Table	of	Contents

# 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,	2013

# 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:

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

Indicate	by	check	mark	if	the	registrants	are	well-known	seasoned	issuers,	as	defined	in	Rule	405	of	the	Securities	Act.

Indicate	by	check	mark	if	the	registrants	are	not	required	to	file	reports	pursuant	to	Section	13	or	Section	15(d)	of	the	Act.

Yes No Entergy	Corporation ü Entergy	Arkansas,	Inc. ü Entergy	Gulf	States	Louisiana,	L.L.C. ü Entergy	Louisiana,	LLC ü Entergy	Mississippi,	Inc. ü Entergy	New	Orleans,	Inc. ü Entergy	Texas,	Inc. ü System	Energy	Resources,	Inc. ü

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	þ	No	o

Indicate	by	check	mark	whether	the	registrants	have	submitted	electronically	and	posted	on	Entergy's	corporate	Web	site,	if	any,	every	Interactive Data	File	required	to	be	submitted	and	posted	pursuant	to	Rule	405	of	Regulation	S-T	(§232.405	of	this	chapter)	during	the	preceding	12	months (or	for	such	shorter	period	that	the	registrant	was	required	to	submit	and	post	such	files).		Yes	þ	No	o

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

Indicate	by	check	mark	whether	the	registrant	is	a	large	accelerated	filer,	an	accelerated	filer,	a	non-accelerated	filer,	or	a	smaller	reporting company.	 	See	definitions	of	"accelerated	filer,"	"large	accelerated	filer,"	and	"smaller	reporting	company"	in	Rule	12b-2	of	the	Securities Exchange	Act	of	1934.

Indicate	by	check	mark	whether	the	registrants	are	shell	companies	(as	defined	in	Rule	12b-2	of	the	Act.)		Yes	o		No	þ

System	Energy	Resources	meets	the	requirements	set	forth	in	General	Instruction	I(1)	of	Form	10-K	and	is	therefore	filing	this	Form	10-K with	reduced	disclosure	as	allowed	in	General	Instruction	I(2).		System	Energy	Resources	is	reducing	its	disclosure	by	not	including	Part	III, Items	10	through	13	in	its	Form	10-K.

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	2013,	was	$12.4	billion	based	on	the	reported	last	sale	price	of	$69.68	per	share	for	such	stock	on	the	New	York	Stock	Exchange	on June	28,	2013.		Entergy	Corporation	is	the	sole	holder	of	the	common	stock	of	Entergy	Arkansas,	Inc.,	Entergy	Mississippi,	Inc.,	Entergy	New Orleans,	Inc.,	Entergy	Texas,	Inc.,	and	System	Energy	Resources,	Inc.		Entergy	Corporation	is	the	sole	holder	of	the	common	stock	of	Entergy Louisiana	Holdings,	Inc.,	which	is	the	sole	holder	of	the	common	membership	interests	in	Entergy	Louisiana,	LLC.		Entergy	Corporation	is	the sole	holder	of	the	common	stock	of	EGS	Holdings,	Inc.,	which	is	the	sole	holder	of	the	common	membership	interests	in	Entergy	Gulf	States Louisiana,	L.L.C.

# 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 2,	2014,	are	incorporated	by	reference	into	Part	III	hereof.

(Page	left	blank	intentionally)

| Statements	of	Changes	in	Equity	for	the	Years	Ended	December	31,	2013,	2012,	and	2011 | Part	II.	Item	8. | 328 |
| :--- | :--- | :--- |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 329 |
| Entergy\tLouisiana,\tLLC\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 330 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 348 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 349 |
| Consolidated\tStatements\tof\tComprehensive\tIncome\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\n2011 | Part\tII.\tItem\t8. | 350 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 351 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2013\tand\t2012 | Part\tII.\tItem\t8. | 352 |
| Consolidated\tStatements\tof\tChanges\tin\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 354 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 355 |
| Entergy\tMississippi,\tInc. |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 356 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 369 |
| Income\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 370 |
| Statements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 371 |
| Balance\tSheets,\tDecember\t31,\t2013\tand\t2012 | Part\tII.\tItem\t8. | 372 |
| Statements\tof\tChanges\tin\tCommon\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 374 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 375 |
| Entergy\tNew\tOrleans,\tInc. |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 376 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 387 |
| Income\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 388 |
| Statements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 389 |
| Balance\tSheets,\tDecember\t31,\t2013\tand\t2012 | Part\tII.\tItem\t8. | 390 |
| Statements\tof\tChanges\tin\tCommon\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 392 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 393 |
| Entergy\tTexas,\tInc.\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 394 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 407 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 408 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 409 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2013\tand\t2012 | Part\tII.\tItem\t8. | 410 |
| Consolidated\tStatements\tof\tChanges\tin\tCommon\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\nand\t2011 | Part\tII.\tItem\t8. | 412 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 413 |
| System\tEnergy\tResources,\tInc. |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 414 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 423 |
| Income\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 424 |
| Statements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | Part\tII.\tItem\t8. | 425 |

This	combined	Form	10-K	is	separately	filed	by	Entergy	Corporation	and	its	seven	"Registrant	Subsidiaries":	Entergy	Arkansas, Inc.,	Entergy	Gulf	States	Louisiana,	L.L.C.,	Entergy	Louisiana,	LLC,	Entergy	Mississippi,	Inc.,	Entergy	New	Orleans,	Inc.,	Entergy Texas,	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	reporting	company.		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	reporting	company,	except	for	the	Notes to	the	financial	statements.		The	Notes	to	the	financial	statements	for	all	of	the	reporting	companies	are	combined.		All	Items	other	than 6,	7,	and	8	are	combined	for	the	reporting	companies.

# FORWARD-LOOKING	INFORMATION

In	this	combined	report	and	from	time	to	time,	Entergy	Corporation	and	the	Registrant	Subsidiaries	each	makes	statements	as	a	registrant 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.	 	Words	such	as	"may,"	"will,"	"could,"	"project," "believe,"	 "anticipate,"	 "intend,"	 "expect,"	 "estimate,"	 "continue,"	 "potential,"	 "plan,"	 "predict,"	 "forecast,"	 and	 other	 similar	 words	 or expressions	are	intended	to	identify	forward-looking	statements	but	are	not	the	only	means	to	identify	these	statements.		Although	each	of	these registrants	believes	that	these	forward-looking	statements	and	the	underlying	assumptions	are	reasonable,	it	cannot	provide	assurance	that	they will	prove	correct.		Any	forward-looking	statement	is	based	on	information	current	as	of	the	date	of	this	combined	report	and	speaks	only	as	of	the date	on	which	such	statement	is	made.		Except	to	the	extent	required	by	the	federal	securities	laws,	these	registrants	undertake	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.	 	There	are	factors	 that	could	cause	actual	results	 to	differ materially	from	those	expressed	or	implied	in	the	forward-looking	statements,	including	(a)	those	factors	discussed	or	incorporated	by	reference	in Item	1A.	Risk	Factors,	(b)	those	factors	discussed	or	incorporated	by	reference	in	Management's	Financial	Discussion	and	Analysis,	and	(c)	the following	factors	(in	addition	to	others	described	elsewhere	in	this	combined	report	and	in	subsequent	securities	filings):

•resolution	of	pending	and	future	rate	cases	and	negotiations,	including	various	performance-based	rate	discussions,	Entergy's	utility supply	plan,	and	recovery	of	fuel	and	purchased	power	costs;

•the	termination	of	Entergy	Arkansas's	participation	in	the	System	Agreement,	which	occurred	in	December	2013,	the	termination	of Entergy	Mississippi's	participation	in	the	System	Agreement	in	November	2015,	the	termination	of	Entergy	Texas's,	Entergy	Gulf States	Louisiana's,	and	Entergy	Louisiana's	participation	in	the	System	Agreement	after	expiration	of	the	recently	proposed	60-month notice	period	or	such	other	period	as	approved	by	the	FERC;

•regulatory	and	operating	challenges	and	uncertainties	associated	with	the	Utility	operating	companies'	move	to	the	MISO	RTO,	which occurred	in	December	2013;

•changes	in	utility	regulation,	including	the	beginning	or	end	of	retail	and	wholesale	competition,	the	ability	to	recover	net	utility	assets and	other	potential	stranded	costs,	and	the	application	of	more	stringent	transmission	reliability	requirements	or	market	power	criteria by	the	FERC;

•changes	in	regulation	of	nuclear	generating	facilities	and	nuclear	materials	and	fuel,	including	with	respect	to	the	planned	or	potential shutdown	of	nuclear	generating	facilities	owned	or	operated	by	the	Entergy	Wholesale	Commodities	business,	and	the	effects	of	new	or existing	safety	or	environmental	concerns	regarding	nuclear	power	plants	and	nuclear	fuel;

•resolution	of	pending	or	future	applications,	and	related	regulatory	proceedings	and	litigation,	for	license	renewals	or	modifications	of nuclear	generating	facilities;

•the	 performance	 of	 and	 deliverability	 of	 power	 from	 Entergy's	 generation	 resources, including the	 capacity	 factors	 at its	 nuclear generating	facilities;

•Entergy's	ability	to	develop	and	execute	on	a	point	of	view	regarding	future	prices	of	electricity,	natural	gas,	and	other	energy-related commodities;

•prices	for	power	generated	by	Entergy's	merchant	generating	facilities	and	the	ability	to	hedge,	meet	credit	support	requirements	for hedges,	sell	power	forward	or	otherwise	reduce	the	market	price	risk	associated	with	those	facilities,	including	the	Entergy	Wholesale Commodities	nuclear	plants;

•the	prices	and	availability	of	fuel	and	power	Entergy	must	purchase	for	its	Utility	customers,	and	Entergy's	ability	to	meet	credit	support requirements	for	fuel	and	power	supply	contracts;

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

•changes	in	law	resulting	from	federal	or	state	energy	legislation	or	legislation	subjecting	energy	derivatives	used	in	hedging	and	risk management	transactions	to	governmental	regulation;

# FORWARD-LOOKING	INFORMATION	(Concluded)

•changes	in	environmental,	tax,	and	other	laws,	including	requirements	for	reduced	emissions	of	sulfur,	nitrogen,	carbon,	greenhouse gases,	mercury,	and	other	regulated	air	and	water	emissions,	and	changes	in	costs	of	compliance	with	environmental	and	other	laws	and regulations;

•uncertainty	regarding	the	establishment	of	interim	or	permanent	sites	for	spent	nuclear	fuel	and	nuclear	waste	storage	and	disposal; •variations	in	weather	and	the	occurrence	of	hurricanes	and	other	storms	and	disasters,	including	uncertainties	associated	with	efforts	to remediate	the	effects	of	hurricanes,	ice	storms,	or	other	weather	events	and	the	recovery	of	costs	associated	with	restoration,	including accessing	funded	storm	reserves,	federal	and	local	cost	recovery	mechanisms,	securitization,	and	insurance;

•effects	of	climate	change;

•changes	in	the	quality	and	availability	of	water	supplies	and	the	related	regulation	of	water	use	and	diversion;

•Entergy's	ability	to	manage	its	capital	projects	and	operation	and	maintenance	costs;

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

•the	economic	climate,	and	particularly	economic	conditions	in	Entergy's	Utility	service	area	and	the	Northeast	United	States	and	events that	could	influence	economic	conditions	in	those	areas;

•the	effects	of	Entergy's	strategies	to	reduce	tax	payments;

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

execute	share	repurchase	programs,	and	fund	investments	and	acquisitions;

•actions	of	rating	agencies,	including	changes	in	the	ratings	of	debt	and	preferred	stock,	changes	in	general	corporate	ratings,	and	changes in	the	rating	agencies'	ratings	criteria;

•changes	in	inflation	and	interest	rates;

•the	effect	of	litigation	and	government	investigations	or	proceedings;

•changes	in	technology,	including	with	respect	to	new,	developing,	or	alternative	sources	of	generation;

•the	potential	effects	of	threatened	or	actual	terrorism,	cyber-attacks	or	data	security	breaches,	including	increased	security	costs,	and	war or	a	catastrophic	event	such	as	a	nuclear	accident	or	a	natural	gas	pipeline	explosion;

•Entergy's	ability	to	attract	and	retain	talented	management	and	directors;

•changes	in	accounting	standards	and	corporate	governance;

•declines	in	the	market	prices	of	marketable	securities	and	resulting	funding	requirements	for	Entergy's	defined	benefit	pension	and	other postretirement	benefit	plans;

•future	wage	and	employee	benefit	costs,	including	changes	in	discount	rates	and	returns	on	benefit	plan	assets;

•changes	in	decommissioning	trust	fund	values	or	earnings	or	in	the	timing	of	or	cost	to	decommission	nuclear	plant	sites;

•the	implementation	of	the	shutdown	of	Vermont	Yankee	by	the	end	of	2014	and	the	related	decommissioning	of	Vermont	Yankee;

•the	effectiveness	of	Entergy's	risk	management	policies	and	procedures	and	the	ability	and	willingness	of	its	counterparties	to	satisfy their	financial	and	performance	commitments;

•factors	that	could	lead	to	impairment	of	long-lived	assets;	and

•the	ability	to	successfully	complete	merger,	acquisition,	or	divestiture	plans,	regulatory	or	other	limitations	imposed	as	a	result	of merger,	acquisition,	or	divestiture,	and	the	success	of	the	business	following	a	merger,	acquisition,	or	divestiture.

# DEFINITIONS

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

# DEFINITIONS	(Continued)

# DEFINITIONS	(Concluded)

# ENTERGY	CORPORATION	AND	SUBSIDIARIES

# MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS

Entergy	operates	primarily	through	two	business	segments:	Utility	and	Entergy	Wholesale	Commodities.

•The	Utility	business	segment	includes	the	generation,	transmission,	distribution,	and	sale	of	electric	power	in	portions	of	Arkansas, Mississippi,	Texas,	and	Louisiana,	including	the	City	of	New	Orleans;	and	operates	a	small	natural	gas	distribution	business. •The	Entergy	Wholesale	Commodities	business	segment	includes	the	ownership	and	operation	of	six	nuclear	power	plants	located	in	the northern	United	States	and	the	sale	of	the	electric	power	produced	by	those	plants	to	wholesale	customers.		In	August	2013,	Entergy announced	plans	to	close	and	decommission	Vermont	Yankee.	The	plant	is	expected	to	cease	power	production	in	the	fourth	quarter	2014 after	its	current	fuel	cycle.	This	business	also	provides	services	to	other	nuclear	power	plant	owners.	Entergy	Wholesale	Commodities also	owns	interests	in	non-nuclear	power	plants	that	sell	the	electric	power	produced	by	those	plants	to	wholesale	customers.

On	December	5,	2011,	Entergy	announced	that	it	would	spin	off	its	transmission	business	and	merge	it	with	a	newly	formed	subsidiary	of ITC	Holdings	Corp.	(ITC).	On	December	13,	2013,	Entergy	and	ITC	mutually	agreed	to	terminate	the	transaction	following	denial	by	the	MPSC of	 the	 joint	 application	 related	 to	 the	 transaction.	Entergy	 and	 ITC	 have	 withdrawn	 transaction-related	 filings	 submitted	 to	 Entergy's	 retail regulators	and	the	FERC.

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

|  |  | %	of	Revenue | %	of	Revenue | %	of	Net	Income | %	of	Net	Income | %	of	Net	Income | %	of	Total	Assets | %	of	Total	Assets |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Segment | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 |
| Utility | 80 | 78 | 79 | 116 | 110 | 82 | 82 | 82 | 80 |
| Entergy\tWholesale\tCommodities | 20 | 22 | 21 | 6 | 5 | 36 | 22 | 22 | 24 |
| Parent\t&\tOther | — | — | — | (22) | (15) | (18) | (4) | (4) | (4) |

See	Note	13	to	the	financial	statements	for	further	financial	information	regarding	Entergy's	business	segments.

# Results	of	Operations

Following	are	income	statement	variances	for	Utility,	Entergy	Wholesale	Commodities,	Parent	&	Other,	and	Entergy	comparing	2013	to 2012	showing	how	much	the	line	item	increased	or	(decreased)	in	comparison	to	the	prior	period.

|  | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;<br>Other | Entergy |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| 2012\tConsolidated\tNet\tIncome\t(Loss) | $960,322 | $40,427 | ($132,386) | $868,363 |
| Net\trevenue\t(operating\trevenue\tless\tfuel\texpense, |  |  |  |  |
| \t\tpurchased\tpower,\tand\tother\tregulatory |  |  |  |  |
| \t\tcharges/credits) | 555,233 | (51,509) | 7,136 | 510,860 |
| Other\toperation\tand\tmaintenance | 184,374 | 90,222 | 11,946 | 286,542 |
| Asset\timpairment\tand\trelated\tcharges | 9,411 | (26,188) | 2,790 | (13,987) |
| Taxes\tother\tthan\tincome\ttaxes | 37,547 | 5,380 | 125 | 43,052 |
| Depreciation\tand\tamortization | 76,850 | 39,824 | (215) | 116,459 |
| Gain\ton\tsale\tof\tbusiness | — | 43,569 | — | 43,569 |
| Other\tincome | 6,378 | 29,624 | 2,268 | 38,270 |
| Interest\texpense | 32,688 | (1,577) | 3,642 | 34,753 |
| Other\texpenses | 18,271 | 50,274 | — | 68,545 |
| Income\ttaxes | 316,577 | (138,800) | 17,349 | 195,126 |
| 2013\tConsolidated\tNet\tIncome\t(Loss) | $846,215 | $42,976 | ($158,619) | $730,572 |

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

As	discussed	in	more	detail	in	Note	1	to	the	financial	statements,	results	of	operations	include	$321.5	million	($202.2	million	after-tax)	in 2013	and	$355.5	million	($223.5	million	after-tax)	in	2012	of	impairment	and	other	related	charges	to	write	down	the	carrying	value	of	Vermont Yankee	and	related	assets	to	their	fair	values.	Also,	net	income	for	Utility	in	2012	was	significantly	affected	by	a	settlement	with	the	IRS	related to	the	income	tax	treatment	of	the	Louisiana	Act	55	financing	of	the	Hurricane	Katrina	and	Hurricane	Rita	storm	costs,	which	resulted	in	a reduction	in	income	tax	expense.	The	net	income	effect	was	partially	offset	by	a	regulatory	charge,	which	reduced	net	revenue	in	2012,	associated with	the	storm	costs	settlement	to	reflect	the	obligation	to	customers	with	respect	to	the	settlement.	See	Note	3	to	the	financial	statements	for additional	discussion	of	the	tax	settlement.

Also,	earnings	were	negatively	affected	in	2013	by	expenses,	including	other	operation	and	maintenance	expenses	and	taxes	other	than income	taxes,	of	approximately	$110	million	($70	million	after-tax),	including	approximately	$85	million	($55	million	after-tax)	for	Utility	and $25	million	($15	million	after-tax)	for	Entergy	Wholesale	Commodities,	recorded	in	connection	with	a	strategic	imperative	intended	to	optimize the	organization	through	a	process	known	as	human	capital	management.	In	December	2013,	Entergy	deferred	for	future	collection	approximately $45	million	($30	million	after-tax)	of	these	costs	in	the	Arkansas	and	Louisiana	jurisdictions	at	the	Utility,	as	approved	by	the	APSC	and	the LPSC,	respectively.	See	"Human	Capital	Management	Strategic	Initiative"	below	for	further	discussion.

# Net	Revenue

# Utility

Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2013	to	2012.

| 2012	net	revenue | $4,969 |
| :--- | :--- |
| Retail\telectric\tprice | 236 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | 165 |
| Grand\tGulf\trecovery | 75 |
| Volume/weather | 40 |
| Fuel\trecovery | 35 |
| MISO\tdeferral | 12 |
| Decommissioning\ttrusts | (23) |
| Other | 15 |
| 2013\tnet\trevenue | $5,524 |

The	retail	electric	price	variance	is	primarily	due	to:

•a	formula	rate	plan	increase	at	Entergy	Louisiana,	effective	January	2013,	which	includes	an	increase	relating	to	the	Waterford	3	steam generator	replacement	project,	which	was	placed	in	service	in	December	2012.	The	net	income	effect	of	the	formula	rate	plan	increase	is limited	to	a	portion	representing	an	allowed	return	on	equity	with	the	remainder	offset	by	costs	included	in	other	operation	and maintenance	expenses,	depreciation	expenses,	and	taxes	other	than	income	taxes;

•the	recovery	of	Hinds	plant	costs	through	the	power	management	rider	at	Entergy	Mississippi,	as	approved	by	the	MPSC,	effective	with the	first	billing	cycle	of	2013.	The	net	income	effect	of	the	Hinds	plant	cost	recovery	is	limited	to	a	portion	representing	an	allowed	return on	equity	on	the	net	plant	investment	with	the	remainder	offset	by	the	Hinds	plant	costs	in	other	operation	and	maintenance	expenses, depreciation	expenses,	and	taxes	other	than	income	taxes;

•an	increase	in	the	capacity	acquisition	rider	at	Entergy	Arkansas,	as	approved	by	the	APSC,	effective	with	the	first	billing	cycle	of December	2012,	relating	to	the	Hot	Spring	plant	acquisition.	The	net	income	effect	of	the	Hot	Spring	plant	cost	recovery	is	limited	to	a portion	representing	an	allowed	return	on	equity	on	the	net	plant	investment	with	the	remainder	offset	by	the	Hot	Spring	plant	costs	in other	operation	and	maintenance	expenses,	depreciation	expenses,	and	taxes	other	than	income	taxes;

•increases	in	the	energy	efficiency	rider,	as	approved	by	the	APSC,	effective	July	2013	and	July	2012.	Energy	efficiency	revenues	are offset	by	costs	included	in	other	operation	and	maintenance	expenses	and	have	no	effect	on	net	income;

•an	annual	base	rate	increase	at	Entergy	Texas,	effective	July	2012,	as	a	result	of	the	PUCT's	order	that	was	issued	in	September	2012	in the	November	2011	rate	case;	and

•a	formula	rate	plan	increase	at	Entergy	Mississippi,	effective	September	2013.

See	Note	2	to	the	financial	statements	for	a	discussion	of	rate	proceedings.

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	recorded	in	the	second	quarter	2012	because Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain tax	position	regarding	the	Hurricane	Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing.	See	Note	3	to	the	financial	statements	for	additional discussion	of	the	tax	settlement.

The	Grand	Gulf	recovery	variance	is	primarily	due	to	increased	recovery	of	higher	costs	resulting	from	the	Grand	Gulf	uprate.

The	volume/weather	variance	is	primarily	due	to	the	effects	of	more	favorable	weather	on	residential	sales	and	an	increase	in	industrial sales	primarily	due	to	growth	in	the	refining	segment.

The	fuel	recovery	variance	is	primarily	due	to:

•the	deferral	of	increased	capacity	costs	that	will	be	recovered	through	fuel	adjustment	clauses;

•the	expiration	of	the	Evangeline	gas	contract	on	January	1,	2013;	and

•an	adjustment	to	deferred	fuel	costs	recorded	in	the	third	quarter	2012	in	accordance	with	a	rate	order	from	the	PUCT	issued	in	September 2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	this	PUCT	order	issued	in	Entergy	Texas's	2011	rate	case.

The	MISO	deferral	variance	is	primarily	due	to	the	deferral	in	April	2013,	as	approved	by	the	APSC,	of	costs	incurred	since	March	2010 related	to	the	transition	and	implementation	of	joining	the	MISO	RTO.

The	 decommissioning	 trusts	 variance	 is	 primarily	 due	 to	 lower	 regulatory	 credits	 resulting	 from	 higher	 realized income on decommissioning	trust	fund	investments.	There	is	no	effect	on	net	income	as	the	credits	are	offset	by	interest	and	investment	income.

# Entergy	Wholesale	Commodities

| 2012	net	revenue | $1,854 |
| :--- | :--- |
| Mark-to-market | (58) |
| Nuclear\tvolume | (24) |
| Nuclear\tfuel\texpenses | (20) |
| Nuclear\trealized\tprice\tchanges | 58 |
| Other | (8) |
| 2013\tnet\trevenue | $1,802 |

As	shown	in	the	table	above,	net	revenue	for	Entergy	Wholesale	Commodities	decreased	by	approximately	$52	million	in	2013	primarily due	to:

•the	effect	of	rising	forward	power	prices	on	electricity	derivative	instruments	that	are	not	designated	as	hedges,	including	additional financial	power	sales	conducted	in	the	fourth	quarter	2013	to	offset	the	planned	exercise	of	in-the-money	protective	call	options	and	to lock	in	margins.	These	additional	sales	did	not	qualify	for	hedge	accounting	treatment,	and	increases	in	forward	prices	after	those	sales were	made	accounted	for	the	majority	of	the	negative	mark-to-market	variance.	It	is	expected	that	the	underlying	transactions	will	result in	earnings	in	first	quarter	2014	as	these	positions	settle.	See	Note	16	to	the	financial	statements	for	discussion	of	derivative	instruments; •the	decrease	in	net	revenue	compared	to	prior	year	resulting	from	the	exercise	of	resupply	options	provided	for	in	purchase	power agreements	where	Entergy	Wholesale	Commodities	may	elect	to	supply	power	from	another	source	when	the	plant	is	not	running. Amounts	related	to	the	exercise	of	resupply	options	are	included	in	the	GWh	billed	in	the	table	below;	and

Entergy	Corporation	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

•higher	nuclear	fuel	expenses	primarily	resulting	from	the	effect	of	the	write-down	in	March	2012	of	the	carrying	value	of	Vermont Yankee's	nuclear	fuel,	which	resulted	in	a	lower	level	of	nuclear	fuel	amortization	in	2012,	and	the	subsequent	purchase	of	additional nuclear	fuel	in	early-2013.

These	decreases	were	partially	offset	by	higher	capacity	prices.

Following	are	key	performance	measures	for	Entergy	Wholesale	Commodities	for	2013	and	2012.

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| Owned\tcapacity\t(MW)\t(a) | 6,068 | 6,612 |
| GWh\tbilled | 45,127 | 46,178 |
| Average\trealized\tprice\tper\tMWh | $50.86 | $50.02 |
| Entergy\tWholesale\tCommodities\tNuclear\tFleet |  |  |
| Capacity\tfactor | 89% | 89% |
| GWh\tbilled | 40,167 | 41,042 |
| Average\trealized\trevenue\tper\tMWh | $50.15 | $50.29 |
| Refueling\tOutage\tDays: |  |  |
| FitzPatrick | — | 34 |
| Indian\tPoint\t2 | — | 28 |
| Indian\tPoint\t3 | 28 | — |
| Palisades | — | 34 |
| Pilgrim | 45 | — |
| Vermont\tYankee | 27 | — |

(a) The	reduction	in	owned	capacity	is	due	to	the	retirement	of	the	544	MW	Ritchie	Unit	2	in	November	2013.

# Realized	Revenue	per	MWh	for	Entergy	Wholesale	Commodities	Nuclear	Plants

The	effects	of	sustained	low	natural	gas	prices	and	power	market	structure	challenges	have	resulted	in	lower	market	prices	for	electricity in	the	New	York	and	New	England	power	regions,	which	is	where	five	of	the	six	Entergy	Wholesale	Commodities	nuclear	power	plants	are located.	Entergy	Wholesale	Commodities's	nuclear	business	experienced	a	decrease	in	realized	price	per	MWh	to	$50.15	in	2013	from	$50.29	in 2012	and	$54.73	in	2011.	The	annual	realized	price	per	MWh	for	Entergy	Wholesale	Commodities	reached	a	peak	of	$61.07	in	2009.	As	shown	in the	contracted	sale	of	energy	table	in	"Market	and	Credit	Risk	Sensitive	Instruments,"	Entergy	Wholesale	Commodities	has	sold	forward	74% of	its	planned	nuclear	energy	output	for	2014	for	an	expected	average	contracted	energy	price	of	$50	per	MWh	based	on	market	prices	at December	31,	2013.	In	addition,	Entergy	Wholesale	Commodities	has	sold	forward	74%	of	its	planned	nuclear	energy	output	for	2015	for	an expected	average	contracted	energy	price	of	$49	per	MWh	based	on	market	prices	at	December	31,	2013.	These	price	trends	present	a	challenging economic	situation	for	the	Entergy	Wholesale	Commodities	plants.	The	challenge	is	greater	for	some	of	these	plants	based	on	a	variety	of	factors such	as	their	market	for	both	energy	and	capacity,	their	size,	their	contracted	positions,	and	the	investment	required	to	maintain	the	safety	and integrity	of	the	plants.	If,	in	the	future,	economic	conditions	or	regulatory	activity	no	longer	support	the	continued	operation	of	a	plant	it	could adversely	affect	Entergy's	results	of	operations	through	loss	of	revenue,	impairment	charges,	increased	depreciation	rates,	transitional	costs,	or accelerated	decommissioning	costs.

On	August	27,	2013,	Entergy	announced	its	plan	to	close	and	decommission	Vermont	Yankee.	 Vermont	Yankee	is	expected	to	cease power	production	in	the	fourth	quarter	2014	after	its	current	fuel	cycle.	This	decision	was	approved	by	the	Board	in	August	2013.	The	decision	to shut	down	the	plant	was	primarily	due	to	sustained	low	natural	gas	and

wholesale	energy	prices,	the	high	cost	structure	of	the	plant,	and	lack	of	a	market	structure	that	adequately	compensates	merchant	nuclear	plants for	their	environmental	and	fuel	diversity	benefits	in	the	region	in	which	the	plant	operates.	See	Note	1	to	the	financial	statements	for	discussion	of impairment	of	long-lived	assets.

Impairment	of	long-lived	assets	and	nuclear	decommissioning	costs,	and	the	factors	that	influence	these	items,	are	both	discussed	below	in "Critical	Accounting	Estimates."	See	also	the	discussion	below	in	"Entergy	Wholesale	Commodities	Authorizations	to	Operate	Its	Nuclear

Power	Plants"	regarding	Entergy	Wholesale	Commodities	nuclear	plant	operating	license	and	related	activity.

# Other	Income	Statement	Items

Other	operation	and	maintenance	expenses	increased	from	$2,080	million	for	2012	to	$2,264	million	for	2013	primarily	due	to:

•an	increase	of	$83	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	the	discount	rates	used	to	determine	net periodic	pension	and	other	postretirement	benefit	costs	and	a	settlement	charge,	recognized	in	September	2013,	related	to	the	payment	of lump	sum	benefits	out	of	the	non-qualified	pension	plan.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs;

•an	increase	of	$46	million	in	fossil-fueled	generation	expenses	primarily	due	to	the	acquisitions	of	the	Hot	Spring	plant	by	Entergy Arkansas	and	the	Hinds	plant	by	Entergy	Mississippi	in	November	2012.	Costs	related	to	the	Hot	Spring	and	Hinds	plants	are	recovered through	the	capacity	acquisition	rider	and	power	management	rider,	respectively,	as	previously	discussed.	Also	contributing	to	the increases	is	an	overall	higher	scope	of	work	done	during	plant	outages	as	compared	to	the	prior	year;

•an	increase	of	$72	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative,	partially	offset	by	the	deferral	of	approximately	$44	million	of	these	costs.

# See	the	"Human	Capital	Management	Strategic	Imperative"	below	for	further	discussion;

•an	increase	of	$16	million	in	energy	efficiency	costs	at	Entergy	Arkansas.	These	costs	are	recovered	through	an	energy	efficiency	rider and	have	no	effect	on	net	income;

•an	increase	of	$13	million	in	nuclear	expenses,	primarily	due	to	higher	labor	costs,	including	higher	contract	labor;

•the	deferral	in	2012,	as	approved	by	the	LPSC	and	the	FERC,	of	costs	related	to	the	transition	and	implementation	of	joining	the	MISO RTO,	which	reduced	2012	expenses	by	$10	million;	and

•an	increase	of	$9	million	resulting	from	costs	related	to	the	generator	stator	incident	at	ANO,	including	an	offset	for	expected	insurance proceeds.	See	"ANO	Damage	and	Outage"	below	for	further	discussion	of	the	incident.

Also,	other	operation	and	maintenance	expenses	include	$36	million	in	2013	and	$38	million	in	2012	of	costs	incurred	related	to	the	now terminated	plan	to	spin	off	and	merge	the	Utility's	transmission	business.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes,	primarily	due	to	the	Hot	Spring	and	Hinds	plant acquisitions	in	2012,	as	well	as	an	increase	in	local	franchise	taxes	resulting	from	higher	residential	and	commercial	revenues	as	compared	with prior	year.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	the	Hot	Spring	and	Hinds	plant acquisitions	in	2012	and	the	completion	of	the	Waterford	3	steam	generator	replacement	project	and	the	Grand	Gulf	uprate	project	in	2012.		Also contributing	to	the	increase	is	an	increase	in	depreciation	rates	as	a	result	of	the	2011	rate	case	order	issued	by	the	PUCT	in	September	2012.

Interest	expense	increased	primarily	due	to	net	debt	issuances	in	2013	of	$520	million	by	the	Utility	operating	companies	and	System Energy	and	lower	AFUDC	due	to	the	completion	of	several	major	projects	in	2012.	See	Note	5	to	the	financial	statements	for	more	details	of	long- term	debt.

Other	operation	and	maintenance	expenses	increased	from	$958	million	for	2012	to	$1,048	million	for	2013	primarily	due	to:

•an	increase	of	$23	million	primarily	due	to	the	effect	of	the	final	court	decisions	in	the	Vermont	Yankee	and	Indian	Point	2	lawsuits against	the	U.S.	Department	of	Energy	related	to	spent	nuclear	fuel	disposal	recorded	in	2012.	The	damages	awarded	included	the reimbursement	of	approximately	$25	million	of	spent	nuclear	fuel	storage	costs	previously	recorded	as	operation	and	maintenance expenses;

•an	increase	of	$16	million	resulting	from	implementation	and	severance	costs	in	2013	related	to	the	human	capital	management	strategic imperative.	See	"Human	Capital	Management	Strategic	Imperative"	below	for	further	discussion;	and

•approximately	$15	million	in	commitments	recorded	in	connection	with	the	settlement	agreement	with	parties	in	Vermont	regarding	the operation	and	decommissioning	of	Vermont	Yankee.	See	"Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial	statements	for further	discussion	of	the	settlement	agreement.

The	asset	impairment	variance	is	primarily	due	to	$321.5	million	($202.2	million	after-tax)	in	2013	and	$355.5	million	($223.5	million after-tax)	in	2012	of	impairment	and	other	related	charges	primarily	to	write	down	the	carrying	value	of	Vermont	Yankee	and	related	assets	to their	fair	values.	See	Note	1	to	the	financial	statements	for	further	discussion	of	these	charges.

Depreciation	and	amortization	expenses	increased	primarily	due	to	an	adjustment	in	2012	resulting	from	final	court	decisions	in	the	Indian Point	2	and	Vermont	Yankee	lawsuits	against	the	U.S.	Department	of	Energy	related	to	spent	nuclear	fuel	disposal.	The	effects	of	recording	the proceeds	from	the	judgment	reduced	the	plant	in	service	balances	and	included	a	$25	million	reduction	to	previously-recorded	depreciation expense.

The	gain	on	sale	of	business	resulted	from	the	sale	in	November	2013	of	Entergy	Solutions	District	Energy,	a	business	wholly-owned	by Entergy	in	the	Entergy	Wholesale	Commodities	segment	that	owns	and	operates	district	energy	assets	serving	the	business	districts	in	Houston and	New	Orleans.	Entergy	sold	Entergy	Solutions	District	Energy	for	$140	million	and	realized	a	pre-tax	gain	of	$44	million	on	the	sale.

Other	income	increased	primarily	due	to	realized	decommissioning	trust	gains	that	resulted	from	portfolio	reallocations	for	Indian	Point	2 and	Palisades.

Other	expenses	increased	primarily	due	to	a	credit	to	decommissioning	expense	of	$49	million	in	the	second	quarter	2012	resulting	from	a reduction	 in	 the	decommissioning	cost	 liability	for	a	plant	as	a	result	of	a	revised	decommissioning	cost	study.	See	 "Critical	Accounting Estimates	-	Nuclear	Decommissioning	Costs"	for	further	discussion	of	nuclear	decommissioning	costs.

# Parent	&	Other

Other	operation	and	maintenance	expenses	increased	primarily	due	to	the	elimination	of	intersegment	activity.

# Income	Taxes

See	Note	3	to	the	financial	statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rates,	and	for additional	discussion	regarding	income	taxes.

The	effective	income	tax	rate	for	2013	was	23.6%.	The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for	2013 was	primarily	related	to	(1)	IRS	settlements	as	discussed	further	in	Note	3	to	the	financial	statements;	and	(2)	a	tax	benefit	associated	with	the	ITC transaction,	because	certain	associated	costs	became	deductible	with	the	termination	of	the	transaction.

The	effective	income	tax	rate	for	2012	was	3.4%.	The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for	2012 was	primarily	related	to	(1)	IRS	settlements	as	discussed	further	in	Note	3	to	the	financial	statements;	and	(2)	a	unanimous	court	decision	from	the U.S.	Court	of	Appeals	for	the	Fifth	Circuit	affirming	an	earlier	decision	of	the	U.S.	Tax	Court	holding	that	Entergy	was	entitled	to	claim	a	credit against	its	U.S.	tax	liability	for	the	U.K.	windfall	tax	that	it	paid.	The	decision	necessitated	that	Entergy	reverse	the	provision	for	the	uncertain	tax position	related	to	that	item.

|  | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;<br>Other | Entergy |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| 2011\tConsolidated\tNet\tIncome\t(Loss) | $1,123,866 | $491,846 | ($248,340) | $1,367,372 |
| Net\trevenue\t(operating\trevenue\tless\tfuel\texpense, |  |  |  |  |
| \t\tpurchased\tpower,\tand\tother\tregulatory |  |  |  |  |
| \t\tcharges/credits) | 64,531 | (191,311) | (4,313) | (131,093) |
| Other\toperation\tand\tmaintenance\texpenses | 128,955 | 52,253 | (3,574) | 177,634 |
| Asset\timpairment | — | 355,524 | — | 355,524 |
| Taxes\tother\tthan\tincome\ttaxes | 803 | 20,675 | (206) | 21,272 |
| Depreciation\tand\tamortization | 45,728 | (3,145) | (200) | 42,383 |
| Other\tincome | (458) | 9,866 | 3,885 | 13,293 |
| Interest\texpense | 20,746 | (15,167) | 50,078 | 55,657 |
| Other\texpenses | 9,356 | (25,209) | — | (15,853) |
| Income\ttaxes | 22,029 | (114,957) | (162,480) | (255,408) |
| 2012\tConsolidated\tNet\tIncome\t(Loss) | $960,322 | $40,427 | ($132,386) | $868,363 |

In	the	fourth	quarter	2012,	Entergy	moved	two	subsidiaries	from	Parent	&	Other	to	the	Entergy	Wholesale	Commodities	segment	to improve	the	alignment	of	certain	intercompany	items	and	income	tax	activity.	The	prior	period	financial	information	in	this	Form	10-K	has	been restated	to	reflect	this	change.

As	discussed	in	more	detail	in	Note	1	to	the	financial	statements,	results	of	operations	for	2012	include	a	$355.5	million	($223.5	million after-tax)	impairment	charge	to	write	down	the	carrying	values	of	Vermont	Yankee	and	related	assets	to	their	fair	values.	 Also,	net	income	in 2012	was	significantly	affected	by	two	settlements	with	the	IRS;	one	of	which	related	to	the	income	tax	treatment	of	the	Louisiana	Act	55 financing	of	the	Hurricane	Katrina	and	Hurricane	Rita	storm	costs,	and	the	other	of	which	related	to	nuclear	power	plant	decommissioning liabilities,	both	of	which	resulted	in	a	reduction	in	income	tax	expense.	The	net	income	effect	was	partially	offset	by	a	regulatory	charge,	which reduced	net	revenue	in	2012,	associated	with	the	storm	costs	settlement	to	reflect	the	obligation	to	customers	with	respect	to	the	settlement.	See Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax	settlements.	Net	income	for	Utility	for	2011	was	significantly	affected	by	a settlement	with	the	IRS	related	to	the	mark-to-market	income	tax	treatment	of	power	purchase	contracts,	which	resulted	in	a	reduction	in	income tax	expense.	The	net	income	effect	was	partially	offset	by	a	regulatory	charge,	which	reduced	net	revenue	in	2011,	because	Entergy	Louisiana	is sharing	the	benefits	with	customers.	See	Notes	3	and	8	to	the	financial	statements	for	additional	discussion	of	the	tax	settlement	and	benefit sharing.

| 2011	net	revenue | $4,904 |
| :--- | :--- |
| Mark-to-market\ttax\tsettlement\tsharing | 200 |
| Retail\telectric\tprice | 81 |
| Grand\tGulf\trecovery | 71 |
| Net\twholesale\trevenue | (28) |
| Purchased\tpower\tcapacity | (29) |
| Volume/weather | (80) |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | (161) |
| Other | 11 |
| 2012\tnet\trevenue | $4,969 |

The	 mark-to-market	 tax	 settlement	 sharing	 variance	 results	 from	 a	 regulatory	 charge	 recorded	 in	 September	 2011	 because	 Entergy Louisiana	is	sharing	the	benefits	of	a	settlement	with	the	IRS	related	to	the	mark-to-market	income	tax	treatment	of	power	purchase	contracts	with customers.	See	Notes	3	and	8	to	the	financial	statements	for	additional	discussion	of	the	tax	settlement	and	benefit	sharing.

•an	increase	in	the	storm	cost	recovery	rider	at	Entergy	Mississippi,	as	approved	by	the	MPSC	for	a	five-month	period	effective	August 2012.	This	increase	is	offset	by	costs	included	in	other	operation	and	maintenance	expenses	and	has	no	effect	on	net	income;

•an	increase	in	the	energy	efficiency	rider	at	Entergy	Arkansas,	as	approved	by	the	APSC,	effective	July	2012.	This	increase	is	offset	by costs	included	in	other	operation	and	maintenance	expenses	and	has	no	effect	on	net	income;

•a	special	formula	rate	plan	rate	increase	at	Entergy	Louisiana	effective	May	2011	in	accordance	with	a	previous	LPSC	order	relating	to	the acquisition	of	Unit	2	of	the	Acadia	Energy	Center.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the	formula	rate	plan	increase; and

•base	rate	increases	at	Entergy	Texas	beginning	May	2011	as	a	result	of	the	settlement	of	the	December	2009	rate	case	and	effective	July 2012	as	a	result	of	the	PUCT's	order	in	the	December	2011	rate	case.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the rate	cases.

These	increases	were	partially	offset	by	formula	rate	plan	decreases	at	Entergy	New	Orleans	effective	October	2011	and	at	Entergy	Gulf	States Louisiana	effective	September	2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	formula	rate	plan	decreases.

The	net	wholesale	revenue	variance	is	primarily	due	to	decreased	sales	volume	to	municipal	and	co-op	customers	and	lower	prices.

The	purchased	power	capacity	variance	is	primarily	due	to	price	increases	for	ongoing	purchased	power	capacity	and	additional	capacity purchases.

The	volume/weather	variance	is	primarily	due	to	decreased	electricity	usage,	including	the	effect	of	milder	weather	as	compared	to	the prior	period	on	residential	and	commercial	sales.	Hurricane	Isaac,	which	hit	the	Utility's	service	area	in	August	2012,	also	contributed	to	the decrease	in	electricity	usage.	Billed	electricity	usage	decreased	a	total	of	1,684	GWh,	or	2%,	across	all	customer	classes.

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	recorded	in	2012	because	Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	agreed	to	share	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing	with	customers.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax settlement.

| 2011	net	revenue | $2,045 |
| :--- | :--- |
| Nuclear\trealized\tprice\tchanges | (194) |
| Nuclear\tvolume | (33) |
| Other | 36 |
| 2012\tnet\trevenue | $1,854 |

As	shown	in	the	table	above,	net	revenue	for	Entergy	Wholesale	Commodities	decreased	by	$191	million,	or	9%,	in	2012	compared	to 2011	primarily	due	to	lower	pricing	in	its	contracts	to	sell	power	and	lower	volume	in	its	nuclear	fleet	resulting	from	more	unplanned	and refueling	outage	days	in	2012	as	compared	to	2011	which	was	partially	offset	by	the	exercise	of	resupply	options	provided	for	in	purchase	power agreements	whereby	Entergy	Wholesale	Commodities	may	elect	to	supply	power	from	another	source	when	the	plant	is	not	running.	Amounts related	to	the	exercise	of	resupply	options	are	included	in	the	GWh	billed	in	the	table	below.	Partially	offsetting	the	lower	net	revenue	from	the nuclear	fleet	was	higher	net	revenue	from	the	Rhode	Island	State	Energy	Center,	which	was	acquired	in	December	2011.

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| Owned\tcapacity\t(MW) | 6,612 | 6,599 |
| GWh\tbilled | 46,178 | 43,497 |
| Average\trealized\tprice\tper\tMWh | $50.02 | $54.50 |
| Entergy\tWholesale\tCommodities\tNuclear\tFleet |  |  |
| Capacity\tfactor | 89% | 93% |
| GWh\tbilled | 41,042 | 40,918 |
| Average\trealized\trevenue\tper\tMWh | $50.29 | $54.73 |
| Refueling\tOutage\tDays: |  |  |
| FitzPatrick | 34 | — |
| Indian\tPoint\t2 | 28 | — |
| Indian\tPoint\t3 | — | 30 |
| Palisades | 34 | — |
| Pilgrim | — | 25 |
| Vermont\tYankee | — | 25 |

Other	operation	and	maintenance	expenses	increased	from	$1,951	million	for	2011	to	$2,080	million	for	2012	primarily	due	to:

•an	increase	of	$47	million	in	compensation	and	benefits	costs	primarily	due	to	decreasing	discount	rates	and	changes	in	certain	actuarial assumptions	resulting	from	an	experience	study.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and	Other	Postretirement Benefits"	below	and	Note	11	to	the	financial	statements	for	further	discussion	of	benefits	costs;

•$38	million	of	costs	incurred	in	2012	related	to	the	now	terminated	plan	to	spin	off	and	merge	the	Utility's	transmission	business; •an	increase	of	$29	million	in	nuclear	expenses	primarily	due	to	higher	labor	costs,	including	higher	contract	labor;

•an	increase	of	$21	million	resulting	from	a	temporary	increase	in	the	Entergy	Mississippi	storm	damage	reserve	authorized	by	the	MPSC effective	August	2012.	These	costs	included	are	recovered	through	the	storm	cost	recovery	rider	and	have	no	effect	on	net	income; •an	increase	of	$14	million	in	energy	efficiency	costs	at	Entergy	Arkansas.	These	costs	are	recovered	through	the	energy	efficiency	rider and	have	no	effect	on	net	income;

•the	deferral	in	2011	of	$13.4	million	of	2010	Michoud	plant	maintenance	costs	pursuant	to	the	settlement	of	Entergy	New	Orleans'	2010 test	year	formula	rate	plan	filing	approved	by	the	City	Council	in	September	2011.	See	Note	2	to	the	financial	statements	for	further discussion	of	the	Entergy	New	Orleans	2010	test	year	formula	rate	plan	filing	and	settlement;	and

•an	increase	of	$10	million	in	operating	expenses	due	to	the	sale	of	surplus	oil	inventory	in	2011.

These	increases	were	partially	offset	by:

•a	decrease	of	approximately	$7	million	as	a	result	of	the	deferral	or	capitalization	of	storm	restoration	costs	for	Hurricane	Isaac,	which	hit the	Utility's	service	area	in	August	2012;

•the	effect	of	the	deferral,	as	approved	by	the	FERC,	and	the	LPSC	for	the	Louisiana	jurisdictions,	of	costs	related	to	the	transition	and implementation	of	joining	the	MISO	RTO,	which	reduced	expenses	by	$10	million;	and

•a	decrease	of	$9	million	in	legal	expenses,	not	including	legal	costs	related	to	the	transition	and	implementation	of	joining	the	MISO	RTO and	the	now	terminated	plan	to	spin	off	and	merge	the	Utility's	transmission	business	which	are	included	in	other	bullets,	primarily resulting	from	a	decrease	in	legal	and	regulatory	activity	decreasing	the	use	of	outside	legal	services.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service.

Interest	expense	increased	primarily	due	to	a	revision	in	2011	caused	by	FERC's	acceptance	of	a	change	in	the	treatment	of	funds	received from	independent	power	producers	for	transmission	interconnection	projects.	Also	contributing	to	the	increase	were	net	debt	issuances	by	certain of	the	Utility	operating	companies.

Other	operation	and	maintenance	expenses	increased	from	$906	million	for	2011	to	$958	million	for	2012	primarily	due	to:

•an	increase	of	$23	million	in	compensation	and	benefits	costs	primarily	due	to	decreasing	discount	rates	and	changes	in	certain	actuarial assumptions	resulting	from	an	experience	study.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and	Other	Postretirement Benefits	"	below	and	Note	11	to	the	financial	statements	for	further	discussion	of	benefits	costs; •an	increase	of	$23	million	primarily	due	to	higher	contract	labor	costs	and	higher	material	and	supply	costs;	and •an	increase	of	$20	million	due	to	the	operations	of	the	Rhode	Island	State	Energy	Center,	which	was	acquired	in	December	2011.

These	increases	were	partially	offset	by	the	effects	of	recording	the	final	court	decisions	in	the	Vermont	Yankee	and	Indian	Point	2	lawsuits against	the	U.S.	Department	of	Energy	related	to	spent	nuclear	fuel	disposal.	The	damages	awarded	include	the	reimbursement	of	approximately $25	million	of	spent	nuclear	fuel	storage	costs	previously	recorded	as	operation	and	maintenance	expenses.

The	asset	impairment	variance	is	due	to	a	$355.5	million	($223.5	million	after-tax)	impairment	charge	recorded	in	the	first	quarter	2012	to write	down	the	carrying	values	of	Vermont	Yankee	and	related	assets	to	their	fair	values.	 See	Note	1	to	the	financial	statements	for	further discussion	of	this	charge.

Taxes	other	than	income	taxes	increased	primarily	due	to	increased	property	taxes	at	FitzPatrick,	increased	electric	generating	excises	at Vermont	Yankee,	and	property	taxes	from	the	Rhode	Island	State	Energy	Center	acquired	in	December	2011.	 Previously,	FitzPatrick	was	granted an	exemption	from	property	taxation	and	paid	taxes	according	to	a	payment	in	lieu	of	property	tax	agreement.	This	agreement	expired	on	June	30, 2011	and	FitzPatrick	is	now	being	taxed	under	the	regular	property	tax	system.	FitzPatrick	has	pending	litigation	in	the	Fifth	Judicial	District	of New	York	State	Supreme	Court	challenging	each	annual	property	tax	assessment	placed	on	FitzPatrick	since	the	expiration	of	the	payment	in	lieu of	tax	agreement.		The	State	of	Vermont	enacted	legislation,	which	became	effective	on	July	1,	2012,	increasing	the	electric	generating	excise	on Vermont	Yankee.	 Vermont	Yankee	challenged	the	constitutionality	of	this	legislation.		In	October	2012	the	federal	judge	for	the	U.S.	District Court	for	the	District	of	Vermont	dismissed	the	suit	on	jurisdictional	grounds.		In	December	2013	the	U.S.	Court	of	Appeals	for	the	Second Circuit	affirmed	that	decision.	As	part	of	the	settlement	agreement	regarding	the	operation	and	decommissioning	of	Vermont	Yankee,	Entergy agreed	not	to	pursue	further	appeals	or	other	challenges	to	this	legislation.	See	"Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial statements	for	further	discussion	of	the	settlement	agreement.

Depreciation	and	amortization	expenses	decreased	primarily	due	to	adjustments	resulting	from	final	court	decisions	in	the	Entergy	Nuclear Indian	Point	2	and	Vermont	Yankee	lawsuits	against	the	U.S.	Department	of	Energy	related	to	spent	nuclear	fuel	disposal.	The	effects	of	recording the	 proceeds	 from	 the	 judgments	 reduced	 the	 plant	 in	 service	 balances	 with	 a	 corresponding	 $25	 million	 reduction	 to	 previously-recorded depreciation	 expense.	Partially	offsetting	the	adjustment	was	an	increase	due	to	additions	to	plant	in	service,	including	the	acquisition	of	the Rhode	Island	State	Energy	Center	in	December	2011.

Other	expenses	decreased	primarily	due	to	a	credit	to	decommissioning	expense	of	$49	million	in	the	second	quarter	2012	compared	to	a credit	to	decommissioning	expense	of	$34	million	in	the	fourth	quarter	2011	resulting	from	reductions	in	the	decommissioning	cost	liabilities	for certain	nuclear	plants	as	a	result	of	revised	decommissioning	cost	studies.	See	"Critical	Accounting	Estimates	-	Nuclear	Decommissioning Costs"	below	for	further	discussion	of	these	credits.

Interest	expense	increased	primarily	due	to	the	issuance	of	$500	million	of	4.7%	senior	notes	by	Entergy	Corporation	in	January	2012	and a	higher	interest	rate	on	outstanding	borrowings	under	the	Entergy	Corporation	credit	facility.

The	effective	income	tax	rate	for	2012	was	3.4%.	The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for	2012 was	related	to	(1)	IRS	settlements	discussed	further	in	Note	3	to	the	financial	statements;	and	(2)	a	unanimous	court	decision	from	the	U.S.	Court of	Appeals	for	the	Fifth	Circuit	affirming	an	earlier	decision	of	the	U.S.	Tax	Court	holding	that	Entergy	was	entitled	to	claim	a	credit	against	its U.S.	tax	liability	for	the	U.K.	windfall	tax	that	it	paid.	The	decision	necessitated	that	Entergy	reverse	the	provision	for	the	uncertain	tax	position related	to	that	item.

The	effective	income	tax	rate	for	2011	was	17.3%.	The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	in	2011 was	primarily	due	to	a	settlement	with	the	IRS	related	to	the	mark-to-market	income	tax	treatment	of	power	purchase	contracts,	which	resulted	in	a reduction	in	income	tax	expense	of	$422	million.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the	settlement.

# Entergy	Wholesale	Commodities	Authorizations	to	Operate	Its	Nuclear	Power	Plants

In	March	2011	and	May	2012	the	NRC	renewed	the	operating	licenses	of	Vermont	Yankee	and	Pilgrim,	respectively,	for	an	additional	20 years,	as	a	result	of	which	each	license	now	expires	in	2032.	For	additional	discussion	regarding	the	planned	shutdown	of	the	Vermont	Yankee plant	by	the	end	of	2014,	see	"Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial	statements.	The	NRC	operating	license	for	Palisades expires	in	2031	and	for	FitzPatrick	expires	in	2034.

The	original	expiration	date	of	the	NRC	operating	license	for	Indian	Point	2	was	in	September	2013	and	the	original	expiration	date	of	the NRC	operating	license	for	Indian	Point	3	is	in	December	2015.	In	April	2007,	Entergy	submitted	the	applications	to	the	NRC	to	renew	the operating	licenses	for	Indian	Point	2	and	3	for	an	additional	20	years.	Indian	Point	Unit	2	has	now	entered	its	"period	of	extended	operation"	after expiration	of	 the	plant's	 initial	 license	 term	under	"timely	renewal,"	which	 is	a	federal	statutory	rule	of	general	applicability	providing	for extension	of	a	license	for	which	a	renewal	application	has	been	timely	filed	with	the	licensing	agency.	The	Indian	Point	license	renewal	application qualifies	for	timely	renewal	protection	because	it	met	NRC	regulatory	standards	for	timely	filing.

Various	parties	have	expressed	opposition	to	renewal	of	the	licenses.	The	ASLB	has	admitted	21	contentions	raised	by	the	State	of	New	York	or other	parties,	which	were	combined	into	16	discrete	issues.

Three	of	the	16	discrete	issues	have	been	resolved	by	the	ASLB	without	hearing,	two	by	means	of	ASLB-approved	settlements,	and	a third	by	summary	disposition.	In	July	2011,	the	ASLB	granted	the	State	of	New	York's	motion	for	summary	disposition	of	an	admitted	contention challenging	the	adequacy	of	a	section	of	Indian	Point's	environmental	analysis	as	incorporated	in	the	Final	Supplemental	Environmental	Impact Statement	(FSEIS)	(discussed	below).	That	section	provided	cost	estimates	for	Severe	Accident	Mitigation	Alternatives	(SAMAs),	which	are hardware	 and	 procedural	 changes	 that	 could	 be	 implemented	 to	 mitigate	 estimated	 impacts	 of	 off-site	 radiological	 releases	 in	 case	 of	 a hypothesized	severe	accident.	In	addition	to	finding	that	the	SAMA	cost	analysis	was	insufficient,	the	ASLB	directed	the	NRC	staff	to	explain why	cost-beneficial	SAMAs	should	not	be	required	to	be	implemented.	Entergy	appealed	the	ASLB's	decision	to	the	NRC	and	the	NRC	staff supported	Entergy's	appeal,	while	the	State	of	New	York	opposed	it.	 In	December	2011,	the	NRC	denied	Entergy's	appeal	as	premature,	stating that	the	appeal	could	be	renewed	at	the	conclusion	of	the	ASLB	proceedings.	In	May	2013,	Entergy	filed	an	updated	SAMA	cost	analysis	with	the NRC,	and	in	July	2013	the	ASLB	granted	Entergy's	motion	for	clarification	that	a	future	NRC	staff	filing	would	be	the	trigger	for	potential	new	or amended	contentions	on	the	SAMA	update.	There	is	no	deadline	for	the	NRC	staff	filing	on	Entergy's	updated	SAMA	cost	analysis.

Of	the	remaining	13	discrete	issues,	nine	that	were	designated	by	the	ASLB	as	"Track	1"	were	subject	to	hearings	over	12	days	in October,	November,	and	December	2012.	In	November	2013,	the	ASLB	issued	a	decision	on	the	nine	Track	1	contentions.	The	ASLB	resolved eight	 Track	 1	 contentions	 favorably	 to	 Entergy.	One	 Track	 1	 contention	 based	 on	 a	 dispute	 over	 the	 characterization	 of	 certain	 electrical equipment	as	"active"	or	"passive"	was	resolved	in	favor	of	the	State	of	New	York	despite	precedent	supporting	the	characterization	advocated	by Entergy	and	NRC	staff.	Appeals	to	the	NRC	of	issues	raised	by	the	ASLB's	Track	1	decision	were	due	in	February	2014.	The	State	of	New	York and	Clearwater	each	appealed	the	decision	on	a	single	contention	(SAMA	decontamination	times	for	the	State	of	New	York	and	environmental justice	for	Clearwater),	while	Riverkeeper	filed	no	appeals.	Entergy	and	NRC	staff	both	appealed	the	same	three	issues:	(1)	the	ASLB's	decision on	electrical	transformers;	(2)	certain	intermediate	determinations	in	the	ASLB's	overall	favorable	decision	on	environmental	justice;	and	(3)	the ASLB's	earlier	decisions	on	SAMA	cost	estimates,	thus	renewing	their	appeals	of	that	issue	previously	denied	by	the	NRC	as	premature.	The ASLB's	decision	on	issues	not	appealed	is	now	final.	NRC	rules	provide	for	two	further	rounds	of	filings	after	submission	of	appeals.	There	is	no deadline	for	the	NRC	to	resolve	appeals	from	the	ASLB.	The	remaining	four	discrete	issues	have	been	designated	by	the	ASLB	as	"Track	2." Testimony	on	Track	2	contentions	has	not	been	completed,	and	Track	2	hearings	have	not	been	scheduled.

The	 NRC	 staff	 is	 also	 continuing	 to	 perform	 its	 technical	 and	 environmental	 reviews	 of	 the	 Indian	 Point	 2	 and	 3	 license	 renewal applications.	The	NRC	staff	issued	a	Final	Safety	Evaluation	Report	(FSER)	in	August	2009,	a	supplement	to	the	FSER	in	August	2011,	a	FSEIS in	December	2010,	and	a	supplement	to	the	FSEIS	in	June	2013.	In	addition,	the	NRC	staff	has	stated	its	intent	to	issue	a	further	supplement	to	the FSER	by	mid-2014.	The	NRC	staff	is	considering	whether	a	second	supplement	to	the	FSEIS	is	necessary.	The	second	supplement	to	the	FSER and	the	already-issued	supplement	to	the	FSEIS	are	expected	to	affect	testimony	yet	to	be	filed	on	Track	2	contentions.

The	 hearing	 process	 is	 an	 integral	 component	 of	 the	 NRC's	 regulatory	 framework,	 and	 evidentiary	 hearings	 on	 license	 renewal applications	are	not	uncommon.	Entergy	is	participating	fully	in	the	hearing	and	appeals	processes	as	authorized	by	the	NRC	regulations.	As	noted in	Entergy	filings	at	the	ASLB	and	the	appellate	levels,	Entergy	believes	the	contentions	proposed	by	the	intervenors	are	unsupported	and	without merit.	Entergy	will	continue	to	work	with	the	NRC	staff	as	it	completes	its	technical	and	environmental	reviews	of	the	Indian	Point	2	and	3	license renewal	applications.	See	"Nuclear	Matters"	below	for	discussion	of	spent	nuclear	fuel	storage	issues	and	its	potential	effect	on	the	timing	of license	renewals.

The	New	York	State	Department	of	Environmental	Conservation	(NYSDEC)	has	taken	the	position	that	Indian	Point	must	obtain	a	new state-issued	Clean	Water	Act	Section	401	water	quality	certification	as	part	of	the	license	renewal	process.	Entergy	submitted	its	application	for	a water	quality	certification	to	the	NYSDEC	in	April	2009,

with	a	reservation	of	rights	regarding	the	applicability	of	Section	401	in	this	case.	After	Entergy	submitted	certain	additional	information	in response	 to	 NYSDEC	 requests	 for	 additional	 information,	 in	 February	 2010	 the	 NYSDEC	 staff	 determined	 that	 Entergy's	 water	 quality certification	application	was	complete.	In	April	2010	the	NYSDEC	staff	issued	a	proposed	notice	of	denial	of	Entergy's	water	quality	certification application	(the	Notice).	NYSDEC	staff's	Notice	triggered	an	administrative	adjudicatory	hearing	before	NYSDEC	ALJs	on	the	proposed	Notice. The	NYSDEC	staff	decision	does	not	restrict	Indian	Point	operations,	but	the	issuance	of	a	certification	is	potentially	required	prior	to	NRC issuance	of	renewed	unit	licenses.	In	June	2011,	Entergy	filed	notice	with	the	NRC	that	the	NYSDEC,	the	agency	that	would	issue	or	deny	a	water quality	certification	for	the	Indian	Point	license	renewal	process,	had	taken	longer	than	one	year	to	take	final	action	on	Entergy's	application	for	a water	quality	certification	and,	therefore,	had	waived	its	opportunity	to	require	a	certification	under	the	provisions	of	Section	401	of	the	Clean Water	Act.	The	NYSDEC	has	notified	the	NRC	that	it	disagrees	with	Entergy's	position	and	does	not	believe	that	it	has	waived	the	right	to	require a	certification.	The	NYSDEC	ALJs	overseeing	the	agency's	certification	adjudicatory	process	stated	in	a	ruling	issued	in	July	2011	that	while	the waiver	issue	is	pending	before	the	NRC,	the	NYSDEC	hearing	process	will	continue	on	selected	issues.	The	ALJs	held	a	Legislative	Hearing (agency	public	comment	session)	and	an	Issues	Conference	(pre-trial	conference)	in	July	2010	and	set	certain	issues	for	trial	in	October	2011, which	is	continuing	into	2014.	After	the	full	hearing	on	the	merits	and	post-hearing	briefing,	the	ALJs	will	issue	a	recommended	decision	to	the Commissioner	who	will	then	issue	the	final	agency	decision.	A	party	to	the	proceeding	can	appeal	the	decision	of	the	Commissioner	to	state	court.

