas	rate	schedules	include	estimates	for	the	billing month	adjusted	by	a	surcharge	or	credit	for	deferred	fuel	expense	arising	from	monthly	reconciliations.

In	August	2000,	the	LPSC	authorized	its	staff	to	initiate	a	proceeding	to	audit	the	fuel	adjustment	clause	filings	of	Entergy	Louisiana	pursuant	to	a	November 1997	LPSC	general	order.	The	time	period	that	is	the	subject	of	the	audit	is	January	1,	2000	through	December	31,	2001.	In	September	2003,	the	LPSC	staff issued	its	audit	report	and	recommended	a	disallowance	with	regard	to	one	item.	The	issue	relates	to	the	alleged	failure	to	uprate	Waterford	3	in	a	timely manner.	The	LPSC	staff	has	quantified	the	possible	disallowance	as	between	$7.6	and	$14	million.	Entergy	Louisiana	notified	the	LPSC	that	it	will	contest the	recommendation.	A	procedural	schedule	has	been	adopted	and	hearings,	which	also	will	address	issues	relating	to	the	reasonableness	of	transmission planning	and	purchases	of	power	from	affiliates,	the	potential	value	of	which	issues	cannot	yet	be	quantified,	are	scheduled	to	begin	in	September	2004,	but the	LPSC	staff	has	requested	a	delay	until	April	2005.

In	January	2003,	the	LPSC	authorized	its	staff	to	initiate	a	proceeding	to	audit	the	fuel	adjustment	clause	filings	of	Entergy	Gulf	States	and	its	affiliates pursuant	to	a	November	1997	LPSC	general	order.	The	audit	will	include	a	review	of	the	reasonableness	of	charges	flowed	by	Entergy	Gulf	States	through its	fuel	adjustment	clause	in	Louisiana	for	the	period	January	1,	1995	through	December	1,	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	Gulf	States	is	operating	in	Texas	under	the	terms	of	a	June	1999	settlement	agreement	approved	by	the	PUCT.	The	settlement	provided	for	a	base rate	freeze	that	has	remained	in	effect	during	the	delay	in	implementation	of	retail	open	access	in	Entergy	Gulf	States'	Texas	service	territory.

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.	The	Court	of	Appeals	heard	oral	argument	in	November	2002.	In	July	2003, the	 Third	 District	 Court	 of	Appeals	 unanimously	 affirmed	 the	 judgment	 of	 the	 Travis	 County	 District	 Court.	After	 considering	 the	 progress	 of	 the proceeding	in	light	of	the	decision	of	the	Court	of	Appeals,	management	has	concluded	that	it	is	prudent	to	accrue	for	the	loss	that	would	be	associated	with a	final,	non-appealable	decision	disallowing	the	abeyed	plant	costs.	The	net	carrying	value	of	the	abeyed	plant	costs	was	$107.7	million	as	of	June	30,	2003, and	after	this	accrual	Entergy	Gulf	States	provided	for	all	potential	loss	related	to	current	or	past	contested	costs	of	construction	of	the	River	Bend	plant. Accrual	of	the	loss	was	recorded	in	the	second	quarter	2003	and	reduced	net	income	by	$65.6	million.	In	January	2004,	the	Texas	Supreme	Court	asked	for full	briefing	on	the	merits	of	the	case	in	response	to	Entergy	Gulf	States'	petition	for	review.

In	May	2002,	Entergy	Gulf	States	filed	its	ninth	and	last	required	post-merger	analysis	with	the	LPSC.	The	filing	includes	an	earnings	review	filing	for	the 2001	test	year	that	resulted	in	a	rate	decrease	of	$11.5	million,	which	was	implemented	effective	June	2002.	In	April	2003,	the	LPSC	staff	filed	testimony	in which	it	recommended	that	the	LPSC	require	a	rate	refund	of	$30.3	million	and	a	prospective	rate	reduction	of	$75.9	million,	before	taking	into	account	the $11.5	million	rate	reduction	that	Entergy	Gulf	States	implemented	effective	June	2002.	In	July	2003,	Entergy	Gulf	States	filed	testimony	rebutting	the	LPSC staff's	testimony	and	supporting	the	filing.	During	discovery,	the	LPSC	staff	requested	that	Entergy	Gulf	States	provide	updated	cost	of	service	data	to reflect	 changes	 in	 costs,	 revenues,	 and	 rate	 base	 through	 December	 31,	 2002.	In	 September	 2003,	 Entergy	 Gulf	 States	 supplied	 the	 updated	 data.	In December	 2003,	 the	 LPSC	 staff	 filed	 testimony	 modifying	 its	 previous	 recommendation.	In	 the	 LPSC	 staff's	 December	 2003	 testimony,	 the	 staff recommended	a	rate	refund	of	$30.6	million	and	a	prospective	rate	reduction	of	approximately	$50	million.	Hearings	are	scheduled	to	begin	in	April	2004.

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	midpoint currently	in	effect	is	10.5%.	Hearings	are	currently	set	for	September	2004.

In	December	2002,	the	MPSC	issued	a	final	order	approving	a	joint	stipulation	entered	into	by	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff in	October	2002.	The	final	order	results	in	a	$48.2	million	rate	increase,	or	about	a	5.3%	increase	in	overall	retail	revenues,	which	is	based	on	an	ROE	of 11.75%.	The	rate	increase	began	in	January	2003.	The	order	endorsed	a	new	power	management	rider	schedule	designed	to	more	efficiently	collect	capacity portions	of	purchased	power	costs.	Also,	the	order	provides	for	improvements	in	the	return	on	equity	formula	and	more	robust	performance	measures	for Entergy	Mississippi's	formula	rate	plan.	Under	the	provisions	of	Entergy	Mississippi's	formula	rate	plan,	a	bandwidth	is	placed	around	the	benchmark	ROE, and	 if	Entergy	Mississippi	earns	outside	of	 the	bandwidth	(as	well	as	outside	of	a	range-of-no-change	at	each	edge	of	 the	bandwidth),	 then	Entergy Mississippi's	rates	will	be	adjusted,	though	on	a	prospective	basis	only.	Under	the	provisions	of	the	order,	Entergy	Mississippi	will	make	its	next	formula rate	plan	filing	during	March	2004.	The	"benchmark	ROE"	set	out	in	Entergy	Mississippi's	March	2004	annual	formula	rate	plan	filing	likely	will	differ from	the	last	approved	ROE.	Under	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	however,	if	Entergy	Mississippi's	earned	ROE	is	above	the top	of	the	range-of-no-change	at	the	top	of	the	formula	rate	plan	bandwidth,	then	Entergy	Mississippi's	"Allowed	ROE"	for	the	next	twelve-month	period	is the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth;	and	Entergy	Mississippi's	retail	rates	are	set	at	that	halfway-point	ROE	level.	In the	situation	where	Entergy	Mississippi's	earned	ROE	is	not	above	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth,	then	Entergy	Mississippi's

"Allowed	ROE"	for	the	next	twelve-month	period	is	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth.

# Filings	with	the	City	Council	(Entergy	New	Orleans)

Plaintiffs	also	filed	this	complaint	with	the	City	Council	in	order	to	initiate	a	review	by	the	City	Council	of	the	plaintiffs'	allegations	and	to	force	restitution to	ratepayers	of	all	costs	they	allege	were	improperly	and	imprudently	included	in	the	fuel	adjustment	filings.	Testimony	was	filed	on	behalf	of	the	plaintiffs in	this	proceeding	asserting,	among	other	things,	that	Entergy	New	Orleans	and	other	defendants	have	engaged	in	fuel	procurement	and	power	purchasing practices	and	included	costs	in	Entergy	New	Orleans'	fuel	adjustment	that	could	have	resulted	in	New	Orleans	customers	being	overcharged	by	more	than $100	million	over	a	period	of	years.	Hearings	were	held	in	February	and	March	2002.	In	February	2004,	the	City	Council	approved	a	resolution	that	results in	a	refund	to	customers	of	$11.3	million,	including	interest,	during	the	months	of	June	through	September	2004.	The	resolution	concludes,	among	other things,	that	the	record	does	not	support	an	allegation	that	Entergy	New	Orleans'	actions	or	inactions,	either	alone	or	in	concert	with	Entergy	or	any	of	its affiliates,	constituted	a	misrepresentation	or	a	suppression	of	the	truth	made	in	order	to	obtain	an	unjust	advantage	of	Entergy	New	Orleans,	or	to	cause	loss, inconvenience	 or	 harm	 to	 its	 ratepayers.	Management	 believes	 that	 it	 has	 adequately	 provided	 for	 the	 liability	 associated	 with	 this	 proceeding	 as	 of December	31,	2003.	The	plaintiffs	have	appealed	the	City	Council	resolution	to	the	state	court	in	Orleans	Parish.

# 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	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	recently	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	uprates	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	recommendation	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.

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

In	accordance	with	regulatory	accounting	principles,	during	the	pendency	of	the	case,	System	Energy	recorded	reserves	for	potential	refunds	against	its revenues.	Upon	the	order	becoming	final,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	recorded

entries	to	spread	the	impacts	of	FERC's	order	to	the	various	revenue,	expense,	asset,	and	liability	accounts	affected,	as	if	the	order	had	been	in	place	since commencement	of	the	case	in	1995.	System	Energy	also	recorded	an	additional	reserve	amount	against	its	revenue,	to	adjust	its	estimate	of	the	impact	of	the order,	 and	 recorded	 additional	 interest	 expense	 on	 that	 reserve.	System	 Energy	 also	 recorded	 reductions	 in	 its	 depreciation	 and	 its	 decommissioning expenses	to	reflect	the	lower	levels	in	FERC's	order,	and	reduced	tax	expense	affected	by	the	order.

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |
| \t\t\tFederal\t(a) | $40,632 | ($11,535) | ($745,724) | ($2,969) | ($7,655) | $95,670 |
| \t\t\tState\t(a) | 16,306 | (1,503) | (16,243) | 2,565 | (1,871) | 15,382 |
| \t\t\t\t\t\tTotal\t(a) | 56,938 | (13,038) | (761,967) | (404) | (9,526) | 111,052 |
| Deferred\t--\tnet | 53,309 | 36,652 | 864,656 | 36,240 | 15,853 | (31,731) |
| Investment\ttax\tcredit |  |  |  |  |  |  |
| \t\t\tadjustments\t--\tnet | (4,951) | (12,078) | (5,281) | (1,405) | (452) | (3,476) |
| \t\t\tRecorded\tincome\ttax\texpense | $105,296 | $11,536 | $97,408 | $34,431 | $5,875 | $75,845 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Current: |  |  |  |  |  |  |
| \t\t\tFederal\t(a) | $13,206 | $66,227 | $43,048 | $21,817 | ($7,103) | $99,429 |
| \t\t\tState\t(a) | 3,243 | 11,345 | 1,867 | 3,969 | (47) | 14,994 |
| \t\t\t\t\t\tTotal\t(a) | 16,449 | 77,572 | 44,915 | 25,786 | (7,150) | 114,423 |
| Deferred\t--\tnet | 59,963 | (4,210) | 45,253 | (6,529) | 7,196 | (34,770) |
| Investment\ttax\tcredit |  |  |  |  |  |  |
| \t\t\tadjustments\t--\tnet | (5,008) | (7,365) | (5,403) | (1,411) | (468) | (3,476) |
| \t\t\tRecorded\tincome\ttax\texpense | $71,404 | $65,997 | $84,765 | $17,846 | ($422) | $76,177 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2001 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Current: |  |  |  |  |  |  |
| \t\t\tFederal\t(a) | $83,314 | $60,333 | $97,265 | $77,074 | $16,844 | ($56,166) |
| \t\t\tState\t(a) | 16,230 | 17,385 | 16,404 | 11,523 | 2,958 | (6,837) |
| \t\t\t\t\tTotal\t(a) | 99,544 | 77,718 | 113,669 | 88,597 | 19,802 | (63,003) |
| Deferred\t--\tnet | 11,414 | 11,554 | (21,931) | (66,633) | (23,691) | 110,240 |
| Investment\ttax\tcredit |  |  |  |  |  |  |
| \t\t\tadjustments\t--\tnet | (5,025) | (7,234) | (5,451) | (1,500) | (507) | (3,476) |
| \t\t\tRecorded\tincome\ttax\texpense | $105,933 | $82,038 | $86,287 | $20,464 | ($4,396) | $43,761 |

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Deferred\tand\tLong-term\tAccrued\tTax\nLiabilities: |  |  |  |  |  |  |
| Net\tregulatory\tassets/(liabilities) | ($157,147) | ($478,254) | ($195,074) | ($34,738) | $38,834 | ($246,519) |
| Plant-related\tbasis\tdifferences,net | (798,641) | (1,095,206) | (806,955) | (284,550) | (74,041) | (332,197) |
| Power\tPurchase\tAgreements | - | - | (945,495) | - | - | - |
| Deferred\tFuel | (4,154) | (45,762) | - | (40,091) | (1,109) | - |
| Long\tterm\ttaxes\taccrued | (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:

| tax	credit | 28,836 | 36,192 | 38,962 | 5,773 | 1,709 | 30,251 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Sale\tand\tleaseback | - | - | 83,539 | - | - | 139,595 |
| NOL\tCarryforward | - | - | 104,489 | - | - | - |
| Unbilled/Deferred\trevenues | - | 11,959 | - | 7,357 | - | - |
| Pension-related\titems | 5,453 | 11,474 | 12,562 | - | 9,324 | 7,354 |
| Reserve\tfor\tregulatory\tadjustments | - | 138,933 | - | - | - | - |
| Rate\trefund | 2,351 | 23,184 | 789 | 379 | 3,977 | 170,222 |
| Customer\tDeposits | 37,778 | 35,840 | 16,804 | 18,085 | 84 | - |
| Nuclear\tDecommissioning | 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\tdeferred\ttax\tliability | ($978,093) | ($1,416,660) | ($1,728,722) | ($392,515) | ($39,026) | ($291,906) |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Deferred\tand\tLong-term\tAccrued\tTax\nLiabilities: |  |  |  |  |  |  |
| Net\tregulatory\tassets/(liabilities) | ($142,438) | ($493,358) | ($198,637) | ($24,560) | $29,435 | ($255,729) |
| Plant-related\tbasis\tdifferences,\tnet | (649,312) | (962,100) | (683,590) | (251,026) | (65,357) | (352,611) |
| Power\tpurchase\tagreements | - | - | (866,976) | - | - | - |
| Deferred\tfuel | - | (40,267) | (4,556) | (22,023) | (1,255) | - |
| \tOther | (89,851) | (43,537) | (107,098) | (19,090) | (5,398) | (20,285) |
| Total | (881,601) | (1,539,262) | (1,860,857) | (316,699) | (42,575) | (628,625) |
| Deferred\tTax\tAssets: |  |  |  |  |  |  |
| Accumulated\tdeferred\tinvestment |  |  |  |  |  |  |
| tax\tcredit | 30,690 | 40,471 | 40,995 | 6,310 | 1,883 | 31,581 |
| Sale\tand\tleaseback | - | - | 96,684 | - | - | 135,544 |
| Unbilled/Deferred\trevenues | 3,360 | 11,959 | - | 6,307 | - | - |
| Pension-related\titems | - | 5,339 | 6,282 | - | 7,803 | 4,085 |
| Rate\trefund | - | 18,084 | 66 | - | 4,502 | - |
| Reserve\tfor\tregulatory\tadjustments | - | 103,843 | - | - | - | - |
| Customer\tdeposits | 11,623 | 22,029 | 10,076 | 14,324 | 113 | - |
| Nuclear\tdecommissioning | 12,070 | 1,073 | 2,833 | - | - | 5,622 |
| Other | 7,090 | 28,117 | 12,751 | 4,771 | 7,259 | 6,931 |
| Total | 64,833 | 230,915 | 169,687 | 31,712 | 21,560 | 183,763 |
| Net\tdeferred\ttax\tliability | ($816,768) | ($1,308,347) | ($1,691,170) | ($284,987) | ($21,015) | ($444,862) |

At	December	31,	2003,	Entergy	Louisiana	had	a	state	net	operating	loss	carryforward	of	$1.7	billion,	primarily	resulting	from	its	mark-to-market	tax election.	If	the	state	net	operating	loss	is	not	utilized	against	income	from	Entergy	Louisiana,	it	will	expire	in	2016.

