# 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,	2004

# 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	Gulf	States	Capital	I 8.75%	Cumulative	Quarterly	Income	Preferred Securities,	Series	A

# (guaranteed	by	Entergy	Gulf	States,	Inc.)

# Entergy	Louisiana,	Inc. Mortgage	Bonds,	7.6%	Series	due	April	2032

Entergy	Mississippi,	Inc. Mortgage	Bonds,	6.0%	Series	due	November 2032 Mortgage	Bonds,	7.25%	Series	due	December 2032

# New	York	Stock	Exchange,	Inc.

New	York	Stock	Exchange,	Inc. 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.	[Ö	]

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

Entergy	Mississippi,	Inc.

Entergy	New	Orleans,	Inc.

System	Energy	Resources,	Inc.

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

# DOCUMENTS	INCORPORATED	BY	REFERENCE

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

# TABLE	OF	CONTENTS

|  | SEC	Form	10-K<br>Reference	Number | Page<br>Number |
| :--- | :--- | :--- |
| Definitions |  | i |
| Entergy's\tBusiness | Part\tI.\tItem\t1. | 1 |
| \t\t\t\t\t\tFinancial\tInformation\tfor\tU.S.\tUtility,\tNon-Utility\tNuclear,\tand |  | 2 |
| Energy |  |  |
| \t\t\t\t\t\t\tCommodity\tServices |  |  |
| \t\t\t\t\t\tStrategy |  | 3 |
| Report\tof\tManagement |  | 4 |
| \t\t\t\t\t\tEntergy\tCorporation\tand\tSubsidiaries |  |  |
| \t\t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 5 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 12 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 22 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 33 |
| \t\t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 41 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 42 |
| \t\t\t\t\tConsolidated\tStatements\tof\tIncome\tFor\tthe\tYears\tEnded\tDecember\t31,\n\t\t\t\t\t\t\t\t\t\t2004,\t2003,\tand\t2002 | Part\tII.\tItem\t8. | 43 |
| \t\t\t\t\tConsolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded | Part\tII.\tItem\t8. | 44 |
| December |  |  |
| \t\t\t\t\t\t\t\t\t\t31,\t2004,\t2003,\tand\t2002 |  |  |
| \t\t\t\t\tConsolidated\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 46 |

| Notes	to	Consolidated	Financial	Statements | Part	II.	Item	8. | 49 |
| :--- | :--- | :--- |
| U.S.\tUtility | Part\tI.\tItem\t1. | 105 |
| \t\t\t\t\t\tCustomers |  | 105 |
| \t\t\t\t\t\tElectric\tEnergy\tSales |  | 105 |
| \t\t\t\t\t\tRetail\tRate\tRegulation |  | 107 |
| \t\t\t\t\t\tProperty\tand\tOther\tGeneration\tResources |  | 113 |
| \t\t\t\t\t\tFuel\tSupply |  | 116 |
| \t\t\t\t\t\tFederal\tRegulation |  | 119 |
| \t\t\t\t\t\tService\tCompanies |  | 128 |
| \t\t\t\t\t\tEarnings\tRatios |  | 128 |
| Non-Utility\tNuclear | Part\tI.\tItem\t1. | 129 |
| \t\t\t\t\t\tProperty |  | 129 |
| \t\t\t\t\t\tEnergy\tand\tCapacity\tSales |  | 129 |
| \t\t\t\t\t\tFuel\tSupply |  | 130 |
| \t\t\t\t\t\tOther\tBusiness\tActivities |  | 131 |
| Energy\tCommodity\tServices | Part\tI.\tItem\t1. | 131 |
| \t\t\t\t\t\tNon-Nuclear\tWholesale\tAssets\tBusiness |  | 132 |
| \t\t\t\t\t\tEntergy-Koch,\tL.P. |  | 132 |
| Regulation\tof\tEntergy's\tBusiness | Part\tI.\tItem\t1. | 133 |
| \t\t\t\t\t\tPUHCA |  | 133 |
| \t\t\t\t\t\tFederal\tPower\tAct |  | 133 |
| \t\t\t\t\t\tState\tRegulation |  | 134 |
| \t\t\t\t\t\tRegulation\tof\tthe\tNuclear\tPower\tIndustry |  | 135 |
| \t\t\t\t\t\tEnvironmental\tRegulation |  | 137 |
| Litigation |  | 142 |
| Research\tSpending |  | 146 |
| Employees |  | 146 |
| Entergy\tArkansas,\tInc. |  |  |
| \t\t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 147 |
| \t\t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 147 |
| \t\t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 150 |
| \t\t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 154 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 164 |
| \t\t\t\t\t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\t2003,\n\t\t\t\t\t\t\t\t\tand\t2002 | Part\tII.\tItem\t8. | 165 |
| \t\t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\n\t\t\t\t\t\t\t\t\t2003,\tand\t2002 | Part\tII.\tItem\t8. | 167 |
| \t\t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 168 |
| \t\t\t\t\t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 170 |
| 2004, |  |  |
| \t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 171 |
| Entergy\tGulf\tStates,\tInc. |  |  |
| \t\t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 172 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 176 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 179 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 188 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 193 |
| \t\t\t\t\t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\t2003, | Part\tII.\tItem\t8. | 194 |
| \t\t\t\t\t\t\t\t\t\t\tand\t2002 |  |  |
| \t\t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004, | Part\tII.\tItem\t8. | 195 |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 196 |
| \t\t\t\t\tStatements\tof\tRetained\tEarnings\tand\tComprehensive\tIncome\tfor\tthe | Part\tII.\tItem\t8. | 198 |
| \t\t\t\t\t\t\t\t\t\t\tYears\tEnded\tDecember\t31,\t2004,\t2003,\tand\t2002 |  |  |
| \t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 199 |
| Entergy\tLouisiana,\tInc. |  |  |
| \t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 200 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 203 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 207 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 213 |
| \t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 218 |
| \t\t\t\t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\t2003, | Part\tII.\tItem\t8. | 219 |
| \t\t\t\t\t\t\t\t\t\t\tand\t2002 |  |  |
| \t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004, | Part\tII.\tItem\t8. | 221 |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 222 |
| \t\t\t\t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 224 |
| 2004, |  |  |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 225 |

| Management's	Financial	Discussion	and	Analysis | Part	II.	Item	7. |  |
| :--- | :--- | :--- |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 226 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 228 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 231 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 236 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 239 |
| \t\t\t\t\t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\t2003, | Part\tII.\tItem\t8. | 240 |
| \t\t\t\t\t\t\t\t\t\t\tand\t2002 |  |  |
| \t\t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004, | Part\tII.\tItem\t8. | 241 |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 242 |
| \t\t\t\t\t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 244 |
| \t\t\t\t\t\t\t\t\t\t\t2004,\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 245 |
| Entergy\tNew\tOrleans,\tInc. |  |  |
| \t\t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 246 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 248 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 251 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 257 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 260 |
| \t\t\t\t\t\tStatements\tof\tOperations\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004, | Part\tII.\tItem\t8. | 261 |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004, | Part\tII.\tItem\t8. | 263 |
| \t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 264 |
| \t\t\t\t\t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 266 |
| \t\t\t\t\t\t\t\t\t\t\t2004,\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 267 |
| System\tEnergy\tResources,\tInc. |  |  |
| \t\t\t\t\t\tManagement's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. |  |
| \t\t\t\t\t\t\t\t\t\t\tResults\tof\tOperations |  | 268 |
| \t\t\t\t\t\t\t\t\t\t\tLiquidity\tand\tCapital\tResources |  | 268 |
| \t\t\t\t\t\t\t\t\t\t\tSignificant\tFactors\tand\tKnown\tTrends |  | 271 |
| \t\t\t\t\t\t\t\t\t\t\tCritical\tAccounting\tEstimates |  | 272 |
| \t\t\t\t\t\tReport\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 276 |
| \t\t\t\t\t\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\t2003, | Part\tII.\tItem\t8. | 277 |
| \t\t\t\t\t\t\t\t\t\t\tand\t2002 |  |  |
| \t\t\t\t\t\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2004,\n\t\t\t\t\t\t\t\t\t\t\t2003,\tand\t2002 | Part\tII.\tItem\t8. | 279 |
| \t\t\t\t\t\tBalance\tSheets,\tDecember\t31,\t2004\tand\t2003 | Part\tII.\tItem\t8. | 280 |
| \t\t\t\t\t\tStatements\tof\tRetained\tEarnings\tfor\tthe\tYears\tEnded\tDecember\t31, | Part\tII.\tItem\t8. | 282 |
| \t\t\t\t\t\t\t\t\t\t\t2004,\t2003,\tand\t2002 |  |  |
| \t\t\t\t\t\tSelected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 283 |
| Notes\tto\tRespective\tFinancial\tStatements\tfor\tthe\tDomestic\tUtility | Part\tII.\tItem\t8. | 284 |
| Companies |  |  |
| \t\t\t\tand\tSystem\tEnergy |  |  |
| Properties | Part\tI.\tItem\t2. | 349 |
| Legal\tProceedings | Part\tI.\tItem\t3. | 349 |
| Submission\tof\tMatters\tto\ta\tVote\tof\tSecurity\tHolders | Part\tI.\tItem\t4. | 349 |
| Directors\tand\tExecutive\tOfficers\tof\tEntergy\tCorporation | Part\tIII.\tItem\t10. | 349 |
| Market\tfor\tRegistrants'\tCommon\tEquity\tand\tRelated\tStockholder\tMatters | Part\tII.\tItem\t5. | 351 |
| Selected\tFinancial\tData | Part\tII.\tItem\t6. | 352 |
| Management's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand | Part\tII.\tItem\t7. | 352 |
| Results\tof |  |  |
| \t\t\tOperations |  |  |
| Quantitative\tand\tQualitative\tDisclosures\tAbout\tMarket\tRisk | Part\tII.\tItem\t7A. | 352 |
| Financial\tStatements\tand\tSupplementary\tData | Part\tII.\tItem\t8. | 353 |
| Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand | Part\tII.\tItem\t9. | 353 |
| Financial |  |  |
| \t\t\tDisclosure |  |  |
| Controls\tand\tProcedures | Part\tII.\tItem\t9A. | 353 |
| Attestation\tReport\tof\tRegistered\tPublic\tAccounting\tFirm | Part\tII.\tItem\t9A. | 354 |
| Other\tInformation | Part\tII.\tItem\t9B. | 368 |
| Directors\tand\tExecutive\tOfficers\tof\tthe\tRegistrants | Part\tIII.\tItem\t10. | 369 |
| Executive\tCompensation | Part\tIII.\tItem\t11. | 373 |
| Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement | Part\tIII.\tItem\t12. | 383 |
| Certain\tRelationships\tand\tRelated\tTransactions | Part\tIII.\tItem\t13. | 386 |
| Principal\tAccountant\tFees\tand\tServices | Part\tIV.\tItem\t14 | 387 |
| Exhibits,\tFinancial\tStatement\tSchedules,\tand\tReports\ton\tForm\t8-K | Part\tIV.\tItem\t15. | 390 |
| Signatures |  | 391 |
| Consent\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 398 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 400 |

												 This	combined	Form	10-K	is	separately	filed	by	Entergy	Corporation,	Entergy	Arkansas,	Inc.,	Entergy	Gulf	States,	Inc.,	Entergy	Louisiana,	Inc., Entergy	Mississippi,	Inc.,	Entergy	New	Orleans,	Inc.,	and	System	Energy	Resources,	Inc.	Information	contained	herein	relating	to	any	individual	company

# is	filed	by	such	company	on	its	own	behalf.	Each	company	makes	representations	only	as	to	itself	and	makes	no	other	representations	whatsoever	as	to	any other	company.

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

# FORWARD-LOOKING	INFORMATION

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

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

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

Entergy's	ability	to	manage	its	operation	and	maintenance	costs,	particularly	at	its	Non-Utility	Nuclear	generating	facilities the	performance	of	Entergy's	generating	plants,	and	particularly	the	capacity	factors	at	its	nuclear	generating	facilities prices	for	power	generated	by	Entergy's	unregulated	generating	facilities,	the	ability	to	extend	or	replace	the	existing	purchased	power	agreements	for	those facilities,	including	the	Non-Utility	Nuclear	plants,	and	the	prices	and	availability	of	power	Entergy	must	purchase	for	its	utility	customers Entergy's	ability	to	develop	and	execute	on	a	point	of	view	regarding	prices	of	electricity,	natural	gas,	and	other	energy-related	commodities changes	in	the	financial	markets,	particularly	those	affecting	the	availability	of	capital	and	Entergy's	ability	to	refinance	existing	debt,	execute	its	share repurchase	program,	and	fund	investments	and	acquisitions

actions	of	rating	agencies,	including	changes	in	the	ratings	of	debt	and	preferred	stock,	and	changes	in	the	rating	agencies'	ratings	criteria changes	in	inflation	and	interest	rates

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

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

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

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

uncertainty	regarding	the	establishment	of	interim	or	permanent	sites	for	spent	nuclear	fuel	storage	and	disposal

resolution	of	pending	or	future	applications	for	license	extensions	or	modifications	of	nuclear	generating	facilities changes	in	law	resulting	from	proposed	energy	legislation

changes	in	environmental,	tax,	and	other	laws,	including	requirements	for	reduced	emissions	of	sulfur,	nitrogen,	carbon,	mercury,	and	other	substances the	economic	climate,	and	particularly	growth	in	Entergy's	service	territory

variations	in	weather	and	the	occurrence	of	hurricanes	and	other	storms	and	disasters advances	in	technology

the	potential	effects	of	threatened	or	actual	terrorism	and	war the	effects	of	Entergy's	strategies	to	reduce	current	tax	payments the	effects	of	litigation	and	government	investigations changes	in	accounting	standards,	corporate	governance,	and	securities	law	requirements Entergy's	ability	to	attract	and	retain	talented	management	and	directors

# DEFINITIONS

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

Unit	Power	Sales	Agreement Agreement,	dated	as	of	June	10,	1982,	as	amended	and	approved	by	FERC,

among	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy

New	Orleans,	and	System	Energy,	relating	to	the	sale	of	capacity	and	energy

from	System	Energy's	share	of	Grand	Gulf

# ENTERGY'S	BUSINESS

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

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

U.S.	Utility	generates,	transmits,	distributes,	and	sells	electric	power	in	a	four-state	service	territory	that	includes	portions	of	Arkansas,	Mississippi,	Texas, and	Louisiana,	including	the	City	of	New	Orleans;	and	operates	a	small	natural	gas	distribution	business.

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

Energy	Commodity	Services	includes	Entergy-Koch	and	Entergy's	non-nuclear	wholesale	assets	business.	Entergy-Koch	engaged	in	two	major	businesses: energy	commodity	marketing	and	trading	through	Entergy-Koch	Trading,	and	gas	transportation	and	storage	through	Gulf	South	Pipeline.	Entergy-Koch	sold both	of	these	businesses	in	the	fourth	quarter	of	2004,	and	Entergy-Koch	is	no	longer	an	operating	entity.	The	non-nuclear	wholesale	assets	business	sells	to wholesale	customers	the	electric	power	produced	by	power	plants	that	it	owns	while	it	focuses	on	improving	performance	and	exploring	sales	or	restructuring opportunities	for	its	power	plants.	Such	opportunities	are	evaluated	consistent	with	Entergy's	market-based	point-of-view.	The	non-nuclear	wholesale	assets business	terminated	new	greenfield	power	development	activity	in	2002.

# OPERATING	INFORMATION

| 2004 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Operating\trevenues | $8,142,808 | $1,341,852 | $216,450 | $10,123,724 |
| Operating\texpenses | $6,795,146 | $978,688 | $308,226 | $8,470,160 |
| Other\tincome | $108,925 | $78,141 | ($44,727) | $124,416 |
| Interest\tand\tother\tcharges | $383,032 | $53,657 | $15,560 | $479,023 |
| Income\ttaxes | $406,864 | $142,620 | ($155,840) | $365,908 |
| Net\tincome | $666,691 | $245,029 | $3,778 | $933,049 |
| 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 |

# CASH	FLOW	INFORMATION

| 2004 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | $2,207,876 | $414,518 | $479,919 | $2,929,319 |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tinvesting\tactivities | ($1,198,009) | ($386,023) | $248,612 | ($1,140,075) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | ($824,579) | ($37,894) | ($724,534) | ($1,671,859) |

| 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) |

# FINANCIAL	POSITION	INFORMATION

| 2004 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Current\tassets | $2,323,801 | $590,580 | $1,282,578 | $3,108,118 |
| Other\tproperty\tand\tinvestments | $1,200,246 | $1,403,222 | $569,975 | $2,995,894 |
| Property,\tplant\tand\tequipment\t-\tnet | $16,502,155 | $1,850,481 | $310,793 | $18,695,631 |
| Deferred\tdebits\tand\tother\tassets | $2,911,035 | $687,321 | $60,632 | $3,511,134 |
| Current\tliabilities | $1,756,011 | $787,668 | $205,348 | $2,470,770 |
| Non-current\tliabilities | $15,214,095 | $1,694,090 | $279,730 | $17,543,320 |
| Shareholders'\tequity | $5,967,131 | $2,049,847 | $1,738,900 | $8,296,687 |
| 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 | $2,890,741 | $745,568 | $10,317 | $3,562,421 |
| 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 |

(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\tPower\tDevelopment\tCorp. |
| \t Entergy\tMississippi,\tInc. | \t Entergy\tNuclear\tFitzPatrick\tLLC |  | \t Entergy\tAsset\tManagement,\tInc. |
| \t Entergy\tNew\tOrleans,\tInc. | \t Entergy\tNuclear\tIndian\tPoint\t2,\tLLC |  | \t Entergy\tPower,\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	105,000	customers.	Competitive	Retail	Services	contributed	approximately	5%	of Entergy's	revenue	in	2004,	but	does	not	currently	have	significant	levels	of	net	income	or	loss,	or	total	assets,	and	Entergy	reports	this	business	as	part	of	All	Other	in its	segment	disclosures.

# Strategy

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

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

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

any	violation	by	Entergy	of	the	New	York	Stock	Exchange	corporate	governance	listing	standards.

Part	I,	Item	1	is	continued	on	page	105.

# ENTERGY	CORPORATION	AND	SUBSIDIARIES

# REPORT	OF	MANAGEMENT

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

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

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

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

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

J.	WAYNE	LEONARD

Chief	Executive	Officer	of	Entergy	Corporation

# HUGH	T.	MCDONALD

LEO	P.	DENAULT

Executive	Vice	President	and	Chief	Financial	Officer	of	Entergy

Corporation

JOSEPH	F.	DOMINO

of	Entergy	Gulf	States,	Inc.

GARY	J.	TAYLOR

Chairman,	President,	and	Chief	Executive	Officer	of	Entergy	New Chairman,	President,	and	Chief	Executive	Officer	of	System

Orleans,	Inc.

THEODORE	H.	BUNTING,	JR.

Vice	President	and	Chief	Financial	Officer	of	System	Energy

Resources,	Inc.

Energy	Resources,	Inc.

JAY	A.	LEWIS

Vice	President	and	Chief	Financial	Officer	of	Entergy	Arkansas,

Inc.,	Entergy	Gulf	States,	Inc.,	Entergy	Louisiana,	Inc.,	Entergy

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

# 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 | Segment | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 |
| U.S.\tUtility |  | 81 | 82 | 82 | 72 | 52 | 97 | 80 | 79 | 79 |
| Non-Utility\tNuclear | Non-Utility\tNuclear | 13 | 14 | 14 | 26 | 32 | 32 | 16 | 15 | 16 |
| Energy | Commodity | 2 | 2 | 4 | - | 19 | (23) | 3 | 7 | 8 |
| Services |  |  |  |  |  |  |  |  |  |  |
| Parent\t&amp;\tOther |  | 4 | 2 | - | 2 | (3) | (6) | 1 | (1) | (3) |

# Results	of	Operations

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

| Operating	Segment | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| U.S.\tUtility | $643,408 | $469,050 | $583,251 |
| Non-Utility\tNuclear | 245,029 | 300,799 | 200,505 |

| Energy	Commodity	Services | 3,481 | 180,454 | (145,830) |
| :--- | :--- | :--- | :--- |
| Parent\t&amp;\tOther | 17,606 | (23,360) | (38,566) |
| Total | $909,524 | $926,943 | $599,360 |

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

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

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

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

# U.S.	UTILITY

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

the	$107.7	million	($65.6	million	net-of-tax)	accrual	in	2003	of	the	loss	that	would	be	associated	with	a	final,	non-appealable	decision	disallowing	abeyed River	Bend	plant	costs.	Refer	to	Note	2	to	the	consolidated	financial	statements	for	more	details	regarding	the	River	Bend	abeyed	plant	costs;

lower	other	operation	and	maintenance	expenses	primarily	due	to	$99.8	million	($70.1	million	net-of-tax)	of	charges	recorded	in	2003	in	connection	with	the voluntary	severance	program;

the	$21.3	million	net-of-tax	cumulative	effect	of	a	change	in	accounting	principle	that	reduced	earnings	at	Entergy	Gulf	States	in	the	first	quarter	of	2003 upon	implementation	of	SFAS	143.	See	"Critical	Accounting	Estimates	-	SFAS	143"	below	for	discussion	of	the	implementation	of	SFAS	143;

miscellaneous	other	income	of	$27.7	million	(pre-tax)	in	2004	resulting	from	a	revision	of	the	decommissioning	liability	for	River	Bend,	as	discussed	in	Note 8	to	the	consolidated	financial	statements;

higher	net	revenue;	and

lower	interest	charges.

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

the	$107.7	million	($65.6	million	net-of-tax)	accrual	in	2003	of	the	loss	that	would	be	associated	with	a	final,	non-appealable	decision	disallowing	abeyed River	Bend	plant	costs;

$99.8	million	($70.1	million	net-of-tax)	of	charges	recorded	in	2003	in	connection	with	the	voluntary	severance	program;	and the	$21.3	million	net-of-tax	cumulative	effect	of	a	change	in	accounting	principle	that	reduced	earnings	at	Entergy	Gulf	States	in	the	first	quarter	of	2003 upon	implementation	of	SFAS	143.	See	"Critical	Accounting	Estimates	-	SFAS	143"	below	for	discussion	of	the	implementation	of	SFAS	143.

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

# Net	Revenue

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

|  | (In	Millions) |
| :--- | :--- |
| 2003\tnet\trevenue | $4,214.5 |
| Volume/weather | 68.3 |
| Summer\tcapacity\tcharges | 17.4 |
| Base\trates | 10.6 |
| Deferred\tfuel\tcost\trevisions | (46.3) |
| Price\tapplied\tto\tunbilled\tsales | (19.3) |
| Other | (1.2) |
| 2004\tnet\trevenue | $4,244.0 |

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

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

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

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

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

# Gross	operating	revenues	and	regulatory	credits

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

Other	regulatory	credits	increased	primarily	due	to	the	following:

cessation	of	the	Grand	Gulf	Accelerated	Recovery	Tariff	that	was	suspended	in	July	2003;

the	amortization	in	2003	of	deferred	capacity	charges	for	summer	2001	power	purchases	at	Entergy	Gulf	States	and	Entergy	Louisiana;

the	deferral	in	2004	of	$14.3	million	of	capacity	charges	related	to	generation	resource	planning	as	allowed	by	the	LPSC;

the	deferral	in	2004	by	Entergy	Louisiana	of	$11.4	million	related	to	the	voluntary	severance	program,	in	accordance	with	a	proposed	stipulation	entered	into with	the	LPSC	staff;	and

the	deferral	in	August	2004	of	$7.5	million	of	fossil	plant	maintenance	and	voluntary	severance	program	costs	at	Entergy	New	Orleans	as	a	result	of	a stipulation	approved	by	the	City	Council.

(In	Millions)

|  | (In	Millions) |
| :--- | :--- |
| 2002\tnet\trevenue | $4,209.6 |
| Base\trate\tincreases | 66.2 |
| Base\trate\tdecreases | (23.3) |
| Deferred\tfuel\tcost\trevisions | 56.2 |
| Asset\tretirement\tobligation | 42.9 |
| Net\twholesale\trevenue | 23.2 |
| March\t2002\tArk.\tsettlement\tagreement | (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	had	a	minimal	impact	on	net	income	due	to	a	corresponding	reduction	in	nuclear	depreciation	and	decommissioning	expenses	associated with	the	change	in	accounting	estimate	to	reflect	an	assumed	extension	of	River	Bend's	useful	life.

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

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

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

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

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

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

# Other	Income	Statement	Variances

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

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

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

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

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

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

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

# insignificant	effect	on	net	income.

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

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

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

# NON-UTILITY	NUCLEAR

Following	are	key	performance	measures	for	Non-Utility	Nuclear:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Net\tMW\tin\toperation\tat\tDecember\t31 | 4,058 | 4,001 | 3,955 |
| Average\trealized\tprice\tper\tMWh | $41.26 | $39.38 | $40.07 |
| Generation\tin\tGWh\tfor\tthe\tyear | 32,524 | 32,379 | 29,953 |
| Capacity\tfactor\tfor\tthe\tyear | 92% | 92% | 93% |

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

lower	operation	and	maintenance	expenses,	which	decreased	from	$681.8	million	in	2003	to	$595.7	million	in	2004,	primarily	resulting	from	charges	recorded in	2003	in	connection	with	the	voluntary	severance	program;

higher	revenues,	which	increased	from	$1.275	billion	in	2003	to	$1.342	billion	in	2004,	primarily	resulting	from	higher	contract	pricing.	The	addition	of	a support	services	contract	for	the	Cooper	Nuclear	Station	and	increased	generation	in	2004	due	to	power	uprates	completed	in	2003	and	fewer	planned	and unplanned	outages	in	2004	also	contributed	to	the	higher	revenues;	and

miscellaneous	income	resulting	from	a	reduction	in	the	decommissioning	liability	for	a	plant,	as	discussed	in	Note	8	to	the	consolidated	financial	statements.

Partially	offsetting	this	increase	were	the	following:

higher	depreciation	expense,	which	increased	from	$34.3	million	in	2003	to	$48.9	million	in	2004,	due	to	additions	to	plant	in	service.

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

# ENERGY	COMMODITY	SERVICES

# Sales	of	Entergy-Koch	Businesses

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

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

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

earnings	from	Entergy's	investment	in	Entergy-Koch	were	$254	million	lower	in	2004,	primarily	as	a	result	of	Entergy-Koch's	trading	business	reporting	a loss	from	its	operations	in	2004;	and

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

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

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

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

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

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

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

$32.7	million	of	the	charges	resulted	from	the	write-off	of	capitalized	project	development	costs	for	projects	that	would	not	be	completed;	and a	gain	of	$25.7	million	($15.9	million	net-of-tax)	realized	on	the	sale	in	August	2002	of	an	interest	in	projects	under	development	in	Spain.

# PARENT	&	OTHER

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

realization	of	$16.7	million	of	tax	benefits	related	to	the	Entergy-Koch	investment;	and

Entergy's	competitive	retail	business	earned	a	very	small	profit	in	2004	compared	to	reporting	a	$14.4	million	loss	in	2003.

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

# Income	Taxes

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

# Liquidity	and	Capital	Resources

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

# Capital	Structure

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Net\tdebt\tto\tnet\tcapital\tat\tthe\tend\tof\tthe\tyear | 44.7% | 45.3% | 47.7% |
| Effect\tof\tsubtracting\tcash\tfrom\tdebt | 2.7% | 2.2% | 4.1% |
| Debt\tto\tcapital\tat\tthe\tend\tof\tthe\tyear | 47.4% | 47.5% | 51.8% |

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

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

| Long-term	debt	maturities | 2004 | 2005 | 2006 | 2007 | 2008-2009 | after	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| As\tof\tDecember\t31,\t2003 |  |  |  |  |  |  |
| U.S.\tUtility | $450 | $355 | $28 | $573 | $721 | $4,305 |
| Non-Utility\tNuclear | 74 | 72 | 76 | 80 | 40 | 173 |
| Energy\tCommodity\tServices | - | - | - | - | - | - |
| Parent\tand\tOther | - | 60 | - | - | 539 | 301 |
| Total | $524 | $487 | $104 | $653 | $1,300 | $4,779 |
| As\tof\tDecember\t31,\t2004 |  |  |  |  |  |  |
| U.S.\tUtility | - | $359 | $27 | $98 | $749 | $4,880 |
| Non-Utility\tNuclear | - | 77 | 76 | 80 | 40 | 173 |
| Energy\tCommodity\tServices | - | - | - | - | - | - |
| Parent\tand\tOther | - | 60 | - | 50 | 539 | 301 |
| Total | - | $496 | $103 | $228 | $1,328 | $5,354 |

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

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

In	December	2004,	Entergy	Corporation	refinanced	the	364-day	bank	credit	facility	by	entering	into	a	five-year	credit	facility.	The	five-year	credit	facility,	which

expires	in	December	2009,	has	a	borrowing	capacity	of	$500	million,	none	of	which	was	outstanding	at	December	31,	2004.

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

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

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

|  | 2005 | 2006 | 2007 | 2008-2009 | after	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Capital\tlease\tpayments,\tincluding\nnuclear\tfuel\tleases | $136 | $143 | $3 | $2 | $3 |

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

| Company | Expiration	Date | Amount	of<br>Facility | Amount	Drawn	as	of<br>Dec.	31,	2004 |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | April\t2005 | $85\tmillion | - |
| Entergy\tLouisiana | April\t2005 | $15\tmillion\t(a) | - |
| Entergy\tMississippi | May\t2005 | $25\tmillion | - |

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

# Operating	Lease	Obligations	and	Guarantees	of	Unconsolidated	Obligations

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

|  | 2005 | 2006 | 2007 | 2008-2009 | after	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Operating\tlease\tpayments | $99 | $86 | $69 | $100 | $210 |

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

| Contractual	Obligations | 2005 | 2006-2007 | 2008-2009 | after	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(1) | $496 | $331 | $1,328 | $5,354 | $7,509 |
| Capital\tlease\tpayments\t(2) | $136 | $146 | $2 | $3 | $287 |
| Operating\tleases\t(2) | $99 | $155 | $100 | $210 | $564 |
| Purchase\tobligations\t(3) | $1,160 | $1,402 | $962 | $1,156 | $4,680 |

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

(2) Capital	lease	payments	include	nuclear	fuel	leases.	Lease	obligations	are	discussed	in	Note	9	to	the consolidated	financial	statements.

(3) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	Approximately	99%	of	the	total	pertains	to fuel	and	purchased	power	obligations	that	are	recovered	in	the	normal	course	of	business	through various	fuel	cost	recovery	mechanisms	in	the	U.S.	Utility	business.

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

# Capital	Funds	Agreement

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

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

permit	the	continued	commercial	operation	of	Grand	Gulf;

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

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

# Capital	Expenditure	Plans	and	Other	Uses	of	Capital

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

| Planned	construction	and	capital	investments | 2005 | 2006 | 2007 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Maintenance\tCapital: |  |  |  |
| U.S.\tUtility | $734 | $699 | $763 |
| Non-Utility\tNuclear | 72 | 72 | 60 |
| Energy\tCommodity\tServices | 3 | 4 | 6 |
| Parent\tand\tOther | 11 | 19 | 11 |
|  | 820 | 794 | 840 |
| Capital\tCommitments:\nU.S.\tUtility | 571 | 349 | 201 |

| Non-Utility	Nuclear | 90 | 67 | 43 |
| :--- | :--- | :--- | :--- |
| Energy\tCommodity\tServices | - | - | - |
| Parent\tand\tOther | - | - | - |
|  | 661 | 416 | 244 |
| Total | $1,481 | $1,210 | $1,084 |

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

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

Replacement	of	the	ANO	1	steam	generators	and	reactor	vessel	closure	head.	Management	estimates	the	cost	of	the	ANO	1	project	to	be	approximately	$235 million,	of	which	approximately	$96	million	has	been	incurred	through	2004.	$115	million	is	expected	to	be	incurred	in	2005,	with	the	remainder	expected	to be	spent	in	2006.	Entergy	expects	the	replacement	to	occur	during	a	planned	refueling	outage	in	2005.	Entergy	Arkansas	filed	with	the	APSC	in	January	2003 a	request	for	a	declaratory	order	that	the	investment	in	the	replacement	is	in	the	public	interest.	The	APSC	issued	the	requested	order	in	May	2003.	This	order is	analogous	to	the	order	received	in	1998	prior	to	the	replacement	of	the	ANO	2	steam	generators.

Purchase	of	the	Perryville	power	plant	in	Louisiana.	In	January	2004,	Entergy	Louisiana	signed	a	definitive	agreement	to	acquire	the	718	MW	Perryville power	plant	for	$170	million.	The	agreement	has	subsequently	been	amended	to	allow	the	current	plant	owner	to	retain	the	interconnection	facilities associated	with	the	plant,	resulting	in	a	decrease	in	the	acquisition	price	to	$162	million.	As	a	result	of	the	amended	terms,	the	FERC	issued	an	order	in October	2004	disclaiming	jurisdiction	over	the	acquisition.	This	order	currently	is	subject	to	rehearing	by	the	FERC.	The	plant	is	owned	by	a	subsidiary	of Cleco	Corporation,	which	subsidiary	submitted	a	bid	in	response	to	Entergy's	Fall	2002	request	for	proposals	for	supply-side	resources.	The	signing	of	the agreement	followed	a	voluntary	Chapter	11	bankruptcy	filing	by	the	plant's	owner.	Entergy	expects	that	Entergy	Louisiana	will	own	100	percent	of	the Perryville	plant,	and	that	Entergy	Louisiana	will	sell	75	percent	of	the	output	to	Entergy	Gulf	States	under	a	long-term	cost-of-service	power	purchase agreement.	In	addition,	Entergy	Louisiana	and	Entergy	Gulf	States	executed	an	interim	power	purchase	agreement	with	the	plant's	owner	through	the	date	of the	acquisition's	closing	(as	long	as	that	occurs	by	December	2005)	for	100	percent	of	the	output	of	the	Perryville	power	plant.	In	April	2004,	the	bankruptcy court	approved	Entergy	Louisiana's	agreement	to	acquire	the	plant.	In	March	2004,	Entergy	Gulf	States	and	Entergy	Louisiana	filed	with	the	LPSC	for	its approval	of	the	acquisition	and	long-term	cost-of-service	power	purchase	agreement.	Entergy	is	seeking	approval	from	the	LPSC	of	cost	recovery	for	the acquisition,	giving	consideration	to	the	need	for	the	power	and	the	prudence	of	Entergy	Louisiana	and	Entergy	Gulf	States	in	engaging	in	the	transaction. Hearings	are	scheduled	for	March	2005.	Assuming	regulatory	approval	by	the	LPSC,	Entergy	Louisiana	expects	the	Perryville	acquisition	to	close	in	mid- 2005.

Transmission	expansion	designed	to	address	immediate	load	growth	needs	and	to	provide	improved	transmission	flexibility	for	the	southeastern	Louisiana	and Texas	regions	of	Entergy's	service	territory.	Entergy	expects	to	spend	$170	million	on	high	voltage	transmission	infrastructure	to	be	completed	in	phases between	mid-2005	to	mid-2007.

Purchase	of	additional	generation	supply	sources	within	the	U.S.	Utility's	service	territory.

Nuclear	power	plant	uprates,	dry	cask	spent	fuel	storage,	and	license	renewals.

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

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

# Dividends	and	Stock	Repurchases

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

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

# PUHCA	Restrictions	on	Uses	of	Capital

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

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

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

# Sources	of	Capital

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

internally	generated	funds;

securities	issuances;

bank	financing	under	new	or	existing	facilities;	and

sales	of	assets.

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

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

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

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

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

# Cash	Flow	Activity

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $692 | $1,335 | $752 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 2,929 | 2,006 | 2,181 |
| Investing\tactivities | (1,140) | (1,783) | (1,388) |
| Financing\tactivities | (1,672) | (869) | (213) |
| Effect\tof\texchange\trates\ton\tcash\tand\tcash\tequivalents | (1) | 3 | 3 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 116 | (643) | 583 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $808 | $692 | $1,335 |

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

The	U.S.	Utility	provided	$2,208	million	in	cash	from	operating	activities	compared	to	providing	$1,675	million	in	2003.	The	increase	resulted	primarily	from the	receipt	of	intercompany	income	tax	refunds	from	the	parent	company,	Entergy	Corporation.	Income	tax	refunds/payments	contributed	approximately $400	million	of	the	increase	in	cash	from	operating	activities	in	2004.	Improved	recovery	of	fuel	costs	and	a	reduction	in	interest	paid	also	contributed	to	the increase	in	2004.

The	Non-Utility	Nuclear	business	provided	$415	million	in	cash	from	operating	activities	compared	to	providing	$183	million	in	2003.	The	increase	resulted primarily	from	lower	intercompany	income	tax	payments	and	increases	in	generation	and	contract	pricing	that	led	to	an	increase	in	revenues.

Entergy's	investment	in	Entergy-Koch,	LP	provided	$526	million	in	cash	from	operating	activities	compared	to	using	$41	million	in	2003.	Entergy	received dividends	from	Entergy-Koch	of	$529	million	in	2004	compared	to	$100	million	in	2003.	In	addition,	tax	payments	related	to	the	investment	were	higher	in 2003	because	the	investment	had	higher	net	income	in	2003.

The	non-nuclear	wholesale	asset	business	used	$46	million	in	cash	from	operating	activities	compared	to	using	$70	million	in	2003.	The	decrease	in	cash	used resulted	primarily	from	a	one-time	$33	million	payment	in	2003	related	to	a	generation	contract	in	the	non-nuclear	wholesale	assets	business.

The	parent	company,	Entergy	Corporation,	used	$146	million	in	cash	from	operating	activities	in	2004	compared	to	providing	$209	million	in	2003	primarily due	to	higher	intercompany	income	tax	payments.

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

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

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

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

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

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

investment	in	Entergy-Koch	due	to	increased	income	from	the	investment.

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

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

In	a	September	2002	settlement	of	an	LPSC	proceeding	that	concerned	the	Vidalia	contract,	the	LPSC	approved	Entergy	Louisiana's	proposed	treatment	of	the regulatory	impact	of	the	tax	accounting	election.	In	general,	the	settlement	permits	Entergy	Louisiana	to	keep	a	portion	of	the	tax	benefit	in	exchange	for	bearing	the risk	associated	with	sustaining	the	tax	treatment.	The	LPSC	settlement	divided	the	term	of	the	Vidalia	contract	into	two	segments:	2002-2012	and	2013-2031. During	the	first	eight	years	of	the	2002-2012	segment,	Entergy	Louisiana	agreed	to	credit	rates	by	flowing	through	its	fuel	adjustment	calculation	$11	million	each year,	beginning	monthly	in	October	2002.	Entergy	Louisiana	must	credit	rates	in	this	way	and	by	this	amount	even	if	Entergy	Louisiana	is	unable	to	sustain	the	tax deduction.	Entergy	Louisiana	also	must	credit	rates	by	$11	million	each	year	for	an	additional	 two	years	unless	either	 the	 tax	accounting	method	elected	 is retroactively	 repealed	 or	 the	 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	decreased	in	2004	primarily	due	to	the	following:

Construction	expenditures	were	$158	million	lower	in	2004	than	in	2003,	including	decreases	of	$81	million	in	the	U.S.	Utility	business,	$39	million	in	the Non-Utility	Nuclear	business,	and	$42	million	in	the	non-nuclear	wholesale	assets	business.

Entergy	received	net	returns	of	invested	capital	from	Entergy-Koch	of	$284	million	in	2004	after	the	sale	by	Entergy-Koch	of	its	trading	and	pipeline businesses.	This	activity	is	reported	in	the	"Decrease	in	other	investments"	line	in	the	cash	flow	statement.

Approximately	$60	million	of	the	cash	collateral	for	a	letter	of	credit	that	secures	the	installment	obligations	owed	to	NYPA	for	the	acquisition	of	the FitzPatrick	and	Indian	Point	3	nuclear	power	plants	was	released	to	Entergy	in	2004.	Approximately	$172	million	of	this	cash	collateral	was	released	to Entergy	in	2003,	and	the	letter	of	credit	is	no	longer	secured	by	cash	collateral.	This	activity	is	reported	in	the	"Decrease	in	other	investments"	line	in	the	cash flow	statement.

The	non-nuclear	wholesale	assets	business	realized	$75	million	in	net	proceeds	from	sales	of	portions	of	three	of	its	power	plants	in	2004.

Entergy	made	temporary	investments	of	$50	million	in	2003,	and	these	investments	matured	in	the	first	quarter	of	2004.

Entergy	Arkansas	used	$7	million,	Entergy	Gulf	States	used	$77	million,	and	Entergy	Mississippi	used	$73	million	for	other	regulatory	investments	in	2003 as	a	result	of	fuel	cost	under-recovery.	In	2004,	Entergy	Arkansas	used	$4	million	and	Entergy	Gulf	States	used	$50	million	for	other	regulatory	investments related	to	fuel	cost	under-recovery.	See	Note	1	to	the	consolidated	financial	statements	for	discussion	of	the	accounting	treatment	of	these	fuel	cost	under- recoveries.

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

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

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

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

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

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

# Financing	Activities

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

Entergy	Corporation	issued	$538	million	of	long-term	notes	in	2003.

Entergy	Corporation	repurchased	$1.018	billion	of	its	common	stock	in	2004,	as	discussed	above	in	the	"Uses	of	Capital"	section.

Entergy	Corporation	paid	$65	million	more	in	common	stock	dividends	in	2004	than	in	2003.

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

Retirements	of	long-term	debt	net	of	issuances	by	the	U.S.	Utility	segment	used	$345	million	in	2004	and	used	$359	million	in	2003.	See	Note	5	to	the consolidated	financial	statements	for	the	details	of	the	long-term	debt	activity	in	2004.

In	2003,	Entergy	Corporation	decreased	the	net	borrowings	on	its	credit	facility	by	$500	million,	while	in	2004,	net	borrowings	on	its	credit	facilities increased	by	$50	million.

The	non-nuclear	wholesale	assets	business	retired	the	$79	million	Top	of	Iowa	wind	project	debt	at	its	maturity	in	January	2003.

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

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

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

# Significant	Factors	and	Known	Trends

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

# State	and	Local	Rate	Regulation	and	Fuel-Cost	Recovery

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

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

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

(2) Under	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	if	Entergy	Mississippi's	earned ROE	 is	 above	 the	 top	 of	 the	 range-of-no-change	 at	 the	 top	 of	 the	 bandwidth,	 then	 Entergy Mississippi's	rates	are	reduced	by	50	percent	of	the	difference	between	the	earned	ROE	and	the	top	of the	 bandwidth.	In	such	circumstance,	Entergy	Mississippi's	"Allowed	ROE"	for	 the	next	 twelve- month	period	is	the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth	-	Entergy Mississippi's	retail	rates	are	set	at	that	halfway-point	ROE	level.	(Before	the	comparison	is	made	of the	earned	ROE	to	the	bandwidth,	the	bandwidth	can	be	adjusted	for	performance	measures	by	as much	as	1%.	Rates	are	adjusted	pursuant	to	Entergy	Mississippi's	formula	rate	plan	on	a	prospective basis	 only.)	In	the	situation	where	Entergy	Mississippi's	earned	ROE	is	not	above	the	top	of	the range-of-no-change	at	the	top	of	the	bandwidth,	then	Entergy	Mississippi's	"Allowed	ROE"	for	the next	 twelve-month	 period	 is	 the	 top	 of	 the	 range-of-no-change	 at	 the	 top	 of	 the	 bandwidth.	If earnings	are	below	the	bandwidth	range,	rates	are	increased	by	50	percent	of	the	difference	between the	earned	ROE	and	 the	bottom	of	 the	bandwidth.	Under	the	provisions	of	Entergy	Mississippi's formula	 rate	 plan,	 each	 annual	 formula	 rate	 plan	 filing	 incorporates	 a	 revised	 calculation	 of	 the benchmark	ROE.

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

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

# Federal	Regulation

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

# System	Agreement	Litigation

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

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

If	the	FERC	grants	the	relief	requested	by	the	LPSC	in	the	proceeding,	the	relief	may	result	in	a	material	increase	in	the	total	production	costs	the	FERC	allocates	to companies	whose	costs	currently	are	projected	to	be	less	than	the	Entergy	System	average,	and	a	material	decrease	in	the	total	production	costs	the	FERC	allocates to	companies	whose	costs	currently	are	projected	to	exceed	that	average.			If	the	FERC	adopts	the	ALJ's	Initial	Decision,	the	amount	of	production	costs	that	would be	reallocated	among	the	domestic	utility	companies	would	be	determined	through	consideration	of	each	domestic	utility	company's	relative	total	production	cost

expressed	as	a	percentage	of	Entergy	System	average	total	production	cost.	The	ALJ's	Initial	Decision	would	reallocate	production	costs	of	the	domestic	utility companies	whose	percent	of	Entergy	System	average	production	cost	are	outside	an	upper	or	lower	bandwidth.	This	would	be	accomplished	by	payments	from domestic	utility	companies	whose	production	costs	are	below	Entergy	System	average	production	cost	to	domestic	utility	companies	whose	production	costs	are above	Entergy	System	average	production	cost.

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

|  | Range	of	Annual	Payments<br>or	(Receipts)<br>(In	Millions) | Average	Annual<br>Payments	or	(Receipts)<br>for	2005-2009	Period<br>(In	Millions) |
| :--- | :--- | :--- |
| Entergy\tArkansas | $154\tto\t$281 | $215 |
| Entergy\tGulf\tStates | ($130)\tto\t($15) | ($63) |
| Entergy\tLouisiana | ($199)\tto\t($98) | ($141) |
| Entergy\tMississippi | ($16)\tto\t$8 | $1 |
| Entergy\tNew\tOrleans | ($17)\tto\t($5) | ($12) |

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

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

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

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

# Transmission

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

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

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

In	January	2005,	Entergy	filed	a	petition	for	declaratory	order	with	the	FERC	requesting	that	the	FERC	provide	guidance	on	two	important	issues:	(1)	whether	the functions	performed	by	the	ICT	will	cause	it	to	become	a	"public	utility"	under	the	Federal	Power	Act	or	the	"transmission	provider"	under	Entergy's	open	access transmission	tariff;	and	(2)	whether	Entergy's	transmission	pricing	proposal,	as	administered	by	the	ICT,	satisfies	the	FERC's	transmission	pricing	policy.	The petition	also	indicates	that,	subject	to	the	outcome	of	the	petition	and	obtaining	support	of	Entergy's	retail	regulators,	Entergy	would	be	willing	to	have	the	ICT perform	the	following	additional	functions:	(a)	grant	or	deny	requests	for	transmission	service;	(b)	calculate	available	flowgate	capacity;	(c)	administer	Entergy's

OASIS;	and	(d)	perform	an	enhanced	planning	function	(integrating	the	plans	of	Entergy	and	other	potential	transmission	owners	to	identify	regional	synergies.) Comments	and	interventions	on	the	petition	were	filed	by	market	participants	and	retail	regulators	on	February	4,	2005.	In	their	individual	comments,	the	APSC, LPSC,	and	City	Council	supported	Entergy's	position	that	the	ICT	would	not	become	a	"public	utility"	or	"transmission	provider"	and	that	the	transmission	pricing proposal	satisfies	the	FERC's	transmission	pricing	policy.	Certain	other	parties	urged	the	FERC	to	reject	the	petition	for	declaratory	order	or,	in	the	alternative,	that the	FERC	assert	jurisdiction	over	the	ICT	and	determine	that	Entergy's	proposed	pricing	policy	is	inconsistent	with	FERC's	current	pricing	policy.	FERC	action	on the	petition	is	expected	during	the	first	half	of	2005.

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

# FERC's	Supply	Margin	Assessment

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

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

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

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

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

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

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

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

# Interconnection	Orders

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

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

refunded	in	the	form	of	transmission	credits,	to	be	utilized	over	time	and	applied	to	Entergy	transmission	service	bills	incurred	after	March	2001.	Entergy	has	sought rehearing	of	the	FERC's	order.

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

# Available	Flowgate	Capacity	Proceeding

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

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

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

# Federal	Legislation

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

# Market	and	Credit	Risks

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

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

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

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

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

# Commodity	Price	Risk

# Power	Generation

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

|  | 2005 | 2006 | 2007 | 2008 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Non-Utility\tNuclear: |  |  |  |  |  |
| Percent\tof\tplanned\tgeneration\tsold\tforward: |  |  |  |  |  |
| Unit-contingent | 36% | 20% | 17% | 1% | 0% |
| Unit-contingent\twith\tavailability\tguarantees | 54% | 52% | 38% | 25% | 0% |
| Firm\tliquidated\tdamages | 4% | 4% | 2% | 0% | 0% |
| Total | 94% | 76% | 57% | 26% | 0% |
| Planned\tgeneration\t(TWh) | 34 | 35 | 34 | 34 | 35 |
| Average\tcontracted\tprice\tper\tMWh | $39 | $41 | $42 | $44 | N/A |

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

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

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

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

|  | 2005 | 2006 | 2007 | 2008 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Non-Utility\tNuclear: |  |  |  |  |  |
| Percent\tof\tcapacity\tsold\tforward: |  |  |  |  |  |
| Bundled\tcapacity\tand\tenergy\tcontracts | 13% | 13% | 13% | 13% | 13% |
| Capacity\tcontracts | 58% | 67% | 36% | 22% | 10% |
| Total | 71% | 80% | 49% | 35% | 23% |
| Planned\tnet\tMW\tin\toperation | 4,155 | 4,200 | 4,200 | 4,200 | 4,200 |
| Average\tcapacity\tcontract\tprice\tper\tkW\tper\tmonth | $1.2 | $1.1 | $1.1 | $1.0 | $0.9 |
| Blended\tCapacity\tand\tEnergy\t(based\ton\trevenues) |  |  |  |  |  |
| %\tof\tplanned\tgeneration\tand\tcapacity\tsold\tforward | 93% | 87% | 65% | 36% | 12% |
| Average\tcontract\trevenue\tper\tMWh | $40 | $42 | $43 | $44 | $43 |

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

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

|  | 2005 | 2006 | 2007 | 2008 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy\tCommodity\tServices: |  |  |  |  |  |
| Capacity |  |  |  |  |  |
| Planned\tMW\tin\toperation | 1,578 | 1,578 | 1,578 | 1,578 | 1,578 |
| %\tof\tcapacity\tsold\tforward | 44% | 33% | 29% | 29% | 19% |
| Energy |  |  |  |  |  |
| Planned\tgeneration\t(TWh) | 3 | 3 | 3 | 3 | 4 |
| %\tof\tplanned\tgeneration\tsold\tforward | 69% | 54% | 45% | 45% | 35% |
| Blended\tCapacity\tand\tEnergy\t(based\ton\trevenues) |  |  |  |  |  |
| %\tof\tplanned\tenergy\tand\tcapacity\tsold\tforward | 63% | 44% | 38% | 39% | 22% |
| Average\tcontract\trevenue\tper\tMWh | $24 | $24 | $28 | $28 | $21 |

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

# Foreign	Currency	Exchange	Rate	Risk

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

# Interest	Rate	and	Equity	Price	Risk	-	Decommissioning	Trust	Funds

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

# Nuclear	Matters

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

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

# Litigation

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

# Critical	Accounting	Estimates

The	preparation	of	Entergy's	financial	statements	in	conformity	with	generally	accepted	accounting	principles	requires	management	to	apply	appropriate	accounting policies	and	to	make	estimates	and	judgments	that	can	have	a	significant	effect	on	reported	financial	position,	results	of	operations,	and	cash	flows.	Management	has

identified	the	following	accounting	policies	and	estimates	as	critical	because	they	are	based	on	assumptions	and	measurements	that	involve	a	high	degree	of uncertainty,	and	the	potential	for	future	changes	in	the	assumptions	and	measurements	that	could	produce	estimates	that	would	have	a	material	effect	on	the presentation	of	Entergy's	financial	position	or	results	of	operations.

# Nuclear	Decommissioning	Costs

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

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

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

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

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

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

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

Discount	rate	-	SFAS	143	requires	that	these	obligations	be	discounted	using	a	credit-adjusted,	risk-free	rate.

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

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

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

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

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

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

In	the	third	quarter	of	2004,	Entergy's	Non-Utility	Nuclear	business	recorded	a	reduction	of	$20.3	million	in	its	decommissioning	cost	liability	to	reflect	changes	in assumptions	regarding	the	timing	of	when	the	decommissioning	of	a	plant	will	begin.	Entergy	considered	the	assumptions	as	part	of	recent	studies	evaluating	the

economic	effect	of	the	plant	in	its	region.	The	revised	estimate	resulted	in	miscellaneous	income	of	$20.3	million,	reflecting	the	excess	of	the	reduction	in	the liability	over	the	amount	of	undepreciated	asset	retirement	cost	recorded	at	the	time	of	adoption	of	SFAS	143.

# Unbilled	Revenue

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

# Impairment	of	Long-lived	Assets

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

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

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

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

Market	value	of	generation	assets	-	Valuing	assets	held	for	sale	requires	estimating	the	current	market	value	of	generation	assets.	While	market	transactions provide	evidence	for	this	valuation,	the	market	for	such	assets	is	volatile	and	the	value	of	individual	assets	is	impacted	by	factors	unique	to	those	assets. Future	operating	costs	-	Entergy	assumes	relatively	minor	annual	increases	in	operating	costs.	Technological	or	regulatory	changes	that	have	a	significant impact	on	operations	could	cause	a	significant	change	in	these	assumptions.

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

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

# Pension	and	Other	Postretirement	Benefits

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

# Assumptions

Key	actuarial	assumptions	utilized	in	determining	these	costs	include:

Discount	rates	used	in	determining	the	future	benefit	obligations;

Projected	health	care	cost	trend	rates;

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

Rate	of	increase	in	future	compensation	levels.

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

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

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

# Cost	Sensitivity

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

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $10,268 | $94,903 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $4,388 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $4,928 | $29,134 |

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

|  | Change	in | Impact	on	2004 | Postretirement	Benefit |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Postretirement\tBenefit\tCost | Obligation |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $4,150 | $23,892 |
| Discount\trate | (0.25%) | $2,715 | $28,719 |

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

# Accounting	Mechanisms

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

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

# Costs	and	Funding

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

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

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

# Other	Contingencies

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

# Environmental

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

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

The	identification	of	additional	sites	or	the	filing	of	other	complaints	in	which	Entergy	may	be	asserted	to	be	a	potentially	responsible	party. The	resolution	or	progression	of	existing	matters	through	the	court	system	or	resolution	by	the	EPA.

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

# Sales	Warranty	and	Tax	Reserves

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

(Page	left	blank	intentionally)

# SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON

| Operating	revenues | $10,123,724 | $9,194,920 | $8,305,035 | $9,620,899	$10,022,129 | $9,620,899	$10,022,129 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tbefore\tcumulative\teffect\tof\taccounting\tchange | $933,049 | $813,393 | $623,072 | $727,025 | $710,915 |
| Earnings\tper\tshare\tbefore\tcumulative\teffect\tof\taccounting\tchange |  |  |  |  |  |
| \t\tBasic | $4.01 | $3.48 | $2.69 | $3.18 | $3.00 |
| \t\tDiluted | $3.93 | $3.42 | $2.64 | $3.13 | $2.97 |
| Dividends\tdeclared\tper\tshare | $1.89 | $1.60 | $1.34 | $1.28 | $1.22 |
| Return\ton\tcommon\tequity | 10.70% | 11.21% | 7.85% | 10.04% | 9.62% |
| Book\tvalue\tper\tshare,\tyear-end | $38.25 | $38.02 | $35.24 | $33.78 | $31.89 |

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

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $2,842 | $2,683 | $2,440 | $2,613 | $2,525 |
| \t\tCommercial | 2,045 | 1,882 | 1,673 | 1,860 | 1,700 |
| \t\tIndustrial | 2,311 | 2,082 | 1,850 | 2,299 | 2,177 |
| \t\tGovernmental | 200 | 195 | 179 | 205 | 185 |
| \t\t\t\tTotal\tretail | 7,398 | 6,842 | 6,142 | 6,977 | 6,587 |
| \t\tSales\tfor\tresale | 390 | 371 | 330 | 395 | 424 |
| \t\tOther\t(1) | 145 | 184 | 174 | (127) | 209 |
| \t\t\t\tTotal | $7,933 | $7,397 | $6,646 | $7,245 | $7,220 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| \t\tResidential | 32,897 | 32,817 | 32,581 | 31,080 | 31,998 |
| \t\tCommercial | 26,468 | 25,863 | 25,354 | 24,706 | 24,657 |
| \t\tIndustrial | 40,293 | 38,637 | 41,018 | 41,577 | 43,956 |
| \t\tGovernmental | 2,568 | 2,651 | 2,678 | 2,593 | 2,605 |
| \t\t\t\tTotal\tretail | 102,226 | 99,968 | 101,631 | 99,956 | 103,216 |
| \t\tSales\tfor\tresale | 8,623 | 9,248 | 9,828 | 8,896 | 9,794 |
| \t\t\t\tTotal | 110,849 | 109,216 | 111,459 | 108,852 | 113,010 |

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

# REPORT	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

To	the	Board	of	Directors	and	Shareholders Entergy	Corporation:

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

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

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

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

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

DELOITTE	&	TOUCHE	LLP

New	Orleans,	Louisiana March	8,	2005

CONSOLIDATED	STATEMENTS	OF	INCOME

| Domestic	electric | $7,932,577 | $7,397,175 | $6,646,414 |
| :--- | :--- | :--- | :--- |
| Natural\tgas | 208,499 | 186,176 | 125,353 |
| Competitive\tbusinesses | 1,982,648 | 1,611,569 | 1,533,268 |
| TOTAL | 10,123,724 | 9,194,920 | 8,305,035 |
| OPERATING\tEXPENSES |  |  |  |
| Operating\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 2,488,208 | 1,987,217 | 2,154,596 |
| \t\tPurchased\tpower | 2,092,922 | 1,728,526 | 833,829 |
| \t\tNuclear\trefueling\toutage\texpenses | 166,072 | 159,995 | 105,592 |
| \t\tProvisions\tfor\tturbine\tcommitments,\tasset\timpairments |  |  |  |
| \t\t\tand\trestructuring\tcharges | 55,000 | (7,743) | 428,456 |
| \t\tOther\toperation\tand\tmaintenance | 2,303,561 | 2,453,869 | 2,486,617 |
| Decommissioning | 149,529 | 146,100 | 76,417 |
| Taxes\tother\tthan\tincome\ttaxes | 409,886 | 405,659 | 380,462 |
| Depreciation\tand\tamortization | 895,593 | 850,503 | 839,181 |
| Other\tregulatory\tcredits\t-\tnet | (90,611) | (13,761) | (141,836) |
| TOTAL | 8,470,160 | 7,710,365 | 7,163,314 |
| OPERATING\tINCOME | 1,653,564 | 1,484,555 | 1,141,721 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 39,582 | 42,710 | 31,658 |
| Interest\tand\tdividend\tincome | 109,809 | 87,386 | 118,325 |
| Equity\tin\tearnings\t(loss)\tof\tunconsolidated\tequity\taffiliates | (78,727) | 271,647 | 183,878 |
| Miscellaneous\t-\tnet | 53,752 | (76,505) | 13,892 |
| TOTAL | 124,416 | 325,238 | 347,753 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 463,384 | 485,964 | 526,442 |
| Other\tinterest\t-\tnet | 41,380 | 53,553 | 70,560 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (25,741) | (33,191) | (24,538) |
| TOTAL | 479,023 | 506,326 | 572,464 |
| INCOME\tBEFORE\tINCOME\tTAXES\tAND\nCUMULATIVE\tEFFECT\tOF\tACCOUNTING\tCHANGES | 1,298,957 | 1,303,467 | 917,010 |
| Income\ttaxes | 365,908 | 490,074 | 293,938 |
| INCOME\tBEFORE\tCUMULATIVE\tEFFECT\nOF\tACCOUNTING\tCHANGES | 933,049 | 813,393 | 623,072 |
| CUMULATIVE\tEFFECT\tOF\tACCOUNTING\nCHANGES\t(net\tof\tincome\ttaxes\tof\t$89,925) | - | 137,074 | - |
| CONSOLIDATED\tNET\tINCOME | 933,049 | 950,467 | 623,072 |
| Preferred\tdividend\trequirements\tand\tother | 23,525 | 23,524 | 23,712 |
| EARNINGS\tAPPLICABLE\tTO\nCOMMON\tSTOCK | $909,524 | $926,943 | $599,360 |
| Earnings\tper\taverage\tcommon\tshare\tbefore\tcumulative |  |  |  |
| effect\tof\taccounting\tchanges: |  |  |  |
| \t\tBasic | $4.01 | $3.48 | $2.69 |
| \t\tDiluted | $3.93 | $3.42 | $2.64 |
| Earnings\tper\taverage\tcommon\tshare: |  |  |  |
| \t\tBasic | $4.01 | $4.09 | $2.69 |
| \t\tDiluted | $3.93 | $4.01 | $2.64 |
| Dividends\tdeclared\tper\tcommon\tshare | $1.89 | $1.60 | $1.34 |
| Average\tnumber\tof\tcommon\tshares\toutstanding: |  |  |  |
| \t\tBasic | 226,863,758 | 226,804,370 | 223,047,431 |
| \t\tDiluted | 231,193,686 | 231,146,040 | 227,303,103 |

See	Notes	to	Consolidated	Financial	Statements.

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

		For	the	Years	Ended	December	31,

# (In	Thousands)

# OPERATING	ACTIVITIES

| Consolidated	net	income | $933,049 | $950,467 | $623,072 |
| :--- | :--- | :--- | :--- |
| Adjustments\tto\treconcile\tconsolidated\tnet\tincome\tto\tnet\tcash\tflow |  |  |  |
| provided\tby\toperating\tactivities: |  |  |  |
| \t\tReserve\tfor\tregulatory\tadjustments | 33,533 | 13,090 | 18,848 |
| \t\tOther\tregulatory\tcredits\t-\tnet | (90,611) | (13,761) | (141,836) |
| \t\tDepreciation,\tamortization,\tand\tdecommissioning | 1,045,122 | 996,603 | 915,597 |
| \t\tDeferred\tincome\ttaxes\tand\tinvestment\ttax\tcredits | 275,458 | 1,189,531 | (256,664) |
| \t\tCumulative\teffect\tof\taccounting\tchanges | - | (137,074) | - |
| \t\tEquity\tin\tearnings\t(loss)\tof\tunconsolidated\tequity\taffiliates\t-\tnet\tof\tdividends | 608,141 | (176,036) | (181,878) |
| \t\tProvisions\tfor\tturbine\tcommitments,\tasset\timpairments,\tand\trestructuring\tcharges | 55,000 | (7,743) | 428,456 |
| \t\tChanges\tin\tworking\tcapital: |  |  |  |
| \t\t\t\tReceivables | (210,419) | (140,612) | (43,957) |
| \t\t\t\tFuel\tinventory | (16,769) | (14,015) | 1,030 |
| \t\t\t\tAccounts\tpayable | 95,306 | (60,164) | 286,230 |
| \t\t\t\tTaxes\taccrued | 75,055 | (882,446) | 462,956 |
| \t\t\t\tInterest\taccrued | 5,269 | (35,837) | 7,209 |
| \t\t\t\tDeferred\tfuel | 213,627 | (33,874) | 156,181 |
| \t\t\t\tOther\tworking\tcapital\taccounts | 41,008 | 16,809 | (286,232) |
| \t\tProvision\tfor\testimated\tlosses\tand\treserves | (18,041) | 196,619 | 10,533 |
| \t\tChanges\tin\tother\tregulatory\tassets | 48,626 | 22,671 | 71,132 |
| \t\tOther | (164,035) | 121,592 | 111,026 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 2,929,319 | 2,005,820 | 2,181,703 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction/capital\texpenditures | \t(1,410,610)\t(1,568,943) | \t(1,410,610)\t(1,568,943) | (1,530,301) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 39,582 | 42,710 | 31,658 |
| Nuclear\tfuel\tpurchases | (238,170) | (224,308) | (250,309) |
| Proceeds\tfrom\tsale/leaseback\tof\tnuclear\tfuel | 109,988 | 150,135 | 183,664 |
| Proceeds\tfrom\tsale\tof\tassets\tand\tbusinesses | 75,430 | 25,987 | 215,088 |
| Investment\tin\tnonutility\tproperties | (6,420) | (71,438) | (216,956) |
| Decrease\tin\tother\tinvestments | 383,498 | 172,187 | 38,964 |
| Changes\tin\tother\ttemporary\tinvestments | 50,000 | (50,000) | 150,000 |
| Decommissioning\ttrust\tcontributions\tand\trealized\tchange\tin\ttrust\tassets | (89,807) | (91,518) | (84,914) |
| Other\tregulatory\tinvestments | (53,566) | (156,446) | (39,390) |
| Other | - | (11,496) | 114,033 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | \t(1,140,075)\t(1,783,130) | \t(1,140,075)\t(1,783,130) | (1,388,463) |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof: |  |  |  |
| \t\tLong-term\tdebt | 1,059,824 | 2,221,164 | 1,197,330 |
| \t\tCommon\tstock\tand\ttreasury\tstock | 170,237 | 217,521 | 130,061 |
| Retirement\tof\tlong-term\tdebt | \t(1,478,894)\t(2,409,917) | \t(1,478,894)\t(2,409,917) | (1,341,274) |
| Repurchase\tof\tcommon\tstock | \t(1,017,996) | (8,135) | (118,499) |
| Redemption\tof\tpreferred\tstock | (3,450) | (3,450) | (1,858) |
| Changes\tin\tcredit\tline\tborrowings\t-\tnet | 49,846 | (499,975) | 244,333 |
| Dividends\tpaid: |  |  |  |
| \t\tCommon\tstock | (427,901) | (362,814) | (298,991) |
| \t\tPreferred\tstock | (23,525) | (23,524) | (23,712) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | \t(1,671,859) | (869,130) | (212,610) |
| Effect\tof\texchange\trates\ton\tcash\tand\tcash\tequivalents | (1,882) | 3,345 | 3,125 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 115,503 | (643,095) | 583,755 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 692,233 | 1,335,328 | 751,573 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $807,736 | $692,233\t\t$1,335,328 | $692,233\t\t$1,335,328 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| \t\tCash\tpaid\tduring\tthe\tperiod\tfor: |  |  |  |
| \t\t\t\tInterest\t-\tnet\tof\tamount\tcapitalized | $477,768 | $552,017 | $633,931 |
| \t\t\t\tIncome\ttaxes | $28,241 | $188,709 | $57,856 |
| \t\tNoncash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| \t\t\t\tDebt\tassumed\tby\tthe\tDamhead\tCreek\tpurchaser | - | - | $488,432 |
| \t\t\t\tDecommissioning\ttrust\tfunds\tacquired\tin\tnuclear\tpower\tplant\tacquisitions | - | - | $310,000 |
| \t\t\t\tLong-term\tdebt\trefunded\twith\tproceeds\tfrom |  |  |  |
| \t\t\t\t\tlong-term\tdebt\tissued\tin\tprior\tperiod | - | - | ($47,000) |

# CONSOLIDATED	BALANCE	SHEETS

# ASSETS

| Cash | $79,136 | $115,112 |
| :--- | :--- | :--- |
| \t\tTemporary\tcash\tinvestments\t-\tat\tcost, |  |  |
| \t\t\twhich\tapproximates\tmarket | 728,600 | 576,813 |
| \t\tSpecial\tdeposits | - | 308 |
| \t\t\t\t\tTotal\tcash\tand\tcash\tequivalents | 807,736 | 692,233 |
| Other\ttemporary\tinvestments | - | 50,000 |
| Notes\treceivable | 3,092 | 1,730 |
| Accounts\treceivable: |  |  |
| \t\tCustomer | 435,191 | 398,091 |
| \t\tAllowance\tfor\tdoubtful\taccounts | (23,758) | (25,976) |
| \t\tOther | 342,289 | 246,824 |
| \t\tAccrued\tunbilled\trevenues | 460,039 | 384,860 |
| \t\t\t\t\tTotal\treceivables | 1,213,761 | 1,003,799 |
| Deferred\tfuel\tcosts | 85,911 | 245,973 |
| Accumulated\tdeferred\tincome\ttaxes | 76,899 | - |
| Fuel\tinventory\t-\tat\taverage\tcost | 127,251 | 110,482 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 569,407 | 548,921 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 107,782 | 138,836 |
| Prepayments\tand\tother | 116,279 | 127,270 |
| TOTAL | 3,108,118 | 2,919,244 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 231,779 | 1,053,328 |
| Decommissioning\ttrust\tfunds | 2,453,406 | 2,278,533 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 219,717 | 262,384 |
| Other | 90,992 | 152,681 |
| TOTAL | 2,995,894 | 3,746,926 |
| PROPERTY,\tPLANT\tAND\tEQUIPMENT |  |  |
| Electric | 29,053,340 | 28,035,899 |
| Property\tunder\tcapital\tlease | 738,554 | 751,815 |
| Natural\tgas | 262,787 | 236,622 |
| Construction\twork\tin\tprogress | 1,197,551 | 1,380,982 |
| Nuclear\tfuel\tunder\tcapital\tlease | 262,469 | 278,683 |
| Nuclear\tfuel | 320,813 | 234,421 |
| TOTAL\tPROPERTY,\tPLANT\tAND\tEQUIPMENT | 31,835,514 | 30,918,422 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 13,139,883 | 12,619,625 |
| PROPERTY,\tPLANT\tAND\tEQUIPMENT\t-\tNET | 18,695,631 | 18,298,797 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 746,413 | 830,539 |
| \t\tOther\tregulatory\tassets | 1,429,261 | 1,398,323 |
| Long-term\treceivables | 39,417 | 20,886 |
| Goodwill | 377,172 | 377,172 |
| Other | 918,871 | 935,501 |
| TOTAL | 3,511,134 | 3,562,421 |

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

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $492,564 | $524,372 |
| Notes\tpayable | 193 | 351 |
| Accounts\tpayable | 896,528 | 796,572 |
| Customer\tdeposits | 222,320 | 199,620 |
| Taxes\taccrued | 224,011 | 224,926 |

| Accumulated	deferred	income	taxes | - | 22,963 |
| :--- | :--- | :--- |
| Nuclear\trefueling\toutage\tcosts | - | 8,238 |
| Interest\taccrued | 144,478 | 139,603 |
| Obligations\tunder\tcapital\tleases | 133,847 | 159,978 |
| Other | 218,442 | 145,453 |
| TOTAL | 2,332,383 | 2,222,076 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 5,067,381 | 4,779,513 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 399,228 | 420,248 |
| Obligations\tunder\tcapital\tleases | 146,060 | 153,898 |
| Other\tregulatory\tliabilities | 329,767 | 291,239 |
| Decommissioning\tand\tretirement\tcost\tliabilities | 2,066,277 | 2,215,490 |
| Transition\tto\tcompetition | 79,101 | 79,098 |
| Regulatory\treserves | 103,061 | 69,528 |
| Accumulated\tprovisions | 549,914 | 506,960 |
| Long-term\tdebt | 7,016,831 | 7,322,940 |
| Preferred\tstock\twith\tsinking\tfund | 17,400 | 20,852 |
| Other | 1,541,331 | 1,407,551 |
| TOTAL | 17,316,351 | 17,267,317 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 365,356 | 334,337 |
| SHAREHOLDERS'\tEQUITY |  |  |
| Common\tstock,\t$.01\tpar\tvalue,\tauthorized\t500,000,000 |  |  |
| \t\tshares;\tissued\t248,174,087\tshares\tin\t2004\tand\tin\t2003 | 2,482 | 2,482 |
| Paid-in\tcapital | 4,835,375 | 4,767,615 |
| Retained\tearnings | 4,984,302 | 4,502,508 |
| Accumulated\tother\tcomprehensive\tloss | (93,453) | (7,795) |
| Less\t-\ttreasury\tstock,\tat\tcost\t(31,345,028\tshares\tin\t2004\tand |  |  |
| \t\t19,276,445\tshares\tin\t2003) | 1,432,019 | 561,152 |
| TOTAL | 8,296,687 | 8,703,658 |

# CONSOLIDATED	STATEMENTS	OF	RETAINED	EARNINGS,	COMPREHENSIVE	INCOME,	AND	PAID-IN	CAPITAL

|  |  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2004 | 2004 | 2003 | 2003 | 2002 | 2002 |
|  |  |  | (In\tThousands) |  |  |  |
| RETAINED\tEARNINGS |  |  |  |  |  |  |
| Retained\tEarnings\t-\tBeginning\tof\tperiod | $4,502,508 |  | $3,938,693 |  | $3,638,448 |  |
| \t\tAdd:\tEarnings\tapplicable\tto\tcommon\tstock | 909,524 | $909,524 | 926,943 | $926,943 | 599,360 | $599,360 |
| \t\tDeduct: |  |  |  |  |  |  |
| \t\t\t\tDividends\tdeclared\ton\tcommon\tstock | 427,740 |  | 362,941 |  | 299,031 |  |
| \t\t\t\tCapital\tstock\tand\tother\texpenses | (10) |  | 187 |  | 84 |  |
| \t\t\t\t\tTotal | 427,730 |  | 363,128 |  | 299,115 |  |
| Retained\tEarnings\t-\tEnd\tof\tperiod | $4,984,302 |  | $4,502,508 |  | $3,938,693 |  |
| ACCUMULATED\tOTHER\tCOMPREHENSIVE\tINCOME\t(LOSS)\n(Net\tof\ttaxes): |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tperiod: |  |  |  |  |  |  |
| \t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | ($25,811) |  | $17,313 |  | ($17,973) |  |
| \t\tOther\taccumulated\tcomprehensive\tincome\t(loss)\titems | 18,016 |  | (39,673) |  | (70,821) |  |
| \t\t\t\t\tTotal | (7,795) |  | (22,360) |  | (88,794) |  |
| Net\tderivative\tinstrument\tfair\tvalue\tchanges\n\t\tarising\tduring\tthe\tperiod | (115,600) | (115,600) | (43,124) | (43,124) | 35,286 | 35,286 |
| Foreign\tcurrency\ttranslation | 1,882 | 1,882 | 4,169 | 4,169 | 65,948 | (15,487) |
| Minimum\tpension\tliability | 2,762 | 2,762 | 1,153 | 1,153 | (10,489) | (10,489) |
| Net\tunrealized\tinvestment\tgains\t(losses) | 25,298 | 25,298 | 52,367 | 52,367 | (24,311) | (24,311) |
| Balance\tat\tend\tof\tperiod:\n\t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | (141,411) |  | (25,811) |  | 17,313 |  |

| Other	accumulated	comprehensive	income	(loss)	items | 47,958 |  | 18,016 |  | (39,673) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \t\t\t\t\tTotal | ($93,453) |  | ($7,795) |  | ($22,360) |
| Comprehensive\tIncome |  | $823,866 |  | $941,508 |  |
| PAID-IN\tCAPITAL |  |  |  |  |  |
| Paid-in\tCapital\t-\tBeginning\tof\tperiod | $4,767,615 |  | $4,666,753 |  | $4,662,704 |
| \t\tAdd:\n\t\t\t\tCommon\tstock\tissuances\trelated\tto\tstock\tplans | 67,760 |  | 100,862 |  | 4,049 |
| Paid-in\tCapital\t-\tEnd\tof\tperiod | $4,835,375 |  | $4,767,615 |  | $4,666,753 |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# NOTE	1.	SUMMARY	OF	SIGNIFICANT	ACCOUNTING	POLICIES

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

# Use	of	Estimates	in	the	Preparation	of	Financial	Statements

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

# Revenues	and	Fuel	Costs

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

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

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

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

# Property,	Plant,	and	Equipment

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

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

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

|  |  | U.S. | Non-Utility Commodity Parent	and | Non-Utility Commodity Parent	and | Non-Utility Commodity Parent	and |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Entergy | Utility | Nuclear | Services | Other |
|  |  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |  |
| Nuclear | $7,308 | $5,987 | $1,321 | $- | $- |
| Other | 1,533 | 1,228 | - | 305 | - |
| Transmission | 2,182 | 2,182 | - | - | - |
| Distribution | 4,672 | 4,672 | - | - | - |
| Other | 1,123 | 1,115 | - | - | 8 |

| Construction	work	in	progress | 1,198 | 924 | 244 | 2 | 28 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Nuclear\tfuel\t(leased\tand\towned) | 583 | 297 | 286 | - | - |
| Asset\tretirement\tobligation | 97 | 97 | - | - | - |
| Property,\tplant,\tand\tequipment\t-\tnet | $18,696 | $16,502 | $1,851 | $307 | $36 |

| 2003 | Entergy | U.S.<br>Utility | Non-Utility<br>Nuclear | Commodity<br>Services | Parent	and<br>Other |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |  |
| Nuclear | $7,056 | $6,112 | $944 | $- | $- |
| Other | 1,816 | 1,359 | - | 457 | - |
| Transmission | 2,067 | 2,067 | - | - | - |
| Distribution | 4,231 | 4,231 | - | - | - |
| Other | 1,079 | 1,069 | - | - | 10 |
| Construction\twork\tin\tprogress | 1,381 | 954 | 398 | - | 29 |
| Nuclear\tfuel\t(leased\tand\towned) | 513 | 298 | 215 | - | - |
| Asset\tretirement\tobligation | 156 | 155 | - | 1 | - |
| Property,\tplant,\tand\tequipment\t-\tnet | $18,299 | $16,245 | $1,557 | $458 | $39 |

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

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

# Jointly-Owned	Generating	Stations

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

|  |  |  | Total |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Megawatt |  |  | Accumulated |
|  | Generating\tStations | Fuel-Type | Capability\t(1) | Ownership | Investment | Depreciation |
|  |  |  |  |  | (In\tMillions) |  |
| U.S.\tUtility: |  |  |  |  |  |  |
| Grand\tGulf | Unit\t1 | Nuclear | 1,270 | 90.00%\t(2) | $3,702 | $1,780 |
| Independence | Units\t1\tand\t2 | Coal | 1,630 | 47.90% | $462 | $249 |
| White\tBluff | Units\t1\tand\t2 | Coal | 1,635 | 57.00% | $428 | $264 |
| Roy\tS.\tNelson | Unit\t6 | Coal | 550 | 60.90% | $403 | $241 |
| Big\tCajun\t2 | Unit\t3 | Coal | 575 | 42.00% | $233 | $128 |
| Energy\tCommodity |  |  |  |  |  |  |
| Services: |  |  |  |  |  |  |
| Harrison\tCounty |  | Gas | 550 | 61.00% | $209 | $7 |
| Warren |  | Gas | 300 | 75.00% | $24 | $9 |

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

(2) Includes	an	11.5%	leasehold	interest	held	by	System	Energy.	System	Energy's	Grand	Gulf	lease obligations	are	discussed	in	Note	9	to	the	consolidated	financial	statements.