In	addition,	the	consistency	of	Indian	Point's	operations	with	New	York	State's	coastal	management	policies	must	be	resolved	to	the extent	required	by	the	Coastal	Zone	Management	Act	(CZMA).	Entergy	has	undertaken	three	independent	initiatives	to	resolve	CZMA	issues. First,	on	July	24,	2012,	Entergy	filed	a	supplement	to	the	Indian	Point	license	renewal	applications	currently	pending	before	the	NRC.		The supplement	states	that,	based	on	applicable	federal	law	and	in	light	of	prior	reviews	by	the	State	of	New	York,	the	NRC	may	issue	the	requested renewed	operating	licenses	for	Indian	Point	without	the	need	for	an	additional	consistency	review	by	the	State	of	New	York	under	the	CZMA.	On July	30,	2012,	Entergy	filed	a	motion	for	declaratory	order	with	the	ASLB	seeking	confirmation	of	its	position	that	no	further	CZMA	consistency determination	is	required	before	the	NRC	may	issue	renewed	licenses.	On	April	5,	2013,	the	State	of	New	York	and	Riverkeeper	filed	answers opposing	Entergy's	motion.	The	State	of	New	York	also	filed	a	cross-motion	for	declaratory	order	seeking	confirmation	that	Indian	Point	had	not been	previously	reviewed,	and	that	only	the	New	York	State	Department	of	State	(NYSDOS)	could	conduct	a	CZMA	review	for	NRC	license renewal	purposes.	On	April	15,	2013,	the	NRC	Staff	filed	answers	recommending	the	ASLB	deny	both	Entergy's	and	the	State	of	New	York's motions	for	declaratory	order.	On	June	12,	2013,	the	ASLB	denied	Entergy's	and	the	State	of	New	York's	motions,	without	prejudice,	on	the ground	that	consultation	on	the	matter	of	previous	review	among	the	NRC,	Entergy	(as	applicant),	and	the	State	of	New	York	had	not	taken	place, as	the	ASLB	determined	to	be	required.	On	December	6,	2013,	NRC	staff	initiated	consultation	under	federal	CZMA	regulations	by	serving	on NYSDOS	written	questions	related	to	whether	Indian	Point	had	been	previously	reviewed.	NRC	staff	did	not	state	a	deadline	for	NYSDOS	to respond.	It	is	uncertain	what	further	steps	may	be	entailed	in	the	consultation	process.

Second,	Entergy	filed	with	the	NYSDOS	in	November	2012	a	petition	for	declaratory	order	that	Indian	Point	is	grandfathered	under	either of	two	criteria	prescribed	by	the	New	York	Coastal	Management	Program	(NYCMP),	which	sets	forth	the	state	coastal	policies	applied	in	a CZMA	consistency	review.	NYSDOS	denied	the	motion	by	order	dated	January	2013.	Entergy	filed	a	petition	for	judicial	review	of	NYSDOS's decision	with	the	New	York	State	Supreme	Court	for	Albany	County	in	March	2013.	The	court	denied	Entergy's	appeal	on	December	13,	2013. Entergy	initiated	an	appeal	to	the	Appellate	Division	of	the	New	York	State	Supreme	Court	on	January	22,	2014.	Briefing	and	oral	argument	have not	yet	been	scheduled.

Third,	 on	 December	 17,	 2012,	 Entergy	 filed	 with	 NYSDOS	 a	 consistency	 determination	 explaining	 why	 Indian	 Point	 satisfies	 all applicable	NYCMP	policies.	Entergy	included	in	the	consistency	determination	a	"reservation	of	rights"	clarifying	that	Entergy	does	not	concede NYSDOS's	 right	 to	 conduct	 a	 new	 CZMA	 review	 for	 Indian	 Point.	The	 six-month	 federal	 deadline	 for	 state	 decision	 on	 a	 consistency determination	runs	from	the	date	the	submission	is	complete.	On	January	16,	2013,	NYSDOS	notified	Entergy	that	it	deemed	the	consistency determination	incomplete	because	it	did	not	include	the	final	version	of	a	further	supplement	to	the	FSEIS	that	was	targeted	for	subsequent

issuance	by	NRC	staff.	On	June	28,	2013,	NYSDOS	notified	Entergy	that	NYSDOS	had	received	a	copy	of	the	final	version	of	the	FSEIS	on	June 20,	2013,	and	that	NYSDOS's	review	of	the	Indian	Point	consistency	determination	had	begun	on	June	20,	2013.	In	October	2013,	Entergy	and NYSDOS	executed	a	stay	agreement	that	extended	the	deadline	for	NYSDOS	to	decide	Indian	Point's	CZMA	consistency	certification	to	March 22, 2014.	In	January	2014,	Entergy	and	NYSDOS	executed	another	stay	agreement	 that	further	extends	YSDOS's	deadline	for	decision	 to December	31,	2014.	A	basis	for	the	further	extension	is	a	request	by	NYSDOS	for	supplemental	information,	to	which	Entergy	will	be	responding in	stages	during	2014.

In	August	2013,	Riverkeeper	filed	with	the	ASLB	a	proposed	amended	Endangered	Species	Act	contention	alleging	that	NRC	Staff's supplemental	FSEIS	issued	in	June	2013	did	not	adequately	consider	Riverkeeper	comments	or	explain	the	effect	of	certain	new	information	used to	develop	the	supplemental	FSEIS.	Entergy	and	NRC	Staff	have	filed	answers	in	opposition.	Riverkeeper's	proposed	amended	contention	and Entergy's	motion	to	dismiss	Riverkeeper's	original	admitted	contention	on	endangered	species	are	pending	before	the	ASLB.

# ANO	Damage	and	Outage

On	March	31,	2013,	during	a	scheduled	refueling	outage	at	ANO	1,	a	contractor-owned	and	operated	heavy-lifting	apparatus	collapsed while	moving	the	generator	stator	out	of	the	turbine	building.		The	collapse	resulted	in	the	death	of	an	ironworker	and	injuries	to	several	other contract	workers,	caused	ANO	2	to	shut	down,	and	damaged	the	ANO	turbine	building.		The	turbine	building	serves	both	ANO	1	and	2	and	is	a non-radiological	area	of	the	plant.	ANO	2	reconnected	to	the	grid	on	April	28,	2013	and	ANO	1	reconnected	to	the	grid	on	August	7,	2013.		The total	cost	of	assessment,	restoration	of	off-site	power,	site	restoration,	debris	removal,	and	replacement	of	damaged	property	and	equipment	was $94	million	as	of	December	31,	2013.		In	addition,	Entergy	Arkansas	incurred	replacement	power	costs	for	ANO	2	power	during	its	outage	and incurred	incremental	replacement	power	costs	for	ANO	1	power	because	the	outage	extended	beyond	the	originally-planned	duration	of	the refueling	outage.		Each	of	the	Utility	operating	companies	has	recovery	mechanisms	in	place	designed	to	recover	its	prudently-incurred	fuel	and purchased	power	costs.

Entergy	Arkansas	is	assessing	its	options	for	recovering	damages	that	resulted	from	the	stator	drop,	including	its	insurance	coverage	and legal	 action.	Entergy	is	a	member	of	Nuclear	Electric	Insurance	Limited	(NEIL),	a	mutual	insurance	company	that	provides	property	damage coverage	to	the	members'	nuclear	generating	plants,	including	ANO.	NEIL	has	notified	Entergy	that	it	believes	that	a	$50	million	course	of construction	sublimit	applies	to	any	loss	associated	with	the	lifting	apparatus	failure	and	stator	drop	at	ANO.	Entergy	has	responded	that	it disagrees	with	NEIL's	position	and	is	evaluating	its	options	for	enforcing	its	rights	under	the	policy.	On	July	12,	2013,	Entergy	Arkansas	filed	a complaint	in	the	Circuit	Court	in	Pope	County,	Arkansas	against	the	owner	of	the	heavy-lifting	apparatus	that	collapsed,	an	engineering	firm,	a general	contractor,	and	certain	individuals	asserting	claims	of	breach	of	contract,	negligence,	and	gross	negligence	in	connection	with	their responsibility	for	the	stator	drop.

In	the	second	quarter	2013,	Entergy	Arkansas	recorded	an	insurance	receivable	of	$50	million	based	on	the	minimum	amount	that	it expects	to	receive	from	NEIL.	This	$50	million	receivable	offset	approximately	$35	million	of	capital	spending,	$13	million	of	operation	and maintenance	expense,	and	$2	million	of	incremental	deferred	refueling	outage	costs	incurred	for	the	recovery	through	December	31,	2013.	As	of December	31,	2013,	Entergy	Arkansas	has	incurred	approximately	$34	million	in	capital	spending,	$9	million	in	operation	and	maintenance expense,	and	$1	million	in	incremental	deferred	refueling	outage	costs	in	excess	of	its	recorded	insurance	receivable.	In	January	2014,	Entergy Arkansas	collected	$20	million	of	the	$50	million	receivable	that	it	expects	to	receive	from	NEIL.

# Human	Capital	Management	Strategic	Imperative

Entergy	engaged	in	a	strategic	imperative	intended	to	optimize	the	organization	through	a	process	known	as	human	capital	management. In	July	2013	management	completed	a	comprehensive	review	of	Entergy's	organization	design	and	processes.	This	effort	resulted	in	a	new internal	organization	structure,	which	resulted	in	the	elimination	of	approximately	800	employee	positions.	Entergy	incurred	approximately	$110 million	in	costs	in	2013	associated	with	this	phase	of	human	capital	management,	primarily	implementation	costs,	severance	expenses,	pension curtailment	losses,	special	termination	benefits	expense,	and	corporate	property,	plant,	and	equipment	impairments.	In	December	2013,	Entergy deferred	for	future	recovery	approximately	$45	million	of	these	costs,	as	approved	by	the	APSC	and	the	LPSC.	See	Note	2	to	the	financial statements	for	details	of	the	deferrals	and	Note	13	to	the	financial	statements	for	details	of	the	restructuring	charges.

# 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.

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 57.9% | 58.7% |
| Effect\tof\texcluding\tsecuritization\tbonds | (1.6%) | (1.8%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 56.3% | 56.9% |
| Effect\tof\tsubtracting\tcash | (1.5%) | (1.1%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 54.8% | 55.8% |

(a) Calculation	excludes	the	Arkansas,	Louisiana,	and	Texas	securitization	bonds,	which	are	non-recourse	to	Entergy	Arkansas,	Entergy Louisiana,	and	Entergy	Texas,	respectively.

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	notes	payable	and	commercial	paper,	capital	lease	obligations,	and	long- term	debt,	including	the	currently	maturing	portion.	Capital	consists	of	debt,	common	shareholders'	equity,	and	subsidiaries'	preferred	stock without	sinking	fund.	Net	capital	consists	of	capital	less	cash	and	cash	equivalents.	Entergy	uses	the	debt	to	capital	ratios	excluding	securitization bonds	in	analyzing	its	financial	condition	and	believes	they	provide	useful	information	to	its	investors	and	creditors	in	evaluating	Entergy's financial	condition	because	the	securitization	bonds	are	non-recourse	to	Entergy,	as	more	fully	described	in	Note	5	to	the	financial	statements. Entergy	also	uses	the	net	debt	to	net	capital	ratio	excluding	securitization	bonds	in	analyzing	its	financial	condition	and	believes	it	provides	useful information	to	its	investors	and	creditors	in	evaluating	Entergy's	financial	condition	because	net	debt	indicates	Entergy's	outstanding	debt	position that	could	not	be	readily	satisfied	by	cash	and	cash	equivalents	on	hand.

Long-term	debt,	including	the	currently	maturing	portion,	makes	up	most	of	Entergy's	total	debt	outstanding.	Following	are	Entergy's long-term	debt	principal	maturities	and	estimated	interest	payments	as	of	December	31,	2013.	To	estimate	future	interest	payments	for	variable rate	debt,	Entergy	used	the	rate	as	of	December	31,	2013.	The	amounts	below	include	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	and

| Long-term	debt	maturities	and<br>estimated	interest	payments | 2014 | 2015 | 2016 | 2017-2018 | after	2018 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Utility | $942 | $1,095 | $754 | $2,328 | $12,240 |
| Entergy\tWholesale\tCommodities | 15 | 19 | 2 | 4 | 55 |
| Parent\tand\tOther | 72 | 616 | 51 | 808 | 489 |
| Total | $1,029 | $1,730 | $807 | $3,140 | $12,784 |

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

Entergy	Corporation	has	in	place	a	credit	facility	that	has	a	borrowing	capacity	of	$3.5	billion	and	expires	in	March	2018.	Entergy Corporation	has	the	ability	to	issue	letters	of	credit	against	50%	of	the	total	borrowing	capacity	of	the	facility.	The	commitment	fee	is	currently 0.275%	of	the	commitment	amount.	Commitment	fees	and	interest	rates	on	loans	under	the	credit	facility	can	fluctuate	depending	on	the	senior unsecured	debt	ratings	of	Entergy	Corporation.	The	weighted	average	interest	rate	for	the	year	ended	December	31,	2013	was	1.96%	on	the	drawn portion	of	the	facility.

As	of	December	31,	2013,	amounts	outstanding	and	capacity	available	under	the	$3.5	billion	credit	facility	are:

A	covenant	in	Entergy	Corporation's	credit	facility	requires	Entergy	to	maintain	a	consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization. The	calculation	of	this	debt	ratio	under	Entergy	Corporation's	credit	facility	is	different	than	the	calculation	of	the	debt	to	capital	ratio	above. Entergy	is	currently	in	compliance	with	the	covenant.	If	Entergy	fails	to	meet	this	ratio,	or	if	Entergy	or	one	of	the	Utility	operating	companies (except	Entergy	New	Orleans)	defaults	on	other	indebtedness	or	is	in	bankruptcy	or	insolvency	proceedings,	an	acceleration	of	the	Entergy Corporation	credit	facility's	maturity	date	may	occur.

In	September	2012,	Entergy	implemented	a	commercial	paper	program,	and	in	July	2013	the	Board	increased	the	commercial	paper program	limit	to	$1.5	billion.	As	of	December	31,	2013,	Entergy	Corporation	had	approximately	$1,045	million	of	commercial	paper	outstanding. The	weighted-average	interest	rate	for	the	year	ended	December	31,	2013	was	0.84%.

Capital	lease	obligations	are	a	minimal	part	of	Entergy's	overall	capital	structure.	Following	are	Entergy's	payment	obligations	under those	leases.

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	each had	credit	facilities	available	as	of	December	31,	2013	as	follows:

| Company | Expiration	Date | Amount	of<br>Facility | Interest	Rate	(a) | Amount	Drawn	as<br>of	December	31,	2013 |
| :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | April\t2014 | $20\tmillion\t(b) | 1.75% | — |
| Entergy\tArkansas | March\t2018 | $150\tmillion\t(c) | 1.67% | — |
| Entergy\tGulf\tStates\tLouisiana | March\t2018 | $150\tmillion\t(d) | 1.67% | — |
| Entergy\tLouisiana | March\t2018 | $200\tmillion\t(e) | 1.67% | — |
| Entergy\tMississippi | May\t2014 | $35\tmillion\t(f) | 1.92% | — |
| Entergy\tMississippi | May\t2014 | $20\tmillion\t(f) | 1.92% | — |
| Entergy\tMississippi | May\t2014 | $37.5\tmillion\t(f) | 1.92% | — |
| Entergy\tNew\tOrleans | November\t2014 | $25\tmillion\t(g) | 1.64% | — |
| Entergy\tTexas | March\t2018 | $150\tmillion\t(h) | 1.92% | — |

(a) The	interest	rate	is	the	rate	as	of	December	31,	2013	that	would	be	applied	to	outstanding	borrowings	under	the	facility.

(b) The	credit	facility	requires	Entergy	Arkansas	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.		Borrowings	under	this Entergy	Arkansas	credit	facility	may	be	secured	by	a	security	interest	in	its	accounts	receivable.

(c) The	 credit	 facility	 allows	 Entergy	Arkansas	 to	 issue	 letters	 of	 credit	 against	50%	of	 the	borrowing	capacity	of	 the	facility.	 	As	of December	31,	2013,	$0.2	million	in	letters	of	credit	were	outstanding.	 	The	credit	facility	requires	Entergy	Arkansas	to	maintain	a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.

(d) The	credit	facility	allows	Entergy	Gulf	States	Louisiana	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the	facility.		As of	December	31,	2013,	$15.2	million	in	letters	of	credit	were	outstanding.		The	credit	facility	requires	Entergy	Gulf	States	Louisiana	to maintain	a	consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.

(e) The	credit	facility	allows	Entergy	Louisiana	 to	 issue	 letters	of	credit	against	50%	of	 the	borrowing	capacity	of	 the	facility.	 	As	of December	31,	2013,	$7.0	million	in	letters	of	credit	were	outstanding.	 	The	credit	facility	requires	Entergy	Louisiana	to	maintain	a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.

(f) The	credit	facilities	require	Entergy	Mississippi	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Borrowings	under	the Entergy	Mississippi	credit	facilities	may	be	secured	by	a	security	interest	in	its	accounts	receivable.

(g) The	credit	facility	requires	Entergy	New	Orleans	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.

(h) The	 credit	 facility	 allows	 Entergy	 Texas	 to	 issue	 letters	 of	 credit	 against	 50%	 of	 the	 borrowing	 capacity	 of	 the	 facility.	 	 As	 of December	 31,	 2013,	 $25	 million	 in	 letters	 of	 credit	 were	 outstanding.	 	 The	 credit	 facility	 requires	 Entergy	 Texas	 to	 maintain	 a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.

In	addition,	Entergy	Mississippi	and	Entergy	New	Orleans	each	entered	into	an	uncommitted	letter	of	credit	facility	as	a	means	to	post collateral	to	support	its	obligations	related	to	MISO.		As	of	December	31,	2013,	a	$21	million	letter	of	credit	was	outstanding	under	Entergy Mississippi's	letter	of	credit	facility	and	a	$8.5	million	letter	of	credit	was	outstanding	under	Entergy	New	Orleans's	letter	of	credit	facility.	 As	of December	31,	2013,	the	letter	of	credit	fee	on	outstanding	letters	of	credit	under	the	Entergy	Mississippi	and	Entergy	New	Orleans	letter	of	credit facilities	was	1.50%.

# 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,	results	of	operations, or	cash	flows.	Following	are	Entergy's	payment	obligations	as	of	December	31,	2013	on	non-cancelable	operating	leases	with	a	term	over	one year:

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

| Contractual	Obligations | 2014 | 2015-2016 | 2017-2018 | after	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $1,029 | $2,537 | $3,140 | $12,784 | $19,490 |
| Capital\tlease\tpayments\t(b) | $5 | $9 | $8 | $30 | $52 |
| Operating\tleases\t(b) | $106 | $155 | $84 | $111 | $456 |
| Purchase\tobligations\t(c) | $1,738 | $2,877 | $2,379 | $9,526 | $16,520 |

(a) Includes	estimated	interest	payments.		Long-term	debt	is	discussed	in	Note	5	to	the	financial	statements.

(b) Lease	obligations	are	discussed	in	Note	10	to	the	financial	statements.

(c) Purchase	obligations	represent	the	minimum	purchase	obligation	or	cancellation	charge	for	contractual	obligations	to	purchase	goods	or services.		Almost	all	of	the	total	are	fuel	and	purchased	power	obligations.

In	 addition	 to	 the	 contractual	 obligations,	 Entergy	 currently	 expects	 to	 contribute	 approximately	 $400	 million	 to	 its	 pension	 plans	 and approximately	$74.1	million	to	other	postretirement	plans	in	2014,	although	the	required	pension	contributions	will	not	be	known	with	more certainty	until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and Other	Postretirement	Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also	in	addition	to	the	contractual	obligations,	Entergy	has	$193	million	of	unrecognized	tax	benefits	and	interest	net	of	unused	tax attributes	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably	estimated	due	to	uncertainties	in	the	timing	of	effective settlement	of	tax	positions.	See	Note	3	to	the	financial	statements	for	additional	information	regarding	unrecognized	tax	benefits.

# 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	2014	through	2016.

| Generation | $650 | $640 | $590 |
| :--- | :--- | :--- | :--- |
| Transmission | 515 | 635 | 570 |
| Distribution | 575 | 545 | 565 |
| Other | 155 | 180 | 150 |
| Total | 1,895 | 2,000 | 1,875 |
| Entergy\tWholesale\tCommodities | 420 | 380 | 230 |
| Total | $2,315 | $2,380 | $2,105 |

Planned	construction	and	capital	investments	refer	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,	and	includes	spending	for	the	nuclear	and	non- nuclear	plants	at	Entergy	Wholesale	Commodities.	In	addition	to	routine	capital	projects,	they	also	refer	to	amounts	Entergy	plans	to	spend	on non-routine	capital	investments	for	which	Entergy	is	either	contractually	obligated,	has	Board	approval,	or	otherwise	expects	to	make	to	satisfy regulatory	or	legal	requirements.	Amounts	include	the	following:

•The	currently	planned	construction	or	purchase	of	additional	generation	supply	sources	within	the	Utility's	service	territory	through	the Utility's	portfolio	transformation	strategy,	including	a	self-build	option	at	Entergy	Louisiana's	Ninemile	site	identified	in	the	Summer 2009	Request	for	Proposal,	discussed	below.

•Entergy	Wholesale	Commodities	investments	associated	with	specific	investments	such	as	dry	cask	storage,	nuclear	license	renewal, NYPA	value	sharing,	component	replacements,	software,	and	security.

•Environmental	compliance	spending.	Entergy	continues	to	review	potential	environmental	spending	needs	and	financing	alternatives	for any	such	spending,	and	future	spending	estimates	could	change	based	on	the	results	of	this	continuing	analysis	and	the	implementation	of new	environmental	laws	and	regulations.

•NRC	post-Fukushima	requirements	for	the	Utility	and	Entergy	Wholesale	Commodities	nuclear	fleets.

•Transmission	spending	to	support	economic	development	projects.

For	the	next	several	years,	the	Utility's	owned	generating	capacity	is	projected	to	be	adequate	to	meet	MISO	reserve	requirements;	however,	in the	longer-term	additional	supply	resources	will	be	needed,	and	its	supply	plan	initiative	will	continue	to	seek	to	transform	its	generation	portfolio with	new	or	repowered	generation	resources.		Opportunities	resulting	from	the	supply	plan	initiative,	including	new	projects	or	the	exploration	of alternative	 financing	 sources,	 could	 result	 in	 increases	 or	 decreases	 in	 the	 capital	 expenditure	 estimates	 given	 above.	Estimated	 capital expenditures	are	also	subject	to	periodic	review	and	modification	and	may	vary	based	on	the	ongoing	effects	of	business	restructuring,	regulatory constraints	and	requirements,	environmental	regulations,	business	opportunities,	market	volatility,	economic	trends,	changes	in	project	plans,	and the	ability	to	access	capital.

# Ninemile	Point	Unit	6	Self-Build	Project

In	June	2011,	Entergy	Louisiana	filed	with	the	LPSC	an	application	seeking	certification	that	the	public	necessity	and	convenience	would be	served	by	Entergy	Louisiana's	construction	of	a	combined-cycle	gas	turbine	generating	facility	(Ninemile	6)	at	its	existing	Ninemile	Point electric	generating	station.	Ninemile	6	will	be	a	nominally-sized	550	MW	unit	that	is	estimated	to	cost	approximately	$721	million	to	construct, excluding	interconnection	and	transmission	upgrades.	Entergy	Gulf	States	Louisiana	joined	in	the	application,	seeking	certification	of	its	purchase under	a	life-of-unit	power	purchase	agreement	of	up	to	25%	of	the	capacity	and	energy	generated	by	Ninemile	6.	The

Ninemile	6	capacity	and	energy	is	proposed	to	be	allocated	55%	to	Entergy	Louisiana,	25%	to	Entergy	Gulf	States	Louisiana,	and	20%	to	Entergy New	Orleans.	In	February	2012	the	City	Council	passed	a	resolution	authorizing	Entergy	New	Orleans	to	purchase	20%	of	the	Ninemile	6	energy and	 capacity.	In	March	2012	the	LPSC	unanimously	voted	to	grant	the	certifications	requested	by	Entergy	Gulf	States	Louisiana	and	Entergy Louisiana.	Following	approval	by	the	LPSC,	Entergy	Louisiana	issued	full	notice	to	proceed	to	the	project's	engineering,	procurement,	and construction	contractor.	All	major	permits	and	approvals	required	to	begin	construction	have	been	obtained	and	construction	is	in	progress.

Under	the	terms	approved	by	the	LPSC,	costs	may	be	recovered	through	Entergy	Louisiana's	and	Entergy	Gulf	States	Louisiana's	formula rate	plans	beginning	in	the	month	after	the	unit	is	placed	in	service.	In	November	2013,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	filed a	joint	application	with	the	LPSC	to	certify	the	estimated	first	year	revenue	requirement	associated	with	Ninemile	6	that	will	be	placed	into	rates. Entergy	New	Orleans	expects	to	initiate	a	rate	proceeding	prior	to	the	expected	in-service	date.

# 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 January	2014	meeting,	the	Board	declared	a	dividend	of	$0.83	per	share,	which	is	the	same	quarterly	dividend	per	share	that	Entergy	has	paid since	the	second	quarter	2010.	Entergy	paid	$593	million	in	2013,	$589	million	in	2012,	and	$590	million	in	2011	in	cash	dividends	on	its common	stock.

In	accordance	with	Entergy's	stock-based	compensation	plans,	Entergy	periodically	grants	stock	options,	restricted	stock,	performance units,	and	restricted	unit	awards	to	key	employees,	which	may	be	exercised	to	obtain	shares	of	Entergy's	common	stock.	According	to	the	plans, these	shares	can	be	newly	issued	shares,	treasury	stock,	or	shares	purchased	on	the	open	market.	Entergy's	management	has	been	authorized	by the	Board	to	repurchase	on	the	open	market	shares	up	to	an	amount	sufficient	to	fund	the	exercise	of	grants	under	the	plans.

In	addition	to	the	authority	to	fund	grant	exercises,	the	Board	has	authorized	share	repurchase	programs	to	enable	opportunistic	purchases in	response	to	market	conditions.	In	October	2010	the	Board	granted	authority	for	a	$500	million	share	repurchase	program.	As	of	December	31, 2013,	$350	million	of	authority	remains	under	the	$500	million	share	repurchase	program.	The	amount	of	repurchases	may	vary	as	a	result	of material	changes	in	business	results	or	capital	spending	or	new	investment	opportunities,	or	if	limitations	in	the	credit	markets	continue	for	a prolonged	period.

# 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	or	commercial	paper;	and

•sales	of	assets.

Circumstances	such	as	weather	patterns,	fuel	and	purchased	power	price	fluctuations,	and	unanticipated	expenses,	including	unscheduled plant	outages	and	storms,	could	affect	the	timing	and	level	of	internally	generated	funds	in	the	future.

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	could	restrict	 the	payment	of	cash	dividends	or	other	distributions	on	 their common	and	preferred	stock.	As	of	December	31,	2013,	under	provisions

in	their	mortgage	indentures,	Entergy	Arkansas	and	Entergy	Mississippi	had	restricted	retained	earnings	unavailable	for	distribution	to	Entergy Corporation	of	$394.9	million	and	$68.5	million,	respectively.	All	debt	and	common	and	preferred	equity	issuances	by	the	Registrant	Subsidiaries require	prior	regulatory	approval	and	their	preferred	equity	and	debt	issuances	are	also	subject	to	issuance	tests	set	forth	in	corporate	charters,	bond indentures,	and	other	agreements.	Entergy	believes	that	the	Registrant	Subsidiaries	have	sufficient	capacity	under	these	tests	to	meet	foreseeable capital	needs.

The	FERC	has	 jurisdiction	over	securities	 issuances	by	 the	Utility	operating	companies	and	System	Energy	(except	securities	with maturities	longer	than	one	year	issued	by	Entergy	Arkansas	and	Entergy	New	Orleans,	which	are	subject	to	the	jurisdiction	of	the	APSC	and	the City	 Council,	 respectively).	No	regulatory	approvals	are	necessary	for	Entergy	Corporation	to	issue	securities.	The	current	FERC-authorized short-term	borrowing	limits	are	effective	through	October	31,	2015.	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi, Entergy	Texas,	and	System	Energy	have	obtained	long-term	financing	authorizations	from	the	FERC	that	extend	through	October	2015.	Entergy Arkansas	has	obtained	long-term	financing	authorization	from	the	APSC	that	extends	through	December	2015.	Entergy	New	Orleans	has	obtained long-term	financing	authorization	from	the	City	Council	that	extends	through	July	2014.	In	addition	to	borrowings	from	commercial	banks,	the FERC	short-term	borrowing	orders	authorize	the	Registrant	Subsidiaries	to	continue	as	participants	in	the	Entergy	System	money	pool.	The money	pool	is	an	intercompany	borrowing	arrangement	designed	to	reduce	Entergy's	subsidiaries'	dependence	on	external	short-term	borrowings. Borrowings	from	the	money	pool	and	external	short-term	borrowings	combined	may	not	exceed	the	FERC-authorized	limits.	See	Notes	4	and	5	to the	financial	statements	for	further	discussion	of	Entergy's	borrowing	limits,	authorizations,	and	amounts	outstanding.

# Hurricane	Isaac

In	August	2012,	Hurricane	Isaac	caused	extensive	damage	to	portions	of	Entergy's	service	area	in	Louisiana,	and	to	a	lesser	extent	in Mississippi	and	Arkansas.		The	storm	resulted	in	widespread	power	outages,	significant	damage	primarily	to	distribution	infrastructure,	and	the loss	of	sales	during	the	power	outages.

In	April	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	a	joint	application	with	the	LPSC	relating	to	Hurricane	Isaac system	restoration	costs.		Specifically,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	requested	that	the	LPSC	determine	the	amount	of such	costs	that	were	prudently	incurred	and	are,	thus,	eligible	for	recovery	from	customers.		Including	carrying	costs	and	additional	storm	escrow funds,	Entergy	Gulf	States	Louisiana	is	seeking	an	LPSC	determination	that	$73.8	million	in	system	restoration	costs	were	prudently	incurred	and Entergy	Louisiana	is	seeking	an	LPSC	determination	that	$247.7	million	in	system	restoration	costs	were	prudently	incurred.		Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	intend	to	replenish	their	storm	escrow	accounts	to	$90	million	and	$200	million,	respectively,	primarily	through traditional	debt	markets	and	have	requested	special	rate	 treatment	of	any	borrowings	for	 that	purpose.	 	In	May	2013,	Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	filed	a	supplemental	application	proposing	a	specific	means	to	finance	system	restoration	costs	and	related requests.	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	are	proposing	to	finance	Hurricane	Isaac	restoration	costs	through	Louisiana	Act 55	financing,	which	was	the	same	method	they	used	for	Hurricanes	Katrina,	Rita,	Gustav,	and	Ike.

The	LPSC	Staff	filed	direct	testimony	in	September	2013	concluding	that	Hurricane	Isaac	system	restoration	costs	incurred	by	Entergy Gulf	States	Louisiana	and	Entergy	Louisiana	were	reasonable	and	prudent,	subject	to	proposed	minor	adjustments	which	totaled	approximately 1%	of	each	company's	costs.	The	LPSC	Staff	also	supported	the	requests	to	re-establish	storm	reserves	of	$90	million	for	Entergy	Gulf	States Louisiana	and	$200	million	for	Entergy	Louisiana.	One	intervenor	filed	testimony	recommending	storm	reserve	levels	of	$70	million	for	Entergy Gulf	States	Louisiana	and	$100	million	for	Entergy	Louisiana,	but	takes	no	position	on	the	prudence	of	the	Hurricane	Isaac	system	restoration costs.	An	evidentiary	hearing	took	place	in	December	2013,	and	an	LPSC	decision	is	expected	in	2014.

Total	restoration	costs	for	the	repair	and/or	replacement	of	Entergy	New	Orleans's	electric	facilities	damaged	by	Hurricane	Isaac	were $47.3	million.	Entergy	New	Orleans	withdrew	$17.4	million	from	the	storm	reserve	escrow

account	to	partially	offset	these	costs.	Entergy	New	Orleans	plans	to	make	a	filing	with	the	City	Council	in	the	first	quarter	of	2014	seeking certification	of	these	costs.

# Entergy	Louisiana	Securitization	Bonds	–	Little	Gypsy

In	August	2011	the	LPSC	issued	a	financing	order	authorizing	the	issuance	of	bonds	to	recover	Entergy	Louisiana's	investment	recovery costs	associated	with	the	canceled	Little	Gypsy	repowering	project.		In	September	2011,	Entergy	Louisiana	Investment	Recovery	Funding	I, L.L.C.,	a	company	wholly-owned	and	consolidated	by	Entergy	Louisiana,	issued	$207.2	million	of	senior	secured	investment	recovery	bonds. The	bonds	have	an	interest	rate	of	2.04%	and	an	expected	maturity	date	of	June	2021.		There	is	no	recourse	to	Entergy	or	Entergy	Louisiana	in	the event	of	a	bond	default.	See	Note	5	to	the	financial	statements	for	additional	discussion	of	the	issuance	of	the	investment	recovery	bonds.

# Cash	Flow	Activity

As	shown	in	Entergy's	Statements	of	Cash	Flows,	cash	flows	for	the	years	ended	December	31,	2013,	2012,	and	2011	were	as	follows.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $533 | $694 | $1,295 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 3,189 | 2,940 | 3,128 |
| Investing\tactivities | (2,602) | (3,639) | (3,447) |
| Financing\tactivities | (381) | 538 | (282) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 206 | (161) | (601) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $739 | $533 | $694 |

Net	cash	provided	by	operating	activities	increased	by	$249	million	in	2013	compared	to	2012	primarily	due	to:

•increased	recovery	of	deferred	fuel	costs;

•higher	Utility	net	revenues	in	2013	resulting	from	additional	generation	investments	made	in	2012;

•proceeds	of	$72	million	associated	with	the	payments	received	in	2013	from	the	U.S.	Department	of	Energy	resulting	from	litigation regarding	the	storage	of	spent	nuclear	fuel;

•a	decrease	of	approximately	$84	million	in	storm	restoration	spending	in	2013	due	to	Hurricane	Isaac	in	August	2012,	offset	by	an increase	of	approximately	$23	million	in	storm	restoration	spending	in	2013	due	to	the	Arkansas	December	2012	winter	storm; •a	refund	of	$30.6	million,	including	interest,	paid	to	AmerenUE	in	June	2012.	The	FERC	ordered	Entergy	Arkansas	to	refund	to AmerenUE	the	rough	production	cost	equalization	payments	previously	collected.	See	Note	2	to	the	financial	statements	for	further discussion	of	the	FERC	order;	and

•a	decrease	of	$14	million	in	spending	on	nuclear	refueling	outages	in	2013	as	compared	to	the	same	period	in	prior	year.

These	increases	in	cash	flow	were	partially	offset	by:

•an	increase	of	$79	million	in	income	tax	payments	primarily	due	to	state	income	tax	effects	of	the	settlement	of	the	2004-2005	IRS	audit in	the	fourth	quarter	2012;

•an	increase	of	$52	million	in	lump	sum	retirement	payments	out	of	the	non-qualified	pension	plan,	partially	offset	by	a	decrease	of	$7 million	in	pension	contributions.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and	Other	Postretirement	Benefits"	below and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding;

•the	decrease	in	Entergy	Wholesale	Commodities	net	revenue	that	was	discussed	previously;	and

•approximately	$25	million	in	spending	related	to	the	generator	stator	incident	at	ANO,	as	discussed	previously.

Entergy's	net	cash	provided	by	operating	activities	decreased	by	$188	million	in	2012	compared	to	2011	primarily	due	to:

•the	decrease	in	Entergy	Wholesale	Commodities	net	revenue	that	is	discussed	previously;

•Hurricane	Isaac	storm	restoration	spending	of	$98	million	in	2012;

•income	tax	payments	of	$49.2	million	in	2012	compared	to	income	tax	refunds	of	$2	million	in	2011.	The	income	tax	payments	in	2012 were	primarily	due	to	state	income	tax	effects	of	the	settlement	of	the	2006-2007	IRS	audit;	and

•a	 refund	 of	 $30.6	 million,	 including	 interest,	 paid	 to	AmerenUE	 in	 June	 2012.	The	 FERC	 ordered	 Entergy	Arkansas	 to	 refund	 to AmerenUE	 the	rough	production	cost	equalization	payments	previously	collected.	See	Note	2	to	the	financial	statements	for	further discussion	of	the	FERC	order.

These	decreases	were	partially	offset	by	a	decrease	of	$230	million	in	pension	contributions.	See	"Critical	Accounting	Estimates	-	Qualified Pension	and	Other	Postretirement	Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

# Investing	Activities

Net	cash	used	in	investing	activities	decreased	by	$1,038	million	in	2013	compared	to	2012	primarily	due	to:

•the	acquisitions	of	the	Hot	Spring	plant	by	Entergy	Arkansas	and	the	Hinds	plant	by	Entergy	Mississippi	in	November	2012.	See	Note	15 to	the	financial	statements	for	further	discussion	of	these	plant	acquisitions;

•the	withdrawal	of	a	total	of	$260	million	from	storm	reserve	escrow	accounts	in	2013,	primarily	by	Entergy	Gulf	States	Louisiana	and Entergy	Louisiana,	after	Hurricane	Isaac.	See	Note	2	to	the	financial	statements	for	a	discussion	of	Hurricane	Isaac;

•a	decrease	in	construction	expenditures,	primarily	in	the	Utility	business,	resulting	from	spending	in	2012	on	the	uprate	project	at	Grand Gulf	and	storm	restoration	spending	in	2012	resulting	from	the	Arkansas	December	2012	winter	storm	and	Hurricane	Isaac,	substantially offset	by	spending	in	2013	on	the	Ninemile	6	self-build	project	and	spending	in	2013	related	to	the	generator	stator	incident	at	ANO,	as discussed	previously.	Entergy's	construction	spending	plans	for	2014	through	2016	are	discussed	further	in	"Capital	Expenditure	Plans and	Other	Uses	of	Capital"	above;	and

•proceeds	of	$140	million	from	the	sale	in	November	2013	of	Entergy	Solutions	District	Energy.	See	Note	15	to	the	financial	statements for	further	discussion	of	the	sale.

# The	decrease	was	partially	offset	by:

•a	change	in	collateral	deposit	activity,	reflected	in	the	"Decrease	(increase)	in	other	investments"	line	on	the	Consolidated	Statement	of Cash	Flows,	as	Entergy	returned	$50	million	more	net	deposits	in	2013	than	2012.	Entergy	Wholesale	Commodities's	forward	sales contracts	are	discussed	in	the	"Market	and	Credit	Risk	Sensitive	Instruments"	section	below;	and •proceeds	of	$21	million	in	2013	compared	to	proceeds	of	$109	million	in	2012	from	the	U.S.	Department	of	Energy	resulting	from litigation	regarding	the	storage	of	spent	nuclear	fuel.

Net	cash	used	in	investing	activities	increased	by	$192	million	in	2012	compared	to	2011	primarily	due	to	an	increase	in	construction expenditures,	primarily	in	the	Utility	business	resulting	from	Hurricane	Isaac	restoration	spending,	the	uprate	project	at	Grand	Gulf,	the	Ninemile Unit	6	self-build	project,	and	the	Waterford	3	steam	generator	replacement	project	in	2012.

# This	increase	was	partially	offset	by:

•a	decrease	of	$190	million	in	payments	for	the	purchase	of	plants	resulting	from	the	purchase	of	the	Hot	Spring	Energy	Facility	by Entergy	Arkansas	for	approximately	$253	million	in	November	2012,	the	purchase	of	the	Hinds	Energy	Facility	by	Entergy	Mississippi for	approximately	$206	million	in	November	2012,	the	purchase	of	the	Acadia	Power	Plant	by	Entergy	Louisiana	for	approximately	$300 million	in	April	2011,	and	the	purchase	of	the	Rhode	Island	State	Energy	Center	for	approximately	$346	million	by	an	Entergy	Wholesale Commodities	subsidiary	in	December	2011.	These	transactions	are	described	in	more	detail	in	Note	15	to	the	financial	statements; •proceeds	received	from	the	U.S.	Department	of	Energy	resulting	from	litigation	regarding	the	storage	of	spent	nuclear	fuel;	and •a	decrease	in	nuclear	fuel	purchases	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements,	material and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle.

# Financing	Activities

Financing	activities	used	$381	million	in	net	cash	in	2013	compared	to	providing	$538	million	in	net	cash	in	2012	primarily	due	to:

•long-term	debt	activity	using	approximately	$69	million	of	cash	in	2013	compared	to	providing	$348	million	of	cash	in	2012.	The	most significant	long-term	debt	activity	in	2013	included	the	net	issuance	of	approximately	$520	million	of	long-term	debt	at	the	Utility operating	companies	and	System	Energy	and	Entergy	Corporation	decreasing	borrowings	outstanding	on	its	long-term	credit	facility	by $540	million.	Entergy	Corporation	issued	$380	million	of	commercial	paper	in	2013	and	$665	million	in	2012,	in	part,	to	repay borrowings	on	its	long-term	credit	facility;

•a	net	decrease	of	$136	million	in	short-term	borrowings	by	the	nuclear	fuel	company	variable	interest	entities;	and •$51	million	in	proceeds	from	the	sale	to	a	third	party	in	2012	of	a	portion	of	Entergy	Gulf	States	Louisiana's	investment	in	Entergy Holdings	Company's	Class	A	preferred	membership	interests.

For	the	details	of	Entergy's	commercial	paper	program	and	the	nuclear	fuel	company	variable	interest	entities'	short-term	borrowings,	see	Note	4 to	the	financial	statements.	See	Note	5	to	the	financial	statements	for	details	of	long-term	debt	and	Entergy's	commercial	paper	program.

Entergy's	financing	activities	provided	$538	million	of	cash	in	2012	compared	to	using	$282	million	of	cash	in	2011	primarily	due	to	the following	activity:

•long-term	debt	activity	provided	approximately	$348	million	of	cash	in	2012	compared	to	$554	million	of	cash	in	2011.	The	most significant	long-term	debt	activity	in	2012	included	the	net	issuance	of	$1.1	billion	of	long-term	debt	at	the	Utility	operating	companies and	System	Energy,	the	issuance	of	$500	million	of	senior	notes	by	Entergy	Corporation,	and	Entergy	Corporation	decreasing	borrowings outstanding	on	its	long-term	credit	facility	by	$1.1	billion.	Entergy	Corporation	issued	$665	million	of	commercial	paper	in	2012	to	repay borrowings	on	its	long-term	credit	facility;

•Entergy	repurchasing	$235	million	of	its	common	stock	in	2011,	as	discussed	below;

•a	net	increase	in	2012	of	$51	million	in	short-term	borrowings	by	the	nuclear	fuel	company	variable	interest	entities;	and •$51	million	in	proceeds	from	the	sale	to	a	third	party	in	2012	of	a	portion	of	Entergy	Gulf	States	Louisiana's	investment	in	Entergy Holdings	Company's	Class	A	preferred	membership	interests.

For	the	details	of	Entergy's	long-term	debt	outstanding,	see	Note	5	to	the	financial	statements.

# Rate,	Cost-recovery,	and	Other	Regulation

# State	and	Local	Rate	Regulation	and	Fuel-Cost	Recovery

The	rates	that	the	Utility	operating	companies	and	System	Energy	charge	for	their	services	significantly	influence	Entergy's	financial position,	results	of	operations,	and	liquidity.	These	companies	are	regulated	and	the	rates	charged	to	their	customers	are	determined	in	regulatory proceedings.	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.	Following	is	a	summary	of	the	Utility	operating	companies'	authorized	returns	on common	equity:

The	Utility	operating	companies'	base	rate,	fuel	and	purchased	power	cost	recovery,	and	storm	cost	recovery	proceedings	are	discussed	in	Note	2 to	the	financial	statements.	The	Entergy	Arkansas	authorized	return	on	common	equity	is	subject	to	pending	rehearing.

# Federal	Regulation

# Entergy's	Integration	Into	the	MISO	Regional	Transmission	Organization

On	December	19,	2013,	the	Utility	operating	companies	successfully	completed	their	planned	integration	into	the	MISO	RTO.	Integration into	the	MISO	RTO	was	the	culmination	of	efforts	undertaken	by	the	Utility	operating	companies	consistent	with	FERC's	order,	issued	in	2000, encouraging	utilities	 to	voluntarily	place	 their	 transmission	facilities	under	 the	control	of	an	 independent	regional	 transmission	organization (RTO).	Initially,	 these	 efforts	 led	 to	 the	 establishment	 of	 Southwest	 Power	 Pool	 (SPP),	 an	 RTO,	 in	 November	 2006,	 as	 the	 Independent Coordinator	of	Transmission	(ICT)	for	the	Utility	operating	companies,	with	responsibility	for	certain	transmission	tariff	functions,	including granting	or	denying	transmission	service,	administering	OASIS,	evaluating	all	transmission	requests,	and	serving	as	the	reliability	coordinator. Also	as	part	of	these	initial	efforts,	an	Entergy	Regional	State	Committee	(E-RSC),	comprised	of	one	representative	from	each	of	the	Utility operating	companies'	retail	regulators,	was	formed.	In	concert	with	the	FERC,	the	E-RSC	retained	an	independent	entity	to	conduct	a	cost-benefit analysis	comparing	the	option	of	continuing	the	ICT	arrangement	to	proposals	under	which	Entergy	would	join	the	SPP	RTO	or	the	MISO	RTO. This	analysis,	completed	in	2011,	showed	that	joining	the	MISO	RTO	would	be	expected	to	provide	the	most	benefits	to	the	Utility	operating companies'	customers	of	these	options.

On	April	25,	2011,	Entergy	announced	that	each	of	the	Utility	operating	companies	proposed	to	join	the	MISO	RTO,	an	RTO	operating	in several	U.S.	states	and	also	in	Canada.	On	December	19,	2013,	the	Utility	operating	companies	integrated	into	the	MISO	RTO.	Becoming	a member	of	MISO	does	not	affect	 the	ownership	by	 the	Utility	operating	companies	of	 their	 transmission	facilities	or	 the	responsibility	for maintaining	those	facilities.	With	the	Utility	operating	companies	fully	integrated	as	members,	however,	MISO	assumed	control	of	transmission planning	and	congestion	management	and,	through	its	Day	2	market,	MISO	provides	schedules	and	pricing	for	the	commitment	and	dispatch	of generation	that	is	offered	into	MISO's	markets,	as	well	as	pricing	for	load	that	bids	into	the	market.

After	the	April	2011	announcement,	each	of	the	Utility	operating	companies	filed	an	application	with	its	retail	regulator	concerning	the proposal	to	join	MISO	and	transfer	functional	control	of	each	company's	transmission	assets	to	MISO.	The	applications	to	join	MISO	sought	a finding	that	membership	in	MISO	is	in	the	public	interest.

The	LPSC	voted	to	grant	Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	application	for	transfer	of	control	to	MISO,	subject	to conditions,	in	May	2012	and	issued	its	order	in	June	2012.

In	October	2012	the	APSC	authorized	Entergy	Arkansas	to	sign	the	MISO	Transmission	Owners	Agreement	and	move	forward	with	the MISO	integration	process.	The	APSC	stated	in	its	order	that	it	would	give	conditional	approval	of	Entergy	Arkansas's	application	upon	MISO's filing	with	the	APSC	proof	of	approval	by	the	appropriate	MISO	entities	of	certain	governance	enhancements.	In	April	2013	the	APSC	issued	an order	resolving	the	outstanding	issues	in	Entergy	Arkansas's	change	of	control	docket	and	granted	Entergy	Arkansas's	application	subject	to	the conditions	set	forth	in	the	APSC's	October	2012	order.	In	September	2013	the	APSC	issued	an	order	directing	Entergy	Arkansas	and	MISO	to show	cause	why	the	APSC	should	not	find	that	Entergy	Arkansas	and	MISO	were	in	violation	of	certain	conditions.	In	October	2013,	Entergy Arkansas	and	MISO	submitted	testimony	in	compliance	with	the	show	cause	order.	In	November	2013	the	APSC	issued	an	order	in	which	it	found that	Entergy	Arkansas	and	MISO	are	not	currently	in	violation	of	the	conditions	addressed	in	the	show	cause	order,	but	directed	that	Entergy Arkansas	and	MISO	demonstrate,	through	monthly	testimony,	that	Entergy	Arkansas	and	MISO	are	moving	forward	with	full	compliance	with those	conditions,	and	that	Entergy	Arkansas	and	MISO	advise	the	APSC	of	FERC	filings	or	FERC	orders	related	to	compliance	with	those conditions.

In	September	2012,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	filed	a	joint	stipulation	indicating	that	they	agree	that Entergy	Mississippi's	proposed	transfer	of	functional	control	of	its	transmission	facilities	to	MISO	is	in	the	public	interest,	subject	to	certain contingencies	and	conditions.	In	November	2012	the	MPSC	issued	an	order	approving	a	joint	stipulation	filed	by	Entergy	Mississippi	and	the Mississippi	Public	Utilities	Staff,	concluding

that	Entergy	Mississippi's	proposed	transfer	of	functional	control	of	its	transmission	facilities	to	MISO	is	in	the	public	interest,	subject	to	certain conditions.

In	November	2012	the	City	Council	issued	a	resolution	concerning	the	application	of	Entergy	New	Orleans.	In	its	resolution,	the	City Council	approved	a	settlement	agreement	agreed	to	by	Entergy	New	Orleans,	Entergy	Louisiana,	MISO,	and	the	advisors	to	the	City	Council related	to	joining	MISO	and	found	that	it	is	in	the	public	interest	for	Entergy	New	Orleans	and	Entergy	Louisiana	to	join	MISO,	subject	to	certain conditions.

Entergy	Texas	submitted	its	change	of	control	filing	in	April	2012.	In	August	2012	parties	in	the	PUCT	proceeding,	with	the	exception	of SPP,	filed	a	non-unanimous	settlement.	The	substance	of	the	settlement	is	that	it	is	in	the	public	interest	for	Entergy	Texas	to	transfer	operational control	of	its	transmission	facilities	to	MISO	under	certain	conditions.	In	October	2012	the	PUCT	issued	an	order	approving	the	transfer	as	in	the public	interest,	subject	to	the	terms	and	conditions	in	the	settlement,	with	several	additional	terms	and	conditions	requested	by	the	PUCT	and agreed	to	by	the	settling	parties.	In	particular,	the	settlement	and	the	PUCT	order	required	Entergy	Texas,	unless	otherwise	directed	by	the	PUCT, to	provide	by	October	31,	2013	its	notice	to	exit	the	System	Agreement,	subject	to	certain	conditions.	In	addition,	the	PUCT	order	requires Entergy	Texas,	as	well	as	Entergy	Corporation	and	Entergy	Services,	Inc.,	to	exercise	reasonable	best	efforts	to	engage	the	Utility	operating companies	and	their	retail	regulators	in	searching	for	a	consensual	means,	subject	to	FERC	approval,	of	allowing	Entergy	Texas	to	exit	the	System Agreement	prior	to	the	end	of	the	mandatory	96-month	notice	period.

With	these	actions	on	their	applications,	the	Utility	operating	companies	obtained	from	all	of	the	retail	regulators	the	public	interest findings	sought	by	the	Utility	operating	companies	in	order	to	move	forward	with	their	plan	to	join	MISO.	Each	of	the	retail	regulators'	orders includes	conditions,	some	of	which	entail	compliance	prospectively.

In	December	2012	the	PUCT	Staff	filed	a	memo	in	the	proceeding	established	by	the	PUCT	to	track	compliance	with	its	October	2012 order.	In	the	memo,	the	PUCT	Staff	expressed	concerns	about	the	effect	of	Entergy	Texas's	exit	from	the	System	Agreement	on	PPAs	for	gas	and oil-fired	 generation	 units	 owned	 by	 Entergy	 Texas	 and	 Entergy	 Gulf	 States	 Louisiana	 that	 were	 entered	 into	 upon	 the	 December	 2007 jurisdictional	separation	of	Entergy	Gulf	States,	Inc.	and,	further,	expressed	concerns	about	the	implications	of	these	issues	as	they	relate	to	the continuing	validity	of	the	PUCT's	October	2012	order	regarding	MISO.	Entergy	Texas	subsequently	filed	a	position	statement	relating	that Entergy	Texas's	exit	from	the	System	Agreement	would	trigger	the	termination	of	the	PPAs	of	concern	to	the	PUCT	Staff.	 Entergy	Texas expressed	its	continuing	commitment	to	work	collaboratively	with	the	PUCT	Staff	and	other	parties	to	address	ongoing	issues	and	challenges	in implementing	the	PUCT	order	including	any	potential	effect	from	termination	of	the	PPAs.	In	January	2013,	Entergy	Texas	filed	an	updated analysis	assessing	the	effect	on	the	benefits	of	MISO	membership	of	terminating	the	particular	PPAs	addressed	in	Entergy	Texas's	Statement	of Position	upon	Entergy	Texas's	exit	from	the	System	Agreement,	and	determined	that	termination	of	these	PPAs	did	not	adversely	affect	the benefits	of	the	move	to	MISO	once	Entergy	Texas	exits	the	System	Agreement.	An	independent	consultant	was	retained	to	assist	the	PUCT	Staff in	its	assessment	of	the	analysis.	In	April	2013	the	PUCT	staff	filed	a	study	performed	by	its	independent	consultant	assessing	Entergy	Texas's January	2013	updated	analysis	of	the	effect	of	termination	of	certain	PPAs	on	Entergy	Texas's	costs	upon	Entergy	Texas's	exit	from	the	System Agreement.	While	the	independent	consultant	study	concluded	that	the	adjustments	made	in	Entergy	Texas's	updated	analysis	were	analytically correct,	the	consultant	also	recommended	further	study	regarding	the	effect	of	the	termination	of	the	PPAs	on	the	benefits	associated	with	Entergy Texas	joining	MISO.	Entergy	Texas	filed	a	response	to	the	consultant	study,	noting	a	number	of	errors	in	the	analysis	and	recommending	against any	further	study	of	this	matter.	Entergy	Texas	subsequently	agreed	to	fund	further	analysis,	to	be	performed	by	a	different	independent	consultant for	the	PUCT,	regarding	the	effects	of	termination	of	these	PPAs.	 In	August	2013	the	report	of	the	PUCT's	second	independent	consultant regarding	the	effects	of	termination	of	these	PPAs	was	filed	with	the	PUCT	as	part	of	a	larger	report	addressing	the	results	of	the	consultant's comprehensive	analysis	of	Entergy	Texas's	transition	to	operations	post-exit	from	the	System	Agreement.	The	report	concluded	(consistent	with Entergy	Texas's	updated	analysis)	that	under	both	the	"Foundation	Case"	capacity	price	forecast	and	the	high	capacity	price	sensitivity	that	were performed,	Entergy	Texas	and	its	customers	would	be	better	off	on	a	present-value	basis	if	these	PPAs	terminate.	 Under	the	low	capacity	price sensitivity,	there	was	a	net	cost	to	Entergy	Texas	customers	if	these	PPAs	terminate.	Consistent	with	the	requirements

of	the	PUCT	conditional	order	approving	the	change	in	control	to	MISO,	on	October	18,	2013,	Entergy	Texas	gave	notice	of	cancellation	to terminate	its	participation	in	the	System	Agreement.

Beginning	in	2011,	the	Utility	operating	companies	and	the	MISO	RTO	began	submitting	various	filings	with	the	FERC	that	contained many	of	the	rates,	terms	and	conditions	that	would	govern	the	Utility	operating	companies	integration	into	the	MISO	RTO.	These	filings	included, but	are	not	limited	to,	proposals	to	address	the	allocation	of	transmission	upgrade	costs,	an	extension	of	the	E-RSC	arrangement,	enhanced authority	for	the	Organization	of	MISO	States,	Inc.,	and	other	numerous	other	matters.	The	Utility	operating	companies	and	the	MISO	RTO received	the	FERC	orders	necessary	for	those	companies	to	integrate	into	the	MISO	RTO	on	December	19,	2013	consistent	with	the	approvals obtained	from	Entergy's	retail	regulators,	although	some	proceedings	remain	pending	at	FERC.

In	January	2013,	Occidental	Chemical	Corporation	filed	with	the	FERC	a	petition	for	declaratory	judgment	and	complaint	against	MISO alleging	that	MISO's	proposed	treatment	of	Qualifying	Facilities	(QFs)	in	the	Entergy	region	is	unduly	discriminatory	in	violation	of	sections	205 and	206	of	the	Federal	Power	Act	and	violates	PURPA	and	the	FERC's	implementing	regulations.	 Occidental's	filing	asks	that	the	FERC	declare that	MISO's	QF	integration	plan	is	unlawful,	find	that	the	plan	cannot	be	implemented	because	MISO	did	not	file	it	pursuant	to	section	205	of	the Federal	Power	Act,	and	direct	that	MISO	modify	certain	aspects	of	the	plan.	Entergy	sought	to	intervene	and	filed	a	protest	to	the	pleadings.

In	February	2013,	Entergy	Services,	on	behalf	of	the	Utility	operating	companies,	made	a	filing	with	the	FERC	requesting	to	adopt	the standard	Attachment	O	formula	rate	template	used	by	transmission	owners	to	establish	transmission	rates	within	MISO.	The	filing	proposed	four transmission	pricing	zones	for	the	Utility	operating	companies,	one	for	Entergy	Arkansas,	one	for	Entergy	Mississippi,	one	for	Entergy	Texas,	and one	for	Entergy	Louisiana,	Entergy	Gulf	States	Louisiana,	and	Entergy	New	Orleans.	In	June	2013	the	FERC	issued	an	order	accepting	the	use	of four	transmission	pricing	zones	and	set	for	hearing	and	settlement	judge	procedures	those	issues	of	material	fact	that	FERC	decided	could	not	be resolved	based	on	the	existing	record.	Several	parties,	including	the	City	Council,	filed	requests	for	rehearing	of	the	June	2013	order.	On	February 20,	2014,	the	FERC	issued	an	order	addressing	the	rehearing	requests.	Among	other	things,	the	FERC	denied	rehearing	and	affirmed	its	prior decision	allowing	the	four	transmission	pricing	zones	for	the	Utility	operating	companies	in	MISO.	The	FERC	granted	rehearing	and	set	for hearing	and	settlement	judge	proceedings	certain	challenges	of	MISO's	regional	through	and	out	rates.

# System	Agreement

The	FERC	regulates	wholesale	rates	(including	Entergy	Utility	intrasystem	energy	allocations	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.	The	Utility	operating	companies historically	have	engaged	in	the	coordinated	planning,	construction,	and	operation	of	generating	and	bulk	transmission	facilities	under	the	terms	of the	System	Agreement,	which	is	a	rate	schedule	that	has	been	approved	by	the	FERC.	Certain	of	the	Utility	operating	companies'	retail	regulators and	other	parties	are	pursuing	litigation	involving	the	System	Agreement	at	the	FERC.	The	proceedings	include	challenges	to	the	allocation	of costs	as	defined	by	the	System	Agreement	and	allegations	of	imprudence	by	the	Utility	operating	companies	in	their	execution	of	their	obligations under	the	System	Agreement.	See	Note	2	to	the	financial	statements	for	discussions	of	this	litigation.

# Utility	Operating	Company	Notices	of	Termination	of	System	Agreement	Participation

Citing	its	concerns	that	the	benefits	of	its	continued	participation	in	the	current	form	of	the	System	Agreement	have	been	seriously	eroded, in	December	2005,	Entergy	Arkansas	submitted	its	notice	that	it	will	terminate	its	participation	in	the	current	System	Agreement	effective	ninety- six	(96)	months	from	the	date	of	the	notice	or	such	earlier	date	as	authorized	by	the	FERC.

In	October	2007	the	MPSC	issued	a	letter	confirming	its	belief	that	Entergy	Mississippi	should	exit	the	System	Agreement	in	light	of	the recent	 developments	 involving	 the	 System	Agreement.	In	 November	 2007,	 Entergy	 Mississippi	 provided	 its	 written	 notice	 to	 terminate	 its participation	in	the	System	Agreement	effective	ninety-six	(96)	months	from	the	date	of	the	notice	or	such	earlier	date	as	authorized	by	the	FERC.

In	 February	 2009,	 Entergy	Arkansas	 and	 Entergy	 Mississippi	 filed	 with	 the	 FERC	 their	 notices	 of	 cancellation	 to	 terminate	 their participation	in	the	System	Agreement,	effective	December	18,	2013	and	November	7,	2015,	respectively.	In	November	2009	the	FERC	accepted the	notices	of	cancellation	and	determined	that	Entergy	Arkansas	and	Entergy	Mississippi	are	permitted	to	withdraw	from	the	System	Agreement following	the	96-month	notice	period	without	payment	of	a	fee	or	the	requirement	to	otherwise	compensate	the	remaining	Utility	operating companies	as	a	result	of	withdrawal.	In	February	2011	the	FERC	denied	the	LPSC's	and	the	City	Council's	rehearing	requests.	In	September	and October	2012	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit	denied	the	LPSC's	and	the	City	Council's	appeals	of	the	FERC	decisions.	In	January 2013	the	LPSC	and	the	City	Council	filed	a	petition	for	a	writ	of	certiorari	with	the	U.S.	Supreme	Court.	In	May	2013	the	U.S.	Supreme	Court denied	the	petition	for	a	writ	of	certiorari.

In	November	2012	the	Utility	operating	companies	filed	amendments	to	the	System	Agreement	with	the	FERC	pursuant	to	section	205	of the	 Federal	 Power	Act.	The	amendments	consist	primarily	of	the	technical	revisions	needed	to	the	System	Agreement	to	(i)	allocate	certain charges	and	credits	from	the	MISO	settlement	statements	to	the	participating	Utility	operating	companies;	and	(ii)	address	Entergy	Arkansas's withdrawal	from	the	System	Agreement.	As	noted	in	the	filing,	the	Utility	operating	companies	integration	into	MISO	and	the	revisions	to	the System	Agreement	are	the	main	feature	of	the	Utility	operating	companies'	future	operating	arrangements,	including	the	successor	arrangements with	respect	to	the	departure	of	Entergy	Arkansas	from	the	System	Agreement.	The	LPSC,	MPSC,	PUCT,	and	City	Council	filed	protests	at	the FERC	regarding	the	amendments	filed	in	November	2012	and	other	aspects	of	the	Utility	operating	companies'	future	operating	arrangements, including	requests	that	the	continued	viability	of	the	System	Agreement	in	MISO	(among	other	issues)	be	set	for	hearing	by	the	FERC.	On	March 12,	2013,	the	Utility	operating	companies	filed	an	answer	to	the	protests.	The	answer	proposed,	among	other	things,	that:	(1)	the	FERC	allow	the System	Agreement	revisions	to	go	into	effect	as	of	December	19,	2013,	without	a	hearing	and	for	an	initial	two-year	transition	period;	(2)	no	later than	October	18,	2013,	Entergy	Services	submit	a	filing	pursuant	to	section	205	of	the	Federal	Power	Act	that	provides	Entergy	Texas's	notice	of cancellation	to	terminate	participation	in	the	System	Agreement	and	responds	to	the	PUCT's	position	that	Entergy	Texas	be	allowed	to	terminate its	participation	prior	to	the	end	of	the	mandatory	96-month	notice	period;	and	(3)	at	least	six	months	prior	to	the	end	of	the	two-year	transition period,	Entergy	Services	submits	an	additional	filing	under	section	205	of	the	Federal	Power	Act	that	addresses	the	allocation	of	MISO	charges and	credits	among	the	Utility	operating	companies	that	remain	in	the	System	Agreement.	On	December	18,	2013,	the	FERC	issued	an	order accepting	the	revisions	filed	in	November	2012,	subject	to	a	further	compliance	filing	and	other	conditions.	The	FERC	set	one	issue	for	hearing involving	 a	 settlement	 with	 Union	 Pacific	 regarding	 certain	 coal	 delivery	 issues.	Consistent	 with	 the	 decisions	 described	 above,	 Entergy Arkansas's	participation	in	the	System	Agreement	terminated	effective	December	19,	2013.