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

The	short-term	borrowings	of	the	domestic	utility	companies	and	System	Energy	are	limited	to	amounts	authorized	by	the	SEC.	The	current	limits	authorized are	effective	 through	November	30,	2004.	Also,	under	the	SEC	order	authorizing	the	short-term	borrowing	limits,	the	domestic	utility	companies	and System	 Energy	 cannot	 incur	 new	 short-term	 indebtedness	 if	 the	 issuer's	 common	 equity	 would	 comprise	 less	 than	 30%	 of	 its	 capital.	In	 addition	 to borrowing	from	commercial	banks,	the	domestic	utility	companies	and	System	Energy	are	authorized	to	borrow	from	the	Entergy	System	Money	Pool (money	 pool).	The	money	pool	is	an	inter-company	borrowing	arrangement	designed	to	reduce	the	domestic	utility	companies'	dependence	on	external short-term	borrowings.	Borrowings	from	the	money	pool	and	external	borrowings	combined	may	not	exceed	the	SEC	authorized	limits.	The	following	are the	outstanding	short-term	borrowings	from	the	money	pool	and	the	SEC-authorized	limits	for	short-term	borrowings	for	the	domestic	utility	companies	and System	Energy	as	of	December	31,	2003:

Authorized Borrowings (In	Millions)

|  | Authorized | Borrowings |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $235 | $69.2 |
| Entergy\tGulf\tStates | $340 | - |
| Entergy\tLouisiana | $225 | $41.3 |
| Entergy\tMississippi | $160 | - |
| Entergy\tNew\tOrleans | $100 | - |
| System\tEnergy | $140 | - |

Because	of	restrictions	contained	in	its	articles	of	incorporation,	Entergy	New	Orleans	could	only	incur	approximately	$38	million	of	new	unsecured	debt	as of	December	31,	2003.

| Company | Expiration	Date | Amount	of<br>Facility | Amount	Drawn	as	of<br>Dec.	31,	2003 |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | \t April\t2004 | $63\tmillion | - |
| Entergy\tLouisiana | \t May\t2004 | $15\tmillion | - |
| Entergy\tMississippi \t May\t2004 | Entergy\tMississippi \t May\t2004 | $25\tmillion | - |

# NOTE	5.	LONG	-	TERM	DEBT	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and System	Energy)

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

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

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

(g) 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.

(h) 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.

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

# NOTE	7.	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,	2003	and	2002	are	presented	below.	Only	the	two	Entergy	Gulf	States	series	"with	sinking	fund" contain	 mandatory	 redemption	 requirements.	All	other	series	are	redeemable	at	Entergy's	option	at	the	call	prices	presented.	Dividends	paid	on	all	of Entergy's	preferred	stock	series	are	eligible	for	the	dividends	received	deduction.	The	dividends	received	deduction	is	limited	by	Internal	Revenue	Code section	244	for	the	following	preferred	stock	series:	Entergy	Arkansas	4.72%,	Entergy	Gulf	States	4.40%,	Entergy	Louisiana	4.96%,	Entergy	Mississippi 4.56%,	and	Entergy	New	Orleans	4.75%.

|  | Shares | Shares |  |  | Call	Price	Per |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Authorized | Authorized |  |  | Share\tas\tof |
|  | and\tOutstanding | and\tOutstanding |  |  | December\t31, |
|  | 2003 | 2002 | 2003 | 2002 | 2003 |
|  |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Entergy\tArkansas\tPreferred\nStock |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.32%\tSeries | 70,000 | 70,000 | $7,000 | $7,000 | $103.65 |
| 4.72%\tSeries | 93,500 | 93,500 | 9,350 | 9,350 | 107.00 |
| 4.56%\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | 102.83 |
| 4.56%\t1965\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | 102.50 |
| 6.08%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 102.83 |
| 7.32%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 103.17 |
| 7.80%\tSeries | 150,000 | 150,000 | 15,000 | 15,000 | 103.25 |
| 7.40%\tSeries | 200,000 | 200,000 | 20,000 | 20,000 | 102.80 |
| 7.88%\tSeries | 150,000 | 150,000 | 15,000 | 15,000 | 103.00 |
| Cumulative,\t$0.01\tpar\tvalue: |  |  |  |  |  |
| $1.96\tSeries\t(a) | 600,000 | 600,000 | 15,000 | 15,000 | 25.00 |
| Total\twithout\tsinking\tfund | 1,613,500 | 1,613,500 | $116,350 | $116,350 |  |

|  | Shares |  |  |  | Call	Price	Per |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Authorized | Authorized |  |  | Share\tas\tof |
|  | and\tOutstanding | and\tOutstanding |  |  | December\t31, |
|  | 2003 | 2002 | 2003 | 2002 | 2003 |
| Entergy\tGulf\tStates\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Preferred\tStock |  |  |  |  |  |
| Authorized\t6,000,000\tshares, |  |  |  |  |  |
| $100\tpar\tvalue,\tcumulative |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| 4.40%\tSeries | 51,173 | 51,173 | $5,117 | $5,117 | $108.00 |
| 4.50%\tSeries | 5,830 | 5,830 | 583 | 583 | 105.00 |
| 4.40%\t1949\tSeries | 1,655 | 1,655 | 166 | 166 | 103.00 |
| 4.20%\tSeries | 9,745 | 9,745 | 975 | 975 | 102.82 |

| 4.44%	Series | 14,804 | 14,804 | 1,480 | 1,480 | 103.75 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 5.00%\tSeries | 10,993 | 10,993 | 1,099 | 1,099 | 104.25 |
| 5.08%\tSeries | 26,845 | 26,845 | 2,685 | 2,685 | 104.63 |
| 4.52%\tSeries | 10,564 | 10,564 | 1,056 | 1,056 | 103.57 |
| 6.08%\tSeries | 32,829 | 32,829 | 3,283 | 3,283 | 103.34 |
| 7.56%\tSeries | 308,830 | 308,830 | 30,883 | 30,883 | 101.80 |
| Total\twithout\tsinking\tfund | 473,268 | 473,268 | $47,327 | $47,327 |  |
| With\tsinking\tfund: |  |  |  |  |  |
| Adjustable\tRate\t-\tA,\t7.0%\t(b) | 96,020 | 108,120 | $9,602 | $10,812 | $100.00 |
| Adjustable\tRate\t-\tB,\t7.0%\t(b) | 112,499 | 135,149 | 11,250 | 13,515 | 100.00 |
| Total\twith\tsinking\tfund | 208,519 | 243,269 | $20,852 | $24,327 |  |
| Fair\tValue\tof\tPreferred\tStock\nwith\tsinking\tfund\t(c) |  |  | $15,354 | $20,792 |  |

|  | Shares | Shares |  |  | Call	Price	Per |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Authorized | Authorized |  |  | Share\tas\tof |
|  | and\tOutstanding | and\tOutstanding |  |  | December\t31, |
|  | 2003 | 2002 | 2003 | 2002 | 2003 |
| Entergy\tLouisiana\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Without\tsinking\nfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.96%\tSeries | 60,000 | 60,000 | $6,000 | $6,000 | $104.25 |
| 4.16%\tSeries | 70,000 | 70,000 | 7,000 | 7,000 | 104.21 |
| 4.44%\tSeries | 70,000 | 70,000 | 7,000 | 7,000 | 104.06 |
| 5.16%\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | 104.18 |
| 5.40%\tSeries | 80,000 | 80,000 | 8,000 | 8,000 | 103.00 |
| 6.44%\tSeries | 80,000 | 80,000 | 8,000 | 8,000 | 102.92 |
| 7.84%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 103.78 |
| 7.36%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 103.36 |
| Cumulative,\t$25\tpar\tvalue: |  |  |  |  |  |
| 8.00%\tSeries | 1,480,000 | 1,480,000 | 37,000 | 37,000 | 25.00 |
| Total\twithout\tsinking\tfund | 2,115,000 | 2,115,000 | $100,500 | $100,500 |  |

|  | Shares | Shares |  |  | Call	Price	Per |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Authorized | Authorized |  |  | Share\tas\tof |
|  | and\tOutstanding | and\tOutstanding |  |  | December\t31, |
|  | 2003 | 2002 | 2003 | 2002 | 2003 |
| Entergy\tMississippi\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Without\tsinking\nfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.36%\tSeries | 59,920 | 59,920 | $5,992 | $5,992 | $103.86 |
| 4.56%\tSeries | 43,887 | 43,887 | 4,389 | 4,389 | 107.00 |
| 4.92%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 102.88 |
| 7.44%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | 102.81 |
| 8.36%\tSeries | 200,000 | 200,000 | 20,000 | 20,000 | 100.00 |
| Total\twithout\tsinking\tfund | 503,807 | 503,807 | $50,381 | $50,381 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2003 | 2002 | 2003 | 2002 | Call	Price	Per<br>Share	as	of<br>December	31,<br>2003 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tNew\tOrleans\tPreferred\nStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.75%\tSeries | 77,798 | 77,798 | $7,780 | $7,780 | $105.00 |
| 4.36%\tSeries | 60,000 | 60,000 | 6,000 | 6,000 | 104.57 |
| 5.56%\tSeries | 60,000 | 60,000 | 6,000 | 6,000 | 102.59 |
| Total\twithout\tsinking\tfund | 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	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	12	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

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

Entergy	Gulf	States	has	annual	sinking	fund	requirements	of	$3.45	million	through	2008	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	8.	COMMON	EQUITY	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans)

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

# 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,	2003, Entergy	Arkansas	and	Entergy	Mississippi	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$309.4	million	and	$41.9 million,	respectively.

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.

# Fuel	Supply	Agreements

# (Entergy	Arkansas	and	Entergy	Mississippi)

Entergy	Arkansas	has	a	long-term	contract	for	the	supply	of	low-sulfur	coal	for	Independence	(which	is	also	25%	owned	by	Entergy	Mississippi).	This contract,	which	expires	in	2011,	provides	for	approximately	90%	of	Independence's	expected	annual	coal	requirements.	Additional	requirements	are	satisfied by	 spot	 market	 purchases.	Entergy	 Arkansas	 has	 entered	 into	 three	 medium-term	 (one	 one-year,	 one	 two-year,	 and	 one	 three-year)	 contracts	 for approximately	52%	of	White	Bluff's	coal	supply	needs.	As	each	contract	expires,	it	is	scheduled	to	be	renewed	at	the	same	quantity	for	a	three-year	term. Entergy	Arkansas	has	an	additional	20%	of	its	2004	coal	requirement	committed	in	a	number	of	one-	to	two-year	contracts.	Additional	coal	requirements	for both	Independence	and	White	Bluff	are	satisfied	by	spot	market	or	over	the	counter	purchases.	Additionally,	Entergy	Arkansas	has	a	long-term	railroad transportation	contract	for	the	delivery	of	coal	to	both	White	Bluff	and	Independence	that	expires	in	2011.

Effective	April	1,	2000,	Louisiana	Generating	LLC	assumed	ownership	of	Cajun's	interest	in	the	Big	Cajun	generating	facilities,	in	which	Entergy	Gulf States	 owns	 a	 42%	 interest.	The	 management	 of	 Louisiana	 Generating	 LLC	 has	 advised	 Entergy	 Gulf	 States	 that	 it	 has	 executed	 coal	 supply	 and transportation	contracts	that	should	provide	an	adequate	supply	of	coal	for	the	operation	of	Big	Cajun	2,	Unit	3	for	the	foreseeable	future.

Entergy	Louisiana	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	$65	million	for	the	years	2004	through	2012.

# Purchased	Power	Agreements

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

# 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,	2003	mature	in	2008:

| Owner | Ownership<br>Percentage | Loan	Outstanding<br>at	December	31,	2003 |
| :--- | :--- | :--- |
| Entergy\tArkansas | 35% | $11.0\tmillion |
| Entergy\tLouisiana | 33% | $14.2\tmillion |
| Entergy\tMississippi | 19% | $5.5\tmillion |
| Entergy\tNew\tOrleans | 13% | $3.3\tmillion |

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

Entergy	Arkansas	has	two	licensed	reactors	and	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy	each	have	one	licensed	reactor	(10%	of	Grand Gulf	1	is	owned	by	a	non-affiliated	company	(SMEPA),	which	would	share	on	a	pro-rata	basis	in	any	retrospective	premium	assessment	under	the	Act).

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

ANO	1	and	2,	Grand	Gulf	1,	River	Bend,	and	Waterford	3

$2.5	million	per	occurrence	-	Other	than	equipment	breakdown/failure

In	addition,	Waterford	3	and	Grand	Gulf	1	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

$413	million	maximum	indemnity Deductible:	12	week	waiting	period

Grand	Gulf	1

$100,000	weekly	indemnity $14	million	maximum	indemnity Deductible:	26	week	waiting	period

Under	the	property	damage	and	accidental	outage	insurance	programs,	Entergy	nuclear	plants	could	be	subject	to	assessments	should	losses	exceed	the accumulated	funds	available	from	NEIL.	As	of	December	31,	2003,	the	maximum	amount	of	such	possible	assessments	per	occurrence	were	$22.0	million

for	Entergy	Arkansas,	$18.8	million	for	Entergy	Gulf	States,	$20.7	million	for	Entergy	Louisiana,	$0.06	million	for	Entergy	Mississippi,	$0.06	million	for Entergy	New	Orleans,	and	$17.7	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.

# 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	neutral	to	the	rate-regulated	business	of	the	domestic	utility	companies	and	System	Energy.

Assets	and	liabilities	increased	approximately	$1.1	billion	for	the	domestic	utility	companies	and	System	Energy	as	a	result	of	recording	the	asset	retirement obligations	at	their	fair	values	of	$1.1	billion	as	determined	under	SFAS	143,	increasing	utility	plant	by	$287	million,	reducing	accumulated	depreciation	by $361	million	and	recording	the	related	regulatory	assets	of	$422	million.	The	implementation	of	SFAS	143	for	the	portion	of	River	Bend	not	subject	to	cost- based	ratemaking	decreased	earnings	 in	 the	first	quarter	of	2003	by	approximately	$21	million	net-of-tax	($0.09	per	share)	as	a	result	of	a	one-time cumulative	effect	of	accounting	change.	In	accordance	with	ratemaking	treatment	and	as	required	by	SFAS	71,	the	depreciation	provisions	for	the	domestic utility	companies	and	System	Energy	include	a	component	for	removal	costs	that	are	not	asset	retirement	obligations	under	SFAS	143.	In	accordance	with regulatory	accounting	principles,	Entergy	has	recorded	a	regulatory	asset	(liability)	in	the	following	amounts	to	reflect	its	estimate	of	the	difference	between estimated	incurred	removal	costs	and	estimated	removal	costs	recovered	in	rates	previously	recorded	as	a	component	of	accumulated	depreciation:

| Entergy	Arkansas | $26.6 | $35.2 |
| :--- | :--- | :--- |
| Entergy\tGulf\tStates | 4.2 | (0.8) |
| Entergy\tLouisiana | (26.8) | (23.2) |
| Entergy\tMississippi | 24.4 | 28.6 |
| Entergy\tNew\tOrleans | 2.1 | (1.5) |
| System\tEnergy | 15.1 | 15.8 |

The	cumulative	liabilities	and	decommissioning	expenses	recorded	in	2003	by	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System Energy	were	as	follows:

|  | Liabilities	as	of | SFAS	143 |  | Liabilities	as	of |
| :--- | :--- | :--- | :--- | :--- |
|  | December\t31,\t2002 | Adoption | Accretion | December\t31,\t2003 |
|  |  | (In\tMillions) |  |  |
| ANO\t1\tand\tANO\t2 | $310.7 | $221.0 | $35.8 | $567.5 |
| River\tBend | 237.0 | 41.2 | 20.6 | 298.8 |
| Waterford\t3 | 125.3 | 179.4 | 20.6 | 325.3 |
| Grand\tGulf\t1 | 153.5 | 137.2 | 21.8 | 312.5 |

Entergy	periodically	reviews	and	updates	estimated	decommissioning	costs.	The	actual	decommissioning	costs	may	vary	from	the	estimates	because	of regulatory	requirements,	changes	in	technology,	and	increased	costs	of	labor,	materials,	and	equipment.