# Nuclear	Refueling	Outage	Costs

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

# Allowance	for	Funds	Used	During	Construction	(AFUDC)

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

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

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

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

# Earnings	per	Share

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

(In	Millions,	Except	Per	Share	Data)

| accounting	change | $909.5 |  | $789.9 |  | $599.4 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Average\tnumber\tof\tcommon\tshares |  |  |  |  |  |  |
| outstanding\t-\tbasic | 226.9 | $4.01 | 226.8 | $3.48 | 223.0 | $2.69 |
| Average\tdilutive\teffect\tof: |  |  |  |  |  |  |
| \t\tStock\tOptions\t(1) | 4.3 | (0.075) | 4.1 | (0.062) | 3.9 | (0.046) |
| \t\tEquity\tAwards | - | - | 0.2 | (0.004) | 0.4 | (0.005) |
| Average\tnumber\tof\tcommon\tshares |  |  |  |  |  |  |
| outstanding\t-\tdiluted | 231.2 | $3.93 | 231.1 | $3.42 | 227.3 | $2.64 |
| Earnings\tapplicable\tto\tcommon\tstock | $909.5 |  | $926.9 |  | $599.4 |  |
| Average\tnumber\tof\tcommon\tshares |  |  |  |  |  |  |
| outstanding\t-\tbasic | 226.9 | $4.01 | 226.8 | $4.09 | 223.0 | $2.69 |
| Average\tdilutive\teffect\tof: |  |  |  |  |  |  |
| \t\tStock\tOptions\t(1) | 4.3 | (0.075) | 4.1 | (0.073) | 3.9 | (0.046) |
| \t\tEquity\tAwards | - | - | 0.2 | (0.004) | 0.4 | (0.005) |
| Average\tnumber\tof\tcommon\tshares |  |  |  |  |  |  |
| outstanding\t-\tdiluted | 231.2 | $3.93 | 231.1 | $4.01 | 227.3 | $2.64 |

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

# Stock-based	Compensation	Plans

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

| Earnings	applicable	to	common	stock | $909,524 | $926,943 | $599,360 |
| :--- | :--- | :--- | :--- |
| Add\tback:\tStock-based\tcompensation\texpense |  |  |  |
| included\tin\tearnings\tapplicable\tto\tcommon\tstock, |  |  |  |
| net | 5,141 | 2,818 | - |
| \t\tof\trelated\ttax\teffects |  |  |  |
| Deduct:\tTotal\tstock-based\temployee\tcompensation\n\t\texpense\tdetermined\tunder\tfair\tvalue\tmethod\tfor\nall\n\t\tawards,\tnet\tof\trelated\ttax\teffects | 16,668 | 24,518 | 28,110 |
| Pro\tforma\tearnings\tapplicable\tto\tcommon\tstock | $897,997 | $905,243 | $571,250 |
| Earnings\tper\taverage\tcommon\tshare: |  |  |  |
| \t\tBasic | $4.01 | $4.09 | $2.69 |
| \t\tBasic\t-\tpro\tforma | $3.96 | $3.99 | $2.56 |
| \t\tDiluted | $3.93 | $4.01 | $2.64 |
| \t\tDiluted\t-\tpro\tforma | $3.88 | $3.92 | $2.51 |

# Application	of	SFAS	71

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

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

EITF	97-4:	"Deregulation	of	the	Pricing	of	Electricity	-	Issues	Related	to	the	Application	of	FASB	Statements	No.	71	and	101"	specifies	that	SFAS	71	should	be discontinued	at	a	date	no	later	than	when	the	effects	of	a	transition	to	competition	plan	for	all	or	a	portion	of	the	entity	subject	to	such	plan	are	reasonably

determinable.	Additionally,	EITF	97-4	promulgates	that	regulatory	assets	to	be	recovered	through	cash	flows	derived	from	another	portion	of	the	entity	that continues	to	apply	SFAS	71	should	not	be	written	off;	rather,	they	should	be	considered	regulatory	assets	of	the	segment	that	will	continue	to	apply	SFAS	71.

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

# Cash	and	Cash	Equivalents

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

# Investments

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

# Equity	Method	Investees

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

# Derivative	Financial	Instruments	and	Commodity	Derivatives

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

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

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

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

# River	Bend	AFUDC

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

# Transition	to	Competition	Liabilities

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

# Reacquired	Debt

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

# Foreign	Currency	Translation

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

# New	Accounting	Pronouncements

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

further	discussed	in	Note	3	to	the	consolidated	financial	statements.

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

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

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

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

# NOTE	2.	RATE	AND	REGULATORY	MATTERS

# Electric	Industry	Restructuring	and	the	Continued	Application	of	SFAS	71

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

| Jurisdiction | Status	of	Retail	Open	Access | %	of	Entergy's<br>2004	Revenues	Derived<br>from	Retail	Electric<br>Utility	Operations<br>in	the	Jurisdiction |
| :--- | :--- | :--- |
| Arkansas | \t Retail\topen\taccess\twas\trepealed\tin\tFebruary\t2003. | 11.6% |
| Texas | \t In\tJuly\t2004,\tthe\tPUCT\teffectively\trejected\tEntergy\tGulf\tStates'\tproposal\tto | 11.8% |
|  | submitted\tin\tthe\tTexas\tLegislature\tthat\twould\tspecify\tthat\tretail\topen\taccess\twill |  |
|  | not\tcommence\tin\tEntergy\tGulf\tStates'\tterritory\tuntil\tthe\tPUCT\tcertifies\ta\tpower |  |
|  | region. |  |
| Louisiana | \t The\tLPSC\thas\tdeferred\tpursuing\tretail\topen\taccess,\tpending\tdevelopments\tat\tthe | 34.1% |
|  | that\twas\tfunded\tby\ta\tgroup\tof\tlarge\tindustrial\tcustomers,\tthe\tLPSC\trecently\thas |  |
|  | what\taction,\tif\tany,\tthe\tLPSC\tmight\ttake\tin\tresponse\tto\tthe\tinformation\tit |  |
|  | received. |  |
| Mississippi | \t The\tMPSC\thas\trecommended\tnot\tpursuing\topen\taccess\tat\tthis\ttime. | 10.9% |
| New\tOrleans | \t The\tCouncil\thas\ttaken\tno\taction\ton\tEntergy\tNew\tOrleans'\tproposal\tfiled\tin\t1997. | 4.5% |

# Texas

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

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

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

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

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

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

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

# Louisiana

In	November	2001,	the	LPSC	decided	not	to	move	forward	with	retail	open	access	for	any	customers	at	this	time.	The	LPSC	instead	directed	its	staff	to	hold collaborative	group	meetings	concerning	open	access	from	time	to	time,	and	to	have	the	LPSC	staff	monitor	developments	in	neighboring	states	and	to	report	to	the LPSC	regarding	the	progress	of	retail	access	developments	in	those	states.	In	September	2004,	in	response	to	a	study	funded	by	certain	industrial	customers	that evaluated	a	limited	industrial-only	retail	choice	program,	the	LPSC	asked	the	LPSC	staff	to	solicit	comments	and	obtain	information	from	utilities,	customers,	and

other	interested	parties	concerning	the	potential	costs	and	benefits	of	a	limited	choice	program,	the	impact	of	such	a	program	on	other	customers,	as	well	as	issues such	as	stranded	costs	and	transmission	service.		Comments	from	interested	parties	were	filed	with	the	LPSC	on	January	14,	2005.	The	LPSC	has	not	established	a procedural	framework	for	 consideration	 of	 the	 comments.	At	 this	 time,	 it	 is	not	certain	what	further	action,	 if	any,	 the	LPSC	might	 take	 in	response	 to	 the information	it	received.

# Regulatory	Assets

# Other	Regulatory	Assets

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

| (Note	8) | $380.1 | $464.9 |
| :--- | :--- | :--- |
| Deferred\tfuel\t-\tnon-current\t-\trecovered\tthrough\trate\triders\twhen\trates\tare |  |  |
| redetermined\tannually | 21.9 | 28.2 |
| Depreciation\tre-direct\t-\trecovery\tbegins\tat\tstart\tof\tretail\topen\taccess\t(Note\t1) | 79.1 | 79.1 |
| DOE\tDecommissioning\tand\tDecontamination\tFees\t-\trecovered\tthrough\tfuel\trates\tuntil |  |  |
| December\t2006\t(Note\t8) | 25.3 | 32.9 |
| Low-level\tradwaste\t-\trecovery\ttiming\tdependent\tupon\tpending\tlawsuit | 19.4 | 19.4 |
| Pension\tcosts\t(Note\t10) | 207.3 | 134.0 |
| Postretirement\tbenefits\t-\trecovered\tthrough\t2013\t(Note\t10) | 19.1 | 21.5 |
| Provision\tfor\tstorm\tdamages\t-\trecovered\tthrough\tcost\tof\tservice | 124.5 | 123.3 |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t8) | 53.2 | 45.6 |
| Resource\tplanning\t-\trecovery\ttiming\twill\tbe\tdetermined\tby\tthe\tLPSC\tin\ta\tbase\trate |  |  |
| proceeding\t(Note\t2) | 25.4 | 5.8 |
| River\tBend\tAFUDC\t-\trecovered\tthrough\tAugust\t2025\t(Note\t1) | 37.5 | 39.4 |
| Sale-leaseback\tdeferral\t-\trecovered\tthrough\tJune\t2014\t(Note\t9) | 127.3 | 131.7 |
| Spindletop\tgas\tstorage\tfacility\t-\trecovered\tthrough\tDecember\t2032 | 42.3 | 38.0 |
| Unamortized\tloss\ton\treaquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 169.9 | 164.4 |
| Other\t-\tvarious | 97.0 | 70.1 |
| Total | $1,429.3 | $1,398.3 |

# Deferred	fuel	costs

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

|  | 2004 | 2003 |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $7.4 | $10.6 |
| Entergy\tGulf\tStates | $90.1 | $118.4 |
| Entergy\tLouisiana | $8.7 | $30.6 |
| Entergy\tMississippi | ($22.8) | $89.1 |
| Entergy\tNew\tOrleans | $2.6 | ($2.7) |

# Entergy	Arkansas

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

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

# Entergy	Gulf	States	(Texas)

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

|  | Amount |
| :--- | :--- |
|  | (In\nMillions) |
| Under-recovered\tfuel\tcosts\tfor\tthe\tperiod\t9/03\t-\t7/04\tto\tbe |  |
| recovered\tthrough\tan\tinterim\tfuel\tsurcharge\tover\ta\tsix-month |  |
| period\tbeginning\tin\tJanuary\t2005 | $27.8 |
| Items\tto\tbe\taddressed\tas\tpart\tof\tunbundling | $29.0 |
| Imputed\tcapacity\tcharges | $\t9.3 |
| Other | $12.5 |

The	PUCT	has	ordered	that	the	imputed	capacity	charges	be	excluded	from	fuel	rates	and	therefore	recovered	through	base	rates.	Entergy	Gulf	States	filed	a	retail electric	rate	case	and	fuel	proceeding	with	the	PUCT	in	August	2004.	As	discussed	below,	the	PUCT	dismissed	the	rate	case	and	fuel	reconciliation	proceeding	in October	2004	indicating	that	Entergy	Gulf	States	is	still	subject	to	a	rate	freeze	based	on	the	current	PUCT-approved	settlement	agreement	stipulating	that	a	rate freeze	would	remain	in	effect	until	retail	open	access	commenced	in	Entergy	Gulf	States'	service	territory,	unless	the	rate	freeze	is	lifted	by	the	PUCT	prior	thereto.

Without	a	Texas	base	rate	proceeding,	it	is	possible	that	Entergy	Gulf	States	will	not	be	allowed	to	recover	imputed	capacity	charges	in	Texas	retail	rates	in	the future.	Entergy	Gulf	States	believes	the	PUCT	has	misinterpreted	the	settlement	and	has	appealed	the	PUCT	order	to	the	Travis	County	District	Court	and	also intends	to	pursue	other	available	remedies	as	discussed	above	in	"Electric	Industry	Restructuring	and	the	Continued	Application	of	SFAS	71."	The	dismissal of	the	rate	case	does	not	preclude	Entergy	Gulf	States	from	seeking	the	reconciliation	of	fuel	and	purchased	power	costs	of	$288	million	incurred	from	September 2003	through	March	2004	when,	at	the	appropriate	time,	similar	costs	are	reconciled	in	the	future.

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

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

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

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

# Entergy	Gulf	States	(Louisiana)	and	Entergy	Louisiana

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

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

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

# Entergy	Mississippi

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

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

# Entergy	New	Orleans

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

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

# Retail	Rate	Proceedings

# Filings	with	the	APSC	(Entergy	Arkansas)

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

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

Retail	Rates

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

approval	of	a	base	rate	increase	of	$42.6	million	annually	for	the	Texas	retail	jurisdiction;

approval	to	implement	a	$14.1	million	per	year	rider	to	recover,	over	a	15-year	period,	$110.9	million	of	incurred	costs	related	to	its	efforts	to	transition	to	a competitive	retail	market	in	accordance	with	the	Texas	restructuring	law;

approval	to	implement	a	proposed	$11.3	million	franchise	fee	rider	to	recover	payments	to	municipalities	charging	such	fees;	and

a	requested	return	on	equity	of	11.5%.

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

# Recovery	of	River	Bend	Costs

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

# Filings	with	the	LPSC

# Proposed	Settlement

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

# Annual	Earnings	Reviews	(Entergy	Gulf	States)

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

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

# (Entergy	Louisiana)

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

# Filings	with	the	MPSC	(Entergy	Mississippi)

# Formula	Rate	Plan	Filings

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

then	Entergy	Mississippi's	"Allowed	ROE"	for	the	next	twelve-month	period	is	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth.

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

# Filings	with	the	Council	(Entergy	New	Orleans)

# Rate	Proceedings

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

# 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.	In	March	2004,	the	plaintiffs	supplemented	and	amended	their	petition.	If	necessary,	at	the	appropriate	time, Entergy	will	also	raise	its	defenses	to	the	antitrust	claims.	The	suit	in	state	court	has	been	stayed	by	stipulation	of	the	parties	pending	a	decision	by	the	City	Council in	the	proceeding	discussed	in	the	next	paragraph.

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

# NOTE	3.	INCOME	TAXES

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Current: |  |  |  |
| \t\tFederal\t(a)(b) | $54,380 | ($731,129) | $510,109 |
| \t\tForeign | (2,231) | 8,284 | (3,295) |
| \t\tState\t(a)(b) | 38,301 | 23,396 | 43,788 |
| \t\t\t\tTotal\t(a)(b) | 90,450 | (699,449) | 550,602 |
| Deferred\t--\tnet | 296,445 | 1,307,092 | (233,532) |
| Investment\ttax\tcredit |  |  |  |
| \t\tadjustments\t--\tnet | (20,987) | (27,644) | (23,132) |
| \t\tRecorded\tincome\ttax\texpense | $365,908 | $579,999 | $293,938 |

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

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

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

| Computed	at	statutory	rate	(35%) | $454,635 | $535,663 | $320,954 |
| :--- | :--- | :--- | :--- |
| Increases\t(reductions)\tin\ttax |  |  |  |
| \t\tresulting\tfrom: |  |  |  |
| \t\tState\tincome\ttaxes\tnet\tof |  |  |  |
| \t\t\t\t\tfederal\tincome\ttax\teffect | 36,185 | 54,024 | 44,835 |
| \t\tRegulatory\tdifferences- |  |  |  |
| \t\t\t\t\tutility\tplant\titems | 41,240 | 52,638 | 29,774 |
| \t\tAmortization\tof\tinvestment |  |  |  |
| \t\t\t\t\ttax\tcredits | (20,596) | (24,364) | (22,294) |
| \t\tEAM\tcapital\tloss | (86,426) | - | - |
| \t\tFlow-through/permanent |  |  |  |
| \t\t\t\t\tdifferences | (42,902) | (30,221) | (38,197) |
| \t\tUS\ttax\ton\tforeign\tincome | 2,014 | 7,888 | (28,416) |
| \t\tOther\t--\tnet | (18,242) | (15,629) | (12,718) |
|  | $365,908 | $579,999 | $293,938 |
| \t\t\t\tTotal\tincome\ttaxes |  |  |  |
| Effective\tIncome\tTax\tRate | 28.2% | 37.9% | 32.1% |

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

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

| Net	regulatory	liabilities | ($978,815) | ($1,072,898) |
| :--- | :--- | :--- |
| Plant-related\tbasis\tdifferences | (4,699,803) | (3,574,593) |
| Power\tpurchase\tagreements | (972,348) | (945,495) |
| Nuclear\tdecommissioning | (545,109) | (519,028) |
| Other | (346,993) | (379,875) |
| Total | (7,543,068) | (6,491,889) |
| Deferred\tTax\tAssets: |  |  |
| Accumulated\tdeferred\tinvestment |  |  |
| tax\tcredit | 133,979 | 141,723 |
| Capital\tlosses | 134,688 | 92,423 |
| Net\toperating\tloss\tcarryforwards | 1,201,006 | 129,122 |
| Sale\tand\tleaseback | 227,155 | 223,134 |
| Unbilled/deferred\trevenues | 28,741 | 18,983 |
| Pension-related\titems | 247,662 | 204,083 |
| Reserve\tfor\tregulatory\tadjustments | 131,112 | 138,933 |
| Customer\tdeposits | 107,652 | 108,591 |
| Nuclear\tdecommissioning | 158,796 | 272,551 |
| Other | 225,659 | 399,080 |
| Valuation\tallowance | (43,864) | (39,210) |
| Total | 2,552,586 | 1,689,413 |
|  | ($4,990,482) | ($4,802,476) |

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

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

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

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

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

Entergy	Corporation	has	in	place	two	separate	revolving	credit	facilities,	a	5-year	credit	facility	and	a	3-year	credit	facility.	The	5-year	credit	facility,	which	expires

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

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

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

| Company | Expiration	Date | Amount	of<br>Facility | Amount	Drawn	as<br>of	Dec.	31,	2004 |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | April\t2005 | $85\tmillion | - |
| Entergy\tLouisiana | April\t2005 | $15\tmillion(a) | - |
| Entergy\tMississippi | May\t2005 | $25\tmillion | - |
| Entergy\tNew\tOrleans | April\t2005 | $14\tmillion(a) | - |

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

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

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

# NOTE	5.	LONG	-	TERM	DEBT

| 8.25%	Series	due	April	2004	-	Entergy	Gulf	States | $- | $292,000 |
| :--- | :--- | :--- |
| \t\t\t\t\t\t6.2%\tSeries\tdue\tMay\t2004\t-\tEntergy\tMississippi | - | 75,000 |
| \t\t\t\t\t\t6.125%\tSeries\tdue\tJuly\t2005\t-\tEntergy\tArkansas | 100,000 | 100,000 |
| \t\t\t\t\t\t8.125%\tSeries\tdue\tJuly\t2005\t-\tEntergy\tNew\tOrleans | 30,000 | 30,000 |
| \t\t\t\t\t\t6.77%\tSeries\tdue\tAugust\t2005\t-\tEntergy\tGulf\tStates | 98,000 | 98,000 |
|  | - | 275,000 |
| \t\t\t\t\t\t4.875%\tSeries\tdue\tOctober\t2007\t-\tSystem\tEnergy | 70,000 | 70,000 |
| \t\t\t\t\t\t5.2%\tSeries\tdue\tDecember\t2007\t-\tEntergy\tGulf\tStates | - | 200,000 |
| \t\t\t\t\t\t6.5%\tSeries\tdue\tMarch\t2008\t-\tEntergy\tLouisiana | - | 115,000 |
| \t\t\t\t\t\t4.35%\tSeries\tdue\tApril\t2008\t-\tEntergy\tMississippi | 100,000 | 100,000 |
| \t\t\t\t\t\t6.45%\tSeries\tdue\tApril\t2008\t-\tEntergy\tMississippi | - | 80,000 |
| \t\t\t\t\t\t3.6%\tSeries\tdue\tJune\t2008\t-\tEntergy\tGulf\tStates | 325,000 | 325,000 |
| \t\t\t\t\t\t3.875%\tSeries\tdue\tAugust\t2008\t-\tEntergy\tNew\tOrleans | 30,000 | 30,000 |
|  | 225,000 | - |
| \t\t\t\t\t\t4.65%\tSeries\tdue\tMay\t2011\t-\tEntergy\tMississippi | 80,000 | - |
| \t\t\t\t\t\t4.875%\tSeries\tdue\tNovember\t2011\t-\tEntergy\tGulf\tStates | 200,000 | - |
| \t\t\t\t\t\t6.0%\tSeries\tdue\tDecember\t2012\t-\tEntergy\tGulf\tStates | 140,000 | 140,000 |
| \t\t\t\t\t\t5.15%\tSeries\tdue\tFebruary\t2013\t-\tEntergy\tMississippi | 100,000 | 100,000 |
| \t\t\t\t\t\t5.25%\tSeries\tdue\tAugust\t2013\t-\tEntergy\tNew\tOrleans | 70,000 | 70,000 |
| \t\t\t\t\t\t5.09%\tSeries\tdue\tNovember\t2014\t-\tEntergy\tLouisiana | 115,000 | - |
| \t\t\t\t\t\t5.6%\tSeries\tdue\tDecember\t2014\t-\tEntergy\tGulf\tStates | 50,000 | - |
| \t\t\t\t\t\t5.25%\tSeries\tdue\tAugust\t2015\t-\tEntergy\tGulf\tStates | 200,000 | 200,000 |
| \t\t\t\t\t\t6.75%\tSeries\tdue\tOctober\t2017\t-\tEntergy\tNew\tOrleans | 25,000 | 25,000 |
| \t\t\t\t\t\t5.4%\tSeries\tdue\tMay\t2018\t-\tEntergy\tArkansas | 150,000 | 150,000 |
| \t\t\t\t\t\t4.95%\tSeries\tdue\tJune\t2018\t-\tEntergy\tMississippi | 95,000 | 95,000 |
| \t\t\t\t\t\t5.0%\tSeries\tdue\tJuly\t2018\t-\tEntergy\tArkansas | 115,000 | 115,000 |
| \t\t\t\t\t\t5.5%\tSeries\tdue\tApril\t2019\t-\tEntergy\tLouisiana | 100,000 | - |
| \t\t\t\t\t\t8.0%\tSeries\tdue\tMarch\t2023\t-\tEntergy\tNew\tOrleans | - | 45,000 |
| \t\t\t\t\t\t7.7%\tSeries\tdue\tJuly\t2023\t-\tEntergy\tMississippi | - | 60,000 |
| \t\t\t\t\t\t7.55%\tSeries\tdue\tSeptember\t2023\t-\tEntergy\tNew\tOrleans | - | 30,000 |
| \t\t\t\t\t\t7.0%\tSeries\tdue\tOctober\t2023\t-\tEntergy\tArkansas | 175,000 | 175,000 |
| \t\t\t\t\t\t5.6%\tSeries\tdue\tSeptember\t2024\t-\tEntergy\tNew\tOrleans | 35,000 | - |
| \t\t\t\t\t\t5.65%\tSeries\tdue\tSeptember\t2029\t-\tEntergy\tNew\tOrleans | 40,000 | - |
| \t\t\t\t\t\t6.7%\tSeries\tdue\tApril\t2032\t-\tEntergy\tArkansas | 100,000 | 100,000 |
| \t\t\t\t\t\t7.6%\tSeries\tdue\tApril\t2032\t-\tEntergy\tLouisiana | 150,000 | 150,000 |
| \t\t\t\t\t\t6.0%\tSeries\tdue\tNovember\t2032\t-\tEntergy\tArkansas | 100,000 | 100,000 |
| \t\t\t\t\t\t6.0%\tSeries\tdue\tNovember\t2032\t-\tEntergy\tMississippi | 75,000 | 75,000 |
| \t\t\t\t\t\t7.25%\tSeries\tdue\tDecember\t2032\t-\tEntergy\tMississippi | 100,000 | 100,000 |
| \t\t\t\t\t\t5.9%\tSeries\tdue\tJune\t2033\t-\tEntergy\tArkansas | 100,000 | 100,000 |
| \t\t\t\t\t\t6.20%\tSeries\tdue\tJuly\t2033\t-\tEntergy\tGulf\tStates | 240,000 | 240,000 |

|  | 2004 | 2003 |
| :--- | :--- | :--- |
|  | (In\tThousands) |  |
| Governmental\tBonds\t(a): |  |  |
| \t\t\t\t\t\t5.45%\tSeries\tdue\t2010,\tCalcasieu\tParish\t-\tLouisiana | $22,095 | $22,095 |
| \t\t\t\t\t\t6.75%\tSeries\tdue\t2012,\tCalcasieu\tParish\t-\tLouisiana | 48,285 | 48,285 |
| \t\t\t\t\t\t6.7%\tSeries\tdue\t2013,\tPointe\tCoupee\tParish\t-\tLouisiana | 17,450 | 17,450 |
| \t\t\t\t\t\t5.7%\tSeries\tdue\t2014,\tIberville\tParish\t-\tLouisiana | 21,600 | 21,600 |
| \t\t\t\t\t\t7.7%\tSeries\tdue\t2014,\tWest\tFeliciana\tParish\t-\tLouisiana | 94,000 | 94,000 |
| \t\t\t\t\t\t5.8%\tSeries\tdue\t2015,\tWest\tFeliciana\tParish\t-\tLouisiana | 28,400 | 28,400 |
| \t\t\t\t\t\t7.0%\tSeries\tdue\t2015,\tWest\tFeliciana\tParish\t-\tLouisiana | 39,000 | 39,000 |
| \t\t\t\t\t\t7.5%\tSeries\tdue\t2015,\tWest\tFeliciana\tParish\t-\tLouisiana | 41,600 | 41,600 |
| \t\t\t\t\t\t9.0%\tSeries\tdue\t2015,\tWest\tFeliciana\tParish\t-\tLouisiana | 45,000 | 45,000 |
| \t\t\t\t\t\t5.8%\tSeries\tdue\t2016,\tWest\tFeliciana\tParish\t-\tLouisiana | 20,000 | 20,000 |
| \t\t\t\t\t\t6.3%\tSeries\tdue\t2016,\tPope\tCounty\t-\tArkansas\t(h) | 19,500 | 19,500 |
| \t\t\t\t\t\t5.6%\tSeries\tdue\t2017,\tJefferson\tCounty\t-\tArkansas | 45,500 | 45,500 |
| \t\t\t\t\t\t6.3%\tSeries\tdue\t2018,\tJefferson\tCounty\t-\tArkansas\t(h) | 9,200 | 9,200 |
| \t\t\t\t\t\t6.3%\tSeries\tdue\t2020,\tPope\tCounty\t-\tArkansas | 120,000 | 120,000 |
| \t\t\t\t\t\t6.25%\tSeries\tdue\t2021,\tIndependence\tCounty\t-\tArkansas\t(h) | 45,000 | 45,000 |
| \t\t\t\t\t\t7.5%\tSeries\tdue\t2021,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 50,000 | 50,000 |
| \t\t\t\t\t\t5.875%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 216,000 | 216,000 |
| \t\t\t\t\t\t5.9%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 102,975 | 102,975 |
| \t\t\t\t\t\t7.0%\tSeries\tdue\t2022,\tWarren\tCounty\t-\tMississippi | - | 8,095 |
| \t\t\t\t\t\t7.0%\tSeries\tdue\t2022,\tWashington\tCounty\t-\tMississippi | - | 7,935 |
| \t\t\t\t\t\t7.0%\tSeries\tdue\t2022,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 24,000 | 24,000 |
| \t\t\t\t\t\t7.05%\tSeries\tdue\t2022,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 20,000 | 20,000 |
| \t\t\t\t\t\tAuction\tRate\tdue\t2022,\tIndependence\tCounty\t-\tMississippi\t(h) | 30,000 | 30,000 |
| \t\t\t\t\t\t4.6%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 16,030 | - |
| \t\t\t\t\t\t5.95%\tSeries\tdue\t2023,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 25,000 | 25,000 |
| \t\t\t\t\t\t6.2%\tSeries\tdue\t2023,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 33,000 | 33,000 |
| \t\t\t\t\t\t6.875%\tSeries\tdue\t2024,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 20,400 | 20,400 |
| \t\t\t\t\t\t6.375%\tSeries\tdue\t2025,\tSt.\tCharles\tParish\t-\tLouisiana | 16,770 | 16,770 |
| \t\t\t\t\t\t7.3%\tSeries\tdue\t2025,\tClaiborne\tCounty\t-\tMississippi | - | 7,625 |
| \t\t\t\t\t\t6.2%\tSeries\tdue\t2026,\tClaiborne\tCounty\t-\tMississippi | 90,000 | 90,000 |
| \t\t\t\t\t\t5.05%\tSeries\tdue\t2028,\tPope\tCounty\t-\tArkansas\t(b) | 47,000 | 47,000 |
| \t\t\t\t\t\t5.65%\tSeries\tdue\t2028,\tWest\tFeliciana\tParish\t-\tLouisiana\t(c) | - | 62,000 |
| \t\t\t\t\t\t6.6%\tSeries\tdue\t2028,\tWest\tFeliciana\tParish\t-\tLouisiana | 40,000 | 40,000 |
| \t\t\t\t\t\t5.35%\tSeries\tdue\t2029,\tSt.\tCharles\tParish\t-\tLouisiana\t(i) | - | - |
| \t\t\t\t\t\tAuction\tRate\tdue\t2030,\tSt.\tCharles\tParish\t-\tLouisiana\t(h) | 60,000 | 60,000 |
|  | 55,000 | 55,000 |
| \t\t\t\t\t\tTotal\tgovernmental\tbonds | 1,462,805 | 1,532,430 |
| Other\tLong-Term\tDebt: |  |  |
| \t\t\t\t\t\tNote\tPayable\tto\tNYPA,\tnon-interest\tbearing,\t4.8%\timplicit\trate | $445,605 | $514,708 |
| \t\t\t\t\t\t3\tyear\tBank\tCredit\tFacility\t(Entergy\tCorporation\tand\tSubsidiaries, |  |  |
| \t\t\t\t\t\t\t\t\tNote\t4) | 50,000 | - |
| \t\t\t\t\t\tBank\tterm\tloan,\tEntergy\tCorporation,\tavg\trate\t2.98%,\tdue\t2005 | 60,000 | 60,000 |
| \t\t\t\t\t\tBank\tterm\tloan,\tEntergy\tCorporation,\tavg\trate\t3.08%,\tdue\t2008 | 35,000 | 35,000 |
| \t\t\t\t\t\t6.17%\tNotes\tdue\tMarch\t2008,\tEntergy\tCorporation | 72,000 | 72,000 |
| \t\t\t\t\t\t6.23%\tNotes\tdue\tMarch\t2008,\tEntergy\tCorporation | 15,000 | 15,000 |
| \t\t\t\t\t\t6.13%\tNotes\tdue\tSeptember\t2008,\tEntergy\tCorporation | 150,000 | 150,000 |

| 7.75%	Notes	due	December	2009,	Entergy	Corporation | 267,000 | 267,000 |
| :--- | :--- | :--- |
| \t\t\t\t\t\t6.58%\tNotes\tdue\tMay\t2010,\tEntergy\tCorporation | 75,000 | 75,000 |
| \t\t\t\t\t\t6.9%\tNotes\tdue\tNovember\t2010,\tEntergy\tCorporation | 140,000 | 140,000 |
| \t\t\t\t\t\t7.06%\tNotes\tdue\tMarch\t2011,\tEntergy\tCorporation | 86,000 | 86,000 |
| \t\t\t\t\t\tLong-term\tDOE\tObligation\t(f) | 156,332 | 154,409 |
| \t\t\t\t\t\tWaterford\t3\tLease\tObligation |  |  |
| \t\t\t\t\t\t\t7.45%\t(Entergy\tCorporation\tand\tSubsidiaries,\tNote\t9) | 247,725 | 262,534 |
| \t\t\t\t\t\tGrand\tGulf\tLease\tObligation |  |  |
| \t\t\t\t\t\t\t5.01%\t(Entergy\tCorporation\tand\tSubsidiaries,\tNote\t9) | 397,119 | 403,468 |
| \t\t\t\t\t\tUnamortized\tPremium\tand\tDiscount\t-\tNet | (10,277) | (11,853) |
| \t\t\t\t\t\t8.5%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| \t\t\t\t\t\t\t\tDue\t2045\t-\tEntergy\tArkansas | - | 61,856 |
| \t\t\t\t\t\t8.75%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| \t\t\t\t\t\t\t\tDue\t2046\t-\tEntergy\tGulf\tStates | 87,629 | 87,629 |
| \t\t\t\t\t\t9.0%\tJunior\tSubordinated\tDeferrable\tInterest\tDebentures |  |  |
| \t\t\t\t\t\t\t\tDue\t2045\t-\tEntergy\tLouisiana | - | 72,165 |
| \t\t\t\t\t\tOther | 9,457 | 9,966 |
| Total\tLong-Term\tDebt | 7,509,395 | 7,847,312 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 492,564 | 524,372 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $7,016,831 | $7,322,940 |
| Fair\tValue\tof\tLong-Term\tDebt\t(g) | $6,614,211 | $7,123,706 |

(a) Consists	of	pollution	control	revenue	bonds	and	environmental	revenue	bonds.

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

(c) The	bonds	had	a	mandatory	tender	date	of	September	1,	2004.	Entergy	Gulf	States	purchased	the bonds	from	the	holders,	pursuant	to	the	mandatory	tender	provision,	and	has	not	remarketed	the bonds	at	this	time.

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

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

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

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

(h) The	bonds	are	secured	by	a	series	of	collateral	first	mortgage	bonds.

(i) The	bonds	in	the	principal	amount	of	$110.95	million	had	a	mandatory	tender	date	of	October	1,

2003.	Entergy	Louisiana	purchased	the	bonds	from	the	holders,	pursuant	to	the	mandatory	tender

provision,	and	has	not	remarketed	the	bonds	at	this	time.

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

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

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

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

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

# Junior	Subordinated	Deferrable	Interest	Debentures	and	Implementation	of	FIN	46

Entergy	 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.

NOTE	6.	PREFERRED	STOCK

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

(a) Represents	weighted-average	annualized	rate	for	2004	and	2003.

(b) Fair	 values	 were	 determined	 using	 bid	 prices	 reported	 by	 dealer	 markets	 and	 by	 nationally recognized	 investment	 banking	 firms.	There	 is	 additional	 disclosure	 of	 fair	 value	 of	 financial instruments	in	Note	14	to	the	consolidated	financial	statements.

# All	outstanding	preferred	stock	is	cumulative.

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

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

# NOTE	7.	COMMON	EQUITY

# Common	Stock

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

| Beginning	Balance,	January	1 | 19,276,445 | $561,152 | 25,752,410 | $747,331 |
| :--- | :--- | :--- | :--- | :--- |
| \t\t\tRepurchases | 16,631,800 | 1,017,996 | 155,000 | 8,135 |
| \t\t\tIssuances: |  |  |  |  |
| Employee\tStock-Based |  |  |  |  |
| Compensation\tPlans | (4,555,897) | (146,877) | (6,622,095) | (194,057) |
| \t\t\tDirectors'\tPlan | (7,320) | (252) | (8,870) | (257) |
| Ending\tBalance,\tDecember\t31 | 31,345,028 | $1,432,019 | 19,276,445 | $561,152 |

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

Equity	Compensation	Plan	Information

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

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

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Stock\tprice\tvolatility | 23.1% | 26.3% | 27.2% |
| Expected\tterm\tin\tyears | 6.3 | 6.2 | 5.0 |
| Risk-free\tinterest\trate | 3.2% | 3.3% | 4.2% |
| Dividend\tyield | 3.3% | 3.3% | 3.2% |
| Dividend\tpayment | $1.80 | $1.40 | $1.32 |

Stock	option	transactions	are	summarized	as	follows:

|  | 2004<br>Number<br>of	Options | Average<br>Exercise<br>Price | 2003<br>Number<br>of	Options | Average<br>Exercise<br>Price | 2002<br>Number<br>of	Options | Average<br>Exercise<br>Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Beginning-of-year\tbalance | 15,429,383 | $38.64 | 19,943,114 | $35.85 | 17,316,816 | $31.06 |
| Options\tgranted | 1,898,098 | $58.63 | 2,936,236 | $44.98 | 8,168,025 | $41.72 |
| Options\texercised | (4,541,053) | $38.07 | (6,927,000) | $33.12 | (4,877,688) | $28.62 |
| Options\tforfeited/expired | (476,351) | $39.94 | (522,967) | $40.98 | (664,039) | $36.36 |
|  | 12,310,077 |  | 15,429,383 |  | 19,943,114 |  |
| End-of-year\tbalance |  | $41.88 |  | $38.64 |  | $35.85 |
| Options\texercisable\tat\tyear-\nend | 7,162,884 | $37.25 | 6,153,043 | $34.82 | 4,837,511 | $31.39 |
| Weighted-average\tfair\tvalue\tof\noptions\tat\ttime\tof\tgrant | $7.76 |  | $6.86 |  | $9.22 |  |

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

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

# Retained	Earnings	and	Dividend	Restrictions

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

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

# NOTE	8.	COMMITMENTS	AND	CONTINGENCIES

Entergy	is	involved	in	a	number	of	legal,	tax,	and	regulatory	proceedings	before	various	courts,	regulatory	commissions,	and	governmental	agencies	in	the	ordinary

course	of	its	business.	While	management	is	unable	to	predict	the	outcome	of	such	proceedings,	management	does	not	believe	that	the	ultimate	resolution	of	these matters	will	have	a	material	adverse	effect	on	Entergy's	results	of	operations,	cash	flows,	or	financial	condition.

# Vidalia	Purchased	Power	Agreement

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

# Nuclear	Insurance

# Third	Party	Liability	Insurance

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

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

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

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

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

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

# Property	Insurance

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

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

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

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

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

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

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

$1.0	million	per	occurrence	-	Turbine/generator	damage

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

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

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

Indian	Point	2	and	3

$4.5	million	weekly	indemnity

$490	million	maximum	indemnity

Deductible:	12	week	waiting	period

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

$4.0	million	weekly	indemnity $490	million	maximum	indemnity

# Vermont	Yankee

# $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,	2004,	the	maximum amounts	of	such	possible	assessments	per	occurrence	were	$50.8	million	for	the	U.S.	Utility	plants	and	$68.9	million	for	the	Non-Utility	Nuclear	plants.

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

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

# Nuclear	Decommissioning	and	Other	Retirement	Costs

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

These	liabilities	are	recorded	at	their	fair	values	(which	is	the	present	values	of	the	estimated	future	cash	outflows)	in	the	period	in	which	they	are	incurred,	with	an accompanying	addition	to	the	recorded	cost	of	the	long-lived	asset.	The	asset	retirement	obligation	is	accreted	each	year	through	a	charge	to	expense,	to	reflect	the time	value	of	money	for	this	present	value	obligation.	The	amounts	added	to	the	carrying	amounts	of	the	long-lived	assets	will	be	depreciated	over	the	useful	lives of	the	assets.	The	net	effect	of	implementing	SFAS	143	for	the	rate-regulated	business	of	the	domestic	utility	companies	and	System	Energy	was	recorded	as	a regulatory	asset,	with	no	resulting	impact	on	Entergy's	net	income.	Entergy	recorded	these	regulatory	assets	because	existing	rate	mechanisms	in	each	jurisdiction are	based	on	the	principle	that	Entergy	will	recover	all	ultimate	costs	of	decommissioning	from	customers.

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

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

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

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

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

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

| Earnings	applicable	to	common	stock	-	as	reported | $599,360 |
| :--- | :--- |
| Pro\tforma\teffect\tof\tSFAS\t143 | $14,119 |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tpro\tforma | $613,479 |
| Basic\tearnings\tper\taverage\tcommon\tshare\t-\tas\treported | $2.69 |

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

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

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

| U.S.	Utility | $1,052.0 | $380.1 |
| :--- | :--- | :--- |
| Non-Utility\tNuclear | $1,401.6 | - |

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

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

# Foreign	Tax	Credits

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

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

# Depreciable	Property	Lives

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

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

# Mark	to	Market	of	Certain	Power	Contracts

In	2001,	Entergy	Louisiana	changed	its	method	of	accounting	for	tax	purposes	related	to	its	wholesale	electric	power	contracts.	The	most	significant	of	these	is	the contract	to	purchase	power	from	the	Vidalia	hydroelectric	project.	The	new	tax	accounting	method	has	provided	a	cumulative	cash	flow	benefit	of	approximately $790	million	as	of	December	31,	2004.	The	related	IRS	interest	exposure	is	$93	million	at	December	31,	2004.	This	benefit	is	expected	to	reverse	in	the	years	2005 through	2031.	The	election	did	not	reduce	book	income	tax	expense.	The	timing	of	the	reversal	of	this	benefit	depends	on	several	variables,	including	the	price	of power.	Due	to	the	temporary	nature	of	the	tax	benefit,	the	potential	interest	charge	represents	Entergy's	net	earnings	exposure.	Entergy	Louisiana's	2001	tax	return is	currently	under	examination	by	the	IRS,	though	no	adjustments	have	yet	been	proposed	with	respect	to	the	mark	to	market	election.	Entergy	believes	that	the contingency	provision	established	in	its	financial	statements	will	sufficiently	cover	the	risk	associated	with	this	issue.

# CashPoint	Bankruptcy

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

On	April	19,	2004,	CashPoint	failed	to	pay	funds	due	to	the	domestic	utility	companies	that	had	been	collected	through	payment	agents.	The	domestic	utility companies	then	obtained	a	temporary	restraining	order	from	the	Civil	District	Court	for	the	Parish	of	Orleans,	State	of	Louisiana,	enjoining	CashPoint	from distributing	funds	belonging	to	Entergy,	except	by	paying	those	funds	to	Entergy.	On	April	22,	2004,	a	petition	for	involuntary	Chapter	7	bankruptcy	was	filed against	CashPoint	by	other	creditors	in	the	United	States	Bankruptcy	Court	for	the	Southern	District	of	New	York.	In	response	to	these	events,	the	domestic	utility companies	expanded	an	existing	contract	with	another	company	to	manage	all	of	their	payment	agents.	The	domestic	utility	companies	filed	proofs	of	claim	in	the

CashPoint	bankruptcy	proceeding	in	September	2004.	Although	Entergy	cannot	precisely	determine	at	this	time	the	amount	that	CashPoint	owes	to	the	domestic utility	companies	that	may	not	be	repaid,	it	has	accrued	an	estimate	of	loss	based	on	current	information.	If	no	cash	is	repaid	to	the	domestic	utility	companies,	an event	Entergy	does	not	believe	is	likely,	the	current	estimate	of	maximum	exposure	to	loss	is	approximately	$25	million.

# Employment	Litigation

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

# NOTE	9.	LEASES

# General

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

|  | Operating | Capital |
| :--- | :--- | :--- |
| Year | Leases | Leases |
|  | (In\tThousands) | (In\tThousands) |
| 2005 | $99,246 | $9,660 |
| 2006 | 85,769 | 5,724 |
| 2007 | 68,557 | 3,438 |
| 2008 | 55,155 | 1,754 |
| 2009 | 45,240 | 237 |
| Years\tthereafter | 210,474 | 2,606 |
| Minimum\tlease\tpayments | 564,441 | 23,419 |
| Less:\tAmount\trepresenting\tinterest | - | 3,388 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $564,441 | $20,031 |

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

# Nuclear	Fuel	Leases

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

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

# Sale	and	Leaseback	Transactions

# Waterford	3	Lease	Obligations

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

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

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

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

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

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

|  | (In	Thousands) |
| :--- | :--- |
| 2005 | $14,554 |
| 2006 | 18,261 |
| 2007 | 18,754 |
| 2008 | 22,606 |
| 2009 | 32,452 |
| Years\tthereafter | 334,062 |
| Total | 440,689 |
| Less:\tAmount\trepresenting\tinterest | 192,964 |

Present	value	of	net	minimum	lease	payments

# Grand	Gulf	Lease	Obligations

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

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

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

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

|  | (In	Thousands) |
| :--- | :--- |
| 2005 | $45,423 |
| 2006 | 46,019 |
| 2007 | 46,552 |
| 2008 | 47,128 |
| 2009 | 47,760 |
| Years\tthereafter | 302,402 |
| Total | 535,284 |
| Less:\tAmount\trepresenting\tinterest | 138,165 |

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

# Pension	Plans

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

# Components	of	Net	Pension	Cost

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Service\tcost\t-\tbenefits\tearned | $76,946 | $70,337 | $56,947 |
| during\tthe\tperiod |  |  |  |
| Interest\tcost\ton\tprojected | 148,092 | 134,403 | 128,387 |
| benefit\tobligation |  |  |  |
| Expected\treturn\ton\tassets | \t(153,584) | (155,460) | (158,202) |
| Amortization\tof\ttransition\tasset | (763) | (763) | (763) |
| Amortization\tof\tprior\tservice\tcost | 5,143 | 5,886 | 5,993 |
| Recognized\tnet\tloss | 21,687 | 6,399 | 5,504 |
| Curtailment\tloss | - | 14,864 | - |
| Special\ttermination\tbenefits | - | 32,006 | - |
| Net\tpension\tcosts | $97,521\t\t$107,672 | $97,521\t\t$107,672 | $37,866 |

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

| Balance	at	beginning	of	year | $2,349,565 | $1,992,207 |
| :--- | :--- | :--- |
| Service\tcost | 76,946 | 70,337 |
| Interest\tcost | 148,092 | 134,403 |
| Amendments | 3,709 | 227 |
| Actuarial\tloss | 171,146 | 205,949 |
| Benefits\tpaid | (117,234) | (97,574) |
| Employee\tcontributions | 1,212 | 1,059 |

| Curtailment	loss | - | 10,951 |
| :--- | :--- | :--- |
| Special\ttermination\tbenefits | - | 32,006 |
| Balance\tat\tend\tof\tyear | $2,633,436 | $2,349,565 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\tof\tyear | $1,744,975 | $1,451,802 |
| Actual\treturn\ton\tplan\tassets | 170,964 | 355,043 |
| Employer\tcontributions | 72,825 | 34,645 |
| Employee\tcontributions | 1,212 | 1,059 |
| Benefits\tpaid | (117,234) | (97,574) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $1,872,742 | $1,744,975 |
| Funded\tstatus | ($760,694) | ($604,590) |
| Amounts\tnot\tyet\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Unrecognized\ttransition\tasset | (662) | (1,426) |
| Unrecognized\tprior\tservice\tcost | 29,053 | 30,467 |
| Unrecognized\tnet\tloss | 542,391 | 410,321 |
| Accrued\tpension\tcost\trecognized\tin\tthe\tbalance\tsheet | ($189,912) | ($165,228) |
| Amounts\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Accrued\tpension\tcost | ($189,912) | ($165,228) |
| Additional\tminimum\tpension\tliability | (244,280) | (180,212) |
| Intangible\tasset | 26,167 | 30,832 |
| Accumulated\tother\tcomprehensive\tincome | 10,781 | 15,359 |
| Regulatory\tasset | 207,332 | 13,021 |
| Net\tamount\trecognized | ($189,912) | ($165,228) |

# Other	Postretirement	Benefits

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

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

# Components	of	Net	Postretirement	Benefit	Cost

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |
| during\tthe\tperiod | $30,947 | $37,799 | $29,199 |
| Interest\tcost\ton\tAPBO | 53,801 | 52,746 | 44,819 |
| Expected\treturn\ton\tassets | (18,825) | (15,810) | (14,066) |
| Amortization\tof\ttransition\tobligation | 9,429 | 15,193 | 17,874 |
| Amortization\tof\tprior\tservice\tcost | (5,222) | (925) | 992 |
| Recognized\tnet\t(gain)/loss | 15,546 | 12,369 | 1,874 |
| Curtailment\tloss | \t- | 57,958 | - |
| Special\ttermination\tbenefits | - | 5,444 | - |
| Net\tother\tpostretirement\tbenefit\tcost | $85,676 | $164,774 | $80,692 |

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

| Balance	at	beginning	of	year | $941,803 | $799,506 |
| :--- | :--- | :--- |
| Service\tcost | 30,947 | 37,799 |
| Interest\tcost | 53,801 | 52,746 |
| Actuarial\tloss | 73,890 | 115,966 |
| Benefits\tpaid | (66,456) | (48,379) |
| Plan\tAmendments\t(a) | (60,231) | (84,722) |
| Plan\tparticipant\tcontributions | 9,312 | 7,074 |
| Curtailments | - | 56,369 |
| Special\ttermination\tbenefits | - | 5,444 |
| Balance\tat\tend\tof\tyear | $983,066 | $941,803 |

Change	in	Plan	Assets

| Fair	value	of	assets	at	beginning	of	year | $227,446 | $182,692 |
| :--- | :--- | :--- |
| Actual\treturn\ton\tplan\tassets | 15,550 | 22,794 |
| Employer\tcontributions | 63,399 | 63,265 |
| Plan\tparticipant\tcontributions | 9,312 | 7,074 |
| Benefits\tpaid | (66,455) | (48,379) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $249,252 | $227,446 |
| Funded\tstatus | ($733,814) | ($714,357) |
| Amounts\tnot\tyet\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Unrecognized\ttransition\tobligation | 5,594 | 44,815 |
| Unrecognized\tprior\tservice\tcost | (39,560) | (20,746) |
| Unrecognized\tnet\tloss | 391,940 | 336,005 |
| Accrued\tother\tpostretirement\tbenefit\tcost\trecognized\tin |  |  |
| the\tbalance\tsheet | ($375,840) | ($354,283) |

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

# Pension	and	Other	Postretirement	Plans'	Assets

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

|  | Pension |  | Postretirement | Postretirement |
| :--- | :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2004 | 2003 |
| Domestic\tEquity\tSecurities | 46% | 56% | 38% | 37% |
| International\tEquity\tSecurities | 21% | 14% | 14% | 0% |
| Fixed-Income\tSecurities | 31% | 28% | 47% | 60% |
| Other | 2% | 2% | 1% | 3% |

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

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

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

|  | Pension | Postretirement |
| :--- | :--- | :--- |
| Domestic\tEquity\tSecurities | 45% | 37% |
| International\tEquity\tSecurities | 20% | 14% |
| Fixed-Income\tSecurities | 31% | 49% |
| Other\t(Cash\tand\tGACs) | 4% | 0% |

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

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

# Accumulated	Pension	Benefit	Obligation

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

# Estimated	Future	Benefit	Payments

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

|  | Estimated	Future	Benefits | Estimated	Future	Benefits |
| :--- | :--- | :--- |
|  | Payments |  |
|  | Pension | Postretirement |
|  | (In\tThousands) |  |
| Year(s) |  |  |
| 2005 | $115,203 | $60,932 |
| 2006 | $116,894 | $59,761 |
| 2007 | $119,092 | $62,392 |
| 2008 | $122,728 | $64,381 |
| 2009 | $127,877 | $66,444 |
| 2010\t-\t2014 | $780,295 | $360,191 |

Contributions

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

# Additional	Information

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

|  | 2004 | 2003 |
| :--- | :--- | :--- |
|  | (In\tThousands) |  |
| Increase/(decrease)\tin\tthe\tminimum\tpension\tliability\tincluded |  |  |
| in: |  |  |
| Other\tcomprehensive\tincome | ($4,578) | ($1,639) |
| Regulatory\tassets | $73,311 | ($23,768) |

# Actuarial	Assumptions

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

|  | 1	Percentage	Point	Increase | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
|  | Impact\ton\tthe | Impact\ton\tthe | Impact\ton\tthe | Impact\ton\tthe |
|  | sum\tof\tservice | sum\tof\tservice | sum\tof\tservice | sum\tof\tservice |
|  | Impact\ton\tthe | costs\tand | Impact\ton\tthe | costs\tand |
| 2004 | APBO | interest\tcost | APBO | interest\tcost |
|  |  | Increase\t(Decrease) | Increase\t(Decrease) |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tCorporation | $99,271 | $11,587 | ($89,801) | ($10,061) |

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| \t\t\t\tPension | 6.00% | 6.25% | 6.75% |
| \t\t\t\tOther\tpostretirement | 6.00% | 6.71% | 6.75% |
| Weighted-average\trate\tof\tincrease |  |  |  |
| \tin\tfuture\tcompensation\tlevels | 3.25% | 3.25% | 3.25% |
| Expected\tlong-term\trate\tof |  |  |  |
| \treturn\ton\tplan\tassets: |  |  |  |
| \t\t\t\tTaxable\tassets | 5.50% | 5.50% | 5.50% |
| \t\t\t\tNon-taxable\tassets | 8.50% | 8.75% | 8.75% |

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

|  | . | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate |  |  |  |  |
| \t\t\t\tPension |  | 6.25% | 6.75% | 7.50% |
| \t\t\t\tOther\tpostretirement |  | 6.71% | 6.75% | 7.50% |
| Weighted-average\trate\tof |  |  |  |  |
| increase |  | 3.25% | 3.25% | 4.60% |
| \tin\tfuture\tcompensation\tlevels |  |  |  |  |
| Expected\tlong-term\trate\tof\n\treturn\ton\tplan\tassets: |  |  |  |  |
| \t\t\t\tTaxable\tassets |  | 5.50% | 5.50% | 5.50% |
| \t\t\t\tNon-taxable\tassets |  | 8.75% | 8.75% | 9.00% |

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

# Voluntary	Severance	Program

As	part	of	an	initiative	to	achieve	productivity	improvements	with	a	goal	of	reducing	costs,	primarily	in	the	Non-Utility	Nuclear	and	U.S.	Utility	businesses,	in	the second	half	of	2003	Entergy	offered	a	voluntary	severance	program	to	employees	in	various	departments.	Approximately	1,100	employees,	including	650	employees in	nuclear	operations	from	the	Non-Utility	Nuclear	and	U.S.	Utility	businesses,	accepted	the	offers.	As	a	result	of	this	program,	in	the	fourth	quarter	2003	Entergy recorded	additional	pension	and	postretirement	costs	(including	 amounts	 capitalized)	 of	 $110.3	 million	 for	 special	 termination	 benefits	 and	 plan	 curtailment charges.	These	amounts	are	included	in	the	net	pension	cost	and	net	postretirement	benefit	cost	for	the	year	ended	December	31,	2003.

# Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003

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

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

In	2004,	Entergy	continued	to	record	an	estimate	of	the	effects	the	Act	in	accounting	for	its	postretirement	benefit	plans.	In	mid-2004,	the	Financial	Accounting Standards	Board	issued	Staff	Position	No.	FAS	106-2,	Accounting	and	Disclosure	Requirements	Related	to	the	Medicare	Prescription	Drug,	Improvement	and

Modernization	Act	of	2003,	which	was	effective	for	Entergy's	June	30,	2004	interim	reporting.

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

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

# Defined	Contribution	Plans

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

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

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

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

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

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

# NOTE	11.	BUSINESS	SEGMENT	INFORMATION

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

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

Entergy's	segment	financial	information	is	as	follows:

| additions | $1,233,208 | $281,377 | $44,284 | $10,074 | $- | $1,568,943 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Energy |  |  |  |
|  |  | Non-Utility | Commodity | All |  |  |
| 2002 | U.\tS.\tUtility | Nuclear* | Services\t* | Other* | Eliminations | Consolidated |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 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\t(loss)\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\nadditions | $1,131,734 | $169,756 | $210,297 | $18,514 | $- | $1,530,301 |

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

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

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

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

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

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

|  |  | Cash |  | Remaining |
| :--- | :--- | :--- | :--- | :--- |
|  |  | through |  | Accrual\tas\tof |
|  | Restructuring | December | Non-Cash | December\t31, |
|  | Costs | 2004 | Portion | 2004 |
|  |  | (In\tMillions) |  |  |
| Fixed\tasset\timpairments | $22.5 | $- | $22.5 | $- |
| 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

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

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

# NOTE	12.	EQUITY	METHOD	INVESTMENTS

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

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Beginning\tof\tyear | $1,053,328 | $824,209 | $766,103 |
| Additional\tinvestments | 157,020 | 4,668 | 36,372 |
| Income\t(loss)\tfrom\tthe | (78,727) | 271,647 | 183,878 |
| investments |  |  |  |
| Other\tincome | 6,232 | 45,583 | 21,462 |
| Distributions\treceived | (888,260) | (105,142) | (73,902) |
| Dispositions\tand\tother | (17,814) | 12,363 | (109,704) |
| adjustments |  |  |  |
| End\tof\tyear | $231,779 | $1,053,328 | $824,209 |

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Income\tStatement\tItems |  |  |  |
| \t\t\t\tOperating\trevenues | $270,177 | $585,404 | $551,853 |
| \t\t\t\tOperating\tincome | ($111,535) | $207,301 | $159,342 |
| \t\t\t\tNet\tincome | $739,858\t(1) | $172,595 | $68,095 |
| Balance\tSheet\tItems |  |  |  |
| \t\t\t\tCurrent\tassets | $540,386 | $2,576,630 |  |
| \t\t\t\tNoncurrent\tassets | $418,038 | $1,675,334 |  |
| \t\t\t\tCurrent\tliabilities | $180,009 | $1,757,663 |  |
| \t\t\t\tNoncurrent\tliabilities | $463,899 | $1,166,540 |  |

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

# Related-party	transactions	and	guarantees

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

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

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

# NOTE	13.	ACQUISITIONS	AND	DISPOSITIONS

# Asset	Acquisitions

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

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

# Asset	Dispositions

# Entergy-Koch	Businesses

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

# Other

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

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

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

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

regulatory	risks	associated	with	the	facility.

# NOTE	14.	RISK	MANAGEMENT	AND	FAIR	VALUES

# Market	and	Commodity	Risks

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

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

Entergy's	exposure	to	market	risk	is	determined	by	a	number	of	factors,	including	the	size,	term,	composition,	and	diversification	of	positions	held,	as	well	as	market volatility	and	liquidity.	For	instruments	such	as	options,	the	time	period	during	which	the	option	may	be	exercised	and	the	relationship	between	the	current	market price	of	the	underlying	instrument	and	the	option's	contractual	strike	or	exercise	price	also	affects	the	level	of	market	risk.	A	significant	factor	influencing	the overall	level	of	market	risk	to	which	Entergy	is	exposed	is	its	use	of	hedging	techniques	to	mitigate	such	risk.	Entergy	manages	market	risk	by	actively	monitoring compliance	with	stated	risk	management	policies	as	well	as	monitoring	the	effectiveness	of	its	hedging	policies	and	strategies.	Entergy's	risk	management	policies limit	the	amount	of	total	net	exposure	and	rolling	net	exposure	during	the	stated	periods.	These	policies,	including	related	risk	limits,	are	regularly	assessed	to ensure	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	 losses	 of	 approximately	 $99	 million	 at	 December	 31,	 2004	 are	 scheduled	 to	 mature	 during	 2005.	Net	 losses	 totaling approximately	$13	million	were	realized	during	2004	on	the	maturity	of	cash	flow	hedges.	Unrealized	gains	or	losses	result	from	hedging	power	output	at	the	Non- Utility	Nuclear	power	stations	and	foreign	currency	hedges	related	to	Euro-denominated	nuclear	fuel	acquisitions.	The	related	gains	or	losses	from	hedging	power are	included	in	revenues	when	realized.	The	realized	gains	or	losses	from	foreign	currency	transactions	are	included	in	the	cost	of	capitalized	fuel.	The	maximum length	of	time	over	which	Entergy	is	currently	hedging	the	variability	in	future	cash	flows	for	forecasted	transactions	at	December	31,	2004	is	approximately	four years.	The	ineffective	portion	of	the	change	in	the	value	of	Entergy's	cash	flow	hedges	during	2004	was	insignificant.

# Fair	Values

# Financial	Instruments

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

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

# NOTE	15.	DECOMMISSIONING	TRUST	FUNDS

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

|  |  | Total | Total |
| :--- | :--- | :--- | :--- |
| 2004 | Fair | Unrealized | Unrealized |
|  | Value | Gains | Losses |
|  |  | (In\tMillions) |  |
| Equity | $995 | $166 | $17 |
| Debt\tSecurities | 1,457 | 33 | 6 |
|  | $2,452 | $199 | $23 |
| \t\tTotal |  |  |  |
| 2003 |  |  |  |
| Equity | $896 | $81 | $11 |
| Debt\tSecurities | 1,383 | 27 | 3 |
|  | $2,279 | $108 | $14 |

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

|  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Gross |  | Gross |
|  | Fair | Unrealized | Fair | Unrealized |
|  | Value | Losses | Value | Losses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $29 | $2 | $334 | $5 |
| More\tthan\t12\tmonths | 115 | 15 | 37 | 1 |
|  | $144 | $17 | $371 | $6 |

# 		Total

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

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

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

# NOTE	16.	QUARTERLY	FINANCIAL	DATA	(UNAUDITED)

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

|  | Operating | Operating | Net |
| :--- | :--- | :--- | :--- |
|  | Revenues | Income | Income\t(Loss) |
|  |  | (In\tThousands) |  |
| 2004: |  |  |  |
| \t\t\tFirst\tQuarter | $2,251,549 | $378,834 | $213,016 |
| \t\t\tSecond\tQuarter | $2,485,097 | $494,312 | $271,011 |
| \t\t\tThird\tQuarter | $2,963,581 | $571,472 | $288,047 |
| \t\t\tFourth\tQuarter | $2,423,497 | $208,946 | $160,975 |
| 2003: |  |  |  |
| \t\t\tFirst\tQuarter | $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) |

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

# Earnings	per	Average	Common	Share

|  | 2004<br>Basic | Diluted | 2003<br>Basic | Diluted |
| :--- | :--- | :--- | :--- | :--- |
| First\tQuarter | $0.90 | $0.88 | $1.77(b) | $1.73(b) |
| Second\tQuarter | $1.16 | $1.14 | $0.91 | $0.89 |
| Third\tQuarter | $1.24 | $1.22 | $1.60 | $1.57 |
| Fourth\tQuarter | $0.71 | $0.69 | ($0.19) | ($0.18) |

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

# ENTERGY'S	BUSINESS	(continued)

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

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

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

# Customers

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

|  |  | Electric	Customers | Electric	Customers | Gas	Customers |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Area\tServed | (In\tThousands) | (%) | (In\tThousands) | (%) |
| Entergy\tArkansas | Portions\tof\tArkansas | 667 | 25% |  |  |
| Entergy\tGulf\tStates | Portions\tof\tTexas\tand |  |  |  |  |
|  | Louisiana | 724 | 27% | 91 | 39% |
| Entergy\tLouisiana | Portions\tof\tLouisiana | 662 | 25% |  |  |
| Entergy\tMississippi | Portions\tof\tMississippi | 420 | 16% |  |  |
|  |  | 189 | 7% | 145 | 61% |
| Entergy\tNew\tOrleansCity\tof\tNew\tOrleans* |  |  |  |  |  |
|  |  | 2,662 | 100% | 236 | 100% |

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

# Electric	Energy	Sales

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

# Selected	2004	Electric	Energy	Sales	Data

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy | Entergy<br>(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tGWh) |  |  |  |
| Sales\tto\tretail |  |  |  |  |  |  |  |
| \t\tcustomers | 19,735 | 35,275 | 28,183 | 12,978 | 6,055 | - | 102,226 |
| Sales\tfor\tresale: |  |  |  |  |  |  |  |
| \t\t\tAffiliates | 7,437 | 1,528 | 1,129 | 305 | 1,514 | 9,212 | - |
| \t\t\tOthers | 4,911 | 3,172 | 122 | 393 | 25 | - | 8,623 |
| \t\t\t\t\t\tTotal | 32,083 | 39,975 | 29,434 | 13,676 | 7,594 | 9,212 | 110,849 |
| Average\tuse\tper |  |  |  |  |  |  |  |
| residential\tcustomer |  |  |  |  |  |  |  |
| (kWh) | 12,485 | 15,620 | 15,359 | 14,475 | 12,618 | - | 14,384 |

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

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

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

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

# Selected	2004	Natural	Gas	Sales	Data

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

| Entergy	New	Orleans | Electric	Operating<br>Revenue | Natural	Gas<br>Revenue |
| :--- | :--- | :--- |
| Residential | 40% | 50% |
| Commercial | 37% | 22% |
| Industrial | 8% | 13% |
| Governmental/Municipal | 15% | 15% |

# Retail	Rate	Regulation

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

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

| Jurisdiction | Status	of	Retail	Open	Access | %	of	Entergy's<br>2004	Revenues	Derived<br>from	Retail	Electric<br>Utility	Operations<br>in	the	Jurisdiction |
| :--- | :--- | :--- |
| Arkansas | \t Retail\topen\taccess\twas\trepealed\tin\tFebruary\t2003. | 11.6% |
| Texas | \t In\tJuly\t2004,\tthe\tPUCT\teffectively\trejected\tEntergy\tGulf\tStates'\tproposal\tto | 11.8% |
|  | submitted\tin\tthe\tTexas\tLegislature\tthat\tspecify\tthat\tretail\topen\taccess\twill\tnot |  |
|  | commence\tin\tEntergy\tGulf\tStates'\tterritory\tuntil\tthe\tPUCT\tcertifies\ta\tpower |  |
|  | region. |  |
| Louisiana | \t The\tLPSC\thas\tdeferred\tpursuing\tretail\topen\taccess,\tpending\tdevelopments\tat\tthe | 34.1% |
|  | that\twas\tfunded\tby\ta\tgroup\tof\tlarge\tindustrial\tcustomers,\tthe\tLPSC\trecently\thas |  |
|  | what\taction,\tif\tany,\tthe\tLPSC\tmight\ttake\tin\tresponse\tto\tthe\tinformation\tit |  |
|  | received. |  |
| Mississippi | \t The\tMPSC\thas\trecommended\tnot\tpursuing\topen\taccess\tat\tthis\ttime. | 10.9% |
| New\tOrleans | \t The\tCouncil\thas\ttaken\tno\taction\ton\tEntergy\tNew\tOrleans'\tproposal\tfiled\tin\t1997. | 4.5% |

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.

Entergy	Louisiana 9.7%- 11.3%(1) 	In	January	2004,	Entergy	Louisiana	filed	with	the	LPSC	an	application for	 a	 $167	 million	 base	 rate	 increase	 and	 an	 ROE	 of	 11.4%.	 The currently	 authorized	 ROE	 midpoint	 is	 10.5%.	Hearings	in	this	matter concluded	in	December	2004.	Based	on	the	evidence	submitted	at	the hearing,	the	LPSC	staff	is	recommending	approximately	a	$7	million base	 rate	 increase.	The	LPSC	staff	proposed	the	implementation	of	a formula	 rate	 plan	 that	 includes	 a	 provision	 for	 the	 recovery	 of incremental	 capacity	 costs,	 including	 those	 related	 to	 the	 proposed Perryville	 acquisition.	A	decision	by	the	LPSC	is	expected	in	mid-	to late-March	2005	on	these	issues.

In	 January	 2005,	 Entergy	 Gulf	 States	 and	 Entergy	 Louisiana	 filed testimony	with	the	LPSC	in	support	of	a	proposed	settlement	with	the LPSC	that	would	resolve,	among	other	dockets,	dockets	established	to consider	 issues	 concerning	 the	 companies'	 power	 purchases	 for	 the summers	 of	 2001,	 2002,	 2003,	 and	 2004.	The	 proposed	 settlement currently	includes	an	offer	to	refund	$14	million	to	Entergy	Louisiana's customers.	The	 LPSC	 has	 solicited	 comments	 on	 the	 proposed settlement	from	the	parties	to	the	various	proceedings	at	issue	in	the proposed settlement.	The	 proposed	 settlement	 is	 scheduled	 to	 be presented	to	the	LPSC	for	consideration	on	March	23,	2005.

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

# Fuel	Recovery

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

# Entergy	Gulf	States

# Louisiana	Jurisdiction	-	Formula	Rate	Plan

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

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

# Formula	Rate	Plan

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

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

In	September	2002,	Entergy	Louisiana	settled	a	proceeding	that	concerned	a	contract	entered	into	by	Entergy	Louisiana	to	purchase,	through	2031,	energy	generated by	a	hydroelectric	facility	known	as	the	Vidalia	project.	In	the	settlement,	the	LPSC	approved	Entergy	Louisiana's	proposed	treatment	of	the	regulatory	impact	of	a tax	accounting	election	related	to	that	project.	In	general,	the	settlement	permits	Entergy	Louisiana	to	keep	a	portion	of	the	tax	benefit	in	exchange	for	bearing	the risk	associated	with	sustaining	the	tax	treatment.	The	LPSC	settlement	divided	the	term	of	the	Vidalia	contract	into	two	segments:	2002-2012	and	2013-2031. During	the	first	eight	years	of	the	2002-2012	segment,	Entergy	Louisiana	agreed	to	credit	rates	by	flowing	through	its	fuel	adjustment	calculation	$11	million	each year,	beginning	monthly	in	October	2002.	Entergy	Louisiana	must	credit	rates	in	this	way	and	by	this	amount	even	if	Entergy	Louisiana	is	unable	to	sustain	the	tax deduction.	Entergy	Louisiana	also	must	credit	rates	by	$11	million	each	year	for	an	additional	 two	years	unless	either	 the	 tax	accounting	method	elected	 is retroactively	 repealed	 or	 the	 Internal	 Revenue	 Service	 denies	 the	 entire	 deduction	 related	 to	 the	 tax	 accounting	 method.	Entergy	 Louisiana	 agreed	 to	 credit ratepayers	additional	amounts	unless	 the	 tax	accounting	election	 is	not	sustained,	 if	 it	 is	challenged.	During	 the	years	2013-2031,	Entergy	Louisiana	and	 its ratepayers	would	share	the	remaining	benefits	of	this	tax	accounting	election.	Note	8	to	the	domestic	utility	companies	and	System	Energy	financial	statements contains	further	discussion	of	the	obligations	related	to	the	Vidalia	project.

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

# Performance-Based	Formula	Rate	Plan

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

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

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

# Formula	Rate	Plans

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

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

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

# Franchises

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

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

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

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

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

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

# Property	and	Other	Generation	Resources

# Generating	Stations

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

| Company | Total | Gas/Oil | Nuclear | Coal | Hydro |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | 4,709 | 1,613 | 1,837 | 1,189 | 70 |
| Entergy\tGulf\tStates | 6,485 | 4,890 | 968 | 627 | - |
| Entergy\tLouisiana | 5,363 | 4,276 | 1,087 | - | - |
| Entergy\tMississippi | 2,898 | 2,490 | - | 408 | - |
| Entergy\tNew\tOrleans | 915 | 915 | - | - | - |
|  | 1,143 | - | 1,143 | - | - |
| System\tEnergy |  |  |  |  |  |
|  | 21,513 | 14,184 | 5,035 | 2,224 | 70 |

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

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

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

Selected	for

Contracts

Negotiation

Signed

Notes

In	January	2004,	Entergy	Louisiana	signed	a	definitive	agreement	to	acquire	the	718	MW	Perryville	power	plant	for	$170	million.	The	agreement	has	subsequently been	amended	to	allow	the	current	plant	owner	to	retain	the	interconnection	facilities	associated	with	the	plant,	resulting	in	a	decrease	in	the	acquisition	price	to $162	million.	As	a	result	of	the	amended	terms,	the	FERC	issued	an	order	in	October	2004	disclaiming	jurisdiction	over	the	acquisition.	This	order	currently	is subject	to	rehearing	by	the	FERC.	The	plant	is	owned	by	a	subsidiary	of	Cleco	Corporation,	which	subsidiary	submitted	a	bid	in	response	to	Entergy's	Fall	2002 request	for	proposals	for	supply-side	resources.	The	signing	of	the	agreement	followed	a	voluntary	Chapter	11	bankruptcy	filing	by	the	plant's	owner.	Entergy expects	that	Entergy	Louisiana	will	own	100	percent	of	the	Perryville	plant,	and	that	Entergy	Louisiana	will	sell	75	percent	of	the	output	to	Entergy	Gulf	States under	a	long-term	cost-of-service	power	purchase	agreement.	In	addition,	Entergy	Louisiana	and	Entergy	Gulf	States	executed	an	interim	power	purchase	agreement with	the	plant's	owner	through	the	date	of	the	acquisition's	closing	(as	long	as	that	occurs	by	December	2005)	for	100	percent	of	the	output	of	the	Perryville	power plant.	In	April	2004,	the	bankruptcy	court	approved	Entergy	Louisiana's	agreement	to	acquire	the	plant.	In	March	2004,	Entergy	Gulf	States	and	Entergy	Louisiana filed	with	the	LPSC	for	its	approval	of	the	acquisition	and	long-term	cost-of-service	power	purchase	agreement.	Entergy	is	seeking	approval	from	the	LPSC	of	cost recovery	for	the	acquisition,	giving	consideration	to	the	need	for	the	power	and	the	prudence	of	Entergy	Louisiana	and	Entergy	Gulf	States	in	engaging	in	the transaction.	Hearings	are	scheduled	for	March	2005.	Assuming	regulatory	approval	by	the	LPSC,	Entergy	Louisiana	expects	the	Perryville	acquisition	to	close	in mid-2005.

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

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

Interconnections

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

# Gas	Property

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

# Titles

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

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

# Fuel	Supply

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

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

|  | Natural	Gas |  | Fuel	Oil |  | Nuclear |  | Coal |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2004 | 2005 | 2004 | 2005 | 2004 | 2005 | 2004 | 2005 |
| Entergy\tArkansas\t(a) | 1% | - | - | - | 65% | 64% | 34% | 35% |
| Entergy\tGulf\tStates | 41% | 36% | 1% | - | 36% | 36% | 22% | 28% |
| Entergy\tLouisiana | 38% | 40% | 8% | 8% | 52% | 50% | 2% | 2% |
| Entergy\tMississippi | 9% | 3% | 46% | 62% | - | - | 45% | 35% |
| Entergy\tNew\tOrleans | 55% | 55% | - | - | 32% | 31% | 13% | 14% |
| System\tEnergy | - | - | - | - | 100%(b) | 100%(b) | - | - |
| U.S.\tUtility\t(a) | 23% | 22% | 6% | 8% | 52% | 50% | 19% | 20% |

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

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

# Natural	Gas

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

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

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

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

purchases.	Entergy	Arkansas	has	a	long-term	railroad	transportation	contract	for	the	delivery	of	coal	to	both	White	Bluff	and	Independence	that	expires	in	2011.	A second	carrier	now	delivers	a	portion	of	White	Bluff's	coal	requirements	under	a	long-term	transportation	agreement	that	expires	on	December	31,	2006.

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

# Nuclear	Fuel

								The	nuclear	fuel	cycle	consists	of	the	following:

mining	and	milling	of	uranium	ore	to	produce	a	concentrate;

conversion	of	the	concentrate	to	uranium	hexafluoride	gas;

enrichment	of	the	hexafluoride	gas;

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

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

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

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

# Natural	Gas	Purchased	for	Resale

Entergy	New	Orleans	has	several	suppliers	of	natural	gas.	Its	system	is	interconnected	with	three	interstate	and	three	intrastate	pipelines.	Entergy	New	Orleans' primary	suppliers	currently	are	Atmos	Energy	and	Louisiana	Gas	Services.	Entergy	New	Orleans	has	a	"no-notice"	service	gas	purchase	contract	with	Atmos Energy	which	guarantees	Entergy	New	Orleans	gas	delivery	at	specific	delivery	points	and	at	any	volume	within	the	minimum	and	maximum	set	forth	in	the contract	amounts.	The	Atmos	Energy	gas	supply	is	transported	to	Entergy	New	Orleans	pursuant	to	a	transportation	service	agreement	with	Gulf	South	Pipeline	Co. This	service	is	subject	to	FERC-approved	rates.	Entergy	New	Orleans	has	firm	contracts	with	its	two	intrastate	suppliers	and	also	makes	interruptible	spot	market purchases.	In	recent	years,	natural	gas	deliveries	to	Entergy	New	Orleans	have	been	subject	primarily	to	weather-related	curtailments.	However,	Entergy	New Orleans	experienced	no	such	curtailments	in	2004.

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

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

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

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

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

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

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

Decision	erroneously	determined	that	the	full	costs	of	the	Vidalia	project	should	be	included	in	Entergy	Louisiana's	production	costs	for	purposes	of	calculating relative	production	costs;	and	the	Initial	Decision	erroneously	adopted	a	new	method	of	calculating	reserve	sharing	costs	rather	than	the	current	method.

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

Entergy	also	proposed	to	have	the	ICT	administer	a	transmission	expansion	pricing	protocol	that	will	increase	the	efficiency	of	transmission	pricing	on	the	Entergy system	and	that	will	be	designed	to	protect	Entergy's	native	load	customers	from	bearing	the	cost	of	transmission	upgrades	not	required	to	reliably	serve	these customers'	needs.	Entergy	intends	for	the	ICT	to	determine	whether	transmission	upgrades	associated	with	new	requests	for	service	should	be	funded	directly	by	the party	requesting	such	service	or	by	a	broader	group	of	transmission	customers,	including	Entergy's	native	load	customers.	This	determination	would	be	made	in

accordance	with	protocols	approved	by	the	FERC,	and	any	party	contesting	such	determination,	including	Entergy,	would	be	required	to	seek	review	at	the	FERC. Several	technical	conferences	regarding	the	ICT	proposal,	or	various	components	thereof,	were	held	in	2004.	Entergy	has	also	responded	to	discovery	requests	that resulted	from	these	conferences.