In	keeping	with	the	commitments	made	in	its	March	2013	answer	to	the	protests	and	after	a	careful	evaluation	of	the	basis	for	and continued	reasonableness	of	the	ninety-six	month	System	Agreement	termination	notice	period,	the	Utility	operating	companies	filed	with	the FERC	on	October	11,	2013	to	amend	the	System	Agreement	changing	the	notice	period	for	an	operating	company	to	terminate	its	participation	in the	System	Agreement	from	ninety-six	months	to	sixty	months.	The	proposed	amendment	also	clarifies	that	the	revised	notice	period	will	apply	to any	written	notice	of	termination	provided	by	an	operating	company	on	or	after	October	12,	2013.	On	October	18,	2013,	Entergy	Texas	provided notice	to	terminate	its	participation	in	the	System	Agreement	effective	after	expiration	of	the	proposed	60-month	notice	period	or	such	other period	as	approved	by	FERC.	The	proposed	amendment	and	Entergy	Texas's	termination	notice	are	without	prejudice	to	continuing	efforts	among affected	operating	companies	and	their	retail	regulators	to	search	for	a	consensual	means	of	allowing	Entergy	Texas	an	early	exit	from	the	System Agreement,	which	could	be	different	from	that	proposed	in	the	October	11,	2013	FERC	filing.	Comments	on	both	filings	were	filed	in	November 2013.

The	LPSC,	the	City	Council,	and	the	PUCT	protested	the	proposed	amendment	to	shorten	the	notice	period	for	an	operating	company	to terminate	its	participation	in	the	System	Agreement	from	ninety-six	months	to	sixty	months.	The	City	Council	argued	that	Entergy	has	not adequately	supported	its	proposal	to	shorten	the	notice	period	from	ninety-six	months	to	sixty	months	and	asked	the	FERC	to	either	reject	the amendment	or	set	it	for	hearing.	The	PUCT	supported	shortening	of	the	notice	period,	but	argued	that	sixty	months	is	not	short	enough	and	that the	FERC	should	instead	order	Entergy	to	shorten	the	notice	period	to	correspond	to	the	time	required	for	a	Utility	operating	company	to	become operationally	ready	to	participate	in	the	MISO	markets	(but	no	longer	than	thirty-six	months).	The	LPSC	argued	that	the	sixty-month	proposal	was not	justified	and	failed	to	make	provision	for	the	consequences	that	would	flow	from	a	company's	withdrawal	from	the	System	Agreement.	The LPSC	and	the	City	Council	both	separately	protested	Entergy	Texas's	termination	notice.

In	January	2014	the	LPSC	issued	a	directive	that	no	later	than	February	15,	2014,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana each	shall	provide	notice	of	their	intention	to	terminate	their	participation	in	the	System	Agreement	and	shall	make	the	necessary	filings	at	the FERC	of	such	notice.	The	LPSC	further	directed	that	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	and	LPSC	Staff	continue	utilizing	their reasonable	best	efforts	to	achieve	a	consensual	resolution	permitting	early	termination	of	the	System	Agreement.	On	February	14,	2014,	Entergy Louisiana	and	Entergy	Gulf	States	Louisiana	provided	notice	of	their	respective	decisions	to	terminate	their	participation	in	the	System	Agreement and	made	a	filing	with	the	FERC	seeking	acceptance	of	the	notice.	In	the	FERC	filing,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana requested	an	effective	date	of	February	14,	2019	or	such	other	effective	date	approved	by	the	FERC	for	the	termination.

See	also	the	discussion	of	the	order	of	the	PUCT	concerning	Entergy	Texas's	proposal	to	join	MISO	discussed	further	in	the	" Federal Regulation	-	Entergy's	Integration	Into	the	MISO	Regional	Transmission	Organization"	section	above.

# U.S.	Department	of	Justice	Investigation

In	September	2010,	Entergy	was	notified	that	the	U.S.	Department	of	Justice	had	commenced	a	civil	investigation	of	competitive	issues concerning	 certain	 generation	 procurement,	 dispatch,	 and	 transmission	 system	 practices	 and	 policies	 of	 the	 Utility	 operating	 companies.	 In November	2012	the	U.S.	Department	of	Justice	issued	a	press	release	in	which	the	U.S.	Department	of	Justice	stated,	among	other	things,	that	the civil	investigation	concerning	certain	generation	procurement,	dispatch,	and	transmission	system	practices	and	policies	of	the	Utility	operating companies	would	remain	open.		The	release	noted,	however,	the	intention	of	each	of	the	Utility	operating	companies	to	join	MISO	and	Entergy's agreement	with	ITC	to	undertake	the	spin-off	and	merger	of	Entergy's	transmission	business.		The	release	stated	that	if	Entergy	follows	through on	these	matters,	the	U.S.	Department	of	Justice's	concerns	will	be	resolved.	The	release	further	stated	that	the	U.S.	Department	of	Justice	will monitor	developments,	and	in	the	event	that	Entergy	does	not	make	meaningful	progress,	the	U.S.	Department	of	Justice	can	and	will	take appropriate	enforcement	action,	if	warranted.	On	December	13,	2013,	Entergy	and	ITC	mutually	agreed	to	terminate	the	transaction	following denial	by	the	MPSC	of	the	joint	application	related	to	the	transaction.	On	December	19,	2013,	the	Utility	operating	companies	successfully completed	their	planned	integration	into	the	MISO	RTO.

# Market	and	Credit	Risk	Sensitive	Instruments

Market	risk	is	the	risk	of	changes	in	the	value	of	commodity	and	financial	instruments,	or	in	future	net	income	or	cash	flows,	in	response	to changing	market	conditions.		Entergy	holds	commodity	and	financial	instruments	that	are	exposed	to	the	following	significant	market	risks.

•The	commodity	price	risk	associated	with	the	sale	of	electricity	by	the	Entergy	Wholesale	Commodities	business.

•The	interest	rate	and	equity	price	risk	associated	with	Entergy's	investments	in	pension	and	other	postretirement	benefit	trust	funds.		See Note	11	to	the	financial	statements	for	details	regarding	Entergy's	pension	and	other	postretirement	benefit	trust	funds.

•The	interest	rate	and	equity	price	risk	associated	with	Entergy's	investments	in	nuclear	plant	decommissioning	trust	funds,	particularly	in the	Entergy	Wholesale	Commodities	business.		See	Note	17	to	the	financial	statements	for	details	regarding	Entergy's decommissioning	trust	funds.

•The	interest	rate	risk	associated	with	changes	in	interest	rates	as	a	result	of	Entergy's	issuances	of	debt.		Entergy	manages	its	interest	rate exposure	by	monitoring	current	interest	rates	and	its	debt	outstanding	in	relation	to	total	capitalization.		See	Notes	4	and	5	to	the financial	statements	for	the	details	of	Entergy's	debt	outstanding.

The	Utility	has	 limited	exposure	 to	 the	effects	of	market	risk	because	 it	operates	primarily	under	cost-based	rate	regulation.	To	 the	 extent approved	by	their	retail	regulators,	the	Utility	operating	companies	hedge	the	exposure	to	price	volatility	inherent	in	their	purchased	power,	fuel, and	gas	purchased	for	resale	costs	that	are	recovered	from	customers.

Entergy's	commodity	and	financial	 instruments	are	exposed	 to	credit	risk.	 	Credit	risk	 is	 the	risk	of	 loss	from	nonperformance	by suppliers,	customers,	or	financial	counterparties	to	a	contract	or	agreement.		Entergy	is	also	exposed	to	a	potential	demand	on	liquidity	due	to credit	support	requirements	within	its	supply	or	sales	agreements.

# Commodity	Price	Risk

# Power	Generation

As	a	wholesale	generator,	Entergy	Wholesale	Commodities's	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.		Entergy Wholesale	Commodities	enters	into	forward	contracts	with	its	customers	and	sells	energy	in	the	day	ahead	or	spot	markets.		In	addition	to	selling the	energy	produced	by	its	plants,	Entergy	Wholesale	Commodities	sells	unforced	capacity,	which	allows	load-serving	entities	to	meet	specified reserve	and	related	requirements	placed	on	them	by	the	ISOs	in	their	respective	areas.		Entergy	Wholesale	Commodities's	forward	physical	power contracts	consist	of	contracts	 to	sell	energy	only,	contracts	 to	sell	capacity	only,	and	bundled	contracts	 in	which	 it	sells	both	capacity	and energy.		While	the	terminology	and	payment	mechanics	vary	in	these	contracts,	each	of	these	types	of	contracts	requires	Entergy	Wholesale Commodities	to	deliver	MWh	of	energy,	make	capacity	available,	or	both.		In	addition	to	its	forward	physical	power	contracts,	Entergy	Wholesale Commodities	also	uses	a	combination	of	financial	contracts,	including	swaps,	collars,	put	and/or	call	options,	to	manage	forward	commodity	price risk.		Certain	hedge	volumes	have	price	downside	and	upside	relative	to	market	price	movement.		The	contracted	minimum,	expected	value,	and sensitivity	are	provided	to	show	potential	variations.		The	sensitivities	may	not	reflect	the	total	maximum	upside	potential	from	higher	market prices.		The	information	contained	in	the	table	below	represents	projections	at	a	point	in	time	and	will	vary	over	time	based	on	numerous	factors, such	as	future	market	prices,	contracting	activities,	and	generation.		Following	is	a	summary	of	Entergy	Wholesale	Commodities's	current	forward capacity	and	generation	contracts	as	well	as	total	revenue	projections	based	on	market	prices	as	of	December	31,	2013.

# Entergy	Wholesale	Commodities	Nuclear	Portfolio

|  | 2014 | 2015 | 2016 | 2017 | 2018 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy |  |  |  |  |  |
| Percent\tof\tplanned\tgeneration\tunder\tcontract\t(a): |  |  |  |  |  |
| Unit-contingent\t(b) | 25% | 15% | 16% | 14% | 14% |
| Unit-contingent\twith\tavailability\tguarantees\t(c) | 16% | 15% | 14% | 15% | 3% |
| Firm\tLD\t(d) | 59% | 44% | 10% | —% | —% |
| Offsetting\tpositions\t(e) | (26%) | —% | —% | —% | —% |
| Total | 74% | 74% | 40% | 29% | 17% |
| Planned\tgeneration\t(TWh)\t(f)\t(g) | 39 | 35 | 36 | 35 | 35 |
| Average\trevenue\tper\tMWh\ton\tcontracted\tvolumes: |  |  |  |  |  |
| Minimum | $47 | $43 | $47 | $51 | $56 |
| Expected\tbased\ton\tmarket\tprices\tas\tof\tDec.\t31,\t2013 | $50 | $49 | $49 | $52 | $56 |
| Sensitivity:\t-/+\t$10\tper\tMWh\tmarket\tprice\tchange | $48-$52 | $45-$54 | $47-$51 | $51-$54 | $56 |
| Capacity |  |  |  |  |  |
| Percent\tof\tcapacity\tsold\tforward\t(h): |  |  |  |  |  |
| Bundled\tcapacity\tand\tenergy\tcontracts\t(i) | 16% | 18% | 18% | 18% | 18% |
| Capacity\tcontracts\t(j) | 28% | 15% | 15% | 6% | —% |
| Total | 44% | 33% | 33% | 24% | 18% |
| Planned\tnet\tMW\tin\toperation\t(g) | 5,011 | 4,406 | 4,406 | 4,406 | 4,406 |
| Average\trevenue\tunder\tcontract\tper\tkW\tper\tmonth\n\t\t\t\t(applies\tto\tcapacity\tcontracts\tonly) | $2.7 | $3.2 | $3.4 | $3.6 | $— |
| Total\tNuclear\tEnergy\tand\tCapacity\tRevenues\t(m) |  |  |  |  |  |
| Expected\tsold\tand\tmarket\ttotal\trevenue\tper\tMWh | $55 | $50 | $49 | $50 | $51 |
| Sensitivity:\t-/+\t$10\tper\tMWh\tmarket\tprice\tchange | $51-$59 | $45-$56 | $42-$56 | $43-$57 | $43-$59 |

|  | 2014 | 2015 | 2016 | 2017 | 2018 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy |  |  |  |  |  |
| Percent\tof\tplanned\tgeneration\tunder\tcontract\t(a): |  |  |  |  |  |
| Cost-based\tcontracts\t(k) | 33% | 35% | 34% | 32% | 33% |
| Firm\tLD\t(d) | 6% | 6% | 6% | 6% | 6% |
| Total | 39% | 41% | 40% | 38% | 39% |
| Planned\tgeneration\t(TWh)\t(f)\t(l) | 6 | 6 | 6 | 6 | 6 |
| Capacity |  |  |  |  |  |
| Percent\tof\tcapacity\tsold\tforward\t(h): |  |  |  |  |  |
| Cost-based\tcontracts\t(k) | 24% | 24% | 24% | 26% | 26% |
| Bundled\tcapacity\tand\tenergy\tcontracts\t(i) | 8% | 8% | 8% | 8% | 8% |
| Capacity\tcontracts\t(j) | 53% | 53% | 53% | 23% | —% |
| Total | 85% | 85% | 85% | 57% | 34% |
| Planned\tnet\tMW\tin\toperation\t(l) | 1,052 | 1,052 | 1,052 | 977 | 977 |

(a) Percent	of	planned	generation	output	sold	or	purchased	forward	under	contracts,	forward	physical	contracts,	forward	financial	contracts, or	options	that	mitigate	price	uncertainty	that	may	require	regulatory	approval	or	approval	of	transmission	rights.

(b) Transaction	under	which	power	is	supplied	from	a	specific	generation	asset;	if	the	asset	is	not	operating,	seller	is	generally	not	liable	to buyer	for	any	damages.

(c) A	sale	of	power	on	a	unit-contingent	basis	coupled	with	a	guarantee	of	availability	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.	All	of	Entergy's	outstanding	guarantees	of	availability	provide	for	dollar limits	on	Entergy's	maximum	liability	under	such	guarantees.

(d) Transaction	that	requires	receipt	or	delivery	of	energy	at	a	specified	delivery	point	(usually	at	a	market	hub	not	associated	with	a	specific asset)	or	settles	financially	on	notional	quantities;	if	a	party	fails	to	deliver	or	receive	energy,	defaulting	party	must	compensate	the	other party	as	specified	in	the	contract,	a	portion	of	which	may	be	capped	through	the	use	of	risk	management	products.

(e) Transactions	for	the	purchase	of	energy,	generally	to	offset	a	firm	LD	transaction.

(f) Amount	of	output	expected	to	be	generated	by	Entergy	Wholesale	Commodities	resources	considering	plant	operating	characteristics, outage	schedules,	and	expected	market	conditions	that	affect	dispatch.

(g) Assumes	NRC	license	renewals	for	plants	whose	current	licenses	expire	within	five	years.	Assumes	shutdown	of	Vermont	Yankee	in	the fourth	quarter	2014	and	uninterrupted	normal	operation	at	remaining	plants.	NRC	license	renewal	applications	are	in	process	for	two units,	as	follows	(with	current	license	expirations	in	parentheses):	Indian	Point	2	(September	2013	and	now	operating	under	its	period	of extended	operations)	and	Indian	Point	3	(December	2015).	For	a	discussion	regarding	the	shutdown	of	the	Vermont	Yankee	plant,	see "Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial	statements.	For	a	discussion	regarding	the	license	renewals	for	Indian Point	2	and	Indian	Point	3,	see	"Entergy	Wholesale	Commodities	Authorizations	to	Operate	Its	Nuclear	Power	Plants "	above.

(h) Percent	of	planned	qualified	capacity	sold	to	mitigate	price	uncertainty	under	physical	or	financial	transactions.

(i) A	contract	for	the	sale	of	installed	capacity	and	related	energy,	priced	per	megawatt-hour	sold.

(j) A	contract	for	the	sale	of	an	installed	capacity	product	in	a	regional	market.

(k) Contracts	priced	in	accordance	with	cost-based	rates,	a	ratemaking	concept	used	for	the	design	and	development	of	rate	schedules	to ensure	that	the	filed	rate	schedules	recover	only	the	cost	of	providing	the	service;	these	contracts	are	on	owned	non-utility	resources located	within	Entergy's	Utility	service	area	and	were	executed	prior	to	receiving	market-based	authority	under	MISO.	The	percentage sold	assumes	approval	of	long-term	transmission	rights.

(l) Non-nuclear	planned	generation	and	net	MW	in	operation	include	purchases	from	affiliated	and	non-affiliated	counterparties	under	long- term	contracts	and	exclude	energy	and	capacity	from	Entergy	Wholesale	Commodities's	wind	investment	and	from	the	544	MW	Ritchie plant	that	Entergy	retired	in	November	2013.	The	decrease	in	planned	net	MW	in	operation	beginning	in	2017	is	due	to	the	expiration	of	a non-affiliated	75	MW	contract.

(m) Includes	expectations	for	the	new	New	York	ISO	Lower	Hudson	Valley	capacity	zone	starting	in	May	2014.

Entergy	estimates	that	a	positive	$10	per	MWh	change	in	the	annual	average	energy	price	in	the	markets	in	which	the	Entergy	Wholesale Commodities	 nuclear	 business	 sells	 power,	 based	 on	 the	 respective	 year-end	 market	 conditions,	 planned	 generation	 volumes,	 and	 hedged positions,	would	have	a	corresponding	effect	on	pre-tax	income	of	$240	million	in	2014	and	would	have	had	a	corresponding	effect	on	pre-tax income	of	$125	million	in	2013.	A	negative	$10	per	MWh	change	in	the	annual	average	energy	price	in	the	markets	based	on	the	respective	year- end	market	conditions,	planned	generation	volumes,	and	hedged	positions,	would	have	a	corresponding	effect	on	pre-tax	income	of	($91)	million in	2014	and	would	have	had	a	corresponding	effect	on	pre-tax	income	of	($76)	million	in	2013.

Entergy's	purchase	of	the	FitzPatrick	and	Indian	Point	3	plants	from	NYPA	included	value	sharing	agreements	with	NYPA.		In	October 2007,	NYPA	and	the	subsidiaries	that	own	the	FitzPatrick	and	Indian	Point	3	plants	amended	and	restated	the	value	sharing	agreements	to	clarify and	amend	certain	provisions	of	the	original	terms.		Under	the

amended	value	sharing	agreements,	the	Entergy	subsidiaries	agreed	to	make	annual	payments	to	NYPA	based	on	the	generation	output	of	the Indian	Point	3	and	FitzPatrick	plants	from	January	2007	through	December	2014.		Entergy	subsidiaries	will	pay	NYPA	$6.59	per	MWh	for	power sold	from	Indian	Point	3,	up	to	an	annual	cap	of	$48	million,	and	$3.91	per	MWh	for	power	sold	from	FitzPatrick,	up	to	an	annual	cap	of	$24 million.		The	annual	payment	for	each	year's	output	is	due	by	January	15	of	the	following	year.		Entergy	will	record	the	liability	for	payments	to NYPA	as	power	is	generated	and	sold	by	Indian	Point	3	and	FitzPatrick.		In	2013,	2012,	and	2011,	Entergy	Wholesale	Commodities	recorded	a liability	of	approximately	$72	million	for	generation	during	each	of	those	years.		An	amount	equal	to	the	liability	was	recorded	each	year	to	the plant	asset	account	as	contingent	purchase	price	consideration	for	the	plants.		This	amount	will	be	depreciated	over	the	expected	remaining	useful life	of	the	plants.

Some	of	the	agreements	to	sell	the	power	produced	by	Entergy	Wholesale	Commodities	power	plants	contain	provisions	that	require	an Entergy	subsidiary	to	provide	collateral	to	secure	its	obligations	under	the	agreements.		The	Entergy	subsidiary	is	required	to	provide	collateral based	upon	the	difference	between	the	current	market	and	contracted	power	prices	in	the	regions	where	Entergy	Wholesale	Commodities	sells power.		The	primary	form	of	collateral	to	satisfy	these	requirements	is	an	Entergy	Corporation	guaranty.		Cash	and	letters	of	credit	are	also acceptable	forms	of	collateral.		At	December	31,	2013,	based	on	power	prices	at	that	time,	Entergy	had	liquidity	exposure	of	$274	million	under the	guarantees	in	place	supporting	Entergy	Wholesale	Commodities	transactions	and	$104	million	of	posted	cash	collateral.		As	of	December	31, 2013,	the	liquidity	exposure	associated	with	Entergy	Wholesale	Commodities	assurance	requirements,	including	return	of	previously	posted collateral	from	counterparties,	would	 increase	by	$123	million	for	a	$1	per	MMBtu	 increase	 in	gas	prices	 in	both	 the	short-and	 long-term markets.		In	the	event	of	a	decrease	in	Entergy	Corporation's	credit	rating	to	below	investment	grade,	based	on	power	prices	as	of	December	31, 2013,	 Entergy	 would	 have	 been	 required	 to	 provide	 approximately	 $113	 million	 of	 additional	 cash	 or	 letters	 of	 credit	 under	 some	 of	 the agreements.

As	of	December	31,	2013,	substantially	all	of	the	counterparties	or	their	guarantors	for	100%	of	the	planned	energy	output	under	contract for	Entergy	Wholesale	Commodities	nuclear	plants	through	2017	have	public	investment	grade	credit	ratings.

# Nuclear	Matters

After	the	nuclear	incident	in	Japan	resulting	from	the	March	2011	earthquake	and	tsunami,	the	NRC	established	a	task	force	to	conduct	a review	of	processes	and	regulations	relating	to	nuclear	facilities	in	the	United	States.		The	task	force	issued	a	near-term	(90-day)	report	in	July 2011	that	made	initial	recommendations,	which	were	subsequently	refined	and	prioritized	after	input	from	stakeholders.		The	task	force	then issued	a	second	report	in	September	2011.		Based	upon	the	task	force's	recommendations,	the	NRC	issued	three	orders	effective	on	March	12, 2012.		The	three	orders	require	U.S.	nuclear	operators	to	undertake	plant	modifications	and	perform	additional	analyses	that	will,	among	other things,	result	 in	 increased	operating	and	capital	costs	associated	with	operating	nuclear	plants.	 	The	NRC,	with	 input	from	 the	 industry,	 is continuing	to	determine	the	specific	actions	required	by	the	orders	and	an	estimate	of	the	full	amount	of	the	increased	costs	cannot	be	made	at	this time.

With	the	issuance	of	the	three	orders,	the	NRC	also	provided	members	of	the	public	an	opportunity	to	request	a	hearing.		Two	established anti-nuclear	groups,	Pilgrim	Watch	and	Beyond	Nuclear,	filed	hearing	requests,	focused	on	Pilgrim,	regarding	two	of	the	three	orders.		These requests	sought	to	have	the	NRC	impose	expanded	remedial	requirements	to	address	the	issues	raised	by	the	NRC's	orders.		Beyond	Nuclear subsequently	withdrew	its	hearing	request	and	the	NRC's	ASLB	denied	Pilgrim	Watch's	hearing	request.		Pilgrim	Watch	appealed	the	Board's decision	to	the	NRC,	which	affirmed	the	Board's	decision	in	January	2013.

In	June	2012	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit	vacated	the	NRC's	2010	update	to	its	Waste	Confidence	Decision,	which	had found	generically	that	a	permanent	geologic	repository	to	store	spent	nuclear	fuel	would	be	available	when	necessary	and	that	spent	nuclear	fuel could	be	stored	at	nuclear	reactor	sites	in	the	interim	without	significant	environmental	effects,	and	remanded	the	case	for	further	proceedings.	The court	concluded	that	the	NRC	had	not	satisfied	the	requirements	of	the	National	Environmental	Policy	Act	(NEPA)	when	it	considered

environmental	effects	in	reaching	these	conclusions.	The	Waste	Confidence	Decision	has	been	relied	upon	by	NRC	license	renewal	applicants	to address	some	of	the	issues	that	NEPA	requires	the	NRC	to	address	before	it	issues	a	renewed	license.	Certain	nuclear	opponents	filed	requests with	the	NRC	asking	it	to	address	the	issues	raised	by	the	court's	decision	in	the	license	renewal	proceedings	for	a	number	of	nuclear	plants including	Grand	Gulf	and	Indian	Point	2	and	3.	In	August	2012	the	NRC	issued	an	order	stating	that	it	will	not	issue	final	licenses	dependent	upon the	Waste	Confidence	Decision	until	the	D.C.	Circuit's	remand	is	addressed,	but	also	stating	that	licensing	reviews	and	proceedings	should continue	to	move	forward.	In	September	2012	the	NRC	directed	its	staff	to	develop	a	revised	Waste	Confidence	Decision	within	24	months.	In September	2013	the	NRC	published	a	draft	of	the	revised	Waste	Confidence	rule	and	supporting	draft	environmental	impact	statement	for	public comment.	The	NRC's	current	schedule	calls	for	publication	of	a	final	rule	and	environmental	impact	statement	no	later	than	October	2014	with	the effective	date	30	days	after	publication.

The	nuclear	industry	continues	to	address	susceptibility	to	stress	corrosion	cracking	of	certain	materials	within	the	reactor	coolant	system. The	issue	is	applicable	at	all	nuclear	units	to	varying	degrees	and	is	managed	in	accordance	with	industry	standard	practices	and	guidelines	which include	in-service	examinations,	replacements,	and	mitigation	strategies.		Developments	in	the	industry	or	identification	of	issues	at	the	nuclear units	could	require	unanticipated	remediation	efforts	that	cannot	be	quantified	in	advance.

# 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	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	these	assumptions	and	measurements	could produce	estimates	that	would	have	a	material	effect	on	the	presentation	of	Entergy's	financial	position,	results	of	operations,	or	cash	flows.

# Nuclear	Decommissioning	Costs

Entergy	 subsidiaries	 own	 nuclear	 generation	 facilities	 in	 both	 the	 Utility	 and	 Entergy	Wholesale	 Commodities	 operating	 segments. Regulations	require	Entergy	subsidiaries	to	decommission	the	nuclear	power	plants	after	each	facility	is	taken	out	of	service,	and	cash	is	deposited in	trust	funds	during	the	facilities'	operating	lives	in	order	to	provide	for	this	obligation.	Entergy	conducts	periodic	decommissioning	cost	studies to	estimate	 the	costs	 that	will	be	 incurred	 to	decommission	 the	facilities.	The	following	key	assumptions	have	a	significant	effect	on	 these estimates.

•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.	A	high	probability	that	the	plant's	license	will	be	renewed	and	the	plant	will	operate	for some	time	beyond	the	original	license	term	has	been	assumed	for	purposes	of	calculating	the	decommissioning	liability	for	a	number	of Entergy's	nuclear	units.	Second,	an	assumption	must	be	made	whether	all	decommissioning	activity	will	proceed	immediately	upon	plant retirement,	or	whether	the	plant	will	be	placed	in	SAFSTOR	status.	SAFSTOR	is	decommissioning	a	facility	by	placing	it	in	a	safe,	stable condition	that	is	maintained	until	it	is	subsequently	decontaminated	and	dismantled	to	levels	that	permit	license	termination,	normally within	60	years	from	permanent	cessation	of	operations.	A	change	of	assumption	regarding	either	the	probability	of	license	renewal,	the period	of	continued	operation,	or	the	use	of	a	SAFSTOR	period	can	change	the	present	value	of	the	asset	retirement	obligations. •Cost	Escalation	Factors	-	Entergy's	current	decommissioning	cost	studies	include	an	assumption	that	decommissioning	costs	will	escalate over	present	cost	levels	by	factors	ranging	from	approximately	2%	to	3.25%.	A	50	basis	point	change	in	this	assumption	could	change	the estimated	present	value	of	the	decommissioning	liabilities	by	approximately	9%	to	18%.	The	timing	assumption	influences	the	effect	of	a

change	in	the	estimated	inflation	or	cost	escalation	rate	because	the	effect	increases	with	the	length	of	time	assumed	before decommissioning	activity	ends.

•Spent	Fuel	Disposal	-	Federal	law	requires	the	DOE	to	provide	for	the	permanent	storage	of	spent	nuclear	fuel,	and	legislation	has	been passed	by	Congress	to	develop	a	repository	at	Yucca	Mountain,	Nevada.	The	current	Presidential	administration,	however,	has	defunded the	Yucca	Mountain	project.	The	DOE	has	not	yet	begun	accepting	spent	nuclear	fuel	and	is	in	non-compliance	with	federal	law.	The DOE	continues	to	delay	meeting	its	obligation	and	Entergy's	nuclear	plant	owners	are	continuing	to	pursue	damages	claims	against	the DOE	for	its	failure	to	provide	timely	spent	fuel	storage.	Until	a	federal	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	during	the	decommissioning	period	can	have	a	significant	effect	(as much	as	an	average	of	20%	to	30%	of	total	estimated	decommissioning	costs).	Entergy's	decommissioning	studies	include	cost	estimates for	spent	fuel	storage,	when	applicable.	These	estimates	could	change	in	the	future,	however,	based	on	the	timing	when	the	DOE	begins	to fulfill	its	obligation	to	receive	and	store	spent	nuclear	fuel.

•Technology	and	Regulation	-	Over	the	past	several	years,	more	practical	experience	with	the	actual	decommissioning	of	nuclear	facilities has	been	gained	and	that	experience	has	been	incorporated	into	Entergy's	current	decommissioning	cost	estimates.	Given	the	long duration	of	decommissioning	projects,	additional	experience,	including	technological	advancements	in	decommissioning,	could	occur, however,	and	affect	current	cost	estimates.	In	addition,	if	regulations	regarding	nuclear	decommissioning	were	to	change,	this	could significantly	affect	cost	estimates.

•Interest	Rates	-	The	estimated	decommissioning	costs	that	are	the	basis	for	the	recorded	decommissioning	liability	are	discounted	to present	value	using	a	credit-adjusted	risk-free	rate.	When	the	decommissioning	liability	is	revised,	increases	in	cash	flows	are	discounted using	a	current	credit-adjusted	risk-free	rate.	Decreases	in	estimated	cash	flows	are	discounted	using	the	previously-used	credit-adjusted risk-free	rate.	Therefore,	to	the	extent	that	one	of	the	factors	noted	above	results	in	a	significant	increase	in	estimated	cash	flows,	current interest	rates	will	affect	the	calculation	of	the	present	value	of	the	additional	decommissioning	liability.

				Future	revisions	of	estimated	decommissioning	costs	that	decrease	the	liability	also	result	in	a	decrease	in	the	asset	retirement	cost	asset.	For	the non-rate-regulated	portions	of	Entergy's	business,	these	reductions	will	immediately	increase	net	income	if	the	reduction	of	the	liability	exceeds the	amount	of	the	undepreciated	asset	retirement	cost	asset	at	the	date	of	the	revision.	Future	revisions	of	estimated	decommissioning	costs	that increase	the	liability	also	result	in	an	increase	in	the	asset	retirement	cost	asset,	which	is	then	depreciated	over	the	asset's	remaining	economic	life. For	a	plant	that	is	shutdown,	or	is	nearing	its	shutdown	date,	however,	for	the	non-rate-regulated	portions	of	Entergy's	business	the	increase	in	the liability	will	immediately	decrease	net	income.

In	the	first	quarter	2013,	Entergy	Wholesale	Commodities	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	a	nuclear site	as	a	result	of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$46.6	million	reduction	in	the	decommissioning	cost liability,	along	with	a	corresponding	reduction	in	the	related	asset	retirement	cost	asset.

In	the	fourth	quarter	2013,	System	Energy	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Grand	Gulf	as	a	result	of a	revised	decommissioning	cost	study.		The	revised	estimate	resulted	in	a	$102.3	million	increase	in	its	decommissioning	liability,	along	with	a corresponding	increase	in	the	related	asset	retirement	cost	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

In	the	fourth	quarter	2013,	Entergy	Louisiana	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Waterford	3	as	a	result of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$39.4	million	increase	in	its	decommissioning	cost	liability,	along with	a	corresponding	increase	in	the	related	asset	retirement	cost	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

In	the	third	quarter	2013,	Entergy	Wholesale	Commodities	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Vermont Yankee	as	a	result	of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$58	million	increase	in	the	decommissioning	cost liability,	along	with	a	corresponding	increase	in	the	related	asset	retirement	cost	asset.	The	increase	in	the	estimated	decommissioning	cost liability	resulted	from	the	change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows	due	to	the	decision	to	cease	operations	of	the plant.	The	asset	retirement	cost	asset	was	included	in	the	carrying	value	used	to	write	down	Vermont	Yankee	and	related	assets	to	their	fair	values in	third	quarter	2013.		See	Note	1	to	the	financial	statements	for	further	discussion	of	the	resulting	impairment	charge	recorded	in	third	quarter 2013.

In	 the	fourth	quarter	2013,	Entergy	Wholesale	Commodities	recorded	a	revision	 to	 its	estimated	decommissioning	cost	 liability	for Vermont	Yankee.	As	a	result	of	a	settlement	agreement	regarding	the	remaining	operation	and	decommissioning	of	Vermont	Yankee,	Entergy reassessed	its	assumptions	regarding	the	timing	of	decommissioning	cash	flows.	The	reassessment	resulted	in	a	$27.2	million	increase	in	the decommissioning	 cost	 liability	 and	 a	 corresponding	 impairment	 charge.	See	Note	1	to	the	financial	statements	for	further	discussion	of	the Vermont	Yankee	plant.

In	the	second	quarter	2012,	Entergy	Louisiana	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Waterford	3	as	a result	of	a	revised	decommissioning	cost	study.		The	revised	estimate	resulted	in	a	$48.9	million	increase	in	its	decommissioning	cost	liability, along	with	a	corresponding	increase	in	the	related	asset	retirement	costs	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

In	the	second	quarter	2012,	Entergy	Wholesale	Commodities	recorded	a	reduction	of	$60.6	million	in	the	estimated	decommissioning	cost liability	for	a	plant	as	a	result	of	a	revised	decommissioning	cost	study.		The	revised	estimate	resulted	in	a	credit	to	decommissioning	expense	of $49	million,	reflecting	the	excess	of	the	reduction	in	the	liability	over	the	amount	of	the	undepreciated	asset	retirement	costs	asset.

In	the	fourth	quarter	of	2011,	Entergy	Wholesale	Commodities	recorded	a	reduction	of	$34.1	million	in	the	decommissioning	cost	liability for	a	plant	as	a	result	of	a	revised	decommissioning	cost	study	obtained	to	comply	with	a	state	regulatory	requirement.		The	revised	cost	study resulted	in	a	change	in	the	undiscounted	cash	flows	and	a	credit	to	decommissioning	expense	of	$34.1	million,	reflecting	the	excess	of	the reduction	in	the	liability	over	the	amount	of	undepreciated	assets.

# Unbilled	Revenue

As	discussed	in	Note	1	to	the	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.	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.

# Impairment	of	Long-lived	Assets	and	Trust	Fund	Investments

Entergy	has	significant	investments	in	long-lived	assets	in	both	of	its	operating	segments,	and	Entergy	evaluates	these	assets	against	the market	economics	and	under	the	accounting	rules	for	impairment	when	there	are	indications	that	impairments	may	exist.		This	evaluation	involves a	 significant	 degree	 of	 estimation	 and	 uncertainty.	 In	 the	 Entergy	 Wholesale	 Commodities	 business,	 Entergy's	 investments	 in	 merchant generation	assets	are	subject	to	impairment	if	adverse	market	conditions	arise,	if	a	unit	plans	to	cease,	or	ceases,	operation	sooner	than	expected, or	for	certain	nuclear	units	if	their	operating	licenses	are	not	renewed.

If	an	asset	 is	considered	held	for	use,	and	Entergy	concludes	 that	an	 impairment	analysis	has	been	 triggered	under	 the	accounting standards,	the	sum	of	the	expected	undiscounted	future	cash	flows	from	the	asset	are	compared	to	the	asset's	carrying	value.		The	carrying	value of	the	asset	includes	any	capitalized	asset	retirement	cost	associated	with	the	decommissioning	liability,	therefore	changes	in	assumptions	that affect	the	decommissioning	liability	can	increase	or	decrease	the	carrying	value	of	the	asset	subject	to	impairment.		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	considered	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	can	be	very	volatile.		This	volatility	increases	the	imprecision	inherent	in	the long-term	forecasts	of	commodity	prices	that	are	a	key	determinant	of	estimated	future	cash	flows.

•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,	these	transactions	are	relatively	infrequent,	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	effect	on	operations	could	cause	a	significant	change	in	these	assumptions.

•Timing	-	Entergy	currently	assumes,	for	some	of	its	nuclear	units,	that	the	plant's	license	will	be	renewed.		A	change	in	that	assumption could	have	a	significant	effect	on	the	expected	future	cash	flows	and	result	in	a	significant	effect	on	operations.

For	additional	discussion	regarding	the	planned	shutdown	of	the	Vermont	Yankee	plant,	see	" Impairment	of	Long-Lived	Assets"	in Note	1	to	the	financial	statements.

Entergy	evaluates	investment	securities	with	unrealized	losses	at	the	end	of	each	period	to	determine	whether	an	other-than-temporary impairment	has	occurred.		The	assessment	of	whether	an	investment	in	a	debt	security	has	suffered	an	other-than-temporary	impairment	is	based on	whether	Entergy	has	the	intent	to	sell	or	more	likely	than	not	will	be	required	to	sell	the	debt	security	before	recovery	of	its	amortized	costs.		If Entergy	does	not	expect	to	recover	the	entire	amortized	cost	basis	of	the	debt	security,	an	other-than-temporary-impairment	is	considered	to	have occurred	and	it	is	measured	by	the	present	value	of	cash	flows	expected	to	be	collected	less	the	amortized	cost	basis	(credit	loss).		Entergy	did	not have	any	material	other	than	temporary	impairments	relating	to	credit	losses	on	debt	securities	in	2013,	2012,	or	2011.		The	assessment	of	whether an	investment	in	an	equity	security	has	suffered	an	other	than	temporary	impairment	is	based	on	a	number	of	factors	including,	first,	whether Entergy	has	the	ability	and	intent	to	hold	the	investment	to	recover	its	value,	the	duration	and	severity	of	any	losses,	and,	then,	whether	it	is expected	that	the	investment	will	recover	its	value	within	a	reasonable	period	of	time.		Entergy's	trusts	are	managed	by	third	parties	who	operate in	accordance	with	agreements	that	define	investment	guidelines	and	place	restrictions	on	the	purchases	and	sales	of	investments.		As	discussed	in Note	1	to	the	financial	statements,	unrealized	losses	on	equity	securities	that	are	considered	other-than-temporarily	impaired	are	recorded	in earnings	for	Entergy	Wholesale	Commodities.		Entergy	Wholesale	Commodities	did	not	record	material	charges	to	other	income	in	2013,	2012, or	2011	resulting	from	the	recognition	of	other-than-temporary	impairment	of	equity	securities	held	in	its	decommissioning	trust	funds.

# Qualified	Pension	and	Other	Postretirement	Benefits

Entergy	sponsors	qualified,	defined	benefit	pension	plans	that	cover	substantially	all	employees.		Additionally,	Entergy	currently	provides postretirement	 health	 care	 and	 life	 insurance	 benefits	 for	 substantially	 all	 employees	 who	 reach	 retirement	 age	 and	 meet	 certain	 eligibility requirements	while	still	working	for	Entergy.

In	December	2013,	Entergy	announced	that	employees	hired	or	rehired	after	June	30,	2014,	will	participate	in	a	new	cash	balance	defined benefit	pension	plan	and	will	be	eligible	to	receive	an	enhanced	employer	matching	contribution	under	one	of	the	Entergy	defined	contribution plans,	rather	than	the	current	final	average	pay	defined	benefit	pension	plan	and	employer	matching	contribution.	These	changes	are	prospective and	 have	 no	 effect	 on	 the	 December	 31,	 2013	pension	obligation.	Additionally,	at	 the	same	 time,	Entergy	announced	changes	 to	 its	other postretirement	benefits	which	include,	among	other	things,	elimination	of	other	postretirement	benefits	for	employees	hired	or	rehired	after	June 30,	2014	and	setting	a	dollar	limit	cap	on	Entergy's	contribution	to	retiree	medical	costs,	effective	2019,	for	those	employees	who	commence	their Entergy	retirement	benefits	on	or	after	January	1,	2015.	In	accordance	with	accounting	standards,	certain	of	the	other	postretirement	benefit changes	have	been	reflected	in	the	December	31,	2013	other	postretirement	obligation.	The	changes	affecting	active	bargaining	unit	employees will	be	negotiated	with	their	unions	prior	to	implementation,	where	necessary,	and	to	the	extent	required	by	law.

Entergy's	reported	costs	of	providing	these	benefits,	as	described	in	Note	11	to	the	financial	statements,	are	affected	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	Utility	and	Entergy	Wholesale	Commodities	segments.

# Assumptions

Key	actuarial	assumptions	utilized	in	determining	these	costs	include:

•Discount	rates	used	in	determining	future	benefit	obligations;

•Projected	health	care	cost	trend	rates;

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

•Rate	of	increase	in	future	compensation	levels;

•Retirement	rates;	and

•Mortality	rates.

Entergy	reviews	the	first	four	assumptions	listed	above	on	an	annual	basis	and	adjusts	them	as	necessary.	 	The	falling	interest	rate environment	over	the	past	few	years	and	volatility	in	the	financial	equity	markets	have	affected	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.

The	retirement	and	mortality	rate	assumptions	are	reviewed	every	three-to-five	years	as	part	of	an	actuarial	study	that	compares	these assumptions	to	the	actual	experience	of	the	pension	and	other	postretirement	plans.		The	2011	actuarial	study	reviewed	plan	experience	from	2007 through	2010.		As	a	result	of	the	2011	actuarial	study,	changes	were	made	to	reflect	the	expectation	that	participants	have	longer	life	expectancies and	different	retirement	patterns	than	previously	assumed.		These	changes	are	reflected	in	the	December	31,	2013,	December	31,	2012	and December	31,	2011	financial	disclosures.

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,	the	discount	rates	used	to	calculate	its 2013	qualified	pension	benefit	obligation	and	2014	qualified	pension	cost	ranged	from	5.04%	to	5.26%	for	its	specific	pension	plans	(5.14% combined	rate	for	all	pension	plans).	The	discount	rates	used	to	calculate	its	2012	qualified	pension	benefit	obligation	and	2013	qualified	pension cost	ranged	from	4.31%	to	4.50%		for	its	specific	pension	plans	(4.36%	combined	rate	for	all	pension	plans).			The	discount	rates	used	to	calculate its	2011	qualified	pension	benefit	obligation	and	2012	qualified	pension	cost	ranged	from	5.1%	to	5.2%	for	its	specific	pension	plans	(5.1% combined	rate	for	all	pension	plans).	 	The	discount	rate	used	 to	calculate	 its	2013	other	postretirement	benefit	obligation	and	2014	other postretirement	 benefit	 cost	 was	 5.05%.The	 discount	 rate	 used	 to	 calculate	 its	 2012	other	postretirement	 benefit	 obligation	 and	 2013	 other postretirement	benefit	cost	was

4.36%.		The	discount	rate	used	to	calculate	its	2011	other	postretirement	benefit	obligation	and	2012	other	postretirement	benefit	cost	was	5.1%.

Entergy	reviews	actual	recent	cost	trends	and	projected	future	trends	in	establishing	health	care	cost	trend	rates.		Based	on	this	review, Entergy's	assumed	health	care	cost	trend	rate	assumption	used	in	measuring	the	December	31,	2013	accumulated	postretirement	benefit	obligation and	2014	postretirement	cost	was	7.25%	for	pre-65	retirees	and	7.00%	for	post-65	retirees	for	2013,	gradually	decreasing	each	successive	year until	it	reaches	4.75%	in	2022	and	beyond	for	both	pre-65	and	post-65	retirees.		Entergy's	assumed	health	care	cost	trend	rate	assumption	used	in measuring	the	December	31,	2012	accumulated	postretirement	benefit	obligation	and	2013	postretirement	cost	was	7.50%	for	pre-65	retirees	and 7.25%	for	post-65	retirees	for	2013,	gradually	decreasing	each	successive	year	until	it	reaches	4.75%	in	2022	and	beyond	for	both	pre-65	and post-65	retirees.	Entergy's	health	care	cost	trend	rate	assumption	used	in	measuring	the	December	31,	2011	accumulated	postretirement	benefit obligation	 and	 2012	 postretirement	 cost	 was	 7.75%	 for	 pre-65	 retirees	 and	 7.5%	 for	 post-65	 retirees	 for	 2012,	 gradually	 decreasing	 each successive	year	until	it	reaches	4.75%	in	2022	and	beyond	for	both	pre-65	and	post-65	retirees.

The	assumed	rate	of	increase	in	future	compensation	levels	used	to	calculate	2013	and	2012	benefit	obligations	was	4.23%.

In	determining	its	expected	long-term	rate	of	return	on	plan	assets	used	in	the	calculation	of	benefit	plan	costs,	Entergy	reviews	past performance,	current	and	expected	future	asset	allocations,	and	capital	market	assumptions	of	its	investment	consultant	and	investment	managers.

Since	2003,	Entergy	has	targeted	an	asset	allocation	for	its	qualified	pension	plan	assets	of	roughly	65%	equity	securities	and	35%	fixed- income	securities.		Entergy	completed	and	adopted	an	optimization	study	in	2011	for	the	pension	assets	that	recommended	that	the	target	asset allocation	adjust	dynamically	over	time,	based	on	the	funded	status	of	the	plan,	from	its	current	allocation	to	an	ultimate	allocation	of	45%	equity and	55%	fixed	income	securities.		The	ultimate	asset	allocation	is	expected	to	be	attained	when	the	plan	is	105%	funded.

The	current	target	allocations	for	both	Entergy's	non-taxable	postretirement	benefit	assets	and	its	taxable	other	postretirement	benefit assets	are	65%	equity	securities	and	35%	fixed-income	securities.		This	takes	into	account	asset	allocation	adjustments	that	were	made	during 2012.

Entergy's	expected	long	term	rate	of	return	on	qualified	pension	assets	used	to	calculate	2013,	2012	and	2011	qualified	pension	costs	was 8.5%	and	will	be	8.5%	for	2014.		Entergy's	expected	long	term	rate	of	return	on	non-taxable	other	postretirement	assets	used	to	calculate	other postretirement	costs	was	8.5%	for	2013,	2012,	and	2011,	and	will	be	8.3%	for	2014.		For	Entergy's	taxable	postretirement	assets,	the	expected long	term	rate	of	return	was	6.5%	for	2013	and	2012,	5.5%	for	2011,	and	will	be	6.5%	in	2014.

Accounting	standards	allow	for	the	deferral	of	prior	service	costs/credits	arising	from	plan	amendments	that	attribute	an	increase	or decrease	in	benefits	to	employee	service	in	prior	periods	and	deferral	of	gains	and	losses	arising	from	the	difference	between	actuarial	estimates and	 actual	 experience.	Prior	service	costs/credits	and	deferred	gains	and	losses	are	then	amortized	into	expense	over	future	periods.	Certain decisions,	 including	 workforce	 reductions	 and	 plan	 amendments,	 may	 significantly	 reduce	 the	 expense	 amortization	 period	 and	 result	 in immediate	recognition	of	certain	previously-deferred	costs	and	gains/losses	in	the	form	of	curtailment	losses	or	gains.	Similarly,	payments	made to	settle	benefit	obligations	can	also	result	in	recognition	in	the	form	of	settlement	losses	or	gains.

# Cost	Sensitivity

The	following	chart	reflects	the	sensitivity	of	qualified	pension	cost	and	qualified	pension	projected	benefit	obligation	to	changes	in certain	actuarial	assumptions	(dollars	in	thousands).

| Discount	rate | (0.25%) | $22,778 | $197,359 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $9,614 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $9,499 | $36,817 |

The	following	chart	reflects	the	sensitivity	of	postretirement	benefit	cost	and	accumulated	postretirement	benefit	obligation	to	changes	in certain	actuarial	assumptions	(dollars	in	thousands).

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit<br>Cost | Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $4,711 | $47,611 |
| Health\tcare\tcost\ttrend | 0.25% | $8,382 | $41,553 |

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

# Accounting	Mechanisms

Accounting	standards	require	an	employer	to	recognize	in	its	balance	sheet	the	funded	status	of	its	benefit	plans.		Refer	to	Note	11	to	the financial	statements	for	a	further	discussion	of	Entergy's	funded	status.

In	accordance	with	pension	accounting	standards,	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	expense	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.

Entergy	calculates	the	expected	return	on	pension	and	other	postretirement	benefit	plan	assets	by	multiplying	the	long-term	expected	rate of	return	on	assets	by	the	market-related	value	(MRV)	of	plan	assets.		Entergy	determines	the	MRV	of	pension	plan	assets	by	calculating	a	value that	uses	a	20-quarter	phase-in	of	the	difference	between	actual	and	expected	returns.		For	other	postretirement	benefit	plan	assets	Entergy	uses fair	value	when	determining	MRV.

# Costs	and	Funding

In	2013,	Entergy's	total	qualified	pension	cost	was	$352	million,	including	a	$16.3	million	curtailment	charge	and	a	$13.1	million	special termination	charge	related	to	workforce	downsizing.		Entergy	anticipates	2014	qualified	pension	cost	to	be	$215.7	million.		Entergy's	pension funding	was	approximately	$163	million	for	2013.		Entergy's	contributions	to	the	pension	trust	are	currently	estimated	to	be	approximately	$400 million	in	2014,	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under	the Moving	Ahead	for	Progress	in	the	21st	Century	Act	(MAP-21).

Minimum	required	funding	calculations	as	determined	under	Pension	Protection	Act	guidance	are	performed	annually	as	of	January	1	of each	year	and	are	based	on	measurements	of	the	assets	and	funding	liabilities	as	measured	at	that	date.		Any	excess	of	the	funding	liability	over	the calculated	fair	market	value	of	assets	results	in	a	funding	shortfall	that,	under	the	Pension	Protection	Act,	must	be	funded	over	a	seven-year	rolling period.		The	Pension	Protection	Act	also	imposes	certain	plan	limitations	if	the	funded	percentage,	which	is	based	on	a	calculated	fair	market values	of	assets	divided	by	funding	liabilities,	does	not	meet	certain	thresholds.	For	funding	purposes,	asset	gains	and	losses	are	smoothed	in	to	the calculated	fair	market	value	of	assets	and	the	funding	liability	is	based	upon	a	weighted	average	24-month	corporate	bond	rate	published	by	the U.S.	Treasury;	therefore,	periodic	changes	in	asset	returns	and	interest	rates	can	affect	funding	shortfalls	and	future	cash	contributions.

MAP-21	became	federal	law	on	July	6,	2012.		Under	the	law,	the	segment	rates	used	to	calculate	funding	liabilities	must	be	within	a corridor	of	the	25-year	average	of	prior	segment	rates.		The	interest	rate	corridor	applies	to	the	determination	of	minimum	funding	requirements and	benefit	restrictions.		The	pension	funding	stabilization	provisions	will	provide	for	a	near-term	reduction	in	minimum	funding	requirements	for single	employer	defined	benefit	plans	in	response	to	the	historically	low	interest	rates	that	existed	when	the	law	was	enacted.		The	law	does	not reduce	contribution	requirements	over	the	long	term,	and	it	is	likely	that	Entergy's	contributions	to	the	pension	trust	will	increase	after	2013.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	in	2013	were	$155.8	million,	including	a	$12.7	million curtailment	charge	related	to	workforce	downsizing.		Entergy	expects	2014	postretirement	health	care	and	life	insurance	benefit	costs	to	be	$50.1 million.	 	 Entergy	 contributed	 $75.7	 million	 to	 its	 postretirement	 plans	 in	 2013.	 	 Entergy's	 current	 estimate	 of	 contributions	 to	 its	 other postretirement	plans	is	approximately	$74.1	million	in	2014.

# Federal	Healthcare	Legislation

The	Patient	Protection	and	Affordable	Care	Act	(PPACA)	became	federal	law	on	March	23,	2010,	and,	on	March	30,	2010,	the	Health Care	and	Education	Reconciliation	Act	of	2010	became	federal	law	and	amended	certain	provisions	of	the	PPACA.		These	new	federal	laws change	the	law	governing	employer-sponsored	group	health	plans,	like	Entergy's	plans,	and	include,	among	other	things,	the	following	significant provisions.

•A	40%	excise	tax	on	per	capita	medical	benefit	costs	that	exceed	certain	thresholds;

•Change	in	coverage	limits	for	dependents;	and

•Elimination	of	lifetime	caps.

The	effect	of	the	PPACA	has	been	reflected	based	on	Entergy's	understanding	of	current	guidance	on	the	rules	and	regulations.	There	are still	many	technical	issues,	however,	that	have	not	been	finalized.		Entergy	will	continue	to	monitor	these	developments	to	determine	the	possible effect	on	Entergy	resulting	from	the	PPACA.		Entergy	is	participating	in	the	programs	currently	provided	for	under	the	PPACA,	such	as	the	early retiree	reinsurance	program,	which	has	provided	for	some	limited	reimbursements	of	certain	claims	for	early	retirees	aged	55	to	64	who	are	not	yet eligible	for	Medicare.

One	provision	of	the	new	law	that	is	effective	in	2013	eliminates	the	federal	income	tax	deduction	for	prescription	drug	expenses	of Medicare	beneficiaries	for	which	the	plan	sponsor	also	receives	the	retiree	drug	subsidy	under	Part	D.		Entergy	receives	subsidy	payments	under the	Medicare	Part	D	plan	and	therefore	in	the	first	quarter	2010	recorded	a	reduction	to	the	deferred	tax	asset	related	to	the	unfunded	other postretirement	benefit	obligation.		The	offset	was	recorded	in	2010	as	a	$16	million	charge	to	income	tax	expense	or,	for	the	Utility,	including each	Registrant	Subsidiary,	as	a	regulatory	asset.

# Other	Contingencies

As	a	company	with	multi-state	utility	operations,	Entergy	is	subject	to	a	number	of	federal	and	state	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	air	emissions,	water	discharges,	solid	and	hazardous	waste, toxic	substances,	protected	species,	and	other	environmental	matters.		Under	these	various	laws	and	regulations,	Entergy	could	incur	substantial costs	to	comply	or	address	any	impacts	to	the	environment.		Entergy	conducts	studies	to	determine	the	extent	of	any	required	remediation	and	has recorded	liabilities	based	upon	its	evaluation	of	the	likelihood	of	loss	and	expected	dollar	amount	for	each	issue.		Additional	sites	or	issues	could be	identified	which	require	environmental	remediation	or	corrective	action	for	which	Entergy	could	be	liable.		The	amounts	of	environmental liabilities	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	impacts,	sites,	issues,	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	or	relevant	state	or	local	authority.

# Litigation

Entergy	is	regularly	named	as	a	defendant	in	a	number	of	lawsuits	involving	employment,	customers,	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	possible,	or	remote	and	records	liabilities	for	cases	that	have	a	probable	likelihood	of	loss	and	the	loss	can	be estimated.		Given	the	environment	in	which	Entergy	operates,	and	the	unpredictable	nature	of	many	of	the	cases	in	which	Entergy	is	named	as	a defendant,	the	ultimate	outcome	of	the	litigation	to	which	Entergy	is	exposed	has	the	potential	to	materially	affect	the	results	of	operations, financial	position,	and	cash	flows	of	Entergy	or	the	Registrant	Subsidiaries.

# Uncertain	Tax	Positions

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	provisions	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.

# New	Accounting	Pronouncements

The	accounting	standard-setting	process,	including	projects	between	the	FASB	and	the	International	Accounting	Standards	Board	(IASB) to	converge	U.S.	GAAP	and	International	Financial	Reporting	Standards,	is	ongoing	and	the	FASB	and	the	IASB	are	each	currently	working	on several	projects	that	have	not	yet	resulted	in	final	pronouncements.		Final	pronouncements	that	result	from	these	projects	could	have	a	material effect	on	Entergy's	future	net	income,	financial	position,	or	cash	flows.

# 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	controls	over financial	reporting	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	training	of	personnel.		This	system	is	also tested	by	a	comprehensive	internal	audit	program.

Entergy	management	assesses	the	design	and	effectiveness	of	Entergy's	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.	 	 The	 original	 1992	 COSO	 Framework	 was	 utilized	 for	 management's	 assessment. 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.

Entergy	Corporation	and	the	Registrant	Subsidiaries'	independent	registered	public	accounting	firm,	Deloitte	&	Touche	LLP,	has	issued an	attestation	report	on	the	effectiveness	of	Entergy's	internal	control	over	financial	reporting	as	of	December	31,	2013,	which	is	included	herein on	pages	436	through	443.

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,	seeks	shareholder	ratification	of	the	appointment,	and	reviews	with	the independent	auditors	the	scope	and	results	of	the	audit	effort.		The	Audit	Committee	also	meets	periodically	with	the	independent	auditors	and	the chief	internal	auditor	without	management	present,	providing	free	access	to	the	Audit	Committee.

Based	on	management's	assessment	of	internal	controls	using	the	original	1992	COSO	criteria,	management	believes	that	Entergy	and each	of	the	Registrant	Subsidiaries	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2013.		Management	further believes	that	this	assessment,	combined	with	the	policies	and	procedures	noted	above,	provides	reasonable	assurance	that	Entergy's	and	each	of the	Registrant	Subsidiaries'	financial	statements	are	fairly	and	accurately	presented	in	accordance	with	generally	accepted	accounting	principles.

Inc.,	Entergy	New	Orleans,	Inc.,	and	Entergy	Texas,	Inc.

# SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands,\tExcept\tPercentages\tand\tPer\tShare\tAmounts) | (In\tThousands,\tExcept\tPercentages\tand\tPer\tShare\tAmounts) | (In\tThousands,\tExcept\tPercentages\tand\tPer\tShare\tAmounts) |  |
| Operating\trevenues | $11,390,947 | $10,302,079 | $11,229,073 | $11,487,577 | $10,745,650 |
| Income\tfrom\tcontinuing\toperations | $730,572 | $868,363 | $1,367,372 | $1,270,305 | $1,251,050 |
| Earnings\tper\tshare\tfrom\tcontinuing\noperations: |  |  |  |  |  |
| Basic | $3.99 | $4.77 | $7.59 | $6.72 | $6.39 |
| Diluted | $3.99 | $4.76 | $7.55 | $6.66 | $6.30 |
| Dividends\tdeclared\tper\tshare | $3.32 | $3.32 | $3.32 | $3.24 | $3.00 |
| Return\ton\tcommon\tequity | 7.56% | 9.33% | 15.43% | 14.61% | 14.85% |
| Book\tvalue\tper\tshare,\tyear-end | $54.00 | $51.72 | $50.81 | $47.53 | $45.54 |
| Total\tassets | $43,406,446 | $43,202,502 | $40,701,699 | $38,685,276 | $37,561,953 |
| Long-term\tobligations\t(a) | $12,382,127 | $12,141,370 | $10,268,645 | $11,575,973 | $11,277,314 |

(a)	Includes	long-term	debt	(excluding	currently	maturing	debt),	noncurrent	capital	lease	obligations,	and	subsidiary	preferred	stock	without sinking	fund	that	is	not	presented	as	equity	on	the	balance	sheet.

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Utility\tElectric\tOperating\nRevenues: |  |  |  |  |  |
| Residential | $3,396 | $3,022 | $3,369 | $3,375 | $2,999 |
| Commercial | 2,415 | 2,174 | 2,333 | 2,317 | 2,184 |
| Industrial | 2,405 | 2,034 | 2,307 | 2,207 | 1,997 |
| Governmental | 218 | 198 | 205 | 212 | 204 |
| Total\tretail | 8,434 | 7,428 | 8,214 | 8,111 | 7,384 |
| Sales\tfor\tresale | 210 | 179 | 216 | 389 | 206 |
| Other | 298 | 264 | 244 | 241 | 290 |
| Total | $8,942 | $7,871 | $8,674 | $8,741 | $7,880 |
| Utility\tBilled\tElectric\tEnergy\tSales\n(GWh): |  |  |  |  |  |
| Residential | 35,169 | 34,664 | 36,684 | 37,465 | 33,626 |
| Commercial | 28,547 | 28,724 | 28,720 | 28,831 | 27,476 |
| Industrial | 41,653 | 41,181 | 40,810 | 38,751 | 35,638 |
| Governmental | 2,412 | 2,435 | 2,474 | 2,463 | 2,408 |
| Total\tretail | 107,781 | 107,004 | 108,688 | 107,510 | 99,148 |
| Sales\tfor\tresale | 3,020 | 3,200 | 4,111 | 4,372 | 4,862 |
| Total | 110,801 | 110,204 | 112,799 | 111,882 | 104,010 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |
| Operating\tRevenues | $2,313 | $2,326 | $2,414 | $2,566 | $2,711 |
| Billed\tElectric\tEnergy\tSales\n(GWh) | 45,127 | 46,178 | 43,497 | 42,934 | 43,743 |

# REPORT	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

# To	the	Board	of	Directors	and	Shareholders	of

# New	Orleans,	Louisiana

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Corporation	and	Subsidiaries	(the	"Corporation")	as	of	December	31, 2013	and	2012,	and	the	related	consolidated	income	statements,	consolidated	statements	of	comprehensive	income,	consolidated	statements	of cash	flows,	and	consolidated	statements	of	changes	in	equity	for	each	of	the	three	years	in	the	period	ended	December	31,	2013.	These	financial statements	are	the	responsibility	of	the	Corporation's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	based on	our	audits.

We	conducted	our	audits	in	accordance	with	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	provide	a	reasonable	basis	for	our	opinion.

In	our	opinion,	such	consolidated	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Corporation	and Subsidiaries	as	of	December	31,	2013	and	2012,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period ended	December	31,	2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

We	have	also	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	the	Corporation's internal	control	over	financial	reporting	as	of	December	31,	2013,	based	on	the	criteria	established	in	Internal	Control	-	Integrated	Framework (1992)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	and	our	report	dated	February	27,	2014	expressed	an unqualified	opinion	on	the	Corporation's	internal	control	over	financial	reporting.

/s/	DELOITTE	&	TOUCHE	LLP

# CONSOLIDATED	INCOME	STATEMENTS

| Electric | $8,942,360 | $7,870,649 | $8,673,517 |
| :--- | :--- | :--- | :--- |
| Natural\tgas | 154,353 | 130,836 | 165,819 |
| Competitive\tbusinesses | 2,294,234 | 2,300,594 | 2,389,737 |
| TOTAL | 11,390,947 | 10,302,079 | 11,229,073 |
| OPERATING\tEXPENSES |  |  |  |
| Operating\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 2,445,818 | 2,036,835 | 2,492,714 |
| Purchased\tpower | 1,554,332 | 1,255,800 | 1,564,967 |
| Nuclear\trefueling\toutage\texpenses | 256,801 | 245,600 | 255,618 |
| Asset\timpairments\tand\trelated\tcharges | 341,537 | 355,524 | — |
| Other\toperation\tand\tmaintenance | 3,331,934 | 3,045,392 | 2,867,758 |
| Decommissioning | 242,104 | 184,760 | 190,595 |
| Taxes\tother\tthan\tincome\ttaxes | 600,350 | 557,298 | 536,026 |
| Depreciation\tand\tamortization | 1,261,044 | 1,144,585 | 1,102,202 |
| Other\tregulatory\tcharges\t-\tnet | 45,597 | 175,104 | 205,959 |
| TOTAL | 10,079,517 | 9,000,898 | 9,215,839 |
| Gain\ton\tsale\tof\tbusiness | 43,569 | — | — |
| OPERATING\tINCOME | 1,354,999 | 1,301,181 | 2,013,234 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 66,053 | 92,759 | 84,305 |
| Interest\tand\tinvestment\tincome | 199,300 | 127,776 | 128,994 |
| Miscellaneous\t-\tnet | (59,762) | (53,214) | (59,271) |
| TOTAL | 205,591 | 167,321 | 154,028 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 629,537 | 606,596 | 551,521 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (25,500) | (37,312) | (37,894) |
| TOTAL | 604,037 | 569,284 | 513,627 |
| INCOME\tBEFORE\tINCOME\tTAXES | 956,553 | 899,218 | 1,653,635 |
| Income\ttaxes | 225,981 | 30,855 | 286,263 |
| CONSOLIDATED\tNET\tINCOME | 730,572 | 868,363 | 1,367,372 |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 18,670 | 21,690 | 20,933 |
| NET\tINCOME\tATTRIBUTABLE\tTO\tENTERGY\tCORPORATION | $711,902 | $846,673 | $1,346,439 |
| Earnings\tper\taverage\tcommon\tshare: |  |  |  |
| Basic | $3.99 | $4.77 | $7.59 |
| Diluted | $3.99 | $4.76 | $7.55 |
| Basic\taverage\tnumber\tof\tcommon\tshares\toutstanding | 178,211,192 | 177,324,813 | 177,430,208 |
| Diluted\taverage\tnumber\tof\tcommon\tshares\toutstanding | 178,570,400 | 177,737,565 | 178,370,695 |

See	Notes	to	Financial	Statements.