If	SFAS	143	had	been	applied	by	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy	during	prior	periods,	the	following	impacts would	have	resulted:

|  | Year	Ended<br>December	31,<br>2002 | Year	Ended<br>December	31,<br>2001 |
| :--- | :--- | :--- |
| Entergy\tArkansas |  |  |
| Pro\tforma\tasset\tretirement\tobligations | $531,659 | $498,041 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $220,971 | $205,324 |
| Asset\tretirement\tobligations\tactually\trecorded | $310,688 | $292,717 |

| Pro	forma	asset	retirement	obligations | $304,728 | $285,640 |
| :--- | :--- | :--- |
| Pro\tforma\teffect\tof\tSFAS\t143 | $179,403 | $174,169 |
| Asset\tretirement\tobligations\tactually\trecorded | $125,325 | $111,471 |
| System\tEnergy |  |  |
| Pro\tforma\tasset\tretirement\tobligations | $290,659 | $270,381 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $137,186 | $130,278 |
| Asset\tretirement\tobligations\tactually\trecorded | $153,473 | $140,103 |
| Entergy\tGulf\tStates |  |  |
| Pro\tforma\tasset\tretirement\tobligations | $278,245 | $259,120 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $41,258 | $32,977 |
| Asset\tretirement\tobligations\tactually\trecorded | $236,987 | $226,143 |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tas\treported | $169,190 | $174,419 |
| Pro\tforma\teffect\tof\tSFAS\t143 | $(2,227) | $(2,428) |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tpro\tforma | $166,963 | $171,991 |

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,	2003	are	as	follows:

# Environmental	Issues	(Entergy	Gulf	States)

Entergy	Gulf	States	has	been	designated	as	a	PRP	for	the	cleanup	of	certain	hazardous	waste	disposal	sites.	Entergy	Gulf	States	is	currently	negotiating	with the	EPA	and	state	authorities	regarding	the	cleanup	of	these	sites.	As	of	December	31,	2003,	Entergy	Gulf	States	does	not	expect	the	remaining	clean-up costs	to	exceed	its	recorded	liability	of	$11.6	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,	and/or	sex.	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	400	lawsuits	involving	just	over	7,000	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	results	of	operation.

# Grand	Gulf	1-Related	Agreements

# Capital	Funds	Agreement	(System	Energy)

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

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

System	Energy	has	agreed	 to	sell	all	of	 its	90%	share	of	capacity	and	energy	from	Grand	Gulf	1	 to	Entergy	Arkansas,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans	in	accordance	with	specified	percentages	(Entergy	Arkansas-36%,	Entergy	Louisiana-14%,	Entergy	Mississippi-33%, and	Entergy	New	Orleans-17%)	as	ordered	by	FERC.	Charges	under	this	agreement	are	paid	in	consideration	for	the	purchasing	companies'	respective entitlement	to	receive	capacity	and	energy	and	are	payable	irrespective	of	the	quantity	of	energy	delivered	so	long	as	the	unit	remains	in	commercial operation.	The	agreement	will	remain	in	effect	until	terminated	by	the	parties	and	the	termination	is	approved	by	FERC,	most	likely	upon	Grand	Gulf	1's retirement	from	service.	Monthly	obligations	are	based	on	actual	capacity	and	energy	costs.	The	average	monthly	payments	for	2003	under	the	agreement are	approximately	$17.2	million	for	Entergy	Arkansas,	$6.7	million	for	Entergy	Louisiana,	$15.9	million	for	Entergy	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	Arkansas	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	1.	In	connection	with	the	equity	funding	of	the	sale	and	leaseback	arrangements,	letters	of	credit	are	required	to	be maintained	to	secure	certain	amounts	payable	for	the	benefit	of	the	equity	investors	by	System	Energy	under	the	leases.	The	current	letters	of	credit	are effective	until	May	30,	2007.

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,	2003,	System Energy's	debt	ratio	was	approximately	49.0%,	and	its	fixed	charge	coverage	ratio	for	2003	was	approximately	3.86,	calculated,	in	each	case,	as	prescribed	in the	reimbursement	agreement.

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

As	of	December	31,	2003,	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:

|  | Entergy | Entergy | Entergy |
| :--- | :--- | :--- | :--- |
| Year | Arkansas | Gulf\tStates | Mississippi |
|  |  | (In\tThousands) |  |
| 2004 | $9,646 | $9,000 | $49 |
| 2005 | 9,611 | - | 49 |
| 2006 | 5,683 | - | 41 |
| 2007 | 3,428 | - | 11 |
| 2008 | 1,753 | - | - |

| Years	thereafter | 2,844 | - | - |
| :--- | :--- | :--- | :--- |
| Minimum\tlease\tpayments | 32,965 | 9,000 | 150 |
| Less:\tAmount |  |  |  |
| representing\tinterest | 8,428 | 705 | 16 |
| Present\tvalue\tof\tnet |  |  |  |
| minimum\tlease\tpayments | $24,537 | $8,295 | $134 |

| Year | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2004 | $21,072 | $27,507 | $12,271 | $7,491 | $101 |
| 2005 | 18,569 | 25,158 | 8,218 | 5,807 | 41 |
| 2006 | 15,056 | 23,330 | 3,985 | 4,134 | - |
| 2007 | 12,667 | 17,029 | 2,881 | 1,182 | - |
| 2008 | 10,197 | 9,785 | 1,430 | 673 | - |
| Years\tthereafter | 62,573 | 130,357 | 2,128 | 533 | - |
| Minimum\tlease\tpayments | $140,134 | $233,166 | $30,913 | $19,820 | $142 |

Rental	expense	amounted	to	$19.4	million,	$20.8	million,	and	$21.1	million	for	Entergy	Arkansas;	$18.2	million,	$17.6	million,	and	$22.0	million	for Entergy	Gulf	States;	and	$11.4	million,	$11.2	million,	and	$11.7	million	for	Entergy	Louisiana	in	2003,	2002,	and	2001,	respectively.	In	addition	to	the above	rental	expense,	railcar	operating	lease	payments,	which	are	recorded	in	fuel	expense,	were	$6.8	million	in	2003,	$8.3	million	in	2002,	and	$12.2 million	in	2001	for	Entergy	Arkansas	and	$1.8	million	in	2003,	$2.0	million	in	2002,	and	$2.8	million	in	2001	for	Entergy	Gulf	States.	The	railcar	lease payments	are	recorded	as	fuel	expense	in	accordance	with	regulatory	treatment.

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	2003,	2002,	and	2001:

|  | 2003 |  | 2002 |  | 2001 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Lease |  | Lease |  | Lease |  |
|  | Payments | Interest | Payments | Interest | Payments | Interest |
|  |  |  | (In\tMillions) |  |  |  |
| Entergy\tArkansas | $49.9 | $3.3 | $49.6 | $3.2 | $54.1 | $5.7 |
| Entergy\tGulf\tStates | 27.8 | 3.0 | 29.2 | 3.0 | 31.5 | 4.1 |
| Entergy\tLouisiana | 32.3 | 2.4 | 32.9 | 2.6 | 37.2 | 3.8 |
| System\tEnergy | 32.0 | 3.1 | 26.1 | 2.5 | 26.5 | 3.6 |
| Total | $142.0 | $11.8 | $137.8 | $11.3 | $149.3 | $17.2 |

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.

| 2004 | $31,739 |
| :--- | :--- |
| 2005 | 14,554 |
| 2006 | 18,262 |
| 2007 | 18,754 |
| 2008 | 22,606 |
| Years\tthereafter | 366,514 |
| Total | 472,429 |
| Less:\tAmount\trepresenting\tinterest | 209,895 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $262,534 |

# Grand	Gulf	1	Lease	Obligations	(System	Energy)

| 2004 | $36,133 |
| :--- | :--- |
| 2005 | 52,253 |
| 2006 | 52,253 |
| 2007 | 52,253 |
| 2008 | 52,253 |
| Years\tthereafter | 365,176 |
| Total | 610,321 |
| Less:\tAmount\trepresenting\tinterest | 206,853 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $403,468 |

# NOTE	11.	RETIREMENT	AND	OTHER	POSTRETIREMENT	BENEFITS	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	and	System	Energy)

The	domestic	utility	companies	and	System	Energy	have	two	pension	plans,	"Entergy	Corporation	Retirement	Plan	for	Non-Bargaining	Employees,"	and "Entergy	Corporation	Retirement	Plan	for	Bargaining	Employees,"	covering	substantially	all	of	their	employees.	The	pension	plans	are	noncontributory	and provide	pension	benefits	that	are	based	on	employees'	credited	service	and	compensation	during	the	final	years	before	retirement.	The	domestic	utility companies	and	System	Energy	fund	pension	costs	in	accordance	with	contribution	guidelines	established	by	the	Employee	Retirement	Income	Security	Act of	1974,	as	amended,	and	the	Internal	Revenue	Code	of	1986,	as	amended.	The	assets	of	the	plans	include	common	and	preferred	stocks,	fixed-income securities,	interest	in	a	money	market	fund,	and	insurance	contracts.	As	of	December	31,	2003	and	December	31,	2002,	Entergy	recognized	an	additional minimum	pension	liability	for	the	excess	of	the	accumulated	benefit	obligation	over	the	fair	market	value	of	plan	assets.	In	accordance	with	FASB	87,	an offsetting	intangible	asset,	up	to	the	amount	of	any	unrecognized	prior	service	cost,	was	also	recorded,	with	the	remaining	offset	to	the	liability	recorded	as	a regulatory	asset	reflective	of	the	recovery	mechanism	for	pension	costs	in	Entergy's	jurisdictions.	Entergy's	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.

Total	2003,	2002,	and	2001	pension	cost	of	the	domestic	utility	companies	and	System	Energy,	including	amounts	capitalized,	included	the	following components:

| during	the	period | $11,156 | $8,788 | $6,369 | $3,411 | $1,539 | $3,142 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Interest\tcost\ton\tprojected |  |  |  |  |  |  |
| \t\tbenefit\tobligation | 33,009 | 27,708 | 20,028 | 11,339 | 3,958 | 4,200 |
| Expected\treturn\ton\tassets | (38,712) | (41,784) | (28,919) | (15,434) | (2,616) | (3,944) |
| Amortization\tof\ttransition\tasset | - | - | - | - | - | (319) |
| Amortization\tof\tprior\tservice\tcost | 1,737 | 1,931 | 789 | 584 | 236 | 73 |
| Recognized\tnet\tloss | 256 | 150 | - | 83 | - | 27 |
| Curtailment\tloss | 5,305 | 2,133 | 2,748 | 1,065 | 129 | 944 |
| Special\ttermination\tbenefits | 5,543 | 2,857 | 2,619 | 811 | 367 | 1,720 |
| Net\tpension\tcost | $18,294 | $1,783 | $3,634 | $1,859 | $3,613 | $5,843 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $9,787 | $7,391 | $5,901 | $2,971 | $1,414 | $2,616 |
| Interest\tcost\ton\tprojected |  |  |  |  |  |  |
| \t\tbenefit\tobligation | 31,058 | 27,737 | 19,747 | 11,013 | 4,126 | 3,735 |
| Expected\treturn\ton\tassets | (40,514) | (43,827) | (30,300) | (16,197) | (2,763) | (3,775) |
| Amortization\tof\ttransition\tasset | - | - | - | - | - | (319) |
| Amortization\tof\tprior\tservice\tcost | 1,743 | 1,923 | 744 | 705 | 269 | 72 |
| Net\tpension\tcost\t(income) | $2,074 | ($6,776) | ($3,908) | ($1,508) | $3,046 | $2,329 |
|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |

| 2001 | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $9,207 | $6,645 | $5,358 | $2,659 | $1,280 | $2,423 |
| Interest\tcost\ton\tprojected |  |  |  |  |  |  |
| \t\tbenefit\tobligation | 30,746 | 26,292 | 19,114 | 10,602 | 3,643 | 3,366 |
| Expected\treturn\ton\tassets | (41,308) | (44,511) | (31,089) | (16,547) | (2,712) | (3,865) |
| Amortization\tof\ttransition\tasset | (2,336) | - | (2,792) | (1,250) | - | (319) |
| Amortization\tof\tprior\tservice\tcost | 1,697 | 1,896 | 759 | 694 | 262 | 59 |
| Recognized\tnet\t(gain)/loss | (2,228) | (7,266) | (2,398) | (1,406) | 172 | (52) |
| Net\tpension\tcost\t(income) | ($4,222) | ($16,944) | ($11,048) | ($5,248) | $2,645 | $1,612 |

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tProjected\tBenefit |  |  |  |  |  |  |
| Obligation\t(PBO) |  |  |  |  |  |  |
| Balance\tat\t12/31/02 | $476,276 | $420,644 | $297,144 | $167,175 | $57,085 | $59,418 |
| Service\tcost | 11,156 | 8,788 | 6,369 | 3,411 | 1,539 | 3,142 |
| Interest\tcost | 33,009 | 27,708 | 20,028 | 11,339 | 3,958 | 4,200 |
| Amendment | 121 | 96 | - | 5 | - | 5 |
| Actuarial\t(gain)/loss | 62,444 | 31,342 | 30,844 | 17,133 | 7,417 | 9,984 |
| Benefits\tpaid | (28,445) | (25,611) | (19,332) | (10,634) | (2,559) | (366) |
| Curtailment\tloss | 4,900 | 1,883 | 2,540 | 944 | 59 | 930 |
| Special\ttermination\tbenefits | 5,543 | 2,857 | 2,619 | 811 | 367 | 1,720 |
| Balance\tat\t12/31/03 | $565,004 | $467,707 | $340,212 | $190,184 | $67,866 | $79,033 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/02 | $367,080 | $380,999 | $261,785 | $144,947 | $32,384 | $34,041 |
| Actual\treturn\ton\tplan\tassets | 84,579 | 93,102 | 74,216 | 35,645 | (260) | 11,700 |
| Employer\tcontributions | (28,445) | (25,611) | (19,332) | (10,634) | (2,559) | (366) |
| Fair\tvalue\tof\tassets\tat\t12/31/03 | $423,214 | $448,490 | $316,669 | $169,958 | $29,565 | $45,375 |
| Funded\tstatus | ($141,790) | ($19,217) | ($23,543) | ($20,226) | ($38,301) | ($33,658) |

| Unrecognized	transition	asset | - | - | - | - | - | (596) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Unrecognized\tprior\tservice\tcost | 9,839 | 7,449 | 4,412 | 3,206 | 1,489 | 353 |
| Unrecognized\tnet\t(gain)/loss | 93,535 | 24,044 | 48,533 | 25,970 | 19,367 | 16,021 |
| Accrued\tpension\tcost\trecognized\nin\tthe\tbalance\tsheet | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |
| Amounts\trecognized\tin\nthe\tbalance\tsheet: |  |  |  |  |  |  |
| Prepaid/(accrued)\tpension\tliability | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |
| Additional\tminimum\tpension\nliability | (54,948) | - | - | (7,301) | (13,140) | (7,426) |
| Intangible\tasset | 13,291 | - | - | 937 | 2,774 | 365 |
| Regulatory\tasset | 41,657 | - | - | 6,364 | 10,366 | 7,061 |
| Net\tamount\trecognized | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tProjected\tBenefit |  |  |  |  |  |  |
| Obligation\t(PBO) |  |  |  |  |  |  |
| Balance\tat\t12/31/01 | $437,553 | $370,907 | $272,452 | $149,808 | $52,394 | $50,564 |
| Service\tcost | 9,787 | 7,391 | 5,901 | 2,971 | 1,414 | 2,616 |
| Interest\tcost | 31,058 | 27,737 | 19,747 | 11,013 | 4,126 | 3,735 |
| Actuarial\t(gain)/loss | 24,452 | 40,309 | 17,740 | 13,638 | 1,341 | 2,661 |
| Benefits\tpaid | (26,574) | (25,700) | (18,696) | (10,255) | (2,190) | (158) |
| Balance\tat\t12/31/02 | $476,276 | $420,644 | $297,144 | $167,175 | $57,085 | $59,418 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/01 | $443,867 | $468,458 | $323,565 | $174,616 | $31,810 | $40,549 |
| Actual\treturn\ton\tplan\tassets | (50,213) | (61,759) | (43,084) | (19,414) | 2,764 | (6,350) |
| Benefits\tpaid | (26,574) | (25,700) | (18,696) | (10,255) | (2,190) | (158) |
| Fair\tvalue\tof\tassets\tat\t12/31/02 | $367,080 | $380,999 | $261,785 | $144,947 | $32,384 | $34,041 |
| Funded\tstatus | ($109,196) | ($39,645) | ($35,359) | ($22,228) | ($24,701) | ($25,377) |
| Amounts\tnot\tyet\trecognized\nin\tthe\tbalance\tsheet: |  |  |  |  |  |  |
| Unrecognized\ttransition\tasset | - | - | - | - | - | (914) |
| Unrecognized\tprior\tservice\tcost | 11,859 | 9,534 | 5,408 | 3,905 | 1,796 | 434 |
| Unrecognized\tnet\t(gain)/loss | 77,214 | 44,170 | 62,987 | 29,132 | 9,073 | 13,820 |
| Accrued\tpension\tcost\trecognized\nin\tthe\tbalance\tsheet | ($20,123) | $14,059 | $33,036 | $10,809 | ($13,832) | ($12,037) |
| Amounts\trecognized\tin\nthe\tbalance\tsheet: |  |  |  |  |  |  |
| Prepaid/(accrued)\tpension\tliability | ($20,123) | $14,059 | $33,036 | $10,809 | ($13,832) | ($12,037) |
| Additional\tminimum\tpension\nliability | (29,622) | (7,140) | (44,163) | (13,001) | (4,767) | (386) |
| Intangible\tasset | 10,566 | 7,140 | 5,408 | 3,191 | 1,796 | 386 |
| Regulatory\tasset | 19,056 | - | 38,755 | 9,810 | 2,971 | - |
| Net\tamount\trecognized | ($20,123) | $14,059 | $33,036 | $10,809 | ($13,832) | ($12,037) |

The	domestic	utility	companies	and	System	Energy	also	provide	health	care	and	life	insurance	benefits	for	retired	employees.	Substantially	all	employees may	become	eligible	for	these	benefits	if	they	reach	retirement	age	while	still	working	for	Entergy.	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	1.	Entergy	Louisiana	and	Entergy	Gulf	States	continue	to	recover	a	portion	of	these	benefits	regulated	by	the	LPSC	and FERC	on	a	pay-as-you-go	basis.	The	assets	of	the	various	postretirement	benefit	plans	other	than	pensions	include	common	stocks,	fixed-income	securities, and	a	money	market	fund.