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

The	domestic	utility	companies	(except	Entergy	New	Orleans)	are	currently	defendants	to	several	complaints	and	rehearing	requests	before	the	FERC	in	which

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

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

# FERC	Audits

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

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

# Other	Customer-initiated	Proceedings	at	FERC

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

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

# System	Energy	and	Related	Agreements

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

# Unit	Power	Sales	Agreement

The	Unit	Power	Sales	Agreement	allocates	capacity,	energy,	and	the	related	costs	from	System	Energy's	90%	ownership	and	leasehold	interests	in	Grand	Gulf	to Entergy	Arkansas	(36%),	Entergy	Louisiana	(14%),	Entergy	Mississippi	(33%),	and	Entergy	New	Orleans	(17%).	Each	of	these	companies	is	obligated	to	make

payments	to	System	Energy	for	its	entitlement	of	capacity	and	energy	on	a	full	cost-of-service	basis	regardless	of	the	quantity	of	energy	delivered,	so	long	as	Grand Gulf	remains	in	commercial	operation.	Payments	under	the	Unit	Power	Sales	Agreement	are	System	Energy's	only	source	of	operating	revenue.	The	financial condition	of	System	Energy	depends	upon	 the	continued	commercial	operation	of	Grand	Gulf	and	 the	receipt	of	such	payments.	Entergy	Arkansas,	Entergy Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	generally	recover	payments	made	under	the	Unit	Power	Sales	Agreement	through	rates	charged	to	their customers.

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

# Availability	Agreement

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

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

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

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

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

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

# Service	Companies

Entergy	Services,	a	corporation	wholly-owned	by	Entergy	Corporation,	provides	management,	administrative,	accounting,	legal,	engineering,	and	other	services primarily	to	the	domestic	utility	companies.	Entergy	Operations	is	also	wholly-owned	by	Entergy	Corporation	and	provides	nuclear	management,	operations	and

maintenance	services	under	contract	for	ANO,	River	Bend,	Waterford	3,	and	Grand	Gulf,	subject	to	the	owner	oversight	of	Entergy	Arkansas,	Entergy	Gulf	States, Entergy	Louisiana,	and	System	Energy,	respectively.	Entergy	Services	and	Entergy	Operations	provide	their	services	to	the	domestic	utility	companies	and	System Energy	on	an	"at	cost"	basis,	pursuant	to	service	agreements	approved	by	the	SEC	under	PUHCA.

# Earnings	Ratios	of	Domestic	Utility	Companies	and	System	Energy

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

# Ratios	of	Earnings	to	Fixed	Charges

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | 3.37 | 3.17 | 2.79 | 3.29 | 3.01 |
| Entergy\tGulf\tStates | 3.04 | 1.51 | 2.49 | 2.36 | 2.60 |
| Entergy\tLouisiana | 3.60 | 3.93 | 3.14 | 2.76 | 3.33 |
| Entergy\tMississippi | 3.41 | 3.06 | 2.48 | 2.14 | 2.33 |
| Entergy\tNew\tOrleans | 3.60 | 1.73 | (b) | (c) | 2.66 |
| System\tEnergy | 3.95 | 3.66 | 3.25 | 2.12 | 2.41 |

# Ratios	of	Earnings	to	Combined	Fixed

# Charges	and	Preferred	Dividends

# Years	Ended	December	31,

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | 2.98 | 2.79 | 2.53 | 2.99 | 2.70 |
| Entergy\tGulf\tStates\t(a) | 2.90 | 1.45 | 2.40 | 2.21 | 2.39 |
| Entergy\tLouisiana | 3.16 | 3.46 | 2.86 | 2.51 | 2.93 |
| Entergy\tMississippi | 3.07 | 2.77 | 2.27 | 1.96 | 2.09 |
| Entergy\tNew\tOrleans | 3.31 | 1.59 | (b) | (c) | 2.43 |

(a) "Preferred	Dividends"	in	the	case	of	Entergy	Gulf	States	also	include	dividends	on	preference stock,	which	was	redeemed	in	July	2000.

(b) For	Entergy	New	Orleans,	earnings	for	the	twelve	months	ended	December	31,	2002	were	not adequate	to	cover	fixed	charges	and	combined	fixed	charges	and	preferred	dividends	by	$0.7 million	and	$3.4	million,	respectively.

(c) For	Entergy	New	Orleans,	earnings	for	the	twelve	months	ended	December	31,	2001	were	not adequate	to	cover	fixed	charges	and	combined	fixed	charges	and	preferred	dividends	by	$6.6

million	and	$9.5	million,	respectively.

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

# Property

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

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

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

# Energy	and	Capacity	Sales

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

# Percent	of	planned	generation	sold	forward:

| Unit-contingent | 36% | 20% | 17% | 1% | 0% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Unit-contingent\twith\tavailability\tguarantees | 54% | 52% | 38% | 25% | 0% |
| Firm\tliquidated\tdamages | 4% | 4% | 2% | 0% | 0% |
| Total | 94% | 76% | 57% | 26% | 0% |
| Planned\tgeneration\t(TWh) | 34 | 35 | 34 | 34 | 35 |
| Average\tcontracted\tprice\tper\tMWh | $39 | $41 | $42 | $44 | N/A |

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

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

# Other	Business	Activities

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

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

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

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

through	Entergy	Wholesale	Operations,	but	these	activities	were	discontinued	in	early	2002.

# Non-Nuclear	Wholesale	Assets	Business

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

| Plant | Location | Ownership | Capacity(1) | Type |
| :--- | :--- | :--- | :--- | :--- |
| Ritchie\tUnit\t2,\t544\tMW | \tHelena,\tAR | 100% | 544\tMW | \tGas/Oil |
| Independence\tUnit\t2,\t842\tMW \tNewark,\tAR | Independence\tUnit\t2,\t842\tMW \tNewark,\tAR | 14% | 121\tMW(2) | \tCoal |
| Warren\tPower,\t300\tMW | \tVicksburg,\tMS | 75% | 225\tMW(2) | \tGas\tTurbine |
| Top\tof\tIowa,\t80\tMW\t(3) | \tWorth\tCounty,\tIA | 50% | 40\tMW | \tWind |
| White\tDeer,\t80\tMW\t(3) | \tAmarillo,\tTX | 50% | 40\tMW | \tWind |
| RS\tCogen,\t425\tMW\t(3) | \tLake\tCharles,\tLA | 50% | 213\tMW | \tGas/Steam |
| Harrison\tCounty,\t550\tMW | \tMarshall,\tTX | 61% | 335\tMW(2) | \tGas\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's	non-nuclear wholesale	assets	business.	For	a	complete	listing	of	Entergy's	joint-owned	generating	stations,	refer to	"Jointly-Owned	Generating	Stations"	in	Note	1	to	the	consolidated	financial	statements.

(3) Indirectly	owned	through	interests	in	unconsolidated	joint	ventures.

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

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

# 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.

# Regulation	of	Entergy's	Business

# PUHCA

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

limits	the	operations	of	a	registered	holding	company	system	to	a	single,	integrated	public	utility	system,	plus	related	systems	and	businesses; regulates	transactions	among	affiliates	within	a	holding	company	system;

governs	the	issuance,	acquisition,	and	disposition	of	securities	and	assets	by	registered	holding	companies	and	their	subsidiaries;

limits	the	entry	by	registered	holding	companies	and	their	subsidiaries	into	businesses	other	than	electric	and/or	gas	utility	businesses;	and requires	SEC	approval	for	certain	utility	mergers	and	acquisitions.

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

# Federal	Power	Act

# The	Federal	Power	Act	regulates:

the	transmission	and	wholesale	sale	of	electric	energy	in	interstate	commerce;

the	licensing	of	certain	hydroelectric	projects;	and

certain	other	activities,	including	accounting	policies	and	practices	of	electric	and	gas	utilities.

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

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

# State	Regulation

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

oversee	utility	service;

set	retail	rates;

determine	reasonable	and	adequate	service;

require	proper	accounting;

control	leasing;

control	the	acquisition	or	sale	of	any	public	utility	plant	or	property	constituting	an	operating	unit	or	system;

set	rates	of	depreciation;

issue	certificates	of	convenience	and	necessity	and	certificates	of	environmental	compatibility	and	public	need;	and

regulate	the	issuance	and	sale	of	certain	securities.

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

retail	rates	and	service;

customer	service	standards;

certification	of	new	transmission	lines;	and

extensions	of	service	into	new	areas.

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

utility	service;

retail	rates	and	charges;

certification	of	generating	facilities;

power	or	capacity	purchase	contracts;	and

depreciation,	accounting,	and	other	matters.

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

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

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 other	matters.

# Regulation	of	the	Nuclear	Power	Industry

Atomic	Energy	Act	of	1954	and	Energy	Reorganization	Act	of	1974

Under	the	Atomic	Energy	Act	of	1954	and	the	Energy	Reorganization	Act	of	1974,	the	operation	of	nuclear	plants	is	heavily	regulated	by	the	NRC,	which	has	broad power	 to	 impose	 licensing	 and	 safety-related	 requirements.	The	NRC	has	broad	authority	 to	 impose	fines	or	shut	down	a	unit,	or	both,	depending	upon	 its assessment	of	the	severity	of	the	situation,	until	compliance	is	achieved.	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy,	as	owners of	all	or	portions	of	ANO,	River	Bend,	Waterford	3,	and	Grand	Gulf,	respectively,	and	Entergy	Operations,	as	the	licensee	and	operator	of	these	units,	are	subject	to the	jurisdiction	of	the	NRC.	Entergy	has	made	substantial	capital	expenditures	at	these	nuclear	plants	because	of	revised	safety	requirements	of	the	NRC	in	the	past, and	additional	expenditures	could	be	required	in	the	future.	Entergy's	Non-Utility	Nuclear	business	is	subject	to	the	NRC's	jurisdiction	as	the	owner	and	operator	of Pilgrim,	 Indian	 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,	2004	of	$156.3	million	for	the	one-time	fee.	Entergy's	Non-Utility	Nuclear	business	has	accepted	assignment	of	the	Pilgrim,	FitzPatrick,	Indian Point	3,	Indian	Point	2,	and	Vermont	Yankee	spent	fuel	disposal	contracts	with	the	DOE	held	by	their	previous	owners.	 The	previous	owners	have	paid	or	retained liability	for	the	fees	for	all	generation	prior	to	the	purchase	dates	of	those	plants.	The	fees	payable	to	the	DOE	may	be	adjusted	in	the	future	to	assure	full	recovery. Entergy	considers	all	costs	incurred	for	the	disposal	of	spent	nuclear	fuel,	except	accrued	interest,	to	be	proper	components	of	nuclear	fuel	expense.	Provisions	to recover	such	costs	have	been	or	will	be	made	in	applications	to	regulatory	authorities	for	the	U.S.	Utility	plants.

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

As	a	result	of	the	DOE's	failure	to	begin	disposal	of	spent	nuclear	fuel	in	1998	pursuant	to	the	Nuclear	Waste	Policy	Act	of	1982	and	the	spent	fuel	disposal

contracts,	Entergy's	nuclear	owner/licensee	subsidiaries	have	incurred	and	will	continue	to	incur	damages.		These	subsidiaries	in	November	2003	began	litigation	to recover	the	damages	caused	by	the	DOE's	delay	in	performance.		Management	cannot	predict	the	timing	or	amount	of	any	potential	recovery.

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

# Nuclear	Plant	Decommissioning

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

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

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

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

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

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

# Energy	Policy	Act	of	1992

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

# Price-Anderson	Act

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

# Environmental	Regulation

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

# Clean	Air	Act	and	Subsequent	Amendments

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

New	source	review	and	preconstruction	permits	for	new	sources	of	criteria	air	pollutants	and	significant	modifications	to	existing	facilities;

Acid	rain	program	for	control	of	sulfur	dioxide	(SO )	and	nitrogen	oxides	(NO ); 2 x

Ozone	non-attainment	area	program	for	control	of	NO

	and	volatile	organic	compounds;

Hazardous	air	pollutant	emissions	reduction	program;

Interstate	Air	Transport;	and

Operating	permits	program	for	administration	and	enforcement	of	these	and	other	Clean	Air	Act	programs.

# New	Source	Review

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

# Acid	Rain	Program

The	 Clean	Air	Act	 provides	 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.	Plant	owners	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,	incremental emission	allowance	costs,	and	the	availability	and	cost	of	purchased	power.

# Ozone	Non-attainment

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

The	EPA	has	now	reclassified	the	Beaumont-Port	Arthur	area	from	"moderate"	to	"serious"	and	has	reclassified	the	Baton	Rouge	area	from	"serious"	to	"severe". These	actions	will	require	that	Texas	and	Louisiana	adopt	plans	to	restrict	the	emission	of	certain	air	pollutants	and	to	make	progress	toward	eventual	attainment	of national	standards.	Texas	adopted	and	forwarded	to	the	EPA	for	approval	revisions	to	the	state	implementation	plan	in	December	2004.	Based	on	this	submittal, Entergy	Gulf	States	believes	that	new	NO control	equipment	will	not	be	required	at	the	Beaumont-Port	Arthur	area	facilities.	The	Louisiana	plan	revisions	were x due	in	June	2004;	however,	due	to	legal	and	regulatory	disputes	over	requirements	unrelated	to	Entergy's	interests,	the	state	has	chosen	to	delay	the	submittal.	The final	content	and	effect	on	Entergy	of	these	developing	plans	is	unknown,	but	Entergy	continues	to	monitor	events	in	these	areas.

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

# Hazardous	Air	Pollutants

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

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

# Interstate	Air	Transport

In	January	2004,	the	EPA	proposed	the	Interstate	Air	Quality	Rule,	renamed	the	Clean	Air	Interstate	Rule	(CAIR),	which	intends	to	reduce	SO 2 	and	NO x 	emissions from	plants	in	order	to	improve	air	quality	in	the	northeastern	United	States.	The	EPA	has	postponed	issuing	a	final	rule	until	the	second	quarter	of	2005.	The	rule has	the	potential	to	require	significant	pollution	control	capital	and/or	operating	costs	(including	any	potential	impacts	to	the	value	of	SO 	allowances).	Entergy's 2 capital	investment	and	annual	operation	and	maintenance	allowance	purchase	costs	will	depend	on	the	economic	assessment	of	NO x 	and	SO 2 	allowance	markets, cost	of	control	technologies,	and	unit	usage	as	well	as	other	uncertainties	described	below.

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

In	May	2004,	the	EPA	re-proposed	the	Best	Retrofit	Control	Technology	(BART)	regulations	which	could	potentially	result	in	a	requirement	to	install	SO 2 	pollution control	technology	on	certain	of	Entergy's	coal	and	oil	generation	units.	The	impact	of	this	proposed	rule	is	unclear,	but	could	result	in	significant	increased	capital and	operating	costs	on	certain	units.

# Future	Legislative	and	Regulatory	Developments

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

designation	by	the	EPA	and	state	environmental	agencies	of	areas	that	are	not	in	attainment	with	national	ambient	air	quality	standards; EPA	initiatives	related	to	regional	haze;

introduction	of	several	bills	in	Congress	proposing	further	limits	on	NO x ,	SO 2, 	mercury,	or	limits	on	carbon	dioxide	(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 2 emission	limits	on	the	electric	industry	in	the	future,	Entergy	has	initiated	actions	designed	to	reduce	its	exposure	to	potential	new	governmental	requirements

related	to	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 	emission	"intensity,"	or	rate	of 2 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

# Clean	Water	Act

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

# 316(b)	Cooling	Water	Intake	Structures

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

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

# Oil	Pollution	Prevention	Regulation

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

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

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

# 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	with	the	EPA	to	perform	removal	action	at	the	site.	In	2002,	approximately	7,400	tons	of	contaminated	soil	and	debris	were	excavated and	disposed	of	from	an	area	within	the	service	center.	In	2003,	a	cap	was	constructed	over	the	remedial	area	to	prevent	the	migration	of	contamination	to	the surface.	Entergy	Gulf	States	anticipates	commencement	of	a	ten-year	groundwater	monitoring	study	upon	issuance	of	a	negotiated	order	by	the	EPA,	which	is expected	to	issue	the	order	in	early	2005.	Entergy	Gulf	States	believes	that	its	ultimate	responsibility	for	this	site	will	not	materially	exceed	its	existing	clean-up provision	of	$1.5	million.

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

# Entergy	Louisiana	and	Entergy	New	Orleans

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

The	Southern	Transformer	Shop	located	in	New	Orleans	served	both	Entergy	Louisiana	and	Entergy	New	Orleans.	This	transformer	shop	is	now	closed	and	soil	and groundwater	assessment	activities	have	resumed	since	the	demolition	of	the	onsite	buildings	and	structures	was	completed	in	early	2004.	Entergy	has	entered	into

the	Voluntary	Remediation	Program	with	the	LDEQ	and	submitted	a	Site	Investigation	Workplan.	 A	liability	of	approximately	$350,000	has	been	established	for environmental	assessment	and	remediation	costs	with	estimated	completion	by	the	end	of	2005.

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

# Entergy	Arkansas,	Entergy	Gulf	States,	and	Entergy	Louisiana

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

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

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	Entergy	New	Orleans	customers	being	overcharged	by	more	than	$100	million over	a	period	of	years.	Hearings	were	held	in	February	and	March	2002.	In	February	2004,	the	City	Council	approved	a	resolution	that	resulted	in	a	refund	to customers	of	$11.3	million,	including	interest,	during	the	months	of	June	through	September	2004.	The	resolution	concludes,	among	other	things,	that	the	record does	not	support	an	allegation	 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.	Oral	argument	on	the	plaintiffs'	appeal	was	conducted	in February	2005.

# Entergy	New	Orleans	Rate	of	Return	Lawsuit

In	April	1998,	a	group	of	residential	and	business	ratepayers	filed	a	complaint	against	Entergy	New	Orleans	in	state	court	in	Orleans	Parish	purportedly	on	behalf	of all	ratepayers	in	New	Orleans.	The	plaintiffs	allege	that	Entergy	New	Orleans	overcharged	ratepayers	by	at	least	$300	million	since	1975	in	violation	of	limits	on Entergy	New	Orleans'	rate	of	return	that	the	plaintiffs	allege	were	established	by	ordinances	passed	by	the	Council	in	1922.	The	plaintiffs	seek,	among	other	things, (i)	a	declaratory	judgment	that	such	franchise	ordinances	have	been	violated;	and	(ii)	a	remand	to	the	Council	for	the	establishment	of	the	amount	of	overcharges plus	interest.	Entergy	New	Orleans	believes	the	lawsuit	is	without	merit.	Entergy	New	Orleans	has	charged	only	those	rates	authorized	by	the	Council	in	accordance with	applicable	law.	In	May	2000,	a	court	of	appeal	granted	Entergy	New	Orleans'	exception	to	jurisdiction	in	the	case	and	dismissed	the	proceeding.	The	Louisiana Supreme	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.

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

# Texas	Power	Price	Lawsuit

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

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

Plaintiffs	estimate	that	customers	in	Texas	were	charged	at	least	$57	million	above	prevailing	market	prices	for	power.	Plaintiffs	seek	actual,	consequential	and exemplary	damages,	costs	and	attorneys'	fees,	and	disgorgement	of	profits.	In	September	2003,	the	Entergy	defendants	removed	the	lawsuit	to	the	federal	court	in Galveston,	and	in	October	2003,	filed	a	pleading	seeking	dismissal	of	the	plaintiffs'	claims.	In	October	2003,	the	plaintiffs	filed	a	motion	to	remand	the	case	to	state court.	In	January	2004,	the	federal	court	determined	that	it	did	not	have	jurisdiction	over	the	subject	matter	of	the	lawsuit,	and	remanded	the	case	to	the	state	district court	in	Chambers	County.	In	November	2004,	the	state	district	court	dismissed	the	case	based	on	a	lack	of	jurisdiction.	The	plaintiffs	have	initiated	appellate proceedings	in	the	Court	of	Appeals.

# Entergy	Louisiana	Formula	Ratemaking	Plan	Lawsuit

In	May	1998,	a	group	of	ratepayers	filed	a	complaint	against	Entergy	Louisiana	and	the	LPSC	in	state	court	in	East	Baton	Rouge	Parish	purportedly	on	behalf	of	all Entergy	Louisiana	ratepayers.	The	plaintiffs	allege	that	the	formula	ratemaking	plan	authorized	by	the	LPSC	has	allowed	Entergy	Louisiana	to	earn	amounts	in excess	of	a	fair	return.	The	plaintiffs	seek,	among	other	things,	(i)	a	declaratory	judgment	that	the	formula	ratemaking	plan	is	an	improper	ratemaking	practice;	and (ii)	a	refund	of	the	amounts	allegedly	charged	in	excess	of	proper	ratemaking	practices.	This	case	has	not	been	active,	and	abandonment	issues	are	being	evaluated. At	this	time,	management	cannot	determine	the	amount	of	damages	being	sought.

# Murphy	Oil	Lawsuit	(Entergy	Corporation	and	Entergy	Louisiana)

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

Murphy	Oil	and	other	defendants	settled	with	the	plaintiffs	for	$8.8	million,	but	Entergy	Louisiana	did	not	participate	in	the	settlement.	After	trial	for	the	remaining parties	in	the	proceeding,	the	judge	issued	a	decision	finding	Entergy	Louisiana	40%	responsible	and	awarding	monetary	damages,	which	total	approximately	$11 million	with	interest	against	Entergy	Louisiana.	Entergy	Louisiana	appealed	the	judgment	to	the	Court	of	Appeals.	Entergy	Louisiana	has	insurance	in	place	for claims	of	this	type,	and	management	does	not	expect	a	material	adverse	financial	effect	from	this	decision.

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

In	1998,	a	group	of	property	owners	filed	a	class	action	suit	against	Entergy	Corporation,	Entergy	Gulf	States,	Entergy	Services	and	Entergy	Technology	Holding Company	in	state	court	in	Jefferson	County,	Texas	purportedly	on	behalf	of	all	property	owners	in	each	of	the	states	throughout	the	Entergy	service	area	who	have conveyed	easements	to	the	defendants.	The	lawsuit	alleged	that	Entergy	installed	fiber	optic	cable	across	their	property	without	obtaining	appropriate	easements. The	plaintiffs	sought	actual	damages	for	the	use	of	the	land	and	a	share	of	the	profits	made	through	use	of	the	fiber	optic	cables	and	punitive	damages.	The	state court	petition	was	voluntarily	dismissed,	and	the	plaintiffs	commenced	a	class	action	suit	with	the	same	claims	in	the	United	States	District	Court	in	Beaumont, Texas.	Both	sides	have	filed	motions	for	summary	judgment,	which	were	heard	by	the	court	in	late	2001.	In	2003,	the	district	judge	ruled	that	as	a	matter	of	law,	all of	the	Texas	easements	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.	In	April	2004,	the	trial	court	entered	an	order	denying	the	plaintiffs' request	that	this	case	be	certified	as	a	class.	The	plaintiffs	have	appealed	this	ruling	to	the	United	States	Court	of	Appeals	for	the	Fifth	Circuit.	At	this	time, management	cannot	determine	the	specific	amount	of	damages	being	sought.

Several	property	owners	have	filed	a	class	action	suit	against	Entergy	Louisiana,	Entergy	Services,	ETHC,	and	Entergy	Technology	Company	in	state	court	in	St. James	Parish,	Louisiana	purportedly	on	behalf	of	all	property	owners	in	Louisiana	who	have	conveyed	easements	to	the	defendants.	The	lawsuit	alleges	that	Entergy installed	fiber	optic	cable	across	their	property	without	obtaining	appropriate	easements.	The	plaintiffs	seek	actual	damages	for	the	use	of	the	land	and	a	share	of	the profits	made	through	use	of	the	fiber	optic	cables	and	punitive	damages.	Entergy	removed	the	case	to	federal	court	in	New	Orleans;	however,	the	District	Court remanded	the	case	back	to	state	court.		While	Entergy	appealed	this	ruling,	recently	the	United	States	Court	of	Appeals	for	the	Fifth	Circuit	denied	this	appeal.		In December	2003,	the	trial	court	held	a	hearing	to	determine	if	a	class	should	be	certified.	On	February	18,	2004,	the	trial	court	entered	an	order	certifying	this	matter as	a	class.	Entergy	has	appealed	this	ruling	to	the	Louisiana	Fifth	Circuit	Court	of	Appeals,	and	oral	arguments	have	been	held.	At	this	time,	management	cannot determine	the	specific	amount	of	damages	being	sought.

Several	property	owners	have	filed	separate	lawsuits	against	Entergy	Corporation,	Entergy	Mississippi,	Entergy	Services,	ETHC,	and	ETC	in	state	court	in	various counties	in	Mississippi	alleging	that	Entergy	Mississippi	installed	fiber	optic	cable	across	their	properties	without	obtaining	appropriate	easements.	The	plaintiffs seek	actual	damages	for	the	use	of	the	land,	a	share	of	the	profits	made	through	use	of	the	fiber	optic	cables,	and	at	least	$20	million	in	punitive	damages	in	one case,	and	an	unspecified	amount	of	punitive	damages	in	the	other	cases.

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

Numerous	lawsuits	have	been	filed	in	federal	and	state	courts	in	Texas,	Louisiana,	and	Mississippi	primarily	by	contractor	employees	in	the	1950-1980	timeframe against	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Mississippi	as	premises	owners	of	power	plants,	for	damages	caused	by	alleged exposure	to	asbestos	or	other	hazardous	material.	Many	other	defendants	are	named	in	these	lawsuits	as	well.	Currently,	there	are	approximately	480	lawsuits involving	approximately	10,000	claims.	Reserves	have	been	established	that	should	be	adequate	to	cover	any	exposure.	Additionally,	negotiations	continue	with insurers	to	recover	more	reimbursement,	while	new	coverage	is	being	secured	to	minimize	anticipated	future	potential	exposures.	Management	believes	that	loss exposure	has	been	and	will	continue	to	be	handled	successfully	so	that	the	ultimate	resolution	of	these	matters	will	not	be	material,	in	the	aggregate,	to	the companies'	financial	position	or	results	of	operation.

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

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

Included	in	the	employment	litigation	are	two	cases	filed	in	state	court	in	Claiborne	County,	Mississippi	in	December	2002.	The	two	cases	were	filed	by	former employees	 of	 Entergy	 Operations	 who	 were	 based	 at	 Grand	 Gulf.	Entergy	 Operations	 and	 Entergy	 employees	 are	 named	 as	 defendants.	The	 cases	 make employment-related	claims,	and	seek	in	total	$53	million	in	alleged	actual	damages	and	$168	million	in	punitive	damages.	Entergy	subsequently	removed	both proceedings	to	the	federal	district	in	Jackson,	Mississippi.	Entergy	cannot	predict	the	ultimate	outcome	of	this	proceeding.

# Research	Spending

Entergy	is	a	member	of	the	Electric	Power	Research	Institute	(EPRI).	EPRI	conducts	a	broad	range	of	research	in	major	technical	fields	related	to	the	electric	utility industry.	Entergy	participates	in	various	EPRI	projects	based	on	Entergy's	needs	and	available	resources.	The	domestic	utility	companies	contributed	$1.6	million	in

# Employees

Employees	are	an	integral	part	of	Entergy's	commitment	to	serving	its	customers.	As	of	December	31,	2004,	Entergy	employed	14,425	people.

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	increased	$16.2	million	due	to	lower	other	operation	and	maintenance	expenses,	a	lower	effective	income	tax	rate	for	2004	compared	to	2003,	and	lower interest	charges.	The	increase	was	partially	offset	by	lower	net	revenue.

	Net	income	decreased	$9.6	million	due	to	lower	net	revenue,	higher	depreciation	and	amortization	expenses,	and	a	higher	effective	income	tax	rate	for	2003 compared	to	2002.	The	decrease	was	substantially	offset	by	lower	other	operation	and	maintenance	expenses,	higher	other	income,	and	lower	interest	charges.

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

| 2003	net	revenue | $998.7 |
| :--- | :--- |
| Deferred\tfuel\tcost\trevisions | (16.9) |
| Other | (3.4) |
| 2004\tnet\trevenue | $978.4 |

Deferred	fuel	cost	revisions	includes	the	difference	between	the	estimated	deferred	fuel	expense	and	the	actual	calculation	of	recoverable	fuel	expense,	which occurs	on	an	annual	basis.	Deferred	fuel	cost	revisions	decreased	net	revenue	due	to	a	revised	estimate	of	fuel	costs	filed	for	recovery	at	Entergy	Arkansas	in	the March	2004	energy	cost	recovery	rider,	which	reduced	net	revenue	by	$11.5	million.	The	remainder	of	the	variance	is	due	to	the	2002	energy	cost	recovery	true-up, made	in	the	first	quarter	of	2003,	which	increased	net	revenue	in	2003.

# Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	credits

										Gross	operating	revenues	increased	primarily	due	to:

an	increase	of	$20.7	million	in	fuel	cost	recovery	revenues	due	to	an	increase	in	the	energy	cost	recovery	rider	effective	April	2004	(fuel	cost	recovery revenues	are	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements);

an	increase	of	$15.5	million	in	Grand	Gulf	revenues	due	to	an	increase	in	the	Grand	Gulf	rider	effective	January	2004;

an	increase	of	$13.9	million	in	gross	wholesale	revenue	primarily	due	to	increased	sales	to	affiliated	systems;	and

an	increase	of	$9.5	million	due	to	volume/weather	primarily	resulting	from	increased	usage	during	the	unbilled	sales	period,	partially	offset	by	the	effect	of milder	weather	on	billed	sales	in	2004.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	increased	recovery	of	deferred	fuel	and	purchased	power	costs	primarily	due	to	an	increase	in	April 2004	in	the	energy	cost	recovery	rider	and	the	true-ups	to	the	2003	and	2002	energy	cost	recovery	rider	filings.

Other	regulatory	credits	decreased	primarily	due	to	the	over-recovery	of	Grand	Gulf	costs	due	to	an	increase	in	the	Grand	Gulf	rider	effective	January	2004.

Net	revenue,	which	is	Entergy	Arkansas'	measure	of	gross	margin,	consists	of	operating	revenues	net	of:	1)	fuel,	fuel-related,	and	purchased	power	expenses	and	2)

other	regulatory	credits.	Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2003	to	2002.

| 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 |
| Deferred\tfuel\tcost\trevisions | 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	mid-	and	late	December	2000,	two	separate	ice	storms	left	226,000	and	212,500	Entergy	Arkansas	customers,	respectively,	without	electric	power	in	its	service area.	Entergy	Arkansas	filed	a	proposal	to	recover	costs	plus	carrying	charges	associated	with	power	restoration	caused	by	the	ice	storms.	Entergy	Arkansas'	final storm	damage	cost	determination	reflected	costs	of	approximately	$195	million.	The	APSC	approved	a	settlement	agreement	submitted	in	March	2002	by	Entergy Arkansas,	the	APSC	staff,	and	the	Arkansas	Attorney	General.	In	the	March	2002	settlement,	the	parties	agreed	that	$153	million	of	the	ice	storm	costs	would	be classified	as	incremental	ice	storm	expenses	that	can	be	offset	against	the	TCA	on	a	rate	class	basis,	and	any	excess	of	ice	storm	costs	over	the	amount	available	in the	TCA	would	be	deferred	and	amortized	over	30	years,	although	such	excess	costs	were	not	allowed	to	be	included	as	a	separate	component	of	rate	base.	The 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	related	to	the	TCA,	Entergy	Arkansas	filed	to	return	$18.1	million	of	the	TCA to	certain	large	general	service	class	customers	that	paid	more	into	the	TCA	than	their	allocation	of	storm	costs.	The	APSC	approved	the	return	of	funds	to	the	large general	service	customer	class	in	the	form	of	refund	checks	in	August	2002.	As	part	of	the	implementation	of	the	March	2002	settlement	agreement	provisions,	the TCA	procedure	ceased	with	the	2001	earnings	evaluation.

Of	the	remaining	ice	storm	costs,	$32.2	million	was	addressed	through	established	ratemaking	procedures,	including	$22.2	million	classified	as	capital	additions, while	$3.8	million	of	the	ice	storm	costs	was	not	recovered	through	rates.

The	effect	on	net	income	of	the	March	2002	settlement	agreement	and	2001	earnings	review	was	a	$2.2	million	increase	in	2003,	because	the	decrease	in	net revenue	was	offset	by	the	decrease	in	operation	and	maintenance	expenses	discussed	below.

The	volume/weather	variance	is	the	result	of	less	favorable	sales	volume	primarily	due	to	the	effect	of	colder	winter	weather	in	December	2002.

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

The	net	wholesale	revenue	variance	was	primarily	due	to	an	increase	in	sales	volume	to	Entergy	New	Orleans	pursuant	to	a	purchased	power	agreement	and	also due	to	higher	wholesale	prices	and	volume.

Deferred	fuel	cost	revisions	includes	the	difference	between	the	estimated	deferred	fuel	expense	and	the	actual	calculation	of	recoverable	fuel	expense,	which occurs	on	an	annual	basis.	In	2002,	the	deferred	fuel	expense	estimate	was	larger	than	the	actual	recoverable	fuel	expense,	which	decreased	net	revenue.	In	2003, the	actual	recoverable	fuel	expense	was	larger	than	the	deferred	fuel	expense	estimate,	which	increased	net	revenue.

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$95.7	million	in	gross	wholesale	revenue	due	to	the	same	factors	discussed	above	that	increased net	wholesale	revenue	and	also	due	to	increased	sales	to	affiliates	in	addition	to	the	Entergy	New	Orleans	sales	mentioned	above.	The	increase	was	partially	offset by	a	decrease	of	$74.4	million	in	fuel	cost	recovery	revenues	due	to	a	decrease	in	the	annual	recovery	rider	in	October	2002.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	the	displacement	of	higher-priced	natural	gas	generation	by	lower-priced	purchased	power	and	coal generation.

Other	regulatory	credits	decreased	primarily	due	to	the	March	2002	settlement	agreement	and	2001	earnings	review	mentioned	above,	which	increased	other regulatory	credits	in	2002	to	offset	$159.9	million	in	other	operation	and	maintenance	expenses	related	to	the	December	2000	ice	storms.	The	decrease	was	partially offset	by	the	asset	retirement	obligation	mentioned	above,	which	increased	regulatory	credits	in	2003	to	offset	the	increase	in	decommissioning	expense.

Other	operation	and	maintenance	expenses	decreased	primarily	due	to	voluntary	severance	accruals	of	$31.8	million	in	2003.	The	decrease	was	partially	offset	by the	following:

an	increase	of	$6.6	million	in	customer	service	support	costs;	and

an	increase	of	$5.1	million	in	benefits	costs.

Interest	charges	decreased	primarily	due	to	the	refinancing	of	First	Mortgage	Bonds	in	mid-2003.

Other	operation	and	maintenance	expenses	decreased	primarily	due	to	expenses	in	2002	of	$159.9	million	due	to	the	March	2002	settlement	agreement	and	2001 earnings	review	which	allowed	Entergy	Arkansas	to	recover	a	large	majority	of	2000	and	2001	ice	storm	repair	expenses	through	the	previously-collected	transition cost	account	amounts	(which	was	offset	by	a	corresponding	decrease	in	other	regulatory	credits	and	has	no	effect	on	net	income).	Decreases	of	$18.7	million	in administrative	and	general	expenses	and	$4.7	million	in	contract	labor	costs	also	contributed	to	the	decrease.	The	decrease	was	partially	offset	by	the	following:

voluntary	severance	accruals	of	$31.8	million	in	2003;	and

an	increase	of	$10.4	million	in	benefits	costs.

Decommissioning	expense	increased	due	to	the	implementation	of	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations."	The	increase	in	decommissioning expense	was	offset	by	increases	in	other	regulatory	credits	and	interest	and	dividend	income	and	has	no	effect	on	net	income.

Depreciation	and	amortization	expenses	increased	primarily	due	to	an	increase	in	plant	in	service.

# Other	income	increased	primarily	due	to:

an	increase	of	$7.3	million	in	interest	and	dividend	income	due	to	the	implementation	of	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations."	As mentioned	above,	the	increase	was	offset	in	decommissioning	expense	and	has	no	effect	on	net	income;	and

an	increase	of	$4.8	million	in	the	allowance	for	equity	funds	used	during	construction	due	to	an	increase	in	construction	work	in	progress.

Interest	charges	decreased	primarily	due	to:

an	increase	in	interest	expense	in	2002	resulting	from	a	true-up	of	the	annual	fuel	recovery	rider	in	March	2002	of	$4.5	million;

interest	recorded	in	2002	of	$4.1	million	(offset	by	a	corresponding	decrease	in	other	regulatory	credits	and	has	no	effect	on	net	income)	on	the	transition	cost account	obligation,	which	was	terminated	as	a	result	of	the	March	2002	settlement	agreement;	and

an	increase	in	2003	of	$3.0	million	in	the	allowance	for	borrowed	funds	used	during	construction	due	to	an	increase	in	construction	work	in	progress.

The	effective	income	tax	rates	for	2004,	2003,	and	2002	were	38.5%,	45.5%,	and	34.5%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rate.	The	lower	effective	income	tax	rate	in	2004 compared	to	2003	was	primarily	due	to	book	and	tax	differences	related	to	utility	plant	items	and	flow-through	items.		Tax	reserves	not	expected	to	reverse	within the	next	year	are	reflected	as	non-current	taxes	accrued	on	the	balance	sheet.

# Cash	Flow

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $8,834 | $95,513 | $103,466 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 446,298 | 437,520 | 357,421 |
| Investing\tactivities | (269,385) | (337,509) | (249,438) |
| Financing\tactivities | (96,003) | (186,690) | (115,936) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 80,910 | (86,679) | (7,953) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $89,744 | $8,834 | $95,513 |

Cash	flow	from	operations	increased	$8.8	million	in	2004	compared	to	2003	primarily	due	to	income	tax	benefits	received	in	2004,	and	increased	recovery	of deferred	fuel	costs.	This	increase	was	substantially	offset	by	money	pool	activity.

In	2003,	the	domestic	utility	companies	and	System	Energy	filed,	with	the	IRS,	a	change	in	tax	accounting	method	notification	for	their	respective	calculations	of cost	of	goods	sold.	The	adjustment	implemented	a	simplified	method	of	allocation	of	overhead	to	the	production	of	electricity,	which	is	provided	under	the	IRS capitalization	regulations.	The	cumulative	adjustment	placing	these	companies	on	the	new	methodology	resulted	in	a	$1.171	billion	deduction	for	Entergy	Arkansas on	Entergy's	2003	income	tax	return.	There	was	no	cash	benefit	from	the	method	change	in	2003.	In	2004,	Entergy	Arkansas	realized	$173	million	in	cash	tax benefit	from	the	method	change.	This	tax	accounting	method	change	is	an	issue	across	the	utility	industry	and	will	likely	be	challenged	by	the	IRS	on	audit.		As	of December	31,	2004,	Entergy	Arkansas	has	a	net	operating	loss	(NOL)	carryforward	for	tax	purposes	of	$766.9	million,	principally	resulting	from	the	change	in	tax accounting	method	related	to	cost	of	goods	sold.		If	the	tax	accounting	method	change	is	sustained,	Entergy	Arkansas	expects	to	utilize	the	NOL	carryforward through	2006.

Cash	flow	from	operations	increased	$80.1	million	in	2003	compared	to	2002	primarily	due	to	income	taxes	paid	of	$2.2	million	in	2003	compared	to	income	taxes paid	of	$83.9	million	in	2002,	and	money	pool	activity.	This	increase	was	partially	offset	by	decreased	recovery	of	deferred	fuel	costs	in	2003.

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

| 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $23,561 | ($69,153) | $4,279 | $23,794 |

Money	pool	activity	used	$92.7	million	of	Entergy	Arkansas'	operating	cash	flow	in	2004,	provided	$73.4	million	in	2003,	and	provided	$19.5	million	in	2002.	See Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

The	decrease	of	$68.1	million	in	net	cash	used	in	investing	activities	in	2004	compared	to	2003	was	primarily	due	to	a	decrease	in	construction	expenditures resulting	from	less	transmission	upgrade	work	requested	by	merchant	generators	in	2004	combined	with	lower	spending	on	customer	support	projects	in	2004.

The	increase	of	$88.1	million	in	net	cash	used	in	investing	activities	in	2003	compared	to	2002	was	primarily	due	to	an	increase	in	construction	expenditures	of $57.4	million	and	the	maturity	of	$38.4	million	of	other	temporary	investments	in	the	first	quarter	of	2002.	Construction	expenditures	increased	in	2003	primarily due	to	the	following:

a	FERC	ruling	that	shifted	responsibility	for	transmission	upgrade	work	performed	for	independent	power	producers	to	Entergy	Arkansas;	and the	ANO	1	steam	generator,	reactor	vessel	head,	and	transformer	replacement	project.

The	decrease	of	$90.7	million	in	net	cash	used	in	financing	activities	in	2004	compared	to	2003	was	primarily	due	to	the	net	redemption	of	$2.4	million	of	long-term debt	in	2004	compared	to	$109.3	million	in	2003,	partially	offset	by	the	payment	of	$16.2	million	more	in	common	stock	dividends	during	the	same	period.

The	increase	of	$70.8	million	in	net	cash	used	in	financing	activities	in	2003	compared	to	2002	was	primarily	due	to	the	net	redemption	of	$109.3	million	of	long- term	debt	in	2003	compared	to	the	net	issuance	of	$18.4	million	in	2002,	partially	offset	by	the	payment	of	$56.3	million	less	in	common	stock	dividends	during	the same	period.

See	Note	5	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	details	on	long-term	debt.

# Uses	of	Capital

Entergy	Arkansas	requires	capital	resources	for:

construction	and	other	capital	investments;

debt	and	preferred	stock	maturities;

working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;	and dividend	and	interest	payments.

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

|  | 2005 | 2006-2007 | 2008-2009 | after	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| capital\tinvestment\t(1) | $321 | $455 | N/A | N/A | $776 |
| Long-term\tdebt | $147 | $- | $1 | $1,191 | $1,339 |
| Capital\tlease\tpayments | $10 | $9 | $2 | $2 | $23 |
| Operating\tleases | $24 | $38 | $23 | $54 | $139 |
| Purchase\tobligations\t(2) | $433 | $832 | $827 | $2,840 | $4,932 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $42 | $52 | N/A | N/A | $94 |

(1) Includes	approximately	$175	to	$180	million	annually	for	maintenance	capital,	which	is	planned spending	on	routine	capital	projects	that	are	necessary	to	support	reliability	of	service,	equipment	or systems	and	to	support	normal	customer	growth.

(2) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	For	Entergy	Arkansas	almost	all	of	the	total consists	of	unconditional	fuel	and	purchased	power	obligations,	including	its	obligations	under	the Unit	Power	Sales	Agreement,	which	is	discussed	in	Note	8	to	the	domestic	utility	companies	and System	Energy	financial	statements.

(3) It	 is	 expected	 that	 additional	 financing	 under	 the	 leases	 will	 be	 arranged	 as	 needed	 to	 acquire additional	fuel,	 to	pay	 interest,	and	 to	pay	maturing	debt.	If	such	additional	financing	cannot	be arranged,	however,	the	lessee	in	each	case	must	repurchase	sufficient	nuclear	fuel	to	allow	the	lessor to	meet	its	obligations.

In	addition	to	these	contractual	obligations,	Entergy	Arkansas	expects	to	contribute	$20.6	million	to	its	pension	plans	and	$16.1	million	to	other	postretirement	plans in	2005.

On	July	25,	2002,	the	Board	authorized	Entergy	Arkansas	and	Entergy	Operations	to	replace	the	ANO	1	steam	generators	and	reactor	vessel	closure	head.	Entergy management	estimates	the	cost	of	the	fabrication	and	replacement	to	be	approximately	$235	million,	of	which	approximately	$96	million	has	been	incurred	through 2004.	$115	million	is	expected	to	be	incurred	in	2005,	with	the	remainder	of	the	costs	expected	in	2006.	Management	expects	that	the	replacement	will	occur	during a	planned	refueling	outage	in	2005.	Entergy	Arkansas	filed	with	the	APSC	in	January	2003	a	request	for	a	declaratory	order	that	the	investment	in	the	replacement is	in	the	public	interest.	The	APSC	issued	the	requested	order	in	May	2003.	This	order	is	analogous	to	the	order	received	in	1998	prior	to	the	replacement	of	the ANO	2	steam	generators.	See	''Nuclear	Matters''	below	for	further	discussion	of	the	replacement	of	the	ANO	1	steam	generators	and	reactor	vessel	closure	head.

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

As	a	wholly-owned	subsidiary,	Entergy	Arkansas	pays	dividends	to	Entergy	Corporation	from	its	earnings	at	a	percentage	determined	monthly.	Entergy	Arkansas' long-term	debt	indentures	restrict	the	amount	of	retained	earnings	available	for	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred stock.	As	of	December	31,	2004,	Entergy	Arkansas	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$394.9	million.

Entergy	Arkansas'	sources	to	meet	its	capital	requirements	include:

cash	on	hand;

debt	or	preferred	stock	issuances;	and

bank	financing	under	new	or	existing	facilities	(Entergy	Arkansas	has	a	364-day	credit	facility	available	with	an	expiration	date	of	April	2005	in	the	amount	of $85	million,	of	which	none	was	drawn	at	December	31,	2004).

Entergy	Arkansas	issued	first	mortgage	bonds	in	2004	as	follows:

The	proceeds	were	used	to	redeem	junior	subordinated	debentures	as	follows:

Entergy	Arkansas	may	refinance	or	redeem	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Arkansas	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also	subject	to issuance	 tests	 set	 forth	 in	 corporate	 charters,	 bond	 indentures,	 and	 other	 agreements.	Entergy	Arkansas	 has	 sufficient	 capacity	 under	 these	 tests	 to	 meet	 its foreseeable	capital	needs.

Short-term	borrowings	by	Entergy	Arkansas,	including	borrowings	under	the	money	pool,	are	limited	to	an	amount	authorized	by	the	SEC,	which	is	$235	million. Under	its	SEC	Order	and	without	further	authorization,	Entergy	Arkansas	cannot	incur	additional	short-term	indebtedness	unless	(a)	it	and	Entergy	Corporation maintain	a	common	equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool	borrowings,	the	security	to	be	issued	(if	rated)	and	all	outstanding securities	of	Entergy	Arkansas,	as	well	as	all	outstanding	securities	of	Entergy	Corporation,	that	are	rated,	are	rated	investment	grade.	See	Note	4	to	the	domestic utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	Entergy	Arkansas'	short-term	borrowing	limits.

# Utility	Restructuring

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

At	FERC,	restructuring	at	the	wholesale	level	has	begun	but	has	been	delayed.	It	is	too	early	to	predict	the	ultimate	effects	of	changes	in	U.S.	energy	markets. Restructuring	issues	are	complex	and	are	continually	affected	by	events	at	the	national,	regional,	state,	and	local	levels.	However,	these	changes	may	result,	in	the long	term,	in	fundamental	changes	in	the	way	traditional	integrated	utilities	and	holding	company	systems,	like	the	Entergy	system,	conduct	their	business.	Some	of these	changes	may	be	positive	for	Entergy,	while	others	may	not.

# System	Agreement	Proceedings

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

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

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

its	continued	participation	in	the	System	Agreement	is	appropriate.

The	domestic	utility	companies	(except	Entergy	New	Orleans)	are	currently	defendants	to	several	complaints	and	rehearing	requests	before	the	FERC	in	which independent	generation	entities	(GenCos)	are	seeking	a	refund	of	monies	that	the	GenCos	had	previously	paid	to	the	Entergy	companies	for	facilities	necessary	to connect	their	generation	facilities	to	Entergy's	transmission	system.	The	FERC	has	issued	initial	orders	in	response	to	two	of	the	complaints	and	in	certain	other dockets	ordering	Entergy	to	refund	approximately	$100	million	in	expenses	and	tax	obligations	previously	paid	by	the	GenCos,	including	$42	million	for	Entergy Arkansas.	The	refunds	will	be	in	the	form	of	transmission	credits	that	will	be	utilized	over	time	as	the	GenCos	take	transmission	service	from	Entergy.	To	the	extent the	Entergy	companies	are	ordered	to	provide	such	refunds,	these	costs	will	qualify	for	inclusion	in	the	Entergy	companies'	rates.	The	recovery	of	these	costs	is	not automatic,	however,	especially	at	the	retail	level,	where	the	majority	of	the	cost	recovery	would	occur.	Entergy	intends	to	pursue	all	regulatory	and	legal	avenues available	to	it	in	order	to	have	these	orders	reversed	and	have	the	affected	interconnection	agreements	reinstated	as	agreed	to	originally	by	the	generators.

Entergy	has	submitted	an	Emergency	Interim	Request	for	Rehearing	requesting	the	FERC	to	defer	the	hearing	process	and	 instead	proceed	 initially	with	an independent	audit	of	the	AFC	program	and	the	expansion	of	the	current	process	involving	other	market	participants	to	address	a	broader	range	of	issues.	Entergy

believes	that	this	type	of	approach	is	a	more	efficient	and	effective	mechanism	for	evaluating	the	AFC	program.	Following	the	completion	of	the	independent	audit and	process	involving	other	market	participants,	the	FERC	could	determine	whether	other	procedural	steps	are	necessary.	The	FERC	has	not	yet	ruled	on	the Emergency	Interim	Request	for	Rehearing	submitted	by	Entergy.

Entergy	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,	8,	and	12	to	the	domestic	utility companies	and	System	Energy	financial	statements.

# State	and	Local	Rate	Regulatory	Risks

The	rates	that	Entergy	Arkansas	charges	for	its	services	are	an	important	item	influencing	Entergy	Arkansas'	financial	position,	results	of	operations,	and	liquidity. Entergy	Arkansas	is	closely	regulated	and	the	rates	charged	to	its	customers	are	determined	in	regulatory	proceedings.	A	governmental	agency,	the	APSC,	is primarily	responsible	for	approval	of	the	rates	charged	to	customers.	Entergy	Arkansas'	fuel	costs	recovered	from	customers	are	also	subject	to	regulatory	scrutiny. Refer	to	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	fuel	recovery	and	retail	rate	proceedings.

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

In	August	2001,	the	NRC	issued	a	bulletin	requesting	all	pressurized	water	reactor	owners	and	operators	to	report	on	the	structural	integrity	of	their	reactor	vessel head	penetration	nozzles	to	justify	continued	operations	past	December	31,	2001.	These	types	of	reactors	are	susceptible	to	stress	corrosion	cracking	of	the	reactor vessel	head	nozzles.	ANO	1	and	ANO	2	are	pressurized	water	reactors.	In	December	2001,	Entergy	issued	a	request	for	proposal	to	provide	replacement	steam generators	 for	ANO	 1.	Entergy	subsequently	entered	a	contract	for	delivery	of	the	replacement	generators	in	August	2005	in	time	for	installation	during	the scheduled	refueling	outage.	Both	the	new	steam	generators	and	the	reactor	vessel	head	will	be	installed	in	the	fall	of	2005.	To	date,	there	has	been	no	primary	side stress	corrosion	cracking	identified	in	the	ANO	2	reactor	vessel	head.	Inspections	of	the	ANO	2	reactor	vessel	head	will	continue	during	planned	refueling	outages.

Entergy	Arkansas	filed	with	the	APSC	in	January	2003	a	request	for	a	declaratory	order	that	the	investment	in	the	replacement	is	in	the	public	interest.	The	APSC issued	the	requested	order	in	May	2003.	This	order	is	analogous	to	the	order	received	in	1998	prior	to	the	replacement	of	the	ANO	2	steam	generators.

# Environmental	Risks

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

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

Regulations	require	Entergy	Arkansas	to	decommission	the	ANO	1	and	ANO	2	nuclear	power	plants	after	the	facilities	are	taken	out	of	service,	and	money	is collected	 and	 deposited	 in	 trust	 funds	 during	 the	 facilities'	 operating	 lives	 in	 order	 to	 provide	 for	 this	 obligation.	Entergy	 Arkansas	 conducts	 periodic decommissioning	cost	studies	(typically	updated	every	five	years)	to	estimate	the	costs	that	will	be	incurred	to	decommission	the	facilities.	The	following	key assumptions	have	a	significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	Entergy	Arkansas'	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over	present	cost	levels by	an	annual	factor	approximating	CPI-U.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost	of	decommissioning	a	facility	by	as much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin	immediately	upon	plant retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable	regulations.	While	the	effect	of	these assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a	"safestore"	status	can	possibly	decrease	the	present	value	of these	obligations.	As	discussed	in	Note	8	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	Entergy	Arkansas	recorded	a	revision	in 2004	to	its	estimated	decommissioning	cost	liability	for	ANO	1	and	ANO	2	to	reflect	changes	due	to	a	new	decommissioning	study.		The	changes	in probability	for	ANO	1	and	ANO	2	had	no	effect	on	net	income	because,	as	discussed	further	below,	any	amounts	recorded	related	to	SFAS	143	are	offset	by the	recording	of	regulatory	assets	or	regulatory	liabilities	when	projected	decommissioning	costs	are	collected	in	rates.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	DOE	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear	fuel,	and	legislation	has	been passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	Until	this	site	is	available,	however,	nuclear	plant	operators	must	provide	for interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and	maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs of	developing	and	maintaining	these	facilities	can	have	a	significant	effect	(as	much	as	16%	of	estimated	decommissioning	costs).	These	estimates	could change	in	the	future	based	on	the	timing	of	the	opening	of	the	Yucca	Mountain	facility,	the	schedule	for	shipments	to	that	facility	when	it	is	opened,	or	other factors.

Technology	and	Regulation	-	To	date,	there	is	limited	practical	experience	in	the	United	States	with	actual	decommissioning	of	large	nuclear	facilities.	As experience	is	gained	and	technology	changes,	cost	estimates	could	also	change.	If	regulations	regarding	nuclear	decommissioning	were	to	change,	this	could

have	a	potentially	significant	effect	on	cost	estimates.	The	effect	of	these	potential	changes	is	not	presently	determinable.	Entergy	Arkansas'	decommissioning cost	studies	assume	current	technologies	and	regulations.

Through	2001,	Entergy	Arkansas	collected	 the	projected	costs	of	decommissioning	ANO	1	and	ANO	2	 through	rates	charged	 to	customers.	Now,	based	on assumptions	approved	by	the	APSC,	including	an	assumed	license	extension	for	ANO	2	(ANO	1's	license	has	already	been	extended),	which	significantly	extends the	earnings	period,	and	the	sufficiency	of	previously	collected	funds,	Entergy	Arkansas	is	not	collecting	additional	funds	to	decommission	ANO	1	and	ANO	2	in its	current	rates.	The	assumptions	will	be	reviewed	annually	and	reflected	in	Entergy	Arkansas'	filing	of	its	annual	determination	of	the	nuclear	decommissioning rate	rider.	The	amounts	that	were	collected	through	rates,	which	were	based	upon	decommissioning	cost	studies,	were	deposited	in	decommissioning	trust	funds.

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.

The	net	effect	of	implementing	this	standard	for	Entergy	Arkansas	was	recorded	as	a	regulatory	asset,	with	no	resulting	impact	on	Entergy	Arkansas'	net	income. Entergy	Arkansas	recorded	this	regulatory	asset	because	its	existing	rate	mechanism	is	based	on	the	original	or	historical	cost	standard	that	allows	Entergy	Arkansas to	recover	all	ultimate	costs	of	decommissioning	existing	assets	from	current	and	future	customers.	Upon	implementation,	assets	and	liabilities	increased	by	$532 million	in	2003	as	a	result	of	recording	the	asset	retirement	obligation	at	its	fair	value	as	determined	under	SFAS	143,	increasing	total	utility	plant	by	$106	million, reducing	accumulated	depreciation	by	$252	million,	and	recording	the	related	regulatory	asset	of	$174	million.

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

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

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

Actuarial	Assumption

Change	in Assumption Impact	on	2004 Pension	Cost Impact	on	Projected Benefit	Obligation Increase/(Decrease)

| Discount	rate | (0.25%) | $2,001 | $20,608 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,055 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $907 | $5,200 |

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

|  | Change	in | Impact	on	2004 | Postretirement	Benefit |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Postretirement\tBenefit\tCost | Obligation |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $557 | $3,633 |
| Discount\trate | (0.25%) | $342 | $4,623 |

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

Total	pension	cost	for	Entergy	Arkansas	in	2004	was	$16.5	million.	Entergy	Arkansas	anticipates	2005	pension	cost	to	increase	to	$21.8	million	due	to	decrease	in the	discount	rate	(from	6.25%	to	6.00%)	and	the	expected	rate	of	return	(from	8.75%	to	8.5%)	used	to	calculate	benefit	obligations.	Entergy	Arkansas	contributed $5.3	million	to	its	pension	plan	in	2004,	and	anticipates	making	$20.6	million	in	contributions	in	2005.	The	rise	in	pension	funding	requirements	is	due	to	declining interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to	2002,	partially	offset	by	the	Pension	Funding	Equity	Act	relief	passed	in	April	2004.

Entergy	Arkansas'	accumulated	benefit	obligation	at	December	31,	2004,	2003,	and	2002	exceeded	plan	assets.	As	a	result,	Entergy	Arkansas	was	required	to recognize	an	additional	minimum	liability	as	prescribed	by	SFAS	87	at	December	31,	2004,	2003,	and	2002.	At	December	31,	2004,	Entergy	Arkansas	increased	its additional	minimum	liability	to	$81.2	million	from	$54.9	million	at	December	31,	2003.	Entergy	Arkansas	decreased	its	intangible	asset	for	the	unrecognized	prior service	cost	to	$10.3	million	at	December	31,	2004	from	$13.3	million	at	December	31,	2003.	Entergy	Arkansas	also	increased	the	regulatory	asset	to	$70.8	million at	December	31,	2004	from	$41.6	million	at	December	31,	2003.	Net	income	for	2004,	2003,	and	2002	was	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Arkansas	in	2004	were	$12.8	million,	including	$5	million	in	savings	due	to	the estimated	effect	of	future	Medicare	Part	D	subsidies.	Entergy	Arkansas	expects	2005	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$13.7 million,	including	$5.8	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.	The	increase	in	postretirement	health	care	and	life insurance	benefit	costs	is	due	to	the	decrease	in	the	discount	rate	(from	6.25%	to	6.00%)	and	an	increase	in	the	health	care	cost	trend	rate	used	to	calculate	benefit obligations.

# To	the	Board	of	Directors	and	Shareholders

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Arkansas,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	income,	retained earnings,	and	cash	flows	(pages	165	through	170	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period	ended	December	31,	2004. These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	based	on our	audits.

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

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Arkansas,	Inc.	as	of	December	31,	2004	and	2003, and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	5	and	Note	8	to	the	notes	to	respective	financial	statements,	in	2003	Entergy	Arkansas,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	 Standards	 Board Interpretation	 No.	 46,	Consolidation	 of	 Variable Interest	 Entities,	and	 Statement	 of	 Financial	Accounting	 Standards	 No.	 143, Accounting	for	Asset	Retirement	Obligations.

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

New	Orleans,	Louisiana

INCOME	STATEMENTS

| OPERATING	REVENUES |  |  |  |
| :--- | :--- | :--- | :--- |
| Domestic\telectric | \t$1,653,145\t\t\t$1,589,670\t\t\t$1,561,110 | \t$1,653,145\t\t\t$1,589,670\t\t\t$1,561,110 | \t$1,653,145\t\t\t$1,589,670\t\t\t$1,561,110 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 210,394 | 153,866 | 294,244 |
| \t\tPurchased\tpower | 484,849 | 476,447 | 355,211 |
| \t\tNuclear\trefueling\toutage\texpenses | 24,568 | 23,638 | 24,387 |
| \t\tOther\toperation\tand\tmaintenance | 384,424 | 402,108 | 543,677 |
| Decommissioning | 32,902 | 35,887 | - |
| Taxes\tother\tthan\tincome\ttaxes | 35,848 | 37,385 | 38,127 |
| Depreciation\tand\tamortization | 206,926 | 202,497 | 187,525 |
| Other\tregulatory\tcredits\t-\tnet | (20,501) | (39,347) | (184,270) |
| TOTAL | 1,359,410 | 1,292,481 | 1,258,901 |
| OPERATING\tINCOME | 293,735 | 297,189 | 302,209 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 11,737 | 12,153 | 7,324 |
| Interest\tand\tdividend\tincome | 10,298 | 9,790 | 2,467 |
| Miscellaneous\t-\tnet | (6,354) | (4,332) | (6,442) |
| TOTAL | 15,681 | 17,611 | 3,349 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 79,521 | 87,666 | 89,923 |
| Other\tinterest\t-\tnet | 4,909 | 3,555 | 13,287 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (6,288) | (7,726) | (4,699) |
| TOTAL | 78,142 | 83,495 | 98,511 |
| INCOME\tBEFORE\tINCOME\tTAXES | 231,274 | 231,305 | 207,047 |
| Income\ttaxes | 89,064 | 105,296 | 71,404 |
| NET\tINCOME | 142,210 | 126,009 | 135,643 |
| Preferred\tdividend\trequirements\tand\tother | 7,776 | 7,776 | 7,776 |
| EARNINGS\tAPPLICABLE\tTO\nCOMMON\tSTOCK | $134,434 | $118,233 | $127,867 |

See	Notes	to	Respective	Financial	Statements.

# STATEMENTS	OF	CASH	FLOWS

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $142,210 | $126,009 | $135,643 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby |  |  |  |
| operating\tactivities: |  |  |  |
| \t\tReserve\tfor\tregulatory\tadjustments | 3,099 | 1,739 | - |
| \t\tOther\tregulatory\tcredits\t-\tnet | (20,501) | (39,347) | (184,270) |
| \t\tDepreciation,\tamortization,\tand\tdecommissioning | 239,828 | 238,384 | 187,525 |
| \t\tDeferred\tincome\ttaxes\tand\tinvestment\ttax\tcredits | 65,847 | 48,357 | 54,955 |

		Changes	in	working	capital:

| TOTAL | 399,421 | 377,985 |
| :--- | :--- | :--- |
| UTILITY\tPLANT |  |  |
| Electric | 6,124,359 | 5,948,090 |
| Property\tunder\tcapital\tlease | 17,500 | 24,047 |
| Construction\twork\tin\tprogress | 226,172 | 238,807 |
| Nuclear\tfuel\tunder\tcapital\tlease | 93,855 | 102,691 |
| Nuclear\tfuel | 12,201 | 7,466 |
| TOTAL\tUTILITY\tPLANT | 6,474,087 | 6,321,101 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 2,753,525 | 2,627,441 |
| UTILITY\tPLANT\t-\tNET | 3,720,562 | 3,693,660 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 101,658 | 128,311 |
| \t\tOther\tregulatory\tassets | 400,174 | 437,544 |
| Other | 42,514 | 45,798 |
| TOTAL | 544,346 | 611,653 |
| TOTAL\tASSETS | \t$5,193,392\t\t$5,058,078 | \t$5,193,392\t\t$5,058,078 |

# BALANCE	SHEETS

# LIABILITIES	AND	SHAREHOLDERS'	EQUITY

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $147,000 | $\t- |
| Accounts\tpayable: |  |  |
|  | 68,829 | 106,958 |
| \t\tAssociated\tcompanies |  |  |
| \t\tOther | 89,896 | 92,638 |
| Customer\tdeposits | 41,639 | 37,693 |
| Taxes\taccrued | 35,874 | - |
| Interest\taccrued | 21,376 | 21,424 |
| Obligations\tunder\tcapital\tleases | 49,816 | 59,089 |
| Other | 19,648 | 16,924 |
| TOTAL | 474,078 | 334,726 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,121,623 | 996,455 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 68,452 | 73,280 |
| Obligations\tunder\tcapital\tleases | 61,538 | 67,648 |
| Other\tregulatory\tliabilities | 67,362 | 52,923 |
| Decommissioning | 492,745 | 567,546 |
| Accumulated\tprovisions | 34,977 | 40,149 |
| Long-term\tdebt | 1,191,763 | 1,338,378 |
| Other | 237,447 | 192,200 |
| TOTAL | 3,275,907 | 3,328,579 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDERS'\tEQUITY |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 116,350 | 116,350 |
| Common\tstock,\t$0.01\tpar\tvalue,\tauthorized\t325,000,000 |  |  |
| \t\tshares;\tissued\tand\toutstanding\t46,980,196\tshares\tin\t2004 |  |  |
| \t\tand\t2003 | 470 | 470 |
| Paid-in\tcapital | 591,127 | 591,127 |
| Retained\tearnings | 735,460 | 686,826 |
| TOTAL | 1,443,407 | 1,394,773 |

# STATEMENTS	OF	RETAINED	EARNINGS

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| Retained\tEarnings,\tJanuary\t1 | $686,826 | $638,193 | $636,226 |
| \t\tAdd:\n\t\t\t\tNet\tincome | 142,210 | 126,009 | 135,643 |

| Preferred	stock | 7,776 | 7,776 | 7,776 |
| :--- | :--- | :--- | :--- |
| \t\t\t\t\t\tCommon\tstock | 85,800 | 69,600 | 125,900 |
| \t\t\t\t\t\t\t\tTotal | 93,576 | 77,376 | 133,676 |
| Retained\tEarnings,\tDecember\t31 | $735,460 | $686,826 | $638,193 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,653,145 | $1,589,670 | $1,561,110 | $1,776,776 | $1,762,635 |
| Net\tIncome | $142,210 | $126,009 | $135,643 | $178,185 | $137,047 |
| Total\tassets | $5,193,392 | $5,058,078 | $4,569,511 | $4,451,580 | $4,228,211 |
| Long-term\tobligations\t(1) | $1,253,301 | $1,406,026 | $1,246,567 | $1,417,262 | $1,401,062 |

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

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $539 | $526 | $556 | $586 | $561 |
| \t\tCommercial | 305 | 291 | 304 | 330 | 307 |
| \t\tIndustrial | 318 | 305 | 330 | 371 | 353 |
| \t\tGovernmental | 16 | 15 | 15 | 16 | 15 |
| \t\t\t\tTotal\tretail | 1,178 | 1,137 | 1,205 | 1,303 | 1,236 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 250 | 234 | 165 | 240 | 246 |
| \t\t\t\tNon-associated\tcompanies | 186 | 188 | 164 | 201 | 235 |
| \t\tOther | 39 | 31 | 27 | 33 | 46 |
| \t\t\t\tTotal | $1,653 | $1,590 | $1,561 | $1,777 | $1,763 |
| Billed\tElectric\tEnergy\tSales |  |  |  |  |  |
| (GWh): |  |  |  |  |  |
| \t\tResidential | 7,028 | 7,057 | 7,050 | 6,918 | 6,791 |
| \t\tCommercial | 5,428 | 5,328 | 5,221 | 5,162 | 5,063 |
| \t\tIndustrial | 7,004 | 6,999 | 7,074 | 7,052 | 7,240 |
| \t\tGovernmental | 275 | 266 | 255 | 245 | 239 |
| \t\t\t\tTotal\tretail | 19,735 | 19,650 | 19,600 | 19,377 | 19,333 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 7,437 | 7,036 | 6,811 | 7,217 | 6,513 |
| \t\t\t\tNon-associated\tcompanies | 4,911 | 5,399 | 5,069 | 4,909 | 5,537 |
| \t\t\t\tTotal | 32,083 | 32,085 | 31,480 | 31,503 | 31,383 |

# ENTERGY	GULF	STATES,	INC.

Net	income	increased	$149.7	million	primarily	due	to	the	following:

the	$107.7	million	accrual	($65.6	million	net-of-tax)	in	June	2003	for	the	loss	that	would	be	associated	with	a	final,	non-appealable	decision	disallowing abeyed	River	Bend	plant	costs.	See	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	more	details	regarding	the	River Bend	abeyed	plant	costs;

the	$21.3	million	net-of-tax	cumulative	effect	of	accounting	change	in	2003	due	to	the	implementation	of	SFAS	143.	See	"Critical	Accounting	Estimates"

below	for	more	information	on	the	implementation	of	SFAS	143;

an	increase	if	$39.7	million	(pre-tax)	in	net	revenue,	as	discussed	below;

miscellaneous	income	of	$27.7	million	(pre-tax)	resulting	from	a	revision	of	the	decommissioning	liability	for	River	Bend	and	of	$10	million	(pre-tax)

resulting	from	a	reduction	in	the	loss	provision	for	an	environmental	clean-up	site,	both	of	which	occurred	in	2004	and	are	discussed	below;

a	decrease	of	$23.2	million	(pre-tax)	in	interest	charges	on	long-term	debt,	as	discussed	below;	and

a	decrease	of	$12.0	million	(pre-tax)	in	other	operation	and	maintenance	expenses,	as	discussed	below.

The	increase	was	partially	offset	by	a	higher	effective	income	tax	rate.

Entergy	Gulf	States	experienced	a	significant	decline	in	net	income	in	2003	compared	to	2002	primarily	due	to	the	following:

the	$107.7	million	accrual	($65.6	million	net-of-tax)	for	the	loss	that	would	be	associated	with	a	final,	nonappealable	decision	disallowing	abeyed	River	Bend plant	costs.	See	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	more	details	regarding	the	River	Bend	abeyed	plant costs;

the	$21.3	million	net-of-tax	cumulative	effect	of	accounting	change	due	to	the	implementation	of	SFAS	143.	See	"Critical	Accounting	Estimates"	below	for more	information	on	the	implementation	of	SFAS	143;

a	decrease	of	$20.6	million	(pre-tax)	in	net	revenue,	as	discussed	below;	and

an	increase	of	$19.2	million	(pre-tax)	in	other	operation	and	maintenance	expenses,	as	discussed	below.

The	decrease	was	partially	offset	by	a	lower	effective	income	tax	rate.

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

|  | (In	Millions) |
| :--- | :--- |
| 2003\tnet\trevenue | $1,110.1 |
| Volume/weather | 26.7 |
| Net\twholesale\trevenue | 13.0 |
| Summer\tcapacity\tcharges | 5.5 |
| Price\tapplied\tto\tunbilled\tsales | 4.8 |
| Fuel\trecovery\trevenues | (14.2) |
| Other | 3.9 |
| 2004\tnet\trevenue | $1,149.8 |

The	volume/weather	variance	resulted	primarily	from	an	increase	of	1,179	GWh	in	electricity	usage	in	the	industrial	sector.	Billed	usage	also	increased	a	total	of	291 GWh	in	the	residential,	commercial,	and	governmental	sectors.

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

Summer	capacity	charges	variance	 is	due	 to	 the	amortization	 in	2003	of	deferred	capacity	charges	for the	summer	of	2001	compared to the	absence	of the amortization	in	2004.	The	amortization	of	these	capacity	charges	began	in	June	2002	and	ended	in	May	2003.

The	price	applied	to	unbilled	sales	variance	resulted	primarily	from	an	increase	in	the	fuel	price	applied	to	unbilled	sales.

Fuel	recovery	revenues	represent	an	under-recovery	of	fuel	charges	that	are	recovered	in	base	rates.

Entergy	Gulf	States	recorded	$22.6	million	of	provisions	in	2004	for	potential	rate	refunds.	These	provisions	are	not	included	in	the	Net	Revenue	table	above because	they	are	more	than	offset	by	provisions	recorded	in	2003.

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$187.8	million	in	fuel	cost	recovery	revenues	as	a	result	of	higher	fuel	rates	in	both	the	Louisiana and	Texas	jurisdictions.	The	increases	in	volume/weather	and	wholesale	revenue,	discussed	above,	also	contributed	to	the	increase.

Fuel	and	purchased	power	expenses	increased	primarily	due	to:

increased	recovery	of	deferred	fuel	costs	due	to	higher	fuel	rates;

increases	in	the	market	prices	of	natural	gas,	coal,	and	purchased	power;	and

an	increase	in	electricity	usage,	discussed	above.

Other	regulatory	credits	increased	primarily	due	to	the	amortization	in	2003	of	deferred	capacity	charges	for	the	summer	of	2001	compared	to	the	absence	of amortization	in	2004.	The	amortization	of	these	charges	began	in	June	2002	and	ended	in	May	2003.

|  | (In	Millions) |
| :--- | :--- |
| 2002\tnet\trevenue | $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	was	due	to	higher	electric	sales	volume	in	the	service	territory.	Billed	usage	increased	a	total	of	517	GWh	in	the	residential	and commercial	sectors.	The	increase	was	partially	offset	by	a	decrease	in	industrial	usage	of	470	GWh	due	to	the	loss	of	two	large	industrial	customers	to	cogeneration. The	customers	accounted	for	approximately	1%	of	Entergy	Gulf	States'	net	revenue	in	2002.

In	2002,	deferred	fuel	costs	of	$8.9	million	related	to	a	Texas	fuel	reconciliation	case	were	written	off	and	$6.5	million	in	expense	resulted	from	an	adjustment	in	the deregulated	asset	plan	percentage	as	the	result	of	a	power	uprate	at	River	Bend.

The	increase	in	net	wholesale	revenue	was	primarily	due	to	an	increase	in	sales	volume	to	municipal	and	co-op	customers	and	also	to	affiliated	systems	related	to Entergy's	generation	resource	planning.

The	base	rate	decreases	were	effective	June	2002	and	January	2003,	both	in	the	Louisiana	jurisdiction.	The	January	2003	base	rate	decrease	of	$22.1	million	had	a minimal	impact	on	net	income	due	to	a	corresponding	reduction	in	nuclear	depreciation	and	decommissioning	expenses	associated	with	the	change	in	accounting	to reflect	an	assumed	extension	of	River	Bend's	useful	life.

In	2002,	a	gain	of	$15.2	million	was	recognized	for	the	Louisiana	portion	of	the	1988	Nelson	Units	1	and	2	sale.	Entergy	Gulf	States	received	approval	from	the LPSC	to	discontinue	applying	amortization	of	the	gain	against	recoverable	fuel,	resulting	in	the	recognition	of	the	deferred	gain	in	income.

Rate	refund	provisions	caused	a	decrease	in	net	revenue	due	to	additional	provisions	recorded	in	2003	compared	to	2002	for	potential	rate	actions	and	refunds.

# Gross	operating	revenues	and	fuel	and	purchased	power	expenses

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$440.2	million	in	fuel	cost	recovery	revenues	as	a	result	of	higher	fuel	rates	in	both	the	Louisiana and	Texas	jurisdictions.

Fuel	and	purchased	power	expenses	increased	$471.1	million	due	to	an	increase	in	the	market	prices	of	natural	gas	and	purchased	power.

Other	operation	and	maintenance	expenses	decreased	primarily	due	to:

voluntary	severance	program	accruals	of	$22.5	million	in	2003;	and a	decrease	of	$4.3	million	in	nuclear	material	and	labor	costs	due	to	reduced	staff	in	2004.

The	decrease	was	partially	offset	by	the	following:

an	increase	of	$8.5	million	in	benefit	costs;	and

an	increase	of	$5	million	in	customer	service	support	costs.

Miscellaneous	income	-	net	increased	$145.6	million	primarily	due	to:

the	$107.7	million	accrual	in	June	2003	for	the	loss	that	would	be	associated	with	a	final,	non-appealable	decision	disallowing	abeyed	River	Bend	plant	costs. See	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	more	details	regarding	the	River	Bend	abeyed	plant	costs; the	River	Bend	decommissioning	cost	liability	revision	made	in	accordance	with	a	new	decommissioning	cost	study	that	reflected	an	expected	life	extension for	the	plant.	For	the	portion	of	River	Bend	not	subject	to	cost-based	ratemaking,	the	revised	estimate	resulted	in	the	elimination	of	the	asset	retirement	cost that	had	been	recorded	at	the	time	of	adoption	of	SFAS	143	with	the	remainder	recorded	as	miscellaneous	income	of	$27.7	million;	and a	reduction	of	approximately	$10	million	in	the	loss	provision	related	to	an	environmental	clean-up	site.

Interest	on	long-term	debt	decreased	$23.2	million	primarily	due	to	the	financing	and	debt	restructuring	program	implemented	in	2003,	which	resulted	in	extended maturities	and	lower	interest	rates	in	Entergy	Gulf	States'	debt	portfolio.

Other	operation	and	maintenance	expenses	increased	primarily	due	to	voluntary	severance	accruals	of	$22.5	million	in	2003.

Decommissioning	expense	increased	primarily	due	to	the	implementation	of	SFAS	143.	The	increase	in	decommissioning	expense	was	offset	by	increases	in	other regulatory	credits	and	interest	and	dividend	income	and	has	no	effect	on	net	income.

Depreciation	and	amortization	expenses	decreased	primarily	due	to	decreased	rates	associated	with	the	assumed	life	extension	of	River	Bend,	partially	offset	by higher	depreciation	due	to	an	increase	in	plant	in	service.	The	decrease	in	depreciation	related	to	the	assumed	license	extension	of	River	Bend	has	a	minimal	impact on	net	income	because	it	was	offset	by	the	January	2003	base	rate	decrease	discussed	in	"Net	Revenue"	above.

Other	income	decreased	primarily	due	to	the	abeyed	River	Bend	plant	cost	accrual	discussed	above.

Interest	expense	on	long-term	debt	increased	primarily	due	to	the	issuance	of	$340	million	of	First	Mortgage	Bonds	in	November	2002,	$600	million	in	June	2003, and	$440	million	in	July	2003,	partially	offset	by	the	retirement	of	$293	million	of	First	Mortgage	Bonds	in	March	2003	and	$745	million	in	the	third	quarter	of 2003.

The	effective	income	tax	rates	for	2004,	2003,	and	2002	were	36.0%,	21.3%,	and	27.5%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rate.		Tax	reserves	not	expected	to	reverse	within	the next	year	are	reflected	as	non-current	taxes	accrued	on	the	balance	sheet.

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $206,030 | $318,404 | $123,728 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 649,458 | 425,963 | 500,654 |
| Investing\tactivities | (389,344) | (446,639) | (351,456) |
| Financing\tactivities | (459,170) | (91,698) | 45,478 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (199,056) | (112,374) | 194,676 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,974 | $206,030 | $318,404 |

Cash	flow	from	operations	increased	$223.5	million	in	2004	compared	to	2003	primarily	due	to	money	pool	activity.	Decreased	vendor	payments,	increased recovery	of	deferred	fuel	costs,	and	lower	interest	payments	also	contributed	to	the	increase.