# CONSOLIDATED	STATEMENTS	OF	COMPREHENSIVE	INCOME

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| Net\tIncome | $730,572 | $868,363 | $1,367,372 |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Cash\tflow\thedges\tnet\tunrealized\tgain\t(loss) |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t($87,940),\t($55,750),\tand\t$34,411) | (161,682) | (97,591) | 71,239 |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t$220,899,\t($61,223),\tand\t($131,198)) | 302,489 | (91,157) | (223,090) |
| Net\tunrealized\tinvestment\tgains |  |  |  |
| (net\tof\ttax\texpense\tof\t$118,878,\t$61,104,\tand\t$19,368) | 122,709 | 63,609 | 21,254 |
| Foreign\tcurrency\ttranslation |  |  |  |
| (net\tof\ttax\texpense\tof\t$131,\t$275,\tand\t$192) | 243 | 508 | 357 |
| Other\tcomprehensive\tincome\t(loss) | 263,759 | (124,631) | (130,240) |
| Comprehensive\tIncome | 994,331 | 743,732 | 1,237,132 |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 18,670 | 21,690 | 20,933 |
| Comprehensive\tIncome\tAttributable\tto\tEntergy\tCorporation | $975,661 | $722,042 | $1,216,199 |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Consolidated\tnet\tincome | $730,572 | $868,363 | $1,367,372 |
| Adjustments\tto\treconcile\tconsolidated\tnet\tincome\tto\tnet\tcash\tflow |  |  |  |
| provided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 2,012,076 | 1,771,649 | 1,745,455 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 311,789 | (26,479) | (280,029) |
| Asset\timpairments\tand\trelated\tcharges | 341,537 | 355,524 | — |
| Gain\ton\tsale\tof\tbusiness | (43,569) | — | — |
| Changes\tin\tworking\tcapital: |  |  |  |
| Receivables | (180,648) | (14,202) | 28,091 |
| Fuel\tinventory | 4,873 | (11,604) | 5,393 |
| Accounts\tpayable | 94,436 | (6,779) | (131,970) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (142,626) | 55,484 | 580,042 |
| Interest\taccrued | (3,667) | 1,152 | (34,172) |
| Deferred\tfuel\tcosts | (4,824) | (99,987) | (55,686) |
| Other\tworking\tcapital\taccounts | (66,330) | (151,989) | 41,875 |
| Changes\tin\tprovisions\tfor\testimated\tlosses | (248,205) | (24,808) | (11,086) |
| Changes\tin\tother\tregulatory\tassets | 1,105,622 | (398,428) | (673,244) |
| Changes\tin\tother\tregulatory\tliabilities | 397,341 | 170,421 | 189,167 |
| Changes\tin\tpensions\tand\tother\tpostretirement\tliabilities | (1,433,663) | 644,099 | 962,461 |
| Other | 314,505 | (192,131) | (604,852) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 3,189,219 | 2,940,285 | 3,128,817 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction/capital\texpenditures | (2,287,593) | (2,674,650) | (2,040,027) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 69,689 | 96,131 | 86,252 |
| Nuclear\tfuel\tpurchases | (517,825) | (557,960) | (641,493) |
| Payment\tfor\tpurchase\tof\tplant | (17,300) | (456,356) | (646,137) |
| Proceeds\tfrom\tsale\tof\tassets\tand\tbusinesses | 147,922 | — | 6,531 |
| Changes\tin\tsecuritization\taccount | 155 | 4,265 | (7,260) |
| NYPA\tvalue\tsharing\tpayment | (71,736) | (72,000) | (72,000) |
| Payments\tto\tstorm\treserve\tescrow\taccount | (7,716) | (8,957) | (6,425) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 260,279 | 27,884 | — |
| Decrease\t(increase)\tin\tother\tinvestments | (82,955) | 15,175 | (11,623) |
| Litigation\tproceeds\tfor\treimbursement\tof\tspent\tnuclear\tfuel\tstorage\tcosts | 21,034 | 109,105 | — |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 2,031,552 | 2,074,055 | 1,360,346 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (2,147,099) | (2,196,489) | (1,475,017) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (2,601,593) | (3,639,797) | (3,446,853) |

| Long-term	debt | 3,746,016 | 3,478,361 | 2,990,881 |
| :--- | :--- | :--- | :--- |
| Preferred\tstock\tof\tsubsidiary | 24,249 | — | — |
| Mandatorily\tredeemable\tpreferred\tmembership\tunits\tof\tsubsidiary | — | 51,000 | — |
| Treasury\tstock | 24,527 | 62,886 | 46,185 |
| Retirement\tof\tlong-term\tdebt | (3,814,666) | (3,130,233) | (2,437,372) |
| Repurchase\tof\tcommon\tstock | — | — | (234,632) |
| Redemption\tof\tsubsidiary\tcommon\tand\tpreferred\tstock | — | — | (30,308) |
| Changes\tin\tcredit\tborrowings\tand\tcommercial\tpaper\t-\tnet | 250,889 | 687,675 | (6,501) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (593,037) | (589,209) | (589,605) |
| Preferred\tstock | (18,802) | (22,329) | (20,933) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (380,824) | 538,151 | (282,285) |
| Effect\tof\texchange\trates\ton\tcash\tand\tcash\tequivalents | (245) | (508) | 287 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 206,557 | (161,869) | (600,034) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 532,569 | 694,438 | 1,294,472 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $739,126 | $532,569 | $694,438 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $570,212 | $546,125 | $532,271 |
| Income\ttaxes | $127,735 | $49,214 | ($2,042) |

# CONSOLIDATED	BALANCE	SHEETS

# ASSETS

| Cash | $129,979 | $112,992 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 609,147 | 419,577 |
| Total\tcash\tand\tcash\tequivalents | 739,126 | 532,569 |
| Securitization\trecovery\ttrust\taccount | 45,885 | 46,040 |
| Accounts\treceivable: |  |  |
| Customer | 670,641 | 568,871 |
| Allowance\tfor\tdoubtful\taccounts | (34,311) | (31,956) |
| Other | 195,028 | 161,408 |
| Accrued\tunbilled\trevenues | 340,828 | 303,392 |
| Total\taccounts\treceivable | 1,172,186 | 1,001,715 |
| Deferred\tfuel\tcosts | 116,379 | 150,363 |
| Accumulated\tdeferred\tincome\ttaxes | 175,073 | 306,902 |
| Fuel\tinventory\t-\tat\taverage\tcost | 208,958 | 213,831 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 915,006 | 928,530 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 192,474 | 243,374 |
| System\tagreement\tcost\tequalization | 61,040 | 16,880 |
| Prepayments\tand\tother | 303,564 | 242,922 |
| TOTAL | 3,929,691 | 3,683,126 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 40,350 | 46,738 |
| Decommissioning\ttrust\tfunds | 4,903,144 | 4,190,108 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 199,375 | 256,039 |
| Other | 210,616 | 436,234 |
| TOTAL | 5,353,485 | 4,929,119 |
| PROPERTY,\tPLANT\tAND\tEQUIPMENT |  |  |
| Electric | 42,935,712 | 41,944,567 |
| Property\tunder\tcapital\tlease | 941,299 | 935,199 |
| Natural\tgas | 366,365 | 353,492 |
|  | 1,514,857 | 1,365,699 |
| Construction\twork\tin\tprogress |  |  |
| Nuclear\tfuel | 1,566,904 | 1,598,430 |
| TOTAL\tPROPERTY,\tPLANT\tAND\tEQUIPMENT | 47,325,137 | 46,197,387 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 19,443,493 | 18,898,842 |
| PROPERTY,\tPLANT\tAND\tEQUIPMENT\t-\tNET | 27,881,644 | 27,298,545 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 849,718 | 742,030 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof |  |  |
| $822,218\tas\tof\tDecember\t31,\t2013\tand\t$914,751\tas\tof |  |  |
| December\t31,\t2012) | 3,893,363 | 5,025,912 |
| Deferred\tfuel\tcosts | 172,202 | 172,202 |
| Goodwill | 377,172 | 377,172 |
| Accumulated\tdeferred\tincome\ttaxes | 62,011 | 37,748 |
| Other | 887,160 | 936,648 |
| TOTAL | 6,241,626 | 7,291,712 |
| TOTAL\tASSETS | $43,406,446 | $43,202,502 |

# LIABILITIES	AND	EQUITY

| Currently	maturing	long-term	debt | $457,095 | $718,516 |
| :--- | :--- | :--- |
| Notes\tpayable\tand\tcommercial\tpaper | 1,046,887 | 796,002 |
| Accounts\tpayable | 1,173,313 | 1,217,180 |
| Customer\tdeposits | 370,997 | 359,078 |
| Taxes\taccrued | 191,093 | 333,719 |
| Accumulated\tdeferred\tincome\ttaxes | 28,307 | 13,109 |
| Interest\taccrued | 180,997 | 184,664 |
| Deferred\tfuel\tcosts | 57,631 | 96,439 |
| Obligations\tunder\tcapital\tleases | 2,323 | 3,880 |
| Pension\tand\tother\tpostretirement\tliabilities | 67,419 | 95,900 |
| System\tagreement\tcost\tequalization | 61,040 | 25,848 |
| Other | 423,470 | 261,986 |
| TOTAL | 4,060,572 | 4,106,321 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 8,724,635 | 8,311,756 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 263,765 | 273,696 |
| Obligations\tunder\tcapital\tleases | 32,218 | 34,541 |
| Other\tregulatory\tliabilities | 1,295,955 | 898,614 |
| Decommissioning\tand\tasset\tretirement\tcost\tliabilities | 3,933,416 | 3,513,634 |
| Accumulated\tprovisions | 115,139 | 362,226 |
| Pension\tand\tother\tpostretirement\tliabilities | 2,320,704 | 3,725,886 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$883,013\tas\tof |  |  |
| December\t31,\t2013\tand\t$973,480\tas\tof\tDecember\t31,\t2012) | 12,139,149 | 11,920,318 |
| Other | 583,667 | 577,910 |
| TOTAL | 29,408,648 | 29,618,581 |
| Commitments\tand\tContingencies |  |  |
| Subsidiaries'\tpreferred\tstock\twithout\tsinking\tfund | 210,760 | 186,511 |
| EQUITY |  |  |
| Common\tShareholders'\tEquity: |  |  |
| Common\tstock,\t$.01\tpar\tvalue,\tauthorized\t500,000,000\tshares; |  |  |
| issued\t254,752,788\tshares\tin\t2013\tand\tin\t2012 | 2,548 | 2,548 |
| Paid-in\tcapital | 5,368,131 | 5,357,852 |
| Retained\tearnings | 9,825,053 | 9,704,591 |
| Accumulated\tother\tcomprehensive\tloss | (29,324) | (293,083) |
| Less\t-\ttreasury\tstock,\tat\tcost\t(76,381,936\tshares\tin\t2013\tand |  |  |
| 76,945,239\tshares\tin\t2012) | 5,533,942 | 5,574,819 |
| Total\tcommon\tshareholders'\tequity | 9,632,466 | 9,197,089 |
| Subsidiaries'\tpreferred\tstock\twithout\tsinking\tfund | 94,000 | 94,000 |
| TOTAL | 9,726,466 | 9,291,089 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $43,406,446 | $43,202,502 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	EQUITY

|  | Subsidiaries'<br>Preferred<br>Stock | Common<br>Stock | Treasury	Stock | Paid-in<br>Capital | Retained<br>Earnings | Accumulated	Other<br>Comprehensive<br>Income	(Loss) | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Balance\tat\tDecember\t31,\t2010 | $94,000 | $2,548 | ($5,524,811) | $5,367,474 | $8,689,401 | ($38,212) | $8,590,400 |
| Consolidated\tnet\tincome\t(a) | 20,933 | — | — | — | 1,346,439 | — | 1,367,372 |
| Other\tcomprehensive\tloss | — | — | — | — | — | (130,240) | (130,240) |
| Common\tstock\trepurchases | — | — | (234,632) | — | — | — | (234,632) |
| Common\tstock\tissuances\trelated\tto\nstock\tplans | — | — | 78,975 | (6,792) | — | — | 72,183 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (588,880) | — | (588,880) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (20,933) | — | — | — | — | — | (20,933) |
| Balance\tat\tDecember\t31,\t2011 | $94,000 | $2,548 | ($5,680,468) | $5,360,682 | $9,446,960 | ($168,452) | $9,055,270 |
| Consolidated\tnet\tincome\t(a) | 21,690 | — | — | — | 846,673 | — | 868,363 |
| Other\tcomprehensive\tloss | — | — | — | — | — | (124,631) | (124,631) |
| Common\tstock\tissuances\trelated\tto\nstock\tplans | — | — | 105,649 | (2,830) | — | — | 102,819 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (589,042) | — | (589,042) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (21,690) | — | — | — | — | — | (21,690) |
| Balance\tat\tDecember\t31,\t2012 | $94,000 | $2,548 | ($5,574,819) | $5,357,852 | $9,704,591 | ($293,083) | $9,291,089 |
| Consolidated\tnet\tincome\t(a) | 18,670 | — | — | — | 711,902 | — | 730,572 |
| Other\tcomprehensive\tincome | — | — | — | — | — | 263,759 | 263,759 |
| Common\tstock\tissuances\trelated\tto\nstock\tplans | — | — | 40,877 | 10,279 | — | — | 51,156 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (591,440) | — | (591,440) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (18,670) | — | — | — | — | — | (18,670) |
| Balance\tat\tDecember\t31,\t2013 | $94,000 | $2,548 | ($5,533,942) | $5,368,131 | $9,825,053 | ($29,324) | $9,726,466 |

(a)	Consolidated	net	income	and	preferred	dividend	requirements	of	subsidiaries	for	2013,	2012,	and	2011	include	$12.0	million,	$15.0	million,	and	$13.3	million,	respectively,	of preferred	dividends	on	subsidiaries'	preferred	stock	without	sinking	fund	that	is	not	presented	as	equity.

# NOTES	TO	FINANCIAL	STATEMENTS

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

The	accompanying	consolidated	financial	statements	include	the	accounts	of	Entergy	Corporation	and	its	subsidiaries.		As	required	by generally	accepted	accounting	principles	in	the	United	States	of	America,	all	intercompany	transactions	have	been	eliminated	in	the	consolidated financial	 statements.	 	 Entergy's	 Registrant	 Subsidiaries	 (Entergy	 Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy	 Louisiana,	 Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)	also	include	their	separate	financial	statements	in	this	Form	10-K.		The Registrant	Subsidiaries	and	many	other	Entergy	subsidiaries	maintain	accounts	in	accordance	with	FERC	and	other	regulatory	guidelines.

# Use	of	Estimates	in	the	Preparation	of	Financial	Statements

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

# Revenues	and	Fuel	Costs

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	Texas	generate,	transmit,	and distribute	electric	power	primarily	to	retail	customers	in	Arkansas,	Louisiana,	Louisiana,	Mississippi,	and	Texas,	respectively.		Entergy	Gulf States	Louisiana	also	distributes	natural	gas	to	retail	customers	in	and	around	Baton	Rouge,	Louisiana.		Entergy	New	Orleans	sells	both	electric power	 and	 natural	 gas	 to	 retail	 customers	 in	 the	 City	 of	 New	 Orleans,	 except	 for	Algiers,	 where	 Entergy	 Louisiana	 is	 the	 electric	 power supplier.		The	Entergy	Wholesale	Commodities	segment	derives	almost	all	of	its	revenue	from	sales	of	electric	power	generated	by	plants	owned by	subsidiaries	in	that	segment.

Entergy	recognizes	revenue	from	electric	power	and	natural	gas	sales	when	power	or	gas	is	delivered	to	customers.		To	the	extent	that deliveries	have	occurred	but	a	bill	has	not	been	issued,	Entergy's	Utility	operating	companies	accrue	an	estimate	of	the	revenues	for	energy delivered	since	the	latest	billings.		The	Utility	operating	companies	calculate	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	Entergy's	Utility	operating companies'	various	jurisdictions.		Changes	are	made	to	the	inputs	in	the	estimate	as	needed	to	reflect	changes	in	billing	practices.		Each	month	the estimated	 unbilled	 revenue	 amounts	 are	 recorded	 as	 revenue	 and	 unbilled	 accounts	 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	reversed	and	new estimates	recorded.

Entergy	records	revenue	from	sales	under	rates	implemented	subject	to	refund	less	estimated	amounts	accrued	for	probable	refunds	when Entergy	believes	it	is	probable	that	revenues	will	be	refunded	to	customers	based	upon	the	status	of	the	rate	proceeding	as	of	the	date	the	financial statements	are	prepared.

Entergy's	Utility	operating	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.		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.	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.

# Accounting	for	MISO	transactions

In	December	2013,	Entergy	 joined	MISO,	a	regional	 transmission	organization	 that	maintains	functional	control	over	 the	combined transmission	systems	of	its	members	and	manages	one	of	the	largest	energy	markets	in	the	U.S.	In	the	MISO	market,	Entergy	offers	its	generation and	bids	its	load	into	the	market	on	an	hourly	basis.	MISO	settles	these	hourly	offers	and	bids	based	on	locational	marginal	prices,	which	is pricing	for	energy	at	a	given	location	based	on	a	market	clearing	price	that	takes	into	account	physical	limitations	on	the	transmission	system, generation,	and	demand	throughout	the	MISO	region.	MISO	evaluates	the	market	participants'	energy	offers	and	demand	bids	to	economically and	reliably	dispatch	the	entire	MISO	system.	Entergy	accounts	for	these	hourly	offers	and	bids,	on	a	net	basis,	in	operating	revenues	when	in	a net	selling	position	and	in	operating	expenses	when	in	a	net	purchasing	position.

# Property,	Plant,	and	Equipment

Property,	plant,	and	equipment	 is	stated	at	original	cost.	 	Depreciation	 is	computed	on	 the	straight-line	basis	at	rates	based	on	 the applicable	estimated	service	lives	of	the	various	classes	of	property.	For	the	Registrant	Subsidiaries,	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	Registrant	Subsidiaries'	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	for	Entergy	(including	property	under	capital	lease	and	associated	accumulated	amortization)	by business	segment	and	functional	category,	as	of	December	31,	2013	and	2012,	is	shown	below:

| 2013 | Entergy | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;<br>Other |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |
| Nuclear | $9,667 | $6,601 | $3,066 | $— |
| Other | 2,836 | 2,465 | 371 | — |
| Transmission | 3,929 | 3,894 | 35 | — |
| Distribution | 6,716 | 6,716 | — | — |
| Other | 1,652 | 1,475 | 174 | 3 |
| Construction\twork\tin\tprogress | 1,515 | 1,217 | 298 | — |
| Nuclear\tfuel | 1,567 | 855 | 712 | — |
| Property,\tplant,\tand\tequipment\t-\tnet | $27,882 | $23,223 | $4,656 | $3 |

| 2012 | Entergy | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;<br>Other |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |
| Nuclear | $9,588 | $6,624 | $2,964 | $— |
| Other | 2,878 | 2,493 | 385 | — |
| Transmission | 3,654 | 3,619 | 35 | — |
| Distribution | 6,561 | 6,561 | — | — |
| Other | 1,654 | 1,416 | 235 | 3 |
| Construction\twork\tin\tprogress | 1,366 | 973 | 392 | 1 |
| Nuclear\tfuel | 1,598 | 907 | 691 | — |
| Property,\tplant,\tand\tequipment\t-\tnet | $27,299 | $22,593 | $4,702 | $4 |

Entergy	amortizes	nuclear	fuel	using	a	units-of-production	method.		Nuclear	fuel	amortization	is	included	in	fuel	expense	in	the	income statements.

"Non-utility	property	-	at	cost	(less	accumulated	depreciation)"	for	Entergy	is	reported	net	of	accumulated	depreciation	of	$203.0	million and	$230.4	million	as	of	December	31,	2013	and	2012,	respectively.

Construction	expenditures	included	in	accounts	payable	is	$166	million	and	$267	million	at	December	31,	2013	and	2012,	respectively.

Net	property,	plant,	and	equipment	for	the	Registrant	Subsidiaries	(including	property	under	capital	lease	and	associated	accumulated amortization)	by	company	and	functional	category,	as	of	December	31,	2013	and	2012,	is	shown	below:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| Production |  |  |  |  |  |  |  |
| Nuclear | $1,047 | $1,422 | $2,202 | $— | $— | $— | $1,930 |
| Other | 609 | 271 | 684 | 537 | (7) | 371 | — |
| Transmission | 1,086 | 646 | 770 | 638 | 31 | 673 | 49 |
| Distribution | 1,831 | 950 | 1,420 | 1,096 | 340 | 1,079 | — |
| Other | 192 | 184 | 292 | 197 | 181 | 106 | 17 |
| Construction\twork\tin\nprogress | 209 | 105 | 673 | 37 | 29 | 95 | 29 |
| Nuclear\tfuel | 322 | 197 | 147 | — | — | — | 189 |
| Property,\tplant,\tand\nequipment\t-\tnet | $5,296 | $3,775 | $6,188 | $2,505 | $574 | $2,324 | $2,214 |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| Production |  |  |  |  |  |  |  |
| Nuclear | $1,073 | $1,428 | $2,180 | $— | $— | $— | $1,943 |
| Other | 621 | 286 | 680 | 545 | (11) | 371 | — |
| Transmission | 1,034 | 573 | 734 | 581 | 27 | 642 | 28 |
| Distribution | 1,747 | 939 | 1,454 | 1,065 | 331 | 1,025 | — |
| Other | 115 | 187 | 289 | 201 | 182 | 106 | 17 |
| Construction\twork\tin\nprogress | 206 | 125 | 405 | 63 | 11 | 90 | 40 |
| Nuclear\tfuel | 304 | 147 | 204 | — | — | — | 253 |
| Property,\tplant,\tand\nequipment\t-\tnet | $5,100 | $3,685 | $5,946 | $2,455 | $540 | $2,234 | $2,281 |

Depreciation	rates	on	average	depreciable	property	for	the	Registrant	Subsidiaries	are	shown	below:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 | 2.5% | 1.8% | 2.5% | 2.6% | 3.0% | 2.5% | 2.8% |
| 2012 | 2.5% | 1.8% | 2.4% | 2.6% | 3.0% | 2.4% | 2.8% |
| 2011 | 2.6% | 1.8% | 2.5% | 2.6% | 3.0% | 2.2% | 2.8% |

Non-utility	 property	 -	 at	 cost	 (less	 accumulated	 depreciation)	 for	 Entergy	 Gulf	 States	 Louisiana	 is	 reported	 net	 of	 accumulated depreciation	of	$146	million	and	$142	million	as	of	December	31,	2013	and	2012,	respectively.		Non-utility	property	-	at	cost	(less	accumulated depreciation)	for	Entergy	Louisiana	is	reported	net	of	accumulated	depreciation	of	$3.0	million	and	$2.8	million	as	of	December	31,	2013	and 2012,	respectively.		Non-utility	property	-	at	cost	(less	accumulated	depreciation)	for	Entergy	Texas	is	reported	net	of	accumulated	depreciation of	$10.4	million	and	$10.0	million	as	of	December	31,	2013	and	2012,	respectively.

As	of	December	31,	2013,	construction	expenditures	included	in	accounts	payable	are	$61.9	million	for	Entergy	Arkansas,	$13.1	million for	Entergy	Gulf	States	Louisiana,	$31.1	million	 for	 Entergy	 Louisiana,	$2.8	million	 for	 Entergy	 Mississippi,	$1.7	million	for	Entergy	New Orleans,	$10.9	million	for	Entergy	Texas,	and	$6.7	million	for	System	Energy.		As	of	December	31,	2012,	construction	expenditures	included	in accounts	payable	are	$56.3	million	for	Entergy	Arkansas,	$9.7	million	for	Entergy	Gulf	States	Louisiana,	$110.4	million	for	Entergy	Louisiana, $4.8	million	for	Entergy	Mississippi,	$1.9	million	for	Entergy	New	Orleans,	$8.6	million	for	Entergy	Texas,	and	$13.5	million	for	System	Energy.

# Jointly-Owned	Generating	Stations

Certain	Entergy	subsidiaries	 jointly	own	electric	generating	facilities	with	affiliates	or	 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,	2013,	the	subsidiaries'	investment	and	accumulated	depreciation	in	each	of	these	generating	stations	were	as follows:

| Generating	Stations | Generating	Stations | Fuel-Type | Total<br>Megawatt<br>Capability	(a) | Ownership |  | Investment | Accumulated<br>Depreciation |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  | (In\tMillions) | (In\tMillions) |
| Utility\tbusiness: |  |  |  |  |  |  |  |
| Entergy\tArkansas\t- |  |  |  |  |  |  |  |
| \t\tIndependence | \t Unit\t1 | Coal | 838 | 31.50% |  | $129 | $97 |
|  | \t Common\tFacilities | Coal |  | 15.75% |  | $33 | $25 |
| \tWhite\tBluff | \t Units\t1\tand\t2 | Coal | 1,637 | 57.00% |  | $502 | $348 |
| \t\tOuachita\t(b) | Common |  |  |  |  |  |  |
|  | Facilities | Gas |  | 66.67% |  | $169 | $144 |
| Entergy\tGulf\tStates\nLouisiana\t- |  |  |  |  |  |  |  |
| \t\tRoy\tS.\tNelson | \t Unit\t6 | Coal | 551 | 40.25% |  | $255 | $176 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon |  |  |  |  |  |  |
|  | Facilities | Coal |  | 15.92% |  | $8 | $3 |
| \t\tBig\tCajun\t2 | \t Unit\t3 | Coal | 603 | 24.15% |  | $143 | $102 |
| \t\tOuachita\t(b) | Common |  |  |  |  |  |  |
|  | Facilities | Gas |  | 33.33% |  | $87 | $73 |
| Entergy\tLouisiana\t-\n\t\t\tAcadia | Common |  |  |  |  |  |  |
|  | Facilities | Gas |  | 50.00% |  | $19 | $— |
| Entergy\tMississippi\t-\n\t\tIndependence | Units\t1\tand\t2 |  |  |  |  |  |  |
|  | and\tCommon |  |  |  |  |  |  |
|  | Facilities | Coal | 1,679 | 25.00% |  | $250 | $144 |
| Entergy\tTexas\t- |  |  |  |  |  |  |  |
| \t\tRoy\tS.\tNelson | \t Unit\t6 | Coal | 551 | 29.75% |  | $183 | $113 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon |  |  |  |  |  |  |
|  | Facilities | Coal |  | 11.77% |  | $6 | $2 |
| \t\tBig\tCajun\t2 | \t Unit\t3 | Coal | 603 | 17.85% |  | $107 | $71 |
| System\tEnergy\t- |  |  |  |  |  |  |  |
| \t\tGrand\tGulf | \t Unit\t1 | Nuclear | 1,413 | 90.00% | (c) | $4,696 | $2,699 |
| Entergy\tWholesale\nCommodities: |  |  |  |  |  |  |  |
| \t\tIndependence | \t Unit\t2 | Coal | 841 | 14.37% |  | $69 | $44 |
| \t\tIndependence | Common |  |  |  |  |  |  |
|  | Facilities | Coal |  | 7.18% |  | $16 | $11 |
| \t\tRoy\tS.\tNelson | \t Unit\t6 | Coal | 551 | 10.9% |  | $105 | $55 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon |  |  |  |  |  |  |
|  | Facilities | Coal |  | 4.31% |  | $2 | $1 |

(a) "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.

(b) Ouachita	Units	1	and	2	are	owned	100%	by	Entergy	Arkansas	and	Ouachita	Unit	3	is	owned	 100%	by	Entergy	Gulf	States	Louisiana.		The investment	and	accumulated	depreciation	numbers	above	are	only	for	the	common	facilities	and	not	for	the	generating	units.

(c) Includes	a	leasehold	interest	held	by	System	Energy.		System	Energy's	Grand	Gulf	lease	obligations	are	discussed	in	Note	10	to	the financial	statements.

# Nuclear	Refueling	Outage	Costs

Nuclear	refueling	outage	costs	are	deferred	during	the	outage	and	amortized	over	the	estimated	period	to	the	next	outage	because	these refueling	outage	expenses	are	incurred	to	prepare	the	units	to	operate	for	the	next	operating	cycle	without	having	to	be	taken	off	line.

# 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	by	the	Registrant	Subsidiaries.		AFUDC	increases	both	the	plant	balance	and	earnings	and	is	realized	in	cash	through	depreciation provisions	included	in	the	rates	charged	to	customers.

Entergy	Corporation	and	the	majority	of	its	subsidiaries	file	a	United	States	consolidated	federal	income	tax	return.		Each	tax-paying entity	records	income	taxes	as	if	it	were	a	separate	taxpayer	and	consolidating	adjustments	are	allocated	to	the	tax	filing	entities	in	accordance	with Entergy's	intercompany	income	tax	allocation	agreement.		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	calculation	included	on	the	consolidated	statements	of	income:

|  | 2013 | 2013 | 2012 | 2012 | 2011 | 2011 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | $/share | (In\tMillions,\tExcept\tPer\tShare\tData) | $/share |  | $/share |
| Net\tincome\tattributable\tto\tEntergy\nCorporation | $711.9 |  | $846.7 |  | $1,346.4 |  |
| Basic\tearnings\tper\taverage\tcommon\tshare | 178.2 | $3.99 | 177.3 | $4.77 | 177.4 | $7.59 |
| Average\tdilutive\teffect\tof: |  |  |  |  |  |  |
| Stock\toptions | 0.1 | — | 0.3 | (0.01) | 1.0 | (0.04) |
| Other\tequity\tplans | 0.3 | — | 0.1 | — | — | — |
| Diluted\tearnings\tper\taverage\tcommon\nshares | 178.6 | $3.99 | 177.7 | $4.76 | 178.4 | $7.55 |

Entergy	Corporation	and	Subsidiaries Notes	to	Financial	Statements

could	potentially	dilute	basic	earnings	per	share	in	the	future.		Those	options	were	not	included	in	the	calculation	of	diluted	earnings	per	share because	the	exercise	price	of	those	options	exceeded	the	average	market	price	for	the	year.

# Stock-based	Compensation	Plans

Entergy	 grants	 stock	 options,	 restricted	 stock,	 performance	 units,	 and	 restricted	 liability	 awards	 to	 key	 employees	 of	 the	 Entergy subsidiaries	under	its	Equity	Ownership	Plans,	which	are	shareholder-approved	stock-based	compensation	plans.		These	plans	are	described	more fully	in	Note	12	to	the	financial	statements.		The	cost	of	the	stock-based	compensation	is	charged	to	income	over	the	vesting	period.		Awards under	Entergy's	plans	generally	vest	over	3	years.

# Accounting	for	the	Effects	of	Regulation

Entergy's	Utility	operating	companies	and	System	Energy	are	rate-regulated	enterprises	whose	rates	meet	 three	criteria	specified	 in accounting	standards.		The	Utility	operating	companies	and	System	Energy	have	rates	that	(i)	are	approved	by	a	body	(its	regulator)	empowered	to set	rates	that	bind	customers;	(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.		Because	the	Utility operating	companies	and	System	Energy	meet	these	criteria,	each	of	them	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.		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.

An	enterprise	that	ceases	to	meet	the	three	criteria	for	all	or	part	of	its	operations	should	report	that	event	in	its	financial	statements.		In general,	the	enterprise	no	longer	meeting	the	criteria	should	eliminate	from	its	balance	sheet	all	regulatory	assets	and	liabilities	related	to	the applicable	operations.		Additionally,	if	it	is	determined	that	a	regulated	enterprise	is	no	longer	recovering	all	of	its	costs,	it	is	possible	that	an impairment	may	exist	that	could	require	further	write-offs	of	plant	assets.

Entergy	Gulf	States	Louisiana	does	not	apply	regulatory	accounting	standards	to	the	Louisiana	retail	deregulated	portion	of	River	Bend, the	30%	interest	in	River	Bend	formerly	owned	by	Cajun,	and	its	steam	business,	where	specific	cost	recovery	is	not	provided	for	in	tariff rates.		The	Louisiana	retail	deregulated	portion	of	River	Bend	is	operated	under	a	deregulated	asset	plan	representing	a	portion	(approximately 15%)	of	River	Bend	plant	costs,	generation,	revenues,	and	expenses	established	under	a	1992	LPSC	order.		The	plan	allows	Entergy	Gulf	States Louisiana	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	incremental	revenue	above	4.6	cents	per	kWh	between	customers	and	shareholders.

# Regulatory	Asset	for	Income	Taxes

Accounting	standards	for	income	taxes	provide	that	a	regulatory	asset	be	recorded	if	it	is	probable	that	the	currently	determinable	future increase	in	regulatory	income	tax	expense	will	be	recovered	from	customers	through	future	rates.	The	primary	source	of	Entergy's	regulatory	asset for	income	taxes	is	book	depreciation	of	AFUDC	equity	that	has	been	capitalized	to	property,	plant,	and	equipment	but	for	which	there	is	no corresponding	tax	basis.	AFUDC	equity	is	a	component	of	property,	plant,	and	equipment	that	is	included	in	rate	base	when	the	plant	is	placed	in service.

# 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.

# Allowance	for	Doubtful	Accounts

The	allowance	for	doubtful	accounts	reflects	Entergy's	best	estimate	of	losses	on	the	accounts	receivable	balances.		The	allowance	is based	on	accounts	receivable	agings,	historical	experience,	and	other	currently	available	evidence.		Utility	operating	company	customer	accounts receivable	are	written	off	consistent	with	approved	regulatory	requirements.

# Investments

Entergy	records	decommissioning	trust	funds	on	the	balance	sheet	at	their	fair	value.		Because	of	the	ability	of	the	Registrant	Subsidiaries to	recover	decommissioning	costs	 in	rates	and	 in	accordance	with	 the	regulatory	 treatment	for	decommissioning	 trust	funds,	 the	Registrant Subsidiaries	record	an	offsetting	amount	in	other	regulatory	liabilities/assets	to	the	unrealized	gains/(losses)	on	investment	securities.		For	the portion	of	River	Bend	that	is	not	rate-regulated,	Entergy	Gulf	States	Louisiana	has	recorded	an	offsetting	amount	in	other	deferred	credits	to	the unrealized	gains/(losses).		Decommissioning	trust	funds	for	Pilgrim,	Indian	Point	2,	Vermont	Yankee,	and	Palisades	do	not	meet	the	criteria	for regulatory	accounting	treatment.		Accordingly,	unrealized	gains	recorded	on	the	assets	in	these	trust	funds	are	recognized	in	the	accumulated	other comprehensive	income	component	of	equity	because	these	assets	are	classified	as	available	for	sale.		Unrealized	losses	(where	cost	exceeds	fair market	value)	on	the	assets	in	these	trust	funds	are	also	recorded	in	the	accumulated	other	comprehensive	income	component	of	equity	unless	the unrealized	loss	is	other	than	temporary	and	therefore	recorded	in	earnings.		The	assessment	of	whether	an	investment	in	a	debt	security	has suffered	an	other-than-temporary	impairment	is	based	on	whether	Entergy	has	the	intent	to	sell	or	more	likely	than	not	will	be	required	to	sell	the debt	security	before	recovery	of	its	amortized	costs.		Further,	if	Entergy	does	not	expect	to	recover	the	entire	amortized	cost	basis	of	the	debt security,	an	other-than-temporary	impairment	is	considered	to	have	occurred	and	it	is	measured	by	the	present	value	of	cash	flows	expected	to	be collected	less	the	amortized	cost	basis	(credit	loss).		The	assessment	of	whether	an	investment	in	an	equity	security	has	suffered	an	other-than- temporary	impairment	is	based	on	a	number	of	factors	including,	first,	whether	Entergy	has	the	ability	and	intent	to	hold	the	investment	to	recover its	value,	the	duration	and	severity	of	any	losses,	and,	then,	whether	it	is	expected	that	the	investment	will	recover	its	value	within	a	reasonable period	of	time.		Entergy's	trusts	are	managed	by	third	parties	who	operate	in	accordance	with	agreements	that	define	investment	guidelines	and place	restrictions	on	the	purchases	and	sales	of	investments.		See	Note	17	to	the	financial	statements	for	details	on	the	decommissioning	trust funds.

# Equity	Method	Investments

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.		In	accordance	with	this	method,	earnings	are	allocated	to	owners	or	members	based	on	what	each	partner	would	receive	from	its	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	for	an investee	plus	any	advances	made	or	commitments	to	provide	additional	financial	support.		See	Note	14	to	the	financial	statements	for	additional information	regarding	Entergy's	equity	method	investments.

# Derivative	Financial	Instruments	and	Commodity	Derivatives

The	accounting	standards	for	derivative	instruments	and	hedging	activities	require	that	all	derivatives	be	recognized	at	fair	value	on	the balance	sheet,	either	as	assets	or	liabilities,	unless	they	meet	various	exceptions	including	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	physically	delivered	in	quantities	expected	to	be	used	or	sold	in	the	ordinary	course	of	business, including	certain	purchases	and	sales	of	power	and	fuel,	meet	the	normal	purchase,	normal	sales	criteria	and	are	not	recognized	on	the	balance sheet.	 	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	to earnings	in	the	periods	when	the	underlying	transactions	actually	occur.		The	ineffective	portions	of	all	hedges	are	recognized	in	current-period earnings.

Entergy	has	determined	that	contracts	to	purchase	uranium	do	not	meet	the	definition	of	a	derivative	under	the	accounting	standards	for derivative	instruments	because	they	do	not	provide	for	net	settlement	and	the	uranium	markets	are	not	sufficiently	liquid	to	conclude	that	forward contracts	are	readily	convertible	to	cash.		If	the	uranium	markets	do	become	sufficiently	liquid	in	the	future	and	Entergy	begins	to	account	for uranium	purchase	contracts	as	derivative	instruments,	the	fair	value	of	these	contracts	would	be	accounted	for	consistent	with	Entergy's	other derivative	instruments.

# Fair	Values

The	estimated	fair	values	of	Entergy's	financial	instruments	and	derivatives	are	determined	using	bid	prices,	market	quotes,	and	financial modeling.		Considerable	judgment	is	required	in	developing	the	estimates	of	fair	value.		Therefore,	estimates	are	not	necessarily	indicative	of	the amounts	that	Entergy	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.		Entergy	considers	the	carrying	amounts	of most	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.		See	Note	16	to	the	financial	statements	for	further	discussion	of	fair	value.

# Impairment	of	Long-Lived	Assets

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

Two	nuclear	power	plants	in	the	Entergy	Wholesale	Commodities	business	segment	(Indian	Point	2	and	Indian	Point	3)	have	applications pending	for	renewed	NRC	licenses.		Various	parties	have	expressed	opposition	to	renewal	of	the	licenses.		Under	federal	law,	nuclear	power plants	may	continue	to	operate	beyond	their	original	license	expiration	dates	while	their	timely	filed	renewal	applications	are	pending	NRC approval.		On	September	28,	2013,	Indian	Point	2	reached	the	expiration	date	of	its	original	NRC	operating	license	and	entered	into	the	period	of extended	operation	under	the	timely	renewal	rule.	If	the	NRC	does	not	renew	the	operating	license	for	either	of	these	plants,	the	plant's	operating life	could	be	shortened,	reducing	its	projected	net	cash	flows	and	impairing	its	value	as	an	asset.

In	March	2011	the	NRC	renewed	Vermont	Yankee's	operating	license	for	an	additional	 20	years.		The	renewed	operating	license	expires in	March	2032.	Vermont	Yankee	also	is	operating	under	a	Certificate	of	Public	Good	from	the	State	of	Vermont	that	was	scheduled	to	expire	in March	2012,	but	has	an	application	pending	before	the	Vermont	Public	Service	Board	(VPSB)	for	a	renewed	Certificate	of	Public	Good.		In	April 2011,	Entergy	Nuclear	Vermont

Yankee	and	Entergy	Nuclear	Operations,	the	owner	and	operator	respectively	of	Vermont	Yankee,	filed	suit	in	the	United	States	District	Court	for the	District	of	Vermont.		The	suit	challenged	certain	conditions	imposed	by	Vermont	upon	Vermont	Yankee's	continued	operation	and	storage	of spent	nuclear	fuel,	including	the	requirement	to	obtain	not	only	a	new	Certificate	of	Public	Good,	but	also	approval	by	Vermont's	General Assembly.		In	January	2012	the	court	decided	that	the	Atomic	Energy	Act	preempted	Vermont's	laws	prohibiting	the	issuance	of	a	new	Certificate of	Public	Good	without	further	authorization	by	Vermont's	legislature.	Vermont	appealed	that	decision	to	the	U.S.	Court	of	Appeals	for	the Second	Circuit,	which	affirmed	that	decision	in	August	2013.

In	January	2012,	after	the	federal	district	court	had	issued	its	decision,	Entergy	filed	a	motion	requesting	that	the	VPSB	grant,	based	on	the existing	record	in	its	Certificate	of	Public	Good	proceeding	that	had	begun	in	2008	but	was	suspended	due	to	the	applicable	laws	being	challenged in	the	federal	court	litigation,	Vermont	Yankee's	pending	application	for	a	new	Certificate	of	Public	Good.		Entergy	subsequently	filed	another motion	asking	the	VPSB	to	declare	that	title	3,	section	814(b)	of	the	Vermont	statutes	(3	V.S.A.	§	814(b))	authorized	Vermont	Yankee	to	operate while	the	Certificate	of	Public	Good	proceeding	was	pending	because	Entergy	had	timely	filed	a	petition	for	a	new	Certificate	of	Public	Good	that had	not	yet	been	decided.		In	March	2012	the	VPSB	issued	orders	denying	Entergy's	motion	with	respect	to	3	V.S.A.	§	814(b)	but	stating	that	the order	did	not	require	Vermont	Yankee	to	cease	operations,	denying	Entergy's	motion	to	issue	a	new	Certificate	of	Public	Good	based	on	the existing	record,	determining	to	open	a	new	docket	and	to	create	a	new	record	to	decide	Vermont	Yankee's	request	for	a	new	Certificate	of	Public Good	(without	prejudice	to	any	rights	that	Entergy	might	have	under	3	V.S.A.	§	814(b)),	and	directing	Entergy	to	file	an	amended	Certificate	of Public	Good	petition	that	identified	the	specific	approvals	it	was	seeking	in	light	of	the	district	court's	decision.		In	April	2012,	Entergy	filed	its amended	Certificate	of	Public	Good	petition.

In	November	2012	the	VPSB	denied	a	motion	by	Entergy	to	amend	provisions	in	the	2002	and	2006	VPSB	orders	respectively	approving Entergy's	acquisition	of	Vermont	Yankee	and	Vermont	Yankee's	construction	of	a	spent	nuclear	fuel	storage	facility.		In	its	March	2012	orders, the	VPSB	had	found	that	these	provisions	contained	conditions	respectively	precluding	the	operation	of	Vermont	Yankee	after	March	21,	2012 absent	issuance	of	a	new	or	renewed	certificate	of	public	good	and	limiting	the	amount	of	spent	nuclear	fuel	stored	at	the	site,	in	each	case	without explicitly	addressing	whether	those	conditions	were	subject	to	3	V.S.A.	§	814(b).		In	January	2013	the	VPSB	issued	an	order	closing	the	old Certificate	of	Public	Good	docket	(the	one	superseded	by	Entergy's	April	2012	amended	petition)	in	which	the	VPSB's	March	and	November 2012	orders	had	been	issued,	making	an	appeal	from	those	orders	ripe.		Entergy	appealed	those	VPSB	orders	to	the	Vermont	Supreme	Court.		That appeal	remains	pending.

In	June	2013	the	VPSB	completed	hearings	on	Entergy's	amended	petition	for	a	Certificate	of	Public	Good	to	continuing	operating Vermont	Yankee.	 In	August	2013,	Entergy	announced	that	it	planned	to	close	Vermont	Yankee	at	the	end	of	2014	and	that	same	day	filed	a second	amended	petition	seeking	authorization	to	operate	the	plant	only	until	that	date.	In	December	2013,	Entergy	and	Vermont	entered	into	a settlement	agreement,	with	an	accompanying	memorandum	of	understanding	that	was	filed	with	the	VPSB,	under	which	Vermont	agreed	to support	Entergy's	request	to	operate	Vermont	Yankee	until	the	end	of	2014.	 The	settlement	agreement	provides	for	Entergy	to	make	$10	million in	economic	transition	payments,	$5	million	in	clean	energy	development	support,	and	a	transitional	 $5	million	payment	to	Vermont.	Entergy	will also	set	aside	a	new	$25	million	fund	to	ensure	the	Vermont	Yankee	site	is	restored	after	decommissioning.	 These	terms	are	contingent	upon	the VPSB's	issuance	by	March	31,	2014	of	a	Certificate	of	Public	Good	authorizing	Vermont	Yankee's	operation	through	2014	and	otherwise conforming	 to	 the	 terms	 of	 the	 settlement	 agreement.	The	settlement	agreement	also	provides	for	 the	dismissal	or	discontinuation	of	other litigation	between	Entergy	and	Vermont;	in	the	case	of	Entergy's	appeal	of	the	VPSB's	March	and	November	2012	orders,	such	dismissal	is contingent	upon	the	VPSB's	issuance	of	such	a	Certificate	of	Public	Good.	The	VPSB	has	scheduled	additional	proceedings	and	further	hearings on	the	memorandum	of	understanding.

# Impairment

Because	of	the	uncertainty	regarding	the	continued	operation	of	Vermont	Yankee,	Entergy	tested	the	recoverability	of	the	plant	and	related assets	in	each	quarter	since	the	first	quarter	2010.		The	determination	of	recoverability	is	based	on	the	probability-weighted	undiscounted	net	cash flows	expected	to	be	generated	by	the	plant

and	related	assets.		Projected	net	cash	flows	primarily	depend	on	the	status	of	the	pending	legal	and	state	regulatory	matters,	as	well	as	projections of	future	revenues	and	expenses	over	the	remaining	life	of	the	plant.		Prior	to	the	first	quarter	2012,	the	probability-weighted	undiscounted	net cash	flows	exceeded	the	carrying	value	of	the	Vermont	Yankee	plant	and	related	assets.		The	decline,	however,	in	the	overall	energy	market	and the	projected	forward	prices	of	power	as	of	March	31,	2012,	which	are	significant	inputs	in	the	determination	of	net	cash	flows,	resulted	in	the probability-weighted	undiscounted	future	cash	flows	being	less	than	the	asset	group's	carrying	value.		Entergy	performed	a	fair	value	analysis based	on	the	income	approach,	a	discounted	cash	flow	method,	to	determine	the	amount	of	impairment.	The	estimated	fair	value	of	the	plant	and related	assets	at	March	31,	2012	was	$162.0	million,	while	the	carrying	value	was	$517.5	million.		Therefore,	the	assets	were	written	down	to their	fair	value	and	an	impairment	charge	of	$355.5	million	($223.5	million	after-tax)	was	recognized.		The	impairment	charge	was	recorded	as	a separate	 line	 item	 in	 Entergy's	 consolidated	 statement	 of	 income	 for	 2012,	 and	 is	 included	 within	 the	 results	 of	 the	 Entergy	 Wholesale Commodities	segment.

The	estimate	of	fair	value	was	based	on	the	price	that	Entergy	would	expect	to	receive	in	a	hypothetical	sale	of	the	Vermont	Yankee	plant and	 related	 assets	 to	 a	 market	 participant	 on	 March	 31,	 2012.	In	order	 to	determine	 this	price,	Entergy	used	significant	observable	 inputs, including	quoted	forward	power	and	gas	prices,	where	available.	Significant	unobservable	inputs,	such	as	projected	long-term	pre-tax	operating margins	(cash	basis),	and	estimated	weighted	average	costs	of	capital	were	also	used	in	the	estimation	of	fair	value.	In	addition,	Entergy	made certain	assumptions	regarding	future	tax	deductions	associated	with	the	plant	and	related	assets.	Based	on	the	use	of	significant	unobservable inputs,	the	fair	value	measurement	for	the	entirety	of	the	asset	group,	and	for	each	type	of	asset	within	the	asset	group,	is	classified	as	Level	3	in the	fair	value	hierarchy	discussed	in	Note	16	to	the	financial	statements.

The	following	table	sets	forth	a	description	of	significant	unobservable	inputs	used	in	the	valuation	of	the	Vermont	Yankee	plant	and related	assets	as	of	March	31,	2012:

| Significant	Unobservable	Inputs | Range | Weighted	Average |
| :--- | :--- | :--- |
| Weighted\taverage\tcost\tof\tcapital | 7.5%-8.0% | 7.8% |
| Long-term\tpre-tax\toperating\tmargin\t(cash\tbasis) | 6.1%-7.8% | 7.2% |

On	August	27,	2013,	Entergy	announced	its	plan	to	close	and	decommission	Vermont	Yankee.	 Vermont	Yankee	is	expected	to	cease power	production	in	the	fourth	quarter	2014	after	its	current	fuel	cycle.	This	decision	was	approved	by	the	Board	in	August	2013,	although	the exact	date	of	shutdown	was	not	determined.	The	decision	to	shut	down	the	plant	was	primarily	due	to	sustained	low	natural	gas	and	wholesale energy	prices,	the	high	cost	structure	of	the	plant,	and	lack	of	a	market	structure	that	adequately	compensates	merchant	nuclear	plants	for	their environmental	and	fuel	diversity	benefits	in	the	region	in	which	the	plant	operates.

As	a	result	of	the	decision	to	shut	down	the	plant,	Entergy	recognized	non-cash	impairment	and	other	related	charges	of $291.5	million ($183.7	million	after-tax)	during	the	third	quarter	2013	to	write	down	the	carrying	value	of	Vermont	Yankee	and	related	assets	to	their	fair	values. Entergy	performed	a	fair	value	analysis	based	on	the	income	approach,	a	discounted	cash	flow	method,	to	determine	the	amount	of	impairment. The	estimated	fair	value	of	the	plant	and	related	assets	was	$62	million,	while	the	carrying	value	was	$349	million.	The	carrying	value	of	$349 million	reflects	the	effect	of	a	$58	million	increase	in	Vermont	Yankee's	estimated	decommissioning	cost	liability	and	the	related	asset	retirement cost	 asset.	The	 increase	 in	 the	 estimated	 decommissioning	 cost	 liability	 resulted	 from	 the	 change	 in	 expectation	 regarding	 the	 timing	 of decommissioning	cash	flows	due	to	the	decision	to	cease	operations.	Impairment	and	other	related	charges	are	recorded	as	a	separate	line	item	in Entergy's	consolidated	statements	of	 income	for	2013	and	 this	 impairment	charge	 is	 included	within	 the	results	of	 the	Entergy	Wholesale Commodities	segment.

The	estimate	of	fair	value	was	based	on	the	price	that	Entergy	would	expect	to	receive	in	a	hypothetical	sale	of	the	Vermont	Yankee	plant and	related	assets	to	a	market	participant.		In	order	to	determine	this	price,	Entergy	used

significant	observable	inputs,	including	quoted	forward	power	and	gas	prices,	where	available.		Significant	unobservable	inputs,	such	as	projected long-term	pre-tax	operating	margins	(cash	basis),	and	estimated	weighted	average	costs	of	capital	were	also	used	in	the	estimation	of	fair	value.		In addition,	Entergy	made	certain	assumptions	regarding	future	tax	deductions	associated	with	the	plant	and	related	assets.		Based	on	the	use	of significant	unobservable	inputs,	the	fair	value	measurement	for	the	entirety	of	the	asset	group,	and	for	each	type	of	asset	within	the	asset	group,	is classified	as	Level	3	in	the	fair	value	hierarchy	discussed	in	Note	16	to	the	financial	statements.

The	following	table	sets	forth	a	description	of	significant	unobservable	inputs	used	in	the	valuation	of	the	Vermont	Yankee	plant	and related	assets	as	of	July	31,	2013:

| Significant	Unobservable	Inputs | Amount |
| :--- | :--- |
| Weighted\taverage\tcost\tof\tcapital | 7.5% |
| Long-term\tpre-tax\toperating\tmargin\t(cash\tbasis) | 7.0% |

Entergy's	Accounting	Policy	group,	which	reports	to	the	Chief	Accounting	Officer,	was	primarily	responsible	for	determining	the	valuation	of	the Vermont	Yankee	plant	and	related	assets,	in	consultation	with	external	advisors.		Accounting	Policy	obtained	and	reviewed	information	from other	Entergy	departments	with	expertise	on	the	various	inputs	and	assumptions	that	were	necessary	to	calculate	the	fair	value	of	the	asset	group.

As	a	result	of	the	settlement	agreement	entered	into	by	Entergy	and	Vermont	regarding	the	remaining	operation	and	decommissioning	of Vermont	Yankee	discussed	above,	Entergy	reassessed	its	assumptions	regarding	the	timing	of	decommissioning	cash	flows	for	Vermont	Yankee. The	reassessment	resulted	in	a	$27.2	million	increase	in	the	decommissioning	cost	liability	and	a	corresponding	impairment	charge,	recorded	in December	 2013.	Impairment	charges	are	recorded	as	a	separate	line	item	in	Entergy's	consolidated	statements	of	income	for	2013	and	this impairment	charge	is	included	within	the	results	of	the	Entergy	Wholesale	Commodities	segment.

In	addition	to	the	impairment	charge	and	depreciation	of	the	remaining	plant	balance	by	the	end	of	2014,	Entergy	expects	to	record additional	charges	through	the	end	of	2014	totaling	approximately	$50	million	to	$55	million	related	to	severance	and	employee	retention	costs relating	to	the	shutdown	of	Vermont	Yankee.

# 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	Louisiana	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	through	August	2025.

# Reacquired	Debt

The	premiums	and	costs	associated	with	reacquired	debt	of	Entergy's	Utility	operating	companies	and	System	Energy	(except	that	portion allocable	to	the	deregulated	operations	of	Entergy	Gulf	States	Louisiana)	are	included	in	regulatory	assets	and	are	being	amortized	over	the	life	of the	related	new	issuances,	or	over	the	life	of	the	original	debt	issuance	if	the	debt	is	not	refinanced,	in	accordance	with	ratemaking	treatment.

# Taxes	Imposed	on	Revenue-Producing	Transactions

Governmental	authorities	assess	taxes	that	are	both	imposed	on	and	concurrent	with	a	specific	revenue-producing	transaction	between	a seller	and	a	customer,	including,	but	not	limited	to,	sales,	use,	value	added,	and	some	excise	taxes.		Entergy	presents	these	taxes	on	a	net	basis, excluding	them	from	revenues,	unless	required	to	report	them	differently	by	a	regulatory	authority.

# Presentation	of	Preferred	Stock	without	Sinking	Fund

Accounting	standards	regarding	non-controlling	interests	and	the	classification	and	measurement	of	redeemable	securities	require	the classification	of	preferred	securities	between	liabilities	and	shareholders'	equity	on	the	balance	sheet	if	the	holders	of	those	securities	have protective	rights	that	allow	them	to	gain	control	of	the	board	of	directors	in	certain	circumstances.		These	rights	would	have	the	effect	of	giving the	holders	the	ability	to	potentially	redeem	their	securities,	even	if	the	likelihood	of	occurrence	of	these	circumstances	is	considered	remote.		The Entergy	Arkansas,	Entergy	Mississippi,	and	Entergy	New	Orleans	articles	of	incorporation	provide,	generally,	that	the	holders	of	each	company's preferred	securities	may	elect	a	majority	of	the	respective	company's	board	of	directors	if	dividends	are	not	paid	for	a	year,	until	such	time	as	the dividends	in	arrears	are	paid.		Therefore,	Entergy	Arkansas,	Entergy	Mississippi,	and	Entergy	New	Orleans	present	their	preferred	securities outstanding	 between	 liabilities	 and	 shareholders'	 equity	 on	 the	 balance	 sheet.	 	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana,	 both organized	as	limited	liability	companies,	have	outstanding	preferred	securities	with	similar	protective	rights	with	respect	to	unpaid	dividends,	but provide	for	the	election	of	board	members	that	would	not	constitute	a	majority	of	the	board;	and	their	preferred	securities	are	therefore	classified for	all	periods	presented	as	a	component	of	members'	equity.

The	outstanding	preferred	securities	of	Entergy	Arkansas,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Finance	Holding	(an Entergy	Wholesale	Commodities	subsidiary),	whose	preferred	holders	also	have	protective	rights,	are	similarly	presented	between	liabilities	and equity	on	Entergy's	consolidated	balance	sheets	and	the	outstanding	preferred	securities	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana are	presented	within	total	equity	in	Entergy's	consolidated	balance	sheets.		The	preferred	dividends	or	distributions	paid	by	all	subsidiaries	are reflected	for	all	periods	presented	outside	of	consolidated	net	income.

# NOTE	2.		RATE	AND	REGULATORY	MATTERS	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

# Regulatory	Assets

# Other	Regulatory	Assets

Regulatory	assets	represent	probable	future	revenues	associated	with	costs	that	Entergy	expects	to	recover	from	customers	through	the regulatory	ratemaking	process	under	which	the	Utility	business	operates.		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"	 that	 are	 included	 on	 Entergy's	 and	 the	 Registrant Subsidiaries'	balance	sheets	as	of	December	31,	2013	and	2012:

| (Note	9)	(b) | $447.6 | $422.6 |
| :--- | :--- | :--- |
| Deferred\tcapacity\t(Note\t2\t–\tRetail\tRate\tProceedings\t–\tFilings\twith\tthe\tLPSC) | 1.2 | 6.8 |
| Grand\tGulf\tfuel\t-\tnon-current\tand\tpower\tmanagement\trider\t-\trecovered\tthrough\trate\triders\twhen |  |  |
| rates\tare\tredetermined\tperiodically\t(Note\t2\t–\tFuel\tand\tpurchased\tpower\tcost\trecovery) | 56.8 | 35.1 |
| New\tnuclear\tgeneration\tdevelopment\tcosts\t(Note\t2)\t(c) | 115.2 | 56.8 |
| Gas\thedging\tcosts\t-\trecovered\tthrough\tfuel\trates | — | 8.3 |
| Pension\t&amp;\tpostretirement\tcosts\t(Note\t11\t–\tQualified\tPension\tPlans,\tOther\tPostretirement\tBenefits,\nand\tNon-Qualified\tPension\tPlans)\t(b) | 1,723.1 | 2,866.3 |
| Provision\tfor\tstorm\tdamages,\tincluding\thurricane\tcosts\t-\trecovered\tthrough |  |  |
| securitization,\tinsurance\tproceeds,\tand\tretail\trates\t(Note\t2\t–\tStorm\tCost\tRecovery\tFilings\twith\tRetail |  |  |
| Regulators) | 786.8 | 970.8 |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(b) | 188.9 | 155.7 |
| River\tBend\tAFUDC\t-\trecovered\tthrough\tAugust\t2025\t(Note\t1\t–\t River\tBend\tAFUDC) | 20.5 | 22.4 |
| Spindletop\tgas\tstorage\tfacility\t-\trecovered\tthrough\tDecember\t2032\t(a) | 27.8 | 29.4 |
| Transition\tto\tcompetition\tcosts\t-\trecovered\tover\ta\t15-year\tperiod\tthrough\tFebruary\t2021 | 74.4 | 82.1 |
| Little\tGypsy\tcosts\t–\trecovered\tthrough\tsecuritization |  |  |
| (Note\t5\t–\tEntergy\tLouisiana\tSecuritization\tBonds\t-\tLittle\tGypsy) | 160.6 | 177.6 |
| Incremental\tice\tstorm\tcosts\t-\trecovered\tthrough\t2032 | 9.5 | 10.0 |
| Michoud\tplant\tmaintenance\t–\trecovered\tover\ta\t7-year\tperiod\tthrough\tSeptember\t2018 | 9.1 | 11.0 |
| MISO\tcosts\t-\trecovery\tthrough\tretail\trates | 74.7 | 23.8 |
| Human\tcapital\tmanagement\tcosts\t-\trecovery\tthrough\tretail\trate\tmechanisms\t(Note\t13) | 45.0 | — |
| Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 83.0 | 95.9 |
| Other | 69.2 | 51.3 |
| Total | $3,893.4 | $5,025.9 |

|  | (In	Millions) | (In	Millions) |
| :--- | :--- | :--- |
| Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\t(b) | $225.9 | $210.2 |
| Incremental\tice\tstorm\tcosts\t-\trecovered\tthrough\t2032 | 9.5 | 10.0 |
| Pension\t&amp;\tpostretirement\tcosts\t(Note\t11\t–\tQualified\tPension\tPlans,\tOther\tPostretirement\tBenefits,\nand\tNon-Qualified\tPension\tPlans)\t(b) | 517.1 | 831.2 |
| Grand\tGulf\tfuel\t-\tnon-current\t-\trecovered\tthrough\trate\triders\twhen\trates\tare\tredetermined\tperiodically |  |  |
| (Note\t2\t–\tFuel\tand\tpurchased\tpower\tcost\trecovery) | 23.5 | 17.3 |
| Provision\tfor\tstorm\tdamages\t-\trecovered\teither\tthrough\tsecuritization\tor\tretail\trates\t(Note\t2\t- \tStorm |  |  |
| Cost\tRecovery\tFilings\twith\tRetail\tRegulators) | 115.2 | 115.2 |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(b) | 18.6 | — |
| MISO\tcosts\t-\trecovery\tthrough\tretail\trates\tthrough\t2018\t(c) | 30.9 | 1.1 |
| Human\tcapital\tmanagement\tcosts\t-\trecovery\tthrough\tretail\trates\tthrough\tJune\t2017\t(Note\t13)\t(c) | 22.0 | — |
| Energy\tefficiency\tcosts\t-\trecovered\tthrough\trate\triders\twhen\trates\tare\tredetermined\tperiodically | 12.5 | 2.4 |
| Transmission\tfacility\toperation\tand\tmaintenance\tcosts\t-\trecovered\tin\tbase\trates\tthrough\t2033 | 8.7 | — |
| Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 28.8 | 31.5 |
| Other | 1.7 | 2.7 |
| Entergy\tArkansas\tTotal | $1,014.4 | $1,221.6 |

# Entergy	Gulf	States	Louisiana

(a) The	jurisdictional	split	order	assigned	the	regulatory	asset	to	Entergy	Texas.		The	regulatory	asset,	however,	is	being	recovered	and amortized	at	Entergy	Gulf	States	Louisiana.		As	a	result,	a	billing	occurs	monthly	over	the	same	term	as	the	recovery	and	receipts	will	be submitted	to	Entergy	Texas.	 	Entergy	Texas	has	recorded	a	receivable	from	Entergy	Gulf	States	Louisiana	and	Entergy	Gulf	States Louisiana	has	recorded	a	corresponding	payable.

(b) Does	not	earn	a	return	on	investment,	but	is	offset	by	related	liabilities.

(c) Does	not	earn	a	return	on	investment.