# Components	of	Net	Other	Postretirement	Benefit	Cost

Total	2003,	2002,	and	2001	other	postretirement	benefit	costs	of	the	domestic	utility	companies	and	System	Energy,	including	amounts	capitalized	and deferred,	included	the	following	components:

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $6,560 | $5,701 | $3,322 | $1,866 | $948 | $1,553 |
| Interest\tcost\ton\tAPBO | 10,637 | 11,314 | 6,780 | 3,459 | 3,436 | 1,352 |
| Expected\treturn\ton\tassets | (4,859) | (4,349) | - | (2,186) | (2,010) | (1,088) |
| Amortization\tof\ttransition\nobligation | 3,327 | 5,307 | 2,238 | 1,301 | 2,449 | 135 |
| Amortization\tof\tprior\tservice\tcost | 143 | 163 | 82 | 51 | 52 | (140) |
| Recognized\tnet\t(gain)/loss | 3,497 | 1,575 | 1,496 | 1,160 | 475 | 350 |
| Curtailment\tloss | 9,276 | 6,301 | 5,041 | 1,259 | 996 | 2,524 |
| Special\ttermination\tbenefits | 794 | 512 | 452 | 73 | 28 | 284 |
| Net\tother\tpostretirement\tbenefit\tcost | $29,375 | $26,524 | $19,411 | $6,983 | $6,374 | $4,970 |
|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |

| 2002 | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $5,429 | $4,153 | $3,137 | $1,513 | $889 | $1,300 |
| Interest\tcost\ton\tAPBO | 9,448 | 9,734 | 6,242 | 3,099 | 3,264 | 1,150 |
| Expected\treturn\ton\tassets | (3,889) | (4,232) | - | (2,088) | (1,959) | (1,023) |
| Amortization\tof\ttransition\nobligation | 3,954 | 5,803 | 2,971 | 1,502 | 2,678 | 220 |
| Amortization\tof\tprior\tservice\tcost | 245 | 278 | 141 | 87 | 89 | 24 |
| Recognized\tnet\t(gain)/loss | 873 | 135 | 75 | 335 | (55) | 11 |
| Net\tother\tpostretirement\tbenefit\tcost | $16,060 | $15,871 | $12,566 | $4,448 | $4,906 | $1,682 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2001 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $4,969 | $3,606 | $2,707 | $1,302 | $739 | $1,094 |
| Interest\tcost\ton\tAPBO | 8,551 | 8,911 | 5,527 | 2,816 | 3,158 | 907 |
| Expected\treturn\ton\tassets | (3,218) | (4,104) | - | (1,933) | (1,832) | (959) |
| Amortization\tof\ttransition\nobligation | 3,954 | 5,803 | 2,971 | 1,502 | 2,678 | 220 |
| Amortization\tof\tprior\tservice\tcost | 245 | 278 | 141 | 87 | 89 | 24 |
| Recognized\tnet\t(gain)/loss | 173 | (1,028) | 45 | - | (180) | - |
| Net\tpostretirement\tbenefit\tcost | $14,674 | $13,466 | $11,391 | $3,774 | $4,652 | $1,286 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |
| Balance\tat\t12/31/02 | $164,258 | $167,678 | $107,398 | $53,398 | $54,646 | $21,410 |
| Service\tcost | 6,560 | 5,701 | 3,322 | 1,866 | 948 | 1,553 |
| Interest\tcost | 10,637 | 11,314 | 6,780 | 3,459 | 3,436 | 1,352 |
| Actuarial\tloss | 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\tamendments | (14,561) | (11,479) | (16,862) | (4,659) | (5,146) | (4,260) |
| Plan\tparticipant\tcontributions | 1,905 | 1,663 | 1,126 | 604 | 750 | 78 |
| Curtailment\tloss | 8,849 | 5,496 | 4,830 | 1,081 | 625 | 2,561 |
| Special\ttermination\tbenefits | 794 | 512 | 452 | 73 | 28 | 284 |
| Balance\tat\t12/31/03 | $187,259 | $194,205 | $112,675 | $57,786 | $55,062 | $25,466 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/02 | $49,076 | $50,001 | $\t- | $23,420 | $28,490 | $13,569 |
| Actual\treturn\ton\tplan\tassets | 6,290 | 6,587 | - | 2,979 | 2,614 | 1,475 |
| Employer\tcontributions | (11,523) | (11,411) | (7,816) | (4,040) | (4,761) | (616) |
| Benefits\tpaid | 23,128 | 12,671 | 6,690 | 5,969 | 6,065 | 2,315 |
| Plan\tparticipant\tcontributions | 1,905 | 1,663 | 1,126 | 604 | 750 | 78 |
| Fair\tvalue\tof\tassets\tat\t12/31/03 | $68,876 | $59,511 | $\t- | $28,932 | $33,158 | $16,821 |
| Funded\tstatus | ($118,383) | ($134,694) | ($112,675) | ($28,854) | ($21,904) | ($8,645) |
| Amounts\tnot\tyet\trecognized\nin\tthe\tbalance\tsheet: |  |  |  |  |  |  |
| Unrecognized\ttransition\tobligation | 21,928 | 41,305 | 10,822 | 9,136 | 19,088 | 134 |
| Unrecognized\tprior\tservice\tcost | - | - | - | - | - | (2,040) |
| Unrecognized\tnet\t(gain)/loss | 71,855 | 49,401 | 38,551 | 22,745 | 12,595 | 8,748 |
| Prepaid/(accrued)\tpostretirement | ($24,600) | ($43,988) | ($63,302) | $3,027 | $9,779 | ($1,803) |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |
| Balance\tat\t12/31/01 | $127,935 | $131,251 | $81,699 | $41,796 | $45,984 | $15,003 |
| Service\tcost | 5,429 | 4,153 | 3,137 | 1,513 | 889 | 1,300 |
| Interest\tcost | 9,448 | 9,734 | 6,242 | 3,099 | 3,264 | 1,150 |
| Actuarial\tloss | 29,801 | 31,486 | 23,007 | 9,521 | 8,088 | 4,538 |
| Benefits\tpaid | (8,355) | (8,946) | (6,687) | (2,531) | (3,579) | (581) |
| Balance\tat\t12/31/02 | $164,258 | $167,678 | $107,398 | $53,398 | $54,646 | $21,410 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/01 | $40,333 | $48,443 | $\t- | $22,855 | $27,760 | $12,551 |
| Actual\treturn\ton\tplan\tassets | (4,235) | (3,098) | - | (1,633) | (1,286) | (191) |
| Employer\tcontributions | 21,333 | 13,602 | 6,687 | 4,729 | 5,595 | 1,790 |
| Benefits\tpaid | (8,355) | (8,946) | (6,687) | (2,531) | (3,579) | (581) |
| Fair\tvalue\tof\tassets\tat\t12/31/02 | $49,076 | $50,001 | $\t- | $23,420 | $28,490 | $13,569 |
| Funded\tstatus | ($115,182) | ($117,677) | ($107,398) | ($29,978) | ($26,156) | ($7,841) |
| Amounts\tnot\tyet\trecognized\nin\tthe\tbalance\tsheet: |  |  |  |  |  |  |
| Unrecognized\ttransition | 39,528 | 58,035 | 29,720 | 15,019 | 26,793 | 2,233 |
| obligation |  |  |  |  |  |  |
| Unrecognized\tprior\tservice\tcost | 858 | 1,024 | 495 | 306 | 313 | 79 |
| Unrecognized\tnet\t(gain)/loss | 56,443 | 28,483 | 26,602 | 18,694 | 9,138 | 6,381 |
| Prepaid/(accrued) | ($18,353) | ($30,135) | ($50,581) | $4,041 | $10,088 | $852 |

| Domestic	Equity	Securities | 56% | 50% | 37% | 34% |
| :--- | :--- | :--- | :--- | :--- |
| International\tEquity\tSecurities | 14% | 10% | 0% | 1% |
| Fixed\tIncome\tSecurities | 28% | 37% | 60% | 64% |
| Other | 2% | 3% | 3% | 3% |

The	optimization	analysis	utilized	in	Entergy's	latest	study	produced	the	following	approved	asset	class	target	allocations.	A	new	study	has	been	recently completed	and	will	be	implemented	during	2004.

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

The	accumulated	benefit	obligation	for	the	domestic	utility	companies	and	System	Entergy	as	December	31,	2003	and	2002	was:

|  | 2003 | 2002 |
| :--- | :--- | :--- |
|  | (In\tThousands) |  |
| Entergy\tArkansas | $509,382 | $304,274 |
| Entergy\tGulf\tStates | $426,320 | $308,609 |
| Entergy\tLouisiana | $309,066 | $273,734 |
| Entergy\tMississippi | $174,245 | $108,762 |
| Entergy\tNew\tOrleans | $59,610 | $51,046 |
| System\tEnergy | $64,661 | $35,271 |

| Pension	Benefits<br>Payments | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |  |
| 2004 | $28,375 | $25,495 | $19,227 | $10,601 | $2,545 | $367 |
| 2005 | $28,885 | $25,767 | $19,369 | $10,768 | $2,564 | $380 |
| 2006 | $29,560 | $26,136 | $19,565 | $10,990 | $2,590 | $396 |
| 2007 | $30,530 | $26,691 | $19,876 | $11,312 | $2,631 | $419 |
| 2008 | $31,726 | $27,454 | $20,345 | $11,719 | $2,693 | $445 |
| 2009\t-\t2013 | $189,162 | $157,145 | $114,128 | $69,046 | $15,110 | $2,868 |

| Other |  |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Postretirement\nBenefits\tPayments | Entergy\nArkansas | Entergy\nGulf\tStates | Entergy\nLouisiana | Entergy\nMississippi | Entergy\nNew\tOrleans | System\nEnergy |
|  |  |  | (In\tThousands) |  |  |  |
| Year(s) |  |  |  |  |  |  |
| 2004 | $11,890 | $12,024 | $7,696 | $3,184 | $4,249 | $1,240 |
| 2005 | $12,508 | $12,763 | $8,081 | $3,488 | $4,418 | $1,350 |
| 2006 | $12,616 | $12,858 | $8,066 | $3,562 | $4,235 | $1,439 |
| 2007 | $13,093 | $13,446 | $8,284 | $3,814 | $4,326 | $1,499 |
| 2008 | $13,390 | $13,873 | $8,430 | $4,046 | $4,387 | $1,547 |
| 2009\t-\t2013 | $73,544 | $75,064 | $44,186 | $23,206 | $22,642 | $9,617 |

The	domestic	utility	companies	and	System	Energy	expect	to	contribute	the	following	to	the	pension	and	other	postretirement	plans	in	2004:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Pension\nContributions | $5,342 | $37 | $8,630 | $2,989 | $4,678 | $5,369 |
| Other\tPostretirement\nContributions | $20,573 | $13,997 | $7,696 | $5,213 | $4,604 | $4,859 |

The	change	in	the	minimum	pension	liability	had	no	effect	on	other	comprehensive	income	at	the	domestic	utility	companies	and	System	Energy	in	2003	or 2002.	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	2003	and	2002:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Increase\t(Decrease) | Increase\t(Decrease) |  |  |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Increase\t(decrease)\tin\nregulatory\tassets: |  |  |  |  |  |  |
| 2003 | $22,600 | - | ($38,755) | ($3.446) | $7,395 | $7,061 |
| 2002 | $19,056 | - | $38,755 | $9,810 | $2,971 | - |

The	assumed	health	care	cost	trend	rate	used	in	measuring	the	APBO	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.	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	2009	and	beyond.	A	one	percentage	point	change	in	the	assumed	health	care	cost	trend	rate	for	2003	would	have	the	following	effects:

|  | 1	Percentage	Point	Increase | 1	Percentage	Point	Increase | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
| 2003 | Increase\tin\tthe\nAPBO | Increase\nin\tthe\tsum\tof\nservice\tcost\tand\ninterest\tcost | Decrease\tin\tthe\nAPBO | Decrease\nin\tthe\tsum\tof\nservice\tcost\tand\ninterest\tcost |
|  |  | (In\tThousands) |  |  |
| Entergy\tArkansas | $19,657 | $2,474 | ($16,458) | ($2,010) |
| Entergy\tGulf\tStates | $21,091 | $2,511 | ($17,665) | ($2,038) |
| Entergy\tLouisiana | $11,274 | $1,370 | ($9,471) | ($1,118) |
| Entergy\tMississippi | $5,945 | $733 | ($4,984) | ($598) |
| Entergy\tNew\tOrleans | $4,606 | $491 | ($3,939) | ($406) |
| System\tEnergy | $3,254 | $504 | ($2,678) | ($401) |

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate | 6.25% | 6.75% | 7.50% |
| Weighted\taverage\trate\tof\nincrease |  |  |  |
| \t\tin\tfuture\tcompensation\tlevels | 3.25% | 3.25% | 4.60% |

| Taxable	assets | 5.50% | 5.50% | 5.50% |
| :--- | :--- | :--- | :--- |
| \t\t\t\tNon-taxable\tassets | 8.75% | 8.75% | 9.00% |

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

|  | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| \t\tPension | 6.75% | 7.50% | 7.50% |
| \t\tOther\tpostretirement | 6.71% | 7.50% | 7.50% |
| Weighted\taverage\trate\tof\nincrease |  |  |  |
| \t\tin\tfuture\tcompensation\tlevels | 3.25% | 4.60% | 4.60% |
| Expected\tlong-term\trate\tof |  |  |  |
| \t\treturn\ton\tplan\tassets: |  |  |  |
| \t\t\t\tTaxable\tassets | 5.50% | 5.50% | 5.50% |
| \t\t\t\tNon-taxable\tassets | 8.75% | 9.00% | 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	and	its	SFAS	106	transition	obligations	are	being	amortized	over	20	years.

During	2003,	the	domestic	utility	companies	and	System	Energy	offered	a	voluntary	severance	program	to	certain	groups	of	employees.	As	a	result	of	this program,	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.

# NOTE	12.	RISK	MANAGEMENT	AND	DERIVATIVES

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.	Cash	flow	hedges	with	unrealized	gains	of	approximately	$6.5	million at	December	31,	2003	are	scheduled	to	mature	during	2004.	Gains	totaling	approximately	$3.3	million	were	realized	during	2003	on	the	maturity	of	cash flow	hedges.	These	unrealized	and	realized	gains	resulted	from	foreign	currency	hedges	related	to	Euro-denominated	nuclear	fuel	acquisition	contracts,	and related	gains	or	losses,	when	realized,	are	included	in	the	capitalized	cost	of	nuclear	fuel.	The	maximum	length	of	time	over	which	Entergy	Gulf	States	is

currently	hedging	the	variability	in	future	cash	flows	for	forecasted	transactions	(excluding	interest	rate	swaps)	at	December	31,	2003	is	approximately seven	months.	The	ineffective	portion	of	the	change	in	the	value	of	Entergy	Gulf	States'	cash	flow	hedges	during	2003	was	insignificant.

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

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

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

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

The	tables	below	contain	the	various	affiliate	transactions	of	the	domestic	utility	companies,	System	Energy,	and	other	Entergy	affiliates.

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |  |
| 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 |
| 2001 | $250.2 | $75.2 | $26.1 | $118.3 | $10.0 | $535.0 |

# Intercompany	Operating	Expenses

(2) Includes	power	purchased	from	Entergy	Power	and	RS	Cogen	LLC	in	2003	of	$5.9	million	and $19.1	million,	respectively.