In	2003,	the	domestic	utility	companies	and	System	Energy	filed,	with	the	IRS,	a	change	in	tax	accounting	method	notification	for	their	respective	calculations	of cost	of	goods	sold.	The	adjustment	implemented	a	simplified	method	of	allocation	of	overhead	to	the	production	of	electricity,	which	is	provided	under	the	IRS capitalization	regulations.	The	cumulative	adjustment	placing	these	companies	on	the	new	methodology	resulted	in	a	$674	million	deduction	for	Entergy	Gulf	States on	Entergy's	2003	income	tax	return.	There	was	no	cash	benefit	from	the	method	change	in	2003.	In	2004	Entergy	Gulf	States	realized	$69	million	in	cash	tax

benefit	from	the	method	change.	This	tax	accounting	method	change	is	an	issue	across	the	utility	industry	and	will	likely	be	challenged	by	the	IRS	on	audit.		As	of December	31,	2004,	Entergy	Gulf	States	has	a	net	operating	loss	(NOL)	carryforward	for	tax	purposes	of	$447.5	million,	principally	resulting	from	the	change	in tax	accounting	method	related	to	cost	of	goods	sold.		If	the	tax	accounting	method	change	is	sustained,	Entergy	Gulf	States	expects	to	utilize	the	NOL	carryforward through	2006.

Cash	flow	from	operations	decreased	$74.7	million	in	2003	compared	to	2002	primarily	due	to	money	pool	activity,	higher	working	capital	needs,	and	increased vendor	payments	in	2003	relating	to	storm	expense	accruals	in	late-2002.	The	decrease	was	partially	offset	by	lower	income	tax	payments.

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

| 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| ($59,720) | $69,354 | $18,131 | $27,665 |

Money	pool	activity	provided	$129.1	million	of	Entergy	Gulf	States'	operating	cash	flows	in	2004,	used	$51.2	million	in	2003,	and	provided	$9.5	million	in	2002. See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

Net	cash	used	in	investing	activities	decreased	$57.3	million	in	2004	compared	to	2003	primarily	due	to	the	maturity	in	2004	of	$23.6	million	of	other	temporary investments	that	had	been	made	in	2003,	which	provided	cash	in	2004.	Also	contributing	to	the	decrease	was	a	$27.2	million	decrease	in	under-recovered	fuel	and purchased	power	expenses	in	Texas	that	have	been	deferred	and	are	expected	to	be	collected	over	a	period	greater	than	twelve	months.	See	Note	1	to	the	domestic utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	the	accounting	for	fuel	costs.

Net	cash	used	in	investing	activities	increased	$95.2	million	in	2003	compared	to	2002	primarily	due	to	an	increase	of	$23.6	million	in	other	temporary	investments in	2003	compared	to	the	maturity	of	$44.6	million	of	other	temporary	investments	that	provided	cash	in	2002.	The	increase	was	also	due	to	an	increase	of	$37.7 million	in	under-recovered	fuel	and	purchased	power	expenses	in	Texas	that	have	been	deferred	and	are	expected	to	be	collected	over	a	period	greater	than	twelve months.	See	Note	1	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	the	accounting	for	fuel	costs.

Net	cash	used	in	financing	activities	increased	$367.5	million	in	2004	compared	to	2003	primarily	due	to	the	net	reduction	of	$357	million	of	long-term	debt	in	2004 compared	to	$15.4	million	in	2003	as	well	as	an	increase	of	$26.2	million	in	common	stock	dividends	paid.

Entergy	Gulf	States	used	$91.7	million	of	cash	in	financing	activities	in	2003	compared	to	providing	$45.5	million	of	cash	in	2002	primarily	due	to	the	net	reduction of	$15.4	million	of	long-term	debt	in	2003	compared	to	the	net	issuance	of	$143.4	million	of	long-term	debt	in	2002.	The	increase	in	cash	used	in	financing	activities was	partially	offset	by	a	decrease	of	$23.1	million	in	common	stock	dividends	paid.

Entergy	Gulf	States	requires	capital	resources	for:

working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;	and

dividend	and	interest	payments.

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

|  | 2005 | 2006-2007 | 2008-2009 | after	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| capital\tinvestment\t(1) | $275 | $505 | N/A | N/A | $780 |
| Long-term\tdebt | $98 | - | $550 | $1,341 | $1,989 |
| Operating\tleases | $27 | $41 | $19 | $115 | $202 |
| Purchase\tobligations\t(2) | $164 | $78 | $6 | $21 | $269 |
| Other\tlong-term\tliabilities | $3 | $7 | $7 | - | $17 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $33 | $38 | N/A | N/A | $71 |

(1) Includes	approximately	$210	to	$220	million	annually	for	maintenance	capital,	which	is	planned spending	on	routine	capital	projects	that	are	necessary	to	support	reliability	of	service,	equipment	or systems	and	to	support	normal	customer	growth.

(2) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	For	Entergy	Gulf	States	it	primarily	includes unconditional	fuel	and	purchased	power	obligations.

In	addition	to	these	contractual	obligations,	Entergy	Gulf	States	expects	to	contribute	$18.9	million	to	its	pension	plans	and	$14.3	million	to	other	postretirement plans	in	2005.

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

In	addition	to	the	purchase	obligations	presented	in	the	table	above,	Entergy	Gulf	States	expects	to	have	an	obligation	to	purchase	power	from	the	Perryville	power plant.	In	January	2004,	Entergy	Louisiana	signed	a	definitive	agreement	to	acquire	the	718	MW	Perryville	power	plant	for	$170	million.	The	agreement	has subsequently	been	amended	 to	allow	 the	current	plant	owner	 to	retain	 the	 interconnection	facilities	associated	with	 the	plant,	resulting	 in	a	decrease	 in	 the acquisition	price	to	$162	million.	As	a	result	of	the	amended	terms,	the	FERC	issued	an	order	in	October	2004	disclaiming	jurisdiction	over	the	acquisition.	This order	currently	is	subject	to	rehearing	by	the	FERC.	The	plant	is	owned	by	a	subsidiary	of	Cleco	Corporation,	which	subsidiary	submitted	a	bid	in	response	to

Entergy's	Fall	2002	request	for	proposals	for	supply-side	resources.	The	signing	of	the	agreement	followed	a	voluntary	Chapter	11	bankruptcy	filing	by	the	plant's owner.	Entergy	expects	that	Entergy	Louisiana	will	own	100	percent	of	the	Perryville	plant,	and	that	Entergy	Louisiana	will	sell	75	percent	of	the	output	to	Entergy Gulf	States	under	a	 long-term	cost-of-service	power	purchase	agreement.	In	addition,	Entergy	Louisiana	and	Entergy	Gulf	States	executed	an	 interim	power purchase	agreement	with	the	plant's	owner	through	the	date	of	the	acquisition's	closing	(as	long	as	that	occurs	by	December	2005)	for	100	percent	of	the	output	of the	Perryville	power	plant.	In	April	2004,	the	bankruptcy	court	approved	Entergy	Louisiana's	agreement	to	acquire	the	plant.	In	March	2004,	Entergy	Gulf	States and	Entergy	Louisiana	filed	with	the	LPSC	for	its	approval	of	the	acquisition	and	long-term	cost-of-service	power	purchase	agreement.	Entergy	is	seeking	approval from	the	LPSC	of	cost	recovery	for	the	acquisition,	giving	consideration	to	the	need	for	the	power	and	the	prudence	of	Entergy	Louisiana	and	Entergy	Gulf	States	in engaging	 in	 the	 transaction.	Hearings	 are	 scheduled	 for	 March	 2005.	Assuming	 regulatory	 approval	 by	 the	 LPSC,	 Entergy	 Louisiana	 expects	 the	 Perryville acquisition	to	close	in	mid-2005.

As	a	wholly-owned	subsidiary,	Entergy	Gulf	States	pays	dividends	to	Entergy	Corporation	from	its	earnings	at	a	percentage	determined	monthly.	Entergy	Gulf States	is	restricted	by	long-term	debt	indentures	in	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred	stock.	Currently,	all	of	Entergy Gulf	States'	retained	earnings	are	available	for	distribution.

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

bank	financing	under	new	or	existing	facilities.

The	following	table	lists	First	Mortgage	Bonds	issued	by	Entergy	Gulf	States	in	2004:

| Issue	Date | Description | Maturity | Amount |
| :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |
| October\t2004 | 4.875%\tSeries | November\t2011 | $200,000 |
| November\t2004 | Libor\t+\t0.4%\tSeries | December\t2009 | 225,000 |
| November\t2004 | 5.6%\tSeries | December\t2014 | 50,000 |

# The	following	table	lists	First	Mortgage	Bonds	retired	by	Entergy	Gulf	States	in	2004:

| Retirement	Date | Description | Maturity | Amount |
| :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |
| April\t2004 | 8.25%\tSeries | April\t2004 | $292,000 |
| December\t2004 | Libor\t+\t0.9%\tSeries | June\t2007 | 275,000 |
| December\t2004 | 5.2%\tSeries | December\t2007 | 200,000 |

Entergy	Gulf	States	may	refinance	or	redeem	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

In	addition,	in	September	2004,	Entergy	Gulf	States	purchased	its	$62	million	5.65%	Series	tax-exempt	bonds	from	the	holders,	pursuant	to	a	mandatory	tender provision,	and	has	not	remarketed	the	bonds	at	this	time.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Gulf	States	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also	subject	to issuance	tests	set	forth	in	its	corporate	charter,	bond	indentures,	and	other	agreements.	Entergy	Gulf	States	has	sufficient	capacity	under	these	tests	to	meet	its foreseeable	capital	needs.

Borrowings	and	securities	issuances	by	Entergy	Gulf	States	are	limited	to	amounts	authorized	by	the	SEC.	The	current	short-term	borrowing	limitation,	including borrowings	under	the	money	pool,	is	$340	million.	Under	its	SEC	Orders	and	without	further	SEC	authorization,	Entergy	Gulf	States	cannot	incur	additional indebtedness	or	issue	other	securities	unless	(a)	it	and	Entergy	Corporation	maintain	a	common	equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool borrowings,	the	security	to	be	issued	(if	rated)	and	all	outstanding	securities	of	Entergy	Gulf	States	(other	than	its	preferred	stock),	as	well	as	all	outstanding securities	of	Entergy	Corporation,	that	are	rated,	are	rated	investment	grade.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements for	further	discussion	of	Entergy	Gulf	States'	short-term	borrowing	limits.

# Transition	to	Retail	Competition

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.

In	February	2005,	bills	were	submitted	in	the	Texas	Legislature	that	would	clarify	that	Entergy	Gulf	States	is	no	longer	subject	to	a	rate	freeze	and	specify	that	retail

open	access	will	not	commence	in	Entergy	Gulf	States'	Texas	service	territory	until	the	PUCT	certifies	a	power	region.

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

# Jurisdictional	Separation	Plan

Pursuit	of	Entergy	Gulf	States'	business	separation	plan	mandated	by	Texas	law	in	connection	with	retail	open	access	in	the	Texas	service	territory	has	been complicated	by	the	existence	of	retail	operations	in	Louisiana	subject	to	the	jurisdiction	of	the	LPSC.	During	the	course	of	Entergy	Gulf	States'	retail	open	access proceedings	with	the	PUCT,	the	LPSC	has	been	holding	independent	proceedings	concerning	the	proposed	separation	of	Entergy	Gulf	States'	business.	Unlike	the plan	filed	with	the	PUCT	in	2000	(and	amended	through	2001),	discussed	below,	to	separate	Entergy	Gulf	States'	Texas	generation,	transmission,	distribution,	and retail	electric	functions	into	separate	companies,	the	investigation	recently	initiated	in	the	LPSC	proceedings	is	evaluating	a	jurisdictional	split	of	Entergy	Gulf States	into	a	Louisiana	company	and	a	Texas	company.	In	a	status	conference	held	in	September	2004	before	an	ALJ,	the	LPSC	staff	asserted	that	uncertainty	with respect	 to	retail	open	access	 in	Texas	should	not	control	whether	or	when	 the	LPSC	should	require	 the	 jurisdictional	separation	of	Entergy	Gulf	States	and recommended	that	an	investigation	concerning	the	proposed	jurisdictional	separation	proceed.	Entergy	Gulf	States	submitted	a	preliminary	methodology	developed by	Entergy	for	the	jurisdictional	separation	of	Entergy	Gulf	States	if	the	regulators	should	determine	that	a	jurisdictional	separation	is	in	the	public	interest. Although	it	contains	many	components	that	are	similar	to	those	set	forth	in	the	business	separation	plan	filed	with	the	PUCT,	the	preliminary	methodology	filed with	the	LPSC	provides	for	the	separation	of	Entergy	Gulf	States	into	a	Louisiana	vertically	integrated	utility	company	and	a	Texas	vertically	integrated	utility company;	rather	than	the	separation	of	Entergy	Gulf	States'	Texas	generation,	transmission,	distribution,	and	retail	electric	functions	into	separate	companies	as	is envisioned	in	the	plan	filed	with	the	PUCT.	A	procedural	schedule	was	established	in	the	status	conference	that	sets	discovery	through	February	2005,	testimony through	the	first	half	of	June	2005,	and	a	hearing	beginning	later	in	June	2005.	Approvals	of	the	FERC,	the	SEC,	the	PUCT,	and	the	NRC	may	also	be	required	for certain	matters	before	any	implementation	of	the	jurisdictional	separation	of	Entergy	Gulf	States.

# Business	Separation	Plan	under	the	Texas	Retail	Open	Access	Law

Entergy	Gulf	States'	business	separation	plan	for	Texas	retail	open	access	developed	pursuant	to	the	Texas	restructuring	law	provides	for	the	separation	of	its generation,	transmission,	distribution,	and	retail	electric	functions	into	separate	companies.	It	has	been	amended	during	the	course	of	various	PUCT	and	LPSC proceedings	and	is	subject	to	further	change	and	regulatory	proceedings.	Entergy	Gulf	States	filed	the	business	separation	plan	with	the	PUCT	in	January	2000	and amended	that	plan	in	June	and	November	2000	and	January	2001.	In	July	2000,	the	PUCT	approved	the	amended	business	separation	plan	in	an	interim	order.	In December	2001,	the	PUCT	abated	the	proceeding	and	indicated	it	will	consider	a	final	order	in	a	timely	manner	consistent	with	a	settlement	agreement	delaying retail	open	access.	The	outcome	of	the	LPSC	proceedings	described	below,	which	have	resulted	in	amendments	to	the	plan	beyond	what	was	approved	by	the PUCT,	have	been	and	will	continue	to	be	reported	to	the	PUCT	and	the	Office	of	Public	Utility	Counsel	and	may	require	additional	PUCT	action	before	the business	separation	plan	could	become	final.

The	LPSC	opened	a	docket	to	identify	the	changes	in	corporate	structure	and	operations	of	Entergy	Gulf	States,	and	their	potential	impact	on	Louisiana	retail ratepayers,	resulting	from	restructuring	in	Texas.	In	those	proceedings,	Entergy	Gulf	States	and	the	LPSC	staff	reached	a	settlement	on	certain	Texas	business separation	plan	issues,	and	after	a	May	2001	hearing,	the	LPSC	issued	an	interim	order	in	July	2001	approving	the	settlement.	In	July	2001,	Entergy	Gulf	States	and the	LPSC	Staff	completed	an	additional	settlement	on	business	separation	plan	issues	relating	to	the	separation	of	Texas	distribution	and	transmission.	A	hearing	on the	distribution	and	transmission	settlement	was	held	and	the	LPSC	approved	the	settlement	in	September	2001.	Issues	related	to	the	separation	of	generation	are still	unresolved.

The	plan	approved	by	the	LPSC	in	September	2001	provides	that	Entergy	Gulf	States	will	be	separated	into	the	following	principal	companies	if	retail	open	access were	to	commence	in	Texas:

a	Texas	distribution	company,	which	will	own	and	operate	Entergy	Gulf	States'	electric	distribution	system	in	Texas;

an	intermediate	transmission	company;

a	Texas	generation	company	(which	may	be	more	than	one	legal	entity),	which	initially	will	purchase	capacity	and	energy	from	the	generating	assets	allocated to	Texas	load	(Texas	generating	assets),	and	eventually	will	own	those	assets;

Texas	retail	electric	providers,	which	will	provide	competitive	retail	electric	service	in	Texas;	and Entergy	Gulf	States-Louisiana.

Pursuant	to	the	LPSC-approved	plan,	Entergy	Gulf	States-Louisiana	would:

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

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.

If	the	FERC	grants	the	relief	requested	by	the	LPSC	in	the	proceeding,	the	relief	may	result	in	a	material	increase	in	the	total	production	costs	the	FERC	allocates	to companies	whose	costs	currently	are	projected	to	be	less	than	the	Entergy	System	average,	and	a	material	decrease	in	the	total	production	costs	the	FERC	allocates

to	companies	whose	costs	currently	are	projected	to	exceed	that	average.			If	the	FERC	adopts	the	ALJ's	Initial	Decision,	the	amount	of	production	costs	that	would be	reallocated	among	the	domestic	utility	companies	would	be	determined	through	consideration	of	each	domestic	utility	company's	relative	total	production	cost expressed	as	a	percentage	of	Entergy	System	average	total	production	cost.	The	ALJ's	Initial	Decision	would	reallocate	production	costs	of	the	domestic	utility companies	whose	percent	of	Entergy	System	average	production	cost	are	outside	an	upper	or	lower	bandwidth.	This	would	be	accomplished	by	payments	from domestic	utility	companies	whose	production	costs	are	below	Entergy	System	average	production	cost	to	domestic	utility	companies	whose	production	costs	are above	Entergy	System	average	production	cost.

Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	a	FERC	decision	and	related	retail	proceedings	should	result	in	similar rate	changes	for	retail	customers.	Although	the	outcome	and	timing	of	the	FERC,	APSC,	and	other	proceedings	cannot	be	predicted	at	this	time,	Entergy	Gulf	States does	not	believe	that	the	ultimate	resolution	of	these	proceedings	will	have	a	material	effect	on	its	financial	condition	or	results	of	operation.

The	LPSC	instituted	a	companion	ex-parte	System	Agreement	investigation	to	litigate	several	of	the	System	Agreement	issues	that	the	LPSC	is	litigating	before	the FERC	in	the	previously	discussed	System	Agreement	proceeding.	This	companion	proceeding	will	require	the	LPSC	to	interpret	various	provisions	of	the	System Agreement,	including	those	relating	to	minimum-run	and	must-run	units,	the	propriety	of	the	methods	used	for	billing	and	dispatch	on	the	Entergy	System,	and	the use	of	a	rolling,	twelve-month	average	of	system	peaks	for	allocating	certain	costs.	In	addition,	by	this	companion	proceeding	the	LPSC	is	questioning	whether Entergy	Louisiana	and	Entergy	Gulf	States	were	prudent	for	not	seeking	changes	to	the	System	Agreement	previously,	so	as	to	lower	costs	imposed	upon	their ratepayers	and	to	increase	costs	imposed	upon	ratepayers	of	other	domestic	utility	companies.	The	LPSC	staff	has	filed	testimony	suggesting	that	the	remedy	for	the alleged	imprudence	of	Entergy	Louisiana	and	Entergy	Gulf	States	should	be	a	reduction	in	allowed	rate	of	return	on	common	equity	of	100	basis	points.	The domestic	utility	companies	have	challenged	the	propriety	of	the	LPSC's	litigating	System	Agreement	issues.	Nevertheless,	on	January	16,	2002	the	LPSC	affirmed	a decision	of	its	ALJ	upholding	the	LPSC	staff's	right	to	litigate	System	Agreement	issues	at	the	LPSC,	rather	than	before	the	FERC.	The	procedural	schedule	is suspended	at	this	time	and	an	evidentiary	hearing	is	not	scheduled.	An	unrelated	case	between	the	LPSC	and	Entergy	Louisiana	raised	the	question	of	whether	a state	regulator	is	preempted	by	federal	law	from	reviewing	and	interpreting	FERC	rate	schedules	that	are	part	of	the	System	Agreement,	and	from	subsequently enforcing	 that	 interpretation.	The	LPSC	interpreted	a	System	Agreement	rate	schedule	in	the	unrelated	case,	and	then	sought	to	enforce	its	interpretation.	The Louisiana	Supreme	Court	affirmed.	In	2003,	the	U.S.	Supreme	Court	ruled	in	Entergy	Louisiana's	favor	and	reversed	the	decisions	of	the	LPSC	and	the	Louisiana Supreme	Court.

In	April	2004,	Entergy	filed	a	proposal	with	the	FERC	to	commit	voluntarily	to	retain	an	independent	entity	(Independent	Coordinator	of	Transmission	or	ICT)	to oversee	the	granting	of	transmission	or	interconnection	service	on	Entergy's	transmission	system,	to	implement	a	transmission	pricing	structure	that	ensures	that Entergy's	retail	native	load	customers	are	required	to	pay	for	only	those	upgrades	necessary	to	reliably	serve	their	needs,	and	to	have	the	ICT	serve	as	the	security coordinator	for	the	Entergy	region.	Assuming	applicable	regulatory	support	and	approvals	can	be	obtained,	Entergy	proposed	to	contract	with	the	ICT	to	oversee	the granting	of	transmission	service	on	the	Entergy	system	as	well	as	the	implementation	of	the	proposed	weekly	procurement	process	(WPP).	The	proposal	was

structured	to	not	transfer	control	of	Entergy's	transmission	system	to	the	ICT,	but	rather	to	vest	with	the	ICT	broad	oversight	authority	over	transmission	planning and	operations.

The	domestic	utility	companies	(except	Entergy	New	Orleans)	are	currently	defendants	to	several	complaints	and	rehearing	requests	before	the	FERC	in	which independent	generation	entities	(GenCos)	are	seeking	a	refund	of	monies	that	the	GenCos	had	previously	paid	to	the	Entergy	companies	for	facilities	necessary	to connect	their	generation	facilities	to	Entergy's	transmission	system.	The	FERC	has	issued	initial	orders	in	response	to	two	of	the	complaints	and	in	certain	other dockets	ordering	Entergy	to	refund	approximately	$100	million	in	expenses	and	tax	obligations	previously	paid	by	the	GenCos,	including	$28	million	for	Entergy Gulf	States.	The	refunds	will	be	in	the	form	of	transmission	credits	that	will	be	utilized	over	time	as	the	GenCos	take	transmission	service	from	Entergy.	To	the extent	the	Entergy	companies	are	ordered	to	provide	such	refunds,	these	costs	will	qualify	for	inclusion	in	the	Entergy	companies'	rates.	The	recovery	of	these	costs is	not	automatic,	however,	especially	at	the	retail	level,	where	the	majority	of	the	cost	recovery	would	occur.	Entergy	intends	to	pursue	all	regulatory	and	legal avenues	available	to	it	in	order	to	have	these	orders	reversed	and	have	the	affected	interconnection	agreements	reinstated	as	agreed	to	originally	by	the	generators.

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

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

approval	to	implement	a	proposed	$11.3	million	franchise	fee	rider	to	recover	payments	to	municipalities	charging	such	fees;	and a	requested	return	on	equity	of	11.5%.

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

Dismissal	of	Entergy	Gulf	States'	rate	case	does	not	preclude	it	from	seeking	recovery	of	the	transition	to	competition	costs	when	the	rate	freeze	is	no	longer	in effect.	Similarly,	the	dismissal	of	the	rate	case	does	not	preclude	Entergy	Gulf	States	from	seeking	the	reconciliation	of	fuel	and	purchased	power	costs	of	$288 million	for	the	period	September	2003	through	March	2004	when,	at	the	appropriate	time,	similar	costs	are	reconciled	in	the	future.	As	discussed	above,	in	February 2005,	bills	were	submitted	in	the	Texas	Legislature	that	would	clarify	that	Entergy	Gulf	States	is	no	longer	subject	to	a	rate	freeze	and	specify	that	retail	open	access will	not	commence	in	Entergy	Gulf	States'	Texas	service	territory	until	the	PUCT	certifies	a	power	region.

In	September	2004,	the	LPSC	consolidated	various	dockets	that	were	the	subject	of	settlement	discussions	between	the	LPSC	staff	and	Entergy	Gulf	States	and Entergy	Louisiana.	The	LPSC	directed	its	staff	to	continue	the	settlement	discussions	and	submit	any	proposed	settlement	to	the	LPSC	for	its	consideration.	In January	2005,	Entergy	Gulf	States	and	Entergy	Louisiana	filed	testimony	with	the	LPSC	in	support	of	a	proposed	settlement	that	currently	includes	an	offer	to refund	$76	million	to	Entergy	Gulf	States'	Louisiana	customers,	with	no	immediate	change	in	current	base	rates.	If	the	LPSC	approves	the	proposed	settlement, Entergy	Gulf	States	will	be	regulated	under	a	three-year	formula	rate	plan	that,	among	other	provisions,	establishes	a	ROE	mid-point	of	10.65%	and	permits	Entergy Gulf	States	to	recover	incremental	capacity	costs	without	filing	a	traditional	base	rate	proceeding.	The	settlement	resolves	all	issues	in,	and	will	result	in	the dismissal	of,	Entergy	Gulf	States'	fourth,	fifth,	sixth,	seventh,	and	eighth	annual	earnings	reviews,	Entergy	Gulf	States'	ninth	post-merger	earnings	review	and revenue	requirement	analysis,	a	fuel	review	for	Entergy	Gulf	States,	dockets	established	to	consider	issues	concerning	power	purchases	for	both	Entergy	Gulf	States and	Entergy	Louisiana	for	the	summers	of	2001,	2002,	2003,	and	2004,	and	a	docket	concerning	retail	issues	arising	under	the	Entergy	System	Agreement.	The settlement	does	not	include	the	System	Agreement	case	pending	at	FERC.	The	LPSC	has	solicited	comments	on	the	proposed	settlement	from	the	parties	to	the various	proceedings	at	issue	in	the	proposed	settlement.	The	proposed	settlement	is	scheduled	to	be	presented	to	the	LPSC	for	consideration	on	March	23,	2005. Refer	to	Note	2	to	the	domestic	utility	and	System	Entergy	financial	statements	for	details	of	the	proceedings	included	in	the	proposed	settlement.

In	July	2004,	Entergy	Gulf	States	filed	with	the	LPSC	an	application	for	a	change	in	its	gas	base	rates	and	charges	seeking	an	increase	of	$9.1	million.	Entergy	Gulf States	also	is	seeking	approval	of	certain	proposed	rate	design,	rate	schedule,	and	policy	changes.	Discovery	is	underway,	and	a	decision	is	expected	during	the	third quarter	of	2005.

In	addition	to	rate	proceedings,	Entergy	Gulf	States'	fuel	costs	recovered	from	customers	are	subject	to	regulatory	scrutiny.	Entergy	Gulf	States'	retail	rate	matters and	proceedings,	including	fuel	cost	recovery-related	issues,	are	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

# Industrial,	Commercial,	and	Wholesale	Customers

Entergy	Gulf	States'	large	industrial	and	commercial	customers	continually	explore	ways	to	reduce	their	energy	costs.	In	particular,	cogeneration	is	an	option available	to	a	portion	of	Entergy	Gulf	States'	industrial	customer	base.	Entergy	Gulf	States	responds	by	working	with	industrial	and	commercial	customers	and negotiating	electric	service	contracts	to	provide	competitive	rates	that	match	specific	customer	needs	and	load	profiles.	Despite	these	actions,	Entergy	Gulf	States expects	to	lose	one	large	industrial	customer	to	cogeneration	in	2005.	Current	sales	to	that	customer	account	for	approximately	$12	million	of	Entergy	Gulf	States' net	revenue	annually.	Entergy	Gulf	States	actively	participates	in	economic	development,	customer	retention,	and	reclamation	activities	to	increase	industrial	and commercial	demand,	from	both	new	and	existing	customers.	Entergy	Gulf	States	does	not	currently	expect	additional	significant	losses	to	cogeneration	because	of the	current	economics	of	the	electricity	markets	and	Entergy	Gulf	States'	marketing	efforts	in	retaining	industrial	customers.

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	Notes	1,	8,	and	12	to	the	domestic	utility companies	and	System	Energy	financial	statements.

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

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

# Litigation	Risks

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

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

Regulations	require	Entergy	Gulf	States	to	decommission	the	River	Bend	nuclear	power	plant	after	the	facility	is	taken	out	of	service,	and	money	is	collected	and deposited	in	trust	funds	during	the	facility's	operating	life	in	order	to	provide	for	this	obligation.	Entergy	Gulf	States	conducts	periodic	decommissioning	cost	studies (typically	updated	every	 three	 to	five	years)	 to	estimate	 the	costs	 that	will	be	 incurred	 to	decommission	 the	facility.	The	following	key	assumptions	have	a significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	Entergy	Gulf	States'	decommissioning	study	includes	an	assumption	that	decommissioning	costs	will	escalate	over	present	cost levels	by	an	annual	factor	averaging	approximately	CPI-U	to	4.5%.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost	of

# decommissioning	a	facility	by	as	much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin	immediately	upon	plant retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable	regulations.	While	the	effect	of	these assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a	"safestore"	status	can	possibly	decrease	the	present	value	of these	obligations.	As	discussed	in	Note	8	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	Entergy	Gulf	States	recorded	revisions	in 2004	to	its	estimated	decommissioning	cost	liability	for	River	Bend	to	reflect	changes	in	assumptions	regarding	license	renewal.	Under	these	license	renewal assumptions,	decommissioning	of	nuclear	plants	is	assumed	to	occur	at	a	date	later	than	the	original	license	expiration,	thereby	lowering	the	estimate	of	the decommissioning	cost	liability.	The	revised	license	renewal	assumptions	for	the	unregulated	portion	of	Entergy	Gulf	States	increased	income	in	2004	by	$17 million	net-of-tax	for	the	excess	of	the	reduction	in	the	liability	over	the	amount	of	undepreciated	asset	retirement	cost	at	the	time	of	adoption	of	SFAS	143. For	the	regulated	portion	of	Entergy	Gulf	States,	the	revised	assumptions	had	no	effect	on	net	income	because,	as	discussed	further	below,	any	amounts recorded	related	to	SFAS	143	are	offset	by	the	recording	of	regulatory	assets	or	regulatory	liabilities	when	projected	decommissioning	costs	are	collected	in rates.	Future	revisions	to	appropriately	reflect	changes	needed	to	the	estimate	of	decommissioning	costs	will	affect	net	income	for	the	unregulated	portion	of Entergy	Gulf	States.	Any	increase	in	the	liability	recorded	due	to	such	changes	are	capitalized	and	depreciated	over	the	asset's	remaining	economic	life	in accordance	with	SFAS	143.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	DOE	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear	fuel,	and	legislation	has	been passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	Until	this	site	is	available,	however,	nuclear	plant	operators	must	provide	for interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and	maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs of	developing	and	maintaining	these	facilities	can	have	a	significant	effect	(as	much	as	16%	of	estimated	decommissioning	costs).	Entergy	Gulf	States' decommissioning	studies	include	cost	estimates	for	spent	fuel	storage.	However,	these	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening of	the	Yucca	Mountain	facility,	the	schedule	for	shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

Entergy	Gulf	States	collects	the	projected	costs	of	decommissioning	River	Bend	through	rates	charged	to	customers	for	the	portion	of	the	plant	subject	to	cost-based ratemaking.	The	amounts	collected	through	rates,	which	are	based	upon	decommissioning	cost	studies,	are	deposited	in	decommissioning	trust	funds.	In	December 2002,	decommissioning	collections	from	customers	for	the	Louisiana-regulated	portion	of	River	Bend	were	suspended	as	a	result	of	the	settlement	with	the	LPSC	of Entergy	Gulf	States'	fourth	through	eighth	earnings	reviews.	If	decommissioning	cost	study	estimates	are	changed	and	approved	by	regulators,	collections	from customers	would	also	change.

Approximately	half	of	River	Bend	is	not	subject	to	cost-based	ratemaking.	When	Entergy	Gulf	States	acquired	the	30%	share	of	River	Bend	formerly	owned	by Cajun,	Entergy	Gulf	States	obtained	decommissioning	trust	funds	of	$132	million,	which	have	since	grown	to	$158	million.	Entergy	Gulf	States	believes	that	these funds	will	be	sufficient	to	cover	the	costs	of	decommissioning	this	portion	of	River	Bend,	and	no	further	collections	or	deposits	are	being	made	for	these	costs.

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

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

Fair	value	approach	-	SFAS	143	requires	that	these	obligations	be	measured	using	a	fair	value	approach.	Among	other	things,	this	entails	the	assumption	that the	costs	will	be	incurred	by	a	third	party	and	will	therefore	include	appropriate	profit	margins	and	risk	premiums.	Entergy	Gulf	States'	decommissioning studies	had	been	based	on	Entergy	Gulf	States	performing	the	work	and	did	not	include	any	such	margins	or	premiums.

The	net	effect	of	implementing	SFAS	143	for	the	portion	of	River	Bend	subject	to	cost-based	ratemaking	was	recorded	as	a	regulatory	asset,	with	no	resulting impact	on	Entergy	Gulf	States'	net	income.	Entergy	Gulf	States	recorded	this	regulatory	asset	because	its	existing	rate	mechanism	is	based	on	the	original	or historical	cost	standard	that	allows	Entergy	Gulf	States	to	recover	all	ultimate	costs	of	decommissioning	existing	assets	from	current	and	future	customers.	Upon implementation	of	SFAS	143	in	2003,	assets	and	liabilities	increased	as	a	result	of	increasing	the	asset	retirement	obligation	by	$129	million	to	its	fair	value	as determined	under	SFAS	143,	reducing	accumulated	depreciation	by	$63	million,	and	recording	 the	related	regulatory	asset	of	$32	million.	The	net	effect	of implementing	SFAS	143	for	the	portion	of	River	Bend	not	subject	to	cost-based	ratemaking	resulted	in	an	earnings	decrease	of	$21	million	net-of-tax	as	a	result	of	a one-time	cumulative	effect	of	accounting	change.

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

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

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

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

As	discussed	in	Note	1	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	Entergy	Gulf	States	records	an	estimate	of	the	revenues	earned	for energy	delivered	since	the	latest	customer	billing.	Each	month	the	estimated	unbilled	revenue	amounts	are	recorded	as	revenue	and	a	receivable,	and	the	prior month's	estimate	is	reversed.	The	difference	between	the	estimate	of	the	unbilled	receivable	at	the	beginning	of	the	period	and	the	end	of	the	period	is	the	amount	of unbilled	revenue	recognized	during	the	period.	The	estimate	recorded	is	primarily	based	upon	an	estimate	of	customer	usage	during	the	unbilled	period	and	the billed	price	to	customers	in	that	month,	including	fuel	price	in	Entergy	Gulf	States'	Louisiana	jurisdiction.	Therefore,	revenue	recognized	may	be	affected	by	the estimated	price	and	usage	at	the	beginning	and	end	of	each	period	and	fuel	price	fluctuations,	in	addition	to	changes	in	certain	components	of	the	calculation

including	changes	to	estimates	such	as	line	loss,	which	affects	the	estimate	of	unbilled	customer	usage,	and	assumptions	regarding	price	such	as	the	fuel	cost recovery	mechanism.

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $1,994 | $16,385 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,134 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $726 | $4,157 |

|  | Change	in | Impact	on	2004 | Postretirement	Benefit |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Postretirement\tBenefit\tCost | Obligation |
|  |  | Increase/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $847 | $4,751 |
| Discount\trate | (0.25%) | $510 | $5,677 |

Total	pension	cost	for	Entergy	Gulf	States	in	2004	was	$0.4	million.	Entergy	Gulf	States	anticipates	2005	pension	cost	to	increase	to	$7.3	million	due	to	decrease	in the	discount	rate	(from	6.25%	to	6.00%)	and	the	expected	rate	of	return	(from	8.75%	to	8.5%)	used	to	calculate	benefit	obligations.	Entergy	Gulf	States	contributed $17	thousand	to	its	pension	plan	in	2004,	and	anticipates	making	$18.9	million	in	contributions	in	2005.	The	rise	in	pension	funding	requirements	is	due	to	declining interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to	2002,	partially	offset	by	the	Pension	Funding	Equity	Act	relief	passed	in	April	2004.

At	December	31,	2003	and	2004,	Entergy	Gulf	States'	accumulated	benefit	obligation	was	less	than	plan	assets,	therefore	there	was	no	additional	minimum	pension liability	required	to	be	recognized.	Net	income	for	2004,	2003,	and	2002	was	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Gulf	States	in	2004	were	$17.6	million,	including	$4.4	million	in	savings	due	to	the estimated	 effect	 of	 future	 Medicare	 Part	 D	 subsidies.	Entergy	 Gulf	 States	 expects	 2005	 postretirement	 health	 care	 and	 life	 insurance	 benefit	 costs	 to	 be approximately	$19.6	million,	including	$5.1	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.	The	increase	in	postretirement	health care	and	life	insurance	benefit	costs	is	due	to	the	decrease	in	the	discount	rate	(from	6.25%	to	6.00%)	and	an	increase	in	the	health	care	cost	trend	rate	used	to

# calculate	benefit	obligations.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Gulf	States,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	income,	retained earnings	and	comprehensive	income,	and	cash	flows	(pages	194	through	198	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period ended	December	31,	2004.	These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these financial	statements	based	on	our	audits.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Gulf	States,	Inc.	as	of	December	31,	2004	and	2003, and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	5	and	Note	8	to	the	notes	to	respective	financial	statements,	in	2003	Entergy	Gulf	States,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	 Standards	 Board Interpretation	 No.	 46,	Consolidation	 of	 Variable Interest	 Entities,	and	 Statement	 of	 Financial	Accounting	 Standards	 No.	 143, Accounting	for	Asset	Retirement	Obligations.

| OPERATING	REVENUES |  |  |  |
| :--- | :--- | :--- | :--- |
| Domestic\telectric | \t$2,821,296\t\t$2,579,916\t\t$2,141,873 | \t$2,821,296\t\t$2,579,916\t\t$2,141,873 | \t$2,821,296\t\t$2,579,916\t\t$2,141,873 |
| Natural\tgas | 61,088 | 59,821 | 42,006 |
| TOTAL | 2,882,384 | 2,639,737 | 2,183,879 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 772,914 | 693,612 | 692,901 |
| \t\tPurchased\tpower | 969,779 | 838,498 | 368,140 |
| \t\tNuclear\trefueling\toutage\texpenses | 15,969 | 14,045 | 12,190 |
| \t\tOther\toperation\tand\tmaintenance | 445,413 | 457,428 | 438,259 |
| Decommissioning | 13,645 | 14,268 | 3,980 |
| Taxes\tother\tthan\tincome\ttaxes | 118,081 | 117,009 | 120,295 |
| Depreciation\tand\tamortization | 197,234 | 199,583 | 204,202 |
| Other\tregulatory\tcredits\t-\tnet | (10,070) | (2,476) | (7,818) |
| TOTAL | 2,522,965 | 2,331,967 | 1,832,149 |
| OPERATING\tINCOME | 359,419 | 307,770 | 351,730 |
| OTHER\tINCOME\t(DEDUCTIONS) |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 13,027 | 15,855 | 11,010 |
| Interest\tand\tdividend\tincome | 15,753 | 17,902 | 8,866 |
| Miscellaneous\t-\tnet | 36,180 | (109,389) | 3,560 |
| TOTAL | 64,960 | (75,632) | 23,436 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 125,356 | 148,516 | 139,343 |
| Other\tinterest\t-\tnet | 8,242 | 8,827 | 5,497 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (9,771) | (13,349) | (9,749) |
| TOTAL | 123,827 | 143,994 | 135,091 |
| INCOME\tBEFORE\tINCOME\tTAXES\tAND\nCUMULATIVE\tEFFECT\tOF\tACCOUNTING\tCHANGE | 300,552 | 88,144 | 240,075 |
| Income\ttaxes | 108,288 | 24,249 | 65,997 |

INCOME	BEFORE	CUMULATIVE	EFFECT

| OF	ACCOUNTING	CHANGE | 192,264 | 63,895 | 174,078 |
| :--- | :--- | :--- | :--- |
| CUMULATIVE\tEFFECT\tOF\tACCOUNTING\nCHANGE\t(net\tof\tincome\ttaxes\tof\t$12,713) | - | (21,333) | - |
| NET\tINCOME | 192,264 | 42,562 | 174,078 |
| Preferred\tdividend\trequirements\tand\tother | 4,472 | 4,701 | 4,888 |
| EARNINGS\tAPPLICABLE\tTO\nCOMMON\tSTOCK | $187,792 | $37,861 | $169,190 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  | (In\tThousands) | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $192,264 | $42,562 | $174,078 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby |  |  |  |
| operating\tactivities: |  |  |  |
| \t\tReserve\tfor\tregulatory\tadjustments | 24,112 | 12,605 | 11,147 |
| \t\tOther\tregulatory\tcredits\t-\tnet | (10,070) | (2,476) | (7,818) |
| \t\tDepreciation,\tamortization,\tand\tdecommissioning | 210,879 | 213,851 | 208,182 |
| \t\tDeferred\tincome\ttaxes\tand\tinvestment\ttax\tcredits | 57,908 | 24,574 | (11,576) |
| \t\tCumulative\teffect\tof\taccounting\tchange | - | 21,333 | - |
| \t\tChanges\tin\tworking\tcapital: |  |  |  |
| \t\t\t\tReceivables | 14,774 | (96,409) | 18,155 |
| \t\t\t\tFuel\tinventory | 1,205 | (1,469) | 4,617 |
| \t\t\t\tAccounts\tpayable | 59,846 | (17,013) | 83,428 |
| \t\t\t\tTaxes\taccrued | 99,955 | 12,618 | (24,740) |
| \t\t\t\tInterest\taccrued | (3,834) | (1,900) | (4,544) |
| \t\t\t\tDeferred\tfuel\tcosts | 78,200 | 59,165 | 65,556 |
| \t\t\t\tOther\tworking\tcapital\taccounts | 7,426 | 11,874 | (19,551) |
| \t\tProvision\tfor\testimated\tlosses\tand\treserves | (13,844) | 115,878 | 1,478 |
| \t\tChanges\tin\tother\tregulatory\tassets | (10,060) | 3,983 | (51,490) |
| \t\tOther | (59,303) | 26,787 | 53,732 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 649,458 | 425,963 | 500,654 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (357,720) | (348,507) | (355,334) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 13,027 | 15,855 | 11,010 |
| Nuclear\tfuel\tpurchases | (45,085) | (39,959) | (21,820) |
| Proceeds\tfrom\tsale/leaseback\tof\tnuclear\tfuel | 38,800 | 38,029 | 21,923 |
| Decommissioning\ttrust\tcontributions\tand\trealized |  |  |  |
| \t\tchange\tin\ttrust\tassets | (12,070) | (11,428) | (12,488) |
| Changes\tin\tother\ttemporary\tinvestments\t-\tnet | 23,579 | (23,579) | 44,643 |
| Other\tregulatory\tinvestments | (49,875) | (77,050) | (39,390) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (389,344) | (446,639) | (351,456) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 472,039 | 1,032,682 | 337,481 |
| Retirement\tof\tlong-term\tdebt | (829,000) | (1,048,129) | (194,057) |
| Redemption\tof\tpreferred\tstock | (3,450) | (3,450) | (1,858) |
| Dividends\tpaid: |  |  |  |
| \t\tCommon\tstock | (94,300) | (68,100) | (91,200) |
| \t\tPreferred\tstock | (4,459) | (4,701) | (4,888) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (459,170) | (91,698) | 45,478 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (199,056) | (112,374) | 194,676 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 206,030 | 318,404 | 123,728 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,974 | $206,030 | $318,404 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid/(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| \t\tInterest\t-\tnet\tof\tamount\tcapitalized | $130,491 | $152,655 | $143,961 |
| \t\tIncome\ttaxes | ($28,169) | ($30,987) | $98,734 |

BALANCE	SHEETS ASSETS

| Cash | $5,627 | $20,754 |
| :--- | :--- | :--- |
| \t\tTemporary\tcash\tinvestments\t-\tat\tcost, |  |  |
| \t\t\twhich\tapproximates\tmarket | 1,347 | 185,276 |
| \t\t\t\t\tTotal\tcash\tand\tcash\tequivalents | 6,974 | 206,030 |
| Other\ttemporary\tinvestments | - | 23,579 |
| Accounts\treceivable: |  |  |
| \t\tCustomer | 124,801 | 115,729 |
| \t\tAllowance\tfor\tdoubtful\taccounts | (2,687) | (4,856) |
| \t\tAssociated\tcompanies | 13,980 | 76,726 |
| \t\tOther | 40,697 | 27,243 |
| \t\tAccrued\tunbilled\trevenues | 137,719 | 114,442 |
| \t\t\t\t\tTotal\taccounts\treceivable | 314,510 | 329,284 |
| Deferred\tfuel\tcosts | 90,124 | 118,449 |
| Accumulated\tdeferred\tincome\ttaxes | 14,339 | 6,116 |
| Fuel\tinventory\t-\tat\taverage\tcost | 49,658 | 50,863 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 101,922 | 99,357 |
| Prepayments\tand\tother | 20,556 | 51,236 |
| TOTAL | 598,083 | 884,914 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 290,952 | 267,917 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 94,052 | 139,911 |
| Other | 22,012 | 21,852 |
| TOTAL | 407,016 | 429,680 |
| UTILITY\tPLANT |  |  |
| Electric | 8,418,119 | 8,208,394 |
| Property\tunder\tcapital\tlease | - | 11,009 |
| Natural\tgas | 78,627 | 69,180 |
| Construction\twork\tin\tprogress | 331,703 | 325,888 |
| Nuclear\tfuel\tunder\tcapital\tlease | 71,279 | 63,684 |
| TOTAL\tUTILITY\tPLANT | 8,899,728 | 8,678,155 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 4,047,182 | 3,953,275 |
| UTILITY\tPLANT\t-\tNET | 4,852,546 | 4,724,880 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 444,799 | 442,062 |
| \t\tOther\tregulatory\tassets | 285,017 | 320,363 |
| Long-term\treceivables | 23,228 | 19,375 |
| Other | 44,713 | 33,588 |
| TOTAL | 797,757 | 815,388 |

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $98,000 | $354,000 |
| Accounts\tpayable: |  |  |
| \t\tAssociated\tcompanies | 153,069 | 84,394 |
| \t\tOther | 147,337 | 156,166 |
| Customer\tdeposits | 53,229 | 47,044 |
| Taxes\taccrued | 22,882 | - |
| Nuclear\trefueling\toutage\tcosts | - | 8,238 |
| Interest\taccrued | 32,742 | 36,576 |
| Obligations\tunder\tcapital\tleases | 33,518 | 34,075 |
| Other | 19,912 | 14,755 |
| TOTAL | 560,689 | 735,248 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,533,804 | 1,422,776 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 138,616 | 144,323 |
| Obligations\tunder\tcapital\tleases | 37,711 | 40,618 |
| Other\tregulatory\tliabilities | 34,009 | 13,885 |
| Decommissioning\tand\tretirement\tcost\tliabilities | 152,095 | 298,785 |
| Transition\tto\tcompetition | 79,098 | 79,098 |
| Regulatory\treserves | 81,455 | 57,343 |
| Accumulated\tprovisions | 66,875 | 75,868 |

| Long-term	debt | 1,891,478 | 1,989,613 |
| :--- | :--- | :--- |
| Preferred\tstock\twith\tsinking\tfund | 17,400 | 20,852 |
| Other | 229,408 | 233,985 |
| TOTAL | 4,261,949 | 4,377,146 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDERS'\tEQUITY |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 47,327 | 47,327 |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t200,000,000 |  |  |
| \t\tshares;\tissued\tand\toutstanding\t100\tshares\tin\t2004\tand\t2003 | 114,055 | 114,055 |
| Paid-in\tcapital | 1,157,486 | 1,157,484 |
| Retained\tearnings | 513,182 | 419,690 |
| Accumulated\tother\tcomprehensive\tincome | 714 | 3,912 |
| TOTAL | 1,832,764 | 1,742,468 |

# STATEMENTS	OF	RETAINED	EARNINGS	AND	COMPREHENSIVE	INCOME

| RETAINED	EARNINGS |  |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Retained\tEarnings\t-\tBeginning\tof\tperiod | \t\t\t$419,690 |  | \t\t$449,929 |  | \t\t$371,939 |  |
| \t\tAdd\t-\tNet\tIncome | 192,264\t\t$192,264 | 192,264\t\t$192,264 | 42,562\t\t$42,562 | 42,562\t\t$42,562 | 174,078\t\t$174,078 | 174,078\t\t$174,078 |
| \t\tDeduct: |  |  |  |  |  |  |
| \t\t\t\tDividends\tdeclared\ton\tcommon\tstock | 94,300 |  | 68,100 |  | 91,200 |  |
| \t\t\t\tPreferred\tdividend\trequirements\tand\tother | 4,472 | 4,472 | 4,701 | 4,701 | 4,888 | 4,888 |
| \t\t\t\t\t\tTotal | 98,772 |  | 72,801 |  | 96,088 |  |
| Retained\tEarnings\t-\tEnd\tof\tperiod | \t\t\t$513,182 |  | \t\t$419,690 |  | \t\t$449,929 |  |
| ACCUMULATED\tOTHER\tCOMPREHENSIVE |  |  |  |  |  |  |
| INCOME\t(Net\tof\tTaxes): |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tperiod: |  |  |  |  |  |  |
| \t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | $3,912 |  | $3,286 |  | $\t- |  |
| Net\tderivative\tinstrument\tfair\tvalue\tchanges\n\tarising\tduring\tthe\tperiod | (3,198) | (3,198) | 626 | 626 | 3,286 | 3,286 |
| Balance\tat\tend\tof\tperiod: |  |  |  |  |  |  |
| \t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | $714 |  | $3,912 |  | $3,286 |  |
| Comprehensive\tIncome |  | \t\t$184,594 |  | \t\t$38,487 |  | \t\t$172,476 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,882,384 | $2,639,737 | $2,183,879 | $2,648,560 | $2,511,240 |
| Net\tIncome | $192,264 | $45,262 | $174,078 | $179,444 | $180,343 |
| Total\tassets | $6,655,402 | $6,854,862 | $6,599,533 | $6,209,741 | $6,134,017 |
| Long-term\tobligations\t(1) | $1,946,589 | $2,051,083 | $2,096,329 | $2,130,245 | $1,978,149 |

(1)	Included	long-term	debt	(excluding	currently	maturing	debt),	preferred	stock	with	sinking	fund,	and	noncurrent	capital	lease	obligations.

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $881 | $829 | $700 | $788 | $717 |
| \t\tCommercial | 672 | 614 | 502 | 587 | 505 |
| \t\tIndustrial | 976 | 853 | 695 | 946 | 871 |
| \t\tGovernmental | 37 | 39 | 34 | 38 | 33 |
| \t\t\t\tTotal\tretail | 2,566 | 2,335 | 1,931 | 2,359 | 2,126 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 52 | 42 | 28 | 73 | 94 |
| \t\t\t\tNon-associated\tcompanies | 160 | 150 | 139 | 146 | 113 |
| \t\tOther | 43 | 53 | 44 | 13 | 138 |
| \t\t\t\tTotal | $2,821 | $2,580 | $2,142 | $2,591 | $2,471 |
| Billed\tElectric\tEnergy\tSales\t(GWh):\n\t\tResidential | 9,803 | 9,739 | 9,502 | 9,059 | 9,405 |

| Commercial | 8,444 | 8,174 | 7,894 | 7,668 | 7,660 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \t\tIndustrial | 16,596 | 15,417 | 15,887 | 16,658 | 17,960 |
| \t\tGovernmental | 432 | 475 | 477 | 452 | 450 |
| \t\t\t\tTotal\tretail | 35,275 | 33,805 | 33,760 | 33,837 | 35,475 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 1,528 | 1,185 | 708 | 1,087 | 1,381 |
| \t\t\t\tNon-associated\tcompanies | 3,172 | 3,358 | 4,391 | 3,305 | 3,248 |
| \t\t\t\tTotal | 39,975 | 38,348 | 38,859 | 38,229 | 40,104 |

# ENTERGY	LOUISIANA,	INC.

Net	income	decreased	$18.7	million	primarily	due	to	lower	net	revenue,	partially	offset	by	lower	other	operation	and	maintenance	expenses.

Net	income	increased	slightly	primarily	due	to	higher	net	revenue	and	lower	interest	charges,	almost	entirely	offset	by	higher	other	operation	and	maintenance expenses,	higher	depreciation	and	amortization	expenses,	and	higher	taxes	other	than	income	taxes.

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

|  | (In	Millions) |
| :--- | :--- |
| 2003\tnet\trevenue | $973.7 |
| Price\tapplied\tto\tunbilled\tsales | (31.9) |
| Deferred\tfuel\tcost\trevisions | (29.4) |
| Rate\trefund\tprovisions | (12.2) |
| Volume/weather | 17.0 |
| Summer\tcapacity\tcharges | 11.8 |
| Other | 2.3 |
| 2004\tnet\trevenue | $931.3 |

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

The	deferred	fuel	cost	revisions	variance	resulted	from	a	revised	unbilled	sales	pricing	estimate	made	in	the	first	quarter	of	2003	to	more	closely	align	the	fuel component	of	that	pricing	with	expected	recoverable	fuel	costs.

The	volume/weather	variance	is	due	to	a	total	increase	of	620	GWh	in	weather-adjusted	usage	in	all	sectors,	partially	offset	by	the	effect	of	milder	weather	on	billed sales	in	the	residential	and	commercial	sectors.

The	summer	capacity	charges	variance	is	due	to	the	amortization	in	2003	of	deferred	capacity	charges	for	the	summer	of	2001	compared	to	the	absence	of	the amortization	in	2004.	The	amortization	of	these	capacity	charges	began	in	August	2002	and	ended	in	July	2003.

an	increase	of	$98.0	million	in	fuel	cost	recovery	revenues	due	to	higher	fuel	rates;	and an	increase	due	to	volume/weather,	as	discussed	above.

The	increase	was	partially	offset	by	the	following:

a	decrease	of	$31.9	million	in	the	price	applied	to	unbilled	sales,	as	discussed	above; a	decrease	of	$12.2	million	in	rate	refund	provisions,	as	discussed	above;	and a	decrease	of	$5.2	million	in	gross	wholesale	revenue	due	to	decreased	sales	to	affiliated	systems.

an	increase	in	the	recovery	from	customers	of	deferred	fuel	costs;	and an	increase	in	the	market	price	of	natural	gas.

Other	regulatory	credits	increased	primarily	due	to:

the	amortization	in	2003	of	$11.8	million	of	deferred	capacity	charges,	as	discussed	above;	and

the	deferral	in	2004	of	$11.4	million	related	to	Entergy's	voluntary	severance	program,	in	accordance	with	a	proposed	stipulation	with	the	LPSC	staff.

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

|  | (In	Millions) |
| :--- | :--- |
| 2002\tnet\trevenue | $922.9 |
| Deferred\tfuel\tcost\trevisions | 59.1 |
| Asset\tretirement\tobligation | 8.2 |
| Volume | (16.2) |
| Vidalia\tsettlement | (9.2) |
| Other | 8.9 |
| 2003\tnet\trevenue | $973.7 |

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

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

The	volume	variance	was	due	to	a	decrease	in	electricity	usage	in	the	service	territory.	Billed	usage	decreased	1,868	GWh	in	the	industrial	sector	including	the	loss of	a	large	industrial	customer	to	cogeneration.

See	"Liquidity	and	Capital	Resources"	below	for	more	details	regarding	the	September	2002	settlement	related	to	the	Vidalia	contract.

# Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	charges	(credits)

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.

an	increase	of	$8.2	million	due	to	the	change	in	accounting	for	asset	retirement	obligations	in	compliance	with	SFAS	143,	adopted	in	January	2003.	This increase	has	no	effect	on	net	income;	and

an	increase	of	$5.9	million	due	to	the	deferral	of	capacity	charges	in	the	third	quarter	of	2003	as	allowed	by	the	LPSC	related	to	generation	resource	planning.

Other	operation	and	maintenance	expenses	decreased	primarily	due	to	voluntary	severance	program	accruals	of	$19.7	million	in	2003,	partially	offset	by	an	increase of	$9.1	million	in	customer	service	support	costs.

Other	operation	and	maintenance	expenses	increased	primarily	due	to:

voluntary	severance	program	accruals	of	$19.7	million;	and

an	increase	of	$13.4	million	in	benefit	costs.

Decommissioning	expenses	increased	$10.1	million	primarily	due	to	the	implementation	of	SFAS	143,	"Accounting	for	Asset	Retirement	Obligations,"	adopted	in January	2003.	See	"Critical	Accounting	Estimates"	for	more	details	on	SFAS	143.	The	increase	in	decommissioning	expense	was	offset	by	regulatory	credits	and interest	and	dividend	income	and	had	no	effect	on	net	income.

Taxes	other	than	income	taxes	increased	primarily	due	to	the	franchise	tax	adjustments	of	$10.8	million	recorded	in	2002	as	a	result	of	a	favorable	court	decision that	allowed	Entergy	Louisiana	to	receive	a	refund	for	certain	franchise	taxes	previously	expensed	and	paid	under	protest.

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.

The	effective	income	tax	rates	for	2004,	2003,	and	2002	were	38.4%,	40.0%,	and	36.9%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rate.		Tax	reserves	not	expected	to	reverse	within the	next	year	are	reflected	as	non-current	taxes	accrued	on	the	balance	sheet.

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $8,787 | $311,800 | $42,408 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 424,718 | 413,939 | 1,035,777 |
| Investing\tactivities | (243,231) | (268,372) | (212,333) |
| Financing\tactivities | (44,225) | (448,580) | (554,052) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
|  | 137,262 | (303,013) | 269,392 |

Cash	flow	from	operations	increased	$10.8	million	in	2004	primarily	due	to	the	increased	collection	of	deferred	fuel	costs	and	the	receipt	of	an	income	tax	payment through	Entergy's	inter-company	tax	allocation	process.	The	increase	was	almost	entirely	offset	by	money	pool	activity.

In	2003,	the	domestic	utility	companies	and	System	Energy	filed,	with	the	IRS,	a	change	in	tax	accounting	method	notification	for	their	respective	calculations	of cost	of	goods	sold.	The	adjustment	implemented	a	simplified	method	of	allocation	of	overhead	to	the	production	of	electricity,	which	is	provided	under	the	IRS capitalization	regulations.	The	cumulative	adjustment	placing	these	companies	on	the	new	methodology	resulted	in	a	$505	million	deduction	for	Entergy	Louisiana on	Entergy's	2003	income	tax	return.	There	was	no	cash	benefit	from	the	method	change	in	2003.	In	2004	Entergy	Louisiana	realized	$100	million	in	cash	tax benefit	from	the	method	change.	This	tax	accounting	method	change	is	an	issue	across	the	utility	industry	and	will	likely	be	challenged	by	the	IRS	on	audit.		As	of December	31,	2004,	Entergy	Louisiana	has	a	net	operating	loss	(NOL)	carryforward	for	tax	purposes	of	$195.7	million,	principally	resulting	from	the	change	in	tax accounting	method	related	to	cost	of	goods	sold.		If	the	tax	accounting	method	change	is	sustained,	Entergy	Louisiana	expects	to	utilize	the	NOL	carryforward through	2005.

Cash	flow	from	operations	decreased	$621.8	million	in	2003	as	a	result	of	Entergy	Louisiana	changing	its	method	of	accounting	for	tax	purposes	related	to	its wholesale	electric	power	contracts,	including	the	contract	to	purchase	power	from	the	Vidalia	project	(the	contract	is	discussed	in	Note	8	to	the	domestic	utility companies	and	System	Energy	financial	statements).	The	new	tax	accounting	method	provided	a	cumulative	cash	flow	benefit	of	approximately	$790	million through	2004,	which	is	expected	to	reverse	in	the	years	2005	through	2031.	The	election	did	not	reduce	book	income	tax	expense.	The	timing	of	the	reversal	of	this benefit	depends	on	several	variables,	including	the	price	of	power.	In	a	settlement	approved	by	the	LPSC,	Entergy	Louisiana	will	keep	a	portion	of	the	benefit	in exchange	for	crediting	customer	rates.	The	credit	will	be	$11	million	annually	through	at	least	2010.	See	Part	I,	Item	1	for	additional	details	concerning	the settlement.

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

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

Money	pool	activity	used	$81.9	million	of	Entergy	Louisiana's	operating	cash	flow	in	2004,	provided	$60.2	million	in	2003,	and	used	$15.0	million	in	2002.	See Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

The	decrease	of	$25.1	million	in	net	cash	used	by	investing	activities	in	2004	was	primarily	due	to	decreased	spending	on	customer	service	projects,	partially	offset by	increases	in	spending	on	transmission	projects	and	fossil	plant	projects.

The	increase	of	$56.0	million	in	net	cash	used	by	investing	activities	in	2003	was	primarily	due	to	increased	spending	on	customer	service,	transmission,	and	nuclear projects.

The	decrease	of	$404.4	million	in	net	cash	used	by	financing	activities	in	2004	was	primarily	due	to:

a	principal	payment	of	$14.8	million	in	2004	for	the	Waterford	Lease	Obligation	compared	to	a	principal	payment	of	$35.4	million	in	2003;	and a	decrease	of	$29.0	million	in	common	stock	dividends	paid.

a	decrease	of	$125.9	million	in	common	stock	dividends	paid;	and

the	repurchase	of	$120	million	of	common	stock	from	Entergy	Corporation	in	2002.

The	decrease	in	net	cash	used	in	2003	was	partially	offset	by	the	following:

the	retirement	in	2003	of	$150	million	of	8.5%	Series	First	Mortgage	Bonds	compared	to	the	net	retirement	of	$134.6	million	of	First	Mortgage	Bonds	in 2002;	and

principal	payments	of	$35.4	million	in	2003	for	the	Waterford	3	Lease	Obligation	compared	to	principal	payments	of	$15.9	million	in	2002.

See	Note	5	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	details	of	long-term	debt.

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:

|  | 2005 | 2006-2007 | 2008-2009 | After	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand\ncapital\tinvestment\t(1) | $455 | $472 | N/A | N/A | $927 |

| Long-term	debt | $55 | $- | $7 | $924 | $986 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Operating\tleases | $10 | $11 | $6 | $2 | $29 |
| Purchase\tobligations\t(2) | $639 | $1,120 | $980 | $4,691 | $7,430 |
| Nuclear\tfuel\tlease\tobligations\t(3) | $23 | $9 | N/A | N/A | $32 |

(2) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	For	Entergy	Louisiana	almost	all	of	the	total consists	of	unconditional	fuel	and	purchased	power	obligations,	including	its	obligations	under	the Vidalia	 purchased	 power	 agreement	 and	 the	 Unit	 Power	 Sales	 Agreement,	 both	 of	 which	 are discussed	in	Note	8	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

In	addition	to	these	contractual	obligations,	Entergy	Louisiana	expects	to	contribute	$2.6	million	to	its	pension	plans	and	$8.5	million	to	other	postretirement	plans in	2005.

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

As	a	wholly-owned	subsidiary,	Entergy	Louisiana	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.	In	addition,	all	of	Entergy Louisiana's	retained	earnings	are	currently	available	for	distribution.

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

bank	financing	under	new	and	existing	facilities.

Entergy	Louisiana	issued	$285	million	of	first	mortgage	bonds	in	2004	as	follows:

Entergy	Louisiana	retired	$187.2	million	of	long-term	debt	in	2004	as	follows:

Entergy	Louisiana	may	refinance	or	redeem	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Louisiana	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also	subject	to issuance	 tests	 set	 forth	 in	 corporate	 charters,	 bond	 indentures,	 and	 other	 agreements.	Entergy	Louisiana	has	sufficient	capacity	under	 these	 tests	 to	meet	 its foreseeable	capital	needs.

In	July	2004,	Entergy	Louisiana	renewed	its	364-day	credit	facility	and	Entergy	New	Orleans	entered	into	a	separate	credit	facility	with	the	same	lender.	Both facilities	will	expire	in	April	2005.	Entergy	Louisiana	can	borrow	up	to	$15	million	and	Entergy	New	Orleans	can	borrow	up	to	$14	million	under	their	respective credit	facilities,	but	at	no	time	can	the	total	amount	borrowed	under	these	facilities	by	the	two	companies	combined	exceed	$15	million.	As	of	December	31,	2004, no	borrowings	were	outstanding	under	these	facilities.	Borrowings	and	securities	issuances	by	Entergy	Louisiana	are	limited	to	amounts	authorized	by	the	SEC.	The current	short-term	borrowing	limitation,	including	borrowings	under	the	money	pool,	is	$225	million.	Under	its	SEC	Orders	and	without	further	SEC	authorization, Entergy	Louisiana	cannot	incur	additional	indebtedness	or	issue	other	securities	unless	(a)	it	and	Entergy	Corporation	maintain	a	common	equity	ratio	of	at	least 30%	and	(b)	with	the	exception	of	money	pool	borrowings,	the	security	to	be	issued	(if	rated)	and	all	outstanding	securities	of	Entergy	Louisiana,	as	well	as	all outstanding	securities	of	Entergy	Corporation,	that	are	rated,	are	rated	investment	grade.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial

statements	for	further	discussion	of	Entergy	Louisiana's	short-term	borrowing	limits.

At	FERC,	the	pace	of	restructuring	at	the	wholesale	level	has	begun	but	has	been	delayed.	It	is	too	early	to	predict	the	ultimate	effects	of	changes	in	United	States energy	markets.	Restructuring	issues	are	complex	and	are	continually	affected	by	events	at	the	national,	regional,	state,	and	local	levels.	However,	these	changes may	result,	in	the	long-term,	in	fundamental	changes	in	the	way	traditional	integrated	utilities	and	holding	company	systems,	like	the	Entergy	system,	conduct	their business.	Some	of	these	changes	may	be	positive	for	Entergy,	while	others	may	not.

# State	Rate	Regulation

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

In	January	2005,	Entergy	Gulf	States	and	Entergy	Louisiana	filed	testimony	with	the	LPSC	in	support	of	a	proposed	settlement	with	the	LPSC	that	would	resolve, among	other	dockets,	dockets	established	to	consider	issues	concerning	power	purchases	for	both	Entergy	Gulf	States	and	Entergy	Louisiana	for	the	summers	of 2001,	2002,	2003,	and	2004.	The	proposed	settlement	currently	includes	an	offer	to	refund	$14	million	to	Entergy	Louisiana's	customers.	The	LPSC	has	solicited comments	on	the	proposed	settlement	from	the	parties	to	the	various	proceedings	at	issue	in	the	proposed	settlement.	The	proposed	settlement	is	scheduled	to	be presented	to	the	LPSC	for	consideration	on	March	23,	2005.

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

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

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

|  | (In	Millions) | (In	Millions) |
| :--- | :--- | :--- |
| Entergy\tArkansas | $154\tto\t$281 | $215 |
| Entergy\tGulf\tStates | ($130)\tto\t($15) | ($63) |
| Entergy\tLouisiana | ($199)\tto\t($98) | ($141) |
| Entergy\tMississippi | ($16)\tto\t$8 | $1 |
| Entergy\tNew\tOrleans | ($17)\tto\t($5) | ($12) |

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

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

the	petition	is	expected	during	the	first	half	of	2005.

The	domestic	utility	companies	(except	Entergy	New	Orleans)	are	currently	defendants	to	several	complaints	and	rehearing	requests	before	the	FERC	in	which independent	generation	entities	(GenCos)	are	seeking	a	refund	of	monies	that	the	GenCos	had	previously	paid	to	the	Entergy	companies	for	facilities	necessary	to connect	their	generation	facilities	to	Entergy's	transmission	system.	The	FERC	has	issued	initial	orders	in	response	to	two	of	the	complaints	and	in	certain	other dockets	ordering	Entergy	to	refund	approximately	$100	million	in	expenses	and	tax	obligations	previously	paid	by	the	GenCos,	including	$3	million	for	Entergy Louisiana.	The	refunds	will	be	in	the	form	of	transmission	credits	that	will	be	utilized	over	time	as	the	GenCos	take	transmission	service	from	Entergy.

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

# 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,	8,	and	12	to	the	domestic	utility companies	and	System	Energy	financial	statements.

Entergy	Louisiana	owns	and	operates,	through	an	affiliate,	the	Waterford	3	nuclear	power	plant.	Entergy	Louisiana	is,	therefore,	subject	to	the	risks	related	to owning	and	operating	a	nuclear	plant.	These	include	risks	from	the	use,	storage,	handling	and	disposal	of	high-level	and	low-level	radioactive	materials,	limitations on	the	amounts	and	types	of	insurance	commercially	available	for	losses	in	connection	with	nuclear	operations,	and	technological	and	financial	uncertainties	related to	decommissioning	nuclear	plants	at	the	end	of	their	licensed	lives,	including	the	sufficiency	of	funds	in	decommissioning	trusts.	In	the	event	of	an	unanticipated early	 shutdown	 of	 Waterford	 3,	 Entergy	 Louisiana	 may	 be	 required	 to	 provide	 additional	 funds	 or	 credit	 support	 to	 satisfy	 regulatory	 requirements	 for decommissioning.

In	August	2001,	the	NRC	issued	a	bulletin	requesting	all	pressurized	water	reactor	owners	and	operators	to	report	on	the	structural	integrity	of	their	reactor	vessel head	penetration	nozzles	to	justify	continued	operations	past	December	31,	2001.	These	types	of	reactors	are	susceptible	to	stress	corrosion	cracking	of	the	reactor vessel	head	nozzles.	Waterford	is	a	pressurized	water	reactor.	To	date,	there	has	been	no	primary	side	stress	corrosion	cracking	identified	in	the	Waterford	reactor

vessel	head.	Inspections	of	the	Waterford	reactor	vessel	head	will	continue	during	planned	refueling	outages.

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	business	risk.

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

Regulations	require	Entergy	Louisiana	to	decommission	the	Waterford	3	nuclear	power	plant	after	the	facility	is	taken	out	of	service,	and	money	is	collected	and deposited	in	trust	funds	during	the	facility's	operating	life	in	order	to	provide	for	this	obligation.	Entergy	Louisiana	conducts	periodic	decommissioning	cost	studies (typically	updated	every	 three	 to	five	years)	 to	estimate	 the	costs	 that	will	be	 incurred	 to	decommission	 the	facility.	The	following	key	assumptions	have	a significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	Entergy	Louisiana's	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over	present	cost levels	by	an	annual	factor	averaging	approximately	4.4%.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost	of	decommissioning	a facility	by	as	much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin	immediately	upon	plant retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable	regulations.	While	the	effect	of	these assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a	"safestore"	status	can	possibly	decrease	the	present	value	of these	obligations.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	DOE	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear	fuel,	and	legislation	has	been passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	Until	this	site	is	available,	however,	nuclear	plant	operators	must	provide	for interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and	maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs of	developing	and	maintaining	these	facilities	can	have	a	significant	effect	(as	much	as	16%	of	estimated	decommissioning	costs).	Entergy	Louisiana's decommissioning	studies	include	cost	estimates	for	spent	fuel	storage.	However,	these	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening of	the	Yucca	Mountain	facility,	the	schedule	for	shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

Entergy	Louisiana	collects	substantially	all	of	the	projected	costs	of	decommissioning	Waterford	3	through	rates	charged	to	customers.	The	amounts	collected through	rates,	which	are	based	upon	decommissioning	cost	studies,	are	deposited	in	decommissioning	trust	funds.	These	collections	plus	earnings	on	the	trust	fund investments	 are	 estimated	 to	 be	 sufficient	 to	 fund	 the	 future	 decommissioning	 costs.	If	decommissioning	cost	study	estimates	are	changed	and	approved	by regulators,	collections	from	customers	would	also	change.

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

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

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

The	net	effect	of	implementing	SFAS	143	for	Entergy	Louisiana	was	recorded	as	a	regulatory	asset,	with	no	resulting	impact	on	Entergy	Louisiana's	net	income. Entergy	Louisiana	recorded	 this	regulatory	asset	because	 its	existing	rate	mechanism	 is	based	on	 the	original	or	historical	cost	standard	 that	allows	Entergy Louisiana	to	recover	all	ultimate	costs	of	decommissioning	existing	assets	from	current	and	future	customers.	Upon	implementation	of	SFAS	143	in	2003,	assets	and liabilities	increased	by	$305	million	as	a	result	of	recording	the	asset	retirement	obligation	at	its	fair	value	of	$305	million	as	determined	under	SFAS	143, increasing	total	utility	plant	by	$99	million,	reducing	accumulated	depreciation	by	$82	million,	and	recording	the	related	regulatory	asset	of	$124	million.

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

Entergy	sponsors	defined	benefit	pension	plans	which	cover	substantially	all	employees.	Additionally,	Entergy	currently	provides	postretirement	health	care	and	life insurance	benefits	for	substantially	all	employees	who	reach	retirement	age	while	still	working	for	Entergy.	Entergy's	reported	costs	of	providing	these	benefits,	as described	in	Note	10	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	are	impacted	by	numerous	factors	including	the	provisions	of	the

plans,	 changing	 employee	 demographics,	 and	 various	 actuarial	 calculations,	 assumptions,	 and	 accounting	 mechanisms.	 Because	 of	 the	 complexity	 of	 these calculations,	the	long-term	nature	of	these	obligations,	and	the	importance	of	the	assumptions	utilized,	Entergy's	estimate	of	these	costs	is	a	critical	accounting estimate.

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $1,061 | $12,385 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $786 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $523 | $3,018 |

|  | Change	in | Impact	on	2004 | Postretirement	Benefit |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Postretirement\tBenefit\tCost | Obligation |
|  | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $416 | $2,407 |
| Discount\trate | (0.25%) | $234 | $3,033 |

Total	pension	cost	for	Entergy	Louisiana	in	2004	was	$3.3	million.	Entergy	Louisiana	anticipates	2005	pension	cost	to	increase	to	$6.8	million	due	to	decrease	in the	discount	rate	(from	6.25%	to	6.00%)	and	the	expected	rate	of	return	(from	8.75%	to	8.5%)	used	to	calculate	benefit	obligations.	Entergy	Louisiana	contributed $3.9	million	to	its	pension	plan	in	2004	and	anticipates	making	$2.6	million	in	contributions	in	2005.	The	decrease	in	pension	funding	requirements	is	due	to	the Pension	Funding	Equity	Act	relief	passed	in	April	2004,	partially	offset	by	declining	interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to 2002.