# Fuel	and	purchased	power	cost	recovery

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	are allowed	to	recover	fuel	and	purchased	power	costs	through	fuel	mechanisms	included	in	electric	and	gas	rates	that	are	recorded	as	fuel	cost recovery	revenues.		The	difference	between	revenues	collected	and	the	current	fuel	and	purchased	power	costs	is	generally	recorded	as	"Deferred fuel	costs"	on	the	Utility	operating	companies'	financial	statements.		The	table	below	shows	the	amount	of	deferred	fuel	costs	as	of	December	31, 2013	and	2012	that	Entergy	expects	to	recover	(or	return	to	customers)	through	fuel	mechanisms,	subject	to	subsequent	regulatory	review.

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| Entergy\tArkansas | $68.7 | $97.3 |
| Entergy\tGulf\tStates\tLouisiana\t(a) | $109.7 | $99.2 |
| Entergy\tLouisiana\t(a) | $37.6 | $94.6 |
| Entergy\tMississippi | $38.1 | $26.5 |
| Entergy\tNew\tOrleans\t(a) | ($19.1) | $1.9 |
| Entergy\tTexas | ($4.1) | ($93.3) |

(a) 2013	and	2012	include	$100.1	million	for	Entergy	Gulf	States	Louisiana,	$68	million	for	Entergy	Louisiana,	and	$4.1	million	for	Entergy New	Orleans	of	fuel,	purchased	power,	and	capacity	costs,	which	do	not	currently	earn	a	return	on	investment	and	whose	recovery	periods are	indeterminate	but	are	expected	to	be	over	a	period	greater	than	twelve	months.

# Entergy	Arkansas

# Production	Cost	Allocation	Rider

The	APSC	approved	a	production	cost	allocation	rider	for	recovery	from	customers	of	the	retail	portion	of	the	costs	allocated	to	Entergy Arkansas	as	a	result	of	the	System	Agreement	proceedings,	which	are	discussed	in	the	"System	Agreement	Cost	Equalization	Proceedings" section	below.		These	costs	cause	an	increase	in	Entergy	Arkansas's	deferred	fuel	cost	balance	because	Entergy	Arkansas	pays	the	costs	over seven	months	but	collects	them	from	customers	over	twelve	months.

# Energy	Cost	Recovery	Rider

Entergy	Arkansas's	retail	rates	include	an	energy	cost	recovery	rider	to	recover	fuel	and	purchased	energy	costs	in	monthly	customer bills.		The	rider	utilizes	the	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-	or	under-recovery, including	carrying	charges,	of	the	energy	costs	for	the	prior	calendar	year.		The	energy	cost	recovery	rider	tariff	also	allows	an	interim	rate	request depending	upon	the	level	of	over-	or	under-recovery	of	fuel	and	purchased	energy	costs.

In	October	2005	the	APSC	initiated	an	investigation	into	Entergy	Arkansas's	interim	energy	cost	recovery	rate.		The	investigation	focused on	Entergy	Arkansas's	1)	gas	contracting,	portfolio,	and	hedging	practices;	2)	wholesale	purchases	during	the	period;	3)	management	of	the	coal inventory	at	its	coal	generation	plants;	and	4)	response	to	the	contractual	failure	of	the	railroads	to	provide	coal	deliveries.		In	March	2006	the APSC	extended	its	investigation	to	cover	the	costs	included	in	Entergy	Arkansas's	March	2006	annual	energy	cost	rate	filing,	and	a	hearing	was held	in	the	APSC	investigation	in	October	2006.

In	January	2007	the	APSC	issued	an	order	in	its	review	of	the	energy	cost	rate.		The	APSC	found	that	Entergy	Arkansas	failed	to	maintain an	adequate	coal	inventory	level	going	into	the	summer	of	2005	and	that	Entergy	Arkansas	should	be	responsible	for	any	incremental	energy	costs that	resulted	from	two	outages	caused	by	employee	and	contractor	error.		The	coal	plant	generation	curtailments	were	caused	by	railroad	delivery problems	and	Entergy	Arkansas	has	since	resolved	litigation	with	the	railroad	regarding	the	delivery	problems.		The	APSC	staff	was	directed	to perform	an	analysis	with	Entergy	Arkansas's	assistance	to	determine	the	additional	fuel	and	purchased	energy	costs	associated	with	these	findings and	file	the	analysis	within	sixty	days	of	the	order.		After	a	final	determination	of	the	costs	is	made	by	the	APSC,	Entergy	Arkansas	will	be directed	to	refund	that	amount	with	interest	to	its	customers	as	a	credit	on	the	energy	cost	recovery	rider.		Entergy	Arkansas	requested	rehearing	of the	order.

In	February	2010	the	APSC	denied	Entergy	Arkansas's	request	for	rehearing,	and	held	a	hearing	in	September	2010	to	determine	the amount	of	damages,	if	any,	that	should	be	assessed	against	Entergy	Arkansas.		A	decision	is	pending.		Entergy	Arkansas	expects	the	amount	of damages,	if	any,	to	have	an	immaterial	effect	on	its	results	of	operations,	financial	position,	or	cash	flows.

The	APSC	also	established	a	separate	docket	to	consider	the	resolved	railroad	litigation,	and	in	February	2010	it	established	a	procedural schedule	that	concluded	with	testimony	through	September	2010.		The	testimony	has	been	filed,	and	the	APSC	will	decide	the	case	based	on	the record	in	the	proceeding.

In	January	2014,	Entergy	Arkansas	filed	a	motion	with	the	APSC	relating	to	its	upcoming	March	2014	calculation	of	its	revised	energy cost	rate.	In	that	motion,	Entergy	Arkansas	requested	that	the	APSC	authorize	Entergy	Arkansas	to	exclude	 $65.9	million	of	deferred	fuel	and purchased	energy	costs	 incurred	 in	2013	from	 the	calculation	of	 its	2014	revised	energy	cost	rate.	The	$65.9	million	 is	 an	 estimate	 of	 the incremental	fuel	and	replacement	energy	costs	that	Entergy	Arkansas	incurred	as	a	result	of	the	ANO	stator	incident.	Entergy	Arkansas	requested that	the	APSC	authorize	Entergy	Arkansas	to	retain	that	amount	in	its	deferred	fuel	balance,	with	recovery	to	be	reviewed	in	a	later	period	after more	information	is	available	regarding	various	claims	associated	with	the	ANO	stator	incident.	The	APSC	approved	Entergy	Arkansas's	request in	February	2014.	See	the	"ANO	Damage	and	Outage"	section	in	Note	8	to	the	financial	statements	for	further	discussion	of	the	ANO	stator incident.

# Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana

Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	recover	electric	fuel	and	purchased	power	costs	for	the	billing	month	based	upon	the level	of	such	costs	incurred	two	months	prior	to	the	billing	month.	Entergy	Gulf	States	Louisiana's	purchased	gas	adjustments	include	estimates for	the	billing	month	adjusted	by	a	surcharge	or	credit	that	arises	from	an	annual	reconciliation	of	fuel	costs	incurred	with	fuel	cost	revenues	billed to	customers,	including	carrying	charges.

In	January	2003	the	LPSC	authorized	its	staff	to	initiate	a	proceeding	to	audit	the	fuel	adjustment	clause	filings	of	Entergy	Gulf	States Louisiana	and	its	affiliates.		The	audit	included	a	review	of	the	reasonableness	of	charges	flowed	by	Entergy	Gulf	States	Louisiana	through	its	fuel adjustment	clause	for	the	period	1995	through	2004.		Entergy	Gulf	States	Louisiana	and	the	LPSC	Staff	reached	a	settlement	to	resolve	the	audit that	required	Entergy	Gulf	States	Louisiana	to	refund	$18	million	to	customers,	including	the	realignment	to	base	rates	of	 $2	million	of	SO2 costs.		The	ALJ	held	a	stipulation	hearing	and	in	November	2011	the	LPSC	issued	an	order	approving	the	settlement.		The	refund	was	made	in	the November	2011	billing	cycle.		Entergy	Gulf	States	Louisiana	had	previously	recorded	provisions	for	the	estimated	outcome	of	this	proceeding.

In	December	2011	the	LPSC	authorized	its	staff	to	initiate	another	proceeding	to	audit	the	fuel	adjustment	clause	filings	of	Entergy	Gulf States	Louisiana	and	its	affiliates.		The	audit	includes	a	review	of	the	reasonableness	of	charges	flowed	by	Entergy	Gulf	States	Louisiana	through its	fuel	adjustment	clause	for	the	period	2005	through	2009.		Discovery	is	in	progress,	but	a	procedural	schedule	has	not	been	established.

In	April	2010	the	LPSC	authorized	its	staff	to	initiate	an	audit	of	Entergy	Louisiana's	fuel	adjustment	clause	filings.		The	audit	includes	a review	of	the	reasonableness	of	charges	flowed	through	the	fuel	adjustment	clause	by	Entergy	Louisiana	for	the	period	from	2005	through 2009.		The	LPSC	Staff	issued	its	audit	report	in	January	2013.		The	LPSC	staff	recommended	that	Entergy	Louisiana	refund	approximately	$1.9 million,	plus	interest,	to	customers	and	realign	the	recovery	of	approximately	 $1.0	million	from	Entergy	Louisiana's	fuel	adjustment	clause	to	base rates.		The	recommended	refund	was	made	by	Entergy	Louisiana	in	May	2013	in	the	form	of	a	credit	to	customers	through	its	fuel	adjustment clause	filing.	Two	parties	intervened	in	the	proceeding.	A	procedural	schedule	was	established	for	the	identification	of	issues	by	the	intervenors and	for	Entergy	Louisiana	to	submit	comments	regarding	the	LPSC	Staff	report	and	any	issues	raised	by	intervenors.	One	intervenor	is	seeking further	proceedings	regarding	certain	issues	it	raised	in	its	comments	on	the	LPSC	Staff	report.	Entergy	Louisiana	has	filed	responses	to	both	the LPSC	Staff	report	and	the	issues	raised	by	the	intervenor.	As	required	by	the	procedural	schedule,	a	joint	status	report	was	submitted	in

October	2013	by	the	parties.	A	status	conference	was	held	in	December	2013.	Discovery	is	in	progress,	but	a	procedural	schedule	has	not	been established.

# Entergy	Mississippi

Entergy	Mississippi's	rate	schedules	include	an	energy	cost	recovery	rider	that,	effective	January	1,	2013,	is	adjusted	annually	to	reflect accumulated	over-	or	under-recoveries.		Entergy	Mississippi's	fuel	cost	recoveries	are	subject	to	annual	audits	conducted	pursuant	to	the	authority of	the	MPSC.

# Mississippi	Attorney	General	Complaint

The	Mississippi	attorney	general	filed	a	complaint	in	state	court	in	December	2008	against	Entergy	Corporation,	Entergy	Mississippi, Entergy	Services,	and	Entergy	Power	alleging,	among	other	things,	violations	of	Mississippi	statutes,	fraud,	and	breach	of	good	faith	and	fair dealing,	and	requesting	an	accounting	and	restitution.		The	complaint	is	wide	ranging	and	relates	to	tariffs	and	procedures	under	which	Entergy Mississippi	purchases	power	not	generated	in	Mississippi	to	meet	electricity	demand.		Entergy	believes	the	complaint	is	unfounded.		In	December 2008	the	defendant	Entergy	companies	removed	the	attorney	general's	lawsuit	to	U.S.	District	Court	in	Jackson,	Mississippi.		The	Mississippi attorney	general	moved	to	remand	the	matter	to	state	court.		In	August	2012	the	District	Court	issued	an	opinion	denying	the	Attorney	General's motion	for	remand,	finding	that	the	District	Court	has	subject	matter	jurisdiction	under	the	Class	Action	Fairness	Act.

The	defendant	Entergy	companies	answered	the	complaint	and	filed	a	counterclaim	for	relief	based	upon	the	Mississippi	Public	Utilities Act	and	the	Federal	Power	Act.		In	May	2009	the	defendant	Entergy	companies	filed	a	motion	for	judgment	on	the	pleadings	asserting	grounds	of federal	preemption,	the	exclusive	jurisdiction	of	the	MPSC,	and	factual	errors	in	the	attorney	general's	complaint.		In	September	2012	the	District Court	heard	oral	argument	on	Entergy's	motion	for	judgment	on	the	pleadings.		The	District	Court's	ruling	on	the	motion	for	judgment	on	the pleadings	is	pending.

In	January	2014	the	U.S.	Supreme	Court	issued	a	decision	in	which	it	held	that	cases	brought	by	attorneys	general	as	the	sole	plaintiff	to enforce	state	laws	were	not	subject	to	the	federal	law	that	allowed	federal	courts	to	hear	those	cases	as	"mass	action"	lawsuits.	One	day	later	the Attorney	General	renewed	its	motion	to	remand	the	Entergy	case	back	to	state	court,	citing	the	U.S.	Supreme	Court's	decision.	The	defendant Entergy	companies	have	responded	to	that	motion	and	the	District	Court	held	oral	argument	on	the	motion	to	remand	in	February	2014.	Entergy also	has	asserted	federal	question	jurisdiction	as	a	basis	for	the	district	court	having	jurisdiction	and	also	has	pending	the	motion	for	judgment	on the	pleadings.

# Entergy	New	Orleans

Entergy	New	Orleans's	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.

Entergy	New	Orleans's	gas	rate	schedules	include	a	purchased	gas	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.

# Entergy	Texas

Entergy	Texas's	rate	schedules	include	a	fixed	fuel	factor	to	recover	fuel	and	purchased	power	costs,	including	interest,	not	recovered	in base	rates.		Semi-annual	revisions	of	the	fixed	fuel	factor	are	made	in	March	and	September

based	on	the	market	price	of	natural	gas	and	changes	in	fuel	mix.		The	amounts	collected	under	Entergy	Texas's	fixed	fuel	factor	and	any	interim surcharge	or	refund	are	subject	to	fuel	reconciliation	proceedings	before	the	PUCT.

In	 December	 2010,	 Entergy	 Texas	 filed	 with	 the	 PUCT	 a	 request	 to	 refund	 fuel	 cost	 recovery	 over-collections	 through	 October 2010.		Pursuant	to	a	stipulation	among	the	parties	that	was	approved	by	the	PUCT	in	March	2011,	Entergy	Texas	refunded	over-collections through	November	2010	of	approximately	$73	million,	including	interest	through	the	refund	period.		The	refund	was	made	for	most	customers over	a	three-month	period	that	began	with	the	February	2011	billing	cycle.

In	December	2011,	Entergy	Texas	filed	with	the	PUCT	a	request	to	refund	approximately	 $43	million,	including	interest,	of	fuel	cost recovery	over-collections	through	October	2011.		Entergy	Texas	and	the	parties	to	the	proceeding	reached	an	agreement	that	Entergy	Texas	would refund	$67	million,	including	interest	and	additional	over-recoveries	through	December	2011,	over	a	three-month	period.		Entergy	Texas	and	the parties	requested	that	interim	rates	consistent	with	the	settlement	be	approved	effective	with	the	March	2012	billing	month,	and	the	PUCT approved	the	application	in	March	2012.		Entergy	Texas	completed	this	refund	to	customers	in	May	2012.

In	October	2012,	Entergy	Texas	filed	with	the	PUCT	a	request	to	refund	approximately	 $78	million,	including	interest,	of	fuel	cost recovery	over-collections	through	September	2012.		Entergy	Texas	requested	that	the	refund	be	implemented	over	a	six-month	period	effective with	the	January	2013	billing	month.		Entergy	Texas	and	the	parties	to	the	proceeding	reached	an	agreement	that	Entergy	Texas	would	refund	$84 million,	including	interest	and	additional	over-recoveries	through	October	2012,	to	most	customers	over	a	three-month	period	beginning	January 2013.		The	PUCT	approved	the	stipulation	in	January	2013.	Entergy	Texas	completed	this	refund	to	customers	in	March	2013.

In	July	2012,	Entergy	Texas	filed	with	the	PUCT	an	application	to	credit	its	customers	approximately	 $37.5	million,	including	interest, resulting	from	the	FERC's	October	2011	order	in	the	System	Agreement	rough	production	cost	equalization	proceeding	which	is	discussed	below in	"System	Agreement	Cost	Equalization	Proceedings."		In	September	2012	the	parties	submitted	a	stipulation	resolving	the	proceeding.		The stipulation	provided	that	most	Entergy	Texas	customers	would	be	credited	over	a	four-month	period	beginning	October	2012.		The	credits	were initiated	with	the	October	2012	billing	month	on	an	interim	basis,	and	the	PUCT	subsequently	approved	the	stipulation,	also	in	October	2012.

At	the	PUCT's	April	2013	open	meeting,	the	PUCT	Commissioners	discussed	their	view	that	a	purchased	power	capacity	rider	was	good public	policy.	The	PUCT	issued	an	order	in	May	2013	adopting	the	rule	allowing	for	a	purchased	power	capacity	rider,	subject	to	an	offsetting adjustment	for	load	growth.	The	rule,	as	adopted,	also	includes	a	process	for	obtaining	pre-approval	by	the	PUCT	of	purchased	power	agreements. Entergy	Texas	has	not	exercised	the	option	to	recover	its	capacity	costs	under	the	new	rider	mechanism	due	to	the	pending	base	rate	case	filed with	the	PUCT	in	September	2013,	but	will	continue	to	evaluate	the	benefits	of	utilizing	the	new	rider	to	recover	future	capacity	costs.

# Retail	Rate	Proceedings

# Filings	with	the	APSC	(Entergy	Arkansas)

# Retail	Rates

# 2013	Base	Rate	Filing

In	March	2013,	Entergy	Arkansas	filed	with	the	APSC	for	a	general	change	in	rates,	charges,	and	tariffs.	The	filing	assumed	Entergy Arkansas's	 transition	 to	 MISO	 in	 December	 2013,	 and	 requested	 a	 rate	 increase	 of	$174	 million,	 including	$49	 million	 of	 revenue	 being transferred	from	collection	in	riders	to	base	rates.	The	filing	also	proposed	a	new	transmission	rider	and	a	capacity	cost	recovery	rider.	The	filing requested	a	10.4%	return	on	common	equity.	In	September	2013,	Entergy	Arkansas	filed	testimony	reflecting	an	updated	rate	increase	request	of $145	million,	with

no	change	to	its	requested	return	on	common	equity	of	10.4%.	Hearings	in	the	proceeding	began	in	October	2013,	and	in	December	2013	the APSC	issued	an	order.	The	order	authorizes	a	base	rate	increase	of	$81	million	and	includes	an	authorized	return	on	common	equity	of	9.3%.	The order	allows	Entergy	Arkansas	to	amortize	its	human	capital	management	costs	over	a	three-and-a-half	year	period,	but	also	orders	Entergy Arkansas	 to	 file	 a	 detailed	 report	 of	 the	Arkansas-specific	 costs,	 savings	 and	 final	 payroll	 changes	 upon	 conclusion	 of	 the	 human	 capital management	initiative.	The	substance	of	the	report	will	be	addressed	in	Entergy	Arkansas's	next	base	rate	filing.	New	rates	will	be	implemented	in the	first	billing	cycle	of	March	2014	and	are	effective	as	of	January	2014.	Additionally,	in	January	2014,	Entergy	Arkansas	filed	a	petition	for rehearing	or	clarification	of	several	aspects	of	the	APSC's	order,	including	the	9.3%	authorized	return	on	common	equity.	In	February	2014	the APSC	granted	Entergy	Arkansas's	petition	for	the	purpose	of	further	consideration.

# Filings	with	the	LPSC

# Retail	Rates	-	Electric

In	May	2011,	Entergy	Gulf	States	Louisiana	made	a	special	formula	rate	plan	rate	implementation	filing	with	the	LPSC	that	implemented effective	with	the	May	2011	billing	cycle	a	$5.1	million	rate	decrease	to	reflect	adjustments	in	accordance	with	a	previous	LPSC	order	relating	to the	acquisition	of	Unit	2	of	the	Acadia	Energy	Center	by	Entergy	Louisiana.		As	a	result	of	the	closing	of	the	acquisition	and	termination	of	the pre-acquisition	power	purchase	agreement	with	Acadia,	Entergy	Gulf	States	Louisiana's	allocation	of	capacity	related	to	this	unit	ended,	resulting in	a	reduction	in	the	additional	capacity	revenue	requirement.

In	May	2011,	Entergy	Gulf	States	Louisiana	made	its	formula	rate	plan	filing	with	the	LPSC	for	the	2010	test	year.		The	filing	reflected	an 11.11%	earned	return	on	common	equity,	which	was	within	the	allowed	earnings	bandwidth,	indicating	no	cost	of	service	rate	change	was necessary	under	the	formula	rate	plan.		The	filing	also	reflected	a	$22.8	million	rate	decrease	for	incremental	capacity	costs.		Entergy	Gulf	States Louisiana	and	the	LPSC	Staff	subsequently	filed	a	joint	report	that	also	stated	that	no	cost	of	service	rate	change	was	necessary	under	the	formula rate	plan,	and	the	LPSC	approved	it	in	October	2011.

In	November	2011	the	LPSC	approved	a	one-year	extension	of	Entergy	Gulf	States	Louisiana's	formula	rate	plan.		In	May	2012,	Entergy Gulf	States	Louisiana	made	its	formula	rate	plan	filing	with	the	LPSC	for	the	2011	test	year.		The	filing	reflected	an	11.94%	earned	return	on common	equity,	which	was	above	the	earnings	bandwidth	and	indicated	a	$6.5	million	cost	of	service	rate	decrease	was	necessary	under	the formula	rate	plan.		The	filing	also	reflected	a	$22.9	million	rate	decrease	for	the	incremental	capacity	rider.		Subsequently,	in	August	2012, Entergy	Gulf	States	Louisiana	submitted	a	revised	filing	that	reflected	an	earned	return	on	common	equity	of	11.86%,	which	indicated	a	$5.7 million	cost	of	service	rate	decrease	was	necessary	under	the	formula	rate	plan.		The	revised	filing	also	indicated	that	a	reduction	of	$20.3	million should	be	reflected	in	the	incremental	capacity	rider.		The	rate	reductions	were	implemented,	subject	to	refund,	effective	for	bills	rendered	the	first billing	cycle	of	September	2012.		Subsequently,	in	December	2012,	Entergy	Gulf	States	Louisiana	submitted	a	revised	evaluation	report	that reflected	expected	retail	jurisdictional	cost	of	$16.9	million	for	the	first-year	capacity	charges	for	the	purchase	from	Entergy	Louisiana	of	one- third	of	Acadia	Unit	2	capacity	and	energy.		This	rate	change	was	implemented	effective	with	the	first	billing	cycle	of	January	2013.		The	2011	test year	 filings,	 as	 revised,	 were	 approved	 by	 the	 LPSC	 in	 February	 2013.	In	April	 2013,	 Entergy	 Gulf	 States	 Louisiana	 submitted	 a	 revised evaluation	report	increasing	the	incremental	capacity	rider	by	approximately	$7.3	million	to	reflect	the	cost	of	an	additional	capacity	contract.

In	connection	with	its	decision	to	extend	the	formula	rate	plan	to	the	2011	test	year,	the	LPSC	required	that	a	base	rate	case	be	filed	by Entergy	Gulf	States	Louisiana,	and	the	required	filing	was	made	on	February	15,	2013.	The	filing	anticipated	Entergy	Gulf	States	Louisiana's integration	into	MISO.	In	the	filing	Entergy	Gulf	States	Louisiana	requested,	among	other	relief:

•authorization	to	increase	the	revenue	it	collects	from	customers	by	approximately	$24	million;

•an	authorized	return	on	common	equity	of	10.4%;

•authorization	to	increase	depreciation	rates	embedded	in	the	proposed	revenue	requirement;	and,

•authorization	to	implement	a	three-year	formula	rate	plan	with	a	midpoint	return	on	common	equity	of	 10.4%,	plus	or	minus	75	basis points	(the	deadband),	that	would	provide	a	means	for	the	annual	re-setting	of	rates	(commencing	with	calendar	year	2013	as	its	first	test year),	that	would	include	a	mechanism	to	recover	incremental	transmission	revenue	requirement	on	the	basis	of	a	forward-looking	test year	as	compared	to	the	initial	base	year	of	2014	with	an	annual	true-up,	that	would	retain	the	primary	aspects	of	the	prior	formula	rate plan,	including	a	60%	to	customers/40%	to	Entergy	Gulf	States	Louisiana	sharing	mechanism	for	earnings	outside	the	deadband,	and	a capacity	rider	mechanism	that	would	permit	recovery	of	incremental	capacity	additions	approved	by	the	LPSC.

Following	a	hearing	before	an	ALJ	and	 the	ALJ's	 issuance	of	a	Report	of	Proceedings,	 in	December	2013	 the	LPSC	approved	an unopposed	settlement	of	the	proceeding.	Major	terms	of	the	settlement	include	approval	of	a	three-year	formula	rate	plan	(effective	for	test	years 2014-2016)	modeled	after	the	formula	rate	plan	in	effect	for	Entergy	Gulf	States	Louisiana	for	2011,	including	the	following:	(1)	a	midpoint	return on	equity	of	9.95%	plus	or	minus	80	basis	points,	with	60/40	sharing	of	earnings	outside	of	the	bandwidth;	(2)	recovery	outside	of	the	sharing mechanism	for	the	non-fuel	MISO-related	costs,	additional	capacity	revenue	requirement,	extraordinary	items,	such	as	the	Ninemile	6	project,	and certain	special	recovery	items;	(3)	three-year	amortization	of	costs	to	achieve	savings	associated	with	the	human	capital	management	initiative, with	savings	to	be	reflected	as	they	are	realized	in	subsequent	years;	(4)	eight-year	amortization	of	costs	incurred	in	connection	with	potential development	of	a	new	nuclear	unit	at	River	Bend,	without	carrying	costs,	beginning	December	2014,	provided,	however,	that	amortization	of these	costs	shall	not	result	in	a	future	rate	increase;	(5)	no	change	in	rates	related	to	test	year	2013,	except	with	respect	to	recovery	of	the	non-fuel MISO-related	costs	and	any	changes	to	the	additional	capacity	revenue	requirement;	and	(6)	no	increase	in	rates	related	to	test	year	2014,	except for	those	items	eligible	for	recovery	outside	of	the	earnings	sharing	mechanism.	Existing	depreciation	rates	will	not	change.	Implementation	of rate	changes	for	items	recoverable	outside	of	the	earnings	sharing	mechanism	will	occur	in	December	2014.

# (Entergy	Louisiana)

In	May	2011,	Entergy	Louisiana	made	a	special	formula	rate	plan	rate	implementation	filing	with	the	LPSC	that	implemented,	effective with	the	May	2011	billing	cycle,	a	$43.1	million	net	rate	increase	to	reflect	adjustments	in	accordance	with	a	previous	LPSC	order	relating	to	the acquisition	of	Unit	2	of	the	Acadia	Energy	Center.		The	net	rate	increase	represented	the	decrease	in	the	additional	capacity	revenue	requirement resulting	from	the	termination	of	the	power	purchase	agreement	with	Acadia	and	the	increase	in	the	revenue	requirement	resulting	from	the ownership	of	the	Acadia	facility.		In	August	2011,	Entergy	Louisiana	made	a	filing	to	correct	the	May	2011	filing	and	decrease	the	rate	by	 $1.1 million.

In	May	2011,	Entergy	Louisiana	made	its	formula	rate	plan	filing	with	the	LPSC	for	the	2010	test	year.		The	filing	reflected	an	11.07% earned	return	on	common	equity,	which	is	just	outside	of	the	allowed	earnings	bandwidth	and	results	in	no	cost	of	service	rate	change	under	the formula	rate	plan.		The	filing	also	reflected	a	very	slight	($9	thousand)	rate	increase	for	incremental	capacity	costs.		Entergy	Louisiana	and	the LPSC	Staff	subsequently	filed	a	joint	report	that	reflected	an	11.07%	earned	return	and	resulted	in	no	cost	of	service	rate	change	under	the	formula rate	plan,	and	the	LPSC	approved	the	joint	report	in	October	2011.

In	November	2011	the	LPSC	approved	a	one-year	extension	of	Entergy	Louisiana's	formula	rate	plan.		In	May	2012,	Entergy	Louisiana made	its	formula	rate	plan	filing	with	the	LPSC	for	the	2011	test	year.		The	filing	reflected	a	9.63%	earned	return	on	common	equity,	which	is within	the	earnings	bandwidth	and	resulted	in	no	cost	of	service	rate	change	under	the	formula	rate	plan.		The	filing	also	reflected	an	$18.1	million rate	increase	for	the	incremental	capacity	rider.		In	August	2012,	Entergy	Louisiana	submitted	a	revised	filing	that	reflected	an	earned	return	on common	 equity	 of	10.38%,	which	is	still	within	the	earnings	bandwidth,	resulting	in	no	cost	of	service	rate	change.		The	revised	filing	also indicated	that	an	increase	of	$15.9	million	should	be	reflected	in	the	incremental	capacity	rider.		The	rate	change

was	implemented,	subject	to	refund,	effective	for	bills	rendered	the	first	billing	cycle	of	September	2012.		Subsequently,	in	December	2012, Entergy	Louisiana	submitted	a	revised	evaluation	report	that	reflected	two	items:	1)	a	$17	million	reduction	for	the	first-year	capacity	charges	for the	purchase	by	Entergy	Gulf	States	Louisiana	from	Entergy	Louisiana	of	one-third	of	Acadia	Unit	2	capacity	and	energy,	and	2)	an	 $88	million increase	for	the	first-year	retail	revenue	requirement	associated	with	the	Waterford	3	replacement	steam	generator	project,	which	was	in-service	in December	2012.		These	rate	changes	were	implemented,	subject	to	refund,	effective	with	the	first	billing	cycle	of	January	2013.		In	April	2013, Entergy	Louisiana	and	the	LPSC	staff	filed	a	joint	report	resolving	the	2011	test	year	formula	rate	plan	and	recovery	related	to	the	Grand	Gulf uprate.	This	report	was	approved	by	the	LPSC	in	April	2013.	With	completion	of	the	Waterford	3	replacement	steam	generator	project,	the	LPSC is	conducting	a	prudence	review	in	connection	with	a	filing	made	by	Entergy	Louisiana	in	April	2013	with	regard	to	the	following	aspects	of	the replacement	project:	1)	project	management;	2)	cost	controls;	3)	success	in	achieving	stated	objectives;	4)	the	costs	of	the	replacement	project; and	5)	the	outage	length	and	replacement	power	costs.	An	evidentiary	hearing	is	scheduled	for	November	2014.

In	connection	with	its	decision	to	extend	the	formula	rate	plan	to	the	2011	test	year,	the	LPSC	required	that	a	base	rate	case	be	filed	by Entergy	Louisiana,	and	the	required	filing	was	made	on	February	15,	2013.	The	filing	anticipated	Entergy	Louisiana's	integration	into	MISO.	In the	filing	Entergy	Louisiana	requested,	among	other	relief:

•authorization	to	increase	the	revenue	it	collects	from	customers	by	approximately	$145	million	(which	does	not	take	into	account	a revenue	offset	of	approximately	$2	million	resulting	from	a	proposed	increase	for	those	customers	taking	service	under	the	Qualifying Facility	Standby	Service);

•authorization	to	implement	a	three-year	formula	rate	plan	with	a	midpoint	return	on	common	equity	of	10.4%,	plus	or	minus	75	basis points	(the	deadband),	that	would	provide	a	means	for	the	annual	re-setting	of	rates	(commencing	with	calendar	year	2013	as	its	first	test year),	that	would	include	a	mechanism	to	recover	incremental	transmission	revenue	requirement	on	the	basis	of	a	forward-looking	test year	as	compared	to	the	initial	base	year	of	2014	with	an	annual	true-up,	that	would	retain	the	primary	aspects	of	the	prior	formula	rate plan,	including	a	60%	to	customers/40%	to	Entergy	Louisiana	sharing	mechanism	for	earnings	outside	the	deadband,	and	a	capacity	rider mechanism	that	would	permit	recovery	of	incremental	capacity	additions	approved	by	the	LPSC.

Following	a	hearing	before	an	ALJ	and	 the	ALJ's	 issuance	of	a	Report	of	Proceedings,	 in	December	2013	 the	LPSC	approved	an unopposed	settlement	of	the	proceeding.	The	settlement	provides	for	a	$10	million	rate	increase	effective	with	the	first	billing	cycle	of	December 2014.	Major	terms	of	the	settlement	include	approval	of	a	three-year	formula	rate	plan	(effective	for	test	years	2014-2016)	modeled	after	the formula	rate	plan	in	effect	for	Entergy	Louisiana	for	2011,	including	the	following:	(1)	a	midpoint	return	on	equity	of	9.95%	plus	or	minus	80 basis	points,	with	60/40	sharing	of	earnings	outside	of	the	bandwidth;	(2)	recovery	outside	of	the	sharing	mechanism	for	the	non-fuel	MISO- related	costs,	additional	capacity	revenue	requirement,	extraordinary	items,	such	as	the	Ninemile	6	project,	and	certain	special	recovery	items;	(3) three-year	amortization	of	costs	to	achieve	savings	associated	with	the	human	capital	management	initiative,	with	savings	reflected	as	they	are realized	in	subsequent	years;	(4)	eight-year	amortization	of	costs	incurred	in	connection	with	potential	development	of	a	new	nuclear	unit	at	River Bend,	without	carrying	costs,	beginning	December	2014,	provided,	however,	that	amortization	of	these	costs	shall	not	result	in	a	future	rate increase;	(5)	recovery	of	non-fuel	MISO-related	costs	and	any	changes	to	the	additional	capacity	revenue	requirement	related	to	test	year	2013 effective	with	the	first	billing	cycle	of	December	2014;	and	(6)	a	cumulative	$30	million	cap	on	cost	of	service	increases	over	the	three-year formula	rate	plan	cycle,	except	for	those	items	outside	of	the	sharing	mechanism.	Existing	depreciation	rates	will	not	change.

# Retail	Rates	-	Gas	(Entergy	Gulf	States	Louisiana)

In	January	2014,	Entergy	Gulf	States	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2013.	 	The	filing	showed	an	earned	return	on	common	equity	of	5.47%,	which	results	 in	a	$1.5	million	 rate	 increase.	The	rate	 increase,	 if approved,	will	be	effective	with	the	first	billing	cycle	of	April	2014.

In	January	2013,	Entergy	Gulf	States	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2012.		The	filing	showed	an	earned	return	on	common	equity	of	11.18%,	which	results	in	a	$43	thousand	rate	reduction.		In	March	2013	the LPSC	Staff	issued	its	proposed	findings	and	recommended	two	adjustments.	Entergy	Gulf	States	Louisiana	and	the	LPSC	Staff	reached	agreement regarding	the	LPSC	Staff's	proposed	adjustments.	As	reflected	in	an	unopposed	joint	report	of	proceedings	filed	by	Entergy	Gulf	States	Louisiana and	the	LPSC	Staff	in	May	2013,	Entergy	Gulf	States	Louisiana	accepted,	with	modification,	the	LPSC	Staff's	proposed	adjustment	to	property insurance	expense	and	agreed	to:	(1)	a	three-year	extension	of	the	gas	rate	stabilization	plan	with	a	midpoint	return	on	equity	of	9.95%,	with	a	first year	midpoint	reset;	(2)	dismissal	of	a	docket	initiated	by	the	LPSC	to	evaluate	the	allowed	return	on	equity	for	Entergy	Gulf	States	Louisiana's gas	rate	stabilization	plan;	and	(3)	presentation	to	the	LPSC	by	November	2014	by	Entergy	Gulf	States	Louisiana	and	the	LPSC	Staff	of	their recommendation	for	 implementation	of	an	 infrastructure	rider	 to	recover	expenditures	associated	with	strategic	plant	 investment.	The	 LPSC approved	the	agreement	in	May	2013.

In	January	2012,	Entergy	Gulf	States	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2011.		The	filing	showed	an	earned	return	on	common	equity	of	10.48%,	which	is	within	the	earnings	bandwidth	of	10.5%,	plus	or	minus	fifty basis	points.		In	April	2012	the	LPSC	Staff	filed	its	findings,	suggesting	adjustments	that	produced	an	11.54%	earned	return	on	common	equity for	the	test	year	and	a	$0.1	million	rate	reduction.		Entergy	Gulf	States	Louisiana	accepted	the	LPSC	Staff's	recommendations,	and	the	rate reduction	was	effective	with	the	first	billing	cycle	of	May	2012.

In	January	2011,	Entergy	Gulf	States	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2010.		The	filing	showed	an	earned	return	on	common	equity	of	8.84%	and	a	revenue	deficiency	of	$0.3	million.		In	March	2011	the	LPSC	Staff filed	its	findings,	suggesting	an	adjustment	that	produced	an	11.76%	earned	return	on	common	equity	for	the	test	year	and	a	$0.2	million	rate reduction.		Entergy	Gulf	States	Louisiana	implemented	the	$0.2	million	rate	reduction	effective	with	the	May	2011	billing	cycle.

# Filings	with	the	MPSC	(Entergy	Mississippi)

# Formula	Rate	Plan	Filings

In	September	2009,	Entergy	Mississippi	filed	with	the	MPSC	proposed	modifications	to	its	formula	rate	plan	rider.		In	March	2010	the MPSC	issued	an	order:	(1)	providing	the	opportunity	for	a	reset	of	Entergy	Mississippi's	return	on	common	equity	to	a	point	within	the	formula rate	 plan	 bandwidth	 and	 eliminating	 the	50/50	sharing	that	had	been	in	the	plan,	(2)	modifying	the	performance	measurement	process,	and (3)	replacing	the	revenue	change	limit	of	two	percent	of	revenues,	which	was	subject	to	a	$14.5	million	revenue	adjustment	cap,	with	a	limit	of four	percent	of	revenues,	although	any	adjustment	above	two	percent	requires	a	hearing	before	the	MPSC.		The	MPSC	did	not	approve	Entergy Mississippi's	request	to	use	a	projected	test	year	for	its	annual	scheduled	formula	rate	plan	filing	and,	therefore,	Entergy	Mississippi	continued	to use	a	historical	test	year	for	its	annual	evaluation	reports	under	the	plan.

In	March	2011,	Entergy	Mississippi	submitted	its	formula	rate	plan	2010	test	year	filing.		The	filing	shows	an	earned	return	on	common equity	 of	10.65%	for	the	test	year,	which	is	within	the	earnings	bandwidth	and	results	in	no	change	in	rates.		In	November	2011	the	MPSC approved	a	joint	stipulation	between	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	that	provides	for	no	change	in	rates.

In	March	2012,	Entergy	Mississippi	submitted	its	formula	rate	plan	filing	for	the	2011	test	year.		The	filing	shows	an	earned	return	on common	equity	of	10.92%	for	the	test	year,	which	is	within	the	earnings	bandwidth	and	results	in	no	change	in	rates.		In	February	2013	the	MPSC approved	a	joint	stipulation	between	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	that	provides	for	no	change	in	rates.

In	March	2013,	Entergy	Mississippi	submitted	its	formula	rate	plan	filing	for	the	2012	test	year.	The	filing	requested	a	$36.3	million revenue	increase	to	reset	Entergy	Mississippi's	return	on	common	equity	to	10.55%,	which	is	a	point	within	the	formula	rate	plan	bandwidth.	In June	2013,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities

Staff	entered	into	a	joint	stipulation,	in	which	both	parties	agreed	that	the	MPSC	should	approve	a	 $22.3	million	rate	increase	for	Entergy Mississippi	which,	with	other	adjustments	reflected	in	the	stipulation,	would	have	the	effect	of	resetting	Entergy	Mississippi's	return	on	common equity	to	10.59%	when	adjusted	for	performance	under	the	formula	rate	plan.	In	August	2013	the	MPSC	approved	the	joint	stipulation	between Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	authorizing	the	rate	increase	effective	with	September	2013	bills.		Additionally,	the MPSC	authorized	Entergy	Mississippi	to	defer	approximately	$1.2	million	in	MISO-related	implementation	costs	incurred	in	2012	along	with other	MISO-related	implementation	costs	incurred	in	2013.

# Filings	with	the	City	Council

In	March	2013,	Entergy	Louisiana	filed	a	rate	case	for	the	Algiers	area,	which	is	in	New	Orleans	and	is	regulated	by	the	City	Council. Entergy	Louisiana	is	requesting	a	rate	increase	of	$13	million	over	three	years,	including	a	10.4%	return	on	common	equity	and	a	formula	rate plan	mechanism	identical	to	its	LPSC	request.	In	January	2014,	the	City	Council	Advisors	filed	direct	testimony	recommending	a	rate	increase	of $5.56	million	 over	three	years,	including	an	8.13%	return	on	common	equity.	Hearings	are	scheduled	for	April	2014.	New	rates	are	currently expected	to	become	effective	in	second	quarter	2014.

# Formula	Rate	Plan

In	April	 2009	 the	 City	 Council	 approved	 a	 three-year	 formula	 rate	 plan	 for	 Entergy	 New	 Orleans,	 with	 terms	 including	 an	11.1% benchmark	electric	return	on	common	equity	(ROE)	with	a	+/-40	basis	point	bandwidth	and	a	10.75%	benchmark	gas	ROE	with	a	+/- 50	basis point	bandwidth.		Earnings	outside	the	bandwidth	reset	to	the	midpoint	benchmark	ROE,	with	rates	changing	on	a	prospective	basis	depending	on whether	Entergy	New	Orleans	was	over-	or	under-earning.		The	formula	rate	plan	also	included	a	recovery	mechanism	for	City	Council-approved capacity	additions,	plus	provisions	for	extraordinary	cost	changes	and	force	majeure	events.

In	May	2011,	Entergy	New	Orleans	filed	its	electric	and	gas	formula	rate	plan	evaluation	reports	for	the	2010	test	year.		The	filings requested	a	$6.5	million	electric	rate	decrease	and	a	$1.1	million	gas	rate	decrease.		Entergy	New	Orleans	and	the	City	Council's	Advisors	reached a	settlement	that	resulted	in	an	$8.5	million	incremental	electric	rate	decrease	and	a	$1.6	million	gas	rate	decrease.		The	settlement	also	provided for	the	deferral	of	$13.4	million	of	Michoud	plant	maintenance	expenses	incurred	in	2010	and	the	establishment	of	a	regulatory	asset	that	will	be amortized	over	the	period	October	2011	through	September	2018.		The	City	Council	approved	the	settlement	in	September	2011.		The	new	rates were	effective	with	the	first	billing	cycle	of	October	2011.

In	May	2012,	Entergy	New	Orleans	filed	its	electric	and	gas	formula	rate	plan	evaluation	reports	for	the	2011	test	year.		Subsequent adjustments	agreed	upon	with	the	City	Council	Advisors	indicate	a	$4.9	million	electric	base	revenue	increase	and	a	$0.05	million	gas	base revenue	increase	as	necessary	under	the	formula	rate	plan.		As	part	of	the	original	filing,	Entergy	New	Orleans	also	requested	to	increase	annual funding	for	its	storm	reserve	by	approximately	$5.7	million	for	five	years.		On	September	26,	2012,	Entergy	New	Orleans	made	a	filing	with	the City	 Council	 that	 implemented	 the	$4.9	 million	 electric	 formula	 rate	 plan	 rate	 increase	 and	 the	$0.05	 million	 gas	 formula	 rate	 plan	 rate increase.		The	new	rates	were	effective	with	the	first	billing	cycle	in	October	2012.		In	August	2013	the	City	Council	unanimously	approved	a settlement	of	all	issues	in	the	formula	rate	plan	proceeding.		Pursuant	to	the	terms	of	the	settlement,	Entergy	New	Orleans	implemented	 an approximately	$1.625	million	net	decrease	to	the	electric	rates	that	were	in	effect	prior	to	the	electric	rate	increase	implemented	in	October	2012, with	no	change	in	gas	rates.		Entergy	New	Orleans	refunded	to	customers	approximately	$6.0	million	over	the	four-month	period	from	September 2013	through	December	2013	to	make	the	electric	rate	decrease	effective	as	of	the	first	billing	cycle	of	October	2012.		Entergy	New	Orleans	had previously	recorded	provisions	for	the	majority	of	the	refund	to	customers,	but	recorded	an	additional	$1.1	million	provision	in	second	quarter 2013	as	a	result	of	the	settlement.	The	City	Council	has	not	yet	acted	on

Entergy	New	Orleans's	request	for	an	increase	in	storm	reserve	funding.		Entergy	New	Orleans's	formula	rate	plan	ended	with	the	2011	test	year and	has	not	yet	been	extended.		Entergy	New	Orleans	expects	to	initiate	a	rate	proceeding	prior	to	the	in-service	date	of	the	Ninemile	6	generating facility.

A	2008	rate	case	settlement	included	 $3.1	million	per	year	in	electric	rates	to	fund	the	Energy	Smart	energy	efficiency	programs.		In September	2009	the	City	Council	approved	the	energy	efficiency	programs	filed	by	Entergy	New	Orleans.		The	rate	settlement	provides	an incentive	for	Entergy	New	Orleans	to	meet	or	exceed	energy	savings	targets	set	by	the	City	Council	and	provides	a	mechanism	for	Entergy	New Orleans	to	recover	lost	contribution	to	fixed	costs	associated	with	the	energy	savings	generated	from	the	energy	efficiency	programs.	In	October 2013	the	City	Council	approved	the	extension	of	the	current	Energy	Smart	program	through	December	2014.	The	City	Council	approved	the	use of	$3.5	million	for	program	costs.	In	addition,	Entergy	New	Orleans	will	be	allowed	to	recover	its	lost	contribution	to	fixed	costs	and	to	earn	an incentive	for	meeting	program	goals.

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

In	December	2009,	Entergy	Texas	filed	a	rate	case	requesting	a	 $198.7	million	increase	reflecting	an	11.5%	return	on	common	equity based	on	an	adjusted	June	2009	test	year.		The	rate	case	also	included	a	$2.8	million	revenue	requirement	to	provide	supplemental	funding	for	the decommissioning	trust	maintained	for	the	70%	share	of	River	Bend	for	which	Entergy	Texas	retail	customers	are	partially	responsible,	in	response to	an	NRC	notification	of	a	projected	shortfall	of	decommissioning	funding	assurance.		Beginning	in	May	2010,	Entergy	Texas	implemented	a $17.5	million	interim	rate	increase,	subject	to	refund.		Intervenors	and	PUCT	Staff	filed	testimony	recommending	adjustments	that	would	result	in a	maximum	rate	increase,	based	on	the	PUCT	Staff's	testimony,	of	$58	million.

The	parties	filed	a	settlement	in	August	2010	intended	to	resolve	the	rate	case	proceeding.		The	settlement	provided	for	a	 $59	million	base rate	increase	for	electricity	usage	beginning	August	15,	2010,	with	an	additional	increase	of	$9	million	for	bills	rendered	beginning	May	2, 2011.		The	settlement	stipulated	an	authorized	return	on	equity	of	10.125%.		The	settlement	stated	that	Entergy	Texas's	fuel	costs	for	the	period April	2007	 through	June	2009	are	reconciled,	with	$3.25	million	of	disallowed	costs,	which	were	included	in	an	interim	fuel	refund.	 	The settlement	also	set	River	Bend	decommissioning	costs	at	$2.0	million	annually.		Consistent	with	the	settlement,	in	the	third	quarter	2010,	Entergy Texas	amortized	$11	million	of	rate	case	costs.		The	PUCT	approved	the	settlement	in	December	2010.

In	November	2011,	Entergy	Texas	filed	a	rate	case	requesting	a	 $112	million	base	rate	increase	reflecting	a	10.6%	return	on	common equity	based	on	an	adjusted	June	2011	test	year.		The	rate	case	also	proposed	a	purchased	power	recovery	rider.		On	January	12,	2012,	the	PUCT voted	not	to	address	the	purchased	power	recovery	rider	in	the	current	rate	case,	but	the	PUCT	voted	to	set	a	baseline	in	the	rate	case	proceeding that	would	be	applicable	if	a	purchased	power	capacity	rider	is	approved	in	a	separate	proceeding.		In	April	2012	the	PUCT	Staff	filed	direct testimony	recommending	a	base	rate	increase	of	$66	million	and	a	9.6%	return	on	common	equity.		The	PUCT	Staff,	however,	subsequently	filed a	statement	of	position	in	the	proceeding	indicating	that	it	was	still	evaluating	the	position	it	would	ultimately	take	in	the	case	regarding	Entergy Texas's	recovery	of	purchased	power	capacity	costs	and	Entergy	Texas's	proposal	to	defer	its	MISO	transition	expenses.		In	April	2012,	Entergy Texas	filed	rebuttal	testimony	indicating	a	revised	request	for	a	$105	million	base	rate	increase.		A	hearing	was	held	in	late-April	through	early- May	2012.

In	September	2012	the	PUCT	issued	an	order	approving	a	$28	million	rate	increase,	effective	July	2012.		The	order	includes	a	finding	that "a	return	on	common	equity	(ROE)	of	9.80	percent	will	allow	[Entergy	Texas]	a	reasonable	opportunity	to	earn	a	reasonable	return	on	invested capital."		The	order	also	provides	for	increases	in	depreciation	rates	and	the	annual	storm	reserve	accrual.		The	order	also	reduced	Entergy	Texas's proposed	purchased	power	capacity

costs,	stating	that	they	are	not	known	and	measurable;	reduced	Entergy	Texas's	regulatory	assets	associated	with	Hurricane	Rita;	excluded	from rate	recovery	capitalized	financially-based	incentive	compensation;	included	$1.6	million	of	MISO	transition	expense	in	base	rates,	and	reduced Entergy's	 Texas's	 fuel	 reconciliation	 recovery	 by	 $4	 million	 because	 it	 disagreed	 with	 the	 line-loss	 factor	 used	 in	 the	 calculation.	 	After considering	the	progress	of	the	proceeding	in	light	of	the	PUCT	order,	Entergy	Texas	recorded	in	the	third	quarter	2012	an	approximate	$24 million	charge	to	recognize	that	assets	associated	with	Hurricane	Rita,	financially-based	incentive	compensation,	and	fuel	recovery	are	no	longer probable	of	recovery.		Entergy	Texas	continues	to	believe	that	it	is	entitled	to	recover	these	prudently	incurred	costs,	however,	and	it	filed	a motion	for	rehearing	regarding	these	and	several	other	issues	in	the	PUCT's	order	on	October	4,	2012.		Several	other	parties	have	also	filed motions	for	rehearing	of	the	PUCT's	order.		The	PUCT	subsequently	denied	rehearing	of	substantive	issues.		Several	parties,	including	Entergy Texas,	have	appealed	the	PUCT's	order	to	the	Travis	County	District	Court.	A	hearing	is	expected	in	April	2014.

In	September	2013,	Entergy	Texas	filed	a	rate	case	requesting	a	 $38.6	million	base	rate	increase	reflecting	a	10.4%	return	on	common equity	based	on	an	adjusted	test	year	ending	March	31,	2013.	The	rate	case	also	proposed	(1)	a	rough	production	cost	equalization	adjustment rider	recovering	Entergy	Texas's	payment	to	Entergy	New	Orleans	to	achieve	rough	production	cost	equalization	based	on	calendar	year	2012 production	costs	and	(2)	a	rate	case	expense	rider	recovering	the	cost	of	the	2013	rate	case	and	certain	costs	associated	with	previous	rate	cases. The	rate	case	filing	also	includes	a	request	to	reconcile	$0.9	billion	of	fuel	and	purchased	power	costs	and	fuel	revenues	covering	the	period	July 2011	 through	 March	 2013.	The	 fuel	 reconciliation	 also	 reflects	 special	 circumstances	 fuel	 cost	 recovery	 of	 approximately	$22	 million	 of purchased	power	capacity	costs.	If	approved,	new	rates	could	go	into	effect	as	early	as	April	2014.	In	January	2014	the	PUCT	staff	filed	direct testimony	recommending	a	retail	rate	reduction	of	$0.3	million	and	a	9.2%	return	on	common	equity.	In	February	2014	the	ALJs	approved	a request	to	abate	the	procedural	schedule	indefinitely	while	settlement	discussions	continued.

# System	Agreement	Cost	Equalization	Proceedings

The	Utility	operating	companies	historically	have	engaged	in	the	coordinated	planning,	construction,	and	operation	of	generating	and	bulk transmission	facilities	under	the	terms	of	the	System	Agreement,	which	is	a	rate	schedule	that	has	been	approved	by	the	FERC.		Certain	of	the Utility	operating	companies'	retail	regulators	and	other	parties	are	pursuing	 litigation	 involving	 the	System	Agreement	at	 the	FERC.	 	The proceedings	include	challenges	to	the	allocation	of	costs	as	defined	by	the	System	Agreement	and	allegations	of	imprudence	by	the	Utility operating	companies	in	their	execution	of	their	obligations	under	the	System	Agreement.

In	June	2005,	the	FERC	issued	a	decision	in	System	Agreement	litigation	that	had	been	commenced	by	the	LPSC,	and	essentially	affirmed its	decision	in	a	December	2005	order	on	rehearing.		The	FERC	decision	concluded,	among	other	things,	that:

•The	System	Agreement	no	longer	roughly	equalizes	total	production	costs	among	the	Utility	operating	companies.

•In	order	to	reach	rough	production	cost	equalization,	the	FERC	imposed	a	bandwidth	remedy	by	which	each	company's	total	annual production	costs	will	have	to	be	within	+/-	11%	of	Entergy	System	average	total	annual	production	costs.

•In	calculating	the	production	costs	for	this	purpose	under	the	FERC's	order,	output	from	the	Vidalia	hydroelectric	power	plant	will	not reflect	the	actual	Vidalia	price	for	the	year	but	is	priced	at	that	year's	average	price	paid	by	Entergy	Louisiana	for	the	exchange	of	electric energy	under	Service	Schedule	MSS-3	of	the	System	Agreement,	thereby	reducing	the	amount	of	Vidalia	costs	reflected	in	the comparison	of	the	Utility	operating	companies'	total	production	costs.

•The	remedy	ordered	by	FERC	in	2005	required	no	refunds	and	became	effective	based	on	calendar	year	2006	production	costs	and	the first	reallocation	payments	were	made	in	2007.

The	FERC's	decision	reallocates	total	production	costs	of	the	Utility	operating	companies	whose	relative	total	production	costs	expressed as	a	percentage	of	Entergy	System	average	production	costs	are	outside	an	upper	or	lower	bandwidth.		Under	the	current	circumstances,	this	will be	accomplished	by	payments	from	Utility	operating	companies	whose	production	costs	are	more	than	11%	below	Entergy	System	average production	costs	to	Utility	operating	companies	whose	production	costs	are	more	than	the	Entergy	System	average	production	cost,	with	payments going	first	to	those	Utility	operating	companies	whose	total	production	costs	are	farthest	above	the	Entergy	System	average.

The	financial	consequences	of	the	FERC's	decision	are	determined	by	the	total	production	cost	of	each	Utility	operating	company,	which are	affected	by	the	mix	of	solid	fuel	and	gas-fired	generation	available	to	each	company	and	the	costs	of	natural	gas	and	purchased	power. Entergy	Louisiana,	Entergy	Gulf	States	Louisiana,	Entergy	Texas,	and	Entergy	Mississippi	are	more	dependent	upon	gas-fired	generation	sources than	Entergy	Arkansas	or	Entergy	New	Orleans.		Of	these,	Entergy	Arkansas	is	the	least	dependent	upon	gas-fired	generation	sources.		Therefore, increases	in	natural	gas	prices	generally	increased	the	amount	by	which	Entergy	Arkansas's	total	production	costs	were	below	the	Entergy	System average	production	costs.

The	LPSC,	APSC,	MPSC,	and	the	Arkansas	Electric	Energy	Consumers	appealed	the	FERC's	December	2005	decision	to	the	United States	Court	of	Appeals	for	the	D.C.	Circuit.		Entergy	and	the	City	of	New	Orleans	intervened	in	the	various	appeals.		The	D.C.	Circuit	issued	its decision	in	April	2008.		The	D.C.	Circuit	concluded	that	the	FERC's	orders	had	failed	to	adequately	explain	both	its	conclusion	that	it	was prohibited	 from	 ordering	 refunds	 for	 the	20-month	period	from	September	13,	2001	-	May	2,	2003	and	its	determination	to	implement	the bandwidth	remedy	commencing	on	January	1,	2006,	rather	than	June	1,	2005.		The	D.C.	Circuit	remanded	the	case	to	the	FERC	for	further proceedings	on	these	issues.

In	October	2011,	the	FERC	issued	an	order	addressing	the	D.C.	Circuit	remand	on	these	two	issues.	 	On	the	first	issue,	the	FERC concluded	that	it	did	have	the	authority	to	order	refunds,	but	decided	that	it	would	exercise	its	equitable	discretion	and	not	require	refunds	for	the 20-month	period	from	September	13,	2001	-	May	2,	2003.		Because	the	ruling	on	refunds	relied	on	findings	in	the	interruptible	load	proceeding, which	is	discussed	in	a	separate	section	below,	the	FERC	concluded	that	the	refund	ruling	will	be	held	in	abeyance	pending	the	outcome	of	the rehearing	requests	in	that	proceeding.		On	the	second	issue,	the	FERC	reversed	its	prior	decision	and	ordered	that	the	prospective	bandwidth remedy	begin	on	June	1,	2005	(the	date	of	its	initial	order	in	the	proceeding)	rather	than	January	1,	2006,	as	it	had	previously	ordered.		Pursuant	to the	October	2011	order,	Entergy	was	required	to	calculate	the	additional	bandwidth	payments	for	the	period	June	-	December	2005	utilizing	the bandwidth	formula	tariff	prescribed	by	the	FERC	that	was	filed	in	a	December	2006	compliance	filing	and	accepted	by	the	FERC	in	an	April	2007 order.	 	As	is	the	case	with	bandwidth	remedy	payments,	these	payments	and	receipts	will	ultimately	be	paid	by	Utility	operating	company customers	to	other	Utility	operating	company	customers.

In	December	2011,	Entergy	filed	with	the	FERC	its	compliance	filing	that	provides	the	payments	and	receipts	among	the	Utility	operating companies	pursuant	to	the	FERC's	October	2011	order.		The	filing	shows	the	following	payments/receipts	among	the	Utility	operating	companies:

Entergy	Arkansas	made	its	payment	in	January	2012.		In	February	2012,	Entergy	Arkansas	filed	for	an	interim	adjustment	to	its	production	cost allocation	 rider	 requesting	 that	 the	$156	million	payment	be	collected	from	customers	over	 the	22-month	period	from	March	2012	through December	2013.		In	March	2012	the	APSC	issued	an	order	stating	that	the	payment	can	be	recovered	from	retail	customers	through	the	production cost	allocation	rider,	subject	to	refund.		The	LPSC	and	the	APSC	have	requested	rehearing	of	the	FERC's	October	2011	order.		In	December	2013 the	LPSC	filed	a	petition	for	a	writ	of	mandamus	at	the	United	States	Court	of	Appeals	for	the	D.C.	Circuit.	In	its	petition,	the	LPSC	requested that	the	D.C.	Circuit	issue	an	order	compelling	the	FERC	to	issue	a	final	order	on	pending	rehearing	requests.	In	its	response	to	the	LPSC	petition, the	FERC	committed	to	rule	on	the	pending	rehearing	request	before	the	end	of	February.	In	January	2014	the	D.C.	Circuit	denied	the	LPSC's petition.	The	APSC,	the	LPSC,	the	PUCT,	and	other	parties	intervened	in	the	December	2011	compliance	filing	proceeding,	and	the	APSC	and	the LPSC	also	filed	protests.

# Calendar	Year	2013	Production	Costs

The	liabilities	and	assets	for	the	preliminary	estimate	of	the	payments	and	receipts	required	to	implement	the	FERC's	remedy	based	on calendar	year	2013	production	costs	were	recorded	in	December	2013,	based	on	certain	year-to-date	information.		The	preliminary	estimate	was recorded	based	on	the	following	estimate	of	the	payments/receipts	among	the	Utility	operating	companies	for	2014.

(Receipts)

|  | 2014	Payments<br>(Receipts) |
| :--- | :--- |
|  | (In\tMillions) |
| Entergy\tGulf\tStates\tLouisiana | $— |
| Entergy\tLouisiana | $— |
| Entergy\tMississippi | $— |
| Entergy\tNew\tOrleans | ($16) |
| Entergy\tTexas | $16 |

The	actual	payments/receipts	for	2014,	based	on	calendar	year	2013	production	costs,	will	not	be	calculated	until	the	Utility	operating companies'	2013	FERC	Form	1s	have	been	filed.		Once	the	calculation	is	completed,	it	will	be	filed	at	the	FERC.		The	level	of	any	payments	and receipts	 is	 significantly	 affected	 by	 a	 number	 of	 factors,	 including,	 among	 others,	 weather,	 the	 price	 of	 alternative	 fuels,	 the	 operating characteristics	of	the	Entergy	System	generating	fleet,	and	multiple	factors	affecting	the	calculation	of	the	non-fuel	related	revenue	requirement components	of	the	total	production	costs,	such	as	plant	investment.	Entergy	Arkansas	is	no	longer	a	participant	in	the	System	Agreement	and	is not	part	of	the	calendar	year	2013	production	costs	calculation.

# Rough	Production	Cost	Equalization	Rates

Each	 May	 since	 2007	 Entergy	 has	 filed	 with	 the	 FERC	 the	 rates	 to	 implement	 the	 FERC's	 orders	 in	 the	 System	 Agreement proceeding.	 	 These	 filings	 show	 the	 following	 payments/receipts	 among	 the	 Utility	 operating	 companies	 are	 necessary	 to	 achieve	 rough production	cost	equalization	as	defined	by	the	FERC's	orders:

|  |  |  |  | Payments	(Receipts) |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | 2013 |
|  |  |  |  | (In\tMillions) |  |  |  |
| Entergy\tArkansas | $252 | $252 | $390 | $41 | $77 | $41 | $— |
| Entergy\tGulf\tStates\tLouisiana | ($120) | ($124) | ($107) | $— | ($12) | $— | $— |
| Entergy\tLouisiana | ($91) | ($36) | ($140) | ($22) | $— | ($41) | $— |
| Entergy\tMississippi | ($41) | ($20) | ($24) | ($19) | ($40) | $— | $— |
| Entergy\tNew\tOrleans | $— | ($7) | $— | $— | ($25) | $— | ($15) |
| Entergy\tTexas | ($30) | ($65) | ($119) | $— | $— | $— | $15 |

The	APSC	has	approved	a	production	cost	allocation	rider	for	recovery	from	customers	of	the	retail	portion	of	the	costs	allocated	to Entergy	Arkansas.		Entergy	Texas	proposed	a	rough	production	cost	equalization	adjustment	rider	in	its	September	2013	rate	filing,	which	is pending.	Management	believes	that	any	changes	in	the	allocation	of	production	costs	resulting	from	the	FERC's	decision	and	related	retail proceedings	should	result	in	similar	rate	changes	for	retail	customers,	subject	to	specific	circumstances	that	have	caused	trapped	costs.		See	"2007 Rate	Filing	Based	on	Calendar	Year	2006	Production	Costs"	below,	however,	for	a	discussion	of	a	FERC	decision	that	could	result	in	trapped costs	at	Entergy	Arkansas	related	to	a	contract	with	AmerenUE.

Entergy	Arkansas	and,	for	December	2012	and	2013,	Entergy	Texas,	record	accounts	payable	and	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	 Entergy	 Mississippi,	 Entergy	 New	 Orleans,	 and	 Entergy	 Texas	 record	 accounts	 receivable	 to	 reflect	 the	 rough	 production	 cost equalization	payments	and	receipts	required	to	implement	the	FERC's	remedy.		Entergy	Arkansas	and,	for	December	2012	and	2013,	Entergy Texas,	record	a	corresponding	regulatory	asset	for	the	right	to	collect	the	payments	from	customers,	and	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	record	corresponding	regulatory	liabilities	for	their	obligations	to	pass the	receipts	on	to	customers.		The	regulatory	asset	and	liabilities	are	shown	as	"System	Agreement	cost	equalization"	on	the	respective	balance sheets.