# Operating	Expenses	Paid	or	Reimbursed	to	Entergy	Operations

|  | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | \t Louisiana | Energy |
|  |  | (In\tMillions) |  |  |
| 2003 | $171.4 | $118.8 | $121.6 | $106.4 |
| 2002 | $172.1 | $110.1 | $112.4 | $97.3 |
| 2001 | $141.4 | $102.7 | $104.6 | $75.8 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tMillions) |  |  |  |
| 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 |
| 2001 | $0.8 | $0.5 | $2.2 | $0.5 | $0.3 | $6.3 |

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	2003	and	2002	were:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2003: |  |  |  |  |  |  |
| First\tQuarter | $362,749 | $584,354 | $462,361 | $227,369 | $140,907 | $141,985 |
| Second\tQuarter | 394,884 | 700,635 | 569,580 | 261,899 | 154,065 | 144,764 |
| Third\tQuarter | 469,925 | 777,182 | 646,503 | 309,739 | 203,751 | 141,239 |
| Fourth\tQuarter | 362,112 | 577,566 | 487,126 | 236,353 | 155,293 | 155,832 |
| 2002: |  |  |  |  |  |  |
| First\tQuarter | $377,823 | $463,904 | $369,963 | $191,690 | $102,947 | $142,330 |
| Second\tQuarter | 367,926 | 567,563 | 483,389 | 261,743 | 121,422 | 142,892 |
| Third\tQuarter | 474,873 | 648,849 | 528,052 | 316,745 | 157,417 | 156,930 |
| Fourth\tQuarter | 340,488 | 503,563 | 433,948 | 220,917 | 126,088 | 160,334 |

# Operating	Income	(Loss)

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| 2003: |  |  |  |  |  |  |
| First\tQuarter | $67,130 | $75,693 | $89,362 | $30,096 | $(1,887) | $55,739 |
| Second\tQuarter | 92,939 | 99,150 | 91,304 | 44,625 | 17,311 | 54,029 |
| Third\tQuarter | 135,790 | 146,063 | 108,232 | 53,173 | 28,230 | 65,791 |
| Fourth\tQuarter | 1,330 | (13,136) | 13,325 | 13,753 | (15,736) | 62,853 |
| 2002: |  |  |  |  |  |  |
| First\tQuarter | $55,731 | $74,486 | $75,888 | $16,928 | $(1,675) | $59,940 |
| Second\tQuarter | 69,394 | 133,741 | 134,481 | 29,253 | 13,151 | 59,122 |
| Third\tQuarter | 138,887 | 125,543 | 108,837 | 50,451 | 19,283 | 65,014 |
| Fourth\tQuarter | 38,197 | 17,960 | (2,564) | 10,134 | (13,409) | 65,058 |

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| 2003: |  |  |  |  |  |  |
| First\tQuarter | $27,145 | $11,792(a) | $43,807 | $12,316 | $(4,327) | $23,735 |
| Second\tQuarter | 47,537 | (20,124) | 45,713 | 22,350 | 9,580 | 22,820 |
| Third\tQuarter | 69,319 | 82,283 | 57,863 | 25,804 | 14,118 | 28,515 |
| Fourth\tQuarter | (17,992) | (31,389) | (1,229) | 6,588 | (11,512) | 30,933 |
| 2002: |  |  |  |  |  |  |
| First\tQuarter | $22,838 | $28,038 | $29,494 | $5,829 | $(3,940) | $26,727 |
| Second\tQuarter | 19,247 | 65,236 | 75,845 | 12,752 | 3,199 | 25,250 |
| Third\tQuarter | 74,664 | 64,489 | 50,063 | 26,213 | 9,307 | 25,640 |
| Fourth\tQuarter | 18,894 | 16,315 | (10,693) | 7,614 | (8,796) | 25,735 |

(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	2003	are	discussed	in	Part	I.	Item	1.	-	Business	under	the	sections	titled	"Rate	Matters",	"Environmental	Regulation", and	"Litigation"	in	this	report.

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

During	the	fourth	quarter	of	2003,	no	matters	were	submitted	to	a	vote	of	the	security	holders	of	Entergy	Corporation.

# DIRECTORS	AND	EXECUTIVE	OFFICERS	OF	ENTERGY	CORPORATION

# Directors

Information	required	by	this	item	concerning	directors	of	Entergy	Corporation	is	set	forth	under	the	heading	"Proposal	1--Election	of	Directors"	contained	in

the	Proxy	Statement	of	Entergy	Corporation,	(the	"Proxy	Statement"),	to	be	filed	in	connection	with	its	Annual	Meeting	of	Stockholders	to	be	held	May	14, 2004,	("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.

(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.

(b) Mr.	Hintz	will	retire	effective	April	2004.

(c) Mr.	 Wilder	 resigned	 effective	 February	 2004.	Leo	 Denault	 has	 been	 named	 Executive	 Vice President	and	Chief	Financial	Officer.

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

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	27,	2004	was	$59.29.	The	high	and	low	prices	of	Entergy	Corporation's	common	stock	for	each	quarterly period	in	2003	and	2002	were	as	follows:

| First | 49.55 | 42.26 | 43.88 | 38.25 |
| :--- | :--- | :--- | :--- | :--- |
| Second | 54.38 | 45.90 | 46.85 | 41.05 |
| Third | 54.99 | 47.75 | 44.95 | 32.12 |
| Fourth | 57.24 | 51.06 | 46.42 | 36.80 |

Consecutive	quarterly	cash	dividends	on	common	stock	were	paid	to	stockholders	of	Entergy	Corporation	in	2003	and	2002.	In	2003,	dividends	of	$0.35	per share	were	paid	in	the	first	and	second	quarters,	and	dividends	of	$0.45	per	share	was	paid	in	the	third	and	fourth	quarters.	In	2002,	dividends	of	$0.33	per share	were	paid	in	the	first	three	quarters,	and	a	dividend	of	$0.35	per	share	was	paid	in	the	fourth	quarter.

As	of	February	27,	2004,	there	were	54,304	stockholders	of	record	of	Entergy	Corporation.

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

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

There	is	no	market	for	the	common	stock	of	Entergy	Corporation's	wholly	owned	subsidiaries.	Cash	dividends	on	common	stock	paid	by	the	domestic	utility companies	and	System	Energy	to	Entergy	Corporation	during	2003	and	2002,	were	as	follows:

| Entergy	Arkansas | $69.6 | $125.9 |
| :--- | :--- | :--- |
| Entergy\tGulf\tStates | $68.1 | $91.2 |
| Entergy\tLouisiana | $145.5 | $271.4 |
| Entergy\tMississippi | $31.7 | $27.3 |
| Entergy\tNew\tOrleans | $3.0 | $0.8 |
| System\tEnergy | $105.0 | $101.8 |

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

Item	6.	Selected	Financial	Data

# Refer	to	"SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON	OF	ENTERGY	CORPORATION	AND	SUBSIDIARIES,	ENTERGY

# ARKANSAS,	 INC.,	 ENTERGY	 GULF	 STATES,	 INC., 	 ENTERGY	 LOUISIANA,	 INC.,	 ENTERGY	 MISSISSIPPI,	 INC.,	 ENTERGY	 NEW

ORLEANS,	INC.,	and	SYSTEM	ENERGY	RESOURCES,	INC."	which	follow	each	company's	financial	statements	in	this	report,	for	information	with respect	to	selected	financial	data	and	certain	operating	statistics.

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

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

# Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk

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

# Item	8.	Financial	Statements	and	Supplementary	Data

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

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

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

As	of	December	31,	2003,	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	specified	in	Securities	and	Exchange	Commission	rules	and	forms.

# 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.

E.	Renae	Conley

Director	of	Entergy	Gulf	States	and	Entergy	Louisiana

President	and	Chief	Executive	Officer	-	LA	of	Entergy	Gulf	States	and	Entergy	Louisiana

# New	Orleans,	LA

# Theodore	Bunting See	information	under	the	Entergy	Arkansas	Officers	Section	above.

# E.	Renae	Conley See	information	under	the	Entergy	Gulf	States	Directors	Section	above.

# Officers

Steven	C.	McNeal See	information	under	the	Entergy	Corporation	Officers	Section	in	Part	I.

# Carolyn	C.	Shanks See	information	under	the	Entergy	Mississippi	Directors	Section	above.

# 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.

C.	John	Wilder	(d) See	information	under	the	Entergy	Corporation	Officers	Section	in	Part	I.

Directors Gary	J.	Taylor 50 Director,	President	and	Chief	Executive	Officer	of	System	Energy 2003-Present

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

Gary	J.	Taylor See	information	under	the	System	Energy	Directors	Section	above.

C.	John	Wilder	(e) See	information	under	the	Entergy	Corporation	Officers	Section	in	Part	I.

(a) Effective	January	2004,	Theodore	Bunting	was	named	Vice	President	and	Chief	Financial	Officer -	Nuclear	Operations.	Effective	January	2004,	Jay	A.	Lewis	was	named	Vice	President	and	Chief Financial	 Officer	 of	 Entergy	 Arkansas,	 Entergy	 Gulf	 States,	 Entergy	 Louisiana,	 Entergy Mississippi,	and	Entergy	New	Orleans.

(b) Effective	January	2004,	Randall	Helmick	was	named	Vice	President,	Customer	Service	Support for	Entergy	Services,	Inc.

(c) Effective	January	2004,	Wade	Stewart	resigned	from	his	position	of	Vice	President,	Regulatory Affairs.

(d) C.	 John	 Wilder	 resigned	 effective	 February	 2004.	Leo	 Denault	 was	 named	 Executive	 Vice President	and	Chief	Financial	Officer	of	Entergy	Corporation,	and	has	replaced	Mr.	Wilder	as	a director	for	each	registrant	listed	above.	Theodore	Bunting	was	named	Vice	President	and	Chief Financial	Officer	of	System	Energy	Resources.

(e) Elaine	Coleman	will	retire	from	her	position	of	Vice	President,	External	Affairs	in	April	2004.

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:

Kathleen	A.	Murphy	(Chairman) George	W.	Davis Maureen	S.	Bateman Dennis	H.	Reilley Bismark	A.	Steinhagen

# Claiborne	P.	Deming

# Steven	V.	Wilkinson

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.	Entergy	has	adopted	a	Code	of	Ethics	for	Principal	Executive	Officer	and	Senior	Financial	Officers. Entergy	also	operates	under	an	omnibus	code	of	ethics	and	business	conduct	called	the	Code	of	Entegrity.	All	employees	are	required	to	abide	by	the	Code. Non-bargaining	employees	are	required	to	acknowledge	annually	that	they	understand	and	abide	by	the	Code.	The	Code	of	Entegrity	is	available	through Entergy's	website	(www.entergy.com)	or	upon	written	request.

# 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	14,	2004,	under	the	heading	"Section	16(a)	Beneficial	Ownership Reporting	Compliance",	which	information	is	incorporated	herein	by	reference.

# Item	11.	Executive	Compensation

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,	2003,	and an	additional	executive	officer	who	would	have	been	included	in	the	table	but	he	retired	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	2003.	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.

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.

| Name | Year | Salary | Annual	Compensation<br>Bonus | Other<br>Annual<br>Comp. | Restricted<br>Stock<br>Awards | Awards<br>Securities<br>Underlying<br>Options | Payouts<br>(a)<br>LTIP | (b)	All<br>Other<br>Comp. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | Payouts |  |
| E.\tRenae\tConley | 2003 | $334,453 | $200,000 | $31,087 | (c) | 33,092\tshares | $460,088 | $15,413 |
| CEO-Entergy\tLouisiana | 2002 | 321,500 | 320,000 | 88,946 | (c) | 40,000 | 331,114 | 15,211 |
| CEO-LA-Entergy\tGulf\tStates | 2001 | 308,769 | 486,186 | 46,240 | (c) | 34,600 | - | 10,742 |
| Joseph\tF.\tDomino | 2003 | $265,626 | $200,765 | $46,480 | (c) | 10,500\tshares | $190,170 | $11,912 |
| CEO-TX-Entergy\tGulf\tStates | 2002 | 255,295 | 210,070 | 63,361 | (c) | 22,000 | 153,202 | 13,568 |
|  | 2001 | 245,384 | 292,583 | 48,254 | (c) | 14,800 | - | 7,150 |
| Donald\tC.\tHintz | 2003 | $660,793 | $605,115 | $80,295 | (c) | 140,000\tshares | $1,748,333 | $33,797 |
|  | 2002 | 629,423 | 754,800 | 206,963 | (c) | 160,000 | 1,408,470 | 34,318 |
|  | 2001 | 599,423 | 779,000 | 198,321 | (c) | 160,000 | - | 21,605 |
| Jerry\tD.\tJackson\t(e) | 2003 | $173,362 | $96,608 | $171,278 | (c) | 10,000\tshares | $582,778 | $6,444,103 |
|  | 2002 | 491,281 | 513,150 | 19,261 | (c) | 75,898 | 627,634 | 17,600 |
|  | 2001 | 475,345 | 576,382 | 19,646 | (c) | 80,000 | - | 17,378 |

| J.	Wayne	Leonard | 2003 | $1,038,461 | $1,197,800 | $26,152 | (c) | 195,000	shares | $2,944,5600 | $73,639 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2002 | 962,500 | 1,450,400 | 5,257 | (c) | 330,600 | 2,372,1600 | 20,517 |
|  | 2001 | 897,500 | 1,684,800 | 3,709 | $7,400,000(c)(d) | 330,600 | - | - |
| Hugh\tT.\tMcDonald | 2003 | $264,201 | $195,000 | $32,276 | (c) | 21,199\tshares | $190,170 | $12,134 |
| CEO-Entergy\tArkansas | 2002 | 247,373 | 185,000 | 56,295 | (c) | 22,000 | 182,854 | 14,867 |
|  | 2001 | 231,335 | 333,078 | 118,502 | (c) | 14,800 | - | 18,664 |
| Daniel\tF.\tPacker | 2003 | $253,628 | $190,000 | $58,519 | (c) | 8,000\tshares | $190,170 | $3,204 |
| CEO-Entergy\tNew\tOrleans | 2002 | 244,776 | 95,000 | 17,705 | (c) | 20,000 | 153,202 | 13,469 |
|  | 2001 | 228,209 | 262,881 | 15,410 | (c) | 14,800 | - | 7,055 |
| Carolyn\tC.\tShanks | 2003 | $263,758 | $195,000 | $92,825 | $152,160\t(c)(d) | 14,000\tshares | $190,170 | $12,132 |
| CEO-Entergy\tMississippi | 2002 | 252,478 | 200,000 | 77,460 | (c) | 20,000 | 153,202 | 14,138 |
|  | 2001 | 241,085 | 287,672 | 17,140 | (c) | 14,800 | - | 7,206 |
| Richard\tJ.\tSmith | 2003 | $473,019 | $380,867 | $64,371 | (c) | 72,777\tshares | $674,795 | $23,128 |
|  | 2002 | 443,269 | 466,200 | 28,862 | (c) | 95,000 | 454,664 | 20,699 |
|  | 2001 | 368,269 | 510,000 | 33,604 | (c) | 50,000 | - | 12,654 |
| Gary\tJ.\tTaylor | 2003 | $394,615 | $316,400 | $78,575 | (c) | 26,900\tshares | $539,836 | $7,240 |
| CEO-System\tEnergy | 2002 | 342,788 | 277,925 | 48,892 | (c) | 34,600 | 336,056 | 16,156 |
|  | 2001 | 319,231 | 389,513 | 46,979 | (c) | 40,000 | - | 11,857 |
| C.\tJohn\tWilder | 2003 | $568,731 | $461,153 | $153,373 | (c) | 80,000\tshares | $779,082 | $51,614 |
|  | 2002 | 521,923 | 549,080 | 156,683 | (c) | 131,366 | 627,634 | 24,459 |
|  | 2001 | 493,128 | 600,000 | 158,059 | (c) | 87,700 | - | 16,284 |
| Jerry\tW.\tYelverton\t(e) | 2003 | $166,849 | $91,718 | $170,607 | (c) | 10,000\tshares | $582,778 | $6,323,392 |
| CEO-System\tEnergy | 2002 | 464,798 | 658,350 | 180,186 | (c) | 85,000 | 627,634 | 28,455 |
|  | 2001 | 443,269 | 540,000 | 145,389 | (c) | 65,000 | - | 14,697 |

(a) Amounts	include	the	value	of	restricted	units	that	vested	in	2003	and	2002	(see	note	(c)	below) under	Entergy's	Equity	Ownership	Plan.

(b) Includes	the	following:

(1) 2003	benefit	accruals	under	the	Defined	Contribution	Restoration	Plan	as	follows:	Ms.