Entergy	Louisiana's	accumulated	benefit	obligation	at	December	31,	2004,	and	2002	exceeded	plan	assets.	As	a	result,	Entergy	Louisiana	was	required	to	recognize an	additional	minimum	liability	as	prescribed	by	SFAS	87	in	those	years.	At	December	31,	2003,	Entergy	Louisiana's	accumulated	benefit	obligation	was	less	than plan	assets,	therefore	there	was	no	additional	minimum	pension	liability	required	to	be	recognized.	At	December	31,	2004,	Entergy	Louisiana	recorded	an	additional pension	minimum	liability	of	$38.9	million;	an	offsetting	intangible	asset	of	$4.8	million,	and	a	regulatory	asset	of	$34.1	million.	Net	income	for	2004,	2003,	and 2002	was	not	impacted	by	the	additional	minimum	pension	liability.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Louisiana	in	2004	were	$12.3	million,	including	$2.8	million	in	savings	due	to	the estimated	effect	of	future	Medicare	Part	D	subsidies.	Entergy	Louisiana	expects	2005	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate $12.7	million,	including	$3.2	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.	The	increase	in	postretirement	health	care	and	life insurance	benefit	costs	is	due	to	the	decrease	in	the	discount	rate	(from	6.25%	to	6.00%)	and	an	increase	in	the	health	care	cost	trend	rate	used	to	calculate	benefit obligations.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Louisiana,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	income,	retained earnings,	and	cash	flows	(pages	219	through	224	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period	ended	December	31,	2004. These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	based	on our	audits.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Louisiana,	Inc.	as	of	December	31,	2004	and	2003, and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	5	and	Note	8	to	the	notes	to	respective	financial	statements,	in	2003	Entergy	Louisiana,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	 Standards	 Board Interpretation	 No.	 46,	Consolidation	 of	 Variable Interest	 Entities,	and	 Statement	 of	 Financial	Accounting	 Standards	 No.	 143, Accounting	for	Asset	Retirement	Obligations.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Domestic\telectric | $2,226,986 | $2,165,570 | $1,815,352 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 671,549 | 525,645 | 436,568 |
| \t\tPurchased\tpower | 667,893 | 668,337 | 438,627 |
| \t\tNuclear\trefueling\toutage\texpenses | 13,633 | 11,130 | 11,502 |
| \t\tOther\toperation\tand\tmaintenance | 367,824 | 376,770 | 340,803 |
| Decommissioning | 21,958 | 20,569 | 10,422 |
| Taxes\tother\tthan\tincome\ttaxes | 68,999 | 70,084 | 60,698 |
| Depreciation\tand\tamortization | 197,380 | 192,972 | 182,871 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (43,765) | (2,160) | 17,219 |
| TOTAL | 1,965,471 | 1,863,347 | 1,498,710 |
| OPERATING\tINCOME | 261,515 | 302,223 | 316,642 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 7,494 | 6,900 | 5,195 |
| Interest\tand\tdividend\tincome | 8,209 | 8,820 | 7,668 |
| Miscellaneous\t-\tnet | (929) | (3,100) | (3,244) |
| TOTAL | 14,774 | 12,620 | 9,619 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 70,210 | 73,227 | 98,242 |
| Other\tinterest\t-\tnet | 3,931 | 3,529 | 2,425 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (4,822) | (5,475) | (3,880) |
| TOTAL | 69,319 | 71,281 | 96,787 |
| INCOME\tBEFORE\tINCOME\tTAXES | 206,970 | 243,562 | 229,474 |
| Income\ttaxes | 79,475 | 97,408 | 84,765 |
| NET\tINCOME | 127,495 | 146,154 | 144,709 |
| Preferred\tdividend\trequirements\tand\tother | 6,714 | 6,714 | 6,714 |

# EARNINGS	APPLICABLE	TO

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $127,495 | $146,154 | $144,709 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\noperating\tactivities: |  |  |  |
| \t\tReserve\tfor\tregulatory\tadjustments | 14,076 | 1,858 | - |
| \t\tOther\tregulatory\tcharges\t(credits)\t-\tnet | (43,765) | (2,160) | 17,219 |
| \t\tDepreciation,\tamortization,\tand\tdecommissioning | 219,338 | 213,541 | 193,293 |
| \t\tDeferred\tincome\ttaxes\tand\tinvestment\ttax\tcredits | 75,078 | 859,157 | 39,849 |
| \t\tChanges\tin\tworking\tcapital: |  |  |  |
| \t\t\t\tReceivables | (36,185) | (4,418) | (68,936) |
| \t\t\t\tAccounts\tpayable | (36,862) | 49,028 | 7,370 |
| \t\t\t\tTaxes\taccrued | 89,079 | (804,805) | 779,590 |
| \t\t\t\tInterest\taccrued | (1,791) | (10,324) | (3,971) |
| \t\t\t\tDeferred\tfuel\tcosts | 21,955 | (56,211) | (41,891) |
| \t\t\t\tOther\tworking\tcapital\taccounts | 20,693 | 10,395 | (118,718) |
| \t\tProvision\tfor\testimated\tlosses\tand\treserves | 6,119 | 12,194 | 5,818 |
| \t\tChanges\tin\tother\tregulatory\tassets | (14,456) | 59,169 | (23,879) |
| \t\tOther | (16,056) | (59,639) | 105,324 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 424,718 | 413,939 | 1,035,777 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (240,283) | (257,754) | (209,826) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 7,494 | 6,900 | 5,195 |
| Nuclear\tfuel\tpurchases | - | (41,525) | (50,473) |
| Proceeds\tfrom\tthe\tsale/leaseback\tof\tnuclear\tfuel | - | 41,525 | 50,473 |
| Decommissioning\ttrust\tcontributions\tand\trealized |  |  |  |
| \tchange\tin\ttrust\tassets | (12,615) | (17,506) | (13,854) |
| Changes\tin\tother\tinvestments\t-\tnet | 2,173 | (12) | 6,152 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (243,231) | (268,372) | (212,333) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 282,745 | - | 144,679 |
| Retirement\tof\tlong-term\tdebt | (203,756) | (296,366) | (300,617) |
| Repurchase\tof\tcommon\tstock | - | - | (120,000) |
| Dividends\tpaid: |  |  |  |
| \t\tCommon\tstock | (116,500) | (145,500) | (271,400) |
| \t\tPreferred\tstock | (6,714) | (6,714) | (6,714) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | (44,225) | (448,580) | (554,052) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 137,262 | (303,013) | 269,392 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 8,787 | 311,800 | 42,408 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $146,049 | $8,787 | $311,800 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid/(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| \t\tInterest\t-\tnet\tof\tamount\tcapitalized | $73,170 | $84,089 | $99,998 |
| \t\tIncome\ttaxes | ($70,650) | $35,128 | ($781,540) |

| Cash | $3,875 | $8,787 |
| :--- | :--- | :--- |
| \t\tTemporary\tcash\tinvestments\t-\tat\tcost, |  |  |
| \t\t\twhich\tapproximates\tmarket | 142,174 | - |
| \t\t\t\t\tTotal\tcash\tand\tcash\tequivalents | 146,049 | 8,787 |
| Accounts\treceivable: |  |  |
| \t\tCustomer | 88,154 | 93,393 |
| \t\tAllowance\tfor\tdoubtful\taccounts | (3,135) | (4,487) |
| \t\tAssociated\tcompanies | 43,121 | 9,074 |
| \t\tOther | 13,070 | 12,334 |
| \t\tAccrued\tunbilled\trevenues | 143,453 | 138,164 |
| \t\t\t\t\tTotal\taccounts\treceivable | 284,663 | 248,478 |
| Deferred\tfuel\tcosts | 8,654 | 30,609 |
| Accumulated\tdeferred\tincome\ttaxes | 12,712 | - |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 77,665 | 74,349 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 5,605 | 19,226 |
| Prepayments\tand\tother | 6,861 | 67,623 |
| TOTAL | 542,209 | 449,072 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 14,230 | 14,230 |
| Decommissioning\ttrust\tfunds | 172,083 | 151,996 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 21,176 | 21,307 |
| Other | 4 | 2,177 |
| TOTAL | 207,493 | 189,710 |
| UTILITY\tPLANT |  |  |
| Electric | 5,985,889 | 5,836,914 |
| Property\tunder\tcapital\tlease | 250,964 | 250,102 |
| Construction\twork\tin\tprogress | 188,848 | 172,405 |
| Nuclear\tfuel\tunder\tcapital\tlease | 31,655 | 65,066 |
| TOTAL\tUTILITY\tPLANT | 6,457,356 | 6,324,487 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 2,799,936 | 2,686,778 |
| UTILITY\tPLANT\t-\tNET | 3,657,420 | 3,637,709 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 132,686 | 156,111 |
| \t\tOther\tregulatory\tassets | 302,456 | 217,689 |
| Long-term\treceivables | 10,736 | 1,511 |
| Other | 25,994 | 22,737 |
| TOTAL | 471,872 | 398,048 |
| TOTAL\tASSETS | $4,878,994 | $4,674,539 |

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $55,000 | $14,809 |

| Associated	companies | 57,681 | 101,191 |
| :--- | :--- | :--- |
| \t\tOther | 128,523 | 121,875 |
| Customer\tdeposits | 66,963 | 61,215 |
| Accumulated\tdeferred\tincome\ttaxes | - | 566 |
| Taxes\taccrued | 7,268 | - |
| Interest\taccrued | 18,438 | 20,229 |
| Obligations\tunder\tcapital\tleases | 22,753 | 35,506 |
| Other | 10,428 | 5,110 |
| TOTAL | 367,054 | 360,501 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,805,410 | 1,728,156 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 96,130 | 101,258 |
| Obligations\tunder\tcapital\tleases | 8,903 | 29,560 |
| Other\tregulatory\tliabilities | 51,260 | 39,026 |
| Decommissioning\tliabilities | 347,255 | 325,298 |
| Accumulated\tprovisions | 92,653 | 86,534 |
| Long-term\tdebt | 930,695 | 887,687 |
| Other | 106,815 | 47,981 |
| TOTAL | 3,439,121 | 3,245,500 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDERS'\tEQUITY |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 100,500 | 100,500 |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t250,000,000 |  |  |
| \tshares;\tissued\t165,173,180\tshares\tin\t2004\tand\t2003 | 1,088,900 | 1,088,900 |
| Capital\tstock\texpense\tand\tother | (1,718) | (1,718) |
| Retained\tearnings | 5,137 | 856 |
| Less\t-\ttreasury\tstock,\tat\tcost\t(18,202,573\tshares\tin\t2004\tand\t2003) | 120,000 | 120,000 |
| TOTAL | 1,072,819 | 1,068,538 |
| TOTAL\tLIABILITIES\tAND\tSHAREHOLDERS'\tEQUITY | $4,878,994 | $4,674,539 |

| Retained	Earnings,	January	1 | $856 | $6,916 | $140,321 |
| :--- | :--- | :--- | :--- |
| \t\tAdd:\n\t\t\t\tNet\tincome | 127,495 | 146,154 | 144,709 |
| \t\tDeduct: |  |  |  |
| \t\t\t\tDividends\tdeclared: |  |  |  |
| \t\t\t\tPreferred\tstock | 6,714 | 6,714 | 6,714 |
| \t\t\t\tCommon\tstock | 116,500 | 145,500 | 271,400 |
| \t\t\t\t\t\tTotal | 123,214 | 152,214 | 278,114 |
| Retained\tEarnings,\tDecember\t31 | $5,137 | $856 | $6,916 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,226,986 | $2,165,570 | $1,815,352 | $1,901,913 | $2,062,437 |

| Net	Income | $127,495 | $146,154 | $144,709 | $132,550 | $162,679 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Total\tassets | $4,878,994 | $4,674,539 | $4,753,704 | $4,149,701 | $4,289,409 |
| Long-term\tobligations\t(1) | $939,598 | $917,247 | $919,319 | $1,197,473 | $1,411,345 |

(1)	Included	long-term	debt	(excluding	currently	maturing	debt),	preferred	stock	with	sinking	fund	(for	the year	2000	only),	and	noncurrent	capital	lease	obligations.

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $770 | $739 | $638 | $658 | $717 |
| \t\tCommercial | 501 | 473 | 403 | 429 | 441 |
| \t\tIndustrial | 779 | 723 | 637 | 760 | 767 |
| \t\tGovernmental | 38 | 41 | 36 | 39 | 39 |
| \t\t\t\tTotal\tretail | 2,088 | 1,976 | 1,714 | 1,886 | 1,964 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 96 | 102 | 8 | 25 | 21 |
| \t\t\t\tNon-associated\tcompanies | 13 | 12 | 11 | 23 | 40 |
| \t\tOther | 30 | 76 | 82 | (32) | 38 |
| \t\t\t\tTotal | $2,227 | $2,166 | $1,815 | $1,902 | $2,063 |
| Billed\tElectric\tEnergy\tSales\n(GWh): |  |  |  |  |  |
| \t\tResidential | 8,842 | 8,795 | 8,780 | 8,255 | 8,648 |
| \t\tCommercial | 5,762 | 5,622 | 5,538 | 5,369 | 5,367 |
| \t\tIndustrial | 13,140 | 12,870 | 14,738 | 14,402 | 15,184 |
| \t\tGovernmental | 439 | 491 | 510 | 498 | 481 |
| \t\t\t\tTotal\tretail | 28,183 | 27,778 | 29,566 | 28,524 | 29,680 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 1,129 | 1,344 | 146 | 381 | 228 |
| \t\t\t\tNon-associated\tcompanies | 122 | 132 | 139 | 334 | 554 |
| \t\t\t\tTotal | 29,434 | 29,254 | 29,851 | 29,239 | 30,462 |

Net	income	increased	$6.4	million	primarily	due	to	higher	net	revenue,	partially	offset	by	higher	other	operation	and	maintenance	expenses	and	higher	taxes	other than	income	taxes.

Net	income	increased	$14.7	million	primarily	due	to	higher	net	revenue,	partially	offset	by	higher	other	operation	and	maintenance	expenses	and	depreciation	and amortization	expenses,	and	lower	interest	income.

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

|  | (In	Millions) |
| :--- | :--- |
| 2003\tnet\trevenue | $426.6 |
| Volume/weather | 6.4 |
| Net\twholesale\trevenue | 5.0 |
| Other | 5.5 |
| 2004\tnet\trevenue | $443.5 |

The	volume/weather	variance	resulted	from	an	increase	of	247	GWh	in	weather-adjusted	usage,	partially	offset	by	the	effect	of	milder	weather	on	billed	sales.

The	net	wholesale	revenue	variance	resulted	from	an	increase	in	energy	available	for	resale	sales,	partially	offset	by	a	decrease	in	the	average	price	of	energy supplied	for	affiliated	sales.

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$174.0	million	in	fuel	cost	recovery	revenues	due	to	higher	fuel	rates	and	an	increase	of	$26.3 million	in	gross	wholesale	revenue.	The	increase	was	partially	offset	by	a	decrease	of	$37.6	million	in	Grand	Gulf	revenue	as	a	result	of	the	cessation	of	the	Grand Gulf	Accelerated	Tariff	in	July	2003.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	the	over-recovery	of	fuel	and	purchased	power	costs	as	a	result	of	higher	fuel	rates.	Entergy

Mississippi's	fuel	rates	include	an	energy	cost	recovery	rider	to	recover	projected	energy	costs.	Actual	fuel	and	purchased	power	costs	were	lower	than	those projected	in	the	computation	of	the	energy	cost	factors	for	the	third	quarter	of	2004	which	contributed	to	the	over-recovery	of	fuel	and	purchased	power	costs.	The MPSC	has	allowed	Entergy	Mississippi	to	refund	these	over-recoveries	in	the	second	and	third	quarters	of	2005.	The	energy	cost	recovery	rider	is	discussed	in	more detail	in	Note	2	to	the	domestic	and	System	Energy	financial	statements.

Other	regulatory	charges	(credits)	have	no	material	effect	on	net	 income	due	 to	recovery	and/or	refund	of	such	expenses.	Other	regulatory	credits increased primarily	due	to	the	under-recovery	through	the	Grand	Gulf	rider	of	Grand	Gulf	capacity	charges.

|  | (In	Millions) |
| :--- | :--- |
| 2002\tnet\trevenue | $380.2 |
| Base\trates | 48.3 |
| Other | (1.9) |
| 2003\tnet\trevenue | $426.6 |

The	increase	in	base	rates	was	effective	January	2003	as	approved	by	the	MPSC.

# Gross	operating	revenue,	fuel	and	purchased	power	expenses,	and	other	regulatory	charges	(credits)

Gross	operating	revenues	increased	primarily	due	to	an	increase	in	base	rates	effective	January	2003	and	an	increase	of	$29.7	million	in	fuel	cost	recovery	revenues due	to	quarterly	changes	in	the	fuel	factor	resulting	from	the	increases	in	market	prices	of	natural	gas	and	purchased	power.	This	increase	was	partially	offset	by	a decrease	of	$35.9	million	in	gross	wholesale	revenue	as	a	result	of	decreased	generation	and	purchases	that	resulted	in	less	energy	available	for	resale	sales.

Fuel	and	fuel-related	expenses	decreased	primarily	due	to	the	decreased	recovery	of	fuel	and	purchased	power	costs	and	decreased	generation,	partially	offset	by	an increase	in	the	market	price	of	purchased	power.

Other	regulatory	charges	increased	primarily	due	to	over-recovery	of	capacity	charges	related	to	the	Grand	Gulf	rate	rider	and	the	cessation	of	the	Grand	Gulf Accelerated	Recovery	Tariff	that	was	suspended	in	July	2003.

an	increase	of	$6.6	million	in	customer	service	support	costs;	and an	increase	of	$3.7	million	in	benefit	costs.

The	increase	was	partially	offset	by	the	absence	of	the	voluntary	severance	program	accruals	of	$7.1	million	that	occurred	in	2003.

Taxes	other	than	income	taxes	increased	primarily	due	to	a	higher	assessment	of	ad	valorem	and	franchise	taxes	compared	to	the	same	period	in	2003.

The	increases	were	partially	offset	by	a	decrease	of	$4.0	million	in	plant	maintenance	expense	due	to	outage	costs	at	a	fossil	plant	in	2002.

Depreciation	and	amortization	expense	increased	due	to	an	increase	in	plant	in	service.

Interest	and	dividend	income	decreased	as	result	of	carrying	charges	associated	with	under-recovery	of	fuel	and	purchased	power	costs	during	2002.

The	effective	income	tax	rates	for	2004,	2003,	and	2002	were	33.5%,	33.9%,	and	25.4%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rate.		Tax	reserves	not	expected	to	reverse	within the	next	year	are	reflected	as	non-current	taxes	accrued	on	the	balance	sheet.

| Cash	and	cash	equivalents	at	beginning	of	period | $63,838 | $147,721 | $54,048 |
| :--- | :--- | :--- | :--- |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 258,179 | 253,288 | 156,868 |
| Investing\tactivities | (151,505) | (264,495) | (135,122) |
| Financing\tactivities | (90,116) | (72,676) | 71,927 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 16,558 | (83,883) | 93,673 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $80,396 | $63,838 | $147,721 |

Cash	flow	from	operations	increased	by	$4.9	million	in	2004	primarily	due	to	money	pool	activity	and	an	increase	in	recovery	of	deferred	fuel	and	purchased	power costs,	partially	offset	by	an	$12	million	income	tax	payment	in	2004	compared	to	a	$78	million	income	tax	refund	in	2003	and	an	increase	in	the	account	receivable balance	as	a	result	of	the	timing	of	customer	collections.

Cash	flow	from	operations	increased	by	$96.4	million	in	2003	primarily	due	to	a	$78	million	income	tax	refund	and	increased	net	income,	partially	offset	by	money pool	activity.

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

| 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $21,584 | $22,076 | $8,702 | $11,505 |

Money	pool	activity	provided	$0.5	million	of	Entergy	Mississippi's	operating	cash	flows	in	2004,	used	$13.4	million	of	its	operating	cash	flows	in	2003,	and provided	$2.8	million	of	its	operating	cash	flows	in	2002.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of the	money	pool.

Net	cash	used	in	investing	activities	decreased	$113.0	million	in	2004	primarily	due	to:

cash	used	in	2003	for	other	regulatory	investments	of	$72.6	million	as	a	result	of	under-recovered	fuel	and	purchased	power	costs;

a	decrease	of	$25.6	million	in	capital	expenditures	in	2004	due	to	decreased	spending	on	customer	care	projects	and	less	transmission	upgrade	work	requested by	merchant	generators;	and

the	maturity	in	2004	of	$7.5	million	of	other	temporary	investments	that	had	been	made	in	2003,	which	provided	cash	in	2004.

Net	cash	used	in	investing	activities	increased	$129.4	in	2003	primarily	due	to	cash	used	for	other	regulatory	investments	of	$72.6	million	as	a	result	of	under- recovered	fuel	and	purchased	power	costs	and	other	temporary	cash	investments	of	$18.6	million	that	provided	cash	in	2002	upon	maturity.

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

Net	cash	used	in	financing	activities	increased	$17.4	million	in	2004	primarily	due	to	an	increase	of	$15.1	million	in	dividends	paid.

Net	cash	used	in	financing	activities	increased	$144.6	million	in	2003	primarily	due	to	a	decrease	in	net	issuances	of	long-term	debt.

Entergy	Mississippi	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Mississippi's	planned	construction	and	other	capital	investments,	and	existing	debt	obligations:

|  | 2005 | 2006-2007 | 2008-2009 | After	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| capital\tinvestment\t(1) | $147 | $381 | N/A | N/A | $528 |
| Long-term\tdebt | - | - | $100 | $595 | $695 |
| Operating\tleases | $7 | $10 | $6 | $11 | $34 |
| Purchase\tobligations\t(2) | $190 | $361 | $336 | $2,059 | $2,946 |

(2) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	For	Entergy	Mississippi	almost	all	of	the	total consists	of	unconditional	fuel	and	purchased	power	obligations,	including	its	obligations	under	the Unit	Power	Sales	Agreement,	which	is	discussed	in	Note	8	to	the	domestic	utility	companies	and System	Energy	financial	statements.

In	addition	to	these	contractual	obligations,	Entergy	Mississippi	expects	to	contribute	$3.4	million	to	its	pension	plans	and	$4.2	million	to	other	postretirement	plans in	2005.

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

As	a	wholly-owned	subsidiary,	Entergy	Mississippi	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.	Entergy	Mississippi's	long- term	debt	indentures	restrict	the	amount	of	retained	earnings	available	for	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred	stock. As	of	December	31,	2004,	Entergy	Mississippi	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$68.5	million.

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

internally	generated	funds; cash	on	hand;

The	following	table	lists	First	Mortgage	Bonds	issued	by	Entergy	Mississippi	in	2004:

| Issue	Date | Description | Maturity | Amount |
| :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |
| April\t2004 | 6.25%\tSeries | April\t2034 | $100,000 |
| April\t2004 | 4.65%\tSeries | May\t2011 | 80,000 |

The	following	table	lists	First	Mortgage	Bonds	retired	by	Entergy	Mississippi	in	2004:

| Retirement	Date | Description | Maturity | Amount |
| :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |
| May\t2004 | 6.20%\tSeries | May\t2004 | $75,000 |
| May\t2004 | 6.45%\tSeries | April\t2008 | 80,000 |
| May\t2004 | 7.70%\tSeries | July\t2023 | 60,000 |

In	September	2004,	Entergy	Mississippi	arranged	the	issuance	of	$16	million	of	Mississippi	Business	Finance	Corporation	4.60%	Series	Pollution	Control	Revenue Refunding	Bonds	(Entergy	Mississippi,	Inc.	Project)	Series	2004	due	April	2022.	The	proceeds	from	this	issuance	were	used	to	redeem	prior	to	maturity,	$7.9 million	of	7.0%	Series	Washington	County	Bonds	due	April	2022	and	$8.1	million	of	7.0%	Series	Warren	County,	Mississippi	Bonds	due	April	2022.

Entergy	Mississippi	may	refinance	or	redeem	debt	and	preferred	stock	prior to	maturity, to the	extent	market	conditions	and interest	and	dividend	rates	are favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	Mississippi	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also	subject	to issuance	tests	set	forth	in	corporate	charters,	bond	 indentures,	and	other	agreements.	Entergy	Mississippi	has	sufficient	capacity	under	these	tests	to	meet	its foreseeable	capital	needs.

Entergy	Mississippi	has	a	364-day	credit	facility	available	expiring	May	2005	in	the	amount	of	$25	million	of	which	none	was	drawn	at	December	31,	2004. Borrowings	and	securities	issuances	by	Entergy	Mississippi	are	limited	to	amounts	authorized	by	the	SEC.	The	current	short-term	borrowing	limitation,	including borrowings	under	the	money	pool,	is	$160	million.	Under	its	SEC	Orders	and	without	further	SEC	authorization,	Entergy	Mississippi	cannot	incur	additional indebtedness	or	issue	other	securities	unless	(a)	it	and	Entergy	Corporation	maintain	a	common	equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool borrowings,	the	security	to	be	issued	(if	rated)	and	all	outstanding	securities	of	Entergy	Mississippi,	as	well	as	all	outstanding	securities	of	Entergy	Corporation,	that are	rated,	are	rated	investment	grade.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	Entergy Mississippi's	short-term	borrowing	limits.

The	MPSC	has	recommended	not	pursuing	open	access	at	this	time.	At	FERC,	the	pace	of	restructuring	at	the	wholesale	level	has	begun	but	has	been	delayed.	It	is too	early	to	predict	the	ultimate	effects	of	changes	in	U.S.	energy	markets.	Restructuring	issues	are	complex	and	are	continually	affected	by	events	at	the	national, regional,	state,	and	local	levels.	However,	these	changes	may	result,	in	the	long-term,	in	fundamental	changes	in	the	way	traditional	integrated	utilities	and	holding company	systems,	like	the	Entergy	system,	conduct	their	business.	Some	of	these	changes	may	be	positive	for	Entergy,	while	others	may	not	be.

# State	and	Local	Rate	Regulation

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

As	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	Entergy	Mississippi	made	its	annual	formula	rate	plan	filing	with the	MPSC	in	March	2004	based	on	a	2003	test	year.	In	April	2004,	the	MPSC	approved	a	joint	stipulation	entered	into	between	the	Mississippi	Public	Utilities	Staff and	Entergy	Mississippi	that	provides	for	no	change	in	rates	based	on	an	adjusted	return	on	common	equity	mid-point	of	10.77%,	establishing	an	allowed	annual regulatory	earnings	range	of	9.3%	to	12.2%.

In	December	2002,	the	MPSC	issued	a	final	order	approving	a	joint	stipulation	entered	into	by	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	in October	2002.	The	final	order	resulted	in	a	$48.2	million	rate	increase	effective	January	2003.

Entergy	Mississippi's	fuel	costs	recovered	from	customers	are	subject	to	regulatory	scrutiny.	Entergy	Mississippi's	retail	rate	matters	and	proceedings,	including	fuel cost	recovery-related	issues	are	discussed	more	thoroughly	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

In	February	2004,	a	FERC	ALJ	issued	an	Initial	Decision	in	the	LPSC-initiated	proceeding	at	the	FERC.	The	Initial	Decision	decided	some	issues	in	favor	of	the relief	sought	by	the	LPSC,	and	decided	some	issues	against	the	relief	sought	by	the	LPSC.	Several	parties,	including	Entergy,	the	LPSC,	the	APSC,	the	MPSC,	the City	Council,	and	the	FERC	Staff,	filed	briefs	on	exceptions	in	response	to	the	ALJ's	Initial	Decision.	Entergy's	exceptions	to	the	ALJ's	Initial	Decision	include:	the

practical	effect	of	the	Initial	Decision	is	full	production	cost	equalization,	which	was	rejected	in	the	Initial	Decision	and	previously	has	been	rejected	by	the	FERC; resource	planning	for	the	Entergy	System	would	be	impeded	if	the	Initial	Decision	were	adopted;	the	remedy	in	the	Initial	Decision	is	inconsistent	with	the	history, structure,	and	precedent	regarding	the	System	Agreement;	the	Initial	Decision's	remedy	ignores	the	historical	pattern	of	production	cost	disparities	on	the	Entergy System	and	would	result	in	substantial,	sudden	transfers	of	costs	between	groups	of	Entergy	customers;	the	numerical	standards	proposed	in	the	Initial	Decision	are arbitrary	and	are	so	complex	that	they	will	be	difficult	to	implement;	the	Initial	Decision	improperly	rejected	Entergy's	resource	planning	remedy;	the	Initial Decision	erroneously	determined	that	the	full	costs	of	the	Vidalia	project	should	be	included	in	Entergy	Louisiana's	production	costs	for	purposes	of	calculating relative	production	costs;	and	the	Initial	Decision	erroneously	adopted	a	new	method	of	calculating	reserve	sharing	costs	rather	than	the	current	method.

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

Entergy	also	proposed	to	have	the	ICT	administer	a	transmission	expansion	pricing	protocol	that	will	increase	the	efficiency	of	transmission	pricing	on	the	Entergy system	and	that	will	be	designed	to	protect	Entergy's	native	load	customers	from	bearing	the	cost	of	transmission	upgrades	not	required	to	reliably	serve	these customers'	needs.	Entergy	intends	for	the	ICT	to	determine	whether	transmission	upgrades	associated	with	new	requests	for	service	should	be	funded	directly	by	the

party	requesting	such	service	or	by	a	broader	group	of	transmission	customers,	including	Entergy's	native	load	customers.	This	determination	would	be	made	in accordance	with	protocols	approved	by	the	FERC,	and	any	party	contesting	such	determination,	including	Entergy,	would	be	required	to	seek	review	at	the	FERC. Several	technical	conferences	regarding	the	ICT	proposal,	or	various	components	thereof,	were	held	in	2004.	Entergy	has	also	responded	to	discovery	requests	that resulted	from	these	conferences.

The	domestic	utility	companies	(except	Entergy	New	Orleans)	are	currently	defendants	to	several	complaints	and	rehearing	requests	before	the	FERC	in	which independent	generation	entities	(GenCos)	are	seeking	a	refund	of	monies	that	the	GenCos	had	previously	paid	to	the	Entergy	companies	for	facilities	necessary	to connect	their	generation	facilities	to	Entergy's	transmission	system.	The	FERC	has	issued	initial	orders	in	response	to	two	of	the	complaints	and	in	certain	other dockets	ordering	Entergy	to	refund	approximately	$100	million	in	expenses	and	tax	obligations	previously	paid	by	the	GenCos,	including	$27	million	for	Entergy Mississippi.	The	refunds	will	be	in	the	form	of	transmission	credits	that	will	be	utilized	over	time	as	the	GenCos	take	transmission	service	from	Entergy.	To	the extent	the	Entergy	companies	are	ordered	to	provide	such	refunds,	these	costs	will	qualify	for	inclusion	in	the	Entergy	companies'	rates.	The	recovery	of	these	costs is	not	automatic,	however,	especially	at	the	retail	level,	where	the	majority	of	the	cost	recovery	would	occur.	Entergy	intends	to	pursue	all	regulatory	and	legal avenues	available	to	it	in	order	to	have	these	orders	reversed	and	have	the	affected	interconnection	agreements	reinstated	as	agreed	to	originally	by	the	generators.

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

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

Entergy	 sponsors	 defined	 benefit	 pension	 plans	 which	 cover	 substantially	 all	 employees.	Additionally,	 Entergy	 provides	 postretirement	 health	 care	 and	 life insurance	benefits	for	substantially	all	employees	who	reach	retirement	age	while	still	working	for	Entergy.	Entergy's	reported	costs	of	providing	these	benefits,	as described	in	Note	10	to	the	domestic	utility	companies	and	System	Energy	financial	statements,	are	impacted	by	numerous	factors	including	the	provisions	of	the plans,	 changing	 employee	 demographics,	 and	 various	 actuarial	 calculations,	 assumptions,	 and	 accounting	 mechanisms.	Because	 of	 the	 complexity	 of	 these

calculations,	the	long-term	nature	of	these	obligations,	and	the	importance	of	the	assumptions	utilized,	Entergy's	estimate	of	these	costs	is	a	critical	accounting estimate.

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) |  |
| Discount\trate | (0.25%) | $598 | $6,213 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $420 | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $271 | $1,463 |

|  | Change	in | Impact	on	2004 | Postretirement	Benefit |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Postretirement\tBenefit\tCost | Obligation |
|  | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) |  |
| Health\tcare\tcost\ttrend | 0.25% | $174 | $1,161 |
| Discount\trate | (0.25%) | $110 | $1,519 |

Total	pension	cost	for	Entergy	Mississippi	in	2004	was	$2.1	million.	Entergy	anticipates	2005	pension	cost	to	increase	to	$4.4	million	due	to	decrease	in	the discount	rate	(from	6.25%	to	6.00%)	and	the	expected	rate	of	return	(from	8.75%	to	8.5%)	used	to	calculate	benefit	obligations.	Entergy	Mississippi	contributed	$1.8 million	to	its	pension	plan	in	2004,	and	anticipates	making	$3.4	million	in	contributions	in	2005.	The	rise	in	pension	funding	requirements	is	due	to	declining interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to	2002,	partially	offset	by	the	Pension	Funding	Equity	Act	relief	passed	in	April	2004.

Entergy	Mississippi's	accumulated	benefit	obligation	at	December	31,	2004,	2003,	and	2002	exceeded	plan	assets.	As	a	result,	Entergy	Mississippi	was	required	to recognize	an	additional	minimum	liability	as	prescribed	by	SFAS	87.	At	December	31,	2004,	Entergy	Mississippi	increased	its	additional	minimum	liability	to $23.5	million	from	$7.3	million	at	December	31,	2003.	Entergy	Mississippi	increased	its	intangible	asset	for	the	unrecognized	prior	service	cost	to	$3.3	million	at December	31,	2004	from	$0.9	million	at	December	31,	2003.	Entergy	Mississippi	also	increased	the	regulatory	asset	to	$20.2	million	at	December	31,	2004	from $6.4	million	at	December	31,	2003.	Net	income	for	2004,	2003,	and	2002	was	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Mississippi	in	2004	were	$3.8	million,	including	$1.7	million	in	savings	due	to	the estimated	effect	of	future	Medicare	Part	D	subsidies.	Entergy	Mississippi	expects	2005	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate $4.2	million,	including	$1.9	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.	The	increase	in	postretirement	health	care	and	life insurance	benefit	costs	is	due	to	the	decrease	in	the	discount	rate	(from	6.25%	to	6.00%)	and	an	increase	in	the	health	care	cost	trend	rate	used	to	calculate	benefit obligations.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Mississippi,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	income,	retained earnings,	and	cash	flows	(pages	240	through	244	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period	ended	December	31,	2004. These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	based	on our	audits.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Mississippi,	Inc.	as	of	December	31,	2004	and	2003, and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

| OPERATING	REVENUES |  |  |  |
| :--- | :--- | :--- | :--- |
| Domestic\telectric | \t $1,213,629\t\t $1,035,360\t\t $991,095 | \t $1,213,629\t\t $1,035,360\t\t $991,095 | \t $1,213,629\t\t $1,035,360\t\t $991,095 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 335,271 | 155,168 | 318,350 |
| \t\tPurchased\tpower | 436,013 | 449,971 | 315,963 |
| \t\tOther\toperation\tand\tmaintenance | 178,007 | 174,192 | 170,052 |
| Taxes\tother\tthan\tincome\ttaxes | 53,443 | 47,734 | 47,993 |
| Depreciation\tand\tamortization | 65,452 | 62,984 | 55,409 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (1,171) | 3,664 | (23,438) |
| TOTAL | 1,067,015 | 893,713 | 884,329 |
| OPERATING\tINCOME | 146,614 | 141,647 | 106,766 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 4,402 | 4,576 | 3,844 |
| Interest\tand\tdividend\tincome | 2,550 | 1,030 | 4,213 |
| Miscellaneous\t-\tnet | (1,508) | (2,242) | (2,572) |
| TOTAL | 5,444 | 3,364 | 5,485 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 41,681 | 43,879 | 42,580 |
| Other\tinterest\t-\tnet | 2,956 | 3,585 | 2,884 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (3,116) | (3,942) | (3,467) |
| TOTAL | 41,521 | 43,522 | 41,997 |
| INCOME\tBEFORE\tINCOME\tTAXES | 110,537 | 101,489 | 70,254 |
| Income\ttaxes | 37,040 | 34,431 | 17,846 |
| NET\tINCOME | 73,497 | 67,058 | 52,408 |
| Preferred\tdividend\trequirements\tand\tother | 3,369 | 3,369 | 3,369 |
| EARNINGS\tAPPLICABLE\tTO\nCOMMON\tSTOCK | $70,128 | $63,689 | $49,039 |

| Accumulated	deferred	income	taxes | 27,924 | - |
| :--- | :--- | :--- |
| Fuel\tinventory\t-\tat\taverage\tcost | 4,137 | 5,077 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 18,414 | 17,682 |
| Prepayments\tand\tother | 15,413 | 9,583 |
| TOTAL | 283,076 | 314,662 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 5,531 | 5,531 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 6,465 | 6,466 |
| TOTAL | 11,996 | 11,997 |
| UTILITY\tPLANT |  |  |
| Electric | 2,385,465 | 2,243,852 |
| Property\tunder\tcapital\tlease | 95 | 136 |
| Construction\twork\tin\tprogress | 89,921 | 108,829 |
| TOTAL\tUTILITY\tPLANT | 2,475,481 | 2,352,817 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 870,188 | 837,492 |
| UTILITY\tPLANT\t-\tNET | 1,605,293 | 1,515,325 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 17,628 | 28,964 |
| \t\tOther\tregulatory\tassets | 82,674 | 58,287 |
| Long-term\treceivable | 4,510 | - |
| Other | 31,009 | 23,117 |
| TOTAL | 135,821 | 110,368 |

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $\t- | $75,000 |
| Accounts\tpayable: |  |  |
| \t\tAssociated\tcompanies | 65,806 | 62,705 |
| \t\tOther | 25,543 | 28,212 |
| Customer\tdeposits | 37,333 | 33,861 |
| Taxes\taccrued | 40,106 | 39,041 |
| Accumulated\tdeferred\tincome\ttaxes | - | 7,120 |
| Interest\taccrued | 12,487 | 13,772 |
| Deferred\tfuel\tcosts | 22,793 | - |
| Obligations\tunder\tcapital\tleases | 43 | 41 |
| Other | 8,341 | 2,567 |
| TOTAL | 212,452 | 262,319 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 438,321 | 385,395 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 13,687 | 15,092 |
| Obligations\tunder\tcapital\tleases | 52 | 95 |
| Accumulated\tprovisions | 12,718 | 9,929 |
| Long-term\tdebt | 695,073 | 654,956 |
| Other | 76,071 | 60,082 |
| TOTAL | 1,235,922 | 1,125,549 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDERS'\tEQUITY |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 50,381 | 50,381 |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t15,000,000 |  |  |
| \tshares;\tissued\tand\toutstanding\t8,666,357\tshares\tin\t2004\tand\t2003 | 199,326 | 199,326 |
| Capital\tstock\texpense\tand\tother | (59) | (59) |
| Retained\tearnings | 338,164 | 314,836 |
| TOTAL | 587,812 | 564,484 |

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Retained\tEarnings,\tJanuary\t1 | $314,836 | $282,847 | $261,108 |
| \t\tAdd:\n\t\t\t\tNet\tincome | 73,497 | 67,058 | 52,408 |
| \t\tDeduct: |  |  |  |
| \t\t\t\tDividends\tdeclared: |  |  |  |
| \t\t\t\t\t\tPreferred\tstock | 3,369 | 3,369 | 3,369 |
| \t\t\t\t\t\tCommon\tstock | 46,800 | 31,700 | 27,300 |
| \t\t\t\t\t\t\t\tTotal | 50,169 | 35,069 | 30,669 |
| Retained\tEarnings,\tDecember\t31 | $338,164 | $314,836 | $282,847 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,213,629 | $1,035,360 | $991,095 | $1,093,741 | $937,371 |
| Net\tIncome | $73,497 | $67,058 | $52,408 | $39,620 | $38,973 |
| Total\tassets | $2,036,186 | $1,952,352 | $1,832,372 | $1,683,026 | $1,683,939 |
| Long-term\tobligations\t(1) | $695,125 | $655,051 | $510,240 | $589,937 | $584,678 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $467 | $410 | $375 | $391 | $341 |
| \t\tCommercial | 397 | 342 | 310 | 328 | 275 |
| \t\tIndustrial | 204 | 174 | 165 | 191 | 161 |
| \t\tGovernmental | 38 | 32 | 29 | 31 | 26 |
| \t\t\t\tTotal\tretail | 1,106 | 958 | 879 | 941 | 803 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 39 | 21 | 63 | 111 | 83 |
| \t\t\t\tNon-associated\tcompanies | 30 | 21 | 15 | 21 | 27 |
| \t\tOther | 39 | 35 | 34 | 22 | 25 |
| \t\t\t\tTotal | $1,214 | $1,035 | $991 | $1,095 | $938 |
| Billed\tElectric\tEnergy\tSales |  |  |  |  |  |
| (GWh): |  |  |  |  |  |
| \t\tResidential | 5,085 | 5,092 | 5,092 | 4,867 | 4,976 |
| \t\tCommercial | 4,518 | 4,476 | 4,445 | 4,322 | 4,307 |
| \t\tIndustrial | 2,977 | 2,939 | 2,910 | 3,051 | 3,188 |
| \t\tGovernmental | 398 | 384 | 382 | 381 | 376 |
| \t\t\t\tTotal\tretail | 12,978 | 12,891 | 12,829 | 12,621 | 12,847 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 305 | 112 | 1,123 | 1,728 | 1,276 |
| \t\t\t\tNon-associated\tcompanies | 393 | 331 | 197 | 289 | 313 |
| \t\t\t\tTotal | 13,676 | 13,334 | 14,149 | 14,638 | 14,436 |

# Net	Income	(Loss)

Net	income	increased	$20.2	million	primarily	due	to	higher	net	revenue.

Entergy	New	Orleans	had	net	income	of	$7.9	million	in	2003	compared	to	a	net	loss	in	2002.	The	increase	was	due	to	higher	net	revenue	and	lower	interest	expense, partially	offset	by	higher	other	operation	and	maintenance	expenses	and	depreciation	and	amortization	expenses.

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

|  | (In	Millions) |
| :--- | :--- |
| 2003\tnet\trevenue | $208.3 |
| Base\trates | 10.6 |
| Volume/weather | 8.3 |
| 2004\tdeferrals | 7.5 |
| Price\tapplied\tto\tunbilled\telectric | 3.7 |
| sales |  |
| Other | 0.6 |
| 2004\tnet\trevenue | $239.0 |

The	 increase in	base	rates	was	effective	June	2003.	The	rate	increase	is	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial statements.

The	volume/weather	variance	is	primarily	due	to	increased	billed	electric	usage	of	162	GWh	in	the	industrial	service	sector.	The	increase	was	partially	offset	by milder	weather	in	the	residential	and	commercial	sectors.

The	2004	deferrals	variance	is	due	to	the	deferral	of	voluntary	severance	plan	and	fossil	plant	maintenance	expenses	in	accordance	with	a	stipulation	approved	by the	City	Council	in	August	2004.	The	stipulation	allows	for	the	recovery	of	these	costs	through	amortization	of	a	regulatory	asset.	The	voluntary	severance	plan	and fossil	plant	maintenance	expenses	are	being	amortized	over	a	five-year	period	that	became	effective	January	2004	and	January	2003,	respectively.	The	formula	rate plan	is	discussed	in	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

The	price	applied	to	unbilled	electric	sales	variance	is	due	to	an	increase	in	the	fuel	price	applied	to	unbilled	sales.

Gross	operating	revenues	increased	primarily	due	to	an	increase	in	gross	wholesale	revenue	as	a	result	of	an	increase	of	$32.4	million	in	sales	to	affiliates	and	an increase	of	$28.7	million	in	fuel	revenues	due	to	higher	fuel	rates,	in	addition	to	the	net	revenue	items	mentioned	above.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	an	increase	in	electricity	generated	and	power	purchased	coupled	with	an	increase	in	the	market prices	of	natural	gas	and	purchased	power.

Other	regulatory	credits	increased	primarily	due	to	a	stipulation	approved	by	the	City	Council	in	August	2004,	as	discussed	above.

|  | (In	Millions) |
| :--- | :--- |
| 2002\tnet\trevenue | $183.7 |
| Base\trates | 15.9 |
| Rate\trefund\tprovisions | 9.1 |
| Other | (0.4) |
| 2003\tnet\trevenue | $208.3 |

Rate	refund	provisions	increased	net	revenue	due	to	larger	accruals	for	potential	rate	actions	and	refunds	in	2002.

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$78.4	million	in	sales	to	affiliates.	The	increase	was	also	attributable	to	a	base	rate	increase	and an	increase	in	the	market	price	of	natural	gas.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	an	increase	in	the	market	price	of	natural	gas.

Other	operation	and	maintenance	expenses	decreased	slightly	primarily	due	to	the	$4.7	million	voluntary	severance	program	accruals	in	2003.	The	decrease	was offset	by	increases	in	customer	service	support	costs	and	maintenance	and	outage	costs	at	fossil	plants.

The	increase	in	miscellaneous	income	is	primarily	due	to	an	asbestos	insurance	settlement	in	April	2004.

Interest	on	long-term	debt	decreased	primarily	due	to	long-term	debt	refinancing	in	the	third	quarter	of	2003.

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	fossil	plant	maintenance	outage	costs.

Depreciation	and	amortization	expenses	increased	due	to	an	increase	in	plant	in	service.

Miscellaneous	income	decreased	primarily	due	to	a	gain	on	the	sale	of	property	at	a	non-operating	plant	site	in	2002.

Other	interest	decreased	primarily	due	to	interest	accrued	in	2002	for	potential	rate	actions	and	refunds	and	a	true-up	of	those	accruals	in	May	2003.

The	effective	income	tax	rates	for	2004,	2003,	and	2002	were	37.5%,	42.8%,	and	64.7%,	respectively.	See	Note	3	to	the	domestic	utility	companies	and	System Energy	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rate.		Tax	reserves	not	expected	to	reverse	within	the next	year	are	reflected	as	non-current	taxes	accrued	on	the	balance	sheet.

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $4,669 | $66,247 | $38,184 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 63,577 | 7,194 | 72,143 |
| Investing\tactivities | (49,280) | (64,806) | (41,647) |
| Financing\tactivities | (11,012) | (3,966) | (2,433) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 3,285 | (61,578) | 28,063 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $7,954 | $4,669 | $66,247 |

Cash	flow	from	operations	increased	$56.4	million	in	2004	primarily	due	to	increased	net	income	and	the	timing	of	collections	of	receivables.

Cash	flow	from	operations	decreased	$64.9	million	in	2003	primarily	due	to	decreased	fuel	cost	recoveries	and	the	timing	of	collection	of	receivables	due	to	an increase	in	retail	customer	receivable	days	outstanding.

Entergy	New	Orleans'	receivables	from	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years:

| 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $1,413 | $1,783 | $3,500 | $9,208 |

Money	pool	activity	provided	$0.4	million	of	Entergy	New	Orleans'	operating	cash	flow	in	2004,	provided	$1.7	million	in	2003,	and	provided	$5.7	million	in	2002. See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

Net	cash	used	in	investing	activities	decreased	$15.5	million	in	2004	primarily	due	to	capital	expenditures	related	to	a	turbine	inspection	project	at	a	fossil	plant	in 2003	and	decreased	customer	service	spending.

Net	cash	used	in	investing	activities	increased	$23.2	million	in	2003	compared	to	2002	primarily	due	to	the	maturity	of	$14.9	million	of	other	temporary	investments in	2002	and	increased	construction	expenditures	due	to	increased	customer	service	spending.

Net	cash	used	in	financing	activities	increased	$7.0	million	in	2004	primarily	due	to	the	costs	and	expenses	related	to	refinancing	$75	million	of	long-term	debt	in 2004	and	an	increase	of	$2.2	million	in	common	stock	dividends	paid.

Net	cash	used	in	financing	activities	increased	$1.5	million	in	2003	primarily	due	to	additional	common	stock	dividends	paid	of	$2.2	million.

In	July	2003,	Entergy	New	Orleans	issued	$30	million	of	3.875%	Series	First	Mortgage	Bonds	due	August	2008	and	$70	million	of	5.25%	Series	First	Mortgage Bonds	due	August	2013.	The	proceeds	from	these	issuances	were	used	to	redeem,	prior	to	maturity,	$30	million	of	7%	Series	First	Mortgage	Bonds	due	July	2008, $40	million	of	8%	Series	bonds	due	March	2006,	and	$30	million	of	6.65%	Series	First	Mortgage	Bonds	due	March	2004.	The	issuances	and	redemptions	are	not shown	on	the	cash	flow	statement	because	the	proceeds	from	the	issuances	were	placed	in	a	trust	for	use	in	the	redemptions	and	never	held	as	cash	by	Entergy	New Orleans.

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:

|  | 2005 | 2006-2007 | 2008-2009 | After	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| capital\tinvestment\t(1) | $47 | $96 | N/A | N/A | $143 |
| Long-term\tdebt | $30 | $- | $30 | $170 | $230 |
| Purchase\tobligations\t(2) | $182 | $346 | $200 | $1,215 | $1,943 |

(1) Consists	 almost	 entirely	 of	 maintenance	 capital,	 which	 is	 planned	 spending	 on	 routine	 capital projects	that	are	necessary	to	support	reliability	of	service,	equipment	or	systems	and	to	support normal	customer	growth.

(2) Purchase	 obligations	 represent	 the	 minimum	 purchase	 obligation	 or	 cancellation	 charge	 for contractual	obligations	to	purchase	goods	or	services.	For	Entergy	New	Orleans	almost	all	of	the	total consists	of	unconditional	fuel	and	purchased	power	obligations,	including	its	obligations	under	the Unit	Power	Sales	Agreement,	which	is	discussed	in	Note	8	to	the	domestic	utility	companies	and System	Energy	financial	statements.

In	addition	to	these	contractual	obligations,	Entergy	New	Orleans	expects	to	contribute	$15.7	million	to	its	pension	plans	and	$4.4	million	to	other	postretirement plans	in	2005.

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

As	a	wholly-owned	subsidiary,	Entergy	New	Orleans	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.	In	addition,	all	of	Entergy New	Orleans'	retained	earnings	are	currently	available	for	distribution.

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

Entergy	New	Orleans	issued	$75	million	of	First	Mortgage	Bonds	in	2004	as	follows:

| Issue	Date | Description | Maturity | Amount |
| :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |
| August\t2004 | 5.60%\tSeries | September\t2024 | $35,000 |
| August\t2004 | 5.65%\tSeries | September\t2029 | 40,000 |

Proceeds	from	the	issuances	in	August	2004	were	used	to	retire	or	redeem	the	following	First	Mortgage	Bonds:

In	July	2004,	Entergy	New	Orleans	entered	into	a	credit	facility	and	Entergy	Louisiana	renewed	its	credit	facility	with	the	same	lender.	Both	facilities	will	expire	in April	2005.	Entergy	New	Orleans	can	borrow	up	to	$14	million	and	Entergy	Louisiana	can	borrow	up	to	$15	million	under	their	respective	credit	facilities,	but	at	no time	can	the	total	amount	borrowed	by	the	two	companies	combined	exceed	$15	million.	As	of	December	31,	2004,	no	borrowings	were	outstanding	under	the facilities.

Entergy	New	Orleans	may	refinance	or	redeem	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are favorable.

All	debt	and	common	and	preferred	stock	issuances	by	Entergy	New	Orleans	require	prior	regulatory	approval.	Preferred	stock	and	debt	issuances	are	also	subject	to issuance	tests	set	forth	in	corporate	charters,	bond	indentures,	and	other	agreements.	Entergy	New	Orleans	has	sufficient	capacity	under	these	tests	to	meet	its foreseeable	capital	needs.

Short-term	borrowings	by	Entergy	New	Orleans,	including	borrowings	under	the	money	pool,	are	limited	to	an	amount	authorized	by	the	SEC,	$100	million.	Under restrictions	contained	in	its	articles	of	incorporation,	Entergy	New	Orleans	could	incur	approximately	$40	million	of	new	unsecured	debt	as	of	December	31,	2004. Under	its	SEC	Order	and	without	further	SEC	authorization,	Entergy	New	Orleans	cannot	incur	additional	short-term	indebtedness	unless	(a)	it	and	Entergy Corporation	maintain	a	common	equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool	borrowings,	the	security	to	be	issued	(if	rated)	and	all outstanding	securities	of	Entergy	New	Orleans	(other	than	preferred	stock),	as	well	as	all	outstanding	securities	of	Entergy	Corporation,	that	are	rated,	are	rated investment	grade.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	Entergy	New	Orleans'	short-term borrowing	limits.

The	rates	that	Entergy	New	Orleans	charges	for	electricity	and	natural	gas	significantly	influence	its	financial	position,	results	of	operations,	and	liquidity.	Entergy New	Orleans	is	closely	regulated	and	the	rates	charged	to	its	customers	are	determined	in	regulatory	proceedings.	A	governmental	agency,	the	City	Council,	is primarily	responsible	for	approval	of	the	rates	charged	to	customers.

In	May	2003,	the	City	Council	approved	a	resolution	allowing	for	a	total	increase	of	$30.2	million	in	electric	and	gas	base	rates	effective	June	1,	2003.		In	April 2004,	Entergy	New	Orleans	made	filings	with	the	City	Council	as	required	by	the	earnings	review	process	prescribed	by	the	Gas	and	Electric	Formula	Rate	Plans approved	by	the	City	Council	in	2003.	The	filings	sought	an	increase	in	Entergy	New	Orleans'	electric	revenues	of	$1.2	million	and	an	increase	in	Entergy	New Orleans'	gas	revenues	of	$32,000.	The	Council	Advisors	and	intervenors	reviewed	the	filings,	and	filed	their	recommendations	in	July	2004.	In	August	2004,	in accordance	with	the	City	Council's	requirements	for	the	formula	rate	plans,	Entergy	New	Orleans	made	a	filing	with	the	City	Council	reflecting	the	parties' concurrence	that	no	change	in	Entergy	New	Orleans'	electric	or	gas	rates	is	warranted.	Later	in	August	2004,	the	City	Council	approved	an	unopposed	settlement among	Entergy	New	Orleans,	the	Council	Advisors,	and	the	intervenors	in	connection	with	the	Gas	and	Electric	Formula	Rate	Plans.	In	accordance	with	the resolution	approving	the	settlement	agreement,	Entergy	New	Orleans'	gas	and	electric	base	rates	remain	unchanged	from	levels	set	in	May	2003.	The	resolution ordered	Entergy	New	Orleans	to	defer	$3.9	million	relating	to	voluntary	severance	plan	costs	allocated	to	its	electric	operations	and	$1.0	million	allocated	to	its	gas operations,	which	amounts	were	accrued	on	its	books	in	2003,	and	to	record	on	its	books	regulatory	assets	in	those	amounts	to	be	amortized	over	five	years	effective January	 2004.	Entergy	New	Orleans	also	was	ordered	to	defer	$6.0	million	of	fossil	plant	maintenance	expense	incurred	in	2003	and	to	record	on	its	books	a regulatory	asset	in	that	amount	to	be	amortized	over	a	five-year	period	effective	January	2003.

Entergy	New	Orleans	will	file	its	formula	rate	plan	for	the	year	ended	December	31,	2004	by	May	1,	2005	and	also	intends	to	file	for	an	extension	of	the	formula rate	plan	by	September	1,	2005.	If	the	formula	rate	plan	is	not	extended	by	the	City	Council,	the	rate	adjustments	in	effect	based	on	the	December	31,	2004	test	year shall	continue.

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

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

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.

|  | Range	of	Annual	Payments<br>or	(Receipts)<br>(In	Millions) | Average	Annual<br>Payments	or	(Receipts)<br>for	2005-2009	Period<br>(In	Millions) |
| :--- | :--- | :--- |
| Entergy\tArkansas | $154\tto\t$281 | $215 |
| Entergy\tGulf\tStates | ($130)\tto\t($15) | ($63) |
| Entergy\tLouisiana | ($199)\tto\t($98) | ($141) |

Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	a	FERC	decision	and	related	retail	proceedings	should	result	in	similar rate	changes	for	retail	customers.	Although	the	outcome	and	timing	of	the	FERC,	APSC,	and	other	proceedings	cannot	be	predicted	at	this	time,	Entergy	New Orleans	does	not	believe	that	the	ultimate	resolution	of	these	proceedings	will	have	a	material	effect	on	its	financial	condition	or	results	of	operation.

On	December	17,	2004,	the	FERC	issued	an	order	initiating	a	hearing	and	investigation	concerning	the	justness	and	reasonableness	of	the	Available	Flowgate Capacity	(AFC)	methodology,	 the	methodology	used	 to	 evaluate	 short-term	 transmission	 service	 requests	 under	 the	 domestic	 utility	 companies'	 open	 access transmission	tariff,	and	establishing	a	refund	effective	date.	In	its	order,	the	FERC	indicated	that	although	it	"appreciates	that	Entergy	is	attempting	to	explore	ways to	improve	transmission	access	on	its	system,"	it	believed	that	an	investigation	was	warranted	to	gather	more	evidence	in	light	of	the	concerns	raised	by	certain transmission	customers	and	certain	issues	raised	in	a	FERC	audit	report	finding	errors	and	problems	with	the	predecessor	methodology	used	by	Entergy	for evaluating	 short-term	 transmission	 requests,	 the	 Generator	 Operating	 Limits	 methodology.	The	 FERC	 order	 indicates	 that	 the	 investigation	 will	 include	 an examination	of	(i)	Entergy's	implementation	of	the	AFC	program,	(ii)	whether	Entergy's	implementation	has	complied	with	prior	FERC	orders	and	open	access transmission	tariff	provisions	addressing	the	AFC	program,	and	(iii)	whether	Entergy's	provision	of	access	to	short-term	transmission	on	its	transmission	system	was

# just,	reasonable,	and	not	unduly	discriminatory.

Entergy	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.

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	 apply appropriate	accounting	policies	and	to	make	estimates	and	judgments	that	can	have	a	significant	effect	on	reported	financial	position,	results	of	operations,	and	cash flows.	Management	has	identified	the	following	accounting	policies	and	estimates	as	critical	because	they	are	based	on	assumptions	and	measurements	that	involve a	high	degree	of	uncertainty,	and	there	is	the	potential	for	future	changes	in	the	assumptions	and	measurements	could	produce	estimates	that	would	have	a	material impact	on	the	presentation	of	Entergy	New	Orleans'	financial	position	or	results	of	operations.

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

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

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tIncrease/(Decrease) |  |
| Discount\trate | (0.25%) | $227 | $2,694 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $73 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $113 | $718 |

Total	pension	cost	for	Entergy	New	Orleans	in	2004	was	$4.6	million.	Entergy	New	Orleans	anticipates	2005	pension	cost	to	decrease	to	$4.2	million.	Entergy	New Orleans	contributed	$2.1	million	to	its	pension	plan	in	2004,	and	anticipates	making	$15.7	million	in	contributions	in	2005.	The	rise	in	pension	funding	requirements is	due	to	declining	interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to	2002,	partially	offset	by	the	Pension	Funding	Equity	Act	relief passed	in	April	2004.

Entergy	New	Orleans'	accumulated	benefit	obligation	at	December	31,	2004,	2003	and	2002	exceeded	plan	assets.	As	a	result,	Entergy	New	Orleans	was	required	to recognize	an	additional	minimum	liability	as	prescribed	by	SFAS	87.	At	December	31,	2004	Entergy	New	Orleans	increased	its	additional	minimum	liability	to $16.9	million	from	$13.1	million	at	December	31,	2003.	Entergy	New	Orleans	decreased	its	intangible	asset	for	the	unrecognized	prior	service	cost	to	$1.7	million at	December	31,	2004	from	$2.8	million	at	December	31,	2003.	Entergy	New	Orleans	increased	the	regulatory	asset	to	$15.2	million	at	December	31,	2004	from $10.3	million	at	December	31,	2003.	Net	income	for	2004,	2003,	and	2002	were	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	New	Orleans	in	2004	were	$4.3	million,	including	$1.3	million	in	savings	due	to	the estimated	effect	of	future	Medicare	Part	D	subsidies.	Entergy	New	Orleans	expects	2005	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate $4.2	million,	including	$1.4	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	New	Orleans,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	operations, retained	earnings,	and	cash	flows	(pages	261	through	266	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period	ended	December 31,	2004.	These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements based	on	our	audits.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	New	Orleans,	Inc.	as	of	December	31,	2004	and 2003,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

STATEMENTS	OF	OPERATIONS

OPERATING	REVENUES

| Domestic	electric | $588,457 | $527,660 | $424,527 |
| :--- | :--- | :--- | :--- |
| Natural\tgas | 147,411 | 126,356 | 83,347 |
| TOTAL | 735,868 | 654,016 | 507,874 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 245,301 | 214,735 | 163,323 |
| \t\tPurchased\tpower | 256,190 | 231,787 | 158,191 |
| \t\tOther\toperation\tand\tmaintenance | 107,874 | 108,217 | 98,511 |
| Taxes\tother\tthan\tincome\ttaxes | 43,577 | 42,198 | 40,099 |
| Depreciation\tand\tamortization | 29,657 | 30,004 | 27,699 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (4,670) | (843) | 2,701 |
| TOTAL | 677,929 | 626,098 | 490,524 |
| OPERATING\tINCOME | 57,939 | 27,918 | 17,350 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 1,378 | 2,085 | 1,835 |
| Interest\tand\tdividend\tincome | 720 | 825 | 689 |
| Miscellaneous\t-\tnet | 270 | (1,453) | 584 |
| TOTAL | 2,368 | 1,457 | 3,108 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 15,357 | 17,436 | 18,011 |
| Other\tinterest\t-\tnet | 1,253 | 350 | 4,939 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (1,243) | (2,145) | (1,840) |
| TOTAL | 15,367 | 15,641 | 21,110 |
| INCOME\t(LOSS)\tBEFORE\tINCOME\tTAXES | 44,940 | 13,734 | (652) |
| Income\ttaxes | 16,868 | 5,875 | (422) |
| NET\tINCOME\t(LOSS) | 28,072 | 7,859 | (230) |
| Preferred\tdividend\trequirements\tand\tother | 965 | 965 | 965 |
| EARNINGS\t(LOSS)\tAPPLICABLE\tTO\nCOMMON\tSTOCK | $27,107 | $6,894 | ($1,195) |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome\t(loss) | $28,072 | $7,859 | ($230) |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby |  |  |  |
| operating\tactivities: |  |  |  |
| \t\tOther\tregulatory\tcharges\t(credits)\t-\tnet | (4,670) | (843) | 2,701 |
| \t\tDepreciation\tand\tamortization | 29,657 | 30,004 | 27,699 |
| \t\tDeferred\tincome\ttaxes\tand\tinvestment\ttax\tcredits | 39,782 | 15,401 | 6,729 |
| \t\tChanges\tin\tworking\tcapital: |  |  |  |
| \t\t\t\tReceivables | 9,162 | (41,308) | 10,540 |
| \t\t\t\tFuel\tinventory | 1,399 | (2,296) | (203) |
| \t\t\t\tAccounts\tpayable | (3,014) | 17,817 | 18,070 |
| \t\t\t\tTaxes\taccrued | (13,056) | 1,372 | 5,603 |
| \t\t\t\tInterest\taccrued | (1,455) | (276) | (544) |
| \t\t\t\tDeferred\tfuel\tcosts | (5,279) | (12,162) | 4,686 |
| \t\t\t\tOther\tworking\tcapital\taccounts | 2,121 | (7,553) | (4,971) |
| \t\tProvision\tfor\testimated\tlosses\tand\treserves | (1,305) | (1,634) | (3,348) |
| \t\tChanges\tin\tother\tregulatory\tassets | (5,380) | (9,473) | (3,061) |
| \t\tOther | (12,457) | 10,286 | 8,472 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 63,577 | 7,194 | 72,143 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (51,264) | (66,285) | (58,341) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 1,378 | 2,085 | 1,835 |
| Changes\tin\tother\ttemporary\tinvestments\t-\tnet | 606 | (606) | 14,859 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (49,280) | (64,806) | (41,647) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 72,640 | - | 24,332 |
| Retirement\tof\tlong-term\tdebt | (77,487) | - | (25,000) |
| Dividends\tpaid: |  |  |  |
| \t\tCommon\tstock | (5,200) | (3,001) | (800) |
| \t\tPreferred\tstock | (965) | (965) | (965) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | (11,012) | (3,966) | (2,433) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 3,285 | (61,578) | 28,063 |

| Cash	and	cash	equivalents	at	beginning	of	period | 4,669 | 66,247 | 38,184 |
| :--- | :--- | :--- | :--- |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $7,954 | $4,669 | $66,247 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid/(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| \t\tInterest\t-\tnet\tof\tamount\tcapitalized | $16,172 | $17,427 | $19,961 |
| \t\tIncome\ttaxes | ($5,736) | ($13,530) | ($37,929) |

| Cash | $2,998 | $28 |
| :--- | :--- | :--- |
| \t\tTemporary\tcash\tinvestments\t-\tat\tcost, |  |  |
| \t\t\twhich\tapproximates\tmarket | 4,956 | 4,641 |
| \t\t\t\t\tTotal\tcash\tand\tcash\tequivalents | 7,954 | 4,669 |
| Other\ttemporary\tinvestments | - | 606 |
| Accounts\treceivable: |  |  |
| \t\tCustomer | 47,356 | 44,663 |
| \t\tAllowance\tfor\tdoubtful\taccounts | (3,492) | (3,104) |
| \t\tAssociated\tcompanies | 12,223 | 24,697 |
| \t\tOther | 7,329 | 10,057 |
| \t\tAccrued\tunbilled\trevenues | 24,848 | 21,113 |
| \t\t\t\t\tTotal\taccounts\treceivable | 88,264 | 97,426 |
| Deferred\tfuel | 2,559 | - |
| Accumulated\tdeferred\tincome\ttaxes | - | 460 |
| Fuel\tinventory\t-\tat\taverage\tcost | 4,181 | 5,580 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 9,150 | 8,660 |
| Prepayments\tand\tother | 3,467 | 8,050 |
| TOTAL | 115,575 | 125,451 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 3,259 | 3,259 |
| UTILITY\tPLANT |  |  |
| Electric | 699,072 | 666,122 |
| Natural\tgas | 183,728 | 167,011 |
| Construction\twork\tin\tprogress | 33,273 | 45,061 |
| TOTAL\tUTILITY\tPLANT | 916,073 | 878,194 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 435,519 | 420,745 |
| UTILITY\tPLANT\t-\tNET | 480,554 | 457,449 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tOther\tregulatory\tassets | 40,354 | 27,222 |
| Long\tterm\treceivables | 2,492 | - |
| Other | 20,540 | 16,246 |
| TOTAL | 63,386 | 43,468 |
| TOTAL\tASSETS | $662,774 | $629,627 |

| CURRENT	LIABILITIES |  |  |
| :--- | :--- | :--- |
| Currently\tmaturing\tlong-term\tdebt | $30,000 | $\t- |
| Accounts\tpayable: |  |  |
| \t\tAssociated\tcompanies | 30,563 | 35,008 |
| \t\tOther | 44,149 | 42,718 |
| Customer\tdeposits | 17,187 | 15,575 |
| Taxes\taccrued | 2,592 | - |
| Accumulated\tdeferred\tincome\ttaxes | 1,906 | - |
| Interest\taccrued | 4,757 | 6,212 |
| Deferred\tfuel\tcosts | - | 2,720 |

| Energy	Efficiency	Program	provision | 6,611 | 6,356 |
| :--- | :--- | :--- |
| Other | 3,477 | 2,088 |
| TOTAL | 141,242 | 110,677 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 47,062 | 39,486 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 3,997 | 4,441 |
| SFAS\t109\tregulatory\tliability\t-\tnet | 46,406 | 40,543 |
| Other\tregulatory\tliabilities | - | 954 |
| Accumulated\tprovisions | 9,323 | 10,628 |
| Pension\tliability | 36,845 | 30,585 |
| Long-term\tdebt | 199,902 | 229,217 |
| Other | 3,755 | 10,761 |
| TOTAL | 347,290 | 366,615 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDERS'\tEQUITY |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 19,780 | 19,780 |
| Common\tstock,\t$4\tpar\tvalue,\tauthorized\t10,000,000 |  |  |
| \tshares;\tissued\tand\toutstanding\t8,435,900\tshares\tin\t2004 |  |  |
| \tand\t2003 | 33,744 | 33,744 |
| Paid-in\tcapital | 36,294 | 36,294 |
| Retained\tearnings | 84,424 | 62,517 |
| TOTAL | 174,242 | 152,335 |
| TOTAL\tLIABILITIES\tAND\tSHAREHOLDERS'\tEQUITY | $662,774 | $629,627 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| Retained\tEarnings,\tJanuary\t1 | $62,517 | $58,624 | $60,619 |
| \t\tAdd:\n\t\t\t\tNet\tincome\t(loss) | 28,072 | 7,859 | (230) |
| \t\tDeduct: |  |  |  |
| \t\t\t\tDividends\tdeclared: |  |  |  |
| \t\t\t\tPreferred\tstock | 965 | 965 | 965 |
| \t\t\t\tCommon\tstock | 5,200 | 3,001 | 800 |
| \t\t\t\t\t\tTotal | 6,165 | 3,966 | 1,765 |
| Retained\tEarnings,\tDecember\t31 | $84,424 | $62,517 | $58,624 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $735,868 | $654,016 | $507,874 | $630,850 | $640,290 |
| Net\tIncome\t(loss) | $28,072 | $7,859 | ($230) | ($2,195) | $16,518 |
| Total\tassets | $662,774 | $629,627 | $584,705 | $566,037 | $559,231 |
| Long-term\tobligations\t(1) | $199,902 | $229,217 | $229,191 | $299,097 | $199,031 |

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

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tMillions) | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| \t\tResidential | $184 | $178 | $170 | $190 | $188 |
| \t\tCommercial | 171 | 162 | 154 | 186 | 171 |
| \t\tIndustrial | 34 | 27 | 25 | 32 | 25 |
| \t\tGovernmental | 70 | 68 | 66 | 81 | 73 |
| \t\t\t\tTotal\tretail | 459 | 435 | 415 | 489 | 457 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 118 | 85 | 7 | 10 | 32 |
| \t\t\t\tNon-associated\tcompanies | 2 | 2 | 2 | 3 | 9 |
| \t\tOther | 9 | 6 | 1 | 1 | 17 |
| \t\t\t\tTotal | $588 | $528 | $425 | $503 | $515 |

| Residential | 2,139 | 2,133 | 2,158 | 1,981 | 2,178 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \t\tCommercial | 2,316 | 2,262 | 2,255 | 2,185 | 2,260 |
| \t\tIndustrial | 575 | 413 | 409 | 414 | 384 |
| \t\tGovernmental | 1,025 | 1,036 | 1,053 | 1,017 | 1,058 |
| \t\t\t\tTotal\tretail | 6,055 | 5,844 | 5,875 | 5,597 | 5,880 |
| \t\tSales\tfor\tresale: |  |  |  |  |  |
| \t\t\t\tAssociated\tcompanies | 1,514 | 1,312 | 144 | 115 | 570 |
| \t\t\t\tNon-associated\tcompanies | 25 | 28 | 32 | 59 | 141 |
| \t\t\t\tTotal | 7,594 | 7,184 | 6,051 | 5,771 | 6,591 |

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

Net	income	remained	relatively	unchanged,	decreasing	$0.06	million	in	2004.

Net	income	increased	$2.7	million	in	2003	primarily	due	to	lower	interest	charges	primarily	resulting	from	lower	interest	expense	associated	with	the	Grand	Gulf sale-leaseback.	This	increase	was	partially	offset	by	a	decrease	in	rate	base	in	2003	resulting	in	lower	operating	income.	The	decrease	in	rate	base	was	due	to	the normal	depreciation	of	Grand	Gulf.

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $52,536 | $113,159 | $49,579 |
| Cash\tflow\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 332,928 | 100,817 | 225,639 |
| Investing\tactivities | (45,053) | (45,065) | (28,873) |
| Financing\tactivities | (124,056) | (116,375) | (133,186) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 163,819 | (60,623) | 63,580 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $216,355 | $52,536 | $113,159 |

Cash	flow	from	operations	increased	by	$232.1	million	in	2004	primarily	due	to	income	tax	refunds	of	$70.6	million	in	2004	compared	to	income	tax	payments	of $230.9	million	in	2003.	The	increase	was	partially	offset	by	money	pool	activity,	as	discussed	below.

In	2003,	the	domestic	utility	companies	and	System	Energy	filed,	with	the	IRS,	a	change	in	tax	accounting	method	notification	for	their	respective	calculations	of cost	of	goods	sold.	The	adjustment	implemented	a	simplified	method	of	allocation	of	overhead	to	the	production	of	electricity,	which	is	provided	under	the	IRS capitalization	regulations.	The	cumulative	adjustment	placing	these	companies	on	the	new	methodology	resulted	in	a	$430	million	deduction	for	System	Energy	on Entergy's	2003	income	tax	return.	There	was	no	cash	benefit	from	the	method	change	in	2003.	In	2004	System	Energy	realized	$144	million	in	cash	tax	benefit	from the	method	change.	This	tax	accounting	method	change	is	an	issue	across	the	utility	industry	and	will	likely	be	challenged	by	the	IRS	on	audit.

Cash	flow	from	operations	decreased	by	$124.8	million	in	2003	primarily	due	to	the	following:

an	increase	in	federal	income	taxes	paid	of	$74.0	million	in	2003	compared	to	2002;

the	cessation	of	the	Entergy	Mississippi	GGART.	System	Energy	collected	$21.7	million	in	2003	and	$40.8	million	in	2002	from	Entergy	Mississippi	in conjunction	with	the	GGART,	which	provided	for	the	acceleration	of	Entergy	Mississippi's	Grand	Gulf	purchased	power	obligation.	The	MPSC	authorized cessation	of	the	GGART	effective	July	1,	2003.	See	Note	2	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of the	GGART;	and

money	pool	activity,	as	discussed	below.

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

| 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $61,592 | $19,064 | $7,046 | $13,853 |

Money	pool	activity	used	$42.5	million	of	System	Energy's	operating	cash	flows	in	2004,	used	$12.0	million	in	2003,	and	provided	$6.8	million	in	2002.	See	Note	4 to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	a	description	of	the	money	pool.

Net	cash	used	for	investing	activities	was	practically	unchanged	in	2004	compared	to	2003	primarily	because	an	increase	in	construction	expenditures	caused	by	a reclassification	of	inventory	items	to	capital	was	significantly	offset	by	the	maturity	of	$6.5	million	of	other	temporary	investments	that	had	been	made	in	2003, which	provided	cash	in	2004.

The	increase	of	$16.2	million	in	net	cash	used	in	investing	activities	in	2003	was	primarily	due	to	the	following:

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	increase	of	$7.7	million	in	net	cash	used	in	financing	activities	in	2004	was	primarily	due	to	$5.5	million	in	costs	related	to	System	Energy	refunding	bonds associated	with	its	Grand	Gulf	Lease	Obligation	in	May	2004	and	the	retirement	of	$	7.6	million	of	long-term	debt	2004.	The	increase	was	partially	offset	by	a decrease	of	$5.0	million	in	the	January	2004	principal	payment	made	on	the	Grand	Gulf	sale-leaseback	compared	to	the	January	2003	principal	payment	.

The	decrease	of	$16.8	million	in	net	cash	used	in	financing	activities	in	2003	was	primarily	due	to	a	decrease	of	$19.5	million	in	the	January	2003	principal	payment made	on	the	Grand	Gulf	sale-leaseback	compared	to	the	January	2002	principal	payment.

System	Energy	requires	capital	resources	for:

debt	maturities;

working	capital	purposes,	including	the	financing	of	fuel	costs;	and dividend	and	interest	payments.

Following	 are the	 amounts	 of	 System	 Energy's	 planned	 construction	 and	 other	 capital investments,	 existing	 debt	 and lease	 obligations,	 and	 other	 purchase obligations:

|  | 2005 | 2006-2007 | 2008-2009 | After	2009 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Planned\tconstruction\tand |  |  |  |  |  |
| capital\tinvestment | $38 | $81 | N/A | N/A | $119 |
| Long-term\tdebt | $29 | $125 | $62 | $659 | $875 |
| Nuclear\tfuel\tlease\tobligations\t(1) | $28 | $38 | N/A | N/A | $66 |

System	Energy	expects	to	contribute	$9.3	million	to	pension	plans	and	$1.7	million	to	other	postretirement	plans	in	2005.

The	planned	capital	investment	estimate	for	System	Energy	reflects	capital	required	to	support	the	existing	business	of	System	Energy.	Management	provides	more information	on	long-term	debt	and	preferred	stock	maturities	in	Notes	5	and	6	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

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

System	Energy's	sources	to	meet	its	capital	requirements	include:

debt	issuances;	and

System	Energy	had	three-year	letters	of	credit	in	place	that	were	scheduled	to	expire	in	March	2003	securing	certain	of	its	obligations	related	to	the	sale-leaseback	of a	portion	of	Grand	Gulf.	System	Energy	replaced	the	letters	of	credit	before	their	expiration	with	new	three-year	letters	of	credit	totaling	approximately	$198	million that	were	backed	by	cash	collateral.	In	December	2003,	System	Energy	replaced	the	cash-backed	letters	of	credit	with	syndicated	bank	letters	of	credit.	In	December 2004	System	Energy	amended	these	letters	of	credit	and	they	now	expire	in	May	2009.

System	Energy	may	refinance	or	redeem	debt	prior	to	maturity,	to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	stock	issuances	by	System	Energy	require	prior	regulatory	approval.	Debt	issuances	are	also	subject	to	issuance	tests	set	forth	in	bond indentures	and	other	agreements.	System	Energy	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital	needs.

Borrowings	and	securities	issuances	by	System	Energy	are	limited	to	amounts	authorized	by	the	SEC.	The	current	short-term	borrowing	limitation,	including borrowings	under	the	money	pool,	is	$140	million.	Under	its	SEC	Orders	and	without	further	SEC	authorization,	System	Energy	cannot	incur	additional	short-term indebtedness	unless	(a)	it	and	Entergy	Corporation	maintain	a	common	equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool	borrowings,	the security	to	be	issued	(if	rated)	and	all	outstanding	securities	of	System	Energy,	as	well	as	all	outstanding	securities	of	Entergy	Corporation,	that	are	rated,	are	rated investment	 grade.	See	Note	4	to	the	domestic	utility	companies	and	System	Energy	financial	statements	for	further	discussion	of	System	Energy's	short-term borrowing	limits.

# 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.	The	funds	are	invested	primarily	in	equity	securities;	fixed-rate,	fixed-income	securities;	and	cash	and	cash equivalents.	Management	believes	that	its	exposure	to	market	fluctuations	will	not	affect	results	of	operations	for	the	Grand	Gulf	trust	funds	because	of	the application	of	regulatory	accounting	principles.	The	decommissioning	trust	funds	are	discussed	more	thoroughly	in	Notes	1,	8,	and	12	to	the	domestic	utility companies	and	System	Energy	financial	statements.

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

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	apply	appropriate accounting	policies	and	to	make	estimates	and	judgments	that	can	have	a	significant	effect	on	reported	financial	position,	results	of	operations,	and	cash	flows. Management	has	identified	the	following	accounting	policies	and	estimates	as	critical	because	they	are	based	on	assumptions	and	measurements	that	involve	a	high degree	of	uncertainty,	and	there	is	the	potential	for	future	changes	in	the	assumptions	and	measurements	could	produce	estimates	that	would	have	a	material	impact on	the	presentation	of	System	Energy's	financial	position	or	results	of	operations.

Regulations	require	that	Grand	Gulf	be	decommissioned	after	the	facility	is	taken	out	of	service,	and	funds	are	collected	and	deposited	in	trust	funds	during	the facility's	operating	life	in	order	to	provide	for	this	obligation.	System	Energy	conducts	periodic	decommissioning	cost	studies	(typically	updated	every	three	to	five years)	to	estimate	the	costs	that	will	be	incurred	to	decommission	the	facility.	See	Note	8	to	the	domestic	utility	companies	and	System	Energy	financial	statements for	details	regarding	System	Energy's	most	recent	study	and	the	obligations	recorded	by	System	Energy	related	to	decommissioning.	The	following	key	assumptions have	a	significant	effect	on	these	estimates:

Cost	Escalation	Factors	-	System	Energy's	decommissioning	studies	include	an	assumption	that	decommissioning	costs	will	escalate	over	present	cost	levels by	an	annual	factor	averaging	approximately	5.5%.	A	50	basis	point	change	in	this	assumption	could	change	the	ultimate	cost	of	decommissioning	a	facility by	as	much	as	11%.

Timing	-	The	date	of	the	plant's	retirement	must	be	estimated	and	an	assumption	must	be	made	whether	decommissioning	will	begin	immediately	upon	plant retirement,	or	whether	the	plant	will	be	held	in	"safestore"	status	for	later	decommissioning,	as	permitted	by	applicable	regulations.	System	Energy's decommissioning	studies	for	Grand	Gulf	assume	immediate	decommissioning	upon	expiration	of	the	original	plant	license.	While	the	impact	of	these assumptions	cannot	be	determined	with	precision,	assuming	either	license	extension	or	use	of	a	"safestore"	status	can	possibly	decrease	the	present	value	of these	obligations.