# 2007	Rate	Filing	Based	on	Calendar	Year	2006	Production	Costs

Several	parties	intervened	in	the	2007	rate	proceeding	at	the	FERC,	including	the	APSC,	the	MPSC,	the	Council,	and	the	LPSC,	which also	filed	protests.		The	PUCT	also	intervened.		Intervenor	testimony	was	filed	in	which	the	intervenors	and	also	the	FERC	Staff	advocated	a number	of	positions	on	issues	that	affect	the	level	of	production	costs	the	individual	Utility	operating	companies	are	permitted	to	reflect	in	the bandwidth	calculation,	including	the	level	of	depreciation	and	decommissioning	expense	for	nuclear	facilities.		The	effect	of	the	various	positions would	be	to	reallocate	costs	among	the	Utility	operating	companies.		The	Utility	operating	companies	filed	rebuttal	testimony	explaining	why	the bandwidth	payments	are	properly	recoverable	under	the	AmerenUE	contract,	and	explaining	why	the	positions	of	FERC	Staff	and	intervenors	on the	other	issues	should	be	rejected.		A	hearing	in	this	proceeding	concluded	in	July	2008,	and	the	ALJ	issued	an	initial	decision	in	September 2008.		The	ALJ's	initial	decision	concluded,	among	other	things,	that:	(1)	the	decisions	to	not	exercise	Entergy	Arkansas's	option	to	purchase	the Independence	plant	in	1996	and	1997	were	prudent;	(2)	Entergy	Arkansas	properly	flowed	a	portion	of	the	bandwidth	payments	through	to AmerenUE	in	accordance	with	the	wholesale	power	contract;	and	(3)	the	level	of	nuclear	depreciation	and	decommissioning	expense	reflected	in the	bandwidth	calculation	should	be	calculated	based	on	NRC-authorized	license	life,	rather	than	the	nuclear	depreciation	and	decommissioning expense	authorized	by	the	retail	regulators	for	purposes	of	retail	ratemaking.		Following	briefing	by	the	parties,	the	matter	was	submitted	to	the FERC	for	decision.	On	January	11,	2010,	the	FERC	issued	its	decision	both	affirming	and	overturning	certain	of	the	ALJ's	rulings,	including overturning	the	decision	on	nuclear	depreciation	and	decommissioning	expense.		The	FERC's	conclusion	related	to	the	AmerenUE	contract	does not	 permit	 Entergy	Arkansas	 to	 recover	 a	 portion	 of	 its	 bandwidth	 payment	 from	AmerenUE.	 	The	 Utility	 operating	 companies	 requested rehearing	of	that	portion	of	the	decision	and	requested	clarification	on	certain	other	portions	of	the	decision.

AmerenUE	 argued	 that	 its	 wholesale	 power	 contract	 with	 Entergy	Arkansas,	 pursuant	 to	 which	 Entergy	Arkansas	 sells	 power	 to AmerenUE,	does	not	permit	Entergy	Arkansas	to	flow	through	to	AmerenUE	any	portion	of	Entergy	Arkansas's	bandwidth	payment.	 	The AmerenUE	contract	expired	in	August	2009.		In	April	2008,	AmerenUE	filed	a	complaint	with	the	FERC	seeking	refunds,	plus	interest,	in	the event	the	FERC	ultimately	determines	that	bandwidth	payments	are	not	properly	recovered	under	the	AmerenUE	contract.		In	response	to	the FERC's	decision	discussed	in	the	previous	paragraph,	Entergy	Arkansas	recorded	a	regulatory	provision	in	the	fourth	quarter	2009	for	a	potential refund	to	AmerenUE.

In	May	2012,	the	FERC	issued	an	order	on	rehearing	in	the	proceeding.		The	order	may	result	in	the	reallocation	of	costs	among	the	Utility operating	 companies,	 although	 there	 are	 still	 FERC	 decisions	 pending	 in	 other	 System	Agreement	 proceedings	 that	 could	 affect	 the	 rough production	cost	equalization	payments	and	receipts.		The	FERC	directed	Entergy,	within	45	days	of	the	issuance	of	a	pending	FERC	order	on rehearing	regarding	the	functionalization	of	costs	in	the	2007	rate	filing,	to	file	a	comprehensive	bandwidth	recalculation	report	showing	updated payments	and	receipts	in	the	2007	rate	filing	proceeding.		The	May	2012	FERC	order	also	denied	Entergy's	request	for	rehearing	regarding	the AmerenUE	contract	and	ordered	Entergy	Arkansas	to	refund	to	AmerenUE	the	rough	production	cost	equalization	payments	collected	from AmerenUE.		Under	the	terms	of	the	FERC's	order	a	refund	of	$30.6	million,	including	interest,	was	made	in	June	2012.		Entergy	and	the	LPSC appealed	certain	aspects	of	the	FERC's	decisions	to	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit.		On	December	7,	2012,	the	D.C.	Circuit dismissed	Entergy's	petition	for	review	as	premature	because	Entergy	filed	a	rehearing	request	of	the	May	2012	FERC	order	and	that	rehearing request	is	still	pending.		The	court	also	ordered	that	the	LPSC's	appeal	be	held	in	abeyance	and	that	the	parties	file	motions	to	govern	further proceedings	within	30	days	of	the	FERC's	completion	of	the	ongoing	"Entergy	bandwidth	proceedings."	On	October	16,	2013,	the	FERC	issued two	orders	related	 to	 this	proceeding.	The	first	order	provided	clarification	with	regard	to	the	derivation	of	the	ratio	that	should	be	used	to functionalize	 net	 operating	 loss	 carryforwards	 for	 purposes	 of	 the	 annual	 bandwidth	 filings.	The	second	order	denied	Entergy's	request	for rehearing	of	 the	FERC's	prior	determination	 that	 interest	should	be	 included	on	recalculated	payment	and	receipt	amounts	required	 in	 this particular	proceeding	due	to	the	length	of	time	that	had	passed.	Entergy	subsequently	appealed	certain	aspects	of	the	FERC's	decisions	to	the	U.S. Court	of	Appeals	for	the	D.C.	Circuit.	On	January	23,	2014,	the	D.C.	Circuit	returned	the	LPSC's	appeal	to	the	active	docket	and	consolidated	it with	Entergy's	petition	for	appellate	review.	The	appeals	are	pending.

Several	parties	intervened	in	the	2008	rate	proceeding	at	the	FERC,	including	the	APSC,	the	LPSC,	and	AmerenUE,	which	also	filed protests.	 	Several	other	parties,	 including	 the	MPSC	and	 the	City	Council,	 intervened	 in	 the	proceeding	without	filing	a	protest.	 	In	direct testimony	filed	 in	January	2009,	certain	 intervenors	and	 the	FERC	staff	advocated	a	number	of	positions	on	 issues	 that	affect	 the	 level	of production	 costs	 the	 individual	 Utility	 operating	 companies	 are	 permitted	 to	 reflect	 in	 the	 bandwidth	 calculation,	 including	 the	 level	 of depreciation	and	decommissioning	expense	for	the	nuclear	and	fossil-fueled	generating	facilities.		The	effect	of	these	various	positions	would	be to	reallocate	costs	among	the	Utility	operating	companies.		In	addition,	three	issues	were	raised	alleging	imprudence	by	the	Utility	operating companies,	including	whether	the	Utility	operating	companies	had	properly	reflected	generating	units'	minimum	operating	levels	for	purposes	of making	unit	commitment	and	dispatch	decisions,	whether	Entergy	Arkansas's	sales	to	third	parties	from	its	retained	share	of	the	Grand	Gulf nuclear	facility	were	reasonable,	prudent,	and	non-discriminatory,	and	whether	Entergy	Louisiana's	long-term	Evangeline	gas	purchase	contract was	prudent	and	reasonable.

The	parties	reached	a	partial	settlement	agreement	of	certain	of	the	issues	initially	raised	in	this	proceeding.	 	The	partial	settlement agreement	was	conditioned	on	the	FERC	accepting	the	agreement	without	modification	or	condition,	which	the	FERC	did	in	August	2009.		A hearing	on	the	remaining	issues	in	the	proceeding	was	completed	in	June	2009,	and	in	September	2009	the	ALJ	issued	an	initial	decision.		The initial	decision	affirms	Entergy's	position	in	the	filing,	except	for	two	issues	that	may	result	in	a	reallocation	of	costs	among	the	Utility	operating companies.		In	October	2011	the	FERC	issued	an	order	on	the	ALJ's	initial	decision.		The	FERC's	order	resulted	in	a	minor	reallocation	of payments/receipts	among	the	Utility	operating	companies	on	one	issue	in	the	2008	rate	filing.		Entergy	made	a	compliance	filing

in	December	2011	showing	the	updated	payment/receipt	amounts.		The	LPSC	filed	a	protest	in	response	to	the	compliance	filing.		In	January	2013 the	FERC	issued	an	order	accepting	Entergy's	compliance	filing.		In	the	January	2013	order	the	FERC	required	Entergy	to	include	interest	on	the recalculated	bandwidth	payment	and	receipt	amounts	for	the	period	from	June	1,	2008	until	the	date	of	the	Entergy	intra-system	bill	that	will reflect	the	bandwidth	recalculation	amounts	for	calendar	year	2007.		In	February	2013,	Entergy	filed	a	request	for	rehearing	of	the	FERC's	ruling requiring	 interest.	In	March	2013	the	LPSC	filed	a	petition	for	review	with	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	seeking	appellate review	of	the	FERC's	earlier	orders	addressing	the	ALJ's	initial	decision.	The	Fifth	Circuit	has	scheduled	the	LPSC	petition	for	oral	argument	in March	2014.

Several	parties	intervened	in	the	2009	rate	proceeding	at	the	FERC,	including	the	LPSC	and	Ameren,	which	also	filed	protests.		In	July 2009	the	FERC	accepted	Entergy's	proposed	rates	for	filing,	effective	June	1,	2009,	subject	to	refund,	and	set	the	proceeding	for	hearing	and settlement	procedures.		Settlement	procedures	were	terminated	and	a	hearing	before	the	ALJ	was	held	in	April	2010.		In	August	2010	the	ALJ issued	an	initial	decision.		The	initial	decision	substantially	affirms	Entergy's	position	in	the	filing,	except	for	one	issue	that	may	result	in	some reallocation	of	costs	among	the	Utility	operating	companies.		The	LPSC,	the	FERC	trial	staff,	and	Entergy	submitted	briefs	on	exceptions	in	the proceeding.		In	May	2012	the	FERC	issued	an	order	affirming	the	ALJ's	initial	decision,	or	finding	certain	issues	in	that	decision	moot.		Rehearing and	clarification	of	FERC's	order	have	been	requested.	In	January	2013	the	LPSC	filed	a	protest	of	Entergy's	July	2012	compliance	filing submitted	in	response	to	the	FERC's	May	2012	order.	In	October	2013	the	FERC	issued	orders	denying	the	LPSC's	rehearing	request	with	respect to	the	FERC's	May	2012	order	and	addressing	Entergy's	compliance	filing	implementing	the	FERC's	directives	in	the	May	2012	order.	 The compliance	filing	order	referred	to	guidance	provided	in	a	separate	order	issued	on	that	same	day	in	the	2007	rate	proceeding	with	respect	to	the ratio	used	to	functionalize	net	operating	loss	carryforwards	for	bandwidth	purposes	and	directed	Entergy	to	make	an	additional	compliance	filing in	the	2009	rate	proceeding	consistent	with	the	guidance	provided	in	that	order.	In	November	2013	the	LPSC	sought	rehearing	of	the	FERC's October	2013	order	and	Entergy	submitted	its	compliance	filing	implementing	the	FERC's	directives	in	the	October	2013	order.

Comprehensive	Bandwidth	Recalculation	for	2007,	2008,	and	2009	Rate	Filing	Proceedings

Entergy	has	committed	to	file	a	comprehensive	bandwidth	recalculation	report	reflecting	the	updated	payment/receipt	amounts	in	the 2007,	 2008,	 and	 2009	 rate	 filing	 proceedings	 mentioned	 above	 in	 compliance	 with	 the	 applicable	 FERC	 orders.	It	 is	 probable	 that	 these proceedings	will	result	in	a	reallocation	of	payments/receipts	among	the	Utility	operating	companies	to	achieve	production	cost	equalization	as defined	by	 the	FERC	orders.	Based	on	the	progress	of	the	proceedings	during	the	fourth	quarter	of	2013,	Entergy	was	able	to	estimate	the following	range	for	these	payments	(receipts)	as	of	December	31,	2013:

|  | Payments	(Receipts) | Payments	(Receipts) |
| :--- | :--- | :--- |
|  | Low | High |
|  | (In\tMillions) | (In\tMillions) |
| Entergy\tArkansas | $30 | $40 |
| Entergy\tGulf\tStates\tLouisiana | ($15) | ($24) |
| Entergy\tLouisiana | ($17) | ($25) |
| Entergy\tMississippi | $15 | $25 |
| Entergy\tNew\tOrleans | ($1) | ($1) |
| Entergy\tTexas | ($12) | ($15) |

The	Utility	operating	companies	recorded	payables	to/receivables	from	associated	companies	based	on	the	low	end	of	the	estimated	range. Any	payments	required	by	the	Utility	operating	companies	as	a	result	of	these	rate	filings	are	expected	to	be	recoverable	from	customers	and	any receipts	are	expected	to	be	credited	to	customers.	Therefore,	offsetting	regulatory	assets/liabilities	were	also	recorded.	There	is	still	significant uncertainty	regarding

the	final	outcome	of	these	proceedings.	As	further	progress	is	made,	the	estimates	of	the	payments/receipts	may	change.	As	is	the	case	with bandwidth	 remedy,	 these	 payments	 and	 receipts	 will	 ultimately	 be	 paid	 by	 Utility	 operating	 company	 customers	 to	 other	 Utility	 operating company	customers.

In	May	2010,	Entergy	filed	with	the	FERC	the	2010	rates	in	accordance	with	the	FERC's	orders	in	the	System	Agreement	proceeding,	and supplemented	the	filing	in	September	2010.		Several	parties	intervened	in	the	proceeding	at	the	FERC,	including	the	LPSC	and	the	City	Council, which	also	filed	protests.		In	July	2010	the	FERC	accepted	Entergy's	proposed	rates	for	filing,	effective	June	1,	2010,	subject	to	refund,	and	set the	proceeding	for	hearing	and	settlement	procedures.		Settlement	procedures	have	been	terminated,	and	the	ALJ	scheduled	hearings	to	begin	in March	2011.		Subsequently,	in	January	2011	the	ALJ	issued	an	order	directing	the	parties	and	FERC	Staff	to	show	cause	why	this	proceeding should	not	be	stayed	pending	the	issuance	of	FERC	decisions	in	the	prior	production	cost	proceedings	currently	before	the	FERC	on	review.		In March	2011	the	ALJ	issued	an	order	placing	this	proceeding	in	abeyance.	In	October	2013	the	FERC	issued	an	order	granting	clarification	and denying	rehearing	with	respect	to	its	October	2011	rehearing	order	in	this	proceeding.	The	FERC	clarified	that	in	a	bandwidth	proceeding	parties can	challenge	erroneous	inputs,	implementation	errors,	or	prudence	of	cost	inputs,	but	challenges	to	the	bandwidth	formula	itself	must	be	raised	in a	Federal	Power	Act	section	206	complaint	or	section	205	filing.	Subsequently	in	October	2013	the	presiding	ALJ	lifted	the	stay	order	holding	in abeyance	the	hearing	previously	ordered	by	the	FERC	and	directing	that	the	remaining	issues	proceed	to	a	hearing	on	the	merits.	The	hearing	is scheduled	for	March	2014.

# 2011	Rate	Filing	Based	on	Calendar	Year	2010	Production	Costs

In	 May	 2011,	 Entergy	 filed	 with	 the	 FERC	 the	 2011	 rates	 in	 accordance	 with	 the	 FERC's	 orders	 in	 the	 System	 Agreement proceeding.	 	 Several	 parties	 intervened	 in	 the	 proceeding	 at	 the	 FERC,	 including	 the	 LPSC,	 which	 also	 filed	 a	 protest.	 	 In	 July	 2011	 the FERC	accepted	Entergy's	proposed	rates	for	filing,	effective	June	1,	2011,	subject	to	refund,	set	the	proceeding	for	hearing	procedures,	and	then held	those	procedures	in	abeyance	pending	FERC	decisions	in	the	prior	production	cost	proceedings	currently	before	the	FERC	on	review.	In January	2014	the	LPSC	filed	a	petition	for	a	writ	of	mandamus	at	the	United	States	Court	of	Appeals	for	the	Fifth	Circuit.	In	its	petition,	the LPSC	requested	that	the	Fifth	Circuit	issue	an	order	compelling	the	FERC	to	issue	a	final	order	in	several	proceedings	related	to	the	System Agreement,	including	the	2011	rate	filing	based	on	calendar	year	2010	production	costs	and	the	2012	and	2013	rate	filings	discussed	below.

2012	Rate	Filing	Based	on	Calendar	Year	2011	Production	Costs

In	 May	 2012,	 Entergy	 filed	 with	 the	 FERC	 the	 2012	 rates	 in	 accordance	 with	 the	 FERC's	 orders	 in	 the	 System	 Agreement proceeding.		Several	parties	intervened	in	the	proceeding	at	the	FERC,	including	the	LPSC,	which	also	filed	a	protest.		In	August	2012	the FERC	accepted	Entergy's	proposed	rates	for	filing,	effective	June	2012,	subject	to	refund,	set	the	proceeding	for	hearing	procedures,	and	then	held those	procedures	in	abeyance	pending	FERC	decisions	in	the	prior	production	cost	proceedings	currently	before	the	FERC	on	review.

In	May	2013,	Entergy	filed	with	the	FERC	the	2013	rates	in	accordance	with	the	FERC's	orders	in	the	System	Agreement	proceeding. Several	parties	intervened	in	the	proceeding	at	the	FERC,	including	the	LPSC,	which	also	filed	a	protest.	The	City	Council	intervened	and	filed comments	related	to	including	the	outcome	of	a	related	FERC	proceeding	in	the	2013	cost	equalization	calculation.	In	August	2013	the	FERC issued	an	order	accepting	the	2013	rates,	effective	June	1,	2013,	subject	to	refund,	set	the	proceeding	for	hearing	procedures,	and	then	held	those procedures	in	abeyance	pending	FERC	decisions	in	the	prior	production	cost	proceedings	currently	before	the	FERC	on	review.

# Interruptible	Load	Proceeding

In	April	2007,	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit	issued	its	opinion	in	the	LPSC's	appeal	of	the	FERC's	March	2004	and	April 2005	orders	related	to	the	treatment	under	the	System	Agreement	of	the	Utility	operating	companies'	interruptible	loads.		In	its	opinion	the	D.C. Circuit	concluded	that	the	FERC	(1)	acted	arbitrarily	and	capriciously	by	allowing	the	Utility	operating	companies	to	phase-in	the	effects	of	the elimination	of	the	interruptible	load	over	a	12-month	period	of	time;	(2)	failed	to	adequately	explain	why	refunds	could	not	be	ordered	under Section	206(c)	of	the	Federal	Power	Act;	and	(3)	exercised	appropriately	its	discretion	to	defer	addressing	the	cost	of	sulfur	dioxide	allowances until	a	later	time.		The	D.C.	Circuit	remanded	the	matter	to	the	FERC	for	a	more	considered	determination	on	the	issue	of	refunds.		The	FERC issued	its	order	on	remand	in	September	2007,	in	which	it	directed	Entergy	to	make	a	compliance	filing	removing	all	interruptible	load	from	the computation	of	peak	load	responsibility	commencing	April	1,	2004	and	to	issue	any	necessary	refunds	to	reflect	this	change.		In	addition,	the	order directed	the	Utility	operating	companies	to	make	refunds	for	the	period	May	1995	through	July	1996.		In	November	2007	the	Utility	operating companies	filed	a	refund	report	describing	the	refunds	to	be	issued	pursuant	to	the	FERC's	orders.		The	LPSC	filed	a	protest	to	the	refund	report	in December	2007,	and	the	Utility	operating	companies	filed	an	answer	to	the	protest	in	January	2008.		The	refunds	were	made	in	October	2008	by the	Utility	operating	companies	that	owed	refunds	to	the	Utility	operating	companies	that	were	due	a	refund	under	the	decision.		The	APSC	and the	Utility	operating	companies	appealed	the	FERC	decisions	to	the	D.C.	Circuit.		Because	of	its	refund	obligation	to	its	customers	as	a	result	of this	proceeding	and	a	related	LPSC	proceeding,	Entergy	Louisiana	recorded	provisions	during	2008	of	approximately	$16	million,	 including interest,	for	rate	refunds.		The	refunds	were	made	in	the	fourth	quarter	2009.

Following	the	filing	of	petitioners'	initial	briefs,	the	FERC	filed	a	motion	requesting	the	D.C.	Circuit	hold	the	appeal	of	the	FERC's decisions	ordering	refunds	in	the	interruptible	load	proceeding	in	abeyance	and	remand	the	record	to	the	FERC.		The	D.C.	Circuit	granted	the FERC's	unopposed	motion	in	June	2009.		In	December	2009	the	FERC	established	a	paper	hearing	to	determine	whether	the	FERC	had	the authority	and,	if	so,	whether	it	would	be	appropriate	to	order	refunds	resulting	from	changes	in	the	treatment	of	interruptible	load	in	the	allocation of	capacity	costs	by	the	Utility	operating	companies.		In	August	2010	the	FERC	issued	an	order	stating	that	it	has	the	authority	and	refunds	are appropriate.		The	APSC,	MPSC,	and	Entergy	requested	rehearing	of	the	FERC's	decision.		In	June	2011	the	FERC	issued	an	order	granting rehearing	in	part	and	denying	rehearing	in	part,	in	which	the	FERC	determined	to	invoke	its	discretion	to	deny	refunds.		The	FERC	held	that	in	this case	where	"the	Entergy	system	as	a	whole	collected	the	proper	level	of	revenue,	but,	as	was	later	established,	incorrectly	allocated	peak	load responsibility	among	the	various	Entergy	operating	companies….the	Commission	will	apply	here	our	usual	practice	in	such	cases,	invoking	our equitable	discretion	to	not	order	refunds,	notwithstanding	our	authority	to	do	so."		The	LPSC	has	requested	rehearing	of	the	FERC's	June	2011 decision.		In	October	2011	the	FERC	issued	an	"Order	Establishing	Paper	Hearing"	inviting	parties	that	oppose	refunds	to	file	briefs	within	30 days	addressing	the	LPSC's	argument	that	FERC	precedent	supports	refunds	under	the	circumstances	present	in	this	proceeding.		Parties	that	favor refunds	were	then	invited	to	file	reply	briefs	within	21	days	of	the	date	that	the	initial	briefs	are	due.		Briefs	were	submitted	and	the	matter	is pending.

In	September	2010	the	FERC	had	issued	an	order	setting	the	refund	report	filed	in	the	proceeding	in	November	2007	for	hearing	and settlement	judge	procedures.		In	May	2011,	Entergy	filed	a	settlement	agreement	that	resolved	all	issues	relating	to	the	refund	report	set	for hearing.		In	June	2011	the	settlement	judge	certified	the	settlement	as	uncontested	and	the	settlement	agreement	is	currently	pending	before	the FERC.		In	July	2011,	Entergy	filed	an	amended/corrected	refund	report	and	a	motion	to	defer	action	on	the	settlement	agreement	until	after	the FERC	rules	on	the	LPSC's	rehearing	request	regarding	the	June	2011	decision	denying	refunds.

Prior	to	the	FERC's	June	2011	order	on	rehearing,	Entergy	Arkansas	filed	an	application	in	November	2010	with	the	APSC	for	recovery of	the	refund	that	it	paid.		The	APSC	denied	Entergy	Arkansas's	application,	and	also	denied	Entergy	Arkansas's	petition	for	rehearing.		If	the FERC	were	to	order	Entergy	Arkansas	to	pay	refunds	on	rehearing	in	the	interruptible	load	proceeding	the	APSC's	decision	would	trap	FERC- approved	 costs	 at	 Entergy	Arkansas	 with	 no	 regulatory-approved	 mechanism	 to	 recover	 them.	 	 In	August	 2011,	 Entergy	Arkansas	 filed	 a complaint	in	the	United	States	District	Court	for	the	Eastern	District	of	Arkansas	asking	for	a	declaratory	judgment	that	the	rejection	of	Entergy Arkansas's	application	by	the	APSC	is	preempted	by	the	Federal	Power	Act.		The	APSC	filed	a	motion	to

dismiss	the	complaint.		In	April	2012	the	United	States	district	court	dismissed	Entergy	Arkansas's	complaint	without	prejudice	stating	that Entergy	Arkansas's	claim	is	not	ripe	for	adjudication	and	that	Entergy	Arkansas	did	not	have	standing	to	bring	suit	at	this	time.

In	March	2013	the	FERC	issued	an	order	denying	the	LPSC's	request	for	rehearing	of	the	FERC's	June	2011	order	wherein	the	FERC concluded	it	would	exercise	its	discretion	and	not	order	refunds	in	the	interruptible	load	proceeding.	Based	on	its	review	of	the	LPSC's	request	for rehearing	and	the	briefs	filed	as	part	of	the	paper	hearing	established	in	October	2011,	the	FERC	affirmed	its	earlier	ruling	and	declined	to	order refunds	under	the	circumstances	of	the	case.	In	May	2013	the	LPSC	filed	a	petition	for	review	with	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit seeking	review	of	FERC	prior	orders	in	the	Interruptible	Load	Proceeding	that	concluded	that	the	FERC	would	exercise	its	discretion	and	not order	refunds	in	the	proceeding.	The	appeal	is	pending.

# Entergy	Arkansas	Opportunity	Sales	Proceeding

In	June	2009,	the	LPSC	filed	a	complaint	requesting	that	the	FERC	determine	that	certain	of	Entergy	Arkansas's	sales	of	electric	energy	to third	parties:	(a)	violated	the	provisions	of	the	System	Agreement	that	allocate	the	energy	generated	by	Entergy	System	resources,	(b)	imprudently denied	the	Entergy	System	and	its	ultimate	consumers	the	benefits	of	low-cost	Entergy	System	generating	capacity,	and	(c)	violated	the	provision of	the	System	Agreement	that	prohibits	sales	to	third	parties	by	individual	companies	absent	an	offer	of	a	right-of-first-refusal	to	other	Utility operating	companies.			The	LPSC's	complaint	challenges	sales	made	beginning	in	2002	and	requests	refunds.		On	July	20,	2009,	the	Utility operating	companies	filed	a	response	to	the	complaint	requesting	that	the	FERC	dismiss	the	complaint	on	the	merits	without	hearing	because	the LPSC	has	failed	to	meet	its	burden	of	showing	any	violation	of	the	System	Agreement	and	failed	to	produce	any	evidence	of	imprudent	action	by the	Entergy	System.		In	their	response,	the	Utility	operating	companies	explained	that	the	System	Agreement	clearly	contemplates	that	the	Utility operating	companies	may	make	sales	to	third	parties	for	their	own	account,	subject	to	the	requirement	that	those	sales	be	included	in	the	load	(or load	shape)	for	the	applicable	Utility	operating	company.		The	response	further	explains	that	the	FERC	already	has	determined	that	Entergy Arkansas's	short-term	wholesale	sales	did	not	trigger	the	"right-of-first-refusal"	provision	of	the	System	Agreement.		While	the	D.C.	Circuit recently	determined	that	the	"right-of-first-refusal"	issue	was	not	properly	before	the	FERC	at	the	time	of	its	earlier	decision	on	the	issue,	the LPSC	has	raised	no	additional	claims	or	facts	that	would	warrant	the	FERC	reaching	a	different	conclusion.

The	LPSC	filed	direct	testimony	in	the	proceeding	alleging,	among	other	things,	(1)	that	Entergy	violated	the	System	Agreement	by permitting	Entergy	Arkansas	to	make	non-requirements	sales	to	non-affiliated	third	parties	rather	than	making	such	energy	available	to	the	other Utility	operating	companies'	customers;	and	(2)	 that	over	 the	period	2000	-	2009,	 these	non-requirements	sales	caused	harm	 to	 the	Utility operating	companies'	customers	and	these	customers	should	be	compensated	for	this	harm	by	Entergy.		In	subsequent	testimony,	the	LPSC modified	its	original	damages	claim	in	favor	of	quantifying	damages	by	re-running	intra-system	bills.		The	Utility	operating	companies	believe	the LPSC's	allegations	are	without	merit.		A	hearing	in	the	matter	was	held	in	August	2010.

In	December	2010,	the	ALJ	issued	an	initial	decision.		The	ALJ	found	that	the	System	Agreement	allowed	for	Entergy	Arkansas	to	make the	sales	to	third	parties	but	concluded	that	the	sales	should	be	accounted	for	in	the	same	manner	as	joint	account	sales.		The	ALJ	concluded	that "shareholders"	should	make	refunds	of	the	damages	to	the	Utility	operating	companies,	along	with	interest.		Entergy	disagreed	with	several aspects	of	the	ALJ's	initial	decision	and	in	January	2011	filed	with	the	FERC	exceptions	to	the	decision.

The	FERC	 issued	a	decision	 in	June	2012	and	held	 that,	while	 the	System	Agreement	 is	ambiguous,	 it	does	provide	authority	for individual	Utility	operating	companies	to	make	opportunity	sales	for	their	own	account	and	Entergy	Arkansas	made	and	priced	these	sales	in	good faith.		The	FERC	found,	however,	that	the	System	Agreement	does	not	provide	authority	for	an	individual	Utility	operating	company	to	allocate the	energy	associated	with	such	opportunity	sales	as	part	of	its	load,	but	provides	a	different	allocation	authority.		The	FERC	further	found	that	the after-the-fact	 accounting	 methodology	 used	 to	 allocate	 the	 energy	 used	 to	 supply	 the	 sales	 was	 inconsistent	 with	 the	 System Agreement.		Quantifying	the	effect	of	the	FERC's	decision	will	require	re-running	intra-system	bills	for	a	ten-

year	period,	and	the	FERC	in	its	decision	established	further	hearing	procedures	to	determine	the	calculation	of	the	effects.		In	July	2012,	Entergy and	the	LPSC	filed	requests	for	rehearing	of	the	FERC's	June	2012	decision,	which	are	pending	with	the	FERC.

As	required	by	 the	procedural	schedule	established	 in	 the	calculation	proceeding,	Entergy	filed	 its	direct	 testimony	 that	 included	a proposed	illustrative	re-run,	consistent	with	the	directives	in	FERC's	order,	of	intra-system	bills	for	2003,	2004,	and	2006,	the	three	years	with	the highest	volume	of	opportunity	sales.		Entergy's	proposed	illustrative	re-run	of	intra-system	bills	shows	that	the	potential	cost	for	Entergy	Arkansas would	be	up	to	$12	million	for	the	years	2003,	2004,	and	2006,	and	the	potential	benefit	would	be	significantly	less	than	that	for	each	of	the	other Utility	operating	companies.		Entergy's	proposed	illustrative	re-run	of	the	intra-system	bills	also	shows	an	offsetting	potential	benefit	to	Entergy Arkansas	for	the	years	2003,	2004,	and	2006	resulting	from	the	effects	of	the	FERC's	order	on	System	Agreement	Service	Schedules	MSS-1, MSS-2,	 and	 MSS-3,	 and	 the	 potential	 offsetting	 cost	 would	 be	 significantly	 less	 than	 that	 for	 each	 of	 the	 other	 Utility	 operating companies.		Entergy	provided	to	the	LPSC	an	illustrative	intra-system	bill	recalculation	as	specified	by	the	LPSC	for	the	years	2003,	2004,	and 2006,	and	the	LPSC	then	filed	answering	testimony	in	December	2012.		In	its	testimony	the	LPSC	claims	that	the	damages	that	should	be	paid	by Entergy	Arkansas	to	the	other	Utility	operating	company's	customers	for	2003,	2004,	and	2006	are	$42	million	to	Entergy	Gulf	States,	Inc.,	$7 million	to	Entergy	Louisiana,	$23	million	to	Entergy	Mississippi,	and	$4	million	to	Entergy	New	Orleans.	The	FERC	staff	and	certain	intervenors filed	direct	and	answering	testimony	in	February	2013.	In	April	2013,	Entergy	filed	its	rebuttal	testimony	in	that	proceeding,	including	a	revised illustrative	re-run	of	the	intra-system	bills	for	the	years	2003,	2004,	and	2006.	The	revised	calculation	determines	the	re-pricing	of	the	opportunity sales	based	on	consideration	of	moveable	resources	only	and	the	removal	of	exchange	energy	received	by	Entergy	Arkansas,	which	increases	the potential	cost	for	Entergy	Arkansas	over	the	three	years	2003,	2004,	and	2006	by	$2.3	million	from	the	potential	costs	identified	in	the	Utility operating	companies'	prior	filings	in	September	and	October	2012.	A	hearing	was	held	in	May	2013	to	quantify	the	effect	of	repricing	the opportunity	sales	in	accordance	with	the	FERC's	decision.

In	August	2013	the	presiding	judge	issued	an	initial	decision.	The	initial	decision	concludes	that	the	methodology	proposed	by	the	LPSC, rather	than	the	methodologies	proposed	by	Entergy	or	the	FERC	Staff,	should	be	used	to	calculate	the	payments	that	Entergy	Arkansas	is	to	make to	the	other	Utility	operating	companies.	The	initial	decision	also	concludes	that	the	other	System	Agreement	service	schedules	should	not	be adjusted	and	that	payments	by	Entergy	Arkansas	should	not	be	reflected	in	the	rough	production	cost	equalization	bandwidth	calculations	for	the applicable	 years.	The	initial	decision	does	recognize	that	the	LPSC's	methodology	would	result	in	an	inequitable	windfall	to	the	other	Utility operating	 companies	 and,	 therefore,	 concludes	 that	 any	 payments	 by	 Entergy	Arkansas	 should	 be	 reduced	 by	20%.	 The	 Utility	 operating companies	are	currently	analyzing	the	effects	of	the	initial	decision.	The	LPSC,	APSC,	City	Council,	and	FERC	staff	filed	briefs	on	exceptions and/or	briefs	opposing	exceptions.	Entergy	filed	a	brief	on	exceptions	requesting	that	FERC	reverse	the	initial	decision	and	a	brief	opposing certain	exceptions	taken	by	the	LPSC	and	FERC	staff.	The	FERC's	review	of	the	initial	decision	is	pending.	No	payments	will	be	made	or received	by	the	Utility	operating	companies	until	the	FERC	issues	an	order	reviewing	the	initial	decision	and	Entergy	submits	a	subsequent	filing to	comply	with	that	order.

# Storm	Cost	Recovery	Filings	with	Retail	Regulators

# Entergy	Arkansas	December	2012	Winter	Storm

In	December	2012	a	severe	winter	storm	consisting	of	ice,	snow,	and	high	winds	caused	significant	damage	to	Entergy	Arkansas's distribution	lines,	equipment,	poles,	and	other	facilities.		Total	restoration	costs	for	the	repair	and/or	replacement	of	Entergy	Arkansas's	electrical facilities	in	areas	damaged	from	the	winter	storm	were	$63	million,	including	costs	recorded	as	regulatory	assets	of	approximately	$22	million.		In the	Entergy	Arkansas	2013	rate	case,	the	APSC	approved	inclusion	of	the	construction	spending	in	rate	base	and	approved	an	increase	in	the normal	storm	cost	accrual,	which	will	effectively	amortize	the	regulatory	asset	over	a	five-year	period.

In	August	2012,	Hurricane	Isaac	caused	extensive	damage	to	portions	of	Entergy's	service	area	in	Louisiana,	and	to	a	lesser	extent	in Mississippi	and	Arkansas.		The	storm	resulted	in	widespread	power	outages,	significant	damage	primarily	to	distribution	infrastructure,	and	the loss	of	sales	during	the	power	outages.		In	January	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	drew	$65	million	 and	$187 million,	respectively,	from	their	funded	storm	reserve	escrow	accounts.		In	April	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed a	joint	application	with	the	LPSC	relating	to	Hurricane	Isaac	system	restoration	costs.		Specifically,	Entergy	Gulf	States	Louisiana	and	Entergy Louisiana	requested	that	the	LPSC	determine	the	amount	of	such	costs	that	were	prudently	incurred	and	are,	thus,	eligible	for	recovery	from customers.		Including	carrying	costs	and	additional	storm	escrow	funds,	Entergy	Gulf	States	Louisiana	is	seeking	an	LPSC	determination	that $73.8	million	in	system	restoration	costs	were	prudently	incurred	and	Entergy	Louisiana	is	seeking	an	LPSC	determination	that	 $247.7	million	in system	restoration	costs	were	prudently	incurred.		Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	intend	to	replenish	their	storm	escrow accounts	to	$90	million	and	$200	million,	respectively,	primarily	through	traditional	debt	markets	and	have	requested	special	rate	treatment	of	any borrowings	for	that	purpose.		In	May	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	a	supplemental	application	proposing	a specific	means	to	finance	system	restoration	costs	and	related	requests.	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	are	proposing	to finance	Hurricane	Isaac	restoration	costs	through	Louisiana	Act	55	financing,	which	was	the	same	method	they	used	for	Hurricanes	Katrina,	Rita, Gustav,	and	Ike.

# Hurricane	Gustav	and	Hurricane	Ike

In	September	2008,	Hurricane	Gustav	and	Hurricane	Ike	caused	catastrophic	damage	to	Entergy's	service	territory.		Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	filed	their	Hurricane	Gustav	and	Hurricane	Ike	storm	cost	recovery	case	with	the	LPSC	in	May	2009.		In September	 2009,	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana	 and	 the	 Louisiana	 Utilities	 Restoration	 Corporation	 (LURC),	 an instrumentality	of	the	State	of	Louisiana,	filed	with	the	LPSC	an	application	requesting	that	the	LPSC	grant	financing	orders	authorizing	the financing	of	Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	storm	costs,	storm	reserves,	and	issuance	costs	pursuant	to	Act	55	of	the Louisiana	 Regular	 Session	 of	 2007	 (Act	 55	 financings).	 	 Entergy	 Gulf	 States	 Louisiana's	 and	 Entergy	 Louisiana's	 Hurricane	 Katrina	 and Hurricane	Rita	storm	costs	were	financed	primarily	by	Act	55	financings,	as	discussed	below.	 	Entergy	Gulf	States	Louisiana	and	Entergy Louisiana	also	filed	an	application	requesting	LPSC	approval	for	ancillary	issues	including	the	mechanism	to	flow	charges	and	Act	55	financing savings	to	customers	via	a	Storm	Cost	Offset	rider.

In	December	2009,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	entered	into	a	stipulation	agreement	with	the	LPSC	Staff	that provides	for	total	recoverable	costs	of	approximately	$234	million	for	Entergy	Gulf	States	Louisiana	and	$394	million	for	Entergy	Louisiana, including	carrying	costs.		Under	this	stipulation,	Entergy	Gulf	States	Louisiana	agrees	not	to	recover	$4.4	million	and	Entergy	Louisiana	agrees not	to	recover	$7.2	million	of	their	storm	restoration	spending.		The	stipulation	also	permits	replenishing	Entergy	Gulf	States	Louisiana's	storm reserve	 in	 the	amount	of	$90	million	and	Entergy	Louisiana's	storm	reserve	in	the	amount	of	$200	million	when	the	Act	55	financings	are accomplished.		In	March	and	April	2010,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	other	parties	to	the	proceeding	filed	with	the LPSC	an	uncontested	stipulated	settlement	that	includes	these	terms	and	also	includes

Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	proposals	under	the	Act	55	financings,	which	includes	a	commitment	to	pass	on	to customers	a	minimum	of	$15.5	million	and	$27.8	million	of	customer	benefits,	respectively,	through	prospective	annual	rate	reductions	of	$3.1 million	and	$5.6	million	for	five	years.		A	stipulation	hearing	was	held	before	the	ALJ	on	April	13,	2010.		On	April	21,	2010,	the	LPSC	approved the	settlement	and	subsequently	issued	two	financing	orders	and	one	ratemaking	order	intended	to	facilitate	the	implementation	of	the	Act	55 financings.		In	June	2010	the	Louisiana	State	Bond	Commission	approved	the	Act	55	financings.

In	July	2010,	the	Louisiana	Local	Government	Environmental	Facilities	and	Community	Development	Authority	(LCDA)	issued	 $468.9 million	in	bonds	under	Act	55.		From	the	 $462.4	million	of	bond	proceeds	loaned	by	the	LCDA	to	the	LURC,	the	LURC	deposited	 $200	million in	 a	 restricted	 escrow	 account	 as	 a	 storm	 damage	 reserve	 for	 Entergy	 Louisiana	 and	 transferred	$262.4	 million	 directly	 to	 Entergy Louisiana.	 	 From	 the	 bond	 proceeds	 received	 by	 Entergy	 Louisiana	 from	 the	 LURC,	 Entergy	 Louisiana	 used	$262.4	 million	 to	 acquire 2,624,297.11	 Class	 B	 preferred,	 non-voting,	 membership	 interest	 units	 of	 Entergy	 Holdings	 Company	 LLC,	 a	 company	 wholly-owned	 and consolidated	by	Entergy,	that	carry	a	9%	annual	distribution	rate.	Distributions	are	payable	quarterly	commencing	on	September	15,	2010,	and	the membership	interests	have	a	liquidation	price	of	$100	per	unit.	The	preferred	membership	interests	are	callable	at	the	option	of	Entergy	Holdings Company	LLC	after	ten	years	under	the	terms	of	the	LLC	agreement.		The	terms	of	the	membership	interests	include	certain	financial	covenants to	which	Entergy	Holdings	Company	LLC	is	subject,	including	the	requirement	to	maintain	a	net	worth	of	at	least	$1	billion.

In	July	2010,	the	LCDA	issued	another	$244.1	million	in	bonds	under	Act	55.		From	the	 $240.3	million	of	bond	proceeds	loaned	by	the LCDA	to	the	LURC,	the	LURC	deposited	$90	million	in	a	restricted	escrow	account	as	a	storm	damage	reserve	for	Entergy	Gulf	States	Louisiana and	 transferred	$150.3	million	directly	to	Entergy	Gulf	States	Louisiana.		From	the	bond	proceeds	received	by	Entergy	Gulf	States	Louisiana from	the	LURC,	Entergy	Gulf	States	Louisiana	used	$150.3	million	to	acquire	1,502,643.04	Class	B	preferred,	non-voting,	membership	interest units	 of	 Entergy	 Holdings	 Company	 LLC,	 a	 company	 wholly-owned	 and	 consolidated	 by	 Entergy,	 that	 carry	 a	9%	 annual	 distribution rate.		Distributions	are	payable	quarterly	commencing	on	September	15,	2010,	and	the	membership	interests	have	a	liquidation	price	of	$100	per unit.		The	preferred	membership	interests	are	callable	at	the	option	of	Entergy	Holdings	Company	LLC	after	ten	years	under	the	terms	of	the	LLC agreement.		The	terms	of	the	membership	interests	include	certain	financial	covenants	to	which	Entergy	Holdings	Company	LLC	is	subject, including	the	requirement	to	maintain	a	net	worth	of	at	least	$1	billion.

Entergy,	Entergy	Gulf	States	Louisiana,	and	Entergy	Louisiana	do	not	report	the	bonds	on	their	balance	sheets	because	the	bonds	are	the obligation	of	the	LCDA,	and	there	is	no	recourse	against	Entergy,	Entergy	Gulf	States	Louisiana	or	Entergy	Louisiana	in	the	event	of	a	bond default.		To	service	the	bonds,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	collect	a	system	restoration	charge	on	behalf	of	the	LURC, and	remit	the	collections	to	the	bond	indenture	trustee.		Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	do	not	report	the	collections	as revenue	because	they	are	merely	acting	as	the	billing	and	collection	agents	for	the	state.

# Hurricane	Katrina	and	Hurricane	Rita

In	August	 and	 September	 2005,	 Hurricanes	 Katrina	 and	 Rita	 caused	 catastrophic	 damage	 to	 large	 portions	 of	 the	 Utility's	 service territories	in	Louisiana,	Mississippi,	and	Texas,	including	the	effect	of	extensive	flooding	that	resulted	from	levee	breaks	in	and	around	the	greater New	Orleans	area.		The	storms	and	flooding	resulted	in	widespread	power	outages,	significant	damage	to	electric	distribution,	transmission,	and generation	and	gas	infrastructure,	and	the	loss	of	sales	and	customers	due	to	mandatory	evacuations	and	the	destruction	of	homes	and	businesses.

In	March	2008,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	 the	Louisiana	Utilities	Restoration	Corporation	(LURC),	an instrumentality	of	 the	State	of	Louisiana,	filed	at	 the	LPSC	an	application	requesting	 that	 the	LPSC	grant	financing	orders	authorizing	 the financing	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	storm	costs,	storm	reserves,	and	issuance	costs	pursuant	to	Act	55	of	the Louisiana	Legislature	(Act	55	financings).		The	Act	55	financings	are	expected	to	produce	additional	customer	benefits	as	compared	to	traditional securitization.		Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	also	filed	an	application	requesting	LPSC	approval	for	ancillary	issues

including	the	mechanism	to	flow	charges	and	savings	to	customers	via	a	Storm	Cost	Offset	rider.	 	On	April	8,	2008,	the	Louisiana	Public Facilities	Authority	(LPFA),	which	is	the	issuer	of	the	bonds	pursuant	to	the	Act	55	financings,	approved	requests	for	the	Act	55	financings.		On April	10,	2008,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	and	the	LPSC	Staff	filed	with	the	LPSC	an	uncontested	stipulated	settlement that	includes	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana's	proposals	under	the	Act	55	financings,	which	includes	a	commitment	to	pass on	to	customers	a	minimum	of	$10	million	and	$30	million	of	customer	benefits,	respectively,	through	prospective	annual	rate	reductions	of	$2 million	and	$6	million	for	five	years.		On	April	16,	2008,	the	LPSC	approved	the	settlement	and	issued	two	financing	orders	and	one	ratemaking order	intended	to	facilitate	implementation	of	the	Act	55	financings.		In	May	2008	the	Louisiana	State	Bond	Commission	granted	final	approval	of the	Act	55	financings.

In	July	2008,	the	LPFA	issued	$687.7	million	in	bonds	under	the	aforementioned	Act	55.		From	the	$679	million	of	bond	proceeds	loaned by	the	LPFA	to	the	LURC,	the	LURC	deposited	$152	million	in	a	restricted	escrow	account	as	a	storm	damage	reserve	for	Entergy	Louisiana	and transferred	$527	 million	 directly	 to	 Entergy	 Louisiana.	 	 From	 the	 bond	 proceeds	 received	 by	 Entergy	 Louisiana	 from	 the	 LURC,	 Entergy Louisiana	invested	$545	million,	 including	$17.8	million	that	was	withdrawn	from	the	restricted	escrow	account	as	approved	by	the	April	16, 2008	LPSC	orders,	in	exchange	for	5,449,861.85	Class	A	preferred,	non-voting,	membership	interest	units	of	Entergy	Holdings	Company	LLC,	a company	wholly-owned	and	consolidated	by	Entergy,	that	carry	a	10%	annual	distribution	rate.		Distributions	are	payable	quarterly	commencing on	September	15,	2008	and	have	a	liquidation	price	of	$100	per	unit.		The	preferred	membership	interests	are	callable	at	the	option	of	Entergy Holdings	Company	LLC	after	ten	years	under	the	terms	of	the	LLC	agreement.		The	terms	of	the	membership	interests	include	certain	financial covenants	to	which	Entergy	Holdings	Company	LLC	is	subject,	including	the	requirement	to	maintain	a	net	worth	of	at	least	$1	billion.

In	August	2008,	the	LPFA	issued	 $278.4	million	in	bonds	under	the	aforementioned	Act	55.		From	the	 $274.7	million	of	bond	proceeds loaned	by	the	LPFA	to	the	LURC,	the	LURC	deposited	$87	million	in	a	restricted	escrow	account	as	a	storm	damage	reserve	for	Entergy	Gulf States	Louisiana	and	transferred	$187.7	million	directly	to	Entergy	Gulf	States	Louisiana.		From	the	bond	proceeds	received	by	Entergy	Gulf States	Louisiana	from	the	LURC,	Entergy	Gulf	States	Louisiana	invested	$189.4	million,	 including	$1.7	million	that	was	withdrawn	from	the restricted	 escrow	 account	 as	 approved	 by	 the	April	 16,	 2008	 LPSC	 orders,	 in	 exchange	 for	1,893,918.39	 Class	A	 preferred,	 non-voting, membership	interest	units	of	Entergy	Holdings	Company	LLC	that	carry	a	10%	annual	distribution	rate.		Distributions	are	payable	quarterly commencing	on	September	15,	2008	and	have	a	liquidation	price	of	$100	per	unit.		The	preferred	membership	interests	are	callable	at	the	option of	Entergy	Holdings	Company	LLC	after	ten	years	under	the	terms	of	the	LLC	agreement.		The	terms	of	the	membership	interests	include	certain financial	covenants	 to	which	Entergy	Holdings	Company	LLC	 is	subject,	 including	 the	requirement	 to	maintain	a	net	worth	of	at	 least	$1 billion.		In	February	2012,	Entergy	Gulf	States	Louisiana	sold	500,000	of	its	Class	A	preferred	membership	units	in	Entergy	Holdings	Company LLC,	a	wholly-owned	Entergy	subsidiary,	to	a	third	party	in	exchange	for	$51	million	plus	accrued	but	unpaid	distributions	on	the	units.		The 500,000	preferred	membership	units	are	mandatorily	redeemable	in	January	2112.

Entergy,	Entergy	Gulf	States	Louisiana,	and	Entergy	Louisiana	do	not	report	the	bonds	on	their	balance	sheets	because	the	bonds	are	the obligation	of	the	LPFA,	and	there	is	no	recourse	against	Entergy,	Entergy	Gulf	States	Louisiana	or	Entergy	Louisiana	in	the	event	of	a	bond default.		To	service	the	bonds,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	collect	a	system	restoration	charge	on	behalf	of	the	LURC, and	 remit	 the	 collections	 to	 the	 bond	 indenture	 trustee.	 	 Entergy,	 Entergy	 Gulf	 States	 Louisiana,	 and	 Entergy	 Louisiana	 do	 not	 report	 the collections	as	revenue	because	they	are	merely	acting	as	the	billing	and	collection	agent	for	the	state.

On	July	1,	2013,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a	joint	stipulation,	wherein	both	parties	agreed that	approximately	$32	million	in	storm	restoration	costs	incurred	in	2011	and	2012	were	prudently	incurred	and	chargeable	to	the	storm	damage reserve,	 while	 approximately	$700,000	 in	 prudently	 incurred	 costs	 were	 more	 properly	 recoverable	 through	 the	 formula	 rate	 plan.	Entergy Mississippi	and	the	Mississippi	Public

Utilities	Staff	also	agreed	that	the	storm	damage	accrual	should	be	increased	from	$750,000	per	month	to	$1.75	million	per	month.	In	September 2013	the	MPSC	approved	the	joint	stipulation	with	the	increase	in	the	storm	damage	accrual	effective	with	October	2013	bills.

In	October	2006,	the	City	Council	approved	a	rate	filing	settlement	agreement	that,	among	other	things,	authorized	a	$75	million	storm reserve	 for	 damage	 from	 future	 storms,	 which	 will	 be	 created	 over	 a	 ten-year	 period	 through	 a	 storm	 reserve	 rider	 that	 began	 in	 March 2007.		These	storm	reserve	funds	are	held	in	a	restricted	escrow	account	until	needed	in	response	to	a	storm.

In	August	2012,	Hurricane	Isaac	caused	extensive	damage	to	Entergy	New	Orleans's	service	area.	The	storm	resulted	in	widespread	power outages,	significant	damage	primarily	to	distribution	infrastructure,	and	the	loss	of	sales	during	the	power	outages.	Total	restoration	costs	for	the repair	and/or	replacement	of	Entergy	New	Orleans's	electric	facilities	damaged	by	Hurricane	Isaac	were	$47.3	million.	Entergy	New	Orleans withdrew	$17.4	million	from	the	storm	reserve	escrow	account	to	partially	offset	these	costs.	Entergy	New	Orleans	plans	to	make	a	filing	with	the City	Council	in	the	first	quarter	2014	seeking	certification	of	these	costs.

# New	Nuclear	Generation	Development	Costs

Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	have	been	developing	and	are	preserving	a	project	option	for	new	nuclear	generation at	River	Bend.		In	March	2010,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	with	the	LPSC	seeking	approval	to	continue	the	limited development	activities	necessary	to	preserve	an	option	to	construct	a	new	unit	at	River	Bend.		The	testimony	and	legal	briefs	of	the	LPSC	staff generally	support	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana,	although	other	parties	filed	briefs,	without	supporting testimony,	in	opposition	to	the	request.		At	an	evidentiary	hearing	in	October	2011,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	the LPSC	staff	presented	testimony	in	support	of	certification	of	activities	to	preserve	an	option	for	a	new	nuclear	plant	at	River	Bend.		The	ALJ recommended,	however,	that	the	LPSC	decline	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	on	the	basis	that	the	LPSC's rule	on	new	nuclear	development	does	not	apply	to	activities	to	preserve	an	option	to	develop	and	on	the	further	grounds	that	the	companies improperly	engaged	in	advanced	preparation	activities	prior	to	certification.		There	has	been	no	suggestion	that	the	planning	activities	or	costs incurred	were	imprudent.		At	its	June	28,	2012	meeting	the	LPSC	voted	to	uphold	the	ALJ's	decision	and	directed	that	Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	be	permitted	to	seek	recovery	of	these	costs	in	their	anticipated,	upcoming	rate	case	filings,	fully	reserving	the LPSC's	right	to	determine	the	recoverability	of	such	costs	in	rates.		The	LPSC	approved	a	settlement	of	Entergy	Gulf	States	Louisiana's	and Entergy	Louisiana's	rate	case	filings	and	approved	the	extension	of	the	current	formula	rate	plans	of	Entergy	Gulf	States	Louisiana	and	Entergy Louisiana	and	provided	for	an	eight-year	amortization	of	costs	incurred	in	connection	with	the	potential	development	of	a	new	nuclear	unit	at River	Bend,	without	carrying	costs,	beginning	in	December	2014,	provided,	however,	that	amortization	of	these	costs	shall	not	result	in	a	future rate	increase.	As	of	December	31,	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	each	have	a	regulatory	asset	of	$29.5	million	on	its balance	sheet	related	to	these	new	nuclear	generation	development	costs.

Pursuant	 to	 the	 Mississippi	 Baseload	Act	 and	 the	 Mississippi	 Public	 Utilities	Act,	 Entergy	 Mississippi	 has	 been	 developing	 and	 is preserving	a	project	option	for	new	nuclear	generation	at	Grand	Gulf	Nuclear	Station.		This	project	is	in	the	early	stages,	and	several	issues	remain to	be	addressed	over	time	before	significant	additional	capital	would	be	committed	to	this	project.		In	October	2010,	Entergy	Mississippi	filed	an application	with	the	MPSC	requesting	that	the	MPSC	determine	that	it	is	in	the	public	interest	to	preserve	the	option	to	construct	new	nuclear generation	at	Grand	Gulf	and	that	the	MPSC	approve	the	deferral	of	Entergy	Mississippi's	costs	incurred	to	date	and	in	the	future	related

to	this	project,	including	the	accrual	of	AFUDC	or	similar	carrying	charges.		In	October	2011,	Entergy	Mississippi	and	the	Mississippi	Public Utilities	Staff	filed	with	the	MPSC	a	joint	stipulation	that	the	MPSC	approved	in	November	2011.		The	stipulation	states	that	there	should	be	a deferral	of	the	$57	million	of	costs	incurred	through	September	2011	in	connection	with	planning,	evaluation,	monitoring,	and	other	and	related generation	resource	development	activities	for	new	nuclear	generation	at	Grand	Gulf.		The	costs	shall	be	treated	as	a	regulatory	asset	until	the proceeding	is	resolved.		The	Mississippi	Public	Utilities	Staff	and	Entergy	Mississippi	also	agree	that	the	MPSC	should	conduct	a	hearing	to consider	the	relief	requested	by	Entergy	Mississippi	in	its	application,	including	evidence	regarding	whether	costs	incurred	in	connection	with planning,	evaluation,	monitoring,	and	other	and	related	generation	resource	development	activities	for	new	nuclear	generation	at	Grand	Gulf	were prudently	incurred	and	are	otherwise	allowable.		The	Mississippi	Public	Utilities	Staff	and	Entergy	Mississippi	further	agree	that	such	prudently incurred	costs	shall	be	recoverable	in	a	manner	to	be	determined	by	the	MPSC.		In	the	Stipulation,	the	Mississippi	Public	Utilities	Staff	and Entergy	Mississippi	agree	that	the	development	of	a	nuclear	unit	project	option	is	consistent	with	the	Mississippi	Baseload	Act.		The	Mississippi Public	Utilities	Staff	and	Entergy	Mississippi	further	agree	that	the	deferral	of	costs	incurred	in	connection	with	planning,	evaluation,	monitoring, and	other	and	related	generation	resource	development	activities	for	new	nuclear	generation	at	Grand	Gulf	also	is	consistent	with	the	Mississippi Baseload	Act.		Entergy	Mississippi	will	not	accrue	carrying	charges	or	continue	to	accrue	AFUDC	on	the	costs,	pending	the	outcome	of	the proceeding.		Further	proceedings	before	the	MPSC	have	not	been	scheduled.

# 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	of the	Texas	retail	customers	of	Entergy	Gulf	States,	Inc.	who	were	billed	and	paid	for	electric	power	from	January	1,	1994	to	the	present.		The named	 defendants	 include	 Entergy	 Corporation,	 Entergy	 Services,	 Entergy	 Power,	 Entergy	 Power	 Marketing	 Corp.,	 and	 Entergy Arkansas.		Entergy	Gulf	States,	Inc.	was	not	a	named	defendant,	but	was	alleged	to	be	a	co-conspirator.		The	court	granted	the	request	of	Entergy Gulf	States,	Inc.	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	less	expensive	power	offered	from	off-system	suppliers.		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	 stated	 in	 their	 pleadings	 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.		The	plaintiffs' experts	have	tendered	a	report	calculating	damages	in	a	large	range,	from	$153	million	to	$972	million	in	present	value,	under	various	scenarios	as of	the	date	of	the	report.		The	Entergy	defendants	have	tendered	expert	reports	challenging	the	assumptions,	methodologies,	and	conclusions	of	the plaintiffs'	expert	reports.

The	case	is	pending	in	state	district	court,	and	in	March	2012	the	court	found	that	the	case	met	the	requirements	to	be	maintained	as	a	class action	under	Texas	law.		On	April	30,	2012,	the	court	entered	an	order	certifying	the	class.		The	defendants	have	appealed	the	order	to	the	Texas Court	of	Appeals	–	First	District	and	oral	argument	was	held	in	May	2013.	The	appeal	is	pending	and	proceedings	in	district	court	are	stayed	until the	appeal	is	resolved.

# NOTE	3.				INCOME	TAXES	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Income	taxes	from	continuing	operations	for	2013,	2012,	and	2011	for	Entergy	Corporation	and	Subsidiaries	consist	of	the	following:

| Federal | $88,291 | ($47,851) | $452,713 |
| :--- | :--- | :--- | :--- |
| Foreign | 101 | 143 | 130 |
| State | 20,584 | (41,516) | 152,711 |
| Total | 108,976 | (89,224) | 605,554 |
| Deferred\tand\tnon-current\t-\tnet | 126,935 | 131,130 | (311,708) |
| Investment\ttax\tcredit |  |  |  |
| adjustments\t-\tnet | (9,930) | (11,051) | (7,583) |
| Income\ttax\texpense\tfrom |  |  |  |
| continuing\toperations | $225,981 | $30,855 | $286,263 |

Income	taxes	for	2013,	2012,	and	2011	for	Entergy's	Registrant	Subsidiaries	consist	of	the	following:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |  |
| Federal | ($13,574) | $12,176 | ($30,973) | $2,498 | $15,017 | $37,199 | ($6,199) |
| State | 6,122 | (9,939) | (5,692) | 4,849 | (1,221) | (843) | 15,845 |
| Total | (7,452) | 2,237 | (36,665) | 7,347 | 13,796 | 36,356 | 9,646 |
| Deferred\tand\tnon-\ncurrent\t-\tnet | 101,253 | 57,620 | 121,416 | 41,150 | (11,952) | (4,639) | 60,614 |
| Investment\ttax\tcredit |  |  |  |  |  |  |  |
| adjustments\t-\tnet | (2,014) | (3,038) | (2,874) | 1,260 | (225) | (1,609) | (1,407) |
| Income\ttaxes | $91,787 | $56,819 | $81,877 | $49,757 | $1,619 | $30,108 | $68,853 |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |  |
| Federal | $64,069 | ($66,081) | ($132,999) | $3,188 | ($9,484) | ($114,677) | ($50,491) |
| State | 6,712 | 9,535 | (1,269) | (4,425) | (1,617) | 4,933 | (8,544) |
| Total | 70,781 | (56,546) | (134,268) | (1,237) | (11,101) | (109,744) | (59,035) |
| Deferred\tand\tnon-\ncurrent\t-\tnet | 26,042 | 112,390 | 8,463 | 59,045 | 18,586 | 144,471 | 137,832 |
| Investment\ttax\tcredit |  |  |  |  |  |  |  |
| adjustments\t-\tnet | (2,017) | (3,228) | (3,117) | 871 | (245) | (1,609) | (1,682) |
| Income\ttaxes | $94,806 | $52,616 | ($128,922) | $58,679 | $7,240 | $33,118 | $77,115 |

| 2011 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |  |
| Federal | ($12,448) | ($30,106) | ($136,800) | ($9,466) | $14,641 | ($33,045) | $139,529 |
| State | (1,751) | 15,950 | 34,832 | 6,069 | 1,724 | 3,153 | 16,825 |
| Total | (14,199) | (14,156) | (101,968) | (3,397) | 16,365 | (29,892) | 156,354 |
| Deferred\tand\tnon-current\n-\tnet | 148,978 | 107,250 | (265,046) | 32,380 | (201) | 80,993 | (84,505) |
| Investment\ttax\tcredit |  |  |  |  |  |  |  |
| adjustments\t-\tnet | (2,014) | (3,358) | (3,197) | (182) | (302) | (1,609) | 3,104 |
| Income\ttaxes | $132,765 | $89,736 | ($370,211) | $28,801 | $15,862 | $49,492 | $74,953 |

Total	income	taxes	for	Entergy	Corporation	and	Subsidiaries	differ	from	the	amounts	computed	by	applying	the	statutory	income	tax	rate to	income	before	income	taxes.		The	reasons	for	the	differences	for	the	years	2013,	2012,	and	2011	are:

| Net	income	attributable	to	Entergy	Corporation | $711,902 | $846,673 | $1,346,439 |
| :--- | :--- | :--- | :--- |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 18,670 | 21,690 | 20,933 |
| Consolidated\tnet\tincome | 730,572 | 868,363 | 1,367,372 |
| Income\ttaxes | 225,981 | 30,855 | 286,263 |
| Income\tbefore\tincome\ttaxes | $956,553 | $899,218 | $1,653,635 |
| Computed\tat\tstatutory\trate\t(35%) | $334,794 | $314,726 | $578,772 |
| Increases\t(reductions)\tin\ttax\tresulting\tfrom: |  |  |  |
| State\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffect | 13,599 | 40,699 | 93,940 |
| Regulatory\tdifferences\t-\tutility\tplant\titems | 32,324 | 35,527 | 39,970 |
| Equity\tcomponent\tof\tAFUDC | (22,356) | (30,838) | (30,184) |
| Amortization\tof\tinvestment\ttax\tcredits | (13,535) | (14,000) | (14,962) |
| Flow-through\t/\tpermanent\tdifferences | (301) | (14,801) | (17,848) |
| Net-of-tax\tregulatory\tliability\t(a) | (2,899) | (4,356) | 65,357 |
| Deferred\ttax\treversal\ton\tPPA\tsettlement\t(a) | — | — | (421,819) |
| Deferred\ttax\tasset\ton\tadditional\tdepreciation\t(b) | — | (155,300) | — |
| Termination\tof\tbusiness\treorganization | (27,192) | — | — |
| Write-off\tof\tregulatory\tasset\tfor\tincome\ttaxes | — | 42,159 | — |
| Capital\tlosses | — | (20,188) | — |
| Provision\tfor\tuncertain\ttax\tpositions\t(c) | (59,249) | (159,957) | 2,698 |
| Valuation\tallowance | (31,573) |  |  |
| Other\t-\tnet | 2,369 | (2,816) | (9,661) |
| Total\tincome\ttaxes\tas\treported | $225,981 | $30,855 | $286,263 |
| Effective\tIncome\tTax\tRate | 23.6% | 3.4% | 17.3% |

(a) See	"Income	Tax	Audits	-	2006-2007	IRS	Audit"	below	for	discussion	of	these	items.