(2) 2003	employer	contributions	to	the	System	Savings	Plan	as	follows:	Ms.	Conley	$8,909;

(d) In	addition	to	the	performance	units	granted	under	the	Equity	Ownership	Plan,	in	January	2001, Mr.	Leonard	was	granted	200,000	restricted	units.	50,000	of	the	restricted	units	vest	on	each	of December	31,	2001,	December	31,	2002,	December	31,	2003	and	December	31,	2004,	based	on continued	 service	 with	 Entergy.	Accumulated	 dividends	 will	 not	 be	 paid	 on	 Mr.	 Leonard's restricted	units	when	vested.	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	these	individuals	may realize	is	dependent	upon	both	the	number	of	units	that	vest	and	the	future	market	price	of Entergy	common	stock.

(e) Mr.	Jackson	and	Mr.	Yelverton	retired	in	2003.

# Option	Grants	in	2003

The	following	table	summarizes	option	grants	during	2003	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.

|  |  | Individual	Grants |  |  | Value |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Number\tof | %\tof\tTotal |  |  | at\tAssumed\tAnnual |  |
|  | Securities | Options |  |  | Rates\tof\tStock |  |
|  | Underlying | Granted\tto | Exercise |  | Price\tAppreciation |  |
|  | Options | Employees | Price\t(per | Expiration | for\tOption\tTerm(b) |  |
| Name | Granted\t(a) | in\t2003 | share)\t(a) | Date | 5% | 10% |
| E.\tRenae\tConley | 24,000 | 0.8% | $44.45 | 1/30/13 | $670,905 | $1,700,204 |
|  | 9,092\t(c) | 0.3% | 51.50 | 1/27/10 | 174,011 | 399,833 |
| Joseph\tF.\tDomino | 10,500 | 0.4% | 44.45 | 1/30/13 | 293,521 | 743,839 |
| Donald\tC.\tHintz | 80,000 | 2.7% | 44.45 | 1/30/13 | 2,236,349 | 5,667,348 |
|  | 20,000\t(c) | 0.7% | 48.74 | 1/27/10 | 377,905 | 873,916 |
|  | 20,000\t(c) | 0.7% | 48.65 | 1/27/10 | 377,027 | 871,821 |
|  | 20,000\t(c) | 0.7% | 48.65 | 1/27/10 | 376,125 | 869,414 |
| Jerry\tD.\tJackson | 10,000 | 0.3% | 44.45 | 1/30/13 | 279,544 | 708,419 |
| J.\tWayne\tLeonard | 195,000 | 6.6% | 44.45 | 1/30/13 | 5,451,101 | 13,814,161 |
| Hugh\tT.\tMcDonald | 12,000 | 0.4% | 44.45 | 1/30/13 | 335,452 | 850,102 |
|  | 9,199\t(c) | 0.3% | 45.50 | 1/27/10 | 168,037 | 390,725 |
| Daniel\tF.\tPacker | 8,000 | 0.3% | 44.45 | 1/30/13 | 223,635 | 566,735 |
| Carolyn\tC.\tShanks | 14,000 | 0.5% | 44.45 | 1/30/13 | 391,361 | 991,786 |
| Richard\tJ.\tSmith | 50,000 | 1.7% | 44.45 | 1/30/13 | 1,397,718 | 3,542,093 |
|  | 7,560\t(c) | 0.3% | 51.50 | 8/30/09 | 133,390 | 302,926 |
|  | 7,577\t(c) | 0.3% | 51.50 | 1/27/10 | 144,801 | 332,642 |
|  | 7,640\t(c) | 0.3% | 51.50 | 1/25/11 | 172,297 | 406,413 |
| Gary\tJ.\tTaylor | 26,900 | 0.9% | 44.45 | 1/30/13 | 751,972 | 1,905,646 |
| C.\tJohn\tWilder | 60,000 | 2.0% | 44.45 | 1/30/13 | 1,677,262 | 4,250,511 |
|  | 1,689\t(c) | 0.1% | 52.45 | 1/28/09 | 26,950 | 60,249 |
|  | 13,056\t(c) | 0.4% | 52.45 | 1/27/10 | 252,857 | 580,444 |
|  | 5,255\t(c) | 0.2% | 52.45 | 1/25/11 | 120,538 | 284,260 |
| Jerry\tW.\tYelverton | 10,000 | 0.3% | 44.45 | 1/30/13 | 279,544 | 708,419 |

(a) Options	were	granted	on	January	30,	2003,	pursuant	to	the	Equity	Ownership	Plan.	All	options granted	on	this	date	have	an	exercise	price	equal	to	the	closing	price	of	Entergy	common	stock on	the	New	York	Stock	Exchange	Composite	Transactions	on	January	30,	2003.	 These	options will	vest	in	equal	increments,	annually,	over	a	three-year	period	beginning	in	2004.

(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	2003,	Ms.	Conley,	Mr.	Hintz,	Mr.	McDonald,	Mr.	Smith	and	Mr.	Wilder	converted presently	exercisable	stock	options	into	an	equivalent	total	of	phantom	stock	units	and	reload stock	options.	They	accomplished	this	by	exercising	stock	options,	paying	the	exercise	price	for these	 options	 by	 surrendering	 shares	 of	 Entergy	 stock,	 and	 deferring	 the	 taxable	 gain	 into phantom	stock	units.	Additional	options,	as	indicated	above,	were	granted	pursuant	to	the	reload feature	 of	 this	 "stock	 for	 stock"	 exercise	 method.	Under	 the	 reload	 mechanism,	 eligible participants	 are	 granted	 an	 additional	 number	 of	 options	 equal	 to	 the	 number	 of	 shares surrendered	to	pay	the	exercise	price.	The	reloaded	stock	options	vest	immediately	and	have	an exercise	price	equal	to	the	price	of	Entergy	common	stock	on	the	New	York	Stock	Exchange Composite	Transactions	on	the	date	of	exercise	of	the	original	options.	The	reloaded	options retain	 the	 original	 grant's	 expiration	 date.	The	 reload	 feature	 was	 removed	 from	 the	 Equity Ownership	Plan	as	approved	by	the	Stockholders	in	May	2003.	Reloads	are	no	longer	available for	options	granted	after	February	13,	2003.

# Aggregated	Option	Exercises	in	2003	and	December	31,	2003	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.

| Name | Shares	Acquired<br>on	Exercise | Value<br>Realized	(a) | Securities	Underlying<br>Unexercised	Options<br>as	of	December	31,	2003<br>Exercisable | Unexercisable | Value	of	Unexercised<br>In-the-Money	Options<br>as	of	December	31,	2003	(b)<br>Exercisable | Unexercisable |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| E.\tRenae\tConley | 20,000 | $570,000 | 52,991 | 62,201 | $939,374 | $948,238 |
| Joseph\tF.\tDomino | 21,500 | 614,000 | 30,686 | 30,101 | 678,569 | 458,920 |
| Donald\tC.\tHintz | 171,912 | 4,206,564 | 477,587 | 280,001 | 10,514,314 | 4,802,652 |
| Jerry\tD.\tJackson | 219,296 | 2,754,258 | 28,031 | - | 324,371 | - |
| J.\tWayne\tLeonard | - | - | 916,200 | 525,600 | 24,355,606 | 8,093,902 |
| Hugh\tT.\tMcDonald | 31,101 | 715,185 | 26,398 | 31,601 | 418,808 | 477,940 |
| Daniel\tF.\tPacker | 6,667 | 146,807 | 16,532 | 26,268 | 301,526 | 406,638 |
| Carolyn\tC.\tShanks | - | - | 23,199 | 32,268 | 529,070 | 482,718 |
| Richard\tJ.\tSmith | 40,108 | 905,791 | 93,871 | 113,334 | 1,238,675 | 1,690,045 |
| Gary\tJ.\tTaylor | 34,600 | 1,017,886 | 38,199 | 63,301 | 714,856 | 965,660 |
| C.\tJohn\tWilder | 39,561 | 1,041,151 | 143,963 | 147,701 | 2,128,329 | 2,252,011 |
| Jerry\tW.\tYelverton | 147,968 | 1,691,998 | 10,000 | - | 126,800 | - |

(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,	2003,	and	the	option	exercise	price.

# Long-Term	Incentive	Plan	Awards	in	2003

The	following	table	summarizes	the	awards	of	performance	units	(equivalent	to	shares	of	Entergy	common	stock)	granted	under	the	Equity	Ownership	Plan in	2003	to	the	Named	Executive	Officers.

| E.	Renae	Conley | 11,600 | 1/1/03-12/31/05 | 1,500 | 5,800 | 11,600 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Joseph\tF.\tDomino | 6,000 | 1/1/03-12/31/05 | 800 | 3,000 | 6,000 |
| Donald\tC.\tHintz | 49,400 | 1/1/03-12/31/05 | 6,200 | 24,700 | 49,400 |
| Jerry\tD.\tJackson | 2,000 | 1/1/03-12/31/05 | 300 | 1,042 | 2,000 |
| J.\tWayne\tLeonard | 80,400 | 1/1/03-12/31/05 | 10,100 | 40,200 | 80,400 |
| Hugh\tT.\tMcDonald | 6,000 | 1/1/03-12/31/05 | 800 | 3,000 | 6,000 |
| Daniel\tF.\tPacker | 6,000 | 1/1/03-12/31/05 | 800 | 3,000 | 6,000 |
| Carolyn\tC.\tShanks | 6,000 | 1/1/03-12/31/05 | 800 | 3,000 | 6,000 |
| Richard\tJ.\tSmith | 25,000 | 1/1/03-12/31/05 | 3,200 | 12,500 | 25,000 |
| Gary\tJ.\tTaylor | 23,800 | 1/1/03-12/31/05 | 3,000 | 11,942 | 23,800 |
| C.\tJohn\tWilder | 25,000 | 1/1/03-12/31/05 | 3,200 | 12,500 | 25,000 |
| Jerry\tW.\tYelverton | 2,000 | 1/1/03-12/31/05 | 300 | 1,042 | 2,000 |

(a) Performance	units	awarded	will	vest	at	the	end	of	a	three-year	period,	subject	to	the	attainment of	approved	performance	goals	for	Entergy.	Restrictions	are	lifted	based	upon	the	achievement of	 the	 cumulative	 result	 of	 these	 goals	 for	 the	 performance	 period.	The	 value	 any	 Named Executive	Officer	may	realize	is	dependent	upon	the	number	of	units	that	vest,	the	future	market price	of	Entergy	common	stock,	and	the	dividends	paid	during	the	performance	period.

(b) The	threshold,	target,	and	maximum	levels	correspond	to	the	achievement	of	25%,	100%,	and 200%,	 respectively,	 of	 Equity	 Ownership	 Plan	 goals.	Achievement	of	a	 threshold,	 target,	or maximum	level	would	result	in	the	award	of	the	number	of	units	indicated	in	the	respective column.	Achievement	of	a	level	between	these	three	specified	levels	would	result	in	the	award	of a	number	of	units	calculated	by	means	of	interpolation.

# Pension	Plan	Tables

# Retirement	Income	Plan	Table

| Annual |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Covered |  |  | Years\tof\tService |  |  |
| Compensation | 15 | 20 | 25 | 30 | 35 |
| $100,000 | $22,500 | $30,000 | $37,500 | $45,000 | $52,500 |
| 200,000 | 45,000 | 60,000 | 75,000 | 90,000 | 105,000 |
| 300,000 | 67,500 | 90,000 | 112,500 | 135,000 | 157,500 |
| 400,000 | 90,000 | 120,000 | 150,000 | 180,000 | 210,000 |
| 500,000 | 112,500 | 150,000 | 187,500 | 225,000 | 262,500 |
| 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 |

All	of	the	Named	Executive	Officers	participate	in	a	Retirement	Income	Plan,	a	defined	benefit	plan,	that	provides	a	benefit	for	employees	at	retirement	from Entergy	based	upon	(1)	generally	all	years	of	service	beginning	at	age	21	 through	 termination,	with	a	forty-year	maximum,	multiplied	by	(2)	1.5%, multiplied	by	(3)	the	final	average	compensation.	Final	average	compensation	is	based	on	the	highest	consecutive	60	months	of	covered	compensation	in	the last	120	months	of	service.	The	normal	form	of	benefit	for	a	single	employee	is	a	lifetime	annuity	and	for	a	married	employee	is	a	50%	joint	and	survivor annuity.	Other	actuarially	equivalent	options	are	available	to	each	retiree.	Retirement	benefits	are	not	subject	to	any	deduction	for	Social	Security	or	other offset	amounts.	The	amount	of	the	Named	Executive	Officers'	annual	compensation	covered	by	the	plan	as	of	December	31,	2003,	is	represented	by	the salary	column	in	the	Summary	Compensation	Table	above.

The	credited	years	of	service	under	the	Retirement	Income	Plan,	as	of	December	31,	2003,	for	the	following	Named	Executive	Officers	is	as	follows:	Mr. Domino	30;	Mr.	Leonard	5;	Mr.	McDonald	20;	Mr.	Packer	21;	and	Ms.	Shanks	18.	The	credited	years	of	service	under	the	Retirement	Income	Plan,	as	of December	31,	2003	for	the	following	Named	Executive	Officers,	as	a	result	of	entering	into	supplemental	retirement	agreements,	is	as	follows:	Ms.	Conley 21;	Mr.	Hintz	32;	Mr.	Smith	27;	Mr.	Taylor	22;	and	Mr.	Wilder	20.	Mr.	Jackson	and	Mr.	Yelverton	retired	in	2003	with	23	years	of	service.

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

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

# System	Executive	Retirement	Plan	Table	(1)

| Annual |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Covered |  |  | Years\tof\tService |  |  |
| 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 |
| 1,250,000 | 375,000 | 562,500 | 625,000 | 687,500 | 750,000 |
| 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 |

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

In	1993,	Entergy	Corporation	adopted	the	System	Executive	Retirement	Plan	(SERP).	This	plan	was	amended	in	1998.	Entergy	Arkansas,	Entergy	Gulf States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	are	participating	employers	 in	 the	SERP.	The	SERP	 is	an unfunded	defined	benefit	plan	offered	at	retirement	to	certain	senior	executives,	which	would	currently	include	all	the	Named	Executive	Officers	(except	for

Mr.	Leonard).	Participating	executives	choose,	at	retirement,	between	the	retirement	benefits	paid	under	provisions	of	the	SERP	or	those	payable	under	the Supplemental	Retirement	Plan	or	the	Post-Retirement	Plan	discussed	above.	The	plan	was	amended	in	1998	to	provide	that	covered	pay	is	the	average	of	the highest	three	years	annual	base	pay	and	incentive	awards	earned	by	the	executive	during	the	ten	years	immediately	preceding	his	retirement.	Benefits	paid under	 the	 SERP	 are	 calculated	 by	 multiplying	 the	 covered	 pay	 times	 target	 pay	 replacement	 ratios	 (45%,	 50%,	 or	 55%,	 dependent	 on	 job	 rating	 at retirement)	that	are	attained,	according	to	plan	design,	at	20	years	of	credited	service.	The	target	ratios	are	increased	by	1%	for	each	year	of	service	over	20 years,	up	to	a	maximum	of	30	years	of	service.	In	accordance	with	the	SERP	formula,	the	target	ratios	are	reduced	for	each	year	of	service	below	20	years. The	credited	years	of	service	under	this	plan	are	identical	to	the	years	of	service	for	Named	Executive	Officers	(other	than	Ms.	Conley,	Mr.	Smith,	Mr. Taylor,	and	Mr.	Wilder)	disclosed	above	in	the	section	entitled	"Pension	Plan	Tables-Retirement	Income	Plan	Table".	 Ms.	Conley,	Mr.	Smith,	Mr.	Taylor, and	Mr.	Wilder	have	4	years,	4	years,	13	years,	and	5	years,	respectively,	of	credited	service	under	this	plan.	 Mr.	Jackson	and	Mr.	Yelverton	retired	in	2003 with	30	years	of	credited	service	under	the	plan.

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

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

# Compensation	of	Directors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

termination	occurs	following	completion	of	a	Merger;

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

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

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

Retention	Agreement	with	Mr.	Jackson	-	Mr.	Jackson	retired	from	full-time	active	employment	on	March	31,	2003.	The	retention	agreement	with	Mr. Jackson	provides	that	upon	retirement	in	accordance	with	the	agreement,	Mr.	Jackson:	(a)	will	be	entitled	to	a	subsidized	retirement	benefit	equal	to	the applicable	nonqualified	retirement	benefit	payable	to	Mr.	Jackson	without	reduction	for	early	retirement	("Subsidized	Retirement	Benefit");	and	(b)	may enter	into	a	consulting	arrangement	with	Entergy	through	March	31,	2005,	under	terms	and	conditions	set	forth	in	the	agreement.	Mr.	Jackson	is	entitled	to certain	benefits,	as	described	in	the	agreement,	in	the	event	of	a	change	in	control	(as	defined	in	the	System	Executive	Continuity	Plan)	after	which	Entergy or	its	successor	company	fails	to	honor	Mr.	Jackson's	consulting	arrangement.