Spent	Fuel	Disposal	-	Federal	regulations	require	the	DOE	to	provide	a	permanent	repository	for	the	storage	of	spent	nuclear	fuel,	and	legislation	has	been passed	by	Congress	to	develop	this	repository	at	Yucca	Mountain,	Nevada.	However,	until	this	site	is	available,	nuclear	plant	operators	must	provide	for interim	spent	fuel	storage	on	the	nuclear	plant	site,	which	can	require	the	construction	and	maintenance	of	dry	cask	storage	sites	or	other	facilities.	The	costs of	developing	and	maintaining	these	facilities	can	have	a	significant	impact	(as	much	as	16%	of	estimated	decommissioning	costs).	System	Energy's decommissioning	studies	include	cost	estimates	for	spent	fuel	storage.	However,	these	estimates	could	change	in	the	future	based	on	the	timing	of	the	opening of	the	Yucca	Mountain	facility,	the	schedule	for	shipments	to	that	facility	when	it	is	opened,	or	other	factors.

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

System	Energy	collects	the	costs	of	decommissioning	Grand	Gulf	through	rates	charged	to	its	customers.	The	amounts	collected	through	rates,	which	are	based upon	decommissioning	cost	studies,	are	deposited	in	decommissioning	trust	funds.	These	collections	plus	earnings	on	the	trust	fund	investments	are	estimated	to	be sufficient	to	fund	the	future	decommissioning	costs.

The	obligation	recorded	by	System	Energy	for	decommissioning	costs	is	reported	in	the	line	item	entitled	"Decommissioning."	Prior	to	the	implementation	of	SFAS 143,	the	amount	recorded	for	this	obligation	was	comprised	of	collections	from	customers	and	earnings	on	the	trust	funds.

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	$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.

|  | Change	in | Impact	on	2004 | Impact	on	Projected |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Assumption | Pension\tCost | Benefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $433 | $4,249 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $130 | - |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $204 | $1,421 |

Total	pension	cost	for	System	Energy	in	2004	was	$4.6	million.	System	Energy	anticipates	2005	pension	cost	to	increase	to	$4.8	million	due	to	decrease	in	the discount	rate	(from	6.25%	to	6.00%)	and	the	expected	rate	of	return	(from	8.75%	to	8.5%)	used	to	calculate	benefit	obligations.	System	Energy	contributed	$3.7 million	to	its	pension	plan	in	2004,	and	anticipates	making	$9.2	million	in	contributions	in	2005.	The	rise	in	pension	funding	requirements	is	due	to	declining interest	rates	and	the	phased-in	effect	of	asset	underperformance	from	2000	to	2002,	offset	by	the	Pension	Funding	Equity	Act	relief	passed	in	April	2004.

System	Energy's	accumulated	benefit	obligation	at	December	31,	2004,	2003,	and	2002	exceeded	plan	assets.	As	a	result,	System	Energy	was	required	to	recognize an	additional	minimum	liability	as	prescribed	by	SFAS	87.	At	December	31,	2004	System	Energy	increased	its	additional	minimum	liability	to	$7.7	million	from $7.4	million	at	December	31,	2003.	System	Energy	decreased	its	intangible	asset	to	$0.2	million	at	December	31,	2004	from	$0.4	million	at	December	31,	2003. System	Energy	increased	its	regulatory	asset	to	$15.2	million	at	December	31,	2004,	from	$7.0	million	at	December	31,	2003.	Net	income	for	2004,	2003,	and	2002 was	not	impacted.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	System	Energy	in	2004	were	$1.5	million,	including	$0.8	million	in	savings	due	to	the	estimated effect	of	future	Medicare	Part	D	subsidies.	System	Energy	expects	2005	postretirement	health	care	and	life	insurance	benefit	costs	to	approximate	$1.7	million, including	$1	million	in	savings	due	to	the	estimated	effect	of	future	Medicare	Part	D	subsidies.	The	increase	in	postretirement	health	care	and	life	insurance	benefit costs	is	due	to	the	decrease	in	the	discount	rate	(from	6.25%	to	6.00%)	and	an	increase	in	the	health	care	cost	trend	rate	used	to	calculate	benefit	obligations.

# To	the	Board	of	Directors	and	Shareholder

We	have	audited	the	accompanying	balance	sheets	of	System	Energy	Resources,	Inc.	as	of	December	31,	2004	and	2003,	and	the	related	statements	of	income, retained	earnings,	and	cash	flows	(pages	277	through	282	and	applicable	items	in	pages	284	through	348)	for	each	of	the	three	years	in	the	period	ended	December 31,	2004.	These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements based	on	our	audits.

In	our	opinion,	such	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	System	Energy	Resources,	Inc.	as	of	December	31,	2004	and 2003,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2004	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.

As	discussed	in	Note	8	to	the	notes	to	respective	financial	statements,	in	2003	System	Energy	Resources,	Inc.	adopted	the	provisions	of	Statement	of	Financial Accounting	Standards	No.	143,	Accounting	for	Asset	Retirement	Obligations.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Domestic\telectric | $545,381 | $583,820 | $602,486 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| \t\tFuel,\tfuel-related\texpenses,\tand |  |  |  |
| \t\t\tgas\tpurchased\tfor\tresale | 38,337 | 43,132 | 36,456 |
| \t\tNuclear\trefueling\toutage\texpenses | 12,655 | 12,695 | 10,723 |
| \t\tOther\toperation\tand\tmaintenance | 96,809 | 105,333 | 98,264 |
| Decommissioning | 23,434 | 21,799 | 16,055 |
| Taxes\tother\tthan\tincome\ttaxes | 24,364 | 25,521 | 25,992 |
| Depreciation\tand\tamortization | 127,081 | 109,528 | 112,093 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (10,433) | 27,400 | 53,769 |
| TOTAL | 312,247 | 345,408 | 353,352 |
| OPERATING\tINCOME | 233,134 | 238,412 | 249,134 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 1,544 | 1,140 | 2,449 |
| Interest\tand\tdividend\tincome | 6,870 | 7,556 | 2,857 |
| Miscellaneous\t-\tnet | 841 | (1,194) | 826 |
| TOTAL | 9,255 | 7,502 | 6,132 |
| INTEREST\tAND\tOTHER\tCHARGES |  |  |  |
| Interest\ton\tlong-term\tdebt | 58,561 | 62,802 | 73,891 |
| Other\tinterest\t-\tnet | 367 | 1,818 | 2,748 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (500) | (554) | (902) |
| TOTAL | 58,428 | 64,066 | 75,737 |
| INCOME\tBEFORE\tINCOME\tTAXES | 183,961 | 181,848 | 179,529 |
| Income\ttaxes | 78,013 | 75,845 | 76,177 |
| NET\tINCOME | $105,948 | $106,003 | $103,352 |

| Deferred	nuclear	refueling	outage	costs | 9,510 | 2,979 |
| :--- | :--- | :--- |
| Prepayments\tand\tother | 1,007 | 1,031 |
| TOTAL | 395,620 | 200,329 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 205,083 | 172,916 |
| UTILITY\tPLANT |  |  |
| Electric | 3,232,314 | 3,205,895 |
| Property\tunder\tcapital\tlease | 469,993 | 466,521 |
| Construction\twork\tin\tprogress | 28,743 | 31,344 |
| Nuclear\tfuel\tunder\tcapital\tlease | 65,572 | 47,242 |
| TOTAL\tUTILITY\tPLANT | 3,796,622 | 3,751,002 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 1,780,450 | 1,672,658 |
| UTILITY\tPLANT\t-\tNET | 2,016,172 | 2,078,344 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| \t\tSFAS\t109\tregulatory\tasset\t-\tnet | 96,047 | 115,633 |
| \t\tOther\tregulatory\tassets | 296,305 | 301,233 |
| Other | 19,578 | 12,269 |
| TOTAL | 411,930 | 429,135 |
| TOTAL\tASSETS | $3,028,805 | $2,880,724 |

|  | 2004 | 2003 |
| :--- | :--- | :--- |
|  | (In\tThousands) |  |
| CURRENT\tLIABILITIES |  |  |
| Currently\tmaturing\tlong-term\tdebt | $25,266 | $6,348 |
| Accounts\tpayable: |  |  |
| \t\tAssociated\tcompanies | 3,880 | - |
| \t\tOther | 21,051 | 30,255 |
| Taxes\taccrued | 46,468 | 55,585 |
| Accumulated\tdeferred\tincome\ttaxes | 3,477 | 942 |
| Interest\taccrued | 42,998 | 29,623 |
| Obligations\tunder\tcapital\tleases | 27,716 | 31,266 |
| Other | 1,621 | 1,971 |
| TOTAL | 172,477 | 155,990 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 421,466 | 290,964 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 75,612 | 79,088 |
| Obligations\tunder\tcapital\tleases | 37,855 | 15,976 |
| Other\tregulatory\tliabilities | 210,863 | 213,093 |
| Decommissioning | 335,893 | 312,459 |
| Accumulated\tprovisions | 2,378 | 3,782 |
| Long-term\tdebt | 849,593 | 882,401 |
| Other | 28,084 | 33,735 |
| TOTAL | 1,961,744 | 1,831,498 |
| Commitments\tand\tContingencies |  |  |
| SHAREHOLDER'S\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t1,000,000\tshares; |  |  |
| \tissued\tand\toutstanding\t789,350\tshares\tin\t2004\tand\t2003 | 789,350 | 789,350 |
| Retained\tearnings | 105,234 | 103,886 |
| TOTAL | 894,584 | 893,236 |
| TOTAL\tLIABILITIES\tAND\tSHAREHOLDER'S\tEQUITY | $3,028,805 | $2,880,724 |

|  | SYSTEM	ENERGY	RESOURCES,	INC.<br>STATEMENTS	OF	RETAINED	EARNINGS |  |  |
| :--- | :--- | :--- | :--- |
|  | For\tthe\tYears\tEnded\tDecember\t31, | For\tthe\tYears\tEnded\tDecember\t31, | For\tthe\tYears\tEnded\tDecember\t31, |
|  | 2004 | 2003 | 2002 |
|  |  | (In\tThousands) |  |
| Retained\tEarnings,\tJanuary\t1 | $103,886 | $102,883 | $101,331 |

| Net	income | 105,948 | 106,003 | 103,352 |
| :--- | :--- | :--- | :--- |
| \t\tDeduct:\n\t\t\t\tDividends\tdeclared | 104,600 | 105,000 | 101,800 |
| Retained\tEarnings,\tDecember\t31 | $105,234 | $103,886 | $102,883 |

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tIn\tThousands) | (Dollars\tIn\tThousands) |  |  |
| Operating\trevenues | $545,381 | $583,820 | $602,486 | $535,027 | $620,032 |
| Net\tIncome | $105,948 | $106,003 | $103,352 | $116,355 | $82,372 |
| Total\tassets | $3,028,805 | $2,880,724 | $2,915,898 | $2,964,041 | $3,369,048 |
| Long-term\tobligations\t(1) | $887,448 | $898,377 | $942,701 | $865,439 | $1,122,178 |
| Electric\tenergy\tsales\t(GWh) | 9,212 | 9,812 | 9,053 | 8,921 | 7,567 |

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

# NOTES	TO	RESPECTIVE	FINANCIAL	STATEMENTS

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

The	accompanying	separate	financial	statements	of	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	(the "domestic	utility	companies")	and	System	Energy	are	included	in	this	document	and	result	from	these	companies	having	registered	securities	with	the	SEC.	These companies	maintain	accounts	in	accordance	with	FERC	and	other	regulatory	guidelines.	Certain	previously	reported	amounts	have	been	reclassified	to	conform	to current	classifications,	with	no	effect	on	net	income	or	shareholders'	equity.

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.

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

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,	2004	and	2003,	is	shown	below:

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tMillions) |  |  |  |
| Production |  |  |  |  |  |  |
| \t\t\t\t\t\tNuclear | $951 | $1,627 | $1,543 | $- | $- | $1,866 |
| \t\t\t\t\t\tOther | 269 | 529 | 197 | 221 | 12 | - |
| Transmission | 646 | 708 | 385 | 406 | 29 | 8 |
| Distribution | 1,283 | 1,339 | 1,000 | 713 | 337 | - |
| Other | 216 | 247 | 269 | 175 | 70 | 16 |
| Construction\twork\tin\tprogress | 226 | 332 | 189 | 90 | 33 | 29 |
| Nuclear\tfuel\t(leased\tand\towned) | 106 | 71 | 32 | - | - | 66 |
| Asset\tretirement\tobligation | 24 | - | 42 | - | - | 31 |
| Property,\tplant,\tand\tequipment\t-\tnet | $3,721 | $4,853 | $3,657 | $1,605 | $481 | $2,016 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tMillions) |  |  |  |
| Production |  |  |  |  |  |  |
| \t\t\t\t\t\tNuclear | $940 | $1,638 | $1,593 | $- | $- | $1,941 |
| \t\t\t\t\t\tOther | 326 | 583 | 205 | 228 | 17 | - |
| Transmission | 636 | 647 | 369 | 380 | 26 | 9 |
| Distribution | 1,184 | 1,197 | 923 | 632 | 294 | - |
| Other | 214 | 238 | 266 | 166 | 75 | 17 |
| Construction\twork\tin\tprogress | 239 | 326 | 172 | 109 | 45 | 31 |
| Nuclear\tfuel\t(leased\tand\towned) | 110 | 64 | 65 | - | - | 47 |
| Asset\tretirement\tobligation | 45 | 32 | 45 | - | - | 33 |
| Property,\tplant,\tand\tequipment\t-\tnet | $3,694 | $4,725 | $3,638 | $1,515 | $457 | $2,078 |

Depreciation	is	computed	on	the	straight-line	basis	at	rates	based	on	the	estimated	service	lives	of	the	various	classes	of	property.	Depreciation	rates	on	average depreciable	property	are	shown	below:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | 3.2% | 2.1% | 2.9% | 2.5% | 2.8% | 2.9% |
| 2003 | 3.2% | 2.2% | 3.0% | 2.5% | 3.1% | 2.8% |
| 2002 | 3.2% | 2.4% | 3.0% | 2.5% | 3.1% | 2.8% |

Non-utility	property	-	at	cost	(less	accumulated	depreciation)	for	Entergy	Gulf	States	is	reported	net	of	accumulated	depreciation	of	$125.1	million	and	$122.7 million	as	of	December	31,	2004	and	2003,	respectively.

|  |  |  | Total |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Megawatt |  |  | Accumulated |
|  | Generating\tStations | Fuel-Type | Capability\t(1) | Ownership | Investment | Depreciation |
|  |  |  |  |  | (In\tMillions) |  |
| Entergy\tArkansas\t-\n\tIndependence | Unit\t1 | Coal | 815 | 31.50% | $117 | $73 |
|  | Common\tFacilities | Coal |  | 15.75% | $31 | $18 |
| \tWhite\tBluff | Units\t1\tand\t2 | Coal | 1,635 | 57.00% | $428 | $264 |
| Entergy\tGulf\tStates\t- |  |  |  |  |  |  |
| \tRoy\tS.\tNelson | Unit\t6 | Coal | 550 | 60.90% | $403 | $241 |
| \tBig\tCajun\t2 | Unit\t3 | Coal | 575 | 42.00% | $233 | $128 |
| Entergy\tMississippi\t- |  |  |  |  |  |  |
| \tIndependence | Units\t1\tand\t2\tand | Coal | 1,630 | 25.00% | $232 | $116 |
|  | Common\tFacilities |  |  |  |  |  |
| System\tEnergy\t-\n\tGrand\tGulf | Unit\t1 | Nuclear | 1,270 | 90.00%(2) | $3,702 | $1,780 |

(2) Includes	 an	 11.5%	 leasehold	 interest	 held	 by	 System	 Energy.	System	 Energy's	 Grand	 Gulf	 lease obligations	are	discussed	in	Note	9	to	the	domestic	utility	companies	and	System	Energy	financial statements.

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

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.

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

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

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.

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

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

Entergy	 applies	 the	 provisions	 of	 SFAS 115, "Accounting	 for	 Investments	 for	 Certain	 Debt	 and	 Equity	 Securities,"	 in	 accounting	 for	 investments	 in decommissioning	trust	funds.	As	a	result,	Entergy	records	the	decommissioning	trust	funds	at	their	fair	value	on	the	consolidated	balance	sheet.	Because	of	the ability	of	 the	domestic	utility	companies	and	System	Energy	 to	recover	decommissioning	costs	 in	rates	and	 in	accordance	with	 the	regulatory	 treatment	for decommissioning	 trust	funds,	Entergy	Arkansas,	Entergy	Gulf	States	(for	 the	regulated	portion	of	River	Bend),	Entergy	Louisiana,	and	System	Energy	have recorded	an	offsetting	amount	of	unrealized	gains/(losses)	on	investment	securities	in	other	regulatory	liabilities/assets.	For	the	nonregulated	portion	of	River	Bend, Entergy	Gulf	States	has	recorded	an	offsetting	amount	of	unrealized	gains/(losses)	in	other	deferred	credits.	See	Note	12	to	the	domestic	utility	companies	and System	Energy	financial	statements	for	details	on	the	decommissioning	trust	funds.

# 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	6	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.

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

# Entergy	Gulf	States'	Deregulated	Operations

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

The	results	of	these	deregulated	operations	before	interest	charges	for	the	years	ended	December	31,	2004,	2003,	and	2002	are	as	follows:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Operating\trevenues | $280,279 | $273,150 | $209,752 |
| Operating\texpenses |  |  |  |
| \t\t\t\t\t\t\t\t\t\tFuel,\toperation,\tand\tmaintenance | 197,275 | 177,385 | 158,927 |
| \t\t\t\t\t\t\t\t\t\tDepreciation\tand\taccretion | 30,653 | 47,566 | 40,092 |
| Total\toperating\texpense | 227,928 | 224,951 | 199,019 |
| Operating\tincome | 52,351 | 48,199 | 10,733 |
| Income\ttax\texpense | 20,414 | 17,722 | 4,503 |
| Net\tincome\tfrom\tderegulated\tutility\toperations | $31,937 | $30,477 | $6,230 |

The	net	investment	associated	with	these	deregulated	operations	as	of	December	31,	2004	and	2003	was	approximately	$830	and	$838	million,	respectively.

During	2004,	Entergy	adopted	the	provisions	of	FSP	106-2,	"Accounting	and	Disclosure	Requirements	Related	to	Medicare	Prescription	Drug,	Improvement	and Modernization	Act	of	2003,"	which	is	discussed	further	in	Note	10	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

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

During	2003,	Entergy	also	adopted	the	provisions	of	the	following	accounting	standards:	SFAS	149,	"Amendment	of	Statement	133	on	Derivative	Instruments	and Hedging	Activities"	and	related	interpretations	by	the	Derivatives	Implementation	Group,	and	FIN	45,	"Guarantor's	Accounting	and	Disclosure	Requirements	for Guarantees	 Including	 Indirect	 Guarantees	 of	 Indebtedness	 of	 Others".	The	 adoption	 of	 these	 standards	 did	 not	 have	 a	 material	 effect	 on	 Entergy's	 financial statements.

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	February	2005,	bills	were	filed	in	the	Texas	legislature	that	would	clarify	that	Entergy	Gulf	States	is	no	longer	operating	under	a	rate	freeze	and	specify	that	retail open	access	will	not	commence	in	Entergy	Gulf	States'	territory	until	the	PUCT	certifies	a	power	region.

# (Entergy	Gulf	States	and	Entergy	Louisiana)

# 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,	2004	and	2003	(in	millions).

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
| Asset\tRetirement\tObligation\t-\trecovery |  |  |  |  |  |  |
| dependent\tupon\ttiming\tof\tdecommissioning |  |  |  |  |  |  |
| (Note\t8) | $141.2 | $- | $141.6 | $- | $- | $97.3 |
| Deferred\tdistribution\texpenses\t- |  |  |  |  |  |  |
| recovered\tthrough\tMay\t2008 | - | - | - | - | 4.9 | - |
| Deferred\tfossil\tplant\tmaintenance |  |  |  |  |  |  |
| expenses\t-\trecovered\tthrough\tDecember |  |  |  |  |  |  |
| 2007\t(Note\t2) | - | - | - | - | 3.6 | - |
| Deferred\tfuel\t-\tnon-current\t-\trecovered |  |  |  |  |  |  |
| through\trate\triders\twhen\trates\tare |  |  |  |  |  |  |
| redetermined\tannually | 13.7 | - | - | 8.1 | - | - |
| Depreciation\tre-direct\t-\trecovery\tbegins\tat |  |  |  |  |  |  |
| start\tof\tretail\topen\taccess |  |  |  |  |  |  |
| (Note\t1) | - | 79.1 | - | - | - | - |
| DOE\tDecom.\tand\tDecontamination\tFees |  |  |  |  |  |  |
| -\trecovered\tthrough\tfuel\trates\tuntil |  |  |  |  |  |  |
| December\t2006\t(Note\t8) | 13.1 | 2.3 | 5.0 | - | - | 4.9 |
| Incremental\tice\tstorm\tcosts\t-\trecovered |  |  |  |  |  |  |
| until\t2032 | 14.2 | - | - | - | - | - |
| Low-level\tradwaste\t-\trecovery\ttiming |  |  |  |  |  |  |
| dependent\tupon\tpending\tlawsuit | 16.2 | 3.1 | - | - | - | - |
| Pension\tcosts\t(Note\t10) | 70.8 | - | 34.1 | 20.2 | 15.2 | 7.4 |
| Postretirement\tbenefits\t-\trecovered |  |  |  |  |  |  |
| through\t2013\t(Note\t10) | 19.1 | - | - | - | - | - |
| Provision\tfor\tstorm\tdamages\t-\trecovered |  |  |  |  |  |  |
| through\tcost\tof\tservice | 29.0 | 57.1 | 41.7 | - | - | - |
| Removal\tcosts\t-\trecovered\tthrough |  |  |  |  |  |  |
| depreciation\trates\t(Note\t8) | 34.9 | 0.9 | - | 32.7 | 1.3 | 17.1 |
| Resource\tplanning\t-\trecovery\ttiming\twill |  |  |  |  |  |  |
| be\tdetermined\tby\tthe\tLPSC\tin\ta\tbase\trate |  |  |  |  |  |  |
| proceeding\t(Note\t2) | - | - | 25.4 | - | - | - |
| River\tBend\tAFUDC\t-\trecovered\tthrough |  |  |  |  |  |  |
| August\t2025\t(Note\t1) | - | 37.5 | - | - | - | - |

| through	June	2014	(Note	9) | - | - | - | - | - | 127.3 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Spindletop\tgas\tstorage\tfacility\t-\trecovered |  |  |  |  |  |  |
| through\t2032 | - | 42.3 | - | - | - | - |
| Unamortized\tloss\ton\treaquired\tdebt\t- |  |  |  |  |  |  |
| recovered\tover\tterm\tof\tdebt | 37.0 | 43.4 | 27.4 | 15.6 | 4.6 | 41.8 |
| Other\t-\tvarious | 11.0 | 19.3 | 27.3 | 6.1 | 10.8 | 0.5 |
| Total | $400.2 | $285.0 | $302.5 | $82.7 | $40.4 | $296.3 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
| Asset\tRetirement\tObligation\t(Note\t8) | $203.7 | $36.2 | $132.3 | $- | $- | $92.7 |
| Deferred\tfuel\t-\tnon-current | 17.1 | - | - | 11.1 | - | - |
| Depreciation\tre-direct\t(Note\t1) | - | 79.1 | - | - | - | - |
| DOE\tDecom.\tand\tDecontamination\tFees |  |  |  |  |  |  |
| (Note\t8) | 17.1 | 3.0 | 6.5 | - | - | 6.4 |
| Incremental\tice\tstorm\tcosts | 14.7 | - | - | - | - | - |
| Low-level\tradwaste | 16.2 | 3.1 | - | - | - | - |
| Pension\tcosts\t(Note\t10) | 41.7 | - | - | 6.4 | 10.4 | 7.1 |
| Postretirement\tbenefits\t(Note\t10) | 21.5 | - | - | - | - | - |
| Provision\tfor\tstorm\tdamages | 25.3 | 57.4 | 40.9 | 3.5 | - | - |
| Removal\tcosts\t(Note\t8) | 26.6 | 4.2 | - | 24.4 | 2.1 | 15.1 |
| Resource\tplanning\t(Note\t2) | - | - | 5.8 | - | - | - |
| River\tBend\tAFUDC\t(Note\t1) | - | 39.4 | - | - | - | - |
| Sale-leaseback\tdeferral\t(Note\t9) | - | - | - | - | - | 131.7 |
| Spindletop\tgas\tstorage\tfacility | - | 38.0 | - | - | - | - |
| Unamortized\tloss\ton\treaquired\tdebt | 38.3 | 46.6 | 24.0 | 11.8 | 1.7 | 41.9 |
| 1994\tFERC\tSettlement\t(Note\t2) | - | - | - | - | - | 4.0 |
| Other | 15.3 | 13.4 | 8.2 | 1.1 | 13.0 | 2.3 |
| Total | $437.5 | $320.4 | $217.7 | $58.3 | $27.2 | $301.2 |

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

|  | Amount |
| :--- | :--- |
|  | (In\tMillions) |
| Under-recovered\tfuel\tcosts\tfor\tthe\tperiod\t9/03\t-\t7/04\tto\tbe |  |
| recovered\tthrough\tan\tinterim\tfuel\tsurcharge\tover\ta\tsix-month |  |
| period\tbeginning\tin\tJanuary\t2005 | $27.8 |
| Items\tto\tbe\taddressed\tas\tpart\tof\tunbundling | $29.0 |
| Imputed\tcapacity\tcharges | $\t9.3 |
| Other | $12.5 |

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

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

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

In	June	and	November	2004,	the	City	Council	passed	resolutions	implementing	a	package	of	measures	developed	by	Entergy	New	Orleans	and	the	Council Advisors	to	protect	customers	from	potential	gas	price	spikes	during	the	2004	-	2005	winter	heating	season.	These	measures	include:	maintaining	Entergy	New Orleans'	financial	hedging	plan	for	its	purchase	of	wholesale	gas,	and	deferral	of	collection	of	up	to	$6.2	million	of	gas	costs	associated	with	a	cap	on	the	purchased gas	adjustment	in	November	and	December	2004	and	in	the	event	that	the	average	residential	customer's	gas	bill	were	to	exceed	a	threshold	level.	The	deferrals resulting	from	these	caps	will	receive	accelerated	recovery	over	a	seven-month	period	beginning	in	April	2005.

Entergy	Gulf	States	is	operating	in	Texas	under	the	terms	of	a	December	2001	settlement	agreement	approved	by	the	PUCT.	 The	settlement	provided	for	a	base	rate freeze	that	has	remained	in	effect	during	the	delay	in	the	implementation	of	retail	open	access	in	Entergy	Gulf	States'	Texas	service	territory.	In	view	of	the	PUCT

order	in	July	2004	to	further	delay	retail	open	access	in	the	Texas	service	territory,	Entergy	Gulf	States	filed	a	retail	electric	rate	case	and	fuel	reconciliation proceeding	with	the	PUCT	in	August	2004	seeking	the	following:

Proposed	Settlement	(Entergy	Gulf	States	and	Entergy	Louisiana)

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

In	July	2004,	Entergy	Gulf	States	filed	with	the	LPSC	an	application	for	a	change	in	its	rates	and	charges	seeking	an	increase	of	$9.1	million	in	gas	base	rates	in order	to	allow	Entergy	Gulf	States	an	opportunity	to	earn	a	fair	and	reasonable	rate	of	return.	Entergy	Gulf	States	also	is	seeking	approval	of	certain	proposed	rate design,	rate	schedule,	and	policy	changes.	Discovery	is	underway,	and	a	decision	is	expected	during	the	third	quarter	of	2005.

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

Entergy	Mississippi	is	operating	under	a	December	2002	order	issued	by	the	MPSC.	The	order	endorsed	a	new	power	management	rider	schedule	designed	to	more efficiently	 collect	 capacity	 portions	 of	 purchased	 power	 costs.	Also,	 the	 order	 provides	 for	 improvements	 in	 the	 return	 on	 equity	 formula	 and	 more	 robust performance	measures	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	Mississippi	law	and	Entergy	Mississippi's	formula	rate	plan,	however,	if

Entergy	Mississippi's	earned	ROE	is	above	the	top	of	the	range-of-no-change	at	the	top	of	the	formula	rate	plan	bandwidth,	then	Entergy	Mississippi's	"Allowed ROE"	for	the	next	twelve-month	period	is	the	point	halfway	between	such	earned	ROE	and	the	top	of	the	bandwidth;	and	Entergy	Mississippi's	retail	rates	are	set	at that	halfway-point	ROE	level.	In	the	situation	where	Entergy	Mississippi's	earned	ROE	is	not	above	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth, then	Entergy	Mississippi's	"Allowed	ROE"	for	the	next	twelve-month	period	is	the	top	of	the	range-of-no-change	at	the	top	of	the	bandwidth.

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

# Grand	Gulf	Accelerated	Recovery	Tariff	(GGART)

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

# Filings	with	the	City	Council	(Entergy	New	Orleans)

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

# Purchased	Power	for	Summer	2001,	2002	and	2003	(Entergy	Gulf	States	and	Entergy	Louisiana)

In	March	2001,	Entergy	Louisiana	and	Entergy	Gulf	States	filed	applications	with	the	LPSC	for	authorization	to	participate	in	contracts	that	would	be	executed	by the	Entergy	System	to	meet	the	summer	peak	load	requirements	for	the	summer	of	2001.	In	May	2001,	the	LPSC	determined	that	24%	of	Entergy	Louisiana's	and Entergy	Gulf	States'	costs	relating	to	summer	2001	purchases	should	be	categorized	as	capacity	charges.	Subsequently,	the	LPSC	raised	certain	prudence	issues related	 to	 the	 2001	 purchases.	The	administrative	 law	 judge	(ALJ)	presiding	over	 the	case	 issued	a	Preliminary	Recommendation	regarding	prudence	 issues primarily	associated	with	the	power	uprates	at	the	Waterford	3	and	Grand	Gulf	nuclear	units.	In	the	event	that	such	decision	becomes	final,	additional	calculations would	be	required	to	determine	the	potential	refund	obligation	for	the	periods	2001,	2002	and	2003.	The	ALJ	also	concluded	that	Entergy	should	be	permitted	the opportunity	to	recover	the	expenses	of	the	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.

Should	the	LPSC	approve	the	proposed	settlement	discussed	above,	all	issues	arising	out	of	the	purchased	power	cases	for	the	summers	of	2001,	2002,	and	2003 would	be	resolved.

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

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Current: |  |  |  |  |  |  |
| \tFederal\t(a)(b) | $14,490 | $42,436 | $2,439 | ($23,568) | ($19,259) | $222,622 |
| \tState\t(a)(b) | 8,727 | 7,944 | 1,957 | (1,221) | (3,655) | 33,926 |
| \t\tTotal\t(a)(b) | 23,217 | 50,380 | 4,396 | (24,789) | (22,914) | 256,548 |
| Deferred\t--\tnet | 70,674 | 63,615 | 80,207 | 63,234 | 40,226 | (175,059) |
| Investment\ttax\tcredit |  |  |  |  |  |  |
| \tadjustments\t--\tnet | (4,827) | (5,707) | (5,128) | (1,405) | (444) | (3,476) |
| \tRecorded\tincome\ttax | $89,064 | $108,288 | $79,475 | $37,040 | $16,868 | $78,013 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Current: |  |  |  |  |  |  |
| \tFederal\t(a) | $40,632 | ($11,535) | ($745,724) | ($2,969) | ($7,655) | $95,670 |
| \tState\t(a) | 16,306 | (1,503) | (16,243) | 2,565 | (1,871) | 15,382 |
| \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 |  |  |  |  |  |  |
| \tadjustments\t--\tnet | (4,951) | (12,078) | (5,281) | (1,405) | (452) | (3,476) |
| \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: |  |  |  |  |  |  |
| \tFederal\t(a) | $13,206 | $66,227 | $43,048 | $21,817 | ($7,103) | $99,429 |
| \tState\t(a) | 3,243 | 11,345 | 1,867 | 3,969 | (47) | 14,994 |
| \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 |  |  |  |  |  |  |
| \tadjustments\t--\tnet | (5,008) | (7,365) | (5,403) | (1,411) | (468) | (3,476) |
| \tRecorded\tincome\ttax\texpense | $71,404 | $65,997 | $84,765 | $17,846 | ($422) | $76,177 |

(a) Entergy	Louisiana's	actual	cash	taxes	paid/(refunded)	were	$(70,650)	in	2004,	$35,128	in	2003,	and $(781,540) in	 2002.	Entergy	 Louisiana's	 mark-to-market	 tax	 accounting	 election	 significantly reduced	taxes	paid	in	2002.	In	2001,	Entergy	Louisiana	changed	its	method	of	accounting	for	tax purposes	related	to	its	wholesale	electric	power	contracts.	The	most	significant	of	these	is	the	contract to	purchase	power	from	the	Vidalia	project	(the	contract	is	discussed	in	Note	8	to	the	domestic	utility companies	and	System	Energy	financial	statements).	The	new	tax	accounting	method	has	provided	a cumulative	cash	flow	benefit	of	approximately	$790	million	 through	2004,	which	 is	expected	 to reverse	in	the	years	2005	through	2031.	The	election	did	not	reduce	book	income	tax	expense.	The timing	of	the	reversal	of	this	benefit	depends	on	several	variables,	including	the	price	of	power. Approximately	half	of	the	consolidated	cash	flow	benefit	of	the	election	occurred	in	2001	and	the remainder	occurred	in	2002.	In	accordance	with	Entergy's	intercompany	tax	allocation	agreement, the	cash	flow	benefit	for	Entergy	Louisiana	occurred	in	the	fourth	quarter	of	2002.

(b) In	2003,	the	domestic	utility	companies	and	System	Energy	filed,	with	the	IRS,	a	change	in	tax accounting	method	notification	for	their	respective	calculations	of	cost	of	goods	sold.	The	adjustment implemented	a	simplified	method	of	allocation	of	overhead	to	the	production	of	electricity,	which	is provided	under	the	IRS	capitalization	regulations.	The	cumulative	adjustment	placing	these companies	on	the	new	methodology	resulted	in	a	$1.171	billion	deduction	for	Entergy	Arkansas,	a $674	million	deduction	for	Entergy	Gulf	States,	a	$505	million	deduction	for	Entergy	Louisiana,	a $145	million	deduction	for	Entergy	Mississippi,	a	$31	million	deduction	for	Entergy	New	Orleans, and	a	$430	million	deduction	for	System	Energy	on	Entergy's	2003	income	tax	return.	There	was	no cash	benefit	from	the	method	change	in	2003.	In	2004,	Entergy	Arkansas	realized	$173	million, Entergy	Gulf	States	realized	$69	million,	Entergy	Louisiana	realized	$100	million,	Entergy Mississippi	realized	$36	million,	and	System	Energy	realized	$144	million	in	cash	tax	benefit	from the	method	change.	This	tax	accounting	method	change	is	an	issue	across	the	utility	industry	and	will likely	be	challenged	by	the	IRS	on	audit.	Entergy	believes	that	its	contingency	provision	established in	its	financial	statements	will	sufficiently	cover	its	risk	associated	with	this	issue.

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Computed\tat\tstatutory\trate\t(35%) | $80,946 | $105,194 | $72,440 | $38,688 | $15,729 | $64,386 |
| Increases\t(reductions)\tin\ttax |  |  |  |  |  |  |
| \t\t\t\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof |  |  |  |  |  |  |
| \t\t\t\tfederal\tincome\ttax\teffect | 12,204 | 8,289 | 6,411 | 3,845 | 1,158 | 7,665 |
| Regulatory\tdifferences\t- |  |  |  |  |  |  |
| \t\t\t\tutility\tplant\titems | 13,775 | 6,951 | 10,052 | (1,482) | 1,373 | 10,528 |
| Amortization\tof\tinvestment |  |  |  |  |  |  |
| \t\t\t\ttax\tcredits | (4,827) | (5,316) | (5,128) | (1,405) | (444) | (3,476) |
| Flow-through/permanent |  |  |  |  |  |  |
| \t\t\t\tdifferences | (9,127) | (7,080) | (3,576) | (2,114) | (878) | (993) |
| Other\t--\tnet | (3,907) | 250 | (724) | (492) | (70) | (97) |
| \tTotal\tincome\ttaxes | $89,064 | $108,288 | $79,475 | $37,040 | $16,868 | $78,013 |
| Effective\tIncome\tTax\tRate | 38.5% | 36.0% | 38.4% | 33.5% | 37.5% | 42.4% |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Computed\tat\tstatutory\trate\t(35%) | $80,957 | $18,934 | $85,247 | $35,522 | $4,807 | $63,647 |
| Increases\t(reductions)\tin\ttax |  |  |  |  |  |  |
| \t\t\t\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof |  |  |  |  |  |  |
| \t\t\t\tfederal\tincome\ttax\teffect | 12,987 | 473 | 7,764 | 3,000 | 21 | 7,765 |
| Regulatory\tdifferences\t- |  |  |  |  |  |  |
| \t\t\t\tutility\tplant\titems | 15,994 | 13,260 | 10,568 | (930) | 2,045 | 11,530 |
| Amortization\tof\tinvestment |  |  |  |  |  |  |
| \t\t\t\ttax\tcredits | (4,951) | (8,797) | (5,281) | (1,404) | (452) | (3,476) |
| Flow-through/permanent |  |  |  |  |  |  |
| \t\t\t\tdifferences | 1,090 | (10,625) | (2,012) | (1,112) | (625) | (420) |
| Benefit\tof\tEntergy\tCorp.\texpenses | (1,145) | (888) | - | - | - | (3,408) |
| Other\t--\tnet | 364 | (821) | 1,122 | (645) | 79 | 207 |
| \tTotal\tincome\ttaxes | $105,296 | $11,536 | $97,408 | $34,431 | $5,875 | $75,845 |
| Effective\tIncome\tTax\tRate | 45.5% | 21.3% | 40.0% | 33.9% | 42.8% | 41.7% |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2002 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Computed\tat\tstatutory\trate\t(35%) | $72,467 | $84,064 | $80,317 | $24,589 | ($228) | $62,836 |
| Increases\t(reductions)\tin\ttax |  |  |  |  |  |  |
| \t\t\t\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof |  |  |  |  |  |  |
| \t\t\t\tfederal\tincome\ttax\teffect | 8,784 | 6,401 | 6,065 | 2,069 | 551 | 7,049 |
| Regulatory\tdifferences\t- |  |  |  |  |  |  |
| \t\t\t\tutility\tplant\titems | 10,615 | 2,738 | 6,875 | (3,032) | 1,125 | 11,453 |
| Amortization\tof\tinvestment |  |  |  |  |  |  |
| \t\t\t\ttax\tcredits | (5,008) | (6,528) | (5,403) | (1,411) | (468) | (3,476) |
| Flow-through/permanent |  |  |  |  |  |  |
| \t\t\t\tdifferences | (10,687) | (15,000) | (1,878) | (1,453) | (538) | (1,183) |
| Benefit\tof\tEntergy\tCorp.\texpenses | (3,428) | (3,830) | (180) | (2,331) | (434) | (191) |
| Other\t--\tnet | (1,339) | (1,848) | (1,031) | (585) | (430) | (311) |
| \tTotal\tincome\ttaxes | $71,404 | $65,997 | $84,765 | $17,846 | ($422) | $76,177 |
| Effective\tIncome\tTax\tRate | 34.5% | 27.5% | 36.9% | 25.4% | 64.7% | 42.4% |

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Deferred\tand\tLong-term\tAccrued\tTax |  |  |  |  |  |  |
| Liabilities: |  |  |  |  |  |  |
| \t\t\tNet\tregulatory\tassets/(liabilities) | ($128,594) | ($479,158) | ($169,675) | ($22,864) | $44,867\t($223,391) | $44,867\t($223,391) |
| \t\t\tPlant-related\tbasis\tdifferences\t-\tnet | (1,237,303) | (1,388,391) | (921,976) | (389,558) | (103,733) | (471,026) |
| \t\t\tPower\tpurchase\tagreements | - | - | (971,676) | - | - | - |
| \t\t\tRate\trefunds | (39,163) | - | (17,736) | (49,124) | (14,375) | - |
| \t\t\tDeferred\tfuel | (2,899) | (36,017) | (1,286) | (6,424) | (3,873) | - |
| \t\t\tOther\treserves | 2,686 | (33,916) | 27,421 | 5,856 | (323) | (80,597) |
| \t\t\tOther | (80,980) | (20,781) | (68,381) | (16,516) | (2,982) | (11,851) |
| \t\t\t\t\t\tTotal | (1,486,253) | (1,958,263) | (2,123,309) | (478,630) | (80,419) | (786,865) |
| Deferred\tTax\tAssets: |  |  |  |  |  |  |
| \t\t\tAccumulated\tdeferred\tinvestment |  |  |  |  |  |  |
| \t\t\t\t\t\ttax\tcredit | 26,936 | 34,359 | 36,989 | 5,235 | 1,538 | 28,922 |
| \t\t\tSale\tand\tleaseback | - | - | 82,410 | - | - | 144,745 |
| \t\t\tNOL\tcarryforward | 300,249 | 164,749 | 164,840 | 34,642 | 18,973 | - |
| \t\t\tUnbilled/Deferred\trevenues | - | 17,001 | - | 10,193 | - | - |
| \t\t\tPension-related\titems | - | 14,499 | 13,039 | - | 10,656 | 6,737 |
| \t\t\tReserve\tfor\tregulatory\tadjustments | - | 131,112 | - | - | - | - |
| \t\t\tRate\trefund | - | 32,932 | - | - | - | 170,222 |
| \t\t\tCustomer\tdeposits | 40,880 | 33,425 | 17,479 | 15,777 | 91 | - |
| \t\t\tNuclear\tdecommissioning | 12,070 | - | 2,833 | - | - | - |
| \t\t\tOther | 11,801 | 10,721 | 13,021 | 2,386 | 193 | 11,296 |
| \t\t\t\tTotal | 391,936 | 438,798 | 330,611 | 68,233 | 31,451 | 361,922 |
| Net\tdeferred\ttax\tliability | ($1,094,317) | ($1,519,465) | ($1,792,698) | ($410,397) | ($48,968)($424,943) | ($48,968)($424,943) |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2003 | Arkansas | Gulf\tStates | Louisiana | Mississippi New\tOrleans | Mississippi New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| Deferred\tand\tLong-term\tAccrued\tTax |  |  |  |  |  |  |
| Liabilities: |  |  |  |  |  |  |
| \t\t\tNet\tregulatory\tassets/(liabilities) | ($157,147) | ($478,254) | ($195,074) | ($34,738) | $38,834 | ($246,519) |
| \t\t\tPlant-related\tbasis\tdifferences,\tnet | (798,641) | (1,095,206) | (806,955) | (284,550) | (74,041) | (332,197) |
| \t\t\tPower\tpurchase\tagreements | - | - | (945,495) | - | - | - |
| \t\t\tDeferred\tfuel | (4,154) | (45,762) | - | (40,091) | (1,109) | - |
| \t\t\tLong\tterm\ttaxes\taccrued | (26,611) | (55,155) | - | (52,646) | (17,491) | (57,239) |
| \t\t\tOther | (85,528) | (26,012) | (67,272) | (21,806) | (1,728) | (11,497) |
| \t\t\t\tTotal | (1,072,081) | (1,700,389) | (2,014,796) | (433,831) | (55,535) | (647,452) |
| Deferred\tTax\tAssets: |  |  |  |  |  |  |
| \t\t\tAccumulated\tdeferred\tinvestment |  |  |  |  |  |  |
| \t\t\t\t\t\ttax\tcredit | 28,836 | 36,192 | 38,962 | 5,773 | 1,709 | 30,251 |
| \t\t\tSale\tand\tleaseback | - | - | 83,539 | - | - | 139,595 |
| \t\t\tNOL\tcarryforward | - | - | 104,489 | - | - | - |
| \t\t\tUnbilled/Deferred\trevenues | - | 11,959 | - | 7,357 | - | - |
| \t\t\tPension-related\titems | 5,453 | 11,474 | 12,562 | - | 9,324 | 7,354 |
| \t\t\tReserve\tfor\tregulatory\tadjustments | - | 138,933 | - | - | - | - |
| \t\t\tRate\trefund | 2,351 | 23,184 | 789 | 379 | 3,977 | 170,222 |
| \t\t\tCustomer\tdeposits | 37,778 | 35,840 | 16,804 | 18,085 | 84 | - |
| \t\t\tNuclear\tdecommissioning | 13,171 | - | 2,833 | - | - | - |
| \t\t\tOther | 6,399 | 26,147 | 26,096 | 9,722 | 1,415 | 8,124 |
| \t\t\t\tTotal | 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) |

As	of	December	31,	2004,	federal	net	operating	loss	carryforwards	were	$766.9	million	for	Entergy	Arkansas,	$447.5	million	for	Entergy	Gulf	States,	$195.7 million	for	Entergy	Louisiana,	$40.9	million	for	Entergy	Mississippi,	and	$54.9	million	for	Entergy	New	Orleans.	If	the	federal	net	operating	loss	carryforwards	are not	utilized,	they	will	expire	in	the	year	2023.

As	of	December	31,	2004,	state	net	operating	loss	carryforwards	were	$1.9	billion	for	Entergy	Louisiana,	$278	million	for	Entergy	Gulf	States,	$11	million	for Entergy	New	Orleans,	and	$638	million	for	Entergy	Arkansas.	If	the	state	net	operating	loss	carryforwards	are	not	utilized,	they	will	expire	in	the	years	2016 through	2018	for	Entergy	Louisiana,	2018	for	Entergy	Gulf	States,	2018	for	Entergy	New	Orleans,	and	2008	for	Entergy	Arkansas.

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

The	short-term	borrowings	of	Entergy's	subsidiaries	are	limited	to	amounts	authorized	by	the	SEC.	The	current	limits	authorized	are	effective	through	November	30, 2007.	In	addition	to	borrowing	from	commercial	banks,	Entergy's	subsidiaries	are	authorized	under	the	SEC	order	to	borrow	from	Entergy's	money	pool.	The	money pool	is	an	inter-company	borrowing	arrangement	designed	to	reduce	Entergy's	subsidiaries'	dependence	on	external	short-term	borrowings.	Borrowings	from	the money	pool	and	external	borrowings	combined	may	not	exceed	the	SEC	authorized	limits.	Under	the	SEC	Order	and	without	further	SEC	authorization,	the domestic	utility	companies	and	System	Energy	cannot	incur	additional	short-term	indebtedness	unless	(a)	the	issuer	and	Entergy	Corporation	maintain	a	common equity	ratio	of	at	least	30%	and	(b)	with	the	exception	of	money	pool	borrowings,	the	security	to	be	issued	(if	rated)	and	all	outstanding	securities	of	the	issuer	(other than	preferred	stock	of	Entergy	Gulf	States	and	Entergy	New	Orleans),	as	well	as	all	outstanding	securities	of	Entergy	Corporation,	that	are	rated,	are	rated investment	grade.

The	following	are	the	SEC	authorized	limits	for	short-term	borrowings	and	the	outstanding	short-term	borrowings	from	the	money	pool	for	the	domestic	utility companies	and	System	Energy	as	of	December	31,	2004:

|  | Authorized | Borrowings |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $235 | - |
| Entergy\tGulf\tStates | $340 | $59.7 |
| Entergy\tLouisiana | $225 | - |
| Entergy\tMississippi | $160 | - |
| Entergy\tNew\tOrleans | $100 | - |
| System\tEnergy | $140 | - |

# NOTE	5.	LONG	-	TERM	DEBT	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System Energy)

|  | 2004 | 2003 |
| :--- | :--- | :--- |
|  | (In\tThousands) |  |
| System\tEnergy |  |  |
| \t\t\t\t\t\t\tMortgage\tBonds: |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.875%\tSeries\tdue\tOctober\t2007 | $70,000 | $70,000 |
| \t\t\t\t\t\t\t\t\t\t\t\t\tTotal\tmortgage\tbonds | 70,000 | 70,000 |
| \t\t\t\t\t\t\tGovernmental\tBonds\t(a): |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t5.875%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 216,000 | 216,000 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t5.9%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 102,975 | 102,975 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.3%\tSeries\tdue\t2025,\tClaiborne\tCounty | - | 7,625 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t6.2%\tSeries\tdue\t2026,\tClaiborne\tCounty | 90,000 | 90,000 |
| \t\t\t\t\t\t\t\t\t\t\t\t\tTotal\tgovernmental\tbonds | 408,975 | 416,600 |
| Other\tLong-Term\tDebt: |  |  |
| \t\t\t\t\t\t\t\t\t\tGrand\tGulf\tLease\tObligation\t5.01%\t(Note\t9) | 397,119 | 403,468 |
| \t\t\t\t\t\t\t\t\t\tUnamortized\tPremium\tand\tDiscount\t-\tNet | (1,235) | (1,319) |
| Total\tLong-Term\tDebt | 874,859 | 888,749 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 25,266 | 6,348 |
|  | $849,593 | $882,401 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear |  |  |
| Fair\tValue\tof\tLong-Term\tDebt\t(d) | $470,187 | $489,436 |

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

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

(e) The	bonds	had	a	mandatory	tender	date	of	September	1,	2004.	Entergy	Gulf	States	purchased	the bonds	from	the	holders,	pursuant	to	the	mandatory	tender	provision,	and	has	not	remarketed	the bonds	at	this	time.

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

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

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 | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) |  |  |  |
| 2005 | $147,000 | $98,000 | $55,000 | - | $30,000 | - |
| 2006 | - | - | - | - | - | - |
| 2007 | - | - | - | - | - | $70,000 |
| 2008 | $621 | $325,000 | - | $100,000 | $30,000 | - |
| 2009 | - | $225,000 | - | - | - | - |

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

Junior	Subordinated	Deferrable	Interest	Debentures	and	Implementation	of	FIN	46	(Entergy	Arkansas,	Entergy	Gulf	States,	and	Entergy	Louisiana)

Entergy	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.

# Tax	Exempt	Bond	Audit	(Entergy	Louisiana)

In	November	2000,	the	Internal	Revenue	Service	(IRS)	began	an	audit	of	certain	Tax	Exempt	Bonds	issued	by	St.	Charles	Parish,	State	of	Louisiana	(the	Issuer). The	Bonds	were	issued	to	finance	previously	unfinanced	acquisition	costs	expended	by	Entergy	Louisiana	to	acquire	certain	radioactive	solid	waste	disposal facilities	(the	Facilities)	at	the	Waterford	Steam	Electric	Generating	Station.	In	January	2002,	the	IRS	issued	a	preliminary	adverse	determination	that	the	Bonds were	not	tax	exempt.	The	stated	basis	for	this	determination	was	that	radioactive	waste	did	not	constitute	"solid	waste"	within	the	provisions	of	the	Internal	Revenue Code	and	therefore	the	Facilities	did	not	qualify	as	solid	waste	disposal	facilities.	In	a	"technical	advice	memorandum,"	issued	in	October	2004	to	the	parish,	the	IRS National	Office	concurred	with	the	preliminary	adverse	determination.	The	Issuer	and	Entergy	Louisiana	intend	to	continue	to	vigorously	contest	this	matter.

# NOTE	6.	PREFERRED	STOCK	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans)

The	number	of	shares	authorized	and	outstanding	and	dollar	value	of	preferred	stock	for	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans	as	of	December	31,	2004	and	2003	are	presented	below.	Only	the	two	Entergy	Gulf	States	series	"with	sinking	fund"	contain mandatory	redemption	requirements.	All	other	series	of	the	U.S.	Utilities	are	redeemable	at	Entergy's	option	at	the	call	prices	presented.	Dividends	paid	on	all	of Entergy's	preferred	stock	series	are	eligible	for	the	dividends	received	deduction.	The	dividends	received	deduction	is	limited	by	Internal	Revenue	Code	section	244 for	the	following	preferred	stock	series:	Entergy	Arkansas	4.72%,	Entergy	Gulf	States	4.40%,	Entergy	Louisiana	4.96%,	Entergy	Mississippi	4.56%,	and	Entergy New	Orleans	4.75%.

|  | Shares<br>Authorized<br>and	Outstanding<br>2004 | 2003 | Dollars<br>(In	Thousands)<br>2004 | 2003 | Call	Price	Per<br>Share	as	of<br>December	31,<br>2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas\tPreferred\tStock |  |  |  |  |  |
| \t\t\t\tWithout\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\tCumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.32%\tSeries | 70,000 | 70,000 | $7,000 | $7,000 | $103.65 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.72%\tSeries | 93,500 | 93,500 | 9,350 | 9,350 | $107.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.56%\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | $102.83 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.56%\t1965\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | $102.50 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t6.08%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.83 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.32%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $103.17 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.80%\tSeries | 150,000 | 150,000 | 15,000 | 15,000 | $103.25 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.40%\tSeries | 200,000 | 200,000 | 20,000 | 20,000 | $102.80 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.88%\tSeries | 150,000 | 150,000 | 15,000 | 15,000 | $103.00 |
| \t\t\t\t\t\t\t\tCumulative,\t$0.01\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t$1.96\tSeries\t(a) | 600,000 | 600,000 | 15,000 | 15,000 | $25.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\twithout\tsinking\tfund | 1,613,500 | 1,613,500 | $116,350 | $116,350 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2004 | 2003 | Dollars<br>(In	Thousands)<br>2004 | 2003 | Call	Price	Per<br>Share	as	of<br>December	31,<br>2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tGulf\tStates\tPreferred\tStock |  |  |  |  |  |
| Preferred\tStock |  |  |  |  |  |
| \t\t\t\tAuthorized\t6,000,000\tshares, |  |  |  |  |  |
| \t\t\t\t$100\tpar\tvalue,\tcumulative |  |  |  |  |  |
| \t\t\t\t\t\t\tWithout\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.40%\tSeries | 51,173 | 51,173 | $5,117 | $5,117 | $108.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.50%\tSeries | 5,830 | 5,830 | 583 | 583 | $105.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.40%\t1949\tSeries | 1,655 | 1,655 | 166 | 166 | $103.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.20%\tSeries | 9,745 | 9,745 | 975 | 975 | $102.82 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.44%\tSeries | 14,804 | 14,804 | 1,480 | 1,480 | $103.75 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t5.00%\tSeries | 10,993 | 10,993 | 1,099 | 1,099 | $104.25 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t5.08%\tSeries | 26,845 | 26,845 | 2,685 | 2,685 | $104.63 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t4.52%\tSeries | 10,564 | 10,564 | 1,056 | 1,056 | $103.57 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t6.08%\tSeries | 32,829 | 32,829 | 3,283 | 3,283 | $103.34 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t7.56%\tSeries | 308,830 | 308,830 | 30,883 | 30,883 | $101.80 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\twithout\tsinking\tfund | 473,268 | 473,268 | $47,327 | $47,327 |  |
| \t\t\t\t\t\t\tWith\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\tAdjustable\tRate-A,\t7.0%\t(b) | 84,000 | 96,020 | $8,400 | $9,602 | $100.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\tAdjustable\tRate-B,\t7.0%\t(b) | 90,000 | 112,500 | 9,000 | 11,250 | $100.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\twith\tsinking\tfund | 174,000 | 208,520 | $17,400 | $20,852 |  |
| Fair\tValue\tof\tPreferred\tStock\twith\nSinking\tFund\t(c) |  |  | $15,286 | $15,354 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2004 | 2003 | Dollars<br>(In	Thousands)<br>2004 | 2003 | Call	Price	Per<br>Share	as	of<br>December	31,<br>2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tLouisiana\tPreferred\tStock |  |  |  |  |  |
| \t\t\t\t\tWithout\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\tCumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.96%\tSeries | 60,000 | 60,000 | $6,000 | $6,000 | $104.25 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.16%\tSeries | 70,000 | 70,000 | 7,000 | 7,000 | $104.21 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.44%\tSeries | 70,000 | 70,000 | 7,000 | 7,000 | $104.06 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t5.16%\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | $104.18 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t5.40%\tSeries | 80,000 | 80,000 | 8,000 | 8,000 | $103.00 |

| 6.44%	Series | 80,000 | 80,000 | 8,000 | 8,000 | $102.92 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t7.84%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $103.78 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t7.36%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $103.36 |
| \t\t\t\t\t\t\t\t\tCumulative,\t$25\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t8.00%\tSeries | 1,480,000 | 1,480,000 | 37,000 | 37,000 | $25.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\twithout\tsinking\tfund | 2,115,000 | 2,115,000 | $100,500 | $100,500 |  |

|  | 2004 | 2003 | 2004 | 2003 | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tMississippi\tPreferred\tStock |  |  |  |  |  |
| \t\t\t\tWithout\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\tCumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.36%\tSeries | 59,920 | 59,920 | $5,992 | $5,992 | $103.86 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.56%\tSeries | 43,887 | 43,887 | 4,389 | 4,389 | $107.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t4.92%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.88 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t7.44%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.81 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t8.36%\tSeries | 200,000 | 200,000 | 20,000 | 20,000 | $100.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\twithout\tsinking\tfund | 503,807 | 503,807 | $50,381 | $50,381 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2004 | 2003 | Dollars<br>(In	Thousands)<br>2004 | 2003 | Call	Price	Per<br>Share	as	of<br>December	31,<br>2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tNew\tOrleans\tPreferred\tStock |  |  |  |  |  |
| \t\t\t\tWithout\tsinking\tfund: |  |  |  |  |  |
| \t\t\t\t\t\t\t\tCumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t4.75%\tSeries | 77,798 | 77,798 | $7,780 | $7,780 | $105.00 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t4.36%\tSeries | 60,000 | 60,000 | 6,000 | 6,000 | $104.58 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t5.56%\tSeries | 60,000 | 60,000 | 6,000 | 6,000 | $102.59 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tTotal\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	2004	and	2003.

(c) Fair	values	were	determined	using	bid	prices	reported	by	dealer	markets	and	by	nationally	recognized

investment	banking	firms.	There	is	an	additional	disclosure	of	fair	value	of	financial	instruments	in

Note	11	to	the	domestic	utility	companies	and	System	Energy	financial	statements.

Entergy	Gulf	States	has	annual	sinking	fund	requirements	of	$3.45	million	through	2009	for	its	preferred	stock	outstanding.	Entergy	Gulf	States	has	the	annual	non- cumulative	option	to	redeem,	at	par,	additional	amounts	of	certain	series	of	its	outstanding	preferred	stock.

# NOTE	7.	COMMON	EQUITY	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans

# Dividend	Restrictions

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

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

# Vidalia	Purchased	Power	Agreement	(Entergy	Louisiana)

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

The	domestic	utility	companies	that	are	owners	of	System	Fuels	have	made	loans	to	System	Fuels	to	finance	its	fuel	procurement,	delivery,	and	storage	activities. The	following	loans	outstanding	to	System	Fuels	as	of	December	31,	2004	mature	in	2008:

| Owner | Ownership<br>Percentage | Loan	Outstanding<br>at	December	31,	2004 |
| :--- | :--- | :--- |
| 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	is owned	by	a	non-affiliated	company	(SMEPA),	which	would	share	on	a	pro-rata	basis	in	any	retrospective	premium	assessment	under	the	Price-Anderson	Act).

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

# ANO	1	and	2,	Grand	Gulf,	River	Bend,	and	Waterford	3

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

In	addition,	Waterford	3	and	Grand	Gulf	are	also	covered	under	NEIL's	Accidental	Outage	Coverage	program.	This	coverage	provides	certain	fixed	indemnities	in the	event	of	an	unplanned	outage	that	results	from	a	covered	NEIL	property	damage	loss,	subject	to	a	deductible.	The	following	summarizes	this	coverage	as	of December	31,	2003:

# Waterford	3

Under	 the	 property	 damage	 and	 accidental	 outage	 insurance	 programs,	 Entergy's	 nuclear	 plants	 could	 be	 subject	 to	 assessments	 should	 losses	 exceed	 the accumulated	funds	available	from	NEIL.	As	of	December	31,	2004,	the	maximum	amount	of	such	possible	assessments	per	occurrence	were	$15.1	million	for Entergy	Arkansas,	$11.1	million	for	Entergy	Gulf	States,	$13.0	million	for	Entergy	Louisiana,	$0.06	million	for	Entergy	Mississippi,	$0.06	million	for	Entergy New	Orleans,	and	$11.5	million	for	System	Energy.

# 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.

Upon	implementation	of	SFAS	143	in	2003,	assets	and	liabilities	increased	$1.1	billion	for	the	U.S.	Utility	segment	as	a	result	of	recording	the	asset	retirement obligations	at	their	fair	values	of	$1.1	billion	as	determined	under	SFAS	143,	increasing	utility	plant	by	$287	million,	reducing	accumulated	depreciation	by	$361 million	and	recording	the	related	regulatory	assets	of	$422	million.	The	implementation	of	SFAS	143	for	the	portion	of	River	Bend	not	subject	to	cost-based ratemaking	decreased	earnings	in	the	first	quarter	of	2003	by	$21	million	net-of-tax	as	a	result	of	a	cumulative	effect	of	accounting	change.	In	accordance	with ratemaking	treatment	and	as	required	by	SFAS	71,	the	depreciation	provisions	for	the	domestic	utility	companies	and	System	Energy	include	a	component	for removal	costs	that	are	not	asset	retirement	obligations	under	SFAS	143.	In	accordance	with	regulatory	accounting	principles,	the	domestic	utility	companies	and System	Energy	have	recorded	regulatory	assets	(liabilities)	in	the	following	amounts	to	reflect	their	estimates	of	the	difference	between	estimated	incurred	removal costs	and	estimated	removal	costs	recovered	in	rates	previously	recorded	as	a	component	of	accumulated	depreciation:

|  | December	31, |  |
| :--- | :--- | :--- |
|  | 2004 | 2003 |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $34.9 | $26.6 |
| Entergy\tGulf\tStates | $0.9 | $4.2 |
| Entergy\tLouisiana | ($34.6) | ($26.8) |
| Entergy\tMississippi | $32.7 | $24.4 |
| Entergy\tNew\tOrleans | $1.3 | $2.1 |
| System\tEnergy | $17.1 | $15.1 |

The	cumulative	decommissioning	liabilities	and	expenses	recorded	in	2004	by	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	and	System	Energy	were as	follows:

|  | Liabilities	as	of | Cash	Flow | Cash	Flow | Liabilities	as	of |
| :--- | :--- | :--- | :--- | :--- |
|  | December\t31,\t2003 | Accretion | Estimate | December\t31,\t2004 |
|  |  | (In\tThousands) |  |  |
| ANO\t1\tand\tANO\t2 | $567.5 | $32.9 | ($107.7) | $492.7 |
| River\tBend | $298.8 | $19.7 | ($166.4) | $152.1 |
| Waterford\t3 | $325.3 | $22.0 | - | $347.3 |
| Grand\tGulf | $312.5 | $23.4 | - | $335.9 |

Entergy	periodically	reviews	and	updates	estimated	decommissioning	costs.	The	actual	decommissioning	costs	may	vary	from	the	estimates	because	of	regulatory requirements,	changes	in	technology,	and	increased	costs	of	labor,	materials,	and	equipment.

If	SFAS	143	had	been	applied	by	Entergy	Gulf	States	for	the	portion	of	River	Bend	not	subject	to	cost-based	ratemaking	during	prior	periods,	the	following	impacts would	have	resulted:

|  | Year	Ended<br>December	31,<br>2002 |
| :--- | :--- |
| Entergy\tGulf\tStates |  |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tas\treported | $169,190 |
| Pro\tforma\teffect\tof\tSFAS\t143 | ($2,227) |
| Earnings\tapplicable\tto\tcommon\tstock\t-\tpro\tforma | $166,963 |

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

|  | Decommissioning | Regulatory |
| :--- | :--- | :--- |
|  | Trust\tFair\tValues | Assets |
|  | (In\tMillions) |  |
| ANO\t1\t&amp;\tANO\t2 | $383.8 | $141.2 |
| River\tBend | $291.0 | - |
| Waterford\t3 | $172.1 | $141.6 |
| Grand\tGulf | $205.1 | $97.3 |

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

portion.	These	assessments	are	recovered	through	rates	in	the	same	manner	as	fuel	costs.

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

During	the	years	1997	through	2004,	Entergy	subsidiaries,	Entergy	Services,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi, Entergy	New	Orleans,	and	System	Energy	Resources	reflected	changes	in	tax	depreciation	methods	with	respect	to	certain	types	of	depreciable	property	(e.g.	street lighting,	billing	meters,	and	various	generation	plant	equipment).	As	of	December	31,	2004,	the	cumulative	effect	of	these	changes	results	in	additional	depreciation deductions	generating	a	cash	flow	benefit	of	$45	million	for	Entergy	Arkansas,	$38	million	for	Entergy	Gulf	States,	$32	million	for	Entergy	Louisiana,	$19	million for	Entergy	Mississippi,	$6	million	for	Entergy	New	Orleans,	and	$12	million	for	System	Energy.	As	of	December	31,	2004,	the	related	IRS	interest	exposure	if	the deduction	is	ultimately	disallowed	is	$13	million	for	Entergy	Arkansas,	$11	million	for	Entergy	Gulf	States,	$9	million	for	Entergy	Louisiana,	$6	million	for Entergy	Mississippi,	$2	million	for	Entergy	New	Orleans,	and	$3	million	for	System	Energy.	This	benefit	reverses	over	time	and	will	also	fluctuate	with	each	year's addition	to	those	types	of	assets.	Due	to	the	temporary	nature	of	the	tax	benefit,	the	potential	interest	charge	represents	the	total	net	exposure	of	the	domestic	utility companies	and	System	Energy.

# CashPoint	Bankruptcy	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans)

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

| Entergy	Arkansas | $1.8 |
| :--- | :--- |
| Entergy\tGulf\tStates | $7.7 |
| Entergy\tLouisiana | $8.8 |
| Entergy\tMississippi | $4.3 |
| Entergy\tNew\tOrleans | $2.4 |

# Environmental	Issues	(Entergy	Gulf	States)

Entergy	Gulf	States	has	been	designated	as	a	PRP	for	the	cleanup	of	certain	hazardous	waste	disposal	sites.	As	of	December	31,	2004,	Entergy	Gulf	States	does	not expect	the	remaining	clean-up	costs	to	exceed	its	recorded	liability	of	$1.5	million	for	the	remaining	sites	at	which	the	EPA	has	designated	Entergy	Gulf	States	as	a PRP.

# City	Franchise	Ordinances	(Entergy	New	Orleans)

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

# Waterford	3	Lease	Obligations	(Entergy	Louisiana)

On	September	28,	1989,	Entergy	Louisiana	entered	into	three	identical	transactions	for	the	sale	and	leaseback	of	undivided	interests	(aggregating	approximately 9.3%) in	Waterford	 3.	In	July	1997,	Entergy	Louisiana	caused	the	lessors	to	issue	$307.6	million	aggregate	principal	amount	of	Waterford	3	Secured	Lease Obligation	Bonds,	8.09%	Series	due	2017,	to	refinance	the	outstanding	bonds	originally	issued	to	finance	the	purchase	of	the	undivided	interests	by	the	lessors.	The lease	payments	were	reduced	 to	reflect	 the	 lower	 interest	costs.	Upon	 the	occurrence	of	certain	events,	Entergy	Louisiana	may	be	obligated	 to	pay	amounts sufficient	to	permit	the	termination	of	the	lease	transactions	and	may	be	required	to	assume	the	outstanding	bonds	issued	to	finance,	in	part,	the	lessors'	acquisition of	the	undivided	interests	in	Waterford	3.

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

Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	New	Orleans,	System	Energy,	or	their	affiliates,	are	defendants	in	numerous	lawsuits	filed	by former	employees	asserting	that	they	were	wrongfully	terminated	and/or	discriminated	against	on	the	basis	of	age,	race,	sex,	and/or	other	protected	characteristics. Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	System	Energy,	and	their	affiliates	are	vigorously	defending these	suits	and	deny	any	liability	to	the	plaintiffs.	Nevertheless,	no	assurance	can	be	given	as	to	the	outcome	of	these	cases.

# Asbestos	and	Hazardous	Material	Litigation	(Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	New	Orleans)

Numerous	lawsuits	have	been	filed	in	federal	and	state	courts	in	Texas,	Louisiana,	and	Mississippi	primarily	by	contractor	employees	in	the	1950-1980	timeframe against	Entergy	Gulf	States,	Entergy	Louisiana,	and	Entergy	New	Orleans,	and	Entergy	Mississippi	as	premises	owners	of	power	plants,	for	damages	caused	by alleged	exposure	 to	asbestos	or	other	hazardous	material.	Many	other	defendants	are	named	in	these	lawsuits	as	well.	Presently,	there	are	approximately	480 lawsuits	 involving	 approximately	 10,000	 claims.	Management	 believes	 that	 adequate	 provisions	 have	 been	 established	 to	 cover	 any	 exposure.	Additionally, negotiations	continue	with	 insurers	 to	recover	more	reimbursement,	while	new	coverage	 is	being	secured	 to	minimize	anticipated	future	potential	exposures. Management	believes	that	loss	exposure	has	been	and	will	continue	to	be	handled	successfully	so	that	the	ultimate	resolution	of	these	matters	will	not	be	material,	in the	aggregate,	to	its	financial	position	or	results	of	operation.

# Grand	Gulf	-	Related	Agreements

# Capital	Funds	Agreement	(System	Energy)

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

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

System	Energy	has	agreed	to	sell	all	of	its	90%	share	of	capacity	and	energy	from	Grand	Gulf	to	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and Entergy	New	Orleans	in	accordance	with	specified	percentages	(Entergy	Arkansas-36%,	Entergy	Louisiana-14%,	Entergy	Mississippi-33%,	and	Entergy	New Orleans-17%)	as	ordered	by	FERC.	Charges	under	this	agreement	are	paid	in	consideration	for	the	purchasing	companies'	respective	entitlement	to	receive	capacity and	energy	and	are	payable	irrespective	of	the	quantity	of	energy	delivered	so	long	as	the	unit	remains	in	commercial	operation.	The	agreement	will	remain	in	effect until	terminated	by	the	parties	and	the	termination	is	approved	by	FERC,	most	likely	upon	Grand	Gulf's	retirement	from	service.	Monthly	obligations	are	based	on actual	capacity	and	energy	costs.	The	average	monthly	payments	for	2004	under	the	agreement	are	approximately	$16.6	million	for	Entergy	Arkansas,	$6.7	million for	Entergy	Louisiana,	$13.7	million	for	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.	In	connection	with	the	equity	funding	of	the	sale	and	leaseback	arrangements,	letters	of	credit	are	required	to	be	maintained	to	secure	certain amounts	payable	for	the	benefit	of	the	equity	investors	by	System	Energy	under	the	leases.	The	current	letters	of	credit	are	effective	until	May	29,	2009.

Under	 the	 provisions	 of	 the	 reimbursement	 agreement	 relating	 to	 the	 letters	 of	 credit,	 System	 Energy	 has	 agreed	 to	 a	 number	 of	 covenants	 regarding	 the maintenance	of	certain	capitalization	and	fixed	charge	coverage	ratios.		System	Energy	agreed,	during	the	term	of	the	reimbursement	agreement,	to	maintain	a	ratio of	debt	to	total	liabilities	and	equity	less	than	or	equal	to	70%.	In	addition,	System	Energy	must	maintain,	with	respect	to	each	fiscal	quarter	during	the	term	of	the reimbursement	agreement,	a	ratio	of	adjusted	net	income	to	interest	expense	of	at	least	1.50	times	earnings.		As	of	December	31,	2004,	System	Energy's	debt	ratio was	approximately	32.5%,	and	its	fixed	charge	coverage	ratio	for	2004	was	approximately	4.12,	calculated,	in	each	case,	as	prescribed	in	the	reimbursement agreement.

# NOTE	9.	LEASES	(Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	and	System	Energy)

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

# Capital	Leases

|  | Entergy | Entergy |
| :--- | :--- | :--- |
| Year | Arkansas | Mississippi |
|  | (In\tThousands) |  |
| 2005 | $9,610 | $50 |
| 2006 | 5,682 | 42 |
| 2007 | 3,427 | 11 |
| 2008 | 1,754 | - |
| 2009 | 237 | - |

| Years	thereafter | 2,606 | - |
| :--- | :--- | :--- |
| Minimum\tlease\tpayments | 23,316 | 103 |
| Less:\tAmount\trepresenting\tinterest | 3,386 | 2 |
| Present\tvalue\tof\tnet\tminimum\tlease | $19,930 | $101 |

|  | Entergy | Entergy | Entergy | Entergy |
| :--- | :--- | :--- | :--- | :--- |
| Year | Arkansas | Gulf\tStates | Louisiana | Mississippi |
|  |  | (In\tThousands) | (In\tThousands) |  |
| 2005 | $23,743 | $26,744 | $9,974 | $7,421 |
| 2006 | 20,029 | 23,942 | 5,647 | 6,596 |
| 2007 | 17,563 | 17,223 | 5,109 | 3,552 |
| 2008 | 14,977 | 9,742 | 3,546 | 3,039 |
| 2009 | 8,622 | 9,108 | 2,346 | 2,676 |
| Years\tthereafter | 54,339 | 115,216 | 2,524 | 11,068 |
| Minimum\tlease\tpayments | $139,273 | $201,975 | $29,146 | $34,352 |

|  | Entergy | Entergy | Entergy | Entergy |
| :--- | :--- | :--- | :--- | :--- |
| Year | Arkansas | Gulf\tStates | Louisiana | Mississippi |
|  |  | (In\tMillions) | (In\tMillions) |  |
| 2004 | $17.4 | $24.4 | $11.9 | $3.4 |
| 2003 | $19.4 | $26.5 | $13.8 | $5.4 |
| 2002 | $20.8 | $25.8 | $13.6 | $5.4 |

In	addition	to	the	above	rental	expense,	railcar	operating	lease	payments	and	oil	tank	facilities	lease	payments	are	recorded	in	fuel	expense	in	accordance	with regulatory	treatment.	Railcar	operating	lease	payments	were	$9.3	million	in	2004,	$6.8	million	in	2003,	and	$8.3	million	in	2002	for	Entergy	Arkansas	and	$2.0 million	in	2004,	$1.8	million	in	2003,	and	$2.0	million	in	2002	for	Entergy	Gulf	States.	Oil	tank	facilities	lease	payments	for	Entergy	Mississippi	were	$3.2	million for	2004	and	$3.1	million	for	each	of	the	years	2003	and	2002.

Lease	payments	are	based	on	nuclear	fuel	use.	The	table	below	represents	the	total	nuclear	fuel	lease	payments	(principal	and	interest)	as	well	as	the	separate	interest component	charged	to	operations	in	2004,	2003,	and	2002:

|  | Lease |  | Lease |  | Lease |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Payments | Interest | Payments | Interest | Payments | Interest |
|  |  |  | (In\tMillions) |  |  |  |
| Entergy\tArkansas | $53.0 | $4.3 | $49.9 | $3.3 | $49.6 | $3.2 |
| Entergy\tGulf\tStates | 29.7 | 3.2 | 27.8 | 3.0 | 29.2 | 3.0 |
| Entergy\tLouisiana | 36.1 | 2.5 | 32.3 | 2.4 | 32.9 | 2.6 |
| System\tEnergy | 27.8 | 2.8 | 32.0 | 3.1 | 26.1 | 2.5 |
| Total | $146.6 | $12.8 | $142.0 | $11.8 | $137.8 | $11.3 |

| 2005 | $14,554 |
| :--- | :--- |
| 2006 | 18,261 |
| 2007 | 18,754 |
| 2008 | 22,606 |
| 2009 | 32,452 |
| Years\tthereafter | 334,062 |
| Total | 440,689 |
| Less:\tAmount\trepresenting\tinterest | 192,964 |

# Grand	Gulf	Lease	Obligations	(System	Energy)

# NOTE	 10.	 RETIREMENT	 AND	 OTHER	 POSTRETIREMENT	 BENEFITS (Entergy	 Arkansas,	 Entergy	 Gulf	 States,	 Entergy	 Louisiana,	 Entergy Mississippi,	Entergy	New	Orleans,	and	System	Energy)

Entergy's	domestic	utility	companies	and	System	Entergy	participate	in	two	of	Entergy's	pension	plans:	"Entergy	Corporation	Retirement	Plan	for	Non-Bargaining Employees"	and	"Entergy	Corporation	Retirement	Plan	for	Bargaining	Employees."	Entergy	Corporation	and	its	subsidiaries	fund	pension	costs	in	accordance	with contribution	guidelines	established	by	the	Employee	Retirement	Income	Security	Act	of	1974,	as	amended,	and	the	Internal	Revenue	Code	of	1986,	as	amended. The	assets	of	the	plans	include	common	and	preferred	stocks,	fixed-income	securities,	interest	in	a	money	market	fund,	and	insurance	contracts.	As	of	December	31, 2004	and	2003,	Entergy's	domestic	utility	companies	and	System	Energy	recognized	an	additional	minimum	pension	liability	for	the	excess	of	the	accumulated benefit	obligation	over	the	fair	market	value	of	plan	assets.	In	accordance	with	SFAS	87,	an	offsetting	intangible	asset,	up	to	the	amount	of	any	unrecognized	prior service	cost,	was	also	recorded,	with	the	remaining	offset	to	the	liability	recorded	as	a	regulatory	asset,	reflective	of	the	recovery	mechanism	for	pension	costs	in Entergy's	jurisdictions.	Entergy's	domestic	utility	companies'	and	System	Energy's	pension	costs	are	recovered	from	customers	as	a	component	of	cost	of	service	in each	of	its	jurisdictions.	Entergy	uses	a	December	31	measurement	date	for	its	pension	plans.