(b) See	"Income	Tax	Audits	-	2004-2005	IRS	Audit"	below	for	discussion	of	this	item.

Total	income	taxes	for	the	Registrant	Subsidiaries	differ	from	the	amounts	computed	by	applying	the	statutory	income	tax	rate	to	income before	taxes.		The	reasons	for	the	differences	for	the	years	2013,	2012,	and	2011	are:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $161,948 | $161,662 | $252,464 | $82,159 | $11,683 | $57,881 | $113,664 |
| Income\ttaxes | 91,787 | 56,819 | 81,877 | 49,757 | 1,619 | 30,108 | 68,853 |
| Pretax\tincome | $253,735 | $218,481 | $334,341 | $131,916 | $13,302 | $87,989 | $182,517 |
| Computed\tat\tstatutory\nrate\t(35%) | $88,807 | $76,468 | $117,019 | $46,171 | $4,656 | $30,796 | $63,881 |
| Increases\t(reductions)\tin\ntax\tresulting\tfrom: |  |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet |  |  |  |  |  |  |  |
| of\tfederal\tincome\ttax |  |  |  |  |  |  |  |
| effect | 10,954 | 7,719 | 11,365 | 4,564 | 1,012 | (897) | 5,900 |
| Regulatory\tdifferences\t-\nutility\tplant\titems | 7,938 | 4,865 | 2,140 | 2,603 | 453 | 3,256 | 11,070 |
| Equity\tcomponent\tof\nAFUDC | (3,820) | (2,822) | (10,278) | (764) | (322) | (1,626) | (2,724) |
| Amortization\tof\ninvestment\ttax\tcredits | (1,989) | (3,018) | (2,846) | (260) | (216) | (1,596) | (3,476) |
| Flow-through\t/\npermanent\tdifferences | 2,540 | 2,377 | 1,269 | 1,702 | (4,402) | 2,467 | (491) |
| Net-of-tax\tregulatory\nliability\t(a) | — | — | (2,899) | — | — | — | — |
| Termination\tof\tbusiness\nreorganization | (6,753) | (3,619) | (3,834) | (4,177) | (501) | (3,542) | (13) |
| Non-taxable\tdividend\nincome | — | (9,612) | (27,341) | — | — | — | — |
| Provision\tfor\tuncertain\ntax\tpositions | (6,527) | (15,557) | (3,088) | (326) | 795 | 1,027 | (5,353) |
| Other\t-\tnet | 637 | 18 | 370 | 244 | 144 | 223 | 59 |
| Total\tincome\ttaxes | $91,787 | $56,819 | $81,877 | $49,757 | $1,619 | $30,108 | $68,853 |
| Effective\tIncome\tTax\nRate | 36.2% | 26.0% | 24.5% | 37.7% | 12.2% | 34.2% | 37.7% |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $152,365 | $158,977 | $281,081 | $46,768 | $17,065 | $41,971 | $111,866 |
| Income\ttaxes\t(benefit) | 94,806 | 52,616 | (128,922) | 58,679 | 7,240 | 33,118 | 77,115 |
| Pretax\tincome | $247,171 | $211,593 | $152,159 | $105,447 | $24,305 | $75,089 | $188,981 |
| Computed\tat\tstatutory\trate |  |  |  |  |  |  |  |
| (35%) | $86,510 | $74,058 | $53,256 | $36,906 | $8,507 | $26,281 | $66,143 |
| Increases\t(reductions)\tin\ttax\nresulting\tfrom: |  |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof\nfederal\tincome\ttax\teffect | 11,282 | 5,087 | 1,976 | 3,944 | 505 | 3,115 | 6,652 |
| Regulatory\tdifferences\t-\nutility\tplant\titems | 6,778 | 8,472 | 312 | 2,619 | 2,289 | 3,668 | 11,389 |
| Equity\tcomponent\tof\nAFUDC | (2,495) | (3,042) | (12,919) | (1,383) | (276) | (1,587) | (9,136) |
| Amortization\tof\ninvestment\ttax\tcredits | (1,992) | (3,204) | (3,089) | (264) | (240) | (1,596) | (3,480) |
| Flow-through\t/\tpermanent\ndifferences | 3,427 | (7,646) | 1,397 | 1,961 | (4,385) | 1,585 | (357) |
| Net-of-tax\tregulatory\nliability\t(a) | — | — | (4,356) | — | — | — | — |
| Non-taxable\tdividend\nincome | — | (9,836) | (27,336) | — | — | — | — |
| Expense\t(benefit)\tof |  |  |  |  |  |  |  |
| Entergy\tCorporation |  |  |  |  |  |  |  |
| expenses | (19,403) | (17,703) | — | 14,449 | 2,758 | — | (10,241) |
| Provision\tfor\tuncertain\ntax\tpositions | 11,227 | 8,745 | (143,583) | 870 | (2,095) | 1,651 | 17,966 |
| Change\tin\tregulatory\nrecovery | — | (553) | 7,854 | — | — | — | — |
| Other\t--\tnet | (528) | (1,762) | (2,434) | (423) | 177 | 1 | (1,821) |
| Total\tincome\ttaxes | $94,806 | $52,616 | ($128,922) | $58,679 | $7,240 | $33,118 | $77,115 |
| Effective\tIncome\tTax\tRate | 38.4% | 24.9% | (84.7%) | 55.6% | 29.8% | 44.1% | 40.8% |

| 2011 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $164,891 | $201,604 | $473,923 | $108,729 | $35,976 | $80,845 | $64,197 |
| Income\ttaxes\t(benefit) | 132,765 | 89,736 | (370,211) | 28,801 | 15,862 | 49,492 | 74,953 |
| Pretax\tincome | $297,656 | $291,340 | $103,712 | $137,530 | $51,838 | $130,337 | $139,150 |
| Computed\tat\tstatutory\nrate\t(35%) | $104,180 | $101,969 | $36,299 | $48,136 | $18,143 | $45,618 | $48,703 |
| Increases\t(reductions)\nin\ttax\tresulting\tfrom: |  |  |  |  |  |  |  |
| State\tincome\ttaxes |  |  |  |  |  |  |  |
| net\tof\tfederal\tincome |  |  |  |  |  |  |  |
| tax\teffect | 13,727 | 9,618 | 943 | 3,211 | 3,350 | 2,033 | 4,436 |
| Regulatory |  |  |  |  |  |  |  |
| differences\t-\tutility |  |  |  |  |  |  |  |
| plant\titems | 10,079 | 8,379 | 1,404 | 2,038 | 3,860 | 4,003 | 10,207 |
| Equity\tcomponent\tof\nAFUDC | (3,363) | (3,181) | (11,315) | (2,963) | (215) | (1,322) | (7,825) |
| Amortization\tof |  |  |  |  |  |  |  |
| investment\ttax |  |  |  |  |  |  |  |
| credits | (1,992) | (3,336) | (3,168) | (960) | (295) | (1,596) | (3,480) |
| Net-of-tax\tregulatory\nliability\t(a) | — | — | 65,357 | — | — | — | — |
| Deferred\ttax\treversal |  |  |  |  |  |  |  |
| on\tPPA\tsettlement |  |  |  |  |  |  |  |
| (a) | — | — | (421,819) | — | — | — | — |
| Flow-through\t/ |  |  |  |  |  |  |  |
| permanent |  |  |  |  |  |  |  |
| differences | (1,365) | 587 | (1,285) | 304 | (4,983) | 88 | 529 |
| Non-taxable\ndividend\tincome | — | (11,364) | (27,336) | — | — | — | — |
| Expense\t(benefit)\tof |  |  |  |  |  |  |  |
| Entergy\tCorporation |  |  |  |  |  |  |  |
| expenses | — | (5,694) | — | (21,248) | (6,235) | (16) | 16,559 |
| Provision\tfor |  |  |  |  |  |  |  |
| uncertain\ttax |  |  |  |  |  |  |  |
| positions | 12,016 | (7,144) | (4,880) | (2) | 2,241 | 717 | 5,878 |
| Other\t--\tnet | (517) | (98) | (4,411) | 285 | (4) | (33) | (54) |
| Total\tincome\ntaxes | $132,765 | $89,736 | ($370,211) | $28,801 | $15,862 | $49,492 | $74,953 |
| Effective\tIncome\tTax\nRate | 44.6% | 30.8% | (357.0%) | 20.9% | 30.6% | 38.0% | 53.9% |

Significant	components	of	accumulated	deferred	income	taxes	and	taxes	accrued	for	Entergy	Corporation	and	Subsidiaries	as	of December	31,	2013	and	2012	are	as	follows:

| Plant	basis	differences	-	net | ($7,941,319) | ($8,240,342) |
| :--- | :--- | :--- |
| Regulatory\tassets | (922,312) | (898,143) |
| Nuclear\tdecommissioning\ttrusts | (1,100,439) | (848,918) |
| Pension,\tnet\tfunding | (299,951) | (305,676) |
| Combined\tunitary\tstate\ttaxes | (183,934) | (233,210) |
| Power\tpurchase\tagreements | (8,096) | — |
| Other | (404,749) | (485,550) |
| Total | (10,860,800) | (11,011,839) |
| Deferred\ttax\tassets: |  |  |
| Nuclear\tdecommissioning\tliabilities | 754,828 | 733,103 |
| Regulatory\tliabilities | 403,370 | 404,852 |
| Pension\tand\tother\tpost-employment\tbenefits | 469,190 | 664,569 |
| Sale\tand\tleaseback | 176,119 | 195,074 |
| Compensation | 125,552 | 53,388 |
| Accumulated\tdeferred\tinvestment\ttax\tcredit | 106,777 | 110,690 |
| Provision\tfor\tallowances\tand\tcontingencies | 66,026 | 61,576 |
| Power\tpurchase\tagreements | — | 43,717 |
| Net\toperating\tloss\tcarryforwards | 548,756 | 960,235 |
| Capital\tlosses\tand\tmiscellaneous\ttax\tcredits | 13,140 | 23,114 |
| Valuation\tallowance | (28,146) | (86,881) |
| Other | 109,606 | 78,721 |
| Total | 2,745,218 | 3,242,158 |
| Noncurrent\taccrued\ttaxes\t(including\tunrecognized |  |  |
| tax\tbenefits) | (400,276) | (210,534) |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | ($8,515,858) | ($7,980,215) |

Entergy's	estimated	tax	attributes	carryovers	and	their	expiration	dates	as	of	December	31,	2013	are	as	follows:

As	a	result	of	the	accounting	for	uncertain	tax	positions,	the	amount	of	the	deferred	tax	assets	reflected	in	the	financial	statements	is	less than	the	amount	of	the	tax	effect	of	the	federal	and	state	net	operating	loss	carryovers,	tax	credit	carryovers,	and	other	tax	attributes	reflected	on income	 tax	 returns.	Because	it	is	more	likely	than	not	that	the	benefit	from	certain	state	net	operating	loss	carryovers	will	not	be	utilized,	a valuation	allowance	of	$23.5	million	has	been	provided	on	the	deferred	tax	assets	relating	to	these	state	net	operating	loss	carryovers.

In	the	third	quarter	2013,	Entergy	reduced	a	valuation	allowance	by	$44	million	($28	million	net	of	the	federal	income	tax	effect)	that	had been	provided	on	a	state	net	operating	loss	carryover	due	to	the	prospective	utilization	of	such	loss	carryover.

Significant	components	of	accumulated	deferred	income	taxes	and	taxes	accrued	for	the	Registrant	Subsidiaries	as	of	 December	31,	2013 and	2012	are	as	follows:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Deferred\ttax\tliabilities: |  |  |  |  |  |  |  |
| Plant\tbasis\tdifferences\t-\tnet | ($1,613,195) | ($1,259,173) | ($1,347,534) | ($727,545) | ($196,726) | ($759,263) | ($698,151) |
| Regulatory\tassets | (212,339) | (102,362) | (255,068) | (33,277) | — | (205,402) | (113,849) |
| Nuclear\tdecommissioning\ntrusts | (110,004) | (32,574) | (50,248) | — | — | — | (58,308) |
| Pension,\tnet\tfunding | (79,589) | (45,342) | (50,630) | (24,392) | (11,606) | (23,598) | (21,187) |
| Deferred\tfuel | (26,946) | (4,361) | (512) | (21,823) | 63 | (470) | (129) |
| Power\tpurchase\tagreements | (7,053) | (20,234) | — | — | 13 | 1,269 | — |
| Other | (62,046) | (25,694) | (69,194) | (10,732) | (13,446) | (58,963) | (8,969) |
| Total | ($2,111,172) | ($1,489,740) | ($1,773,186) | ($817,769) | ($221,702) | ($1,046,427) | ($900,593) |
| Deferred\ttax\tassets: |  |  |  |  |  |  |  |
| Regulatory\tliabilities | 120,966 | 60,176 | 94,019 | 8,357 | 35,764 | 7,952 | 76,135 |
| Nuclear\tdecommissioning\nliabilities | (64,571) | 49,439 | 92,206 | — | — | — | (71,898) |
| Pension\tand\tother\tpost-\nemployment\tbenefits | (12,132) | 73,136 | 62,999 | (1,345) | 1,532 | (13,417) | (2,073) |
| Sale\tand\tleaseback | — | — | 52,054 | — | — | — | 124,065 |
| Accumulated\tdeferred\ninvestment\ttax\tcredit | 15,281 | 35,297 | 25,913 | 3,263 | 416 | 5,651 | 20,956 |
| Provision\tfor\tallowances\tand\ncontingencies | 12,313 | 14,784 | 3,347 | 13,066 | 8,535 | 5,980 | — |
| Unbilled/deferred\trevenues | 37,825 | (22,340) | 3,026 | 6,791 | 4,226 | 10,655 | — |
| Compensation | 7,131 | 4,701 | 3,470 | 1,778 | 1,696 | 6,774 | 822 |
| Net\toperating\tloss\ncarryforwards | 85,875 | — | 230,592 | 19,400 | — | — | — |
| Capital\tlosses\tand\nmiscellaneous\ttax\tcredits | — | — | — | 6,173 | — | — | — |
| Other | 3,682 | 4,939 | 4,148 | 4,224 | 2,930 | 3,807 | 2,001 |
| Total | 206,370 | 220,132 | 571,774 | 61,707 | 55,099 | 27,402 | 150,008 |
| Noncurrent\taccrued\ttaxes |  |  |  |  |  |  |  |
| (including\tunrecognized\ttax |  |  |  |  |  |  |  |
| benefits) | 22,565 | (279,269) | 25,512 | (6,290) | (5,015) | (37,777) | 10,302 |
| Accumulated\tdeferred |  |  |  |  |  |  |  |
| income\ttaxes\tand\ttaxes |  |  |  |  |  |  |  |
| accrued | ($1,882,237) | ($1,548,877) | ($1,175,900) | ($762,352) | ($171,618) | ($1,056,802) | ($740,283) |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Deferred\ttax\tliabilities: |  |  |  |  |  |  |  |
| Plant\tbasis\tdifferences\t-\nnet | $(1,565,988) | $(1,268,164) | $(1,544,256) | $(727,442) | $(202,496) | $(770,084) | $(759,896) |
| Regulatory\tassets | (172,915) | (100,578) | (249,051) | (27,077) | (4,790) | (220,417) | (119,209) |
| Nuclear\tdecommissioning\ntrusts | (67,025) | (25,472) | (29,493) | — | — | — | (27,809) |
| Pension,\tnet\tfunding | (76,989) | (50,790) | (53,256) | (24,226) | (12,420) | (24,335) | (21,372) |
| Deferred\tfuel | (50,068) | (1,618) | (11,815) | (11,332) | (976) | 3,932 | (445) |
| Other | (55,000) | (27,501) | (92,433) | (12,641) | (10,577) | (23,681) | (6,592) |
| Total | ($1,987,985) | ($1,474,123) | ($1,980,304) | ($802,718) | ($231,259) | ($1,034,585) | ($935,323) |
| Deferred\ttax\tassets: |  |  |  |  |  |  |  |
| Nuclear\tdecommissioning\nliabilities | (63,189) | 51,593 | 92,930 | — | — | — | (65,564) |
| Regulatory\tliabilities | 79,805 | 47,474 | 173,046 | 8,515 | 47,257 | 3,429 | 45,327 |
| Pension\tand\tother\tpost-\nemployment\tbenefits | 1,711 | 98,259 | 87,539 | 2,086 | 1,606 | (16,054) | 2,212 |
| Sale\tand\tleaseback | — | — | 57,423 | — | — | — | 137,651 |
| Accumulated\tdeferred\ninvestment\ttax\tcredit | 16,062 | 36,642 | 27,008 | 2,776 | 500 | 6,210 | 21,492 |
| Provision\tfor\tallowances\nand\tcontingencies | 4,723 | 33,074 | 48,241 | 9,564 | (2,865) | (35,505) | — |
| Power\tpurchase\nagreements | 94 | 37,771 | — | 84 | 21 | 2,752 | — |
| Unbilled/deferred\nrevenues | 27,651 | (23,150) | (7,101) | 9,242 | 3,352 | 12,986 | — |
| Compensation | 3,587 | 580 | 18 | (664) | 13 | 4,547 | 180 |
| Net\toperating\tloss\ncarryforwards | 102,034 | — | 460,367 | 45,475 | — | 20,307 | 86,228 |
| Capital\tlosses\tand\nmiscellaneous\ttax\tcredits | — | — | — | 3,737 | — | — | — |
| Other | 5,565 | 6,106 | 5,513 | 5,021 | 4,472 | 6,707 | 2,000 |
| Total | 178,043 | 288,349 | 944,984 | 85,836 | 54,356 | 5,379 | 229,526 |
| Noncurrent\taccrued\ttaxes |  |  |  |  |  |  |  |
| (including\tunrecognized\ttax |  |  |  |  |  |  |  |
| benefits) | 46,930 | (239,670) | 218,033 | (1,121) | 13,630 | 55,113 | (4,130) |
| Accumulated\tdeferred |  |  |  |  |  |  |  |
| income\ttaxes\tand\ttaxes |  |  |  |  |  |  |  |
| accrued | ($1,763,012) | ($1,425,444) | ($817,287) | ($718,003) | ($163,273) | ($974,093) | ($709,927) |

The	Registrant	Subsidiaries'	estimated	tax	attributes	carryovers	and	their	expiration	dates	as	of	December	31,	2013	are	as	follows:

As	a	result	of	the	accounting	for	uncertain	tax	positions,	the	amount	of	the	deferred	tax	assets	reflected	in	the	financial	statements	is	less than	the	amount	of	the	tax	effect	of	the	federal	and	state	net	operating	loss	carryovers	and	tax	credit	carryovers.

# Unrecognized	tax	benefits

Accounting	standards	establish	a	"more-likely-than-not"	recognition	threshold	that	must	be	met	before	a	tax	benefit	can	be	recognized	in the	financial	statements.		If	a	tax	deduction	is	taken	on	a	tax	return,	but	does	not	meet	the	more-likely-than-not	recognition	threshold,	an	increase in	income	tax	liability,	above	what	is	payable	on	the	tax	return,	is	required	to	be	recorded.		A	reconciliation	of	Entergy's	beginning	and	ending amount	of	unrecognized	tax	benefits	is	as	follows:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Gross\tbalance\tat\tJanuary\t1 | $4,170,403 | $4,387,780 | $4,949,788 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\ncurrent\tyear | 162,338 | 163,612 | 211,966 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 410,108 | 1,517,797 | 332,744 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (103,360) | (476,873) | (259,895) |
| Settlements | (43,620) | (1,421,913) | (841,528) |
| Lapse\tof\tstatute\tof\tlimitations | (2,645) | — | (5,295) |
| Gross\tbalance\tat\tDecember\t31 | 4,593,224 | 4,170,403 | 4,387,780 |
| Offsets\tto\tgross\tunrecognized\ttax\tbenefits: |  |  |  |
| Credit\tand\tloss\tcarryovers | (4,400,498) | (4,022,535) | (3,212,397) |
| Cash\tpaid\tto\ttaxing\tauthorities | — | — | (363,266) |
| Unrecognized\ttax\tbenefits\tnet\tof\tunused\ttax\tattributes\nand\tpayments\t(a) |  |  |  |
|  | $192,726 | $147,868 | $812,117 |

(a) Potential	tax	liability	above	what	is	payable	on	tax	returns

The	balances	of	unrecognized	tax	benefits	include	$176	million,	$203	million,	 and	$521	million	 as	 of	December	31,	2013,	2012,	and 2011,	respectively,	which,	if	recognized,	would	lower	the	effective	income	tax	rates.	 	Because	of	the	effect	of	deferred	tax	accounting,	the remaining	balances	of	unrecognized	tax	benefits	of	$4.417	billion,	$3.968	billion,	and	$3.867	billion	as	of	December	31,	2013,	2012,	and	2011, respectively,	if	disallowed,	would	not	affect	the	annual	effective	income	tax	rate	but	would	accelerate	the	payment	of	cash	to	the	taxing	authority to	an	earlier	period.

Entergy	has	made	deposits	with	 the	IRS	against	 its	potential	 liabilities	arising	from	audit	adjustments	and	settlements	related	 to	 its uncertain	tax	positions.		Entergy's	practice	is	to	make	additional	deposits	when	necessary	as	the	cash	tax	benefits	of	uncertain	tax	positions	are realized	on	tax	returns.	The	total	amount	of	cash	deposits	shown	for	2011	has	been	fully	offset	against	settled	liabilities	which	arose	in	2012.

Entergy	accrues	interest	expense,	if	any,	related	to	unrecognized	tax	benefits	in	income	tax	expense.		Entergy's	December	31,	2013,	2012, and	2011	accrued	balance	for	the	possible	payment	of	interest	is	approximately	$96.4	million,	$146.3	million,	and	$99	million,	respectively.

A	reconciliation	of	the	Registrant	Subsidiaries'	beginning	and	ending	amount	of	unrecognized	tax	benefits	for	2013,	2012,	and	2011	is	as follows:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\n1,\t2013 | $344,669 | $465,721 | $536,673 | $16,841 | $52,018 | $13,954 | $260,346 |
| Additions\tbased\ton\ttax |  |  |  |  |  |  |  |
| positions\trelated\tto\tthe |  |  |  |  |  |  |  |
| current\tyear | 6,427 | 7,276 | 10,611 | 957 | 583 | 2,170 | 4,170 |
| Additions\tfor\ttax\tpositions\nof\tprior\tyears | 1,228 | 7,189 | 118,025 | 401 | 3,506 | 587 | 8,391 |
| Reductions\tfor\ttax\npositions\tof\tprior\tyears | (3,943) | (15,045) | (38,428) | (1,941) | (962) | (4,186) | (967) |
| Settlements | (668) | (66) | (15,276) | (72) | (3,466) | 492 | (6,755) |
| Gross\tbalance\tat\nDecember\t31,\t2013 | 347,713 | 465,075 | 611,605 | 16,186 | 51,679 | 13,017 | 265,185 |
| Offsets\tto\tgross\nunrecognized\ttax\tbenefits: |  |  |  |  |  |  |  |
| Loss\tcarryovers | (345,674) | (136,151) | (611,605) | (16,186) | (22,078) | (266) | (225,286) |
| Unrecognized\ttax\tbenefits |  |  |  |  |  |  |  |
| net\tof\tunused\ttax\tattributes |  |  |  |  |  |  |  |
| and\tpayments | $2,039 | $328,924 | $— | $— | $29,601 | $12,751 | $39,899 |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\n1,\t2012 | $335,493 | $390,493 | $446,187 | $11,052 | $56,052 | $19,225 | $281,183 |
| Additions\tbased\ton\ttax |  |  |  |  |  |  |  |
| positions\trelated\tto\tthe |  |  |  |  |  |  |  |
| current\tyear | 10,409 | 8,974 | 67,721 | 8,401 | 497 | 1,656 | 8,715 |
| Additions\tfor\ttax\npositions\tof\tprior\tyears | 429,232 | 392,548 | 331,432 | 4,057 | 445 | 4,834 | 271,172 |
| Reductions\tfor\ttax\npositions\tof\tprior\tyears | (39,534) | (50,518) | (169,465) | (5,703) | (2,506) | (11,649) | (20,934) |
| Settlements | (390,931) | (275,776) | (139,202) | (966) | (2,470) | (112) | (279,790) |
| Gross\tbalance\tat\nDecember\t31,\t2012 | 344,669 | 465,721 | 536,673 | 16,841 | 52,018 | 13,954 | 260,346 |
| Offsets\tto\tgross |  |  |  |  |  |  |  |
| unrecognized\ttax |  |  |  |  |  |  |  |
| benefits: |  |  |  |  |  |  |  |
| Loss\tcarryovers | (342,127) | (160,955) | (536,673) | (16,841) | (35,511) | (1,593) | (249,424) |
| Unrecognized\ttax |  |  |  |  |  |  |  |
| benefits\tnet\tof\tunused\ttax |  |  |  |  |  |  |  |
| attributes\tand\tpayments | $2,542 | $304,766 | $— | $— | $16,507 | $12,361 | \t $10,922 |

| 2011 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\n1,\t2011 | $240,239 | $353,886 | $505,188 | $24,163 | $18,176 | $14,229 | $224,518 |
| Additions\tbased\ton\ttax |  |  |  |  |  |  |  |
| positions\trelated\tto\tthe |  |  |  |  |  |  |  |
| current\tyear | 11,216 | 9,398 | 8,748 | 457 | 50,212 | 1,760 | 44,419 |
| Additions\tfor\ttax\npositions\tof\tprior\tyears | 44,202 | 50,944 | 21,052 | 21,902 | 7,343 | 7,533 | 14,200 |
| Reductions\tfor\ttax\npositions\tof\tprior\tyears | (3,255) | (21,719) | (27,991) | (5,022) | (12,289) | (3,432) | (4,942) |
| Settlements | 43,091 | (2,016) | (60,810) | (30,448) | (7,390) | (865) | 2,988 |
| Gross\tbalance\tat\nDecember\t31,\t2011 | 335,493 | 390,493 | 446,187 | 11,052 | 56,052 | 19,225 | 281,183 |
| Offsets\tto\tgross |  |  |  |  |  |  |  |
| unrecognized\ttax |  |  |  |  |  |  |  |
| benefits: |  |  |  |  |  |  |  |
| Loss\tcarryovers | (146,429) | (26,394) | (216,720) | (5,930) | (1,211) | (10,645) | (10,752) |
| Cash\tpaid\tto\ttaxing\nauthorities | (75,977) | (45,493) | — | (7,556) | (1,174) | (1,376) | (41,878) |
| Unrecognized\ttax |  |  |  |  |  |  |  |
| benefits\tnet\tof\tused\ttax |  |  |  |  |  |  |  |
| attributes\tand\tpayments | $113,087 | $318,606 | $229,467 | ($2,434) | $53,667 | $7,204 | $228,553 |

The	Registrant	Subsidiaries'	balances	of	unrecognized	tax	benefits	included	amounts	which,	if	recognized,	would	have	reduced	income tax	expense	as	follows:

|  | December	31,<br>2013 | December	31,<br>2012 | December	31,<br>2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Entergy\tArkansas | $0.6 | $0.6 | $— |
| Entergy\tGulf\tStates\tLouisiana | $44.0 | $44.0 | $107.9 |
| Entergy\tLouisiana | $87.9 | $92.4 | $281.3 |
| Entergy\tMississippi | $3.9 | $3.9 | $3.8 |
| Entergy\tNew\tOrleans | $— | $— | $— |
| Entergy\tTexas | $10.1 | $8.6 | $7.3 |
| System\tEnergy | $3.3 | $3.5 | $— |

The	Registrant	Subsidiaries	accrue	interest	and	penalties	related	to	unrecognized	tax	benefits	in	income	tax	expense.		Penalties	have	not been	accrued.		Accrued	balances	for	the	possible	payment	of	interest	are	as	follows:

|  | December	31,<br>2013 | December	31,<br>2012 | December	31,<br>2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Entergy\tArkansas | $15.2 | $21.8 | $11.4 |
| Entergy\tGulf\tStates\tLouisiana | $17.0 | $33.1 | $14.4 |
| Entergy\tLouisiana | $1.0 | $0.9 | $0.8 |
| Entergy\tMississippi | $2.1 | $2.4 | $1.7 |
| Entergy\tNew\tOrleans | $0.9 | $0.1 | $2.4 |
| Entergy\tTexas | $0.8 | $0.7 | $0.1 |
| System\tEnergy | $19.0 | $33.2 | $18.5 |

# Income	Tax	Litigation

In	October	2010	the	U.S.	Tax	Court	entered	a	decision	in	favor	of	Entergy	regarding	the	ability	to	credit	the	U.K.	Windfall	Tax	against U.S.	income	tax	as	a	foreign	tax	credit	for	tax	years	1997	and	1998.		The	U.K.	Windfall	Tax	relates	to	Entergy's	former	investment	in	London Electricity.

The	IRS	filed	an	appeal	of	the	U.K.	Windfall	Tax	decision	with	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	in	December	2010.		Oral arguments	were	heard	in	November	2011.		In	June	2012	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	unanimously	affirmed	the	U.S.	Tax	Court decision.		As	a	result	of	this	decision,	Entergy	reversed	its	liability	for	uncertain	tax	positions	associated	with	this	issue.		On	September	4,	2012, the	U.S.	Solicitor	General,	on	behalf	of	the	Commissioner	of	Internal	Revenue,	petitioned	the	U.S.	Supreme	Court	for	a	writ	of	certiorari	to	review the	Fifth	Circuit	judgment.

Concurrent	with	the	Tax	Court's	issuance	of	a	favorable	decision	regarding	the	above	issues,	the	Tax	Court	issued	a	favorable	decision	in a	separate	proceeding,	PPL	Corp.	v.	Commissioner,	regarding	the	creditability	of	the	U.K.	Windfall	Tax.		The	IRS	appealed	the	PPL	decision	to the	United	States	Court	of	Appeals	for	the	Third	Circuit.		In	December	2011	the	Third	Circuit	reversed	the	Tax	Court's	holding	in	 PPL	Corp.	v. Commissioner,	stating	that	the	U.K.	tax	was	not	eligible	for	the	foreign	tax	credit.		PPL	Corp.	petitioned	the	U.S.	Supreme	Court	for	a	writ	of certiorari	to	review	the	U.S.	Court	of	Appeals	for	the	Third	Circuit	decision.		On	October	29,	2012,	the	U.S.	Supreme	Court	granted	PPL	Corp.'s petition	for	certiorari.		The	Solicitor	General's	petition	for	writ	of	certiorari	in	Entergy's	case	was	held	pending	the	disposition	of	the	PPL	case.

On	May	20,	2013,	the	Supreme	Court	issued	a	unanimous	decision	in	PPL's	favor,	holding	that	the	U.K.	Windfall	Tax	is	a	creditable	tax for	U.S.	federal	income	tax	purposes.	On	May	28,	2013,	the	Supreme	Court	denied	the	petition	for	certiorari	filed	by	the	Commissioner	of	Internal Revenue	in	Entergy's	U.K.	Windfall	Tax	case,	allowing	the	decision	in	Entergy's	favor	from	the	United	States	Court	of	Appeals	for	the	Fifth Circuit	to	become	final.

In	February	2008	the	IRS	issued	a	Statutory	Notice	of	Deficiency	for	the	year	2000.		The	deficiency	resulted	from	a	disallowance	of foreign	tax	credits	(the	same	issue	discussed	above)	as	well	as	the	disallowance	of	depreciation	deductions	on	non-utility	nuclear	plants.		Entergy filed	a	Tax	Court	petition	in	May	2008	challenging	the	IRS	treatment	of	these	issues.		In	June	2010	a	trial	on	the	depreciation	issue	was	held	in Washington,	D.C.		In	February	2011	a	joint	stipulation	of	settled	issues	was	filed	under	which	the	IRS	conceded	its	position	with	respect	to	the depreciation

issue.		The	outcome	of	the	foreign	tax	credit	matter	for	the	year	2000	is	effectively	settled	in	Entergy's	favor	as	determined	by	the	U.S.	Supreme Court's	unanimous	decision	in	the	PPL	proceeding	in	May	2013	as	discussed	above.

# Income	Tax	Audits

Entergy	and	 its	subsidiaries	file	U.S.	federal	and	various	state	and	foreign	 income	 tax	returns. 	IRS	examinations	are	substantially completed	for	years	before	2009.	All	state	taxing	authorities'	examinations	are	completed	for	years	before	2005.

In	June	2009,	Entergy	filed	a	formal	protest	with	the	IRS	Appeals	Division	indicating	disagreement	with	certain	issues	contained	in	the 2004-2005	Revenue	Agent's	Report	(RAR).		The	most	significant	issue	disputed	was	the	inclusion	of	nuclear	decommissioning	liabilities	in	cost of	goods	sold	for	the	nuclear	power	plants	owned	by	the	Utility	resulting	from	an	Application	for	Change	in	Accounting	Method	for	tax	purposes (the	"2004	CAM").

During	the	fourth	quarter	2012,	Entergy	settled	the	position	relating	to	the	2004	CAM.			Under	the	settlement	Entergy	conceded	its	tax position,	resulting	in	an	increase	in	taxable	income	of	approximately	$2.97	billion	for	the	tax	years	2004	-	2007.		The	settlement	provides	that Entergy	Louisiana	is	entitled	to	additional	tax	depreciation	of	approximately	$547	million	for	years	2006	and	beyond.		The	deferred	tax	asset	net of	interest	charges	associated	with	the	settlement	is	$155	million	for	Entergy.		There	was	a	related	increase	to	Entergy	Louisiana's	member's equity	account.

The	IRS	issued	its	2006-2007	RAR	in	October	2011.		In	connection	with	the	2006-2007	IRS	audit	and	resulting	RAR,	Entergy	resolved the	significant	issues	discussed	below.

In	August	2011,	Entergy	entered	into	a	settlement	agreement	with	the	IRS	relating	to	the	mark-to-market	income	tax	treatment	of	various wholesale	 electric	 power	 purchase	 and	 sale	 agreements,	 including	 Entergy	 Louisiana's	 contract	 to	 purchase	 electricity	 from	 the	 Vidalia hydroelectric	facility.		See	Note	8	to	the	financial	statements	for	further	details	regarding	this	contract	and	a	previous	LPSC-approved	settlement regarding	the	tax	treatment	of	the	contract.

With	respect	to	income	tax	accounting	for	wholesale	electric	power	purchase	agreements,	Entergy	recognized	income	for	tax	purposes	of approximately	$1.5	 billion,	 which	 represents	 a	 reversal	 of	 previously	 deducted	 temporary	 differences	 on	 which	 deferred	 taxes	 had	 been provided.		Also	in	connection	with	this	settlement,	Entergy	recognized	a	gain	for	income	tax	purposes	of	approximately	$1.03	billion	on	the formation	of	a	wholly-owned	subsidiary	in	2005	with	a	corresponding	step-up	in	the	tax	basis	of	depreciable	assets	resulting	in	additional	tax depreciation	at	Entergy	Louisiana.		Because	Entergy	Louisiana	is	entitled	to	deduct	additional	tax	depreciation	of	$1.03	billion	in	the	future, Entergy	Louisiana	recorded	a	deferred	tax	asset	for	this	additional	tax	basis.		The	tax	expense	associated	with	the	gain	is	offset	by	recording	the deferred	tax	asset	and	by	utilization	of	net	operating	losses.		With	the	recording	of	the	deferred	tax	asset,	there	was	a	corresponding	increase	to Entergy	Louisiana's	member's	equity	account.		The	agreement	with	the	IRS	effectively	settled	the	tax	treatment	of	various	wholesale	electric power	purchase	and	sale	agreements,	resulting	in	the	reversal	in	third	quarter	2011	of	approximately	$422	million	of	deferred	tax	liabilities	and liabilities	for	uncertain	tax	positions	at	Entergy	Louisiana,	with	a	corresponding	reduction	in	income	tax	expense.		Under	the	terms	of	an	LPSC- approved	final	settlement,	Entergy	Louisiana	recorded	a	$199	million	regulatory	charge	and	a	corresponding	regulatory	liability.

After	consideration	of	the	taxable	income	recognition	and	the	additional	depreciation	deductions	provided	for	in	the	settlement,	Entergy's net	operating	loss	carryover	was	reduced	by	approximately	$2.5	billion.

In	the	third	quarter	2008,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	received	$679	million	and	$274.7	million,	respectively, from	the	Louisiana	Utilities	Restoration	Corporation	("LURC").		These	receipts	from	LURC	were	from	the	proceeds	of	a	Louisiana	Act	55 financing	of	the	costs	incurred	to	restore	service	following	Hurricane	Katrina	and	Hurricane	Rita.		See	Note	2	to	the	financial	statements	for further	details	regarding	the	financings.

In	June	2012,	Entergy	effectively	settled	the	tax	treatment	of	the	storm	restoration,	which	resulted	in	an	increase	to	2008	taxable	income	of $129	million	for	Entergy	Louisiana	and	$104	million	for	Entergy	Gulf	States	Louisiana	and	a	reduction	of	income	tax	expense	of	$172	million, including	$143	 million	 for	 Entergy	 Louisiana	 and	$20	 million	 for	 Entergy	 Gulf	 States	 Louisiana.	Under	 the	 terms	 of	 an	 LPSC-approved settlement	related	to	the	Louisiana	Act	55	financings,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	recorded,	respectively,	a	$137	million ($84	million	net-of-tax)	and	a	$28	million	($17	million	net-of-tax)	regulatory	charge	and	a	corresponding	regulatory	liability	to	reflect	their obligations	to	customers	with	respect	to	the	settlement.

In	the	fourth	quarter	2009,	Entergy	filed	Applications	for	Change	in	Accounting	Method	(the	"2009	CAM")	for	tax	purposes	with	the	IRS for	certain	costs	under	Section	263A	of	the	Internal	Revenue	Code.		In	the	Applications,	Entergy	proposed	to	treat	the	nuclear	decommissioning liability	associated	with	the	operation	of	its	nuclear	power	plants	as	a	production	cost	properly	includable	in	cost	of	goods	sold.		The	effect	of	the 2009	CAM		was	a	$5.7	billion	reduction	in	2009	taxable	income.		The	2009	CAM	was	adjusted	to	 $9.3	billion	in	2012.

In	the	fourth	quarter	2012	the	IRS	disallowed	the	reduction	to	2009	taxable	income	related	to	the	2009	CAM.		In	the	third	quarter	2013, the	Internal	Revenue	Service	issued	its	RAR	for	the	tax	years	2008-2009.	As	a	result	of	the	issuance	of	this	RAR,	Entergy	and	the	IRS	resolved	all of	the	2008-2009	issues	described	above	except	for	the	2009	CAM.	Entergy	disagrees	with	the	IRS's	disallowance	of	the	2009	CAM	and	filed	a protest	with	the	IRS	Appeals	Division	on	October	24,	2013.	The	issuance	of	the	RAR	by	the	IRS	effectively	settles	all	other	issues,	which	resulted in	an	adjustment	to	the	provision	for	uncertain	tax	positions.

# Other	Tax	Matters

Entergy	regularly	negotiates	with	the	IRS	to	achieve	settlements.		The	results	of	all	pending	litigations	and	audit	issues	could	result	in significant	changes	to	the	amounts	of	unrecognized	tax	benefits,	as	discussed	above.

In	March	2010,	Entergy	filed	an	Application	for	Change	in	Accounting	Method	with	the	IRS.		In	the	application,	Entergy	proposed	to change	the	definition	of	unit	of	property	for	its	generation	assets	to	determine	the	appropriate	characterization	of	costs	associated	with	such	units as	capital	or	repair	under	the	Internal	Revenue	Code	and	related	Treasury	Regulations.		The	effect	of	this	change	was	an	approximate	$1.3	billion reduction	in	2011	taxable	income	for	Entergy,	including	reductions	of	$292	million	for	Entergy	Arkansas,	$132	million	for	Entergy	Gulf	States Louisiana,	$185	million	for	Entergy	Louisiana,	$48	million	for	Entergy	Mississippi,	$45	million	for	Entergy	Texas,	$13	million	for	Entergy	New Orleans,	and	$180	million	for	System	Energy.

In	 September	 2013	 the	 IRS	 issued	 final	 regulations	 that	 provide	 guidance	 on	 the	 deductibility	 and	 capitalization	 of	 costs	 incurred associated	with	tangible	property.	Although	Entergy	continues	to	analyze	these	regulations,	which	contain	numerous	complex	provisions,	Entergy currently	estimates	that	the	effect	of	the	regulations	would	result	in	a	$348	million	reduction	of	Entergy's	2014	repairs	and	maintenance	tax deduction,	including	decreases	in	the	deduction	of	$114	million	for	Entergy	Arkansas,	$34	million	for	Entergy	Gulf	States	Louisiana,	$22	million for	 Entergy	 Louisiana,	$43	million	for	Entergy	Mississippi,	$137	million	for	Entergy	Texas,	and	an	increase	of	$2	million	for	Entergy	New Orleans.

During	the	second	quarter	2011,	Entergy	filed	an	Application	for	Change	in	Accounting	Method	with	the	IRS	related	to	the	allocation	of overhead	costs	between	production	and	non-production	activities.		The	accounting	method	affects	the	amount	of	overhead	that	will	be	capitalized or	deducted	for	tax	purposes.		The	accounting	method	is	expected	to	be	implemented	for	the	2014	tax	year.

In	March	2013,	Entergy	Louisiana	distributed	to	its	parent,	Entergy	Louisiana	Holdings,	Inc.,	Louisiana	income	tax	credits	of	 $20.6 million	which	resulted	in	a	decrease	in	Entergy	Louisiana's	member's	equity	account.

# NOTE	4.		REVOLVING	CREDIT	FACILITIES,	LINES	OF	CREDIT,	AND	SHORT-TERM	BORROWINGS	(Entergy	Corporation,

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

Entergy	Corporation	has	in	place	a	credit	facility	that	has	a	borrowing	capacity	of	$3.5	billion	and	expires	in	March	2018.		Entergy Corporation	also	has	the	ability	to	issue	letters	of	credit	against	50%	of	the	total	borrowing	capacity	of	the	credit	facility.		The	commitment	fee	is currently	0.275%	of	the	commitment	amount.		Commitment	fees	and	interest	rates	on	loans	under	the	credit	facility	can	fluctuate	depending	on	the senior	unsecured	debt	ratings	of	Entergy	Corporation.		The	weighted	average	interest	rate	for	the	year	ended	December	31,	2013	was	1.96%	on the	 drawn	 portion	 of	 the	 facility.	 	 Following	 is	 a	 summary	 of	 the	 borrowings	 outstanding	 and	 capacity	 available	 under	 the	 facility	 as	 of December	31,	2013.

| Capacity	(a) | Borrowings | Letters<br>of	Credit | Capacity<br>Available |
| :--- | :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |  |
| $3,500 | $255 | $8 | $3,237 |

Entergy	Corporation's	facility	requires	it	to	maintain	a	consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.		Entergy	is	in compliance	with	this	covenant.		If	Entergy	fails	to	meet	this	ratio,	or	if	Entergy	Corporation	or	one	of	the	Utility	operating	companies	(except Entergy	New	Orleans)	defaults	on	other	indebtedness	or	is	in	bankruptcy	or	insolvency	proceedings,	an	acceleration	of	the	facility	maturity	date may	occur.

Entergy	Corporation	has	a	commercial	paper	program	with	a	program	limit	of	up	to 	$1.5	billion.	 	 At	December	31,	2013,	 Entergy Corporation	had	$1,045	million	of	commercial	paper	outstanding.		The	weighted-average	interest	rate	for	the	year	ended	December	31,	2013	was 0.84%.

|  |  |  |  | Amount	Drawn<br>as	of |
| :--- | :--- | :--- | :--- | :--- |
| Company | Expiration\tDate | Amount\tof\tFacility | Interest\tRate\t(a) | December\t31,\t2013 |
| Entergy\tArkansas | April\t2014 | $20\tmillion\t(b) | 1.75% | — |
| Entergy\tArkansas | March\t2018 | $150\tmillion\t(c) | 1.67% | — |
| Entergy\tGulf\tStates\tLouisiana | March\t2018 | $150\tmillion\t(d) | 1.67% | — |
| Entergy\tLouisiana | March\t2018 | $200\tmillion\t(e) | 1.67% | — |
| Entergy\tMississippi | May\t2014 | $35\tmillion\t(f) | 1.92% | — |
| Entergy\tMississippi | May\t2014 | $20\tmillion\t(f) | 1.92% | — |
| Entergy\tMississippi | May\t2014 | $37.5\tmillion\t(f) | 1.92% | — |
| Entergy\tNew\tOrleans | November\t2014 | $25\tmillion\t(g) | 1.64% | — |
| Entergy\tTexas | March\t2018 | $150\tmillion\t(h) | 1.92% | — |

(b) The	credit	facility	requires	Entergy	Arkansas	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.		Entergy	Arkansas	is	in compliance	 with	 this	 covenant.	Borrowings	under	 this	Entergy	Arkansas	credit	facility	may	be	secured	by	a	security	 interest	 in	 its accounts	receivable.

(c) The	 credit	 facility	 allows	 Entergy	Arkansas	 to	 issue	 letters	 of	 credit	 against	50%	of	 the	borrowing	capacity	of	 the	facility.	 	As	of December	31,	2013,	$0.2	million	in	letters	of	credit	were	outstanding.	 	The	credit	facility	requires	Entergy	Arkansas	to	maintain	a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	Arkansas	is	in	compliance	with	this	covenant.

(d) The	credit	facility	allows	Entergy	Gulf	States	Louisiana	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the	facility.		As of	December	31,	2013,	$15.2	million	in	letters	of	credit	were	outstanding.		The	credit	facility	requires	Entergy	Gulf	States	Louisiana	to maintain	a	consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	Gulf	States	Louisiana	is	in	compliance	with	this covenant.

(e) The	credit	facility	allows	Entergy	Louisiana	 to	 issue	 letters	of	credit	against	50%	of	 the	borrowing	capacity	of	 the	facility.	 	As	of December	31,	2013,	$7.0	million	in	letters	of	credit	were	outstanding.	 	The	credit	facility	requires	Entergy	Louisiana	to	maintain	a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	Louisiana	is	in	compliance	with	this	covenant.

(f) The	credit	facilities	require	Entergy	Mississippi	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	Mississippi	is	in compliance	with	this	covenant.	Borrowings	under	the	Entergy	Mississippi	credit	facilities	may	be	secured	by	a	security	interest	in	its accounts	receivable.

(g) The	credit	facility	requires	Entergy	New	Orleans	to	maintain	a	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	New	Orleans	is in	compliance	with	this	covenant.

(h) The	 credit	 facility	 allows	 Entergy	 Texas	 to	 issue	 letters	 of	 credit	 against	 50%	 of	 the	 borrowing	 capacity	 of	 the	 facility.	 	 As	 of December	 31,	 2013,	 $25	 million	 in	 letters	 of	 credit	 were	 outstanding.	 	 The	 credit	 facility	 requires	 Entergy	 Texas	 to	 maintain	 a consolidated	debt	ratio	of	65%	or	less	of	its	total	capitalization.	Entergy	Texas	is	in	compliance	with	this	covenant.

The	facility	fees	on	the	credit	facilities	range	from	0.125%	to	0.275%	of	the	commitment	amount.

In	addition,	Entergy	Mississippi	and	Entergy	New	Orleans	each	entered	into	an	uncommitted	letter	of	credit	facility	as	a	means	to	post collateral	to	support	its	obligations	related	to	MISO.		As	of	December	31,	2013,	a	$21	million	letter	of	credit	was	outstanding	under	Entergy Mississippi's	letter	of	credit	facility	and	an	$8.5	million	letter	of	credit	was	outstanding	under	Entergy	New	Orleans's	letter	of	credit	facility.	As of	December	31,	2013,	the	letter	of	credit

fee	on	outstanding	letters	of	credit	under	the	Entergy	Mississippi	and	Entergy	New	Orleans	letter	of	credit	facilities	was	1.50%.

The	short-term	borrowings	of	the	Registrant	Subsidiaries	are	limited	to	amounts	authorized	by	the	FERC.	The	current	FERC-authorized limits	are	effective	through	October	31,	2015.	In	addition	to	borrowings	from	commercial	banks,	these	companies	are	authorized	under	a	FERC order	to	borrow	from	the	Entergy	System	money	pool.	The	money	pool	is	an	inter-company	borrowing	arrangement	designed	to	reduce	the	Utility subsidiaries'	dependence	on	external	short-term	borrowings.	Borrowings	from	the	money	pool	and	external	borrowings	combined	may	not	exceed the	FERC-authorized	limits.	The	following	are	the	FERC-authorized	limits	for	short-term	borrowings	and	the	outstanding	short-term	borrowings as	of	December	31,	2013	(aggregating	both	money	pool	and	external	short-term	borrowings)	for	the	Registrant	Subsidiaries:

|  | Authorized | Borrowings |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $250 | — |
| Entergy\tGulf\tStates\tLouisiana | $200 | — |
| Entergy\tLouisiana | $250 | — |
| Entergy\tMississippi | $175 | $4 |
| Entergy\tNew\tOrleans | $100 | — |
| Entergy\tTexas | $200 | — |
| System\tEnergy | $200 | — |

# Variable	Interest	Entities	 (Entergy	 Corporation,	 Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy	 Louisiana,	 and	 System Energy)

See	Note	18	 to	 the	financial	statements	for	a	discussion	of	 the	consolidation	of	 the	nuclear	fuel	company	variable	 interest	entities (VIE).		The	nuclear	fuel	company	variable	interest	entities	have	credit	facilities	and	also	issue	commercial	paper	to	finance	the	acquisition	and ownership	of	nuclear	fuel	as	follows	as	of	December	31,	2013:

| Company | Expiration<br>Date | Amount<br>of<br>Facility | Average<br>Interest<br>Rate	on<br>Borrowings<br>(a) | Amount<br>Outstanding<br>as	of<br>December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (Dollars\tin\tMillions) | (Dollars\tin\tMillions) |  |
| Entergy\tArkansas\tVIE | June\t2016 | $85 | n/a | — |
| Entergy\tGulf\tStates\tLouisiana\tVIE | June\t2016 | $100 | 1.375% | $14.8 |
| Entergy\tLouisiana\tVIE | June\t2016 | $90 | 1.56% | $2.9 |
| System\tEnergy\tVIE | June\t2016 | $125 | n/a | — |

(a) Includes	letter	of	credit	fees	and	bank	fronting	fees	on	commercial	paper	issuances	by	the	nuclear	fuel	company	variable	interest	entities for	Entergy	Arkansas,	Entergy	Louisiana,	and	System	Energy.		The	nuclear	fuel	company	variable	interest	entity	for	Entergy	Gulf	States Louisiana	does	not	issue	commercial	paper,	but	borrows	directly	on	its	bank	credit	facility.

Amounts	outstanding	on	the	Entergy	Gulf	States	Louisiana	nuclear	fuel	company	variable	interest	entity's	credit	facility,	if	any,	are included	in	long-term	debt	on	its	balance	sheet	and	commercial	paper	outstanding	for	the	other	nuclear	fuel	company	variable	interest	entities	is classified	as	a	current	 liability	on	 the	respective	balance	sheets.	 	The	commitment	fees	on	 the	credit	facilities	are	0.125%	 of	 the	 undrawn commitment	amount.		Each	credit	facility	requires	the	respective	lessee	of	nuclear	fuel	(Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy

Louisiana,	or	Entergy	Corporation	as	guarantor	for	System	Energy)	to	maintain	a	consolidated	debt	ratio	of	70%	or	less	of	its	total	capitalization. The	respective	lessees	are	each	in	compliance	with	this	covenant.

The	nuclear	fuel	company	variable	interest	entities	had	notes	payable	that	are	included	in	debt	on	the	respective	balance	sheets	as	of December	31,	2013	as	follows:

| Company | Description | Amount |
| :--- | :--- | :--- |
| Entergy\tArkansas\tVIE | \t 5.69%\tSeries\tI\tdue\tJuly\t2014 | $70\tmillion |
| Entergy\tArkansas\tVIE | \t 3.23%\tSeries\tJ\tdue\tJuly\t2016 | $55\tmillion |
| Entergy\tArkansas\tVIE | \t 2.62%\tSeries\tK\tdue\tDecember\t2017 | $60\tmillion |
| Entergy\tGulf\tStates\tLouisiana\tVIE | \t 3.25%\tSeries\tQ\tdue\tJuly\t2017 | $75\tmillion |
| Entergy\tGulf\tStates\tLouisiana\tVIE | \t 3.38%\tSeries\tR\tdue\tAugust\t2020 | $70\tmillion |
| Entergy\tLouisiana\tVIE | \t 5.69%\tSeries\tE\tdue\tJuly\t2014 | $50\tmillion |
| Entergy\tLouisiana\tVIE | \t 3.30%\tSeries\tF\tdue\tMarch\t2016 | $20\tmillion |
| Entergy\tLouisiana\tVIE | \t 3.25%\tSeries\tG\tdue\tJuly\t2017 | $25\tmillion |
| System\tEnergy\tVIE | \t 5.33%\tSeries\tG\tdue\tApril\t2015 | $60\tmillion |
| System\tEnergy\tVIE | \t 4.02%\tSeries\tH\tdue\tFebruary\t2017 | $50\tmillion |
| System\tEnergy\tVIE | \t 3.78%\tSeries\tI\tdue\tOctober\t2018 | $85\tmillion |

In	accordance	with	regulatory	treatment,	interest	on	the	nuclear	fuel	company	variable	interest	entities'	credit	facilities,	commercial	paper, and	long-term	notes	payable	is	reported	in	fuel	expense.

In	February	2014	the	Entergy	Louisiana	nuclear	fuel	company	variable	interest	entity	issued	$40	million	 of	3.92%	Series	H	Notes	due February	2021.	The	Entergy	Louisiana	nuclear	fuel	company	variable	interest	entity	used	the	proceeds	to	purchase	additional	nuclear	fuel.

Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy	 Louisiana,	 and	 System	 Energy	 each	 have	 obtained	 long-term financing authorizations	from	the	FERC	that	extend	through	October	2015	for	issuances	by	its	nuclear	fuel	company	variable	interest	entity.

# NOTE	5.		LONG	-	TERM	DEBT	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Long-term	debt	for	Entergy	Corporation	and	subsidiaries	as	of	December	31,	2013	and	2012	consisted	of:

|  | Weighted |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Average\tInterest | Interest\tRate\tRanges\tat | Interest\tRate\tRanges\tat | Outstanding\tat |  |
|  | Rate\tDecember\t31, | December\t31, | December\t31, | December\t31, |  |
| \t\tType\tof\tDebt\tand\tMaturity | 2013 | 2013 | 2012 | 2013 | 2012 |
|  |  |  |  | (In\tThousands) |  |
| Mortgage\tBonds |  |  |  |  |  |
| 2013-2018 | 5.43% | 1.88%-6.50% | 1.88%-6.50% | $1,460,000 | $1,930,000 |
| 2019-2023 | 4.24% | 3.05%-7.13% | 3.10%-7.13% | 2,925,000 | 2,250,000 |
| 2024-2028 | 5.27% | 4.44%-5.66% | 4.44%-5.66% | 1,158,363 | 1,158,369 |
| 2029-2038 | 6.18% | 5.65%-6.40% | 5.65%-6.40% | 867,914 | 867,976 |
| 2039-2063 | 5.55% | 4.70%-7.88% | 4.90%-7.88% | 1,560,000 | 1,335,000 |
| Governmental\tBonds\t(a) |  |  |  |  |  |
| 2013-2018 | 1.84% | 1.55%-2.88% | 2.88%-4.60% | 86,655 | 86,655 |
| 2019-2023 | 5.30% | 2.38%-5.88% | 4.60%-5.88% | 291,000 | 307,030 |
| 2024-2031 | 5.00% | 5.00% | 5.00% | 198,680 | 198,680 |
| Securitization\tBonds |  |  |  |  |  |
| 2014-2021 | 2.92% | 2.04%-5.79% | 2.12%-5.79% | 550,243 | 459,152 |
| 2022-2024 | 4.86% | 4.38%-5.93% | 2.04%-5.93% | 333,000 | 514,584 |
| Variable\tInterest\tEntities\tNotes\nPayable\t(Note\t4) |  |  |  |  |  |
| 2013-2020 | 3.50% | 1.38%-5.69% | 2.62%-9.00% | 634,800 | 640,000 |
| Entergy\tCorporation\tNotes |  |  |  |  |  |
| due\tSeptember\t2015 | n/a | 3.625% | 3.625% | 550,000 | 550,000 |
| due\tJanuary\t2017 | n/a | 4.70% | 4.70% | 500,000 | 500,000 |
| due\tSeptember\t2020 | n/a | 5.125% | 5.125% | 450,000 | 450,000 |
| Note\tPayable\tto\tNYPA | (b) | (b) | (b) | 95,011 | 109,679 |
| 5\tYear\tCredit\tFacility\t(Note\t4) | n/a | 1.96% | 2.04% | 255,000 | 795,000 |
| Long-term\tDOE\tObligation\t(c) | — | — | — | 181,253 | 181,157 |
| Waterford\t3\tLease\tObligation\t(d) | n/a | 7.45% | 7.45% | 148,716 | 162,949 |
| Grand\tGulf\tLease\tObligation\t(d) | n/a | 5.13% | 5.13% | 97,414 | 138,893 |
| Term\tLoan\t-\tEntergy\tArkansas | n/a | 1.13% | — | 250,000 | — |
| Unamortized\tPremium\tand\tDiscount\t-\nNet |  |  |  | (11,172) | (10,744) |
| Other |  |  |  | 14,367 | 14,454 |
| Total\tLong-Term\tDebt |  |  |  | 12,596,244 | 12,638,834 |
| Less\tAmount\tDue\tWithin\tOne\tYear |  |  |  | 457,095 | 718,516 |
| Long-Term\tDebt\tExcluding\tAmount |  |  |  |  |  |
| Due\tWithin\tOne\tYear |  |  |  | $12,139,149 | $11,920,318 |
| Fair\tValue\tof\tLong-Term\tDebt\t(e) |  |  |  | $12,439,785 | $12,849,330 |

(a) Consists	of	pollution	control	revenue	bonds	and	environmental	revenue	bonds,	some	of	which	are	secured	by	collateral	first	mortgage bonds.

(b) These	notes	do	not	have	a	stated	interest	rate,	but	have	an	implicit	interest	rate	of	4.8%.

(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) See	Note	10	to	the	financial	statements	for	further	discussion	of	the	Waterford	3	and	Grand	Gulf	lease	obligations.

(e) The	 fair	 value	 excludes	 lease	 obligations	 of	$149	million	 at	 Entergy	 Louisiana	 and	$97	million	 at	 System	 Energy,	 long-term	 DOE obligations	of	$181	million	at	Entergy	Arkansas,	and	the	note	payable	to	NYPA	of	 $95	million	at	Entergy,	and	includes	debt	due	within one	year.		Fair	values	are	classified	as	Level	2	in	the	fair	value	hierarchy	discussed	in	Note	16	to	the	financial	statements	and	are	based	on prices	derived	from	inputs	such	as	benchmark	yields	and	reported	trades.

The	 annual	 long-term	 debt	 maturities	 (excluding lease obligations and long-term	 DOE obligations) for debt outstanding as of December	31,	2013,	for	the	next	five	years	are	as	follows:

# Amount

(In	Thousands)

In	November	2000,	Entergy's	non-utility	nuclear	business	purchased	the	FitzPatrick	and	Indian	Point	 3	power	plants	in	a	seller-financed transaction.		Entergy	issued	notes	to	NYPA	with	seven	annual	installments	of	approximately	$108	million	commencing	one	year	from	the	date	of the	closing,	and	eight	annual	installments	of	$20	million	commencing	eight	years	from	the	date	of	the	closing.		These	notes	do	not	have	a	stated interest	rate,	but	have	an	implicit	interest	rate	of	4.8%.		In	accordance	with	the	purchase	agreement	with	NYPA,	the	purchase	of	Indian	Point	 2	in 2001	resulted	in	Entergy	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.	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	Utility	operating	companies	or System	Energy	were	to	default	on	other	indebtedness,	Entergy	could	be	required	to	post	collateral	to	support	the	letter	of	credit.

Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	Texas,	and	System	Energy	have	obtained	long-term financing	authorizations	from	the	FERC	that	extend	through	October	2015.		Entergy	Arkansas	has	obtained	long-term	financing	authorization from	the	APSC	that	extends	through	December	2015.		Entergy	New	Orleans	has	obtained	long-term	financing	authorization	from	the	City	Council that	extends	through	July	2014.