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	the	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;

Retention	Agreement	with	Mr.	Wilder	-	Mr.	Wilder	voluntarily	resigned	from	Entergy	employment	effective	February	20,	2004.	The	retention	agreement Mr.	Wilder	previously	entered	into	with	Entergy	provides,	among	other	things,	for	payments	to	be	made	to	him	upon	termination	of	employment	in	certain circumstances	in	connection	with	a	Merger	or	otherwise,	subject	to	the	terms	and	conditions	of	the	agreement.	In	certain	circumstances,	Mr.	Wilder	would be	entitled	to	a	lump	sum	cash	severance	payment	equal	to	three	times	the	sum	of	his	base	salary	and	target	annual	incentive	award	and	a	"gross-up" payment	in	respect	of	any	excise	taxes	he	might	incur.	In	other	circumstances,	as	a	substitute	for	the	above	payment,	Mr.	Wilder	(or	his	beneficiaries)	would be	entitled	to	a	lump	sum	cash	severance	payment	equal	to	four	times	(in	limited	circumstances,	three	times)	the	sum	of	his	base	salary	and	maximum annual	incentive	award	(in	limited	circumstances,	his	target	annual	incentive	award),	a	pro	rata	annual	incentive	award,	additional	years	of	credited	service under	 Entergy's	 supplemental	 retirement	 plan,	 immediate	 vesting	 of	 equity	 awards,	 the	 opportunity	 to	 continue	 to	 be	 employed	 in	 a	 special	 project coordinator	position,	and	a	"gross-up"	payment	in	respect	of	any	excise	taxes	he	might	incur.

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

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

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

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

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

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

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

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

# Personnel	Committee	Interlocks	and	Insider	Participation

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

# Item	12.	Security	Ownership	of	Certain	Beneficial	Owners	and	Management

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

As	of	December	31,	2003,	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:

| Maureen	S.	Bateman* | 2,100 | - | 2,400 |
| :--- | :--- | :--- | :--- |
| W.\tFrank\tBlount* | 8,784 | - | 12,800 |
| George\tW.\tDavis* | 3,300 | - | 4,000 |
| Simon\tD.\tdeBree* | 1,008 | - | 1,600 |
| Claiborne\tP.\tDeming* | 1,100 | - | 800 |
| Frank\tF.\tGallaher** | 8,952 | - | 12,078 |
| Alexis\tHerman* | 300 | - | - |
| Donald\tC.\tHintz** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard*** | 13,268 | 1,201,600 | 50,588 |
| Robert\tv.d.\tLuft* | 23,872 | 312,666 | 8,800 |
| Kathleen\tA.\tMurphy*\t(e) | 2,100 | 1,000 | 2,400 |
| Paul\tW.\tMurrill*\t(d) | 2,826 | - | 13,600 |
| James\tR.\tNichols* | 11,616 | - | 13,600 |
| William\tA.\tPercy,\tII* | 2,350 | - | 2,400 |
| Dennis\tH.\tReilley*\t(d) | 600 | - | 3,200 |
| Richard\tJ.\tSmith** | 786 | 150,538 | 48,675 |
| Wm.\tClifford\tSmith* | 12,248 | - | 16,000 |
| Bismark\tA.\tSteinhagen*\t(e) | 8,824 | 2,623 | 23,200 |
| Gary\tJ.\tTaylor** | 1,161 | 72,032 | 11,720 |
| C.\tJohn\tWilder** | 1,021 | 222,430 | 172,368 |
| Steven\tV.\tWilkinson* | 50 | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 128,471 | 2,985,683 | 671,007 |

Entergy	Corporation Common	Stock Amount	of	Nature	of Beneficial	Ownership	(a)

|  | Sole	Voting |  |  |
| :--- | :--- | :--- | :--- |
|  | and | Other |  |
|  | Investment | Beneficial | Entergy\tCorporation |
| Name | Power | Ownership(b) | Stock\tEquivalent\tUnits |
|  |  |  | (c) |
| Entergy\tArkansas |  |  |  |
| Donald\tC\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard** | 13,268 | 1,201,600 | 50,588 |
| Hugh\tT.\tMcDonald*** | 4,436 | 42,665 | 25,110 |
| Richard\tJ.\tSmith*** | 786 | 150,538 | 48,675 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 46,952 | 2,602,814 | 545,262 |
| Entergy\tGulf\tStates |  |  |  |
| E.\tRenae\tConley*** | 1,659 | 85,858 | 37,730 |
| Joseph\tF.\tDomino*** | 12,373 | 46,453 | 21,316 |
| Donald\tC.\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard** | 13,268 | 1,201,600 | 50,588 |
| Richard\tJ.\tSmith*** | 786 | 150,538 | 48,675 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 71,489 | 2,782,341 | 581,360 |
| Entergy\tLouisiana |  |  |  |
| E.\tRenae\tConley*** | 1,659 | 85,858 | 37,730 |
| Donald\tC.\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard** | 13,268 | 1,201,600 | 50,588 |
| Richard\tJ.\tSmith*** | 786 | 150,538 | 48,675 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 54,663 | 2,709,622 | 559,761 |
| Entergy\tMississippi |  |  |  |
| Donald\tC.\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard** | 13,268 | 1,201,600 | 50,588 |
| Carolyn\tC.\tShanks*** | 4,694 | 39,466 | 11,025 |
| Richard\tJ.\tSmith*** | 786 | 150,538 | 48,675 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| All\tdirectors\tand\texecutive\nofficers | 52,198 | 2,606,215 | 531,172 |

|  | Entergy	Corporation<br>Common	Stock |  |  |
| :--- | :--- | :--- | :--- |
|  | Amount\tof\tNature\tof\nBeneficial\tOwnership\t(a) | Amount\tof\tNature\tof\nBeneficial\tOwnership\t(a) |  |
|  | Sole\tVoting |  |  |
|  | and | Other |  |
|  | Investment | Beneficial | Entergy\tCorporation |
| Name | Power | Ownership(b) | Stock\tEquivalent\tUnits |
|  |  |  | (c) |
| Entergy\tNew\tOrleans |  |  |  |
| Donald\tC.\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |

| J.	Wayne	Leonard** | 13,268 | 1,201,600 | 50,588 |
| :--- | :--- | :--- | :--- |
| Daniel\tF.\tPacker*** | 4,178 | 30,799 | 4,727 |
| Richard\tJ.\tSmith*** | 786 | 150,538 | 48,675 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 44,530 | 2,563,615 | 524,874 |
| System\tEnergy |  |  |  |
| Donald\tC.\tHintz*** | 4,381 | 650,920 | 171,580 |
| Jerry\tD.\tJackson** | - | 28,031 | - |
| J.\tWayne\tLeonard** | 13,268 | 1,201,600 | 50,588 |
| Richard\tJ.\tSmith** | 786 | 150,538 | 48,675 |
| Gary\tJ.\tTaylor*** | 1,161 | 72,032 | 11,720 |
| C.\tJohn\tWilder*** | 1,021 | 222,430 | 172,368 |
| Jerry\tW.\tYelverton** | - | 10,000 | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 42,085 | 2,500,333 | 492,417 |

* 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,	2003,	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	 Executive Annual	 Incentive	 Plan	 Deferral	 Program,	 Defined	 Contribution	 Restoration	 Plan,	 and	 the Executive	Deferred	Compensation	Plan.	These	units	will	be	paid	out	in	a	combination	of	Entergy Corporation	Common	Stock	and	cash	based	on	the	value	of	Entergy	Corporation	Common	Stock on	the	date	of	payout.	The	deferral	period	is	determined	by	the	individual	and	is	at	least	two years	from	the	award	of	the	bonus.	For	directors	of	Entergy	Corporation	the	stock	equivalent units	are	part	of	the	Service	Award	for	Directors.	All	non-employee	directors	are	credited	with 800	units	for	each	year	of	service	on	the	Board.

(d) Dr.	Murrill	and	Mr.	Reilley	have	deferred	receipt	of	an	additional	5,100	shares	and	2,100	shares, respectively.

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,	2003.

| Plan | Number	of	Securities<br>to	be	Issued	Upon<br>Exercise	of<br>Outstanding	Options | Weighted<br>Average<br>Exercise<br>Price | Number	of	Securities<br>Remaining	Available<br>for	Future	Issuance	(a) |
| :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans\napproved\tby\tsecurity\tholders | 4,003,462 | $38.41 | 7,786,150 |
| Equity\tcompensation\tplans |  |  |  |
| not | 11,425,921 | 38.72 | - |
| approved\tby\tsecurity\tholders |  |  |  |
| Total | 15,429,383 | $38.64 | 7,786,150 |

(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.

Entergy	shareholders	have	also	approved	the	"Stock	Plan	for	Outside	Directors."	This	plan	grants	non-employee	members	of	the	Board	600	shares	of Entergy	common	stock	in	each	year	of	service	on	the	Board,	paid	in	quarterly	installments.

# Item	13.	Certain	Relationships	and	Related	Transactions

During	 2003,	 T.	 Baker	 Smith	 &	 Son,	 Inc.	 performed	 land-surveying	 services	 for,	 and	 received	 payments	 of	 approximately	 $390,689	 from	 Entergy companies.	Mr.	Wm.	Clifford	Smith,	a	director	of	Entergy	Corporation,	is	Chairman	of	the	Board	of	T.	Baker	Smith	&	Son,	Inc.	 Mr.	Smith's	children	own 100%	of	the	voting	stock	of	T.	Baker	Smith	&	Son,	Inc.

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

Other	than	as	provided	under	applicable	corporate	laws,	Entergy	does	not	have	policies	whereby	transactions	involving	executive	officers	and	directors	are approved	by	a	majority	of	disinterested	directors.	However,	pursuant	to	the	Entergy	Corporation	Code	of	Conduct,	transactions	involving	an	Entergy company	and	its	executive	officers	must	have	prior	approval	by	the	next	higher	reporting	level	of	that	individual,	and	transactions	involving	an	Entergy company	and	its	directors	must	be	reported	to	the	secretary	of	the	appropriate	Entergy	company.	Also,	Entergy's	Corporate	Governance	Guidelines	require directors	to	obtain	the	approval	of	the	Corporate	Governance	Committee	to	participate	in	a	transaction	to	which	Entergy	is	a	party	where	the	director	has	a direct	or	indirect	financial	or	personal	interest.

# 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,	2003	and	2002	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:

|  | 2003 | 2002 |
| :--- | :--- | :--- |
| Entergy\tCorporation\t(consolidated) |  |  |
| Audit\tFees | $3,244,750 | $3,043,100 |
| Audit-Related\tFees\t(a) | 690,665 | 392,021 |
| Total\taudit\tand\taudit-related\tfees | 3,935,415 | 3,435,121 |
| Tax\tFees\t(b) | 119,802 | 128,029 |
| All\tOther\tFees\t(c) | 5,000 | 35,751 |
| Total\tFees\t(d) | $4,060,217 | $3,598,901 |
| Entergy\tArkansas |  |  |
| Audit\tFees | $402,200 | $270,450 |
| Audit-Related\tFees\t(a) | 68,963 | - |
| Total\taudit\tand\taudit-related\tfees | 471,163 | 270,450 |
| Tax\tFees | - | - |
| All\tOther\tFees\t(c) | - | 5,691 |
| Total\tFees\t(d) | $471,163 | $276,141 |
| Entergy\tGulf\tStates |  |  |
| Audit\tFees | $432,050 | $255,000 |
| Audit-Related\tFees\t(a) | 79,026 | - |
| Total\taudit\tand\taudit-related\tfees | 511,076 | 255,000 |
| Tax\tFees | - | - |
| All\tOther\tFees | - | - |
| Total\tFees\t(d) | $511,076 | $255,000 |
| Entergy\tLouisiana |  |  |
| Audit\tFees | $355,800 | $270,000 |
| Audit-Related\tFees\t(a) | 69,617 | - |
| Total\taudit\tand\taudit-related\tfees | 425,417 | 270,000 |
| Tax\tFees | - | - |
| All\tOther\tFees | - | - |
| Total\tFees\t(d) | $425,417 | $270,000 |

|  | 2003 | 2002 |
| :--- | :--- | :--- |
| Entergy\tMississippi |  |  |
| Audit\tFees | $413,300 | $267,650 |
| Audit-Related\tFees\t(a) | 53,204 | - |

| Total	audit	and	audit-related	fees | 466,504 | 267,650 |
| :--- | :--- | :--- |
| Tax\tFees | - | - |
| All\tOther\tFees | - | - |
| Total\tFees\t(d) | $466,504 | $267,650 |
| Entergy\tNew\tOrleans |  |  |
| Audit\tFees | $365,800 | $256,500 |
| Audit-Related\tFees\t(a) | 147,855 | 85,114 |
| Total\taudit\tand\taudit-related\tfees | 513,655 | 341,614 |
| Tax\tFees | - | - |
| All\tOther\tFees\t(c) | - | 30,060 |
| Total\tFees\t(d) | $513,655 | $371,674 |
| System\tEnergy |  |  |
| Audit\tFees | $350,200 | $225,350 |
| Audit-Related\tFees\t(a) | 8,800 | - |
| Total\taudit\tand\taudit-related\tfees | 359,000 | 225,350 |
| Tax\tFees | - | - |
| All\tOther\tFees | - | - |
| Total\tFees\t(d) | $359,000 | $225,350 |

(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	minimus	provision.

(d) 100%	of	fees	paid	in	2003	and	approximately	90%	of	fees	paid	in	2002	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).

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,	and	Reports	on	Form	8-K

(a)1. Financial	 Statements	 and	 Independent	 Auditors'	 Reports	 for	 Entergy,	 Entergy	 Arkansas, Entergy	 Gulf	 States,	 Entergy	 Louisiana,	 Entergy	 Mississippi,	 Entergy	 New	 Orleans,	 and System	Energy	are	listed	in	the	Table	of	Contents.

# (a)2. Financial	Statement	Schedules

# Independent	Auditor's	Report	on	Financial	Statement	Schedules	(see	page	368)

Financial	Statement	Schedules	are	listed	in	the	Index	to	Financial	Statement	Schedules	(see page	S-1)

Exhibits	 for	 Entergy,	 Entergy	Arkansas,	 Entergy	 Gulf	 States,	 Entergy	 Louisiana,	 Entergy Mississippi,	Entergy	New	Orleans,	and	System	Energy	are	listed	in	the	Exhibit	Index	(see	page E-1).	Each	management	contract	or	compensatory	plan	or	arrangement	required	to	be	filed	as an	exhibit	hereto	is	identified	as	such	by	footnote	in	the	Exhibit	Index.

# (b) Reports	on	Form	8-K

A	Current	Report	on	Form	8-K,	dated	January	20,	2004,	was	filed	with	the	SEC	on	January	20, 2004,	 reporting	 information	 under	 Item 7. "Financial	 Statements,	 Pro	 Forma	 Financial Statements	 and	 Exhibits,"	 Item	 9.	 "Regulation	 FD	 Disclosure,"	 and	 Item	 12.	 "Results	 of Operations	and	Financial	Condition."

A	Current	Report	on	Form	8-K,	dated	February	2,	2004,	was	filed	with	the	SEC	on	February	2, 2004,	 reporting	 information	 under	 Item 7. "Financial	 Statements,	 Pro	 Forma	 Financial Statements	and	Exhibits"	and	Item	9.	"Regulation	FD	Disclosure."

A	Current	Report	on	Form	8-K,	dated	February	16,	2004,	was	filed	with	the	SEC	on	February 17,	 2004,	 reporting	 information	 under	 Item	 7.	 "Financial	 Statements,	 Pro	 Forma	 Financial Statements	 and	 Exhibits,"	 Item	 9.	 "Regulation	 FD	 Disclosure,"	 and	 Item	 12.	 "Results	 of Operations	and	Financial	Condition."

A	Current	Report	on	Form	8-K,	dated	February	20,	2004,	was	filed	with	the	SEC	on	February 23, 2004,	 reporting	 information	 under	 Item 5. "Other	 Events"	 and	 Item 7. "Financial Statements,	Pro	Forma	Financial	Statements	and	Exhibits."

# 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.

By	/s/	Nathan	E.	Langston

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

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.

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, George	W.	Davis,	Simon	deBee,	Claiborne	P.	Deming,	Alexis	M.	Herman,	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).

(Nathan	E.	Langston,	Attorney-in-fact)

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

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	-	Operations;	Principal	Financial	Officer);	Donald	C.	Hintz,	Richard	J.	Smith,	and	Leo	P.	Denault	(Directors).