Total	2004,	2003,	and	2002	pension	cost	of	the	domestic	utility	companies	and	System	Energy,	including	amounts	capitalized,	included	the	following	components:

| 2004 | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $11,941 | $9,693 | $7,009 | $3,615 | $1,569 | $3,386 |
| Interest\tcost\ton\tprojected |  |  |  |  |  |  |
| \t\tbenefit\tobligation | 35,846 | 28,471 | 21,790 | 11,915 | 4,465 | 5,189 |
| Expected\treturn\ton\tassets | (36,913) | (39,682) | (27,510) | (14,716) | (2,568) | (4,556) |
| Amortization\tof\ttransition\tasset | - | - | - | - | - | (319) |
| Amortization\tof\tprior\tservice\tcost | 1,662 | 1,511 | 650 | 513 | 226 | 67 |
| Recognized\tnet\tloss | 3,952 | 405 | 1,344 | 794 | 898 | 788 |
| Net\tpension\tcost | $16,488 | $398 | $3,283 | $2,121 | $4,590 | $4,555 |

| 2003 | Entergy<br>Arkansas | Entergy<br>Gulf	States | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $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	of	transition	asset | - | - | - | - | - | (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\n\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 |

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

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tProjected\tBenefit |  |  |  |  |  |  |
| Obligation\t(PBO) |  |  |  |  |  |  |
| Balance\tat\t12/31/03 | $565,004 | $467,707 | $340,212 | $190,184 | $67,866 | $79,033 |
| Service\tcost | 11,941 | 9,693 | 7,009 | 3,615 | 1,569 | 3,386 |
| Interest\tcost | 35,846 | 28,471 | 21,790 | 11,915 | 4,465 | 5,189 |
| Actuarial\tloss | 46,590 | 17,687 | 32,309 | 13,200 | 8,169 | 9,175 |
| Benefits\tpaid | (34,565) | (27,348) | (22,218) | (12,771) | (3,719) | (1,784) |
| Balance\tat\t12/31/04 | $624,816 | $496,210 | $379,102 | $206,143 | $78,350 | $94,999 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/03 | $423,214 | $448,490 | $316,669 | $169,958 | $29,565 | $45,375 |
| Actual\treturn\ton\tplan\tassets | 39,265 | 42,380 | 31,046 | 16,268 | 2,849 | 8,667 |
| Employer\tcontributions | 5,342 | 17 | 3,907 | 1,823 | 2,118 | 3,742 |
| Benefits\tpaid | (34,565) | (27,348) | (22,218) | (12,771) | (3,719) | (1,784) |
| Fair\tvalue\tof\tassets\tat\t12/31/04 | $433,256 | $463,539 | $329,404 | $175,278 | $30,813 | $56,000 |
| Funded\tstatus | ($191,560) | ($32,671) | ($49,698) | ($30,865) | ($47,537) | ($38,999) |
| Amounts\tnot\tyet\trecognized |  |  |  |  |  |  |
| in\tthe\tbalance\tsheet |  |  |  |  |  |  |
| Unrecognized\ttransition\tasset | - | - | - | - | - | (277) |
| Unrecognized\tprior\tservice\tcost | 8,177 | 5,938 | 3,762 | 2,692 | 1,263 | 286 |
| Unrecognized\tnet\tloss | 133,821 | 38,628 | 75,962 | 36,825 | 26,357 | 20,298 |
| Prepaid/(accrued)\tpension\tcost |  |  |  |  |  |  |
| recognized\tin\tthe\tbalance\tsheet | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) |
| Amounts\trecognized\tin |  |  |  |  |  |  |
| the\tbalance\tsheet |  |  |  |  |  |  |
| Prepaid/(accrued)\tpension | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) |
| liability |  |  |  |  |  |  |
| Additional\tminimum\tpension\nliability | (81,161) | - | (38,871) | (23,492) | (16,928) | (7,678) |
| Intangible\tasset | 10,313 | - | 4,759 | 3,308 | 1,698 | 247 |
| Regulatory\tasset | 70,848 | - | 34,112 | 20,184 | 15,230 | 7,431 |
| Net\tamount\trecognized | ($49,562) | $11,895 | $30,026 | $8,652 | ($19,917) | ($18,692) |

|  | 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\tloss | 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 |
| Benefits\tpaid | (28,445) | (25,611) | (19,332) | (10,634) | (2,559) | (366) |

| Fair	value	of	assets	at	12/31/03 | $423,214 | $448,490 | $316,669 | $169,958 | $29,565 | $45,375 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Funded\tstatus | ($141,790) | ($19,217) | ($23,543) | ($20,226) | ($38,301) | ($33,658) |
| Amounts\tnot\tyet\trecognized |  |  |  |  |  |  |
| in\tthe\tbalance\tsheet |  |  |  |  |  |  |
| Unrecognized\ttransition\tasset | - | - | - | - | - | (596) |
| Unrecognized\tprior\tservice\tcost | 9,839 | 7,449 | 4,412 | 3,206 | 1,489 | 353 |
| Unrecognized\tnet\tloss | 93,535 | 24,044 | 48,533 | 25,970 | 19,367 | 16,021 |
| Prepaid/(accrued)\tpension\tcost |  |  |  |  |  |  |
| recognized\tin\tthe\tbalance\tsheet | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |
| Amounts\trecognized\tin |  |  |  |  |  |  |
| the\tbalance\tsheet: |  |  |  |  |  |  |
| Prepaid/(accrued)\tpension | ($38,416) | $12,276 | $29,402 | $8,950 | ($17,445) | ($17,880) |
| liability |  |  |  |  |  |  |
| 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) |

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

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

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

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

Pursuant	to	regulatory	directives,	Entergy	Arkansas,	Entergy	Mississippi,	Entergy	New	Orleans,	the	portion	of	Entergy	Gulf	States	regulated	by	the	PUCT,	and System	Energy	fund	postretirement	benefit	obligations	collected	 in	rates.	System	Energy	is	funding,	on	behalf	of	Entergy	Operations,	postretirement	benefits associated	with	Grand	Gulf.	Entergy	Louisiana	and	Entergy	Gulf	States	continue	to	recover	a	portion	of	these	benefits	regulated	by	the	LPSC	and	FERC	on	a	pay- as-you-go	basis.

# Components	of	Net	Other	Postretirement	Benefit	Cost

Total	2004,	2003,	and	2002	other	postretirement	benefit	costs	of	the	domestic	utility	companies	and	System	Energy,	including	amounts	capitalized	and	deferred, included	the	following	components:

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |
| \t\tduring\tthe\tperiod | $3,860 | $5,328 | $2,371 | $1,213 | $662 | $1,389 |
| Interest\tcost\ton\tAPBO | 10,075 | 11,050 | 6,641 | 3,222 | 3,204 | 1,430 |
| Expected\treturn\ton\tassets | (6,210) | (4,995) | - | (2,554) | (2,263) | (1,362) |
| Amortization\tof\ttransition |  |  |  |  |  |  |
| \t\tobligation | 1,068 | 4,589 | 1,202 | 431 | 2,121 | 15 |
| Amortization\tof\tprior\tservice\tcost | 27 | - | 98 | 16 | 38 | (361) |
| Recognized\tnet\tloss | 3,937 | 1,620 | 2,003 | 1,503 | 522 | 358 |
| Net\tother\tpostretirement\tbenefit |  |  |  |  |  |  |
| \t\tcost | $12,757 | $17,592 | $12,315 | $3,831 | $4,284 | $1,469 |

|  | 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 |  |  |  |  |  |  |
| \t\tobligation | 3,327 | 5,307 | 2,238 | 1,301 | 2,449 | 135 |
| Amortization\tof\tprior\tservice\tcost | 143 | 163 | 82 | 51 | 52 | (140) |
| Recognized\tnet\tloss | 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 |  |  |  |  |  |  |
| \t\tcost | $29,375 | $26,524 | $19,411 | $6,983 | $6,374 | $4,970 |

|  | 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 | $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 |  |  |  |  |  |  |
| \t\tobligation | 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 |  |  |  |  |  |  |
| \t\tcost | $16,060 | $15,871 | $12,566 | $4,448 | $4,906 | $1,682 |

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |
| Balance\tat\t12/31/03 | $187,259 | $194,205 | $112,675 | $57,786 | $55,062 | $25,466 |
| Service\tcost | 3,860 | 5,328 | 2,371 | 1,213 | 662 | 1,389 |
| Interest\tcost | 10,075 | 11,050 | 6,641 | 3,222 | 3,204 | 1,430 |
| Actuarial\tloss | 10,714 | 9,086 | 8,175 | 6,787 | 3,624 | 1,441 |
| Benefits\tpaid | (15,964) | (13,832) | (9,843) | (5,307) | (5,967) | (1,719) |
| Plan\tamendments\t(a) | (18,279) | (6,406) | (5,546) | (6,894) | (2,582) | (1,125) |
| Plan\tparticipant\tcontributions | 1,693 | 1,833 | 1,323 | 771 | 846 | 20 |
| Balance\tat\t12/31/04 | 179,358 | 201,264 | 115,796 | 57,578 | 54,849 | 26,902 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\t12/31/03 | $68,876 | $59,511 | $- | $28,932 | $33,158 | $16,821 |
| Actual\treturn\ton\tplan\tassets | 5,657 | 4,773 | - | 2,154 | 2,340 | 1,495 |
| Employer\tcontributions | 16,729 | 14,540 | 8,520 | 5,521 | 4,870 | 4,691 |
| Plan\tparticipant\tcontributions | 1,693 | 1,833 | 1,323 | 771 | 846 | 20 |
| Benefits\tpaid | (15,964) | (13,832) | (9,843) | (5,307) | (5,967) | (1,719) |
| Fair\tvalue\tof\tassets\tat\t12/31/04 | $76,991 | $66,825 | $- | $32,071 | $35,247 | $21,308 |
| Funded\tstatus | ($102,367) | ($134,439) | ($115,796) | ($25,507) | ($19,602) | ($5,594) |
| Amounts\tnot\tyet\trecognized |  |  |  |  |  |  |
| in\tthe\tbalance\tsheet |  |  |  |  |  |  |
| Unrecognized\ttransition\tobligation | 6,567 | 30,310 | 3,057 | 2,810 | 13,929 | 119 |
| Unrecognized\tprior\tservice\tcost | (4,013) | - | 919 | (1,015) | 418 | (2,805) |
| Unrecognized\tnet\tloss | 79,185 | 57,089 | 44,723 | 28,429 | 15,620 | 9,699 |
| Prepaid/(accrued)\tpostretirement |  |  |  |  |  |  |
| benefit\tcost\trecognized\tin\tthe |  |  |  |  |  |  |
| balance\tsheet | ($20,628) | ($47,040) | ($67,097) | $4,717 | $10,365 | $1,419 |

(a) Reflects	plan	design	changes,	including	a	change	in	participation	assumption	for	certain	bargaining employees	at	Entergy	Arkansas	and	Entergy	Mississippi,	effective	January	1,	2004.

|  | 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\tpaid | (11,523) | (11,411) | (7,816) | (4,040) | (4,761) | (616) |
| Plan\tamendments\t(a) | (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 | $- | $23,420 | $28,490 | $13,569 |
| Actual\treturn\ton\tplan\tassets | 6,290 | 6,587 | - | 2,979 | 2,614 | 1,475 |
| Benefits\tpaid | (11,523) | (11,411) | (7,816) | (4,040) | (4,761) | (616) |
| Employer\tcontributions | 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 | $- | $28,932 | $33,158 | $16,821 |
| Funded\tstatus | ($118,383) | ($134,694) | ($112,675) | ($28,854) | ($21,904) | ($8,645) |

# Amounts	not	yet	recognized

| Unrecognized	transition	obligation | 21,928 | 41,305 | 10,822 | 9,136 | 19,088 | 134 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Unrecognized\tprior\tservice\tcost | - | - | - | - | - | (2,040) |
| Unrecognized\tnet\tloss | 71,855 | 49,401 | 38,551 | 22,745 | 12,595 | 8,748 |
| Prepaid/(accrued)\tpostretirement |  |  |  |  |  |  |
| benefit\tcost\trecognized\tin\tthe |  |  |  |  |  |  |
| balance\tsheet | ($24,600) | ($43,988) | ($63,302) | $3,027 | $9,779 | ($1,803) |

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

|  | Pension |  | Postretirement | Postretirement |
| :--- | :--- | :--- | :--- | :--- |
|  | 2004 | 2003 | 2004 | 2003 |
| Domestic\tEquity\tSecurities | 46% | 56% | 38% | 37% |
| International\tEquity\tSecurities | 21% | 14% | 14% | 0% |
| Fixed\tIncome\tSecurities | 31% | 28% | 47% | 60% |
| Other | 2% | 2% | 1% | 3% |

|  | Pension | Postretirement |
| :--- | :--- | :--- |
| Domestic\tEquity\tSecurities | 45% | 37% |
| International\tEquity\tSecurities | 20% | 14% |
| Fixed\tIncome\tSecurities | 31% | 49% |
| Other\t(Cash\tand\tGACs) | 4% | 0% |

These	allocation	percentages	combined	with	each	asset	class'	expected	investment	return	produced	an	aggregate	return	expectation	for	the	five	years	following	the study	of	7.6%	for	pension	assets,	5.4%	for	taxable	postretirement	assets,	and	7.2%	for	non-taxable	postretirement	assets.	These	returns	are	not	inconsistent	with Entergy's	disclosed	expected	pre-tax	return	on	assets	of	8.5%	over	the	life	of	the	respective	liabilities.

The	accumulated	benefit	obligation	for	the	domestic	utility	companies	and	System	Entergy	as	December	31,	2004	and	2003	was:

|  | December	31, |  |
| :--- | :--- | :--- |
|  | 2004 | 2003 |
|  | (In\tThousands) |  |
| Entergy\tArkansas | $558,283 | $509,382 |
| Entergy\tGulf\tStates | $449,986 | $426,320 |
| Entergy\tLouisiana | $341,681 | $309,066 |
| Entergy\tMississippi | $189,119 | $174,245 |
| Entergy\tNew\tOrleans | $69,202 | $59,610 |
| System\tEnergy | $79,641 | $64,661 |

| 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) |  |  |  |  |  |  |
| 2005 | $34,240 | $26,852 | $21,707 | $12,630 | $3,634 | $1,764 |
| 2006 | $34,660 | $27,037 | $21,790 | $12,771 | $3,648 | $1,783 |
| 2007 | $35,332 | $27,358 | $21,956 | $13,000 | $3,676 | $1,814 |
| 2008 | $36,266 | $27,885 | $22,290 | $13,326 | $3,731 | $1,859 |
| 2009 | $37,674 | $28,718 | $22,840 | $13,821 | $3,823 | $1,927 |
| 2010\t-\t2014 | $227,605 | $167,679 | $130,644 | $82,964 | $21,870 | $11,552 |

# Estimated	Future

| Other	Postretirement<br>Benefits	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) |  |  |  |  |  |  |
| 2005 | $13,588 | $12,638 | $8,528 | $4,127 | $4,565 | $1,311 |
| 2006 | $12,989 | $12,280 | $8,182 | $3,849 | $4,162 | $1,390 |
| 2007 | $13,362 | $12,901 | $8,402 | $3,993 | $4,268 | $1,464 |
| 2008 | $13,500 | $13,381 | $8,545 | $4,095 | $4,353 | $1,522 |
| 2009 | $13,707 | $13,808 | $8,642 | $4,133 | $4,443 | $1,620 |
| 2010\t-\t2014 | $67,855 | $74,755 | $43,297 | $22,011 | $21,774 | $9,788 |

The	domestic	utility	companies	and	System	Energy	expect	to	contribute	the	following	to	the	pension	and	other	postretirement	plans	in	2005:

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Pension\tContributions | $20,560 | $18,948 | $2,622 | $3,416 | $15,667 | $9,266 |
| Other\tPostretirement |  |  |  |  |  |  |
| \t\tContributions | $16,063 | $14,317 | $8,528 | $4,159 | $4,436 | $1,732 |

The	change	in	the	minimum	pension	liability	had	no	effect	on	other	comprehensive	income	at	the	domestic	utility	companies	and	System	Energy	in	2004	or	2003. The	change	in	the	minimum	pension	liability	included	in	regulatory	assets	at	each	of	the	domestic	utility	companies	and	System	Energy	was	as	follows	for	2004	and 2003:

|  | Entergy | Entergy	Gulf | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | States | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2004 | $29,191 | $- | $34,112 | $13,820 | $4,865 | $370 |
| 2003 | $22,600 | $- | ($38,755) | ($3,446) | $7,395 | $7,061 |

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

|  | 1	Percentage	Point	Increase | 1	Percentage	Point	Increase | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Impact\ton\tthe |  | Impact\ton\tthe |
|  |  | sum\tof\tservice |  | sum\tof\tservice |
|  | Impact\ton\tthe | costs\tand | Impact\ton\tthe | costs\tand |
| 2004 | APBO | interest\tcost | APBO | interest\tcost |
|  |  | Increase\t(Decrease) | Increase\t(Decrease) |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tArkansas | $14,980 | $1,548 | ($13,825) | ($1,378) |
| Entergy\tGulf\tStates | $19,685 | $2,205 | ($17,932) | ($1,918) |
| Entergy\tLouisiana | $9,930 | $1,021 | ($9,146) | ($907) |
| Entergy\tMississippi | $4,785 | $479 | ($4,418) | ($428) |
| Entergy\tNew\tOrleans | $3,998 | $362 | ($3,726) | ($327) |
| System\tEnergy | $3,152 | $448 | ($2,821) | ($384) |

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| \t\t\t\t\tPension | 6.00% | 6.25% | 6.75% |
| \t\t\t\tOther\tpostretirement | 6.00% | 6.71% | 6.75% |
| Weighted-average\trate\tof\tincrease |  |  |  |
| \t\tin\tfuture\tcompensation\tlevels | 3.25% | 3.25% | 3.25% |
| 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 | 8.50% | 8.75% | 8.75% |

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate |  |  |  |
| \t\t\t\tPension | 6.25% | 6.75% | 7.50% |
| \t\t\t\tOther\tpostretirement | 6.71% | 6.75% | 7.50% |
| Weighted-average\trate\tof\tincrease |  |  |  |
| \t\tin\tfuture\tcompensation\tlevels | 3.25% | 3.25% | 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% | 8.75% | 9.00% |

The	domestic	utility	companies'	and	System	Energy's	remaining	pension	transition	assets	are	being	amortized	over	the	greater	of	the	remaining	service	period	of active	participants	or	15	years	ending	in	2005,	and	their	SFAS	106	transition	obligations	are	being	amortized	over	20	years	ending	in	2012.

In	the	second	half	of	2003,	the	domestic	utility	companies	and	System	Energy	offered	a	voluntary	severance	program	to	certain	groups	of	employees.	As	a	result	of this	program,	in	the	fourth	quarter	2003	the	domestic	utility	companies	and	System	Energy	recorded	additional	pension	and	postretirement	costs	(including	amounts capitalized)	 of	 $53.9	 million	 for	 special	 termination	 benefits	 and	 plan	 curtailment	 charges.	These	 amounts	 are	 included	 in	 the	 net	 pension	 cost	 and	 net postretirement	benefit	cost	for	the	year	ended	December	31,	2003.

In	December	2003,	the	President	signed	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	into	law.	The	Act	introduces	a	prescription drug	benefit	under	Medicare	(Part	D),	starting	in	2006,	as	well	as	a	federal	subsidy	to	employers	who	provide	a	retiree	prescription	drug	benefit	that	is	at	least actuarially	equivalent	to	Medicare	Part	D.	At	December	2003,	specific	authoritative	guidance	on	the	accounting	for	the	federal	subsidy	was	pending.	As	allowed	by Financial	Accounting	 Standards	 Board	 Staff	 Position	 No.	 FAS	 106-1,	 Entergy	 elected	 to	 record	 an	 estimate	 of	 the	 effects	 of	 the	Act	 in	 accounting	 for	 its postretirement	benefit	plans	at	December	31,	2003,	under	SFAS	106	and	in	providing	disclosures	required	by	SFAS	No.	132	(revised	2003),	Employers'	Disclosures about	Pensions	and	Other	Postretirement	Benefits.	At	December	31,	2003,	based	on	actuarial	analysis	of	prescription	drug	benefits,	estimated	future	Medicare subsidies	were	expected	to	reduce	the	December	31,	2003	Accumulated	Postretirement	Benefit	Obligation	by	$56	million.	For	the	year	ended	December	31,	2003 the	impact	of	the	Act	on	net	postretirement	benefit	cost	was	immaterial,	as	it	reflected	only	one	month's	impact	of	the	Act.

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

The	actuarially	estimated	effect	of	future	Medicare	subsidies	was	as	follows:

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \tArkansas | \tGulf\tStates \tLouisiana\tMississippi\tNew\tOrleans\tEnergy | \tGulf\tStates \tLouisiana\tMississippi\tNew\tOrleans\tEnergy | \tGulf\tStates \tLouisiana\tMississippi\tNew\tOrleans\tEnergy | \tGulf\tStates \tLouisiana\tMississippi\tNew\tOrleans\tEnergy | \tGulf\tStates \tLouisiana\tMississippi\tNew\tOrleans\tEnergy |
|  |  |  | Increase\t(Decrease) | Increase\t(Decrease) |  |  |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Impact\ton\t12/31/2003\tAPBO | ($28,824) | ($25,603) | ($16,194) | ($9,888) | ($8,035)\t($3,811) | ($8,035)\t($3,811) |
| Impact\ton\t12/31/2004\tAPBO | ($35,928) | ($31,846) | ($20,085) | ($12,227) | ($9,742)\t($4,982) | ($9,742)\t($4,982) |
| Impact\ton\t2004\tother |  |  |  |  |  |  |
| postretirement\tbenefit\tcost | ($4,999) | ($4,405) | ($2,752) | ($1,657) | ($1,248) | ($815) |

# NOTE	11.	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.	Gains	totaling	approximately	$6.4	million	were	realized	during	2004	on	the	maturity	of	cash	flow hedges.	These	realized	gains	resulted	from	foreign	currency	hedges	related	to	Euro-denominated	nuclear	fuel	acquisition	contracts,	and	related	gains	or	losses,	when realized,	are	included	in	the	capitalized	cost	of	nuclear	fuel.	The	ineffective	portion	of	the	change	in	the	value	of	Entergy	Gulf	States'	cash	flow	hedges	during	2004 was	insignificant.	Entergy	Gulf	States	has	no	outstanding	cash	flow	hedges	as	of	December	31,	2004.

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

|  |  | Total | Total |
| :--- | :--- | :--- | :--- |
|  | Fair | Unrealized | Unrealized |
| 2004 | Value | Gains | Losses |
|  |  | (In\tMillions) |  |
| Equity | $189.5 | $66.6 | $1.6 |
| Debt\tSecurities | 194.3 | 4.3 | 1.9 |
|  | $383.8 | $70.9 | $3.5 |

| Equity | $168.3 | $47.2 | $- |
| :--- | :--- | :--- | :--- |
| Debt\tSecurities | 192.2 | 7.0 | 1.2 |
|  | $360.5 | $54.2 | $1.2 |

|  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Gross |  | Gross |
|  | Fair | Unrealized | Fair | Unrealized |
|  | Value | Losses | Value | Losses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.7 | $- | $87.4 | $1.6 |
| More\tthan\t12\tmonths | 12.2 | 1.6 | 12.2 | 0.3 |
|  | $12.9 | $1.6 | $99.6 | $1.9 |

During	the	year	ended	December	31,	2004,	the	proceeds	from	the	dispositions	of	securities	amounted	to	$1.7	million	with	gross	gains	of	$17,098	and	gross	losses	of $18,274.

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

|  |  | Total | Total |
| :--- | :--- | :--- | :--- |
|  | Fair | Unrealized | Unrealized |
| 2004 | Value | Gains | Losses |
|  |  | (In\tMillions) |  |
| Equity | $138.1 | $20.4 | $0.8 |
| Debt\tSecurities | 152.9 | 8.8 | 0.2 |
|  | $291.0 | $29.2 | $1.0 |
| \t\tTotal |  |  |  |
| 2003 |  |  |  |
| Equity | $119.4 | $8.0 | $0.2 |
| Debt\tSecurities | 148.5 | 10.4 | 1.0 |
|  | $267.9 | $18.4 | $1.2 |

|  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Gross |  | Gross |
|  | Fair | Unrealized | Fair | Unrealized |
|  | Value | Losses | Value | Losses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.6 | $- | $10.0 | $0.1 |
| More\tthan\t12\tmonths | 10.5 | 0.8 | 2.3 | 0.1 |
|  | $11.1 | $0.8 | $12.3 | $0.2 |

|  | Fair |
| :--- | :--- |
|  | Value |
|  | (In\tMillions) |
| less\tthan\t1\tyear | $8.7 |
| 1\tyear\t-\t5\tyears | 42.0 |
| 5\tyears\t-\t10\tyears | 51.3 |
| 10\tyears\t-\t15\tyears | 37.7 |
| 15\tyears\t-\t20\tyears | 11.0 |
| 20\tyears+ | 2.2 |

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

|  |  | Total | Total |
| :--- | :--- | :--- | :--- |
|  | Fair | Unrealized | Unrealized |
| 2004 | Value | Gains | Losses |
|  |  | (In\tMillions) |  |
| Equity | $92.5 | $17.1 | $2.5 |
| Debt\tSecurities | 79.6 | 2.8 | 0.8 |
|  | $172.1 | $19.9 | $3.3 |
| \t\tTotal |  |  |  |
| 2003 |  |  |  |
| Equity | $74.6 | $6.0 | $- |
| Debt\tSecurities | 77.4 | 3.3 | 0.1 |
|  | $152.0 | $9.3 | $0.1 |

|  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Gross |  | Gross |
|  | Fair | Unrealized | Fair | Unrealized |
|  | Value | Losses | Value | Losses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.3 | $- | $28.9 | $0.6 |
| More\tthan\t12\tmonths | 15.5 | 2.5 | 8.2 | 0.2 |
|  | $15.8 | $2.5 | $37.1 | $0.8 |

# System	Energy

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

|  |  | Total | Total |
| :--- | :--- | :--- | :--- |
|  | Fair | Unrealized | Unrealized |
| 2004 | Value | Gains | Losses |
|  |  | (In\tMillions) |  |
| Equity | $127.0 | $15.0 | $7.2 |
| Debt\tSecurities | 78.1 | 1.9 | 0.6 |
|  | $205.1 | $16.9 | $7.8 |
| \t\tTotal |  |  |  |
| 2003 |  |  |  |
| Equity | $103.4 | $5.5 | $9.9 |
| Debt\tSecurities | 69.5 | 2.6 | 0.3 |
|  | $172.9 | $8.1 | $10.2 |

Equity	Securities

Debt	Securities

|  |  | Gross |  | Gross |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair | Unrealized | Fair | Unrealized |
|  | Value | Losses | Value | Losses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.4 | $- | $40.4 | $0.5 |
| More\tthan\t12\tmonths | 50.4 | 7.2 | 2.0 | 0.1 |
|  | $50.8 | $7.2 | $42.4 | $0.6 |

During	the	year	ended	December	31,	2004,	the	proceeds	from	the	dispositions	of	securities	amounted	to	$7.5	million	and	gross	gains	of	$32,362	and	gross	losses	of $58,755.

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

Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	System	Energy	evaluate	unrealized	gains	and	losses	at	the	end	of	each	period	to	determine	whether	an other	than	temporary	impairment	has	occurred.	This	analysis	considers	the	length	of	time	that	a	security	has	been	in	a	loss	position,	the	current	performance	of	that security,	and	whether	decommissioning	costs	are	recovered	in	rates.	No	significant	impairments	were	recorded	in	2004	and	2003	as	a	result	of	these	evaluations.

Due	to	the	regulatory	treatment	of	decommissioning	collections	and	trust	fund	earnings,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	System	Energy record	regulatory	assets	or	liabilities	for	unrealized	gains	and	losses	on	trust	investments.	For	the	unregulated	portion	of	River	Bend,	Entergy	Gulf	States	has recorded	an	offsetting	amount	of	unrealized	gains	or	losses	in	other	deferred	credits.

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

Each	domestic	utility	company	purchases	electricity	from	and	sells	electricity	to	the	other	domestic	utility	companies,	and	System	Energy	under	rate	schedules	filed with	 FERC.	The	 domestic	 utility	 companies	 and	 System	 Energy	 purchase	 fuel	 from	 System	 Fuels;	 receive	 management,	 technical,	 advisory,	 operating,	 and administrative	services	from	Entergy	Services;	and	receive	management,	technical,	and	operating	services	from	Entergy	Operations.	Pursuant	to	SEC	rules	under PUHCA	and	the	Federal	Power	Act,	these	transactions	are	on	an	"at	cost"	basis.	In	addition,	Entergy	Power	sells	electricity	to	Entergy	Arkansas,	Entergy	Louisiana, and	Entergy	New	Orleans,	and	RS	Cogen	sells	electricity	to	Entergy	Louisiana	and	Entergy	New	Orleans.

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

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

The	tables	below	contain	the	various	affiliate	transactions	of	the	domestic	utility	companies,	System	Energy,	and	other	Entergy	affiliates.

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tMillions) |  |  |  |
| 2004 | $256.8 | $52.5 | $96.6 | $47.6 | $117.8 | $545.4 |
| 2003 | $242.3 | $42.8 | $102.4 | $27.6 | $85.5 | $583.8 |
| 2002 | $172.6 | $28.8 | $8.8 | $70.6 | $7.1 | $602.5 |

# Intercompany	Operating	Expenses

(2) Includes	power	purchased	from	Entergy	Power	and	RS	Cogen	LLC	in	2004	of	$9.1	million	and $33.0	million,	respectively,	and	in	2003	of	$5.9	million	and	$19.1	million,	respectively.

(3) Includes	power	purchased	from	Entergy	Power	and	RS	Cogen	LLC	in	2004	of	$9.0	million	and $10.6	million,	respectively,	and	in	2003	of	$5.7	million	and	$6.9	million,	respectively.

Intercompany	Interest	Income

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tMillions) |  |  |  |
| 2004 | $0.6 | $0.4 | $1.1 | $0.6 | $0.2 | $0.6 |
| 2003 | $0.6 | $0.4 | $1.2 | $0.3 | $0.2 | $0.1 |
| 2002 | $1.0 | $0.3 | $0.7 | $0.4 | $0.2 | $0.9 |

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

The	business	of	the	domestic	utility	companies	and	System	Energy	is	subject	to	seasonal	fluctuations	with	the	peak	periods	occurring	during	the	third	quarter. Operating	results	for	the	four	quarters	of	2004	and	2003	were:

# Operating	Revenue

|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Arkansas | Gulf\tStates | Louisiana | Mississippi | New\tOrleans | Energy |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2004: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $363,461 | $638,996 | $488,046 | $236,829 | $169,767 | $127,168 |
| \t\tSecond\tQuarter | $405,509 | $685,313 | $555,511 | $289,573 | $186,337 | $132,720 |
| \t\tThird\tQuarter | $481,103 | $840,630 | $668,240 | $390,337 | $200,036 | $144,052 |
| \t\tFourth\tQuarter | $403,072 | $717,445 | $515,189 | $296,890 | $179,728 | $141,441 |
| 2003: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $362,749 | $584,354 | $462,361 | $227,369 | $140,907 | $141,985 |
| \t\tSecond\tQuarter | $394,884 | $700,635 | $569,580 | $261,899 | $154,065 | $144,764 |
| \t\tThird\tQuarter | $469,925 | $777,182 | $646,503 | $309,739 | $203,751 | $141,239 |
| \t\tFourth\tQuarter | $362,112 | $577,566 | $487,126 | $236,353 | $155,293 | $155,832 |
|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |

# Operating	Income	(Loss)

|  | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2004: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $48,566 | $88,312 | $48,318 | $22,724 | $15,487 | $57,767 |
| \t\tSecond\tQuarter | $80,669 | $101,832 | $84,357 | $42,157 | $22,880 | $59,585 |
| \t\tThird\tQuarter | $123,910 | $127,838 | $87,130 | $52,003 | $24,450 | $59,601 |
| \t\tFourth\tQuarter | $40,590 | $41,437 | $41,710 | $29,730 | ($4,878) | $56,181 |
| 2003: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $67,130 | $75,693 | $89,362 | $30,096 | ($1,887) | $55,739 |
| \t\tSecond\tQuarter | $92,939 | $99,150 | $91,304 | $44,625 | $17,311 | $54,029 |
| \t\tThird\tQuarter | $135,790 | $146,063 | $108,232 | $53,173 | $28,230 | $65,791 |
| \t\tFourth\tQuarter | $1,330 | ($13,136) | $13,325 | $13,753 | ($15,736) | $62,853 |
|  | Entergy | Entergy | Entergy | Entergy | Entergy | System |

|  | Arkansas | Gulf	States | Louisiana | Mississippi | New	Orleans | Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2004: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $19,276 | $41,728 | $21,211 | $8,637 | $7,114 | $24,664 |
| \t\tSecond\tQuarter | $43,277 | $55,591 | $43,713 | $20,808 | $12,319 | $25,532 |
| \t\tThird\tQuarter | $67,944 | $82,456 | $45,496 | $27,873 | $13,189 | $27,505 |
| \t\tFourth\tQuarter | $11,713 | $12,489 | $17,075 | $16,179 | ($4,550) | $28,247 |
| 2003: |  |  |  |  |  |  |
| \t\tFirst\tQuarter | $27,145 | $11,792(a) | $43,807 | $12,316 | ($4,327) | $23,735 |
| \t\tSecond\tQuarter | $47,537 | ($20,124) | $45,713 | $22,350 | $9,580 | $22,820 |
| \t\tThird\tQuarter | $69,319 | $82,283 | $57,863 | $25,804 | $14,118 | $28,515 |
| \t\tFourth\tQuarter | ($17,992) | ($31,389) | ($1,229) | $6,588 | ($11,512) | $30,933 |

(a) Entergy	Gulf	States'	net	income	before	the	cumulative	effect	of	accounting	change	for	the	first quarter	of	2003	was	$33,125.

# Item	2.	Properties

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

# Item	3.	Legal	Proceedings

Details	of	the	registrant's	material	environmental	regulation	and	proceedings	and	other	regulatory	proceedings	and	litigation	that	are	pending	or	those terminated	in	the	fourth	quarter	of	2004	are	discussed	in	Part	I.	Item	1.	-	Business	under	the	sections	titled	"Retail	Rate	Regulation",	"Wholesale	Rate	Matters", "Environmental	Regulation",	and	"Litigation"	in	this	report.

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

During	the	fourth	quarter	of	2004,	no	matters	were	submitted	to	a	vote	of	the	security	holders	of	Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	Resources.

# DIRECTORS	AND	EXECUTIVE	OFFICERS	OF	ENTERGY	CORPORATION

# Directors

												Information	required	by	this	item	concerning	directors	of	Entergy	Corporation	is	set	forth	under	the	heading	"Proposal	1--Election	of	Directors"	contained	in the	Proxy	Statement	of	Entergy	Corporation,	(the	"Proxy	Statement"),	to	be	filed	in	connection	with	its	Annual	Meeting	of	Stockholders	to	be	held	May	13,	2005,

("Annual	Meeting"),	and	is	incorporated	herein	by	reference.	Information	required	by	this	item	concerning	officers	and	directors	of	the	remaining	registrants	is reported	in	Part	III	of	this	document.

# Executive	Officers

President,	US	Region	and	Vice	President,	Global	Human

# 		Resource	Strategy,	E.I.	DuPont	de	Nemours,

# Wilmington,

# 		Delaware

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

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

# PART	II

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

# Entergy	Corporation

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

												 Entergy	Corporation's	stock	price	as	of	February	28,	2005	was	$69.12.	The	high	and	low	prices	of	Entergy	Corporation's	common	stock	for	each	quarterly period	in	2004	and	2003	were	as	follows:

|  | 2004 |  | 2003 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | High | Low | High | Low |
|  |  | (In\tDollars) |  |  |
| First | 60.20 | 56.01 | 49.55 | 42.26 |
| Second | 59.92 | 50.64 | 54.38 | 45.90 |
| Third | 61.98 | 54.43 | 54.99 | 47.75 |
| Fourth | 68.67 | 60.08 | 57.24 | 51.06 |

												Consecutive	quarterly	cash	dividends	on	common	stock	were	paid	to	stockholders	of	Entergy	Corporation	in	2004	and	2003.	In	2004,	dividends	of	$0.45	per share	were	paid	in	the	first	three	quarters,	and	a	dividend	of	$0.54	per	share	was	paid	in	the	fourth	quarter.	In	2003,	dividends	of	$0.35	per	share	were	paid	in	the first	and	second	quarters,	and	dividends	of	$0.45	per	share	were	paid	in	the	third	and	fourth	quarters.

												 Entergy	Corporation's	future	ability	to	pay	dividends	is	discussed	in	Note	7	to	the	consolidated	financial	statements.	In	addition	to	the	restrictions	described in	Note	7,	PUHCA	provides	that,	without	approval	of	the	SEC,	the	unrestricted,	undistributed	retained	earnings	of	any	Entergy	Corporation	subsidiary	are	not available	for	distribution	to	Entergy	Corporation's	common	stockholders	until	such	earnings	are	made	available	to	Entergy	Corporation	through	the	declaration	of dividends	by	such	subsidiaries.

# Unregistered	Sales	of	Equity	Securities	and	Use	Of	Proceeds

# Issuer	Purchases	of	Equity	Securities	(1)

| Period | Total	Number<br>of	Shares<br>Purchased | Average	Price<br>Paid<br>per	Share | Total	Number	of<br>Shares	Purchased<br>as	Part	of	a	Publicly<br>Announced	Plan | Maximum<br>$	Amount<br>of	Shares	that<br>May	Yet	to	be<br>Purchased<br>Under	the	Plan |
| :--- | :--- | :--- | :--- | :--- |
| 10/01/2004-10/31/2004 | 2,135,000 | $62.05 | 2,135,000 | $1,293,054,803 |
| 11/01/2004-11/30/2004 | 2,931,000 | $65.55 | 2,931,000 | $1,124,355,785 |
| 12/01/2004-12/31/2004 | 4,183,800 | $66.24 | 4,183,800 | $999,999,962(2) |
| Total | 9,249,800 | $65.04 | 9,249,800 |  |

(1) In	accordance	with	Entergy's	stock-based	compensation	plans,	Entergy	periodically	grants	stock options	to	its	employees,	which	may	be	exercised	to	obtain	shares	of	Entergy's	common	stock. According	 to	 the	 plans,	 these	 shares	 can	 be	 newly	 issued	 shares,	 treasury	 stock,	 or	 shares purchased	on	the	open	market.	See	Note	7	to	the	consolidated	financial	statements	for	additional discussion	of	the	stock-based	compensation	plan.	Entergy's	management	has	been	authorized	to repurchase	on	the	open	market	shares	up	to	an	amount	sufficient	to	fund	the	exercise	of	grants under	the	plans,	and	this	authorization	does	not	have	an	expiration	date.	In	August	2004,	Entergy announced	a	program	under	which	Entergy	Corporation	will	repurchase	up	to	$1.5	billion	of	its common	 stock.	The	 program	 extends	 through	 the	 end	 of	 2006.	This	 repurchase	 program	 is incremental	to	the	existing	authority	to	repurchase	shares	to	fund	the	exercise	of	employee	stock options.	The	amount	of	repurchases	under	the	program	may	vary	as	a	result	of	material	changes	in business	results	or	capital	spending,	or	as	a	result	of	material	new	investment	opportunities.

(2) Maximum	amount	of	shares	that	may	yet	be	repurchased	relates	only	to	the	$1.5	billion	plan	and does	not	include	an	estimate	of	the	amount	of	shares	that	may	be	purchased	to	fund	the	exercise	of grants	under	the	stock-based	compensation	plans.

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

												There	is	no	market	for	the	common	stock	of	Entergy	Corporation's	wholly	owned	subsidiaries.	Cash	dividends	on	common	stock	paid	by	the	domestic	utility companies	and	System	Energy	to	Entergy	Corporation	during	2004	and	2003,	were	as	follows:

| Entergy	Arkansas | $85.8 | $69.6 |
| :--- | :--- | :--- |
| Entergy\tGulf\tStates | $94.3 | $68.1 |
| Entergy\tLouisiana | $116.5 | $145.5 |
| Entergy\tMississippi | $46.8 | $31.7 |
| Entergy\tNew\tOrleans | $5.2 | $3.0 |
| System\tEnergy | $104.6 | $105.0 |

												Information	with	respect	to	restrictions	that	limit	the	ability	of	the	domestic	utility	companies	and	System	Energy	to	pay	dividends	is	presented	in	Note	7	to the	domestic	utility	companies	and	System	Energy	financial	statements.

# Item	6.	Selected	Financial	Data

Refer	to	"SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON	OF	ENTERGY	CORPORATION	AND	SUBSIDIARIES,	ENTERGY ARKANSAS,	INC.,	ENTERGY	GULF	STATES,	INC., 	ENTERGY	LOUISIANA,	INC.,	ENTERGY	MISSISSIPPI,	INC.,	ENTERGY	NEW	ORLEANS,

INC.,	and	SYSTEM	ENERGY	RESOURCES,	INC."	which	follow	each	company's	financial	statements	in	this	report,	for	information	with	respect	to	selected financial	data	and	certain	operating	statistics.

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

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

# Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk

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

# Item	8.	Financial	Statements	and	Supplementary	Data

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

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

												 No	event	that	would	be	described	in	response	to	this	item	has	occurred	with	respect	to	Entergy,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana, Entergy	Mississippi,	Entergy	New	Orleans,	or	System	Energy.

# Item	9A.	Controls	and	Procedures

# Disclosure	Controls	and	Procedures

												 As	of	December	31,	2004,	evaluations	were	performed	under	the	supervision	and	with	the	participation	of	Entergy,	Entergy	Arkansas,	Entergy	Gulf	States, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	(individually	"Registrant"	and	collectively	the	"Registrants")	management, including	 their	respective	Chief	Executive	Officers	(CEO)	and	Chief	Financial	Officers	(CFO).	The	evaluations	assessed	 the	effectiveness	of	 the	Registrants' disclosure	controls	and	procedures.	Based	on	the	evaluations,	each	CEO	and	CFO	has	concluded	that,	as	to	the	Registrant	or	Registrants	for	which	they	serve	as CEO	or	CFO,	the	Registrants'	disclosure	controls	and	procedures	are	effective	to	ensure	that	information	required	to	be	disclosed	by	each	Registrant	in	reports	that	it files	or	submits	under	the	Securities	Exchange	Act	of	1934	is	recorded,	processed,	summarized	and	reported	within	the	time	periods	specified	in	Securities	and Exchange	Commission	rules	and	forms.

# Internal	Control	Over	Financial	Reporting

The	managements	of	Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and System	Energy	Resources	(individually	"Registrant"	and	collectively	the	"Registrants")	are	responsible	for	establishing	and	maintaining	adequate	internal	control over	financial	reporting	for	the	Registrants.	Each	Registrant's	internal	control	system	is	designed	to	provide	reasonable	assurance	regarding	the	preparation	and	fair presentation	of	each	Registrant's	financial	statements	presented	in	accordance	with	generally	accepted	accounting	principles.

												 All	internal	control	systems,	no	matter	how	well	designed,	have	inherent	limitations.	Therefore,	even	those	systems	determined	to	be	effective	can	provide only	reasonable	assurance	with	respect	to	financial	statement	preparation	and	presentation.

												 Each	Registrant's	management	assessed	the	effectiveness	of	each	Registrant's	internal	control	over	financial	reporting	as	of	December	31,	2004.	In	making this	assessment,	each	management	used	the	criteria	set	forth	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(COSO)	in	Internal Control	-	Integrated	Framework.

Based	on	each	management's	assessment	and	the	criteria	set	forth	by	COSO,	each	Registrant's	management	believes	that	each	Registrant	maintained effective	internal	control	over	financial	reporting	as	of	December	31,	2004.

												The	Registrants'	registered	public	accounting	firm	has	issued	an	attestation	report	on	each	management's	assessment	of	each	Registrant's	internal	control	over financial	reporting.

# Attestation	Report	of	Registered	Public	Accounting	Firm

We	have	audited	management's	assessment,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting,	that	Entergy	Corporation	and	Subsidiaries	(the "Company")	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated Framework issued	by	 the	Committee	of	Sponsoring	Organizations	of	 the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining effective	internal	control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to express	an	opinion	on	management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

We	conducted	our	audit	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we	plan

and	perform	the	audit	to	obtain	reasonable	assurance	about	whether	effective	internal	control	over	financial	reporting	was	maintained	in	all	material	respects.	Our audit	included	obtaining	an	understanding	of	internal	control	over	financial	reporting,	evaluating	management's	assessment,	testing	and	evaluating	the	design	and operating	effectiveness	of	internal	control,	and	performing	such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We	believe	that	our	audit provides	a	reasonable	basis	for	our	opinions.

A	company's	internal	control	over	financial	reporting	is	a	process	designed	by,	or	under	the	supervision	of,	the	company's	principal	executive	and	principal	financial officers,	or	persons	performing	similar	functions,	and	effected	by	 the	company's	board	of	directors,	management,	and	other	personnel	 to	provide	reasonable assurance	regarding	the	reliability	of	financial	reporting	and	the	preparation	of	financial	statements	for	external	purposes	in	accordance	with	accounting	principles generally	accepted	in	the	United	States	of	America.	A	company's	internal	control	over	financial	reporting	includes	those	policies	and	procedures	that	(1)	pertain	to the	maintenance	of	records	that,	in	reasonable	detail,	accurately	and	fairly	reflect	the	transactions	and	dispositions	of	the	assets	of	the	company;	(2)	provide reasonable	assurance	that	transactions	are	recorded	as	necessary	to	permit	preparation	of	financial	statements	in	accordance	with	generally	accepted	accounting principles,	and	that	receipts	and	expenditures	of	the	company	are	being	made	only	in	accordance	with	authorizations	of	management	and	directors	of	the	company; and	(3)	provide	reasonable	assurance	regarding	prevention	or	timely	detection	of	unauthorized	acquisition,	use,	or	disposition	of	the	company's	assets	that	could have	a	material	effect	on	the	financial	statements.

Because	of	the	inherent	limitations	of	internal	control	over	financial	reporting,	including	the	possibility	of	collusion	or	improper	management	override	of	controls, material	misstatements	due	to	error	or	fraud	may	not	be	prevented	or	detected	on	a	timely	basis.	Also,	projections	of	any	evaluation	of	the	effectiveness	of	the internal	control	over	financial	reporting	to	future	periods	are	subject	to	the	risk	that	the	controls	may	become	inadequate	because	of	changes	in	conditions,	or	that the	degree	of	compliance	with	the	policies	or	procedures	may	deteriorate.

In	our	opinion,	management's	assessment	that	Entergy	Corporation	and	Subsidiaries	maintained	effective	internal	control	over	financial	reporting	as	of	December 31,	 2004,	 is	 fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	Control--Integrated	Framework issued	 by	 the	 Committee	 of Sponsoring	Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	Entergy	Corporation	and	Subsidiaries	maintained,	in	all	material	respects,	effective internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	 issued	by	 the Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission.

We	have	also	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	the	consolidated	financial	statements as	of	and	for	the	year	ended	December	31,	2004	of	the	Company	and	our	report	dated	March	8,	2005	expressed	an	unqualified	opinion	on	those	financial	statements.

We	have	audited	management's	assessment,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting,	that	Entergy	Arkansas,	Inc.	(the	"Company") maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated	Framework issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining	effective	internal control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to	express	an	opinion	on management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

We	conducted	our	audit	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we	plan and	perform	the	audit	to	obtain	reasonable	assurance	about	whether	effective	internal	control	over	financial	reporting	was	maintained	in	all	material	respects.	Our audit	included	obtaining	an	understanding	of	internal	control	over	financial	reporting,	evaluating	management's	assessment,	testing	and	evaluating	the	design	and operating	effectiveness	of	internal	control,	and	performing	such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We	believe	that	our	audit provides	a	reasonable	basis	for	our	opinions.

In	our	opinion,	management's	assessment	that	Entergy	Arkansas,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	is fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	Entergy	Arkansas,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over	financial reporting	 as	 of	 December	 31,	 2004,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	of	the	Treadway	Commission.

We	have	also	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	the	financial	statements	as	of	and	for the	year	ended	December	31,	2004	of	the	Company	and	our	report	dated	March	8,	2005	expressed	an	unqualified	opinion	on	those	financial	statements.

To	the	Board	of	Directors	and	Shareholders Entergy	Gulf	States,	Inc. New	Orleans,	Louisiana

We	have	audited	management's	assessment,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting,	that	Entergy	Gulf	States,	Inc.	(the	"Company") maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated	Framework issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining	effective	internal control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to	express	an	opinion	on management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	management's	assessment	that	Entergy	Gulf	States,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	is fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	Entergy	Gulf	States,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.

We	have	audited	management's	assessment,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting,	that	Entergy	Louisiana,	Inc.	(the	"Company") maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated	Framework issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining	effective	internal control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to	express	an	opinion	on management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	management's	assessment	that	Entergy	Louisiana,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	is fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	 of	 the	Treadway	 Commission.	Also	in	our	opinion,	Entergy	Louisiana,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.

We	 have	 audited	 management's	 assessment,	 included	 in	 the	 accompanying	 Internal	 Control	 over	 Financial	 Reporting,	 that	 Entergy	 Mississippi,	 Inc.	 (the "Company")	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated Framework issued	by	 the	Committee	of	Sponsoring	Organizations	of	 the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining effective	internal	control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to express	an	opinion	on	management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	management's	assessment	that	Entergy	Mississippi,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	is fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	Entergy	Mississippi,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.

We	 have	 audited	 management's	 assessment,	 included	 in	 the	 accompanying	 Internal	 Control	 over	 Financial	 Reporting,	 that	 Entergy	 New	 Orleans,	 Inc.	 (the "Company")	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated Framework issued	by	 the	Committee	of	Sponsoring	Organizations	of	 the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining effective	internal	control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to express	an	opinion	on	management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	management's	assessment	that	Entergy	New	Orleans,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	is fairly	 stated,	 in	 all	 material	 respects,	 based	 on	 the	 criteria	 established in	Internal	 Control--Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	Entergy	New	Orleans,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over

financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.

We	have	audited	management's	assessment,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting,	that	System	Energy	Resources,	Inc.	(the "Company")	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control--Integrated Framework issued	by	 the	Committee	of	Sponsoring	Organizations	of	 the	Treadway	Commission.	The	Company's	management	is	responsible	for	maintaining effective	internal	control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting.	Our	responsibility	is	to express	an	opinion	on	management's	assessment	and	an	opinion	on	the	effectiveness	of	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	management's	assessment	that	System	Energy	Resources,	Inc.	maintained	effective	internal	control	over	financial	reporting	as	of	December	31, 2004,	is	fairly	stated,	in	all	material	respects,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.	Also	in	our	opinion,	System	Energy	Resources,	Inc.	maintained,	in	all	material	respects,	effective	internal	control	over financial	reporting	as	of	December	31,	2004,	based	on	the	criteria	established	in	Internal	Control--Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission.

# Item	9B.	Other	Information

												On	March	9,	2005	Entergy	Corporation	borrowed	$15	million	under	its	$965	million,	3-year	credit	facility,	dated	as	of	May	13,	2004,	among	Entergy Corporation,	Citibank,	N.A.,	as	Administrative	Agent	and	LC	Issuing	Bank,	ABN	AMRO	Bank,	N.V.,	as	LC	Issuing	Bank,	and	several	banks	party	thereto	(the	3- Year	Facility).		Entergy	Corporation	described	material	terms	of	the	3-Year	Facility	in	its	Report	on	Form	10-Q	for	the	quarterly	period	ended	June	30,	2004,	and filed	the	agreement	as	Exhibit	4(d).

												In	addition	to	the	3-Year	Facility,	Entergy	Corporation	also	maintains	(i)	a	$500	million,	5-year	credit	facility,	dated	as	of	December	14,	2004,	among Entergy	Corporation,	Citibank,	N.A.,	as	bank	and	administrative	agent,	and	several	banks	party	thereto	(the	5-Year	Facility);	and	(ii)	Credit	Agreements,	dated	as	of May	31,	2002	and	November	24,	2003,	among	Entergy	Corporation,	Bayerische	Hypo-und	Vereinsbank	AG,	New	York	Branch,	as	Bank,	and	Bayerische	Hypo-und Vereinsbank	AG,	New	York	Branch,	as	Administrative	Agent	(the	Hypo	Term	Loans).		The	table	below	includes	the	borrowings	outstanding	and	capacity	available under	these	facilities	as	of	March	7,	2005.

| Facility | Capacity | Borrowings | Letters<br>of	Credit | Capacity<br>Available |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| 3-Year\tFacility | $965 | $403 | $50 | $512 |
| 5-Year\tFacility | $500 | $75 | - | $425 |
| Hypo\tTerm\tLoans | $95 | $95 | - | - |

PART	III

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

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

# Mark	T.	Savoff See	information	under	the	Entergy	Corporation	Officers	Section	in

# Part	I.

# Officers

See	information	under	the	Entergy	Corporation	Officers	Section	in Part	I.

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

# Corporate	Governance	Guidelines	and	Committee	Charters

Each	of	the	Audit,	Corporate	Governance	and	Personnel	Committees	of	Entergy	Corporation's	Board	of	Directors	operates	under	a	written	charter.	In addition,	the	full	Board	has	adopted	Corporate	Governance	Guidelines.	Each	charter	and	the	guidelines	are	available	through	Entergy's	website	(www.entergy.com) or	upon	written	request.

# Audit	Committee	of	the	Entergy	Corporation	Board

												The	following	directors	are	members	of	the	Audit	Committee	of	Entergy	Corporation's	Board	of	Directors:

Steven	V.	Wilkinson	(Chairman)

Kathleen	A.	Murphy

James	R.	Nichols

William	A.	Percy,	II

Bismark	A.	Steinhagen

All	Audit	Committee	members	are	independent.	For	purposes	of	independence	of	members	of	the	Audit	Committee,	an	independent	director	also	may	not	accept directly	or	indirectly	any	consulting,	advisory	or	other	compensatory	fee	from	Entergy	or	be	affiliated	with	Entergy	as	defined	in	SEC	rules.	All	Audit	Committee members	possess	 the	 level	of	financial	 literacy	and	accounting	or	related	financial	management	expertise	required	by	 the	NYSE	rules.	Steven	V.	Wilkinson qualifies	as	an	"audit	committee	financial	expert,"	as	that	term	is	defined	in	the	SEC	rules.

# Code	of	Ethics

												The	Board	of	Directors	has	adopted	a	Code	of	Business	Conduct	and	Ethics	for	Members	of	the	Board	of	Directors.	The	code	is	available	through	Entergy's website	(www.entergy.com)	or	upon	written	request.	The	Board	has	also	adopted	a	Code	of	Business	Conduct	and	Ethics	for	Employees,	that	includes	Special Provision	 Relating	 to	 Principal	 Executive	 Officer	 and	 Senior	 Financial	 Officers.	The	 Code	 of	 Business	 Conduct	 and	 Ethics	 for	 Employees	 is	 to	 be	 read	 in conjunction	with	Entergy's	omnibus	code	of	integrity	under	which	Entergy	operates	called	the	Code	of	Entegrity	as	well	as	system	policies.	All	employees	are required	to	abide	by	the	Codes.	Non-bargaining	employees	are	required	to	acknowledge	annually	that	they	understand	and	abide	by	the	Code	of	Entegrity.	The	Code of	Business	Conduct	and	Ethics	for	Employees	and	the	Code	of	Entegrity	are	available	through	Entergy's	website	(www.entergy.com)	or	upon	written	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	13,	2005,	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,	2004,	and two	additional	executive	officers	who	would	have	been	included	in	the	table	but	retired	or	resigned	during	the	year	at	Entergy	Arkansas,	Entergy	Gulf	States, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	(collectively,	the	"Named	Executive	Officers").	This	determination	was	based on	total	annual	base	salary	and	bonuses	from	all	Entergy	sources	earned	by	each	officer	for	the	year	2004.	See	Item	10,	"Directors	and	Executive	Officers	of	the Registrants,"	for	information	on	the	principal	positions	of	the	Named	Executive	Officers	in	the	table	below.

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.

(6) Travel	expenses	related	to	volunteer	service	to	Mr.	Domino	for	$3,727.

(7) Home	security	monitoring	to	Ms.	Shanks	for	$180.

(c) In	addition	to	the	performance	units	granted	under	the	Equity	Ownership	Plan,	Ms.	Shanks	was granted	3,000	restricted	units	in	2003.	Restrictions	will	be	lifted	on	1,200	units	in	2006	and	the remaining	1,800	units	in	2011,	based	on	continued	service	with	Entergy.	Accumulated	dividends will	not	be	paid.	The	value	Ms.	Shanks	may	realize	is	dependent	upon	both	the	number	of	units that	vest	and	the	future	market	price	of	Entergy	common	stock.

(d) Amounts	include	the	value	of	performance	units	that	vested	in	2004,	2003	and	2002	(see	note (b)	above)	under	Entergy's	Equity	Ownership	Plan.

(e) All	Other	Compensation	includes	the	following:

(1) 2004	benefit	accruals	under	the	Defined	Contribution	Restoration	Plan	as	follows:	Ms.

(3) A	2004	 lump	sum	award	made	under	 the	System	Executive	Retirement	Plan	 to	Mr. Hintz	 in	 the	 amount	 of $8,453,970.	For a	 description	 of	 the	 System	 Executive Retirement	Plan,	see	the	discussion	under	"Executive	Retirement	and	Benefit	Plans	- System	Executive	Retirement	Plan."

# Option	Grants	in	2004

The	following	table	summarizes	option	grants	during	2004	to	the	Named	Executive	Officers.	The	absence,	in	the	table	below,	of	any	Named	Executive Officer	indicates	that	no	options	were	granted	to	such	officer.

|  |  |  |  |  | Potential	Realizable | Potential	Realizable |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Individual\tGrants | Individual\tGrants |  | Value | Value |
|  | Number\tof | %\tof\tTotal |  |  | at\tAssumed\tAnnual | at\tAssumed\tAnnual |
|  | Securities | Options |  |  | Rates\tof\tStock | Rates\tof\tStock |
|  | Underlying | Granted\tto | Exercise |  | Price\tAppreciation | Price\tAppreciation |
|  | Options | Employees | Price\t(per | Expiration | for\tOption\tTerm(b) | for\tOption\tTerm(b) |
| Name | Granted\t(a) | in\t2004 | share)\t(a) | Date | 5% | 10% |
| E.\tRenae\tConley | 18,400 | 1.0% | $58.60 | 3/02/14 | $678,099 | $1,718,437 |
| Leo\tP.\tDenault | 40,000 | 2.1% | 58.60 | 3/02/14 | 1,474,129 | 3,735,732 |
| Joseph\tF.\tDomino | 10,000 | 0.5% | 58.60 | 3/02/14 | 368,532 | 933,933 |
|  | 4,610\t(c) | 0.2% | 59.02 | 1/28/09 | 73,874 | 162,917 |
|  | 1,601\t(c) | 0.1% | 65.22 | 1/28/09 | 24,022 | 52,055 |
|  | 1,308\t(c) | 0.1% | 65.26 | 1/28/09 | 19,637 | 42,554 |
|  | 670\t(c) | 0.1% | 65.25 | 1/25/11 | 15,546 | 35,490 |

| Donald	C.	Hintz | 20,000 | 1.1% | 58.60 | 3/02/14 | 737,065 | 1,867,866 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| J.\tWayne\tLeonard | 220,000 | 11.6% | 58.60 | 3/02/14 | 8,107,710 | 20,546,528 |
| Hugh\tT.\tMcDonald | 10,000 | 0.5% | 58.60 | 3/02/14 | 368,532 | 933,933 |
| Daniel\tF.\tPacker | 10,000 | 0.5% | 58.60 | 3/02/14 | 368,532 | 933,933 |
| Mark\tT.\tSavoff | 31,800 | 1.7% | 58.60 | 3/02/14 | 1,171,933 | 2,969,907 |
| Carolyn\tC.\tShanks | 10,000 | 0.5% | 58.60 | 3/02/14 | 368,532 | 933,933 |
| Richard\tJ.\tSmith | 63,600 | 3.4% | 58.60 | 3/02/14 | 2,343,865 | 5,939,814 |
| Gary\tJ.\tTaylor | 40,000 | 2.1% | 58.60 | 3/02/14 | 1,474,129 | 3,735,732 |

(a) Options	were	granted	on	March	2,	2004,	pursuant	to	the	Equity	Ownership	Plan.	All	options granted	on	this	date	have	an	exercise	price	equal	to	the	closing	price	of	Entergy	common	stock on	the	New	York	Stock	Exchange	Composite	Transactions	on	March	2,	2004.	These	options	will vest	 in	 equal	 increments,	 annually,	 over	 a	 three-year	 period	 beginning	 in	 2005,	 based	 on continued	service	with	Entergy.

(b) Calculation	based	on	the	market	price	of	the	underlying	securities	assuming	the	market	price increases	 over	 the	 option	 period	 and	 assuming	 annual	 compounding.	 The	 column	 presents estimates	of	potential	values	based	on	simple	mathematical	assumptions.	The	actual	value,	if any,	a	Named	Executive	Officer	may	realize	is	dependent	upon	the	market	price	on	the	date	of option	exercise.

(c) During	2004,	Mr.	Domino	converted	presently	exercisable	stock	options	into	Entergy	stock	and reload	 stock	 options.	He	accomplished	 this	by	exercising	stock	options,	paying	 the	exercise price	 and	 all	 applicable	 taxes	 for	 these	 shares	 by	 surrendering	 shares	 of	 Entergy	 stock. Additional	options,	as	indicated	above,	were	granted	pursuant	to	the	reload	feature	of	this	"stock for	stock"	exercise	method.	Under	the	reload	mechanism,	eligible	participants	are	granted	an additional	number	of	options	equal	to	the	number	of	shares	surrendered	to	pay	the	exercise	price. The	reloaded	stock	options	vest	immediately	and	have	an	exercise	price	equal	to	the	price	of Entergy	common	stock	on	the	New	York	Stock	Exchange	Composite	Transactions	on	the	date of	exercise	of	the	original	options.	The	reloaded	options	retain	the	original	grant's	expiration date.	The	reload	feature	was	removed	from	 the	Equity	Ownership	Plan	as	approved	by	 the Stockholders	in	May	2003.	Reloads	are	no	longer	available	for	options	granted	after	February 13,	2003.

# Aggregated	Option	Exercises	in	2004	and	December	31,	2004	Option	Values

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

| Name | Shares	Acquired<br>on	Exercise | Value<br>Realized	(a) | Number	of<br>Securities	Underlying<br>Unexercised	Options<br>as	of	December	31,	2004<br>Exercisable | Unexercisable | Value	of	Unexercised<br>In-the-Money	Options<br>as	of	December	31,	2004	(b)<br>Exercisable | Unexercisable |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| E.\tRenae\tConley | - | $\t- | 85,858 | 47,734 | $2,376,930 | $881,007 |
| Leo\tP.\tDenault | - | - | 42,322 | 53,368 | 896,883 | 687,797 |
| Joseph\tF.\tDomino | 14,667 | 464,974 | 39,975 | 24,334 | 925,393 | 441,831 |
| Donald\tC.\tHintz | 147,588 | 4,552,699 | 630,000 | - | 17,776,875 | - |
| J.\tWayne\tLeonard | - | - | 1,201,600 | 460,200 | 41,668,356 | 7,840,180 |
| Hugh\tT.\tMcDonald | - | - | 42,665 | 25,334 | 1,128,347 | 464,971 |
| Daniel\tF.\tPacker | - | - | 30,799 | 22,001 | 859,748 | 386,004 |
| Mark\tT.\tSavoff | - | - | - | 31,800 | - | 285,882 |
| Carolyn\tC.\tShanks | 21,467 | 572,052 | 17,999 | 26,001 | 453,296 | 478,564 |
| Richard\tJ.\tSmith | - | - | 150,537 | 120,268 | 3,720,385 | 1,947,463 |
| Gary\tJ.\tTaylor | 13,333 | 293,326 | 58,699 | 69,468 | 1,620,626 | 1,073,323 |
| C.\tJohn\tWilder | 222,430 | 3,649,306 | - | - | - | - |

(a) Based	on	the	difference	between	the	closing	price	of	Entergy's	common	stock	on	the	New	York Stock	Exchange	Composite	Transactions	on	the	exercise	date	and	the	option	exercise	price.

(b) Based	on	the	difference	between	the	closing	price	of	Entergy's	common	stock	on	the	New	York Stock	Exchange	Composite	Transactions	on	December	31,	2004,	and	the	option	exercise	price.

# Long-Term	Incentive	Plan	Awards	in	2004

The	following	table	summarizes	the	awards	of	performance	units	(equivalent	to	shares	of	Entergy	common	stock)	granted	under	the	Equity	Ownership	Plan	in	2004 to	the	Named	Executive	Officers.

| Name | Number	of<br>Units | Performance	Period	Until<br>Maturation	or	Payout | Threshold | Target | Maximum |
| :--- | :--- | :--- | :--- | :--- | :--- |
| E.\tRenae\tConley | 8,000 | 1/1/04-12/31/06 | 400 | 3,200 | 8,000 |
| Leo\tP.\tDenault | 15,800 | 1/1/04-12/31/06 | 700 | 6,322 | 15,800 |
| Joseph\tF.\tDomino | 4,000 | 1/1/04-12/31/06 | 200 | 1,600 | 4,000 |
| Donald\tC.\tHintz | 3,600 | 1/1/04-12/31/06 | 200 | 1,456 | 3,600 |
| J.\tWayne\tLeonard | 85,200 | 1/1/04-12/31/06 | 3,500 | 34,100 | 85,200 |
| Hugh\tT.\tMcDonald | 4,000 | 1/1/04-12/31/06 | 200 | 1,600 | 4,000 |
| Daniel\tF.\tPacker | 4,000 | 1/1/04-12/31/06 | 200 | 1,600 | 4,000 |
| Mark\tT.\tSavoff | 16,500 | 1/1/04-12/31/06 | 700 | 6,600 | 16,500 |
| Carolyn\tC.\tShanks | 4,000 | 1/1/04-12/31/06 | 200 | 1,600 | 4,000 |
| Richard\tJ.\tSmith | 16,500 | 1/1/04-12/31/06 | 700 | 6,600 | 16,500 |
| Gary\tJ.\tTaylor | 16,500 | 1/1/04-12/31/06 | 700 | 6,600 | 16,500 |

(a) Performance	units	awarded	will	vest	at	the	end	of	a	three-year	period,	subject	to	the	attainment of	approved	performance	goals	for	Entergy.	Actual	awards	are	based	upon	the	achievement	of the	cumulative	result	of	these	goals	for	the	performance	period.	The	value	any	Named	Executive Officer	may	realize	is	dependent	upon	the	number	of	units	that	vest,	the	future	market	price	of Entergy	common	stock,	and	the	dividends	paid	during	the	performance	period.

(b) The	threshold,	target,	and	maximum	levels	correspond	to	the	achievement	of	10%,	100%,	and 250%,	 respectively,	 of	 Equity	 Ownership	 Plan	 goals.	Achievement	of	a	 threshold,	 target,	or maximum	level	would	result	in	the	award	of	the	number	of	units	indicated	in	the	respective column.	Achievement	of	a	level	between	these	three	specified	levels	would	result	in	the	award	of a	number	of	units	calculated	by	means	of	interpolation.

# Executive	Retirement	and	Benefit	Plans

												 The	Named	Executive	Officers	are	eligible	to	participate	in	three	types	of	non-qualified	retirement	benefit	plans.	The	first	type	of	plan	is	one	that	provides retirement	income,	and	includes	the	qualified	retirement	plan	combined	with	the	Pension	Equalization	Plan,	the	Supplemental	Retirement	Plan,	and	the	System Executive	Retirement	Plan.	In	these	plans,	an	executive	is	typically	enrolled	in	one	or	more	plans	but	only	paid	the	amount	due	under	the	plan	that	provides	the highest	benefit,	except	that	participants	in	the	Supplemental	Retirement	Plan	are	also	eligible	for	benefits	under	the	Pension	Equalization	Plan.	The	second	type	of plan	provides	for	payments	in	the	event	of	a	change	in	control,	and	includes	the	System	Executive	Continuity	Plans.	Finally,	the	Executive	Deferred	Compensation Plan	and	the	Equity	Ownership	Plan	allow	for	deferral	of	earned	income.

Qualified	Retirement	Plan	Combined	with	Pension	Equalization	Plan.	Entergy	Corporation	has	a	tax-qualified	defined	benefit	plan,	which,	combined	with	a	non- qualified	Pension	Equalization	Plan	(PEP),	provides	for	a	retirement	benefit	calculated	by	multiplying	the	number	of	years	of	employment	by	1.5%,	which	is	then multiplied	by	the	final	average	pay	as	defined	in	the	plans,	and	currently	includes	base	salary	plus	annual	bonus.	The	normal	form	of	benefit	for	a	single	executive employee	is	a	lifetime	annuity	and	for	a	married	executive	employee	is	a	reduced	benefit	with	a	50%	surviving	spouse	annuity.	Retirement	benefits	are	not	subject to	any	deduction	for	social	security.

												The	maximum	benefit	under	the	qualified	pension	plan	is	limited	by	Sections	401	and	415	of	the	Internal	Revenue	Code	of	1986,	as	amended;	however, Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy	have	elected	to	participate	in	the	PEP sponsored	by	Entergy	Corporation.	Under	the	PEP,	certain	executives,	including	the	Named	Executive	Officers,	would	receive	an	additional	amount	to	compensate for	the	benefit	that	would	have	been	payable	under	the	qualified	pension	plan,	except	for	the	Internal	Revenue	Code	Sections	401	and	415	limitations	discussed above.	The	PEP	also	includes	as	earnings	for	purposes	of	calculating	PEP	benefits	a	Named	Executive	Officer's	Executive	Annual	Incentive	Plan	bonus	and	any base	salary	or	bonus	the	Named	Executive	Officer	elects	to	defer.

The	following	table	shows	the	annual	retirement	benefits	that	would	be	paid	at	normal	retirement	(age	65	or	later)	and	includes	covered	compensation	for the	executive	officers	included	in	the	salary	column	of	the	Summary	Compensation	Table	above.

| Annual |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Covered |  |  | Years\tof\tService |  |  |
| Compensation | 15 | 20 | 25 | 30 | 35 |
| $200,000 | $45,000 | $60,000 | $75,000 | $90,000 | $105,000 |
| 300,000 | 67,500 | 90,000 | 112,500 | 135,000 | 157,500 |
| 400,000 | 90,000 | 120,000 | 150,000 | 180,000 | 210,000 |
| 500,000 | 112,500 | 150,000 | 187,500 | 225,000 | 262,500 |
| 750,000 | 168,750 | 225,000 | 281,250 | 337,500 | 393,750 |
| 1,000,000 | 225,000 | 300,000 | 375,000 | 450,000 | 525,000 |
| 1,250,000 | 281,250 | 375,000 | 468,750 | 562,500 | 656,250 |
| 1,500,000 | 337,500 | 450,000 | 562,500 | 675,000 | 787,500 |

Supplemental	Retirement	Plan	(SRP).	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy participate	in	the	Supplemental	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries.	Executives	may	participate	in	the	SRP,	which	is	an	unfunded	defined benefit	plan,	at	the	invitation	of	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy.	 Mr. Packer	is	the	only	named	executive	officer	who	is	currently	a	participant	in	the	plan.	The	SRP	provides	that,	under	certain	circumstances,	a	participant	may	receive a	monthly	retirement	benefit	payment	for	120	months.	The	amount	of	monthly	payment	shall	not	exceed	2.5%	of	the	participant's	average	basic	annual	pay	(as defined	in	the	SRP).

System	Executive	Retirement	Plan	(SERP).	This	executive	plan	is	an	unfunded	defined	benefit	plan	for	participating	executives,	including	all	of	the	executive officers	named	in	the	Summary	Compensation	Table	(except	for	Mr.	Leonard,	who	receives	non-qualified	supplemental	retirement	benefits	under	the	terms	of	his retention	contract,	which	are	described	below).	Executive	officers	can	choose,	at	retirement,	between	the	retirement	benefits	paid	under	the	SERP	or	those	payable under	the	non-qualified	supplemental	retirement	plans	discussed	above,	and	in	which	they	participate.	SERP	benefits	are	calculated	by	multiplying	the	covered	pay times	the	maximum	pay	replacement	ratios	of	55%,	60%	or	65%	(dependent	on	job	rating	at	retirement)	that	are	attained	at	30	years	of	credited	service.	The	current maximum	pay	replacement	ratio	at	20	years	of	credited	service	for	Ms.	Conley,	Mr.	Denault,	Mr.	Savoff,	Mr.	Smith	and	Mr.	Taylor	is	50%.	 The	current	maximum pay	replacement	ratio	at	20	years	of	credited	service	for	Mr.	Domino,	Mr.	McDonald,	Mr.	Packer	and	Ms.	Shanks	is	45%.	The	ratios	are	reduced	for	each	year	of employment	below	30	years.	The	normal	form	of	benefit	for	a	single	employee	is	a	lifetime	annuity,	and	for	a	married	employee	is	a	reduced	benefit	with	a	50% surviving	spouse	annuity.	These	retirement	payments	may	be	offset	by	any	and	all	defined	benefit	plan	payments	from	the	Company	and	from	prior	employers. These	payments	are	not	subject	to	social	security	offsets.

												Receipt	of	benefits	under	any	of	the	supplemental	retirement	plans	described	above	is	contingent	upon	several	factors.	The	participant	must	agree,	without the	specific	consent	of	the	Entergy	company	for	which	such	participant	was	last	employed,	not	to	take	employment	after	retirement	with	any	entity	that	is	in competition	with,	or	similar	in	nature	to,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy or	any	affiliate	thereof.	Eligibility	for	benefits	is	forfeitable	for	various	reasons,	including	violation	of	an	agreement	with	Entergy	Arkansas,	Entergy	Gulf	States, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy,	or	for	resignation	or	termination	of	employment	for	any	reason	before	or	after normal	retirement	age	and	without	the	employer's	permission.

												Upon	retirement,	and	subject	to	existing	deferral	elections	and	the	provisions	of	Internal	Revenue	Code	Section	409A,	executives	are	able	to	receive	the value	of	their	SERP,	SRP,	or	PEP	benefit	paid	either	as	a	lump	sum	or	a	series	of	annual	payments.	 The	following	table	shows	the	annual	retirement	benefits	that would	be	paid	at	normal	retirement	(age	65	or	later)	under	the	SERP.

# System	Executive	Retirement	Plan	Table	(1)

| Annual |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Covered |  |  | Years\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 |
| 1,500,000 | 450,000 | 675,000 | 750,000 | 825,000 | 900,000 |
| 2,000,000 | 600,000 | 900,000 | 1,000,000 | 1,100,000 | 1,200,000 |
| 2,500,000 | 750,000 | 1,125,000 | 1,250,000 | 1,375,000 | 1,500,000 |
| 3,000,000 | 900,000 | 1,350,000 | 1,500,000 | 1,650,000 | 1,800,000 |

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

System	Executive	Continuity	Plans.	All	Named	Executive	Officers	participate	in	one	of	Entergy's	two	System	Executive	Continuity	Plans.	However,	if	Mr.	Leonard receives	benefits	under	the	change	in	control	protections	of	his	retention	contract,	which	is	described	below,	he	will	not	also	receive	benefits	under	the	Continuity Plans.	Each	plan	provides	severance	pay	and	benefits	under	specified	circumstances	following	a	change	in	control.	In	the	event	a	participant's	employment	is involuntarily	terminated	without	cause	or	if	a	participant	terminates	for	good	reason	during	the	change	in	control	period,	the	named	executive	officers	will	be entitled	to:

a	cash	severance	payment	equal	to	one	to	three	times	base	salary	and	target	bonus	payable	in	a	single	sum	distribution.	The	precise	level	of	payment	is determined	by	the	participant's	management	level.	The	cash	severance	payment	under	the	Continuity	Plans	is	limited	to	2.99	times	base	salary	and	applicable annual	incentive	bonus,	except	for	participants	(other	than	Mr.	Leonard	and	Mr.	Denault)	who	were	entitled	to	receive	a	three	times	severance	payment	prior to	March	of	2004;

continued	medical	and	dental	insurance	coverage	for	one	to	three	years,	but	subject	to	offset	for	any	similar	coverage	provided	by	the	participant's	new employer;

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

payment	of	a	"gross-up"	payment	to	compensate	for	any	excise	taxes	the	participant	might	incur.

Participants	in	the	Continuity	Plans	are	subject	to	post-employment	restrictive	covenants,	including	noncompetition	provisions	that	run	for	two	years	for	Named Executive	Officers	but	extend	to	three	years	if	permissible	under	applicable	law.

Deferred	Compensation	Plans.	Executives	are	eligible	to	defer	earned	income	through	participation	in	Entergy's	Executive	Deferred	Compensation	Plan	("EDCP") or	by	purchasing	phantom	units	of	Entergy	stock	at	fair	market	value	under	the	Equity	Ownership	Plan	("EOP").	Executives	may	under	the	EDCP	defer	receipt	of base	salary,	amounts	due	under	the	executive	plans	described	above,	annual	bonuses,	performance	units,	and	approved	incentive	compensation	such	as	restricted units	and	signing	bonuses.	The	investment	options	available	to	executives	under	the	EDCP	are	similar	to	those	currently	available	under	the	Savings	Plan	of	Entergy Corporation	and	Subsidiaries,	except	that	executives	may	not	invest	in	Entergy	stock	under	the	EDCP.	Executives	may	under	the	EOP	defer	receipt	of	annual bonuses,	performance	units,	restricted	units,	and	pre-2003	option	gains.