E.	Renae	Conley	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice President,	Chief	Financial	Officer	-	Operations;	Principal	Financial	Officer);	Donald	C.	Hintz,	Richard	J.	Smith,	and	Leo	P.	Denault	(Directors).

Carolyn	C.	Shanks	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice President,	Chief	Financial	Officer	-	Operations;	Principal	Financial	Officer);	Donald	C.	Hintz,	Richard	J.	Smith,	and	Leo	P.	Denault	(Directors).

Daniel	F.	Packer	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice President,	Chief	Financial	Officer	-	Operations;	Principal	Financial	Officer);	Donald	C.	Hintz,	Richard	J.	Smith,	and	Leo	P.	Denault	(Directors).

Signature

Title

# /s/	Nathan	E.	Langston Senior	Vice	President	and	Chief March	9,	2004

# Nathan	E.	Langston

# Accounting	Officer

(Principal	Accounting	Officer)

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);	Donald	C.	Hintz	and	Leo	P.	Denault	(Directors).

# INDEPENDENT	AUDITORS'	CONSENTS

We	consent	to	the	incorporation	by	reference	in	Post-Effective	Amendments	No.	3	and	5A	on	Form	S-8	and	their	related	prospectuses	to	Registration Statement	 No. 33-54298 of	 Entergy	 Corporation	 on	 Form	 S-4,	 Registration	 Statements	 No. 333-02503 and 333-22007 of	 Entergy	 Corporation ("Corporation")	on	Form	S-3	and	Registration	Statements	No.	333-98179,	333-90914,	333-75097,	333-55692,	and	333-68950	of	the	Corporation	on	Form	S- 8	of	our	reports	dated	March	9,	2004,	which	reports	 include	an	explanatory	paragraph	regarding	 the	Corporation's	change	 in	2003	 in	 the	method	of accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities,	the	change	in	2002	in	the	method	of	accounting	for	goodwill and	intangible	assets,	and	the	change	in	2001	in	the	method	of	accounting	for	derivative	instruments;	appearing	in	this	Annual	Report	on	Form	10-K	of	the Corporation	for	the	year	ended	December	31,	2003.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-50289,	333-00103,	333-05045,	and	333-109453	of	Entergy	Arkansas,	Inc. on	Form	S-3	of	our	report	dated	March	9,	2004,	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,	appearing	in	this	Annual	Report	on	Form	10-K	of Entergy	Arkansas,	Inc.	for	the	year	ended	December	31,	2003.

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	and	Registration	Statement	No.	333-17911	of	Entergy	Gulf	States,	Inc.	on	Form	S-2	of	our	report	dated	March	9,	2004,	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,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Gulf	States,	Inc.	for	the	year	ended	December	31,	2003.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-46085,	33-39221,	33-50937,	333-00105,	333-01329,	333-03567	and	333- 93683	of	Entergy	Louisiana,	Inc.	on	Form	S-3	of	our	report	dated	March	9,	2004,	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,	appearing	in this	Annual	Report	on	Form	10-K	of	Entergy	Louisiana,	Inc.	for	the	year	ended	December	31,	2003.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-53004,	33-55826,	and	333-110675	of	Entergy	Mississippi,	Inc.	on	Form	S-3 of	our	report	dated	March	9,	2004,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Mississippi,	Inc.	for	the	year	ended	December	31,	2003.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-57926,	333-00255	and	333-95599	of	Entergy	New	Orleans,	Inc.	on	Form	S- 3	of	our	report	dated	March	9,	2004,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	New	Orleans,	Inc.	for	the	year	ended	December	31,	2003.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-47662,	33-61189,	and	333-06717	of	System	Energy	Resources,	Inc.	on	Form S-3	of	our	report	dated	March	9,	2004,	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	for	consolidation	of	variable	interest	entities,	appearing	in	this	Annual	Report	on	Form	10-K	of System	Energy	Resources,	Inc.	for	the	year	ended	December	31,	2003.

We	have	audited	the	consolidated	financial	statements	of	Entergy	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.	(the	Companies),	as	of	December	31,	2003	and 2002,	and	for	each	of	the	three	years	in	the	period	ended	December	31,	2003,	and	have	issued	our	reports	thereon	dated	March	5,	2004.	Our	report	on	the consolidated	financial	statements	of	the	Corporation	includes	an	explanatory	paragraph	regarding	its	change	in	2003	in	the	method	of	accounting	for	asset retirement	obligations	and	for	consolidation	of	variable	interest	entities,	its	change	in	2002	in	the	method	of	accounting	for	goodwill	and	intangible	assets,

and	its	change	in	2001	in	the	method	of	accounting	for	derivative	instruments.	Our	reports	on	the	financial	statements	of	Entergy	Arkansas,	Inc.,	Entergy Gulf	States,	Inc.,	and	Entergy	Louisiana,	Inc.'s	each	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	 2003	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	statements	and	financial	statement	schedules	are	the	responsibility	of	the	Corporation's	and the	respective	Companies'	managements.	Our	responsibility	is	to	express	our	opinions	on	the	financial	statements	and	financial	statement	schedules	based	on our	audits.	(We	did	not	audit	the	financial	statements	of	Entergy-Koch,	LP	for	the	year	ended	December	31,	2003,	the	Corporation's	investment	in	which	is accounted	for	by	the	use	of	the	equity	method.	The	Corporation's	equity	in	earnings	of	unconsolidated	equity	affiliates	for	the	year	ended	December	31, 2003	includes	$180,110,000	for	Entergy	Koch,	LP,	which	earnings	were	audited	by	other	auditors	whose	report	has	been	furnished	to	us,	and	our	opinion, insofar	as	it	relates	to	the	amount	audited	by	other	auditors	included	for	such	company,	is	based	solely	on	the	report	of	such	other	auditors.)	In	our	opinion, such	financial	statement	schedules,	when	considered	in	relation	to	the	basic	financial	statements	taken	as	a	whole,	present	fairly	in	all	material	respects	the information	set	forth	therein.

# INDEX	TO	FINANCIAL	STATEMENT	SCHEDULES

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.

# Income:

See	Entergy	Corporation	and	Subsidiaries	Notes	to	Financial

# Statements	in	Part	II,	Item	8.

# 								SCHEDULE	I	-	FINANCIAL	STATEMENTS	OF	ENTERGY	CORPORATION

# 		Accounts	payable:

										ACCUMULATED	OTHER	COMPREHENSIVE

# See	Entergy	Corporation	and	Subsidiaries	Notes	to	Financial	Statements	in

# 												SCHEDULE	II	-	VALUATION	AND	QUALIFYING	ACCOUNTS

# 	Accumulated	Provisions

# 		Deducted	from	Assets--

		(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.

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.

						respective	provisions	were	created.	In	the	case	of	the	provision	for

						doubtful	accounts,	such	deductions	are	reduced	by	recoveries	of	amounts 						previously	written	off.

# 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

# 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).

# (4)	Instruments	Defining	Rights	of	Security	Holders,	Including	Indentures

(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)	8	-- Officer'	Certificate	for	Entergy	Corporation	(4(a)	to	Form	10-Q	for	the	quarter	ended September	30,	2003).

# *(a)	9	-- Officer'	Certificate	for	Entergy	Corporation.

*(a)	10-- Officer'	Certificate	for	Entergy	Corporation.

*(a)	11-- Credit	 Agreement,	 dated	 as	 of	 November	 24,	 2003,	 among	 Entergy	 Corporation, Bayerische	Hypo-und	Vereinsbank	AG,	New	York	Branch,	the	Bank,	and	Bayerische Hypo-und	Vereinsbank	AG,	New	York	Branch,	as	Administrative	Agent.

(c)	2	-- Indenture	 for	 Unsecured	 Subordinated	 Debt	 Securities	 relating	 to	 Trust	 Securities between	Entergy	Arkansas	and	Bank	of	New	York	(as	Trustee),	dated	as	of	August	1, 1996	(A-1(a)	to	Rule	24	Certificate	dated	August	26,	1996	in	70-8723).

(c)	4	-- Guarantee	Agreement	 between	 Entergy	Arkansas	 (as	 Guarantor)	 and	The	 Bank	 of New	York	(as	Trustee),	dated	as	of	August	14,	1996,	with	respect	to	Entergy	Arkansas Capital	 I's	 obligations	 on	 its 8 1/2% Cumulative	 Quarterly	 Income	 Preferred Securities,	Series	A	(A-4(a)	to	Rule	24	Certificate	dated	August	26,	1996	in	70-8723).

# (d)	1	-- Indenture	of	Mortgage,	dated	September	1,	1926,	as	amended	by	certain	Supplemental

(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)	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).

(e)	7	-- Guarantee	Agreement	between	Entergy	Louisiana,	Inc.	(as	Guarantor)	and	The	Bank of	New	York	(as	Trustee)	dated	as	of	July	16,	1996	with	respect	to	Entergy	Louisiana Capital	I's	obligation	on	 its	9%	Cumulative	Quarterly	Income	Preferred	Securities, Series	A	(A-19(a)	to	Rule	24	Certificate	dated	July	25,	1996	in	70-8487).

# (f)	1	-- Mortgage	and	Deed	of	Trust,	dated	as	of	February	1,	1988,	as	amended	by	twenty-one

# (10)	Material	Contracts

(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)	9	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

(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)	28	-- 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)	29	-- Nineteenth	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of

September	1,	1986,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.

(a)	30	-- 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)	31	-- 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)	32	-- 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)	33	-- 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)	34	-- 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)	35	-- Thirty-second	Supplementary	Capital	Funds	Agreement	and	Assignment,	dated	as	of December	 27,	 1996,	 among	 Entergy	 Corporation,	 System	 Energy	 and	 The	 Chase Manhattan	Bank	(B-1(a)	to	Rule	24	Certificate	dated	January	13,	1997	in	70-7561).

(a)	37	-- 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)	38	-- 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.

(a)	39	-- 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)	40	-- 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)	41	-- 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)	50	-- 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)	51	-- 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)	53	-- 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)	86	-- System	Executive	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective

*+(a)	99	-- Employment	Agreement	effective	November	24,	2003	between	Mark	T.	Savoff	and Entergy	Services.

# Mississippi	 Business	 Finance	 Corporation	 (B-6(b)	 to	 Rule	 24	 Certificate	 dated

(b)	53	-- 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)	54	-- 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

(b)	55	-- 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)	56	-- 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)	57	-- 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)	58	-- 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)	9	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

(c)	41	-- 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)	44	-- 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)	45	-- 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)	48	-- Independence	 Steam	 Electric	 Station	 Ownership	 Agreement,	 dated	 July	 31,	 1979, among	 Entergy	Arkansas	 and	Arkansas	 Electric	 Cooperative	 Corporation	 and	 City Water	 and	 Light	 Plant	 of	 the	 City	 of	 Jonesboro,	 Arkansas	 and	 City	 of	 Conway, Arkansas	(5(r)7	in	2-66235).

(c)	52	-- 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)	53	-- 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)	54	-- 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)	57	-- 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)	64	-- 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)	65	-- 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).

Fuels	and	Entergy	Arkansas	(B	to	Rule	24	letter	filing	dated	November	10,	1987	in	70-

(c)	70	-- 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).

# (d)	2	-- Guaranty	Agreement,	dated	August	1,	1992,	between	Entergy	Gulf	States	and	Hibernia

# National	 Bank,	 relating	 to	 Pollution	 Control	 Revenue	 Refunding	 Bonds	 of	 the

(d)	3	-- Guaranty	 Agreement,	 dated	 January 1, 1993,	 between	 Entergy	 Gulf	 States	 and Hancock	Bank	of	Louisiana,	relating	to	Pollution	Control	Revenue	Refunding	Bonds	of the	 Parish	 of	 Pointe	 Coupee	 (Louisiana) (10-2 to	 Form	 10-K	 for	 the	 year	 ended December	31,	1992	in	1-27031).

(d)	14	-- First	Amended	 Power	 Sales	Agreement,	 dated	 December	 1,	 1985	 between	 Sabine River	Authority,	State	of	Louisiana,	and	Sabine	River	Authority,	State	of	Texas,	and Entergy	Gulf	States,	Central	Louisiana	Electric	Co.,	Inc.,	and	Louisiana	Power	and Light	Company	(10-72	to	Form	10-K	for	the	year	ended	December	31,	1985	in	1- 27031).

+(d)	16	-- Trust	Agreement	for	Deferred	Payments	to	be	made	by	Entergy	Gulf	States	pursuant	to the	Executive	Income	Security	Plan,	by	and	between	Entergy	Gulf	States	and	Bankers Trust	Company,	effective	November	1,	1986	(10-78	to	Form	10-K	for	the	year	ended December	31,	1986	in	1-27031).

+(d)	17	-- Trust	Agreement	for	Deferred	Installments	under	Entergy	Gulf	States'	Management Incentive	Compensation	Plan	and	Administrative	Guidelines	by	and	between	Entergy Gulf	States	and	Bankers	Trust	Company,	effective	June	1,	1986	(10-79	to	Form	10-K for	the	year	ended	December	31,	1986	in	1-27031).

+(d)	18	-- Nonqualified	Deferred	Compensation	Plan	for	Officers,	Nonemployee	Directors	and Designated	Key	Employees,	effective	December	1,	1985,	as	amended,	continued	and completely	 restated	 effective	 as	 of	 March	 1,	 1991 (10-3 to	Amendment	 No.	 8	 in Registration	No.	2-76551).

+(d)	19	-- Trust	Agreement	for	Entergy	Gulf	States'	Nonqualified	Directors	and	Designated	Key Employees	by	and	between	Entergy	Gulf	States	and	First	City	Bank,	Texas-Beaumont, N.A.	(now	Texas	Commerce	Bank),	effective	July	1,	1991	(10-4	to	Form	10-K	for	the year	ended	December	31,	1992	in	1-27031).

(d)	24	-- Partnership	Agreement	by	and	among	Conoco	Inc.,	and	Entergy	Gulf	States,	CITGO Petroleum	Corporation	and	Vista	Chemical	Company,	dated	April	28,	1988	(10-67	to Form	10-K	for	the	year	ended	December	31,	1988	in	1-27031).

(d)	28	-- Operating	Agreement	between	Entergy	Operations	and	Entergy	Gulf	States,	dated	as	of December	31,	1993	(B-2(f)	to	Rule	24	Certificate	in	70-8059).

(d)	29	-- Guarantee	Agreement	between	Entergy	Corporation	and	Entergy	Gulf	States,	dated	as of	December	31,	1993	(B-5(a)	to	Rule	24	Certificate	in	70-8059).

*(d)	32	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

(d)	33	-- Third	Amendment,	 dated	 January	 1,	 1994,	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for the	year	ended	December	31,	1993).

Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the year	ended	December	31,	1996).

(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)	9	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

(e)	29	-- 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)	30	-- 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)	32	-- 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)	33	-- 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)	34	-- 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)	35	-- 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)	36	-- 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)	37	-- 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).

(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)	9	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

(f)	26	-- Installment	Sale	Agreement,	dated	as	of	June	1,	1974,	between	Entergy	Mississippi	and Washington	County,	Mississippi	(B-2(a)	to	Rule	24	Certificate	dated	August	1,	1974	in 70-5504).

(f)	27	-- Amended	and	Restated	Installment	Sale	Agreement,	dated	as	of	April	1,	1994,	between Entergy	Mississippi	and	Warren	County,	Mississippi	(B-6(a)	 to	Rule	24	Certificate dated	May	4,	1994	in	70-7914).

(f)	42	-- 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)	44	-- 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)	45	-- 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)	9	-- Amendment,	dated	August	1,	2003,	to	Service	Agreement	with	Entergy	Services.

# (g)	27	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and

# Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi	and	Entergy	New	Orleans

(g)	28	-- 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)	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).

(g)	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).

(g)	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).

# (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	355.

*(b) Consent	of	Ernst	&	Young	LLP.

*(24)	Powers	of	Attorney

*(e) Rule	13a-14(a)/15d-14(a)	Certification	for	Entergy	Gulf	States	and	Entergy	Louisiana.

*(i) Rule	 13a-14(a)/15d-14(a)	 Certification	 for	 Entergy	 Arkansas,	 Entergy	 Gulf	 States, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans.

# (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

*	Filed	herewith.

+	Management	contracts	or	compensatory	plans	or	arrangements.

Officer'	Certificate	for	Entergy	Corporation.

*(a)	25	-- 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.

*+(f)48	-- Employment	Agreement	effective	July	24,	2003	between	Carolyn	C.	Shanks	and	Entergy Mississippi.

Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans.



Question: what portion of the total entergy staff is employed at entergy operations?
Calculation: entergy_ops = 2902
entergy_total = 14773
percent_ops = entergy_ops / entergy_total
answer = percent_ops * 100
Answer: 19.6%