# Compensation	of	Directors

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

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

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

# Executive	Employment	Contracts	and	Retention	Agreements

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

Retention	Agreement	with	Mr.	Leonard	-	Mr.	Leonard's	retention	agreement	provides	that	if	he	terminates	his	employment	following	his	attainment	of	age	55,	with or	without	"good	reason"	and	except	for	"cause,"	he	will	be	entitled	to	a	non-qualified	supplemental	retirement	benefit	in	lieu	of	participation	in	the	Company's	non- qualified	supplemental	retirement	plans	such	as	the	SERP,	the	SRP,	or	the	PEP.	 Mr.	Leonard	will	reach	age	55	during	the	2005	calendar	year.	If	Mr.	Leonard's employment	is	terminated	by	Entergy	for	"cause"	at	any	time,	before	or	after	his	attainment	of	age	55,	he	will	forfeit	his	non-qualified	supplemental	retirement benefit.	However,	if	Mr.	Leonard	were	to	leave	without	"cause"	on	or	after	his	attainment	of	age	55,	he	would	be	entitled	to	receive	this	benefit,	plus:

previously	vested	stock	options	(with	248,533	options	vesting	during	2005	in	addition	to	those	described	in	the	"December	31,	2004	Option	Values"	table above),	which	must	be	exercised	within	90	days	of	termination;

income	earned	in	prior	periods	and	deferred	into	available	investment	options,	subject	to	his	deferral	elections	and	the	provisions	of	Internal	Revenue	Code Section	409A.	As	of	December	31,	2004,	Mr.	Leonard	had	credited	to	his	deferral	accounts	150,731	phantom	units	of	Entergy	Company	stock	and	$146,250 in	other	deemed	investment	funds;	and

other	broad-based	compensation	and	benefits	generally	available	to	terminated	employees	under	plans	or	arrangements	in	which	Mr.	Leonard	participates,	in accordance	with	the	terms	and	conditions	of	those	plans	and	arrangements.

												Mr.	Leonard's	non-qualified	supplemental	retirement	benefit	is	calculated	as	a	single	life	annuity	equal	to	60%	of	his	final	monthly	compensation	(as	defined under	the	SERP),	reduced	to	account	for	benefits	payable	to	Mr.	Leonard	under	the	Company's	and	a	former	employer's	qualified	pension	plans.	As	of	December 31,	2004,	his	final	monthly	compensation	was	$191,228	which	amount	would	provide	for	a	single	life	annuity	of	approximately	$1,376,842	per	year	as	his	non- qualified	supplemental	retirement	benefit,	subject	to	the	offsets	described	above.	The	benefit	is	payable	in	a	single	lump	sum,	or	as	periodic	payments,	at	his discretion.	If	elected,	periodic	payments	will	be	due	for	Mr.	Leonard's	life,	and	then	a	reduced	benefit	of	50%	will	be	due	for	the	life	of	his	spouse.

Upon	attainment	of	10	years	of	service	with	the	Company,	which	will	occur	in	2008,	Mr.	Leonard	would	qualify	for	retirement	under	certain	Company plans.	At	this	point,	he	would	become	eligible	to	receive	additional	benefits	comparable	to	those	available	to	other	retirees	of	the	Company,	such	as	accelerated vesting	of	stock	options,	an	extended	period	to	exercise	those	options,	pro-rated	payment	of	annual	and	long-term	incentive	awards,	and	continued	health	and welfare	coverage	to	the	extent	available.

The	retention	agreement	with	Mr.	Leonard	further	provides	that,	subject	to	certain	forfeiture	provisions,	upon	a	termination	of	employment	while	a	Merger	is pending	(a)	by	Entergy	without	"cause"	or	by	Mr.	Leonard	for	"good	reason",	as	such	terms	are	defined	in	the	agreement,	or	(b)	by	reason	of	Mr.	Leonard's	death	or disability:

Entergy	will	pay	to	him	a	lump	sum	cash	severance	payment	equal	to	2.99	times	the	sum	of	Mr.	Leonard's	base	salary	plus	the	lesser	of	(i)	his	target	annual incentive	award,	or	(ii)	his	applicable	annual	incentive	award,	each	subject	to	the	provisions	of	Internal	Revenue	Code	Section	409A;

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

his	non-qualified	supplemental	retirement	benefit	will	fully	vest,	will	be	determined	as	if	he	had	remained	employed	with	Entergy	until	the	attainment	of	age 55,	and	will	commence	upon	his	attainment	of	age	55,	with	certain	adjustments	in	the	case	of	death	or	disability;

he	will	be	entitled	to	immediate	payment	of	performance	awards,	based	upon	an	assumed	target	achievement	of	applicable	performance	goals	under	most circumstances	and	an	assumed	maximum	achievement	of	applicable	performance	goals	in	the	case	of	a	merger-related	termination,	as	defined	in	the agreement;

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

Entergy	will	pay	to	him	a	"gross-up"	payment	to	compensate	him	for	any	excise	taxes	he	might	incur.

Employment	Agreement	with	Ms.	Shanks	-	The	employment	agreement	with	Ms.	Shanks	provides	for	her	continued	employment	until	2011.	During	this	period,	Ms. Shanks	will	continue	to	participate	in	all	executive	plans,	programs,	and	arrangements	for	which	she	is	eligible.	In	October	of	2011,	Ms.	Shanks	will	become	a special	project	coordinator	of	Entergy	Mississippi	or	another	Entergy	System	company	until	2016.	During	her	tenure	as	special	project	coordinator,	Ms.	Shanks	will continue	to	receive	her	same	rate	of	annual	base	salary	in	effect	immediately	prior	to	her	assumption	of	this	post,	but	will	forfeit	an	amount	sufficient	to	fund	this salary	from	amounts	that	would	otherwise	be	credited	to	her	non-qualified	deferral	accounts.	Commencing	in	October	of	2016,	Ms.	Shanks	will	be	eligible	to	retire with	all	of	the	post-retirement	compensation	and	benefits	for	which	she	is	eligible.

												During	the	term	of	the	agreement,	Ms.	Shanks	may	resign,	or	Entergy	may	terminate	her	for	"cause,"	as	defined	in	the	agreement.	In	either	of	those	events, Ms.	Shanks	is	due	no	additional	compensation	or	benefits	under	the	agreement.	If	there	is	a	"change	in	control"	before	October	of	2011,	she	remains	eligible	for benefits	under	the	System	Executive	Continuity	Plan.	If	the	change	in	control	occurs	while	Ms.	Shanks	is	a	special	project	coordinator,	and	Entergy's	obligations under	this	agreement	are	breached,	she	receives:

a	cash	payment	equal	to	her	remaining	unpaid	base	salary;

all	other	benefits	to	which	she	would	be	entitled	had	she	remained	employed	until	the	conclusion	of	the	term	of	the	agreement;	and

all	legal	fees	and	expenses	incurred	in	disputing	in	good	faith	any	term	of	the	agreement.

Retention	agreement	with	Mr.	Smith	-	The	retention	agreement	with	Mr.	Smith	provides	that	Mr.	Smith	will	be	paid	a	retention	payment	of	approximately	$525,000 on	each	of	the	first	three	anniversaries	of	the	date	on	which	a	Merger	is	completed,	if	he	remains	employed	on	each	of	those	dates.	The	agreement	also	provides	that upon	termination	of	employment	while	a	Merger	is	pending	and	for	three	years	after	completion	(a)	by	Mr.	Smith	for	"good	reason"	or	by	Entergy	without	"cause", as	such	terms	are	defined	in	the	agreement	or	(b)	by	reason	of	Mr.	Smith's	death	or	disability:

Entergy	will	pay	to	him	a	lump	sum	cash	severance	payment	equal	to	the	unpaid	installments,	if	any,	of	the	retention	payments	described	above;

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

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

# Personnel	Committee	Interlocks	and	Insider	Participation

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

# Item	12.	Security	Ownership	of	Certain	Beneficial	Owners	and	Management

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

												As	of	December	31,	2004,	the	directors,	the	Named	Executive	Officers,	and	the	directors	and	officers	as	a	group	for	Entergy	Corporation,	Entergy	Arkansas,

Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy,	respectively,	beneficially	owned	directly	or	indirectly common	stock	of	Entergy	Corporation	as	indicated:

| Name | Sole	Voting<br>and<br>Investment<br>Power | Other<br>Beneficial<br>Ownership(b) | Entergy	Corporation<br>Stock	Equivalent	Units	(c) |
| :--- | :--- | :--- | :--- |
| Entergy\tCorporation |  |  |  |
| Maureen\tS.\tBateman* | 2,700 | - | 3,200 |
| W.\tFrank\tBlount* | 9,384 | - | 13,600 |
| Simon\tD.\tdeBree* | 1,442 | - | 2,400 |
| Claiborne\tP.\tDeming* | 6,700 | - | 1,600 |
| Leo\tP.\tDenault** | 951 | 52,423 | 48,924 |
| Alexis\tHerman* | 900 | - | 800 |
| Donald\tC.\tHintz*** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard*** | 13,433 | 1,376,800 | 150,731 |
| Robert\tv.d.\tLuft* | 24,472 | 285,667 | 9,600 |
| Kathleen\tA.\tMurphy*\t(e) | 2,700 | 1,000 | 3,200 |
| Dr.\tPaul\tW.\tMurrill*\t(d) | 2,915 | - | 14,400 |
| James\tR.\tNichols*\t(e) | 8,910 | 3,684 | 14,400 |
| William\tA.\tPercy,\tII* | 2,950 | - | 3,200 |
| Dennis\tH.\tReilley*\t(d) | 600 | - | 4,000 |
| Mark\tT.\tSavoff** | 174 | - | 207 |
| Robert\tD.\tSloan** | 309 | 4,033 | 217 |
| Richard\tJ.\tSmith** | 1,658 | 190,538 | 56,875 |
| Wm.\tClifford\tSmith* | 12,988 | - | 16,800 |
| Bismark\tA.\tSteinhagen*\t(e) | 9,424 | 2,623 | 24,000 |
| C.\tJohn\tWilder** | - | - | - |
| Steven\tV.\tWilkinson* | 750 | - | 800 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 118,815 | 2,979,314 | 537,451 |

| Name | Amount	of	Nature	of<br>Beneficial	Ownership	(a)<br>Sole	Voting<br>and<br>Investment<br>Power | Other<br>Beneficial<br>Ownership(b) | Entergy	Corporation<br>Stock	Equivalent	Units	(c) |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas |  |  |  |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Donald\tC\tHintz** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard** | 13,433 | 1,376,800 | 150,731 |
| Hugh\tT.\tMcDonald*** | 4,733 | 53,999 | 25,967 |
| Mark\tT.\tSavoff*** | 174 | - | 207 |
| Richard\tJ.\tSmith*** | 1,658 | 190,538 | 56,875 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 37,483 | 2,759,540 | 451,418 |
| Entergy\tGulf\tStates |  |  |  |
| E.\tRenae\tConley*** | 1,843 | 107,192 | 40,402 |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Joseph\tF.\tDomino*** | 8,125 | 50,809 | 24,377 |
| Donald\tC.\tHintz** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard** | 13,433 | 1,376,800 | 150,731 |
| Mark\tT.\tSavoff*** | 174 | - | 207 |
| Richard\tJ.\tSmith*** | 1,658 | 190,538 | 56,875 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 42,718 | 2,863,542 | 490,230 |
| Entergy\tLouisiana |  |  |  |
| E.\tRenae\tConley*** | 1,843 | 107,192 | 40,402 |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Donald\tC.\tHintz** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard** | 13,433 | 1,376,800 | 150,731 |
| Mark\tT.\tSavoff*** | 174 | - | 207 |
| Richard\tJ.\tSmith*** | 1,658 | 190,538 | 56,875 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 34,593 | 2,812,733 | 465,853 |
| Entergy\tMississippi |  |  |  |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Donald\tC.\tHintz** | 4,963 | 630,000 | 87,605 |

| J.	Wayne	Leonard** | 13,433 | 1,376,800 | 150,731 |
| :--- | :--- | :--- | :--- |
| Mark\tT.\tSavoff*** | 174 | - | 207 |
| Carolyn\tC.\tShanks*** | 4,999 | 29,333 | 15,698 |
| Richard\tJ.\tSmith*** | 1,658 | 190,538 | 56,875 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 37,749 | 2,734,874 | 441,149 |

| Name | Amount	of	Nature	of<br>Beneficial	Ownership	(a)<br>Sole	Voting<br>and<br>Investment<br>Power | Other<br>Beneficial<br>Ownership(b) | Entergy	Corporation<br>Stock	Equivalent	Units	(c) |
| :--- | :--- | :--- | :--- |
| Entergy\tNew\tOrleans |  |  |  |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Donald\tC.\tHintz** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard** | 13,433 | 1,376,800 | 150,731 |
| Daniel\tF.\tPacker*** | 543 | 40,133 | 5,446 |
| Mark\tT.\tSavoff*** | 174 | - | 207 |
| Richard\tJ.\tSmith*** | 1,658 | 190,538 | 56,875 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 33,293 | 2,745,674 | 430,897 |
| System\tEnergy |  |  |  |
| Leo\tP.\tDenault*** | 951 | 52,423 | 48,924 |
| Donald\tC.\tHintz** | 4,963 | 630,000 | 87,605 |
| J.\tWayne\tLeonard** | 13,433 | 1,376,800 | 150,731 |
| Steven\tC.\tMcNeal* | 5,237 | 19,000 | 3,624 |
| Mark\tT.\tSavoff** | 174 | - | 207 |
| Richard\tJ.\tSmith** | 1,658 | 190,538 | 56,875 |
| Gary\tJ.\tTaylor*** | 1,198 | 79,200 | 12,094 |
| C.\tJohn\tWilder** | - | - | - |
| All\tdirectors\tand\texecutive |  |  |  |
| officers | 38,307 | 2,727,108 | 429,075 |

* Director	of	the	respective	Company

** Named	Executive	Officer	of	the	respective	Company

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

(a) Based	on	information	furnished	by	the	respective	individuals.	Except	as	noted,	each	individual has	sole	voting	and	investment	power.	The	number	of	shares	of	Entergy	Corporation	common stock	owned	by	each	individual	and	by	all	directors	and	executive	officers	as	a	group	does	not exceed	one	percent	of	the	outstanding	Entergy	Corporation	common	stock.

(b) Other	 Beneficial	 Ownership	 includes,	 for	 the	 Named	 Executive	 Officers,	 shares	 of	 Entergy Corporation	common	stock	that	may	be	acquired	within	60	days	after	December	31,	2004,	in	the form	of	unexercised	stock	options	awarded	pursuant	to	the	Equity	Ownership	Plan.

(c) Represents	 the	 balances	 of	 stock	 equivalent	 units	 each	 executive	 holds	 under	 the	 deferral provisions	of	the	Equity	Ownership	Plan	and	the	Defined	Contribution	Restoration	Plan.	These units	will	be	paid	out	in	a	combination	of	Entergy	Corporation	Common	Stock	and	cash	based on	the	value	of	Entergy	Corporation	Common	Stock	on	the	date	of	payout.	The	deferral	period is	 determined	 by	 the	 individual	 and	 is	 at	 least	 two	 years	 from	 the	 award	 of	 the	 bonus.	For directors	of	Entergy	Corporation	the	stock	equivalent	units	are	part	of	the	Service	Award	for Directors.	All	non-employee	directors	are	credited	with	units	for	each	year	of	service	on	the Board.

(d) Dr.	Murrill	and	Mr.	Reilley	have	deferred	receipt	of	an	additional	5,100	shares	and	2,100	shares, respectively.

(e) Includes 1,000 shares	 in	 which	 Ms.	 Murphy	 has	 joint	 ownership, 2,623 shares	 for	 Mr. Steinhagen	that	are	in	his	wife's	name,	and	3,684	shares	for	Mr.	Nichols	that	are	owned	by	a charitable	foundation	that	he	controls.

Entergy	has	two	plans	that	grant	stock	options,	equity	awards,	and	incentive	awards	to	key	employees	of	the	Entergy	subsidiaries.	The	Equity	Ownership Plan	is	a	shareholder-approved	stock-based	compensation	plan.	The	Equity	Awards	Plan	is	a	Board-approved	stock-based	compensation	plan.	The	following	table summarizes	information	about	Entergy's	stock	options	awarded	under	these	plans	as	of	December	31,	2004.

| Plan | Number	of	Securities<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 |  |  |  |
| approved\tby\tsecurity\tholders | 5,327,272 | $45.64 | 5,582,403 |
| Equity\tcompensation\tplans |  |  |  |
| not | 6,982,805 | $39.02 | - |

(a) Effective	upon	 the	May	9,	2003	stockholder	re-approval	of	 the	Equity	Ownership	Plan,	 the Board	directed	that	no	further	awards	be	issued	under	the	Equity	Awards	Plan.	As	of	May	9, 2003,	4,076,628	shares	were	available	for	issuance	under	the	Equity	Awards	Plan.

# Item	13.	Certain	Relationships	and	Related	Transactions

During	2004,	T.	Baker	Smith	&	Son,	Inc.	performed	land-surveying	services	for,	and	received	payments	of	approximately	$735,856	from	Entergy companies.	Mr.	Wm.	Clifford	Smith,	a	director	of	Entergy	Corporation,	is	Chairman	of	the	Board	of	T.	Baker	Smith	&	Son,	Inc.	 Mr.	Smith's	children	own	100%	of the	voting	stock	of	T.	Baker	Smith	&	Son,	Inc.

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

												Entergy's	Code	of	Business	Conduct	and	Ethics	for	Employees	provides	that	any	waiver	of	that	Code	for	executive	officers,	including	a	waiver	of	a	conflict of	interest,	can	be	made	only	by	the	Board,	or	if	the	Board	so	chooses,	by	a	committee	of	independent	directors,	and	must	be	promptly	disclosed	to	Entergy's shareholders.	Entergy's	Code	of	Business	Conduct	and	Ethics	for	Members	of	the	Board	of	Directors	provides	that	any	waiver	of	that	Code,	including	any	waiver	of a	conflict	of	interest,	can	be	made	only	by	the	Board,	following	a	recommendation	by	the	Corporate	Governance	Committee,	and	must	be	promptly	disclosed	to Entergy's	shareholders.

# Item	14.	Principal	Accountant	Fees	and	Services	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi, Entergy	New	Orleans,	and	System	Energy)

												 Aggregate	fees	billed	to	Entergy	Corporation	(consolidated),	Entergy	Arkansas,	Entergy	Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New Orleans,	and	System	Energy	for	the	years	ended	December	31,	2004	and	2003	by	Deloitte	&	Touche	LLP,	the	member	firms	of	Deloitte	Touche	Tohmatsu,	and	their respective	affiliates	(collectively,	"Deloitte	&	Touche"),	which	includes	Deloitte	Consulting	were	as	follows:

| Audit	Fees | $708,875 | $365,800 |
| :--- | :--- | :--- |
| Audit-Related\tFees\t(a) | 183,710 | 147,855 |
| Total\taudit\tand\taudit-related\tfees | 892,585 | 513,655 |
| Tax\tFees | - | - |
| All\tOther\tFees\t(c) | - | - |
| Total\tFees\t(d) | $892,585 | $513,655 |
| System\tEnergy |  |  |
| Audit\tFees | $598,750 | $350,200 |
| Audit-Related\tFees\t(a) | 38,500 | 8,800 |
| Total\taudit\tand\taudit-related\tfees | 637,250 | 359,000 |
| Tax\tFees | - | - |
| All\tOther\tFees | - | - |
| Total\tFees\t(d) | $637,250 | $359,000 |

(a) Includes	 fees	 for	 employee	 benefit plan audits, consultation on financial accounting and reporting,	and	other	attestation	services.

(b) Includes	fees	for	tax	return	review	and	tax	compliance	assistance.

(c) Includes	fees	for	assistance	on	regulatory	matters.	During	2003	the	fees	for	other	services	were approved	under	the	de	minimis	provision.

# Entergy	Audit	Committee	Guidelines	for	Pre-approval	of	Independent	Auditor	Services

												The	Audit	Committee	has	adopted	the	following	guidelines	regarding	the	engagement	of	Entergy's	independent	auditor	to	perform	services	for	Entergy:

1. The	independent	auditor	will	provide	the	Audit	Committee,	for	approval,	an	annual	engagement letter	outlining	the	scope	of	services	proposed	to	be	performed	during	the	fiscal	year,	including audit	services	and	other	permissible	non-audit	services	(e.g.	audit	related	services,	tax	services,	and all	other	services).

2. For	other	permissible	services	not	included	in	the	engagement	letter,	Entergy	management	will submit	a	description	of	the	proposed	service,	including	a	budget	estimate,	to	the	Audit	Committee for	pre-approval.	Management	and	the	independent	auditor	must	agree	that	the	requested	service	is consistent	 with	 the	 SEC's	 rules	 on	 auditor	 independence	 prior	 to	 submission	 to	 the	 Audit Committee.	The	Audit	Committee,	at	its	discretion,	will	pre-approve	permissible	services	and	has established	the	following	additional	guidelines	for	permissible	non-audit	services	provided	by	the independent	auditor:

Aggregate	non-audit	service	fees	are	targeted	at	fifty	percent	or	less	of	the	approved audit	service	fee.

All	other	services	should	only	be	provided	by	the	independent	auditor	if	it	is	the	only qualified	provider	of	that	service	or	if	the	Audit	Committee	specifically	requests	the service.

3. The	Audit	Committee	will	be	informed	quarterly	as	to	the	status	of	pre-approved	services	actually provided	by	the	independent	auditor.

4. To	ensure	prompt	handling	of	unexpected	matters,	the	Audit	Committee	delegates	to	the	Audit Committee	Chair	or	its	designee	the	authority	to	approve	permissible	services	and	fees.	The	Audit Committee	 Chair	 or	 designee	 will	 report	 action	 taken	 to	 the	 Audit	 Committee	 at	 the	 next scheduled	Audit	Committee	meeting.

5. The	Vice	President,	Risk	Management	and	General	Auditor	will	be	responsible	for	tracking	all independent	auditor	fees	and	will	report	quarterly	to	the	Audit	Committee.

# PART	IV

# Item	15.	Exhibits,	Financial	Statement	Schedules

(a)1. Financial	Statements	and	Independent	Auditors'	Reports	for	Entergy,	Entergy	Arkansas,	Entergy Gulf	States,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	System	Energy are	listed	in	the	Table	of	Contents.

# (a)2. Financial	Statement	Schedules

Independent	Auditor's	Report	on	Financial	Statement	Schedules	(see	page	400)

Financial	Statement	Schedules	are	listed	in	the	Index	to	Financial	Statement	Schedules	(see	page S-1)

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.

# 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.

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,	Simon	deBee, Claiborne	P.	Deming,	Alexis	M.	Herman,	Donald	C.	Hintz,	Kathleen	A.	Murphy,	Paul	W.	Murrill,	James	R.	Nichols,	William	A.	Percy,	II,	Dennis	H. Reilley,	Wm.	Clifford	Smith,	Bismark	A.	Steinhagen,	and	Steven	V.	Wilkinson	(Directors).

By:	/s/	Nathan	E.	Langston

(Nathan	E.	Langston,	Attorney-in-fact)

Hugh	T.	McDonald	(Chairman	of	 the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice President,	Chief	Financial	Officer	-	Utility	Operations	Group;	Principal	Financial	Officer);	Leo	P.	Denault,	Mark	T.	Savoff,	and	Richard	J.	Smith (Directors).

Joseph	F.	Domino	(Chairman	of	the	Board,	President,	Chief	Executive	Officer-Texas,	and	Director;	Principal	Executive	Officer);	E.	Renae	Conley (President,	Chief	Executive	Officer-Louisiana,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice	President,	Chief	Financial	Officer	- Utility	Operations	Group;	Principal	Financial	Officer);	Leo	P.	Denault,	Mark	T.	Savoff,	and	Richard	J.	Smith	(Directors).

E.	Renae	Conley	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice	President,

Chief	Financial	Officer	-	Utility	Operations	Group;	Principal	Financial	Officer);	Leo	P.	Denault,	Mark	T.	Savoff,	and	Richard	J.	Smith	(Directors).

Carolyn	C.	Shanks	(Chairman	of	 the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice President,	Chief	Financial	Officer	-	Utility	Operations	Group;	Principal	Financial	Officer);	Leo	P.	Denault,	Mark	T.	Savoff,	and	Richard	J.	Smith (Directors).

Daniel	F.	Packer	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Jay	A.	Lewis	(Vice	President, Chief	Financial	Officer	-	Utility	Operations	Group;	Principal	Financial	Officer);	Leo	P.	Denault,	Mark	T.	Savoff,	and	Richard	J.	Smith	(Directors).

Gary	J.	Taylor	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Theodore	H.	Bunting,	Jr.	(Vice President,	Chief	Financial	Officer	-	Nuclear	Operations;	Principal	Financial	Officer);	Leo	P.	Denault	and	Steven	C.	McNeal	(Directors).

# CONSENTS	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

We	consent	to	the	incorporation	by	reference	in	Post-Effective	Amendments	No.	3	and	5A	on	Form	S-8	and	their	related	prospectuses	to	Registration	Statement	No. 33-54298	of	Entergy	Corporation	on	Form	S-4,	Registration	Statements	No.	333-02503	and	333-22007	of	Entergy	Corporation	on	Form	S-3	and	Registration Statements	No.	333-55692,	333-68950,	333-75097,	333-90914,	and	333-98179	of	Entergy	Corporation	on	Form	S-8	of	our	reports	dated	March	8,	2005,	relating	to the	financial	statements	(which	report	expresses	an	unqualified	opinion	and	includes	an	explanatory	paragraph	regarding	Entergy	Corporation's	change	in	2003	in the	method	of	accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities	and	the	change	in	2002	in	the	method	of	accounting	for goodwill	and	intangible	assets),	financial	statement	schedules,	and	to	management's	report	on	the	effectiveness	of	internal	control	over	financial	reporting,	appearing in	this	Annual	Report	on	Form	10-K	of	Entergy	Corporation	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	333-00103,	333-05045,	and	333-109453	of	Entergy	Arkansas,	Inc.	on	Form	S-3	of	our reports	dated	March	8,	2005,	relating	to	the	financial	statements	of	Entergy	Arkansas,	Inc.	(which	report	includes	an	explanatory	paragraph	regarding	Entergy Arkansas,	Inc.'s	change	in	2003	in	the	method	of	accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities),	financial	statement schedules,	and	to	management's	report	on	the	effectiveness	of	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy Arkansas,	Inc.	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-49739,	33-51181,	333-60957,	and	333-109923	of	Entergy	Gulf	States,	Inc.	on	Form S-3	of	our	reports	dated	March	8,	2005,	relating	to	the	financial	statements	of	Entergy	Gulf	States,	Inc.	(which	report	includes	an	explanatory	paragraph	regarding Entergy	Gulf	States,	Inc.'s	change	in	2003	in	the	method	of	accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities),	financial statement	schedules,	and	to	management's	report	on	the	effectiveness	of	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of Entergy	Gulf	States,	Inc.	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	333-00105,	333-01329,	333-03567,	and	333-114174	of	Entergy	Louisiana,	Inc.	on Form	S-3	of	our	reports	dated	March	8,	2005,	relating	to	the	financial	statements	of	Entergy	Louisiana,	Inc.	(which	report	includes	an	explanatory	paragraph regarding	Entergy	Louisiana,	Inc.'s	change	in	2003	in	the	method	of	accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities), financial	statement	schedules,	and	to	management's	report	on	the	effectiveness	of	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form 10-K	of	Entergy	Louisiana,	Inc.	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-110675	of	Entergy	Mississippi,	Inc.	on	Form	S-3	of	our	reports	dated	March	8, 2005,	relating	to	the	financial	statements	of	Entergy	Mississippi,	Inc.,	financial	statement	schedules,	and	to	management's	report	on	the	effectiveness	of	internal control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Mississippi,	Inc.	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-113586	of	Entergy	New	Orleans,	Inc.	on	Form	S-3	of	our	reports	dated	March	8, 2005,	relating	to	the	financial	statements	of	Entergy	New	Orleans,	Inc.,	financial	statement	schedules,	and	to	management's	report	on	the	effectiveness	of	internal control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	New	Orleans,	Inc.	for	the	year	ended	December	31,	2004.

We	consent	to	the	incorporation	by	reference	in	Registration	Statements	No.	33-47662,	33-61189,	and	333-06717	of	System	Energy	Resources,	Inc.	on	Form	S-3	of our	reports	dated	March	8,	2005,	relating	to	the	financial	statements	of	System	Energy	Resources,	Inc.	(which	report	includes	an	explanatory	paragraph	regarding System	Energy	Resources,	Inc.'s	change	in	2003	in	the	method	of	accounting	for	asset	retirement	obligations)	and	to	management's	report	on	the	effectiveness	of internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	System	Energy	Resources,	Inc.	for	the	year	ended	December	31,	2004.

We	have	audited	the	consolidated	financial	statements	of	Entergy	Corporation	(the	"Corporation")	and	we	have	also	audited	the	financial	statements	of	Entergy Arkansas,	Inc.,	Entergy	Gulf	States,	Inc.,	Entergy	Louisiana,	Inc.,	Entergy	Mississippi,	Inc.,	and	Entergy	New	Orleans,	Inc.	(collectively	the	"Companies"),	as	of December	31,	2004	and	2003,	and	for	each	of	the	three	years	in	the	period	ended	December	31,	2004,	management's	assessment	of	the	effectiveness	of	the Corporation's	and	the	respective	Companies'	internal	control	over	financial	reporting	as	of	December	31,	2004,	and	the	effectiveness	of	the	Corporation's	and	the respective	Companies'	internal	control	over	financial	reporting	as	of	December	31,	2004,	and	have	issued	our	reports	thereon	dated	March	8,	2005.	Our	report	on	the consolidated	financial	statements	of	the	Corporation	expresses	an	unqualified	opinion	and	includes	an	explanatory	paragraph	regarding	its	change	in	2003	in	the method	of	accounting	for	asset	retirement	obligations	and	for	consolidation	of	variable	interest	entities,	and	its	change	in	2002	in	the	method	of	accounting	for goodwill	and	intangible	assets.	Our	reports	on	the	financial	statements	of	Entergy	Arkansas,	Inc.,	Entergy	Gulf	States,	Inc.,	and	Entergy	Louisiana,	Inc.,	each express	an	unqualified	opinion	and	include	an	explanatory	paragraph	regarding	their	change	in	2003	in	the	method	of	accounting	for	asset	retirement	obligations	and for	consolidation	of	variable	interest	entities.	The	financial	statements	described	above,	and	our	respective	reports	thereon	are	included	elsewhere	in	this	2004 Annual	 Report	 to	 Shareholders.	Our	 audits	 also	 included	 the	 consolidated	 financial	 statement	 schedules	 of	 Entergy	 Corporation	 and	 the	 financial	 statement schedules	of	Entergy	Arkansas,	Inc.,	Entergy	Gulf	States,	Inc.,	Entergy	Louisiana,	Inc.,	Entergy	Mississippi,	Inc.,	and	Entergy	New	Orleans,	Inc.,	listed	in	Item	15. These	financial	statement	schedules	are	the	responsibility	of	the	Corporation's	and	the	respective	Companies'	managements.	Our	responsibility	is	to	express	an opinion	based	on	our	audits.	(We	did	not	audit	the	financial	statements	of	Entergy-Koch,	LP,	the	Corporation's	investment	in	which	is	accounted	for	by	use	of	the equity	method.	The	Corporation's	equity	in	earnings	of	unconsolidated	equity	affiliates	for	the	year	ended	December	31,	2003	includes	$180,110,000	for	Entergy- Koch,	LP,	which	earnings	were	audited	by	other	auditors	whose	report,	which	as	to	2003	included	an	explanatory	paragraph	concerning	a	change	in	accounting	for inventory	held	for	trading	purposes	and	energy	trading	contracts	not	qualifying	as	derivatives,	has	been	furnished	to	us,	and	our	opinion,	insofar	as	it	relates	to	the amount	audited	by	other	auditors	 included	for	such	company,	 is	based	solely	on	 the	report	of	such	other	auditors.)	In	our	opinion,	such	financial	statement schedules,	when	considered	in	relation	to	the	basic	financial	statements	taken	as	a	whole,	present	fairly	in	all	material	respects	the	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.

SCHEDULE	I	-	FINANCIAL	STATEMENTS	OF	ENTERGY	CORPORATION STATEMENTS	OF	INCOME

| Equity	in	income	of	subsidiaries | $936,961 | $945,514 | $629,367 |
| :--- | :--- | :--- | :--- |
| \t\tInterest\ton\ttemporary\tinvestments | 37,859 | 36,400 | 46,964 |
| \t\t\t\t\tTotal | 974,820 | 981,914 | 676,331 |

| Administrative	and	general	expenses | 23,643 | 16,844 | 41,126 |
| :--- | :--- | :--- | :--- |
| \t\tReimbursement\ton\tSubsidiary\tStock\tOption\tExpenses | (49,481) | (14,419) | - |
| \t\tIncome\ttaxes\t(credit) | 16,544 | (7,916) | 6,948 |
| \t\tTaxes\tother\tthan\tincome | 1,754 | 753 | 588 |
| \t\tInterest | 72,836 | 59,709 | 28,309 |
| \t\t\t\t\tTotal | 65,296 | 54,971 | 76,971 |
| Net\tIncome | $909,524 | $926,943 | $599,360 |

See	Entergy	Corporation	and	Subsidiaries	Notes	to	Financial

Statements	in	Part	II,	Item	8.

# SCHEDULE	I	-	FINANCIAL	STATEMENTS	OF	ENTERGY	CORPORATION

| Net	income | $909,524 | $926,943 | $599,360 |
| :--- | :--- | :--- | :--- |
| \t\tNoncash\titems\tincluded\tin\tnet\tincome: |  |  |  |
| \t\t\t\tEquity\tin\tearnings\tof\tsubsidiaries | (936,961) | (945,514) | (629,367) |
| \t\t\t\tDeferred\tincome\ttaxes | 32,316 | (2,811) | (4,803) |
| \t\t\t\tDepreciation | 237 | 591 | 912 |
| \t\tChanges\tin\tworking\tcapital: |  |  |  |
| \t\t\t\tReceivables | 38,007 | (878) | 1,430 |
| \t\t\t\tPayables | (678) | (9,258) | 4,898 |
| \t\t\t\tOther\tworking\tcapital\taccounts | (237,727) | 145,014 | (480,711) |
| \t\tCommon\tstock\tdividends\treceived\tfrom\tsubsidiaries | 825,022 | 424,993 | 618,400 |
| \t\tOther | 55,811 | 95,388 | 68,981 |
| \t\t\t\tNet\tcash\tflow\tprovided\tby\toperating\tactivities | 685,551 | 634,468 | 179,100 |
| Investing\tActivities: |  |  |  |
| \t\tInvestment\tin\tsubsidiaries | (99,502) | (254,894) | (256,212) |
| \t\tCapital\texpenditures | (460) | 874 | (768) |
| \t\tChanges\tin\tother\ttemporary\tinvestments | 10,328 | (10,328) | 4,782 |
| \t\tOther | 59,719 | (59,719) | 103 |
| \t\t\t\tNet\tcash\tflow\tused\tin\tinvesting\tactivities | (29,915) | (324,067) | (252,095) |
| Financing\tActivities: |  |  |  |
| \t\tChanges\tin\tcredit\tline\tborrowings | 50,000 | (499,975) | 245,000 |
| \t\tAdvances\tto\tsubsidiaries | (13,312) | (7,254) | (6,460) |
| \t\tCommon\tstock\tdividends\tpaid | (427,901) | (362,814) | (298,991) |
| \t\tRepurchase\tof\tcommon\tstock | (1,017,996) | (8,135) | (118,499) |
| \t\tNotes\treceivable\tto/from\tassociated\tcompanies | 510,113 | (111,595) | (146,380) |
| \t\tIssuance\tof\tcommon\tstock | 170,237 | 217,521 | 130,061 |
| \t\tIssuance\tof\tlong-term\tdebt | - | 534,362 | 265,330 |
| \t\t\t\tNet\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (728,859) | (237,890) | 70,061 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (73,223) | 72,511 | (2,934) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 80,398 | 7,887 | 10,821 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $7,175 | $80,398 | $7,887 |

| which	approximates	market | $7,175 | $80,398 |
| :--- | :--- | :--- |
| \t\t\t\t\t\t\t\tTotal\tcash\tand\tcash\tequivalents | 7,175 | 80,398 |
| \t\tOther\ttemporary\tinvestments | - | 10,328 |
| \t\tNotes\treceivable\t-\tassociated\tcompanies | 116,855 | 626,968 |
| \t\tAccounts\treceivable\t-\tassociated\tcompanies | 8,506 | 44,639 |
| \t\tOther | 62,017 | 53,549 |
| \t\t\t\t\t\tTotal | 194,553 | 815,882 |

| Investment	in	Wholly-owned	Subsidiaries | 8,734,507 | 8,607,556 |
| :--- | :--- | :--- |
| Deferred\tDebits\tand\tOther\tAssets | 556,643 | 606,760 |
| \t\t\t\t\t\t\tTotal | $9,485,703 | $10,030,198 |
| LIABILITIES\tAND\tSHAREHOLDERS'\tEQUITY |  |  |
| Current\tLiabilities: |  |  |
| \t\tAccounts\tpayable: |  |  |
| \t\t\t\tAssociated\tcompanies | $2,190 | $2,433 |
| \t\t\t\tOther | 1,308 | 745 |
| \t\tOther\tcurrent\tliabilities | 11,536 | 188,779 |
| \t\t\t\t\t\tTotal | 15,034 | 191,957 |
| Deferred\tCredits\tand\tNoncurrent\tLiabilities | 223,982 | 234,558 |
| Long-term\tdebt | 950,000 | 900,025 |
| Shareholders'\tEquity: |  |  |
| \t\tCommon\tstock,\t$.01\tpar\tvalue,\tauthorized |  |  |
| \t\t\t500,000,000\tshares;\tissued\t248,174,087\tshares |  |  |
| \t\t\tin\t2004\tand\tin\t2003 | 2,482 | 2,482 |
| \t\tPaid-in\tcapital | 4,835,375 | 4,767,615 |
| \t\tRetained\tearnings | 4,984,302 | 4,502,508 |
| \t\tAccumulated\tother\tcomprehensive\tloss | (93,453) | (7,795) |
| \t\tLess\tcost\tof\ttreasury\tstock\t(31,345,028\tshares\tin |  |  |
| \t\t\t2004\tand\t19,276,445\tshares\tin\t2003) | 1,432,019 | 561,152 |
| \t\t\t\t\t\tTotal\tcommon\tshareholders'\tequity | 8,296,687 | 8,703,658 |
| \t\t\t\t\t\tTotal | $9,485,703 | $10,030,198 |

See	Entergy	Corporation	and	Subsidiaries	Notes	to	Financial	Statements	in	Part	II,	Item	8.

| Retained	Earnings	-	Beginning	of	period | $4,502,508 |  | $3,938,693 |  | $3,638,448 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| \t\tAdd:\tEarnings\tapplicable\tto\tcommon\tstock | 909,524 | $909,524 | 926,943 | $926,943 | 599,360 | $599,360 |
| \t\tDeduct: |  |  |  |  |  |  |
| \t\t\t\tDividends\tdeclared\ton\tcommon\tstock | 427,740 |  | 362,941 |  | 299,031 |  |
| \t\t\t\tCapital\tstock\tand\tother\texpenses | (10) |  | 187 |  | 84 |  |
| \t\t\t\t\t\tTotal | 427,730 |  | 363,128 |  | 299,115 |  |
| Retained\tEarnings\t-\tEnd\tof\tperiod | $4,984,302 |  | $4,502,508 |  | $3,938,693 |  |
| ACCUMULATED\tOTHER\tCOMPREHENSIVE\tINCOME\t(LOSS)\t(Net\nof\ttaxes): |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tperiod: |  |  |  |  |  |  |
| \t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | ($25,811) |  | $17,313 |  | ($17,973) |  |
| \t\tOther\taccumulated\tcomprehensive\t(loss)\titems | 18,016 |  | (39,673) |  | (70,821) |  |
| \t\t\t\tTotal | (7,795) |  | (22,360) |  | (88,794) |  |
| Net\tderivative\tinstrument\tfair\tvalue\tchanges\n\tarising\tduring\tthe\tperiod | (115,600) | (115,600) | (43,124) | (43,124) | 35,286 | 35,286 |
| Foreign\tcurrency\ttranslation\tadjustments | 1,882 | 1,882 | 4,169 | 4,169 | 65,948 | (15,487) |
| Minimum\tpension\tliability\tadjustment | 2,762 | 2,762 | 1,153 | 1,153 | (10,489) | (10,489) |
| Net\tunrealized\tinvestment\tgains\t(losses) | 25,298 | 25,298 | 52,367 | 52,367 | (24,311) | (24,311) |
| Balance\tat\tend\tof\tperiod: |  |  |  |  |  |  |
| \t\tAccumulated\tderivative\tinstrument\tfair\tvalue\tchanges | ($141,411) |  | ($25,811) |  | 17,313 |  |
| \t\tOther\taccumulated\tcomprehensive\t(loss)\titems | 47,958 |  | 18,016 |  | (39,673) |  |
| \t\t\t\tTotal | ($93,453) |  | ($7,795) |  | ($22,360) |  |
| Comprehensive\tIncome |  | $823,866 |  | $941,508 |  | $584,359 |

PAID-IN	CAPITAL

| Paid-in	Capital	-	Beginning	of	period | $4,767,615 | $4,666,753 | $4,662,704 |
| :--- | :--- | :--- | :--- |
| \t\tAdd:\n\t\t\t\tCommon\tstock\tissuances\trelated\tto\tstock\tplans | 67,760 | 100,862 | 4,049 |
| Paid-in\tCapital\t-\tEnd\tof\tperiod | $4,835,375 | $4,767,615 | $4,666,753 |

# SCHEDULE	II	-	VALUATION	AND	QUALIFYING	ACCOUNTS

| Column	A | Column	B | Column	C | Column	D | Column	E |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Other |  |
|  |  | Additions | Changes |  |
|  |  |  | Deductions |  |
|  | Balance\tat |  | from | Balance |
|  | Beginning | Charged\tto | Provisions | at\tEnd |
| Description | of\tPeriod | Income | (Note\t1) | of\tPeriod |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $25,976 | $5,479 | $7,697 | $23,758 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($123,313) | $49,950 | $50,762 | ($124,125) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 34,189 | 667,983 | 88,739 | 613,433 |
| \t\t\t\tEnvironmental | 26,514 | 26,653 | 35,729 | 17,438 |
| \t\t\t\t\t\tTotal | ($62,610) | $744,586 | $175,230 | $506,746 |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $27,285 | $12,598 | $13,907 | $25,976 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($93,941) | $108,221 | $137,593 | ($123,313) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 30,629 | 29,255 | 25,695 | 34,189 |
| \t\t\t\tEnvironmental | 26,488 | 11,621 | 11,595 | 26,514 |
| \t\t\t\t\t\tTotal | ($36,824) | $149,097 | $174,883 | ($62,610) |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $28,355 | $13,024 | $14,094 | $27,285 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($203,537) | $211,210 | $101,614 | ($93,941) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 29,385 | 26,667 | 25,423 | 30,629 |
| \t\t\t\tEnvironmental | 34,802 | 39,368 | 47,682 | 26,488 |
| \t\t\t\t\t\tTotal | ($139,350) | $277,245 | $174,719 | ($36,824) |

(1)	Deductions	from	provisions	represent	losses	or	expenses	for	which	the	respective	provisions	were	created.	In	the	case	of	the	provision	for	doubtful	accounts, such	deductions	are	reduced	by	recoveries	of	amounts	previously	written	off.

(2)	Injuries	and	damages	provision	is	provided	to	absorb	all	current	expenses	as	appropriate	and	for	the	estimated	cost	of	settling	claims	for	injuries	and	damages.

SCHEDULE	II	-	VALUATION	AND	QUALIFYING	ACCOUNTS Years	Ended	December	31,	2004,	2003,	and	2002 (In	Thousands)

Column	A

Column	B

Column	C

Additions

Balance	at Beginning

Charged	to

Column	D Column	E Other Changes Deductions from Balance Provisions at	End

| Description | of	Period | Income | (Note	1) | of	Period |
| :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $9,020 | $3,030 | $1,011 | $11,039 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($25,283) | $10,476 | $14,220 | ($29,027) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 3,353 | 2,849 | 3,589 | 2,613 |
| \t\t\t\tEnvironmental | 1,729 | 1,761 | 1,925 | 1,565 |
| \t\t\t\t\t\tTotal | ($20,201) | $15,086 | $19,734 | ($24,849) |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $8,031 | $2,626 | $1,637 | $9,020 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($13,789) | $31,452 | $42,946 | ($25,283) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 2,700 | 2,950 | 2,297 | 3,353 |
| \t\t\t\tEnvironmental | 1,624 | 2,280 | 2,175 | 1,729 |
| \t\t\t\t\t\tTotal | ($9,465) | $36,682 | $47,418 | ($20,201) |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $5,837 | $2,194 | $- | $8,031 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($178,715) | $183,438 | $18,512 | ($13,789) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 2,890 | 3,129 | 3,319 | 2,700 |
| \t\t\t\tEnvironmental | 6,910 | 1,999 | 7,285 | 1,624 |
| \t\t\t\t\t\tTotal | ($168,915) | $188,566 | $29,116 | ($9,465) |

| Column	A | Column	B | Column	C | Column	D | Column	E |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Other |  |
|  |  | Additions | Changes |  |
|  |  |  | Deductions |  |
|  | Balance\tat |  | from | Balance |
|  | Beginning | Charged\tto | Provisions | at\tEnd |
| Description | of\tPeriod | Income | (Note\t1) | of\tPeriod |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $4,856 | $889 | $3,058 | $2,687 |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tNot\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($57,353) | $7,673 | $7,453 | ($57,133) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 11,554 | 12,288 | 14,872 | 8,970 |
| \t\t\t\tEnvironmental | 14,711 | 20,201 | 30,430 | 4,482 |
| \t\t\t\t\t\tTotal | ($31,088) | $40,162 | $52,755 | ($43,681) |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $5,893 | $4,484 | $5,521 | $4,856 |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tNot\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($45,287) | $26,988 | $39,054 | ($57,353) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 8,284 | 8,805 | 5,535 | 11,554 |
| \t\t\t\tEnvironmental | 15,417 | 3,319 | 4,025 | 14,711 |
| \t\t\t\t\t\tTotal | ($21,586) | $39,112 | $48,614 | ($31,088) |

| Doubtful	Accounts | $3,696 | $3,961 | $1,764 | $5,893 |
| :--- | :--- | :--- | :--- | :--- |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tNot\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($8,721) | $4,486 | $41,052 | ($45,287) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 6,773 | 7,684 | 6,173 | 8,284 |
| \t\t\t\tEnvironmental | 18,716 | 34,296 | 37,595 | 15,417 |
| \t\t\t\t\t\tTotal | $16,768 | $46,466 | $84,820 | ($21,586) |

| Column	A | Column	B | Column	C | Column	D | Column	E |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Other |  |
|  |  | Additions | Changes |  |
|  |  |  | Deductions |  |
|  | Balance\tat |  | from | Balance |
|  | Beginning | Charged\tto | Provisions | at\tEnd |
| Description | of\tPeriod | Income | (Note\t1) | of\tPeriod |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $4,487 | $473 | $1,825 | $3,135 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($40,878) | $20,146 | $20,973 | ($41,705) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 8,537 | 6,188 | 4,329 | 10,396 |
| \t\t\t\tEnvironmental | 7,245 | 2,589 | 1,770 | 8,064 |
| \t\t\t\t\t\tTotal | ($25,096) | $28,923 | $27,072 | ($23,245) |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $4,090 | $2,152 | $1,755 | $4,487 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($39,048) | $36,691 | $38,521 | ($40,878) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 9,114 | 5,256 | 5,833 | 8,537 |
| \t\t\t\tEnvironmental | 8,157 | 2,441 | 3,353 | 7,245 |
| \t\t\t\t\t\tTotal | ($21,777) | $44,388 | $47,707 | ($25,096) |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $2,909 | $1,181 | $- | $4,090 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($26,575) | $14,064 | $26,537 | ($39,048) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 9,829 | 4,750 | 5,465 | 9,114 |
| \t\t\t\tEnvironmental | 8,127 | 1,843 | 1,813 | 8,157 |
| \t\t\t\t\t\tTotal | ($8,619) | $20,657 | $33,815 | ($21,777) |

| Description | of	Period | Income | (Note	1) | of	Period |
| :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $1,375 | $357 | $606 | $1,126 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($3,481) | $10,916 | $4,962 | $2,473 |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 5,414 | 2,938 | 2,803 | 5,549 |
| \t\t\t\tEnvironmental | 495 | 1,236 | 841 | 890 |
| \t\t\t\t\t\tTotal | $2,428 | $15,090 | $8,606 | $8,912 |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $1,633 | $587 | $845 | $1,375 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | ($2,937) | $12,323 | $12,867 | ($3,481) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 7,928 | 7,410 | 9,924 | 5,414 |
| \t\t\t\tEnvironmental | 667 | 1,482 | 1,654 | 495 |
| \t\t\t\t\t\tTotal | $5,658 | $21,215 | $24,445 | $2,428 |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $1,232 | $1,063 | $662 | $1,633 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | $1,279 | $8,882 | $13,098 | ($2,937) |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 6,306 | 5,526 | 3,904 | 7,928 |
| \t\t\t\tEnvironmental | 487 | 886 | 706 | 667 |
| \t\t\t\t\t\tTotal | $8,072 | $15,294 | $17,708 | $5,658 |

| Column	A | Column	B | Column	C | Column	D | Column	E |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Other |  |
|  |  | Additions | Changes |  |
|  |  |  | Deductions |  |
|  | Balance\tat |  | from | Balance |
|  | Beginning | Charged\tto | Provisions | at\tEnd |
| Description | of\tPeriod | Income | (Note\t1) | of\tPeriod |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $3,104 | $612 | $224 | $3,492 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | $3,682 | $739 | $3,154 | $1,267 |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 4,077 | 3,231 | 2,043 | 5,265 |
| \t\t\t\tEnvironmental | 663 | 866 | 763 | 766 |
| \t\t\t\t\t\tTotal | $8,422 | $4,836 | $5,960 | $7,298 |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $4,774 | $2,479 | $4,149 | $3,104 |
| \t\tAccumulated\tProvisions\tNot |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets: |  |  |  |  |
| \t\t\t\tProperty\tinsurance | $7,120 | $767 | $4,205 | $3,682 |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 2,603 | 2,514 | 1,040 | 4,077 |
| \t\t\t\tEnvironmental | 623 | 428 | 388 | 663 |
| \t\t\t\t\t\tTotal | $10,346 | $3,709 | $5,633 | $8,422 |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |
| \t\tAccumulated\tProvisions |  |  |  |  |
| \t\t\t\tDeducted\tfrom\tAssets-- |  |  |  |  |
| \t\t\t\tDoubtful\tAccounts | $4,273 | $501 | $- | $4,774 |

| Property	insurance | $9,195 | $340 | $2,415 | $7,120 |
| :--- | :--- | :--- | :--- | :--- |
| \t\t\t\tInjuries\tand\tdamages\t(Note\t2) | 3,587 | 5,578 | 6,562 | 2,603 |
| \t\t\t\tEnvironmental | 562 | 344 | 283 | 623 |
| \t\t\t\t\t\tTotal | $13,344 | $6,262 | $9,260 | $10,346 |

# 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

# (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)	2	-- Credit	Agreement,	dated	as	of	May	31,	2002,	among	Entergy	Corporation,	as	Borrower, Bayerische	 Hypo-	 und	 Vereinsbank	AG,	 New	 York	 Branch,	 as	 Bank,	 and	 Bayerische Hypo-und	Vereinsbank	AG,	New	York	Branch,	as	Administrative	Agent.

(a)	5	-- Credit	Agreement,	 dated	 as	 of	 May	 13,	 2004,	 among	 Entergy	 Corporation,	 the	 Banks (Citibank,	N.A.,	ABN	AMRO	Bank	N.V.,	BNP	Paribas,	J.	P.	Morgan	Chase	Bank,	The Royal	Bank	of	Scotland	plc,	Barclays	Bank	PLC,	Calyon	New	York	Branch,	KeyBank National	Association,	Morgan	Stanley	Bank,	The	Bank	of	New	York,	Wachovia	Bank, N.A.,	Credit	Suisse	First	Boston	(Cayman	Islands	Branch),	Mellon	Bank,	N.A.,	Regions Bank,	 Societe	 Generale,	 Union	 Bank	 of	 California,	 N.A.,	 Bayerische	 Hypo-und Vereinsbank	AG	(New	York	Branch),	Deutsche	Bank	AG	New	York	Branch,	KBC	Bank N.V.,	Lehman	Brothers	Bank,	FSB,	Mizuho	Corporate	Bank	Limited,	The	Bank	of	Nova Scotia,	 UFJ	 Bank	 Limited,	 and	 West	 LB	 AG,	 New	 York	 Branch,	 Citibank,	 N.A.,	 as Administrative	Agent	and	LC	Issuing	Bank,	and	ABN	AMRO	Bank,	N.V.,	as	LC	Issuing Bank	(4(d)	to	Form	10-Q	for	the	quarter	ended	June	30,	2004	in	1-11299).

(a)	6	-- Credit	Agreement,	dated	as	of	December	14,	2004,	among	Entergy	Corporation,	the	Banks (Citibank,	N.A.,	ABN	AMRO	Bank	N.V.,	BNP	Paribas,	J.	P.	Morgan	Chase	Bank,	The Royal	Bank	of	Scotland	plc,	Barclays	Bank	PLC,	Calyon	New	York	Branch,	KeyBank National	Association,	Morgan	Stanley	Bank,	The	Bank	of	New	York,	Wachovia	Bank, N.A.,	Credit	Suisse	First	Boston	(Cayman	Islands	Branch),	Mellon	Bank,	N.A.,	Regions Bank,	 Societe	 Generale,	 Union	 Bank	 of	 California,	 N.A.,	 Bayerische	 Hypo-und Vereinsbank	AG	(New	York	Branch),	Deutsche	Bank	AG	New	York	Branch,	KBC	Bank N.V.,	Lehman	Brothers	Bank,	FSB,	Mizuho	Corporate	Bank	Limited,	The	Bank	of	Nova Scotia,	and	West	LB	AG,	New	York	Branch,	Citibank,	N.A.,	as	Administrative	Agent	and LC	Issuing	Bank,	and	ABN	AMRO	Bank,	N.V.,	as	LC	Issuing	Bank	(99	to	Form	8-K	dated December	20,	2004	in	1-11299).

(d)	2	-- Indenture,	dated	March	21,	1939,	accepting	resignation	of	The	Chase	National	Bank	of	the City	of	New	York	as	trustee	and	appointing	Central	Hanover	Bank	and	Trust	Company	as successor	trustee	(B-a-1-6	in	Registration	No.	2-4076).

(d)	3	-- Indenture	for	Unsecured	Subordinated	Debt	Securities	relating	to	Trust	Securities,	dated	as of	January	15,	1997	(A-11(a)	to	Rule	24	Certificate	dated	February	6,	1997	in	70-8721).

(d)	4	-- Amended	and	Restated	Trust	Agreement	of	Entergy	Gulf	States	Capital	I	dated	January	28, 1997	of	Series	A	Preferred	Securities	(A-13(a)	to	Rule	24	Certificate	dated	February	6, 1997	in	70-8721).

(d)	5	-- Guarantee	Agreement	between	Entergy	Gulf	States,	Inc.	(as	Guarantor)	and	The	Bank	of New	York	(as	Trustee)	dated	as	of	January	28,	1997	with	respect	to	Entergy	Gulf	States Capital	 I's	 obligation	 on	 its	 8.75%	 Cumulative	 Quarterly	 Income	 Preferred	 Securities, Series	A	(A-14(a)	to	Rule	24	Certificate	dated	February	6,	1997	in	70-8721).

# (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	March	1,	2004,	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)	20	-- Thirtieth	 Assignment	 of	 Availability	 Agreement,	 Consent	 and	 Agreement,	 dated	 as	 of August	 1,	 1996,	 among	 System	 Energy,	 Entergy	Arkansas,	 Entergy	 Louisiana,	 Entergy Mississippi	and	Entergy	New	Orleans,	and	United	States	Trust	Company	of	New	York	and Gerard	F.	Ganey,	as	Trustees	(B-2(a)	to	Rule	24	Certificate	dated	August	8,	1996	in	70- 8511).

(a)	21	-- Thirty-first	Assignment	of	Availability	Agreement,	Consent	and	Agreement,	dated	as	of August	 1,	 1996,	 among	 System	 Energy,	 Entergy	Arkansas,	 Entergy	 Louisiana,	 Entergy Mississippi,	and	Entergy	New	Orleans,	and	United	States	Trust	Company	of	New	York	and Gerard	F.	Ganey,	as	Trustees	(B-2(b)	to	Rule	24	Certificate	dated	August	8,	1996	in	70- 8511).

(a)	22	-- Thirty-fourth	Assignment	of	Availability	Agreement,	Consent	and	Agreement,	dated	as	of September	1,	2002,	among	System	Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans,	The	Bank	of	New	York	and	Douglas	J.	MacInnes (B-2(a)(1)	to	Rule	24	Certificate	dated	October	4,	2001	in	70-9753).

(a)	23	-- Thirty-fifth	Assignment	of	Availability	Agreement,	Consent	and	Agreement,	dated	as	of December	22,	2003,	among	System	Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans,	and	Union	Bank	of	California,	N.A	(10(a)25	 to Form	10-K	for	the	year	ended	December	31,	2003	in	1-11299).

*(a)	24	-- First	 Amendment	 to	 Thirty-fifth	 Assignment	 of	 Availability	 Agreement,	 Consent and Agreement,	dated	as	of	December	17,	2004.

(a)	27	-- Eighteenth	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of September	1,	1986,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey, as	Trustees	(D-2	to	Rule	24	Certificate	dated	October	1,	1986	in	70-7272).

(a)	28	-- Nineteenth	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of September	1,	1986,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey, as	Trustees	(D-3	to	Rule	24	Certificate	dated	October	1,	1986	in	70-7272).

(a)	29	-- Twenty-sixth	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of October	1,	1992,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey,	as Trustees	(B-3(c)	to	Rule	24	Certificate	dated	November	2,	1992	in	70-7946).

(a)	30	-- Twenty-seventh	 Supplementary	 Capital	 Funds	Agreement	 and	Assignment,	 dated	 as	 of April	1,	1993,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey,	as Trustees	(B-3(d)	to	Rule	24	Certificate	dated	May	4,	1993	in	70-7946).

(a)	31	-- Twenty-ninth	Supplementary	Capital	Funds	Agreement	and	Assignment,	dated	as	of	April 1,	1994,	with	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey,	as	Trustees (B-3(f)	to	Rule	24	Certificate	dated	May	6,	1994	in	70-7946).

(a)	32	-- Thirtieth	Supplementary	Capital	Funds	Agreement	and	Assignment,	dated	as	of	August	1, 1996,	among	Entergy	Corporation,	System	Energy	and	United	States	Trust	Company	of New	York	and	Gerard	F.	Ganey,	as	Trustees	(B-3(a)	to	Rule	24	Certificate	dated	August	8, 1996	in	70-8511).

(a)	33	-- Thirty-first	Supplementary	Capital	Funds	Agreement	and	Assignment,	dated	as	of	August	1, 1996,	among	Entergy	Corporation,	System	Energy	and	United	States	Trust	Company	of New	York	and	Gerard	F.	Ganey,	as	Trustees	(B-3(b)	to	Rule	24	Certificate	dated	August	8, 1996	in	70-8511).

(a)	34	-- Thirty-fourth	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of September	1,	2002,	among	Entergy	Corporation,	System	Energy,	The	Bank	of	New	York and	Douglas	J.	MacInnes	(B-3(a)(1)	to	Rule	24	Certificate	dated	October	4,	2002	in	70- 9753).

(a)	36	-- First	Amendment	to	Supplementary	Capital	Funds	Agreements	and	Assignments,	dated	as of	June	1,	1989,	by	and	between	Entergy	Corporation,	System	Energy,	Deposit	Guaranty National	Bank,	United	States	Trust	Company	of	New	York	and	Gerard	F.	Ganey	(C	to	Rule 24	Certificate	dated	June	8,	1989	in	70-7026).

(a)	37	-- First	Amendment	to	Supplementary	Capital	Funds	Agreements	and	Assignments,	dated	as of	June	1,	1989,	by	and	between	Entergy	Corporation,	System	Energy,	United	States	Trust Company	of	New	York	and	Gerard	F.	Ganey	(C	to	Rule	24	Certificate	dated	June	8,	1989	in 70-7123).

(a)	38	-- First	Amendment	to	Supplementary	Capital	Funds	Agreement	and	Assignment,	dated	as	of June	1,	1989,	by	and	between	Entergy	Corporation,	System	Energy	and	Chemical	Bank	(C to	Rule	24	Certificate	dated	June	8,	1989	in	70-7561).

(a)	48	-- First	Amendment	 to	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi	and	Entergy New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1-3517).

(a)	50	-- Middle	South	Utilities	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement,	dated	April	28,	1988	(D-1	 to	Form	U5S	for	 the	year	ended	December	31, 1987).

(a)	51	-- First	Amendment,	dated	January	1,	1990,	to	the	Middle	South	Utilities	Inc.	and	Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-2	to	Form	U5S	for	the year	ended	December	31,	1989).

(a)	52	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(a)	53	-- Third	 Amendment	 dated	 January 1, 1994	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(a)	54	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

*+(a)	76	-- First	Amendment	of	 the	System	Executive	Continuity	Plan	of	Entergy	Corporation	and Subsidiaries,	effective	December	29,	2004.

*+(a)	78	-- First	Amendment	of	the	System	Executive	Continuity	Plan	II	of	Entergy	Corporation	and Subsidiaries,	effective	December	29,	2004.

*+(a)	100	-- Summary	of	Executive	Officer	and	Director	Compensation.

*+(a)	101	-- Terms	of	Restricted	Stock	Grants	for	Outside	Directors.

(b)	44	-- First	Amendment	to	the	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi	and	Entergy New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1-3517).

(b)	50	-- Partial	Termination	Agreement,	dated	as	of	December	1,	1986,	between	System	Energy	and Entergy	Mississippi	(A-2	to	Rule	24	Certificate	dated	January	8,	1987	in	70-5399).

(b)	52	-- First	Amendment,	dated	January	1,	1990	to	the	Middle	South	Utilities	Inc.	and	Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-2	to	Form	U5S	for	the year	ended	December	31,	1989).

(b)	53	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(b)	54	-- Third	 Amendment	 dated	 January 1, 1994	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(b)	55	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

*(b)	57	-- Amendment,	dated	January	1,	2004,	to	Service	Agreement	with	Entergy	Services.

*(b)	58	-- Amendment,	dated	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(b)	61	-- Letter	of	Credit	and	Reimbursement	Agreement,	dated	as	of	December	22,	2003,	among System	Energy	Resources,	Inc.,	Union	Bank	of	California,	N.A.,	as	administrating	bank	and funding	 bank,	 Keybank	 National	 Association,	 as	 syndication	 agent,	 Banc	 One	 Capital Markets,	Inc.,	as	documentation	agent,	and	the	Banks	named	therein,	as	Participating	Banks (10(b)63	to	Form	10-K	for	the	year	ended	December	31,	2003	in	1-9067).

*(b)	62	-- Amendment	to	Letter	of	Credit	and	Reimbursement	Agreement,	dated	as	of	December	22, 2003

*(b)	63	-- First	 Amendment	 and	 Consent, dated as of	 May 3, 2004, to	 Letter of	 Credit and Reimbursement	Agreement.

Agreement,	 dated	 April	 23,	 1982,	 among	 Entergy	 Arkansas	 and	 certain	 other	 System companies,	relating	to	System	Planning	and	Development	and	Intra-System	Transactions (10(a)	1	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

*(c)	9	-- Amendment,	dated	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(c)	39	-- White	 Bluff	 Operating	Agreement,	 dated	 June	 27,	 1977,	 among	 Entergy	Arkansas	 and Arkansas	Electric	Cooperative	Corporation	and	City	Water	and	Light	Plant	of	the	City	of Jonesboro,	Arkansas	(B-2(a)	to	Rule	24	Certificate	dated	June	30,	1977	in	70-6009).

(c)	40	-- White	Bluff	Ownership	Agreement,	dated	June	27,	1977,	among	Entergy	Arkansas	and Arkansas	Electric	Cooperative	Corporation	and	City	Water	and	Light	Plant	of	the	City	of Jonesboro,	Arkansas	(B-1(a)	to	Rule	24	Certificate	dated	June	30,	1977	in	70-6009).

(c)	42	-- Transmission	Agreement,	dated	August	2,	1977,	between	Entergy	Arkansas	and	City	Water and	Light	Plant	of	the	City	of	Jonesboro,	Arkansas	(5(r)3	in	2-60233).

(c)	43	-- Power	Coordination,	Interchange	and	Transmission	Service	Agreement,	dated	as	of	June	27, 1977,	between	Arkansas	Electric	Cooperative	Corporation	and	Entergy	Arkansas	(5(r)4	in 2-60233).

(c)	44	-- Independence	Steam	Electric	Station	Operating	Agreement,	dated	July	31,	1979,	among Entergy	Arkansas	 and	Arkansas	 Electric	 Cooperative	 Corporation	 and	 City	 Water	 and Light	Plant	of	the	City	of	Jonesboro,	Arkansas	and	City	of	Conway,	Arkansas	(5(r)6	in	2- 66235).

(c)	46	-- Independence	Steam	Electric	Station	Ownership	Agreement,	dated	July	31,	1979,	among Entergy	Arkansas	 and	Arkansas	 Electric	 Cooperative	 Corporation	 and	 City	 Water	 and Light	Plant	of	the	City	of	Jonesboro,	Arkansas	and	City	of	Conway,	Arkansas	(5(r)7	in	2- 66235).

(c)	50	-- Consent,	Agreement	and	Assumption,	dated	December	4,	1984,	among	Entergy	Arkansas, Entergy	Mississippi,	other	co-owners	of	the	Independence	Station	and	United	States	Trust Company	of	New	York,	as	Trustee	(10(c)56	to	Form	10-K	for	the	year	ended	December	31, 1984	in	1-10764).

(c)	51	-- Power	Coordination,	Interchange	and	Transmission	Service	Agreement,	dated	as	of	July	31, 1979,	between	Entergy	Arkansas	and	City	Water	and	Light	Plant	of	the	City	of	Jonesboro, Arkansas	(5(r)8	in	2-66235).

(c)	52	-- Power	Coordination,	Interchange	and	Transmission	Agreement,	dated	as	of	June	29,	1979, between	City	of	Conway,	Arkansas	and	Entergy	Arkansas	(5(r)9	in	2-66235).

(c)	56	-- First	Amendment	 to	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1-3517).

(c)	60	-- First	Amendment,	dated	January	1,	1990,	to	the	Middle	South	Utilities,	Inc.	and	Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-2	to	Form	U5S	for	the year	ended	December	31,	1989).

(c)	61	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(c)	62	-- Third	 Amendment	 dated	 January 1, 1994,	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(c)	63	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

(c)	72	-- Power	Coordination,	Interchange	and	Transmission	Service	Agreement	between	Entergy Power	and	Entergy	Arkansas,	dated	as	of	August	28,	1990	(10(c)71	to	Form	10-K	for	the year	ended	December	31,	1990	in	1-10764).

(d)	1	-- Guaranty	Agreement,	dated	August	1,	1992,	between	Entergy	Gulf	States	and	Hibernia National	Bank,	relating	to	Pollution	Control	Revenue	Refunding	Bonds	of	the	Industrial Development	Board	of	the	Parish	of	Calcasieu,	Inc.	(Louisiana)	(10-1	to	Form	10-K	for	the year	ended	December	31,	1992	in	1-27031).

(d)	2	-- Guaranty	Agreement,	dated	January	1,	1993,	between	Entergy	Gulf	States	and	Hancock Bank	of	Louisiana,	relating	to	Pollution	Control	Revenue	Refunding	Bonds	of	the	Parish	of Pointe	Coupee	(Louisiana)	(10-2	to	Form	10-K	for	the	year	ended	December	31,	1992	in	1- 27031).

(d)	3	-- Deposit	Agreement,	dated	as	of	December	1,	1983	between	Entergy	Gulf	States,	Morgan Guaranty	Trust	Co.	as	Depositary	and	the	Holders	of	Depository	Receipts,	relating	to	the Issue	of	900,000	Depositary	Preferred	Shares,	each	representing	1/2	share	of	Adjustable Rate	Cumulative	Preferred	Stock,	Series	E-$100	Par	Value	(4-17	to	Form	10-K	for	the	year ended	December	31,	1983	in	1-27031).

(d)	4	-- Agreement	effective	February	1,	1964,	between	Sabine	River	Authority,	State	of	Louisiana, and	Sabine	River	Authority	of	Texas,	and	Entergy	Gulf	States,	Central	Louisiana	Electric Company,	Inc.,	and	Louisiana	Power	&	Light	Company,	as	supplemented	(B	to	Form	8-K dated	May	6,	1964,	A	to	Form	8-K	dated	October	5,	1967,	A	to	Form	8-K	dated	May	5, 1969,	and	A	to	Form	8-K	dated	December	1,	1969	in	1-27031).

(d)	5	-- Joint	 Ownership	 Participation	 and	 Operating	 Agreement	 regarding	 River	 Bend	 Unit	 1 Nuclear	Plant,	dated	August	20,	1979,	between	Entergy	Gulf	States,	Cajun,	and	SRG&T; Power	Interconnection	Agreement	with	Cajun,	dated	June	26,	1978,	and	approved	by	the REA	on	August	16,	1979,	between	Entergy	Gulf	States	and	Cajun;	and	Letter	Agreement regarding	 CEPCO	 buybacks,	 dated	August	 28,	 1979,	 between	 Entergy	 Gulf	 States	 and Cajun	(2,	3,	and	4,	respectively,	to	Form	8-K	dated	September	7,	1979	in	1-27031).

(d)	11	-- Agreements	between	Southern	Company	and	Entergy	Gulf	States,	dated	February	25,	1982, which	cover	the	construction	of	a	140-mile	transmission	line	to	connect	the	two	systems, purchase	of	power	and	use	of	 transmission	facilities	(10-31	 to	Form	10-K	for	 the	year ended	December	31,	1981	in	1-27031).

(d)	13	-- First	Amended	Power	Sales	Agreement,	dated	December	1,	1985	between	Sabine	River Authority,	State	of	Louisiana,	and	Sabine	River	Authority,	State	of	Texas,	and	Entergy	Gulf States,	Central	Louisiana	Electric	Co.,	Inc.,	and	Louisiana	Power	and	Light	Company	(10- 72	to	Form	10-K	for	the	year	ended	December	31,	1985	in	1-27031).

+(d)	15	-- Trust	Agreement	for	Deferred	Payments	to	be	made	by	Entergy	Gulf	States	pursuant	to	the Executive	Income	Security	Plan,	by	and	between	Entergy	Gulf	States	and	Bankers	Trust Company,	effective	November	1,	1986	(10-78	to	Form	10-K	for	the	year	ended	December 31,	1986	in	1-27031).

+(d)	16	-- Trust	 Agreement	 for	 Deferred	 Installments	 under	 Entergy	 Gulf	 States'	 Management Incentive	Compensation	Plan	and	Administrative	Guidelines	by	and	between	Entergy	Gulf States	and	Bankers	Trust	Company,	effective	June	1,	1986	(10-79	to	Form	10-K	for	the year	ended	December	31,	1986	in	1-27031).

+(d)	17	-- Nonqualified	 Deferred	 Compensation	 Plan	 for	 Officers,	 Nonemployee	 Directors	 and Designated	 Key	 Employees,	 effective	 December	 1,	 1985,	 as	 amended,	 continued	 and completely	 restated	 effective	 as	 of	 March 1, 1991 (10-3 to	 Amendment	 No. 8 in Registration	No.	2-76551).

+(d)	18	-- Trust	Agreement	 for	 Entergy	 Gulf	 States'	 Nonqualified	 Directors	 and	 Designated	 Key Employees	by	and	between	Entergy	Gulf	States	and	First	City	Bank,	Texas-Beaumont, N.A.	(now	Texas	Commerce	Bank),	effective	July	1,	1991	(10-4	to	Form	10-K	for	the	year ended	December	31,	1992	in	1-27031).

(d)	21	-- Trust	and	Investment	Management	Agreement	between	Entergy	Gulf	States	and	Morgan Guaranty	and	Trust	Company	of	New	York	(the	"Decommissioning	Trust	Agreement)	with respect	to	decommissioning	funds	authorized	to	be	collected	by	Entergy	Gulf	States,	dated March	15,	1989	(10-66	to	Form	10-K	for	the	year	ended	December	31,	1988	in	1-27031).

*(d)	23	-- Amendment	No.	3	dated	March	5,	1998	between	Entergy	Gulf	States	and	Mellon	Bank	to Decommissioning	Trust	Agreement.

*(d)	24	-- Amendment	No.	4	dated	December	17,	2003	between	Entergy	Gulf	States	and	Mellon	Bank to	Decommissioning	Trust	Agreement.

(d)	29	-- Operating	Agreement	between	Entergy	Operations	and	Entergy	Gulf	States,	dated	as	of December	31,	1993	(B-2(f)	to	Rule	24	Certificate	in	70-8059).

(d)	30	-- Guarantee	Agreement	between	Entergy	Corporation	and	Entergy	Gulf	States,	dated	as	of December	31,	1993	(B-5(a)	to	Rule	24	Certificate	in	70-8059).

*(d)	33	-- Amendment,	dated	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(d)	34	-- Third	 Amendment,	 dated	 January 1, 1994,	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(d)	35	-- Fourth	Amendment,	dated	April	1,	1997,	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

(d)	38	-- Refunding	Agreement	dated	as	of	May	1,	1998	between	Entergy	Gulf	States	and	Industrial Development	Board	of	the	Parish	of	Calcasieu,	Inc.	(B-3(b)	to	Rule	24	Certificate	dated January	29,	1999	in	70-8721).

(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	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(e)	29	-- First	Amendment	to	the	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi	and	Entergy New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1-3517).

(e)	32	-- First	Amendment,	dated	January	1,	1990,	to	the	Middle	South	Utilities,	Inc.	and	Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	January	1,	1990	(D-2 to	Form	U5S	for	the	year	ended	December	31,	1989).

(e)	33	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(e)	34	-- Third	 Amendment	 dated	 January 1, 1994	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(e)	35	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

(e)	36	-- Contract	for	Disposal	of	Spent	Nuclear	Fuel	and/or	High-Level	Radioactive	Waste,	dated February	2,	1984,	among	DOE,	System	Fuels	and	Entergy	Louisiana	(10(d)33	to	Form	10- K	for	the	year	ended	December	31,	1984	in	1-8474).

(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	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(f)	31	-- Consent,	Agreement	and	Assumption,	dated	December	4,	1984,	among	Entergy	Arkansas, Entergy	Mississippi,	other	co-owners	of	the	Independence	Station	and	United	States	Trust Company	of	New	York,	as	Trustee	(10(c)56	to	Form	10-K	for	the	year	ended	December	31, 1984	in	0-375).

(f)	35	-- First	Amendment	to	the	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	 Energy	 and	 Entergy	 Arkansas,	 Entergy	 Louisiana,	 Entergy	 Mississippi,	 and Entergy	New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1- 3517).

(f)	39	-- Partial	Termination	Agreement,	dated	as	of	December	1,	1986,	between	System	Energy	and Entergy	Mississippi	(A-2	to	Rule	24	Certificate	dated	January	8,	1987	in	70-5399).

(f)	41	-- First	Amendment	dated	January	1,	1990	to	the	Middle	South	Utilities	Inc.	and	Subsidiary Companies	Intercompany	Tax	Allocation	Agreement	(D-2	to	Form	U5S	for	the	year	ended December	31,	1989).

(f)	42	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(f)	43	-- Third	 Amendment	 dated	 January 1, 1994	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(f)	44	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

(g)	1	-- Agreement,	dated	April	23,	1982,	among	Entergy	New	Orleans	and	certain	other	System companies,	relating	to	System	Planning	and	Development	and	Intra-System	Transactions (10(a)1	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

*(g)	9	-- Amendment,	dated	March	1,	2004,	to	Service	Agreement	with	Entergy	Services.

(g)	27	-- First	Amendment	to	the	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi	and	Entergy New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in	1-3517).

(g)	31	-- First	Amendment,	dated	January	1,	1990,	to	the	Middle	South	Utilities,	Inc.	and	Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-2	to	Form	U5S	for	the year	ended	December	31,	1989).

(g)	32	-- Second	Amendment	 dated	 January	 1,	 1992,	 to	 the	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3	to	Form	U5S	for	the year	ended	December	31,	1992).

(g)	33	-- Third	 Amendment	 dated	 January 1, 1994	 to	 Entergy	 Corporation	 and	 Subsidiary Companies	Intercompany	Income	Tax	Allocation	Agreement	(D-3(a)	to	Form	U5S	for	the year	ended	December	31,	1993).

(g)	34	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies Intercompany	Income	Tax	Allocation	Agreement	(D-5	to	Form	U5S	for	the	year	ended December	31,	1996).

# (12)	Statement	Re	Computation	of	Ratios

*(a) Entergy	Arkansas'	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to Fixed	Charges	and	Preferred	Dividends,	as	defined.

*(b) Entergy	Gulf	States'	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to Fixed	Charges	and	Preferred	Dividends,	as	defined.

*(c) Entergy	Louisiana's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to Fixed	Charges	and	Preferred	Dividends,	as	defined.

*(d) Entergy	Mississippi's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings to	Fixed	Charges	and	Preferred	Dividends,	as	defined.

*(e) Entergy	New	Orleans'	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings to	Fixed	Charges	and	Preferred	Dividends,	as	defined.

*(f) System	Energy's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges,	as	defined.

# *(21)	Subsidiaries	of	the	Registrants

# (23)	Consents	of	Experts	and	Counsel

# *(a) The	consent	of	Deloitte	&	Touche	LLP	is	contained	herein	at	page	398.

*(b) Consent	of	Ernst	&	Young	LLP.

# *(24)	Powers	of	Attorney

*(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.



Question: what are the deferred fuel cost revisions as a percentage of 2004 net revenue?
Answer: 3.16%