•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;

Long-term	debt	for	the	Registrant	Subsidiaries	as	of	December	31,	2013	and	2012	consisted	of:

| 5.40%	Series	due	August	2013 | $— | $300,000 |
| :--- | :--- | :--- |
| 5.0%\tSeries\tdue\tJuly\t2018 | 115,000 | 115,000 |
| 3.75%\tSeries\tdue\tFebruary\t2021 | 350,000 | 350,000 |
| 3.05%\tSeries\tdue\tJune\t2023 | 250,000 | — |
| 5.66%\tSeries\tdue\tFebruary\t2025 | 175,000 | 175,000 |
| 5.9%\tSeries\tdue\tJune\t2033 | 100,000 | 100,000 |
| 6.38%\tSeries\tdue\tNovember\t2034 | 60,000 | 60,000 |
| 5.75%\tSeries\tdue\tNovember\t2040 | 225,000 | 225,000 |
| 4.9%\tSeries\tdue\tDecember\t2052 | 200,000 | 200,000 |
| 4.75%\tSeries\tdue\tJune\t2063 | 125,000 | — |
| Total\tmortgage\tbonds | 1,600,000 | 1,525,000 |
| Governmental\tBonds\t(a): |  |  |
| 4.6%\tSeries\tdue\t2017,\tJefferson\tCounty\t(d) | — | 54,700 |
| 1.55%\tSeries\tdue\t2017,\tJefferson\tCounty\t(d) | 54,700 | — |
| 5.0%\tSeries\tdue\t2021,\tIndependence\tCounty\t(d) | — | 45,000 |
| 2.38%\tSeries\tdue\t2021,\tIndependence\tCounty\t(d) | 45,000 | — |
| Total\tgovernmental\tbonds | 99,700 | 99,700 |
| Variable\tInterest\tEntity\tNotes\tPayable\t(Note\t4): |  |  |
| 9%\tSeries\tH\tdue\tJune\t2013 | — | 30,000 |
| 5.69%\tSeries\tI\tdue\tJuly\t2014 | 70,000 | 70,000 |
| 3.23%\tSeries\tJ\tdue\tJuly\t2016 | 55,000 | 55,000 |
| 2.62%\tSeries\tK\tdue\tDecember\t2017 | 60,000 | 60,000 |
| Total\tvariable\tinterest\tentity\tnotes\tpayable | 185,000 | 215,000 |
| Securitization\tBonds: |  |  |
| 2.30%\tSeries\tSenior\tSecured\tdue\tAugust\t2021 | 88,986 | 101,575 |
| Total\tsecuritization\tbonds | 88,986 | 101,575 |
| Other: |  |  |
| Long-term\tDOE\tObligation\t(b) | 181,253 | 181,157 |
| Term\tLoan\tdue\tJanuary\t2015,\tweighted\tavg\trate\t1.13% | 250,000 | — |
| Unamortized\tPremium\tand\tDiscount\t–\tNet | (1,242) | (655) |
| Other | 2,105 | 2,118 |
| Total\tLong-Term\tDebt | 2,405,802 | 2,123,895 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 70,000 | 330,000 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $2,335,802 | $1,793,895 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $2,142,527 | $1,876,335 |

| 6.0%	Series	due	May	2018 | $375,000 | $375,000 |
| :--- | :--- | :--- |
| 3.95%\tSeries\tdue\tOctober\t2020 | 250,000 | 250,000 |
| 5.59%\tSeries\tdue\tOctober\t2024 | 300,000 | 300,000 |
| 6.2%\tSeries\tdue\tJuly\t2033 | 240,000 | 240,000 |
| 6.18%\tSeries\tdue\tMarch\t2035 | 85,000 | 85,000 |
| Total\tmortgage\tbonds | 1,250,000 | 1,250,000 |
| Governmental\tBonds\t(a): |  |  |
| 2.875%\tSeries\tdue\t2015,\tLouisiana\tPublic\tFacilities\tAuthority\t(d) | 31,955 | 31,955 |
| 5.0%\tSeries\tdue\t2028,\tLouisiana\tPublic\tFacilities\tAuthority\t(d) | 83,680 | 83,680 |
| Total\tgovernmental\tbonds | 115,635 | 115,635 |
| Variable\tInterest\tEntity\tNotes\tPayable\t(Note\t4): |  |  |
| 5.56%\tSeries\tN\tdue\tMay\t2013 | — | 75,000 |
| 3.25%\tSeries\tQ\tdue\tJuly\t2017 | 75,000 | 75,000 |
| 3.38%\tSeries\tR\tdue\tAugust\t2020 | 70,000 | — |
| Credit\tFacility\tdue\tJune\t2016,\tweighted\tavg\trate\t1.38% | 14,800 | — |
| Total\tvariable\tinterest\tentity\tnotes\tpayable | 159,800 | 150,000 |
| Other: |  |  |
| Unamortized\tPremium\tand\tDiscount\t–\tNet | (1,574) | (1,810) |
| Other | 3,604 | 3,604 |
| Total\tLong-Term\tDebt | 1,527,465 | 1,517,429 |
| Less\tAmount\tDue\tWithin\tOne\tYear | — | 75,000 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $1,527,465 | $1,442,429 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $1,631,308 | $1,668,819 |

| 1.875%	Series	due	December	2014 | $250,000 | $250,000 |
| :--- | :--- | :--- |
| 6.50%\tSeries\tdue\tSeptember\t2018 | 300,000 | 300,000 |
| 4.8%\tSeries\tdue\tMay\t2021 | 200,000 | 200,000 |
| 3.3%\tSeries\tdue\tDecember\t2022 | 200,000 | 200,000 |
| 4.05%\tSeries\tdue\tSeptember\t2023 | 325,000 | — |
| 5.40%\tSeries\tdue\tNovember\t2024 | 400,000 | 400,000 |
| 4.44%\tSeries\tdue\tJanuary\t2026 | 250,000 | 250,000 |
| 6.4%\tSeries\tdue\tOctober\t2034 | 70,000 | 70,000 |
| 6.3%\tSeries\tdue\tSeptember\t2035 | 100,000 | 100,000 |
| 6.0%\tSeries\tdue\tMarch\t2040 | 150,000 | 150,000 |
| 5.875%\tSeries\tdue\tJune\t2041 | 150,000 | 150,000 |
| 5.25%\tSeries\tdue\tJuly\t2052 | 200,000 | 200,000 |
| 4.7%\tSeries\tdue\tJune\t2063 | 100,000 | — |
| Total\tmortgage\tbonds | 2,695,000 | 2,270,000 |
| Governmental\tBonds\t(a): |  |  |
| 5.0%\tSeries\tdue\t2030,\tLouisiana\tPublic\tFacilities\tAuthority\t(d) | 115,000 | 115,000 |
| Total\tgovernmental\tbonds | 115,000 | 115,000 |
| Variable\tInterest\tEntity\tNotes\tPayable\t(Note\t4): |  |  |
| 5.69%\tSeries\tE\tdue\tJuly\t2014 | 50,000 | 50,000 |
| 3.30%\tSeries\tF\tdue\tMarch\t2016 | 20,000 | 20,000 |
| 3.25%\tSeries\tG\tdue\tJuly\t2017 | 25,000 | 25,000 |
| Total\tvariable\tinterest\tentity\tnotes\tpayable | 95,000 | 95,000 |
| Securitization\tBonds: |  |  |
| 2.04%\tSeries\tSenior\tSecured\tdue\tJune\t2021 | 164,993 | 181,584 |
| Total\tsecuritization\tbonds | 164,993 | 181,584 |
| Other: |  |  |
| Waterford\t3\tLease\tObligation\t7.45%\t(Note\t10) | 148,716 | 162,949 |
| Unamortized\tPremium\tand\tDiscount\t-\tNet | (2,962) | (2,230) |
| Other | 3,769 | 3,792 |
| Total\tLong-Term\tDebt | 3,219,516 | 2,826,095 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 320,231 | 14,236 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $2,899,285 | $2,811,859 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $3,148,877 | $2,921,322 |

| 3.60%	Series	due	June	2015 | $200,000 | $200,000 |
| :--- | :--- | :--- |
| 7.125%\tSeries\tdue\tFebruary\t2019 | 500,000 | 500,000 |
| 4.1%\tSeries\tdue\tSeptember\t2021 | 75,000 | 75,000 |
| 7.875%\tSeries\tdue\tJune\t2039 | 150,000 | 150,000 |
| Total\tmortgage\tbonds | 925,000 | 925,000 |
| Securitization\tBonds: |  |  |
| 2.12%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tFebruary\t2016 | 54,047 | 93,436 |
| 5.79%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tOctober\t2018 | 97,414 | 119,341 |
| 3.65%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tAugust\t2019 | 144,800 | 144,800 |
| 5.93%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tJune\t2022 | 114,400 | 114,400 |
| 4.38%\tSeries\tSenior\tSecured\tdue\tNovember\t2023 | 218,600 | 218,600 |
| Total\tsecuritization\tbonds | 629,261 | 690,577 |
| Other: |  |  |
| Unamortized\tPremium\tand\tDiscount\t-\tNet | (2,211) | (2,653) |
| Other | 4,889 | 4,889 |
| Total\tLong-Term\tDebt | 1,556,939 | 1,617,813 |
| Less\tAmount\tDue\tWithin\tOne\tYear | — | — |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $1,556,939 | $1,617,813 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $1,726,623 | $1,885,672 |

| 4.1%	Series	due	April	2023 | $250,000 | $250,000 |
| :--- | :--- | :--- |
| Total\tmortgage\tbonds | 250,000 | 250,000 |
| Governmental\tBonds\t(a): |  |  |
| 5.875%\tSeries\tdue\t2022,\tMississippi\tBusiness\tFinance\tCorp. | 216,000 | 216,000 |
| Total\tgovernmental\tbonds | 216,000 | 216,000 |
| Variable\tInterest\tEntity\tNotes\tPayable\t(Note\t4): |  |  |
| 6.29%\tSeries\tF\tdue\tSeptember\t2013 | — | 70,000 |
| 5.33%\tSeries\tG\tdue\tApril\t2015 | 60,000 | 60,000 |
| 4.02%\tSeries\tH\tdue\tFebruary\t2017 | 50,000 | 50,000 |
| 3.78%\tSeries\tI\tdue\tOctober\t2018 | 85,000 | — |
| Total\tvariable\tinterest\tentity\tnotes\tpayable | 195,000 | 180,000 |
| Other: |  |  |
| Grand\tGulf\tLease\tObligation\t5.13%\t(Note\t10) | 97,414 | 138,893 |
| Unamortized\tPremium\tand\tDiscount\t–\tNet | (981) | (1,096) |
| Other | 3 | 2 |
| Total\tLong-Term\tDebt | 757,436 | 783,799 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 48,653 | 111,854 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $708,783 | $671,945 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $664,890 | $664,670 |

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

(b) 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.

(c) The	fair	value	excludes	lease	obligations	of	$149	million	at	Entergy	Louisiana	and	$97	million	at	System	Energy	and	long-term	DOE obligations	of	$181	million	at	Entergy	Arkansas,	and	includes	debt	due	within	one	year.		Fair	values	are	classified	as	Level	2	in	the	fair value	hierarchy	discussed	in	Note	16	to	the	financial	statements	and	are	based	on	prices	derived	from	inputs	such	as	benchmark	yields	and reported	trades.

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

|  | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2014 | $70,000 | — | $300,000 | — | — | — | — |
| 2015 | $250,000 | $31,955 | — | — | — | $200,000 | $60,000 |
| 2016 | $55,000 | $14,800 | $20,000 | $125,000 | — | $54,047 | — |
| 2017 | $114,700 | $75,000 | $25,000 | — | — | — | $50,000 |
| 2018 | $115,000 | $375,000 | $300,000 | $95,000 | — | $97,414 | $85,000 |

# Entergy	Arkansas	Securitization	Bonds

In	June	2010,	the	APSC	issued	a	financing	order	authorizing	the	issuance	of	bonds	to	recover	Entergy	Arkansas's	January	2009	ice	storm damage	 restoration	 costs,	 including	 carrying	 costs	 of	$11.5	million	 and	$4.6	million	of	up-front	financing	costs.	 	In	August	2010,	Entergy Arkansas	Restoration	Funding,	LLC,	a	company	wholly-owned	and	consolidated	by	Entergy	Arkansas,	 issued	$124.1	million	 of	 storm	 cost recovery	bonds.		The	bonds	have	a	coupon	of	2.30%	and	an	expected	maturity	date	of	August	2021.		Although	the	principal	amount	is	not	due until	the	date	given	above,	Entergy	Arkansas	Restoration	Funding	expects	to	make	principal	payments	on	the	bonds	over	the	next	five	years	in	the amount	of	$12.8	million	for	2014,	$13.2	million	for	2015,	$13.4	million	for	2016,	$13.8	million	for	2017,	and	$14.1	million	for	2018.		With	the proceeds,	Entergy	Arkansas	Restoration	Funding	purchased	from	Entergy	Arkansas	the	storm	recovery	property,	which	is	the	right	to	recover from	customers	through	a	storm	recovery	charge	amounts	sufficient	to	service	the	securitization	bonds.		The	storm	recovery	property	is	reflected as	a	regulatory	asset	on	the	consolidated	Entergy	Arkansas	balance	sheet.		The	creditors	of	Entergy	Arkansas	do	not	have	recourse	to	the	assets	or revenues	of	Entergy	Arkansas	Restoration	Funding,	including	the	storm	recovery	property,	and	the	creditors	of	Entergy	Arkansas	Restoration Funding	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Arkansas.		Entergy	Arkansas	has	no	payment	obligations	to	Entergy	Arkansas Restoration	Funding	except	to	remit	storm	recovery	charge	collections.

In	August	2011,	the	LPSC	issued	a	financing	order	authorizing	the	issuance	of	bonds	to	recover	Entergy	Louisiana's	investment	recovery costs	associated	with	the	cancelled	Little	Gypsy	repowering	project.		In	September	2011,	Entergy	Louisiana	Investment	Recovery	Funding	I, L.L.C.,	a	company	wholly-owned	and	consolidated	by	Entergy	Louisiana,	issued	$207.2	million	of	senior	secured	investment	recovery	bonds. The	bonds	have	an	interest	rate	of	2.04%	and	an	expected	maturity	date	of	June	2021.		Although	the	principal	amount	is	not	due	until	the	date given	above,	Entergy	Louisiana	Investment	Recovery	Funding	expects	to	make	principal	payments	on	the	bonds	over	the	next	five	years	in	the amounts	of	$21.9	million	for	2014,	$20.5	million	for	2015,	$21.6	million	for	2016,	$21.7	million	for	2017,	and	$22.3	million	for	2018.		With	the proceeds,	Entergy	Louisiana	Investment	Recovery	Funding	purchased	from	Entergy	Louisiana	the	investment	recovery	property,	which	is	the right	to	recover	from	customers	through	an	investment	recovery	charge	amounts	sufficient	to	service	the	bonds.		In	accordance	with	the	financing order,	Entergy	Louisiana	will	apply	the	proceeds	it	received	from	the	sale	of	the	investment	recovery	property	as	a	reimbursement	for	previously- incurred	investment	recovery	costs.		The	investment	recovery	property	is	reflected	as	a	regulatory	asset	on	the	consolidated	Entergy	Louisiana balance	sheet.		The	creditors	of	Entergy	Louisiana	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Louisiana	Investment	Recovery Funding,	including	the	investment	recovery	property,	and	the	creditors	of	Entergy	Louisiana	Investment	Recovery	Funding	do	not	have	recourse to	the	assets	or	revenues	of	Entergy	Louisiana.		Entergy	Louisiana	has	no	payment	obligations	to	Entergy	Louisiana	Investment	Recovery	Funding except	to	remit	investment	recovery	charge	collections.

# Entergy	Texas	Securitization	Bonds	-	Hurricane	Rita

In	April	2007,	the	PUCT	issued	a	financing	order	authorizing	the	issuance	of	securitization	bonds	to	recover	 $353	million	of	Entergy Texas's	Hurricane	Rita	reconstruction	costs	and	up	 to	$6	million	 of	 transaction	 costs,	 offset	 by	$32	million	of	related	deferred	 income	 tax benefits.		In	June	2007,	Entergy	Gulf	States	Reconstruction	Funding	I,	LLC,	a	company	that	is	now	wholly-owned	and	consolidated	by	Entergy Texas,	issued	$329.5	million	of	senior	secured	transition	bonds	(securitization	bonds)	as	follows:

|  | Amount |
| :--- | :--- |
|  | (In\tThousands) |
| Senior\tSecured\tTransition\tBonds,\tSeries\tA: |  |
| Tranche\tA-1\t(5.51%)\tdue\tOctober\t2013 | $93,500 |
| Tranche\tA-2\t(5.79%)\tdue\tOctober\t2018 | 121,600 |
| Tranche\tA-3\t(5.93%)\tdue\tJune\t2022 | 114,400 |
| Total\tsenior\tsecured\ttransition\tbonds | $329,500 |

Although	the	principal	amount	of	each	tranche	is	not	due	until	the	dates	given	above,	Entergy	Gulf	States	Reconstruction	Funding	expects	to make	principal	payments	on	the	bonds	over	the	next	five	years	in	the	amounts	of	$23.2	million	for	2014,	$24.6	million	for	2015,	$26.0	million	for 2016,	$27.6	million	for	2017,	and	$29.2	million	 for	2018.		All	of	the	scheduled	principal	payments	for	2014-2016	are	for	Tranche	A-2,	$23.6 million	of	the	scheduled	principal	payments	for	2017	are	for	Tranche	A-2	and		 $4.0	million	of	the	scheduled	principal	payments	for	2017	are	for Tranche	A-3.	All	of	the	scheduled	principal	payments	for	2018	are	for	Tranche	A-3.

With	the	proceeds,	Entergy	Gulf	States	Reconstruction	Funding	purchased	from	Entergy	Texas	the	transition	property,	which	is	the	right to	recover	from	customers	through	a	transition	charge	amounts	sufficient	to	service	the	securitization	bonds.		The	transition	property	is	reflected	as a	regulatory	asset	on	the	consolidated	Entergy	Texas	balance	sheet.		The	creditors	of	Entergy	Texas	do	not	have	recourse	to	the	assets	or	revenues of	Entergy	Gulf	States	Reconstruction	Funding,	including	the	transition	property,	and	the	creditors	of	Entergy	Gulf	States	Reconstruction	Funding do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Texas.		Entergy	Texas	has	no	payment	obligations	to	Entergy	Gulf	States	Reconstruction Funding	except	to	remit	transition	charge	collections.

# Entergy	Texas	Securitization	Bonds	-	Hurricane	Ike	and	Hurricane	Gustav

In	September	2009,	the	PUCT	authorized	the	issuance	of	securitization	bonds	to	recover	$566.4	million	of	Entergy	Texas's	Hurricane	Ike and	Hurricane	Gustav	restoration	costs,	plus	carrying	costs	and	transaction	costs,	offset	by	insurance	proceeds.		In	November	2009,	Entergy Texas	Restoration	funding,	LLC	(Entergy	Texas	Restoration	Funding),	a	company	wholly-owned	and	consolidated	by	Entergy	Texas,	issued $545.9	million	of	senior	secured	transition	bonds	(securitization	bonds),	as	follows:

|  | Amount |
| :--- | :--- |
|  | (In\tThousands) |
| Senior\tSecured\tTransition\tBonds |  |
| Tranche\tA-1\t(2.12%)\tdue\tFebruary\t2016 | $182,500 |
| Tranche\tA-2\t(3.65%)\tdue\tAugust\t2019 | 144,800 |
| Tranche\tA-3\t(4.38%)\tdue\tNovember\t2023 | 218,600 |
| Total\tsenior\tsecured\ttransition\tbonds | $545,900 |

Although	the	principal	amount	of	each	tranche	is	not	due	until	the	dates	given	above,	Entergy	Texas	Restoration	Funding	expects	to	make principal	payments	on	the	bonds	over	the	next	five	years	in	the	amount	of	$40.2	million	for	2014,	$41.2	million	for	2015,	$42.6	million	for	2016, $44.1	million	for	2017,	and	$45.8	million	for	2018.		All	of	the	scheduled	principal	payments	for	2014	are	for	Tranche	A-1,	$13.8	million	of	the scheduled	principal	payments	for	2015	are	for	Tranche	A-1	and	$27.4	million	are	for	Tranche	A-2.	All	of	the	scheduled	principal	payments	for 2016-2017	are	for	Tranche	A-2,	$30.8	million	of	the	scheduled	principal	payments	for	2018	are	for	Tranche	A-2	and	$15.0	million	 are	 for Tranche	A-3.

With	the	proceeds,	Entergy	Texas	Restoration	Funding	purchased	from	Entergy	Texas	the	transition	property,	which	is	the	right	to	recover from	customers	through	a	transition	charge	amounts	sufficient	to	service	the	securitization	bonds.	 	The	transition	property	is	reflected	as	a regulatory	asset	on	the	consolidated	Entergy	Texas	balance	sheet.		The

creditors	of	Entergy	Texas	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Texas	Restoration	Funding,	including	the	transition	property, and	the	creditors	of	Entergy	Texas	Restoration	Funding	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Texas.		Entergy	Texas	has	no payment	obligations	to	Entergy	Texas	Restoration	Funding	except	to	remit	transition	charge	collections.

# NOTE	6.			PREFERRED	EQUITY	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans)

The	number	of	shares	and	units	authorized	and	outstanding	and	dollar	value	of	preferred	stock,	preferred	membership	interests,	and	non- controlling	 interest	 for	 Entergy	 Corporation	 subsidiaries	 as	 of	December	31,	2013	 and	2012	are	presented	below.	 	All	series	of	 the	Utility preferred	stock	are	redeemable	at	the	option	of	the	related	company.

|  | Shares/Units<br>Authorized | Shares/Units<br>Authorized | Shares/Units<br>Outstanding | Shares/Units<br>Outstanding |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Entergy\tCorporation |  |  |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |
| Utility: |  |  |  |  |  |  |
| Preferred\tStock\tor\tPreferred |  |  |  |  |  |  |
| Membership\tInterests\twithout\tsinking |  |  |  |  |  |  |
| fund: |  |  |  |  |  |  |
| Entergy\tArkansas,\t4.32%-6.45%\n\t\t\t\tSeries | 3,413,500 | 3,413,500 | 3,413,500 | 3,413,500 | $116,350 | $116,350 |
| Entergy\tGulf\tStates\tLouisiana,\n\t\t\t\tSeries\tA\t8.25\t% | 100,000 | 100,000 | 100,000 | 100,000 | 10,000 | 10,000 |
| Entergy\tLouisiana,\t6.95%\tSeries\t(a) | 1,000,000 | 1,000,000 | 840,000 | 840,000 | 84,000 | 84,000 |
| Entergy\tMississippi,\t4.36%-6.25%\n\t\t\t\tSeries | 1,403,807 | 1,403,807 | 1,403,807 | 1,403,807 | 50,381 | 50,381 |
| Entergy\tNew\tOrleans,\t4.36%-5.56%\n\t\t\t\tSeries | 197,798 | 197,798 | 197,798 | 197,798 | 19,780 | 19,780 |
| Total\tUtility\tPreferred\tStock\tor |  |  |  |  |  |  |
| Preferred\tMembership\tInterests\twithout |  |  |  |  |  |  |
| sinking\tfund | 6,115,105 | 6,115,105 | 5,955,105 | 5,955,105 | 280,511 | 280,511 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |  |
| Preferred\tStock\twithout\tsinking\tfund: |  |  |  |  |  |  |
| Entergy\tAsset\tManagement,\t8.95%\t(b) | 1,000,000 | 1,000,000 | — | — | — | — |
| Entergy\tFinance\tHolding,\tInc.\t8.75%\t(c) | 250,000 | — | 250,000 | — | 24,249 | — |
| Total\tSubsidiaries'\tPreferred\tStock\nwithout\tsinking\tfund | 7,365,105 | 7,115,105 | 6,205,105 | 5,955,105 | $304,760 | $280,511 |

(a) In	2007,	Entergy	Louisiana	Holdings,	an	Entergy	subsidiary,	purchased	160,000	of	these	shares	from	the	holders.

(b) Upon	the	sale	of	Class	B	preferred	shares	in	December	2009,	Entergy	Asset	Management	had	issued	and	outstanding	Class	A	and	Class	B preferred	shares.		On	December	20,	2011,	Entergy	Asset	Management	purchased	all	of	the	outstanding	Class	B	preferred	shares	from	the holder	 thereof;	 currently,	 there	 are	 no	 outstanding	 Class	 B	 preferred	 shares.	 	 On	 December	 20,	 2011,	 Entergy	Asset	 Management purchased	all	of	the	outstanding	Class	A	preferred	shares	(278,905	shares)	that	were	held	by	a	third	party;	currently,	there	are	 4,759 shares	held	by	an	Entergy	affiliate.

(c) Dollar	amount	outstanding	is	net	of	$751	thousand	of	preferred	stock	issuance	costs.

At	December	31,	2013	and	2012,	Entergy	Gulf	States	Louisiana	had	outstanding	100,000	units	of	no	par	value	8.25%	Series	Preferred Membership	Interests	that	were	initially	issued	by	Entergy	Gulf	States,	Inc.	as	preference	stock.		The	preference	shares	were	converted	into	the preferred	units	as	part	of	the	jurisdictional	separation.		The	distributions	are	cumulative	and	payable	quarterly	beginning	March	15,	2008.		The preferred	membership	interests	are	redeemable	on	or	after	December	15,	2015,	at	Entergy	Gulf	States	Louisiana's	option,	at	the	fixed	redemption price	of	$100	per	unit.

In	December	2013,	Entergy	Finance	Holding,	Inc.	issued	250,000	shares	of	$100	par	value	8.75%	Series	Preferred	Stock,	all	of	which	are outstanding	as	of	December	31,	2013.	The	dividends	are	cumulative	and	payable	quarterly	beginning	March	15,	2014.	The	preferred	stock	is redeemable	on	or	after	December	16,	2023,	at	Entergy	Finance	Holding,	Inc.'s	option,	at	the	fixed	redemption	price	of	$100	per	share.

The	number	of	shares	and	units	authorized	and	outstanding	and	dollar	value	of	preferred	stock	and	membership	interests	for	Entergy Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	as	of	December	31,	2013	and	2012 are	presented	below.		All	series	of	the	Utility	operating	companies'	preferred	stock	and	membership	interests	are	redeemable	at	the	respective company's	option	at	the	call	prices	presented.		Dividends	and	distributions	paid	on	all	of	Entergy's	preferred	stock	and	membership	interests 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	Mississippi	4.56%,	and	Entergy	New	Orleans	4.75%.

|  | Shares<br>Authorized<br>and	Outstanding<br>2013 | 2012 | Dollars<br>(In	Thousands)<br>2013 | 2012 | Call	Price	per<br>Share	as	of<br>December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas\tPreferred\tStock |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.32%\tSeries | 70,000 | 70,000 | $7,000 | $7,000 | $103.65 |
| 4.72%\tSeries | 93,500 | 93,500 | 9,350 | 9,350 | $107.00 |
| 4.56%\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | $102.83 |
| 4.56%\t1965\tSeries | 75,000 | 75,000 | 7,500 | 7,500 | $102.50 |
| 6.08%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.83 |
| Cumulative,\t$25\tpar\tvalue: |  |  |  |  |  |
| 6.45%\tSeries\t(a) | 3,000,000 | 3,000,000 | 75,000 | 75,000 | $25 |
| Total\twithout\tsinking\tfund | 3,413,500 | 3,413,500 | $116,350 | $116,350 |  |

|  | Units<br>Authorized<br>and	Outstanding<br>2013 | 2012 | Dollars<br>(In	Thousands)<br>2013 | 2012 |
| :--- | :--- | :--- | :--- | :--- |
| Entergy\tGulf\tStates\tLouisiana\nPreferred\tMembership\tInterests |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |
| Cumulative,\t$100\tliquidation\tvalue: |  |  |  |  |
| 8.25%\tSeries\t(b) | 100,000 | 100,000 | $10,000 | $10,000 |
| Total\twithout\tsinking\tfund | 100,000 | 100,000 | $10,000 | $10,000 |

|  | Units<br>Authorized<br>and	Outstanding<br>2013 | 2012 | Dollars<br>(In	Thousands)<br>2013 | 2012 | Call	Price	per<br>Unit	as	of<br>December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tLouisiana\tPreferred\tMembership\nInterests |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tliquidation\tvalue: |  |  |  |  |  |
| 6.95%\tSeries\t(a) | 1,000,000 | 1,000,000 | $100,000 | $100,000 | $100 |
| Total\twithout\tsinking\tfund | 1,000,000 | 1,000,000 | $100,000 | $100,000 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2013 | 2012 | Dollars<br>(In	Thousands)<br>2013 | 2012 | Call	Price	per<br>Share	as	of<br>December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tMississippi\tPreferred\tStock |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.36%\tSeries | 59,920 | 59,920 | $5,992 | $5,992 | $103.88 |
| 4.56%\tSeries | 43,887 | 43,887 | 4,389 | 4,389 | $107.00 |
| 4.92%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.88 |
| Cumulative,\t$25\tpar\tvalue |  |  |  |  |  |
| 6.25%\tSeries\t(a) | 1,200,000 | 1,200,000 | 30,000 | 30,000 | $25 |
| Total\twithout\tsinking\tfund | 1,403,807 | 1,403,807 | $50,381 | $50,381 |  |

|  | Shares<br>Authorized<br>and	Outstanding<br>2013 | 2012 | Dollars<br>(In	Thousands)<br>2013 | 2012 | Call	Price	per<br>Share	as	of<br>December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tNew\tOrleans\tPreferred\tStock |  |  |  |  |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.36%\tSeries | 60,000 | 60,000 | $6,000 | $6,000 | $104.58 |
| 4.75%\tSeries | 77,798 | 77,798 | 7,780 | 7,780 | $105.00 |
| 5.56%\tSeries | 60,000 | 60,000 | 6,000 | 6,000 | $102.59 |
| Total\twithout\tsinking\tfund | 197,798 | 197,798 | $19,780 | $19,780 |  |

(a) Series	is	callable	at	par.

(b) Series	is	callable	at	par	on	and	after	December	15,	2015.

# NOTE	7.			COMMON	EQUITY	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

# Common	Stock

Common	stock	and	treasury	stock	shares	activity	for	Entergy	for	2013,	2012,	and	2011	is	as	follows:

|  | Common<br>Shares<br>Issued | Treasury<br>Shares | Common<br>Shares<br>Issued | Treasury<br>Shares | Common<br>Shares<br>Issued | Treasury<br>Shares |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Beginning\tBalance,\tJanuary |  |  |  |  |  |  |
| 1 | 254,752,788 | 76,945,239 | 254,752,788 | 78,396,988 | 254,752,788 | 76,006,920 |
| Repurchases | — | — | — | — | — | 3,475,000 |
| Issuances: |  |  |  |  |  |  |
| Employee\tStock-Based\n\t\tCompensation\tPlans | — | (557,734) | — | (1,446,305) | — | (1,079,008) |
| Directors'\tPlan | — | (5,569) | — | (5,444) | — | (5,924) |
| Ending\tBalance,\tDecember |  |  |  |  |  |  |
| 31 | 254,752,788 | 76,381,936 | 254,752,788 | 76,945,239 | 254,752,788 | 78,396,988 |

Entergy	Corporation	reissues	treasury	shares	to	meet	the	requirements	of	the	Stock	Plan	for	Outside	Directors	(Directors'	Plan),	 two Equity	Ownership	Plans	of	Entergy	Corporation	and	Subsidiaries,	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	dollar	value of	shares	of	Entergy	Corporation	common	stock.

In	October	2010	the	Board	granted	authority	for	a	$500	million	share	repurchase	program.		As	of	December	31,	2013,	$350	million	of authority	remains	under	the	$500	million	share	repurchase	program.

# 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	could	restrict	 the	payment	of	cash	dividends	or	other	distributions	on	 their common	 and	 preferred	 equity.	 	 As	 of	December	 31,	 2013,	 under	 provisions	 in	 their	 mortgage	 indentures,	 Entergy	Arkansas	 and	 Entergy Mississippi	had	retained	earnings	unavailable	for	distribution	to	Entergy	Corporation	of	$394.9	million	and	$68.5	million,	respectively.		Entergy Corporation	received	dividend	payments	from	subsidiaries	totaling	$702	million	in	2013,	$439	million	in	2012,	and	$595	million	in	2011.

# Comprehensive	Income

Accumulated	other	comprehensive	loss	is	included	in	the	equity	section	of	the	balance	sheets	of	Entergy,	Entergy	Gulf	States	Louisiana, and	Entergy	Louisiana.	The	following	table	presents	changes	in	accumulated	other	comprehensive	loss	for	Entergy	for	the	year	ended	December 31,	2013	by	component:

|  | Cash	flow<br>hedges<br>net<br>unrealized<br>gain	(loss) | Pension<br>and<br>other<br>postretirement<br>liabilities | Net<br>unrealized<br>investment<br>gains | Foreign<br>currency<br>translation | Total<br>Accumulated<br>Other<br>Comprehensive<br>Loss |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Beginning\tbalance,\tDecember\t31,\t2012 | $79,905 | ($590,712) | $214,547 | $3,177 | ($293,083) |
| Other\tcomprehensive\tincome\t(loss)\tbefore\nreclassifications | (133,312) | 260,567 | 143,936 | 243 | 271,434 |
| Amounts\treclassified\tfrom |  |  |  |  |  |
| accumulated\tother\tcomprehensive |  |  |  |  |  |
| loss | (28,370) | 41,922 | (21,227) | — | (7,675) |
| Net\tother\tcomprehensive\tincome\t(loss)\tfor\nthe\tperiod | (161,682) | 302,489 | 122,709 | 243 | 263,759 |
| Ending\tbalance,\tDecember\t31,\t2013 | ($81,777) | ($288,223) | $337,256 | $3,420 | ($29,324) |

The	following	table	presents	changes	in	accumulated	other	comprehensive	loss	for	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana for	the	year	ended	December	31,	2013:

Total	reclassifications	out	of	accumulated	other	comprehensive	loss	(AOCI)	for	Entergy	for	the	year	ended	December	31,	2013	are	as

# follows:

(a) These	accumulated	other	comprehensive	loss	components	are	included	in	the	computation	of	net	periodic	pension	cost.	See	Note	11	to the	financial	statements	for	additional	details.

Total	reclassifications	out	of	accumulated	other	comprehensive	loss	(AOCI)	for	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	for the	year	ended	December	31,	2013	are	as	follows:

# NOTE	 8. 	 COMMITMENTS	AND	 CONTINGENCIES	 (Entergy	 Corporation,	 Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Entergy	 and	 the	 Registrant	 Subsidiaries	 are	 involved	 in	 a	 number	 of	 legal,	 regulatory,	 and	 tax	 proceedings	 before	 various	 courts, regulatory	commissions,	and	governmental	agencies	in	the	ordinary	course	of	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	effect	on	Entergy's	results	of operations,	cash	flows,	or	financial	condition.		Entergy	discusses	regulatory	proceedings	in	Note	2	to	the	financial	statements	and	discusses	tax proceedings	in	Note	3	to	the	financial	statements.

# 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	$181.1	million	in	2013,	$125.0	million	in	2012,	and $185.6	million	in	2011.		If	the	maximum	percentage	(94%)	of	the	energy	is	made	available	to	Entergy	Louisiana,	current	production	projections would	require	estimated	payments	of	approximately	$147.5	million	in	2014,	and	a	total	of	$2.19	billion	for	the	years	2015	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	10	years,	beginning	in	October	2002.		In	addition,	in	accordance	with	an	LPSC	settlement,	Entergy Louisiana	credited	rates	in	August	2007	by	$11.3	million	(including	interest)	as	a	result	of	a	settlement	with	the	IRS	of	the	2001	tax	treatment	of the	Vidalia	contract.		As	discussed	in	more	detail	in	Note	3	to	the	financial	statements,	in	August	2011,	Entergy	agreed	to	a	settlement	with	the IRS	regarding	the	mark-to-market	income	tax	treatment	of	various	wholesale	electric	power	purchase	and	sale	agreements,	including	the

Vidalia	agreement.		In	October	2011	the	LPSC	approved	a	final	settlement	under	which	Entergy	Louisiana	agreed	to	share	the	remaining	benefits of	this	tax	accounting	election	by	crediting	customers	an	additional	$20.235	million	per	year	for	15	years	beginning	January	2012.		Entergy Louisiana	recorded	a	$199	million	regulatory	charge	and	a	corresponding	regulatory	liability	to	reflect	this	obligation.		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.

# Baxter	Wilson	Plant	Event

On	September	11,	2013,	Entergy	Mississippi's	Baxter	Wilson	(Unit	1)	power	plant	experienced	a	significant	unplanned	outage	event.		The cause	of	the	event	is	currently	under	investigation.		Entergy	Mississippi	is	still	in	the	process	of	assessing	the	nature	and	extent	of	the	damage	to the	unit.	The	current	estimate	of	costs	to	return	the	unit	to	service	is	between	$45	million	and	$60	million.	 	This	estimate	may	change	as restorative	activities	occur.		The	costs	necessary	to	return	the	plant	to	service	are	expected	to	continue	to	be	incurred	into	the	third	quarter	2014. Entergy	Mississippi	believes	 that	 the	damage	 is	primarily	covered	by	 its	property	 insurance	policy,	subject	 to	a	$20	 million	 deductible.	In December	2013,	Entergy	Mississippi	made	a	filing	with	the	MPSC	requesting	approval	for	Entergy	Mississippi	to	defer	and	accumulate	the	costs incurred	in	connection	with	Baxter	Wilson	repair	activities,	net	of	applicable	insurance	proceeds,	with	such	costs	to	be	recoverable	in	a	manner	to be	determined	by	the	MPSC.	The	MPSC	has	not	acted	on	Entergy	Mississippi's	request.

# Nuclear	Insurance

# Third	Party	Liability	Insurance

The	Price-Anderson	Act	requires	that	reactor	licensees	purchase	insurance	and	participate	in	a	secondary	insurance	pool	that	provides insurance	coverage	for	the	public	in	the	event	of	a	nuclear	power	plant	accident.		The	costs	of	this	insurance	are	borne	by	the	nuclear	power industry.		Congress	amended	and	renewed	the	Price-Anderson	Act	in	2005	for	a	term	through	2025.		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	layers	of	coverage:

1. The	primary	level	is	private	insurance	underwritten	by	American	Nuclear	Insurers	(ANI)	and	provides	public	liability	insurance	coverage o f	$375	 million.	 If	 this	 amount	 is	 not	 sufficient	 to	 cover	 claims	 arising	 from	 an	 accident,	 the	 second	 level,	 Secondary	 Financial Protection,	applies.

2. Within	the	Secondary	Financial	Protection	level,	each	nuclear	reactor	has	a	contingent	obligation	to	pay	a	retrospective	premium,	equal	to its	proportionate	share	of	the	loss	in	excess	of	the	primary	level,	regardless	of	proximity	to	the	incident	or	fault,	up	to	a	maximum	of $127.3	million	per	reactor	per	incident	(Entergy's	maximum	total	contingent	obligation	per	incident	is	 $1.4	billion).		This	consists	of	a $121.3	million	maximum	retrospective	premium	plus	a	five	percent	surcharge,	which	equates	to	$127.3	million,	that	may	be	payable,	if needed,	at	a	rate	that	is	currently	set	at	$19.0	million	per	year	per	incident	per	nuclear	power	reactor.

3. In	the	event	that	one	or	more	acts	of	terrorism	cause	a	nuclear	power	plant	accident,	which	results	in	third-party	damages	–	off-site property	and	environmental	damage,	off-site	bodily	 injury,	and	on-site	 third-party	bodily	 injury	(i.e.	contractors);	 the	primary	 level provided	by	ANI	combined	with	 the	Secondary	Financial	Protection	would	provide	$13.6	billion	 in	coverage.	 	The	Terrorism	Risk Insurance	Reauthorization	Act	of	2007	created	a	government	program	that	provides	for	up	to	$100	billion	in	coverage	in	excess	of	existing coverage	for	a	terrorist	event.

Currently,	104	 nuclear	 reactors	 are	 participating	 in	 the	 Secondary	 Financial	 Protection	 program.	 	 The	 product	 of	 the	 maximum retrospective	 premium	 assessment	 to	 the	 nuclear	 power	 industry	 and	 the	 number	 of	 nuclear	 power	 reactors	 provides	 over	$13.2	 billion	 in secondary	layer	insurance	coverage	to	compensate	the	public	in	the	event	of	a	nuclear	power	reactor	accident.		The	Price-Anderson	Act	provides that	all	potential	liability	for	a	nuclear	accident	is	limited	to	the	amounts	of	insurance	coverage	available	under	the	primary	and	secondary	layers.

Entergy	Arkansas	has	two	licensed	reactors	and	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy	each	have	one licensed	reactor	(10%	of	Grand	Gulf	is	owned	by	a	non-affiliated	company	(SMEPA)	that	would	share	on	a	pro-rata	basis	in	any	retrospective premium	assessment	to	System	Energy	under	the	Price-Anderson	Act).		The	Entergy	Wholesale	Commodities	segment	includes	the	ownership and	operation	of	six	nuclear	power	reactors	and	the	ownership	of	the	shutdown	Indian	Point	1	reactor	and	Big	Rock	Point	facility.

# Property	Insurance

Entergy's	nuclear	owner/licensee	subsidiaries	are	members	of	Nuclear	Electric	Insurance	Limited	(NEIL),	a	mutual	insurance	company that	provides	property	damage	coverage,	including	decontamination	and	premature	decommissioning	expense,	to	the	members'	nuclear	generating plants.		Effective	April	1,	2013,	Entergy	was	insured	against	such	losses	per	the	following	structures:

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)		-	$750	million	per	occurrence •Blanket	Layer	(shared	among	the	Utility	plants)	-	$350	million	per	occurrence •Total	limit	-	$1.6	billion	per	occurrence

•Deductibles:

•$2.5	million	per	occurrence	-	Turbine/generator	damage

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

•$10	million	per	occurrence	plus	10%	of	amount	above	$10	million	-	Damage	from	a	windstorm,	flood,	earthquake,	or	volcanic eruption

Note:		ANO	1	and	2	share	in	the	primary	and	excess	layers	with	common	policies	because	the	policies	are	issued	on	a	per	site	basis.	Also, flood	 and	 earthquake	 coverage	 are	 excluded	 from	 the	 primary	 layer,	 which	 provides	 the	 first	$500	 million	 in	 coverage.	Entergy	 currently purchases	primary	layer	flood	coverage	for	Waterford	3	and	River	Bend.

Entergy	Wholesale	Commodities	Plants	(FitzPatrick,	Pilgrim,	Vermont	Yankee,	Palisades,	and	Big	Rock	Point)

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

•Excess	Layer	-	$615	million	per	occurrence

•Total	limit	-	$1.115	billion	per	occurrence

Note:		Big	Rock	Point	has	its	own	primary	policy	with	no	excess	coverage.	Also,	flood	and	earthquake	coverage	are	excluded	from	the primary	layer,	which	provides	the	first	$500	million	in	coverage.	Entergy	currently	purchases	primary	layer	flood	and	earthquake	coverage	for Vermont	Yankee,	Palisades,	and	Big	Rock	Point.

Entergy	Wholesale	Commodities	Plant	(Indian	Point)

•Excess	Layer	-	$1.1	billion	per	occurrence

•Total	limit	-	$1.6	billion	per	occurrence •Deductibles:

Note:	The	Indian	Point	Units	share	in	the	primary	and	excess	layers	with	common	policies	because	the	policies	are	issued	on	a	per	site basis.	Also,	flood	and	earthquake	coverage	are	excluded	from	the	primary	layer,	which	provides	the	first	$500	million	 in	 coverage.	Entergy currently	purchases	primary	layer	flood	coverage	for	Indian	Point.

In	addition,	Waterford	3,	Grand	Gulf,	and	the	Entergy	Wholesale	Commodities	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 primary	property	damage	loss,	subject	to	a	deductible	period.		The	payout	for	damage	resulting	from	non-nuclear	events	is	limited	to	a	$327.6 million	per	occurrence	sub-limit.	The	following	summarizes	this	coverage	effective	April	1,	2013:

# Waterford	3

•$2.95	million	weekly	indemnity

•$413	million	maximum	indemnity

•Deductible:		26	week	deductible	period

# Grand	Gulf

•$400,000	weekly	indemnity	(total	for	four	policies) •$56	million	maximum	indemnity	(total	for	four	policies) •Deductible:		26	week	deductible	period

Indian	Point	2,	Indian	Point	3,	and	Palisades •$4.5	million	weekly	indemnity •$490	million	maximum	indemnity •Deductible:	12	week	deductible	period

Under	the	property	damage	and	accidental	outage	insurance	programs,	all	NEIL	insured	plants	could	be	subject	to	assessments	should losses	exceed	the	accumulated	funds	available	from	NEIL.		Effective	April	1,	2013,	the	maximum	amounts	of	such	possible	assessments	per occurrence	were	as	follows:

|  | Assessments |
| :--- | :--- |
|  | (In\tMillions) |
| Utility: |  |
| Entergy\tArkansas | $25.1 |
| Entergy\tGulf\tStates\tLouisiana | $23 |
| Entergy\tLouisiana | $24.2 |
| Entergy\tMississippi | $0.07 |
| Entergy\tNew\tOrleans | $0.07 |
| Entergy\tTexas | N/A |
| System\tEnergy | $18.9 |

Potential	assessments	for	the	Entergy	Wholesale	Commodities	plants	are	covered	by	insurance	obtained	through	NEIL's	reinsurers.

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	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.		The	Terrorism	Risk	Insurance	Reauthorization	Act	of	2007	created	a	government	program	that	provides	for	up	to $100 billion	in	coverage	in	excess	of	existing	coverage	for	a	terrorist	event.

# Conventional	Property	Insurance

Entergy's	conventional	property	insurance	program	provides	coverage	of	up	to	 $400	million	on	an	Entergy	system-wide	basis	for	all operational	perils	(direct	physical	loss	or	damage	due	to	machinery	breakdown,	electrical	failure,	fire,	lightning,	hail,	or	explosion)	on	an	"each and	every	loss"	basis;	up	to	$400	million	in	coverage	for	certain	natural	perils	(direct	physical	loss	or	damage	due	to	earthquake,	tsunami,	and flood)	on	an	annual	aggregate	basis;	up	to	$125	million	for	certain	other	natural	perils	(direct	physical	loss	or	damage	due	to	a	named	windstorm and	associated	storm	surge)	on	an	annual	aggregate	basis;	and	up	to	$400	million	in	coverage	for	all	other	natural	perils	not	previously	stated (direct	physical	loss	or	damage	due	to	a	tornado,	ice	storm,	or	any	other	natural	peril	except	named	windstorm	and	associated	storm	surge, earthquake,	tsunami,	and	flood)	on	an	"each	and	every	loss"	basis.		The	conventional	property	insurance	program	provides	up	to	$50	million	in coverage	for	the	Entergy	New	Orleans	gas	distribution	system	on	an	"each	and	every	loss"	basis.		This	$50	million	limit	is	subject	to:	the	$400 million	annual	aggregate	limit	for	the	natural	perils	of	earthquake,	tsunami,	and	flood;	the	$125	million	annual	aggregate	limit	for	the	natural perils	of	named	windstorm	and	associated	storm	surge;	the	$400	million	per	occurrence	limit	for	all	other	natural	perils	not	previously	stated, which	includes	tornado	and	ice	storm,	but	excludes	named	windstorm	and	associated	storm	surge,	earthquake,	tsunami,	and	flood;	and	the	$400 million	per	occurrence	limit	for	operational	perils.		The	coverage	is	subject	to	a	$40	million	self-insured	retention	per	occurrence	for	the	natural perils	of	named	windstorm	and	associated	storm	surge,	earthquake,	flood,	and	tsunami;	and	a	$20	million	self-insured	retention	per	occurrence	for operational	perils	and	all	other	natural	perils	not	previously	stated,	which	includes	tornado	and	ice	storm,	but	excludes	named	windstorm	and associated	storm	surge,	earthquake,	tsunami,	and	flood.

Covered	property	generally	includes	power	plants,	substations,	facilities,	inventories,	and	gas	distribution-related	properties.		Excluded property	generally	 includes	above-ground	 transmission	and	distribution	 lines,	poles,	and	 towers	for	substations	valued	at	$5	million	 or	 less, coverage	for	named	windstorm	and	associated	storm	surge	 is	excluded.	 	This	coverage	 is	 in	place	for	Entergy	Corporation,	 the	Registrant Subsidiaries,	and	certain	other	Entergy	subsidiaries,	including	the	owners	of	the	nuclear	power	plants	in	the	Entergy	Wholesale	Commodities segment.	 	Entergy	also	purchases	$300	million	in	terrorism	insurance	coverage	for	its	conventional	property.		The	Terrorism	Risk	Insurance Reauthorization	Act	of	2007	created	a	government	program	that	provides	for	up	to	$100	billion	in	coverage	in	excess	of	existing	coverage	for	a terrorist	event.

In	addition	to	the	conventional	property	insurance	program,	Entergy	has	purchased	additional	coverage	($20	million	per	occurrence)	for some	of	its	non-regulated,	non-generation	assets.		This	policy	serves	to	buy-down	the	$20	million	deductible	and	is	placed	on	a	scheduled	location basis.		The	applicable	deductibles	are	$100,000	to	$250,000,	except	for	properties	that	are	damaged	by	flooding	and	properties	whose	values	are greater	than	$20	million;	these	properties	have	a	$500,000	deductible.		Four	nuclear	locations	have	a	$2.5	million	deductible,	which	coincides with	the	nuclear	property	insurance	deductible	at	each	respective	nuclear	site.

# Gas	System	Rebuild	Insurance	Proceeds	(Entergy	New	Orleans)

Entergy	New	Orleans	received	insurance	proceeds	for	future	construction	expenditures	associated	with	rebuilding	its	gas	system,	and	the October	2006	City	Council	resolution	approving	the	settlement	of	Entergy	New	Orleans's	rate	and	storm-cost	recovery	filings	requires	Entergy New	 Orleans	 to	 record	 those	 proceeds	 in	 a	 designated	 sub-account	 of	 other	 deferred	 credits	 until	 the	 proceeds	 are	 spent	 on	 the	 rebuild project.		This	other	deferred	credit	is	shown	as	"Gas	system	rebuild	insurance	proceeds"	on	Entergy	New	Orleans's	balance	sheet.

# Employment	and	Labor-related	Proceedings

The	Registrant	Subsidiaries	and	other	Entergy	subsidiaries	are	responding	to	various	lawsuits	in	both	state	and	federal	courts	and	to	other labor-related	proceedings	filed	by	current	and	former	employees,	recognized	bargaining

representatives,	and	third	parties	not	selected	for	open	positions	or	providing	services	directly	or	indirectly	to	one	or	more	of	the	Registrant Subsidiaries	and	other	Entergy	subsidiaries.		Generally,	the	amount	of	damages	being	sought	is	not	specified	in	these	proceedings.		These	actions include,	but	are	not	limited	to,	allegations	of	wrongful	employment	actions;	wage	disputes	and	other	claims	under	the	Fair	Labor	Standards	Act	or its	state	counterparts;	claims	of	race,	gender,	age,	and	disability	discrimination;	disputes	arising	under	collective	bargaining	agreements;	unfair labor	practice	proceedings	and	other	administrative	proceedings	before	the	National	Labor	Relations	Board	or	concerning	the	National	Labor Relations	Act;	claims	of	retaliation;	claims	of	harassment	and	hostile	work	environment;	and	claims	for	or	regarding	benefits	under	various Entergy	Corporation-sponsored	plans.	Entergy	and	the	Registrant	Subsidiaries	are	responding	to	these	lawsuits	and	proceedings	and	deny	liability to	the	claimants.		Management	believes	that	loss	exposure	has	been	and	will	continue	to	be	handled	so	that	the	ultimate	resolution	of	these	matters will	not	be	material,	in	the	aggregate,	to	the	financial	position,	results	of	operation,	or	cash	flows	of	Entergy	or	the	Utility	operating	companies.

# Asbestos	Litigation	(Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas)

Numerous	lawsuits	have	been	filed	in	federal	and	state	courts	primarily	in	Texas	and	Louisiana,	primarily	by	contractor	employees	who worked	in	the	1940-1980s	timeframe,	against	Entergy	Gulf	States	Louisiana	and	Entergy	Texas,	and	to	a	lesser	extent	the	other	Utility	operating companies,	as	premises	owners	of	power	plants,	for	damages	caused	by	alleged	exposure	to	asbestos.		Many	other	defendants	are	named	in	these lawsuits	as	well.		Currently,	there	are	approximately	400	lawsuits	involving	approximately	5,000	claimants.		Management	believes	that	adequate provisions	 have	 been	 established	 to	 cover	 any	 exposure. Additionally,	 negotiations	 continue	 with	 insurers	 to	 recover reimbursements.		Management	believes	that	loss	exposure	has	been	and	will	continue	to	be	handled	so	that	the	ultimate	resolution	of	these	matters will	not	be	material,	in	the	aggregate,	to	the	financial	position,	results	of	operation,	or	cash	flows	of	the	Utility	operating	companies.

# Grand	Gulf	-	Related	Agreements

# Capital	Funds	Agreement	(Entergy	Corporation	and	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	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	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	the	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.		The agreement	will	remain	in	effect	until	terminated	by	the	parties	and	the	termination	is	approved	by	the	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	2013	under	the agreement	are	approximately	$22.3	million	for	Entergy	Arkansas,	$8.7	million	for	Entergy	Louisiana,	$19.2	million	for	Entergy	Mississippi,	and $10.8	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)	and	expenses	incurred	in	connection	with	a	permanent	shutdown	of	Grand Gulf.		System	Energy	has	assigned	its	rights	to	payments	and	advances	to	certain	creditors	as	security	for	certain	obligations.		Since	commercial operation	of	Grand	Gulf	began,	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's	responsibilities	and	obligations	with	respect	to	Grand	Gulf	under	the	Availability Agreement.		FERC's	decision	allocating	a	portion	of	Grand	Gulf	capacity	and	energy	to	Entergy	Arkansas	supersedes	the	Reallocation	Agreement as	it	relates	to	Grand	Gulf.		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's	 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,	in	two	separate	but	substantially	identical	transactions,	System	Energy	sold	and	leased	back	undivided	ownership interests	in	Grand	Gulf	for	the	aggregate	sum	of	$500	million.		During	the	term	of	the	leases,	System	Energy	is	required	to	maintain	letters	of credit	for	the	equity	investors	to	secure	certain	amounts	payable	to	the	equity	investors	under	the	transactions.

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,	2013,	System	Energy	was	in	compliance	with	these	covenants.

# NOTE		9.			ASSET	RETIREMENT	OBLIGATIONS		(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Accounting	standards	require	companies	to	record	liabilities	for	all	legal	obligations	associated	with	the	retirement	of	long-lived	assets	that result	 from	 the	 normal	 operation	 of	 the	 assets.	 	 For	 Entergy,	 substantially	 all	 of	 its	 asset	 retirement	 obligations	 consist	 of	 its	 liability	 for decommissioning	its	nuclear	power	plants.		In	addition,	an	insignificant	amount	of	removal	costs	associated	with	non-nuclear	power	plants	is	also included	in	the	decommissioning	line	item	on	the	balance	sheets.

These	liabilities	are	recorded	at	their	fair	values	(which	are	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	accretion	will	continue	through	the completion	of	the	asset	retirement	activity.		The	amounts	added	to	the	carrying	amounts	of	the	long-lived	assets	will	be	depreciated	over	the	useful lives	of	the	assets.		The	application	of	accounting	standards	related	to	asset	retirement	obligations	is	earnings	neutral	to	the	rate-regulated	business of	the	Registrant	Subsidiaries.

In	accordance	with	ratemaking	treatment	and	as	required	by	regulatory	accounting	standards,	the	depreciation	provisions	for	the	Registrant Subsidiaries	include	a	component	for	removal	costs	that	are	not	asset	retirement	obligations	under	accounting	standards.		In	accordance	with regulatory	accounting	principles,	the	Registrant	Subsidiaries	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:

|  | December	31, | December	31, |
| :--- | :--- | :--- |
|  | 2013 | 2012 |
|  | (In\tMillions) | (In\tMillions) |
| Entergy\tArkansas | $18.6 | ($12.2) |
| Entergy\tGulf\tStates\tLouisiana | ($35.3) | ($22.0) |
| Entergy\tLouisiana | ($37.0) | ($9.2) |
| Entergy\tMississippi | $64.3 | $57.4 |
| Entergy\tNew\tOrleans | $34.9 | $29.9 |
| Entergy\tTexas | $15.1 | $11.5 |
| System\tEnergy | $56.0 | $56.8 |

The	cumulative	decommissioning	and	retirement	cost	liabilities	and	expenses	recorded	in	 2013	by	Entergy	were	as	follows:

|  | Liabilities	as<br>of	December	31,<br>2012 | Accretion | Change	in<br>Cash	Flow<br>Estimate | Spending | Liabilities	as<br>	of	December	31,<br>2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Utility: |  |  |  |  |  |
| Entergy\tArkansas | $680.7 | $43.1 | $— | $— | $723.8 |
| Entergy\tGulf\tStates\tLouisiana | $380.8 | $22.3 | $— | $— | $403.1 |
| Entergy\tLouisiana | $418.1 | $21.6 | $39.4 | $— | $479.1 |
| Entergy\tMississippi | $6.0 | $0.4 | $— | $— | $6.4 |
| Entergy\tNew\tOrleans | $2.2 | $0.1 | $— | $— | $2.3 |
| Entergy\tTexas | $4.1 | $0.2 | $— | $— | $4.3 |
| System\tEnergy | $478.4 | $35.5 | $102.3 | $— | $616.2 |
| Entergy\tWholesale\tCommodities | $1,543.3 | $125.3 | $38.6 | ($9.0) | $1,698.2 |

|  | Liabilities	as<br>of	December	31,<br>2011 | Accretion | Change	in<br>Cash	Flow<br>Estimate | Spending | Liabilities	as<br>	of	December	31,<br>2012 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Utility: |  |  |  |  |  |
| Entergy\tArkansas | $640.2 | $40.5 | $— | $— | $680.7 |
| Entergy\tGulf\tStates\tLouisiana | $359.8 | $21.0 | $— | $— | $380.8 |
| Entergy\tLouisiana | $345.8 | $23.4 | $48.9 | $— | $418.1 |
| Entergy\tMississippi | $5.7 | $0.3 | $— | $— | $6.0 |
| Entergy\tNew\tOrleans | $2.9 | $0.2 | $— | ($0.9) | $2.2 |
| Entergy\tTexas | $3.9 | $0.2 | $— | $— | $4.1 |
| System\tEnergy | $445.4 | $33.0 | $— | $— | $478.4 |
| Entergy\tWholesale\tCommodities | $1,492.9 | $119.4 | ($58.5) | ($10.5) | $1,543.3 |

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.		As	described	below,	during 2013	and	2012	Entergy	updated	decommissioning	cost	estimates	for	certain	nuclear	power	plants.

In	the	third	quarter	2013,	Entergy	Wholesale	Commodities	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Vermont Yankee	as	a	result	of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$58	million	increase	in	the	decommissioning	cost liability,	along	with	a	corresponding	increase	in	the	related	asset	retirement	cost	asset.	The	increase	in	the	estimated	decommissioning	cost liability	resulted	from	the	change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows	due	to	the	decision	to	cease	operations	of	the plant.	The	asset	retirement	cost	asset	was	included	in	the	carrying	value	used	to	write	down	Vermont	Yankee	and	related

assets	to	their	fair	values	in	third	quarter	2013.		See	Note	1	to	the	financial	statements	for	further	discussion	of	the	resulting	impairment	charge recorded	in	third	quarter	2013.

In	 the	fourth	quarter	2013,	Entergy	Wholesale	Commodities	recorded	a	revision	 to	 its	estimated	decommissioning	cost	 liability	for Vermont	Yankee.	As	a	result	of	the	settlement	agreement	regarding	the	remaining	operation	and	decommissioning	of	Vermont	Yankee,	Entergy reassessed	its	assumptions	regarding	the	timing	of	decommissioning	cash	flows.	The	reassessment	resulted	in	a	$27.2	million	increase	in	the decommissioning	cost	liability	and	a	corresponding	impairment	charge,	which	will	not	result	in	future	cash	expenditures.	See	Note	1	to	the financial	statements	for	further	discussion	of	the	Vermont	Yankee	plant.

Assuming	 the	 end	 of	Vermont	Yankee	 operations	 in	 the	 fourth	 quarter	 2014,	 the	 amount	 required	 to	 meet	 the	 NRC	 minimum	 for decommissioning	financial	assurance	for	license	termination	is	$569.1	million.	The	Vermont	Yankee	decommissioning	trust	had	a	balance	of approximately	$612.1	million	as	of	December	31,	2013,	excluding	the	$40	million	guarantee	by	Entergy	Corporation	to	satisfy	NRC	requirements following	the	2009	review	of	financial	assurance	levels.	Filings	with	the	NRC	for	planned	shutdown	activities	will	determine	whether	any	other financial	assurance	may	be	required.

For	the	Indian	Point	3	and	FitzPatrick	plants	purchased	in	2000,	NYPA	retained	the	decommissioning	trusts	and	the	decommissioning liabilities.		NYPA	and	Entergy	subsidiaries	executed	decommissioning	agreements,	which	specify	their	decommissioning	obligations.		NYPA	has the	 rights	 to	 require	 the	 Entergy	 subsidiaries	 to	 assume	 each	 of	 the	 decommissioning	 liabilities	 provided	 that	 it	 assigns	 the	 corresponding decommissioning	trust,	up	to	a	specified	level,	to	the	Entergy	subsidiaries.		If	the	decommissioning	liabilities	are	retained	by	NYPA,	the	Entergy subsidiaries	 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	recorded	an	asset,	which	is	$572.6	million	as	of	December	31,	2013,	representing	its	estimate	of	the	present value	of	the	difference	between	the	stipulated	contract	amount	for	decommissioning	the	plants	less	the	decommissioning	costs	estimated	in independent	decommissioning	cost	studies.		The	asset	is	increased

by	monthly	accretion	based	on	the	applicable	discount	rate	necessary	to	ultimately	provide	for	the	estimated	future	value	of	the	decommissioning contract.		The	monthly	accretion	is	recorded	as	interest	income.

Entergy	maintains	decommissioning	trust	funds	that	are	committed	to	meeting	its	obligations	for	the	costs	of	decommissioning	the	nuclear power	plants.		The	fair	values	of	the	decommissioning	trust	funds	and	the	related	asset	retirement	obligation	regulatory	assets	(liabilities)	of Entergy	as	of	December	31,	2013	are	as	follows:

| ANO	1	and	ANO	2 | $710.9 | $219.1 |
| :--- | :--- | :--- |
| River\tBend | $573.7 | ($28.7) |
| Waterford\t3 | $347.3 | $128.5 |
| Grand\tGulf | $603.9 | $60.8 |
| Entergy\tWholesale\tCommodities | $2,667.3 | $— |

| ANO	1	and	ANO	2 | $600.6 | $204.0 |
| :--- | :--- | :--- |
| River\tBend | $477.4 | ($1.7) |
| Waterford\t3 | $287.4 | $126.7 |
| Grand\tGulf | $490.6 | $58.9 |
| Entergy\tWholesale\tCommodities | $2,334.1 | $— |

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

# General

As	 of	December	31,	2013,	Entergy	had	capital	leases	and	non-cancelable	operating	leases	for	equipment,	buildings,	vehicles,	and	fuel storage	facilities	(excluding	nuclear	fuel	 leases	and	 the	Grand	Gulf	and	Waterford	3	sale	and	 leaseback	 transactions)	with	minimum	 lease payments	as	follows:

| Year | Operating<br>Leases | Capital<br>Leases |
| :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |
| 2014 | $106,175 | $4,694 |
| 2015 | 89,999 | 4,615 |
| 2016 | 64,758 | 4,457 |
| 2017 | 46,731 | 4,457 |
| 2018 | 36,778 | 3,672 |
| Years\tthereafter | 111,484 | 30,551 |
| Minimum\tlease\tpayments | 455,925 | 52,446 |
| Less:\t\tAmount\trepresenting\tinterest |  | 18,135 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $34,311 | $34,311 |

Total	rental	expenses	for	all	leases	(excluding	nuclear	fuel	leases	and	the	Grand	Gulf	and	Waterford	3	sale	and	leaseback	transactions) amounted	to	$63.7	million	in	2013,	$69.9	million	in	2012,	and	$75.3	million	in	2011.

As	of	December	31,	2013,	the	Registrant	Subsidiaries	had	capital	leases	and	non-cancelable	operating	leases	for	equipment,	buildings, vehicles,	and	fuel	storage	facilities	(excluding	nuclear	fuel	leases	and	the	sale	and	leaseback	transactions)	with	minimum	lease	payments	as follows:

# Capital	Leases

| Year | Entergy<br>Arkansas | Entergy<br>Mississippi |
| :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |
| 2014 | $237 | $1,570 |
| 2015 | 158 | 1,570 |
| 2016 | — | 1,570 |
| 2017 | — | 1,570 |
| 2018 | — | 785 |
| Years\tthereafter | — | — |
| Minimum\tlease\tpayments | 395 | 7,065 |
| Less:\t\tAmount\trepresenting\tinterest | 216 | 1,081 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $179 | $5,984 |

| Year | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2014 | $32,124 | $19,735 | $11,398 | $7,155 | $2,121 | $6,442 |
| 2015 | 33,069 | 10,294 | 9,825 | 6,162 | 2,083 | 5,620 |
| 2016 | 17,999 | 9,551 | 6,574 | 4,379 | 1,720 | 4,487 |
| 2017 | 11,019 | 8,547 | 4,580 | 2,992 | 1,300 | 3,318 |
| 2018 | 6,669 | 7,753 | 3,078 | 2,300 | 883 | 2,681 |
| Years\tthereafter | 3,908 | 34,981 | 3,706 | 4,306 | 1,988 | 2,356 |
| Minimum\tlease\tpayments | $104,788 | $90,861 | $39,161 | $27,294 | $10,095 | $24,904 |

# Rental	Expenses

| Year | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| 2013 | $12.0 | $10.9 | $10.1 | $4.6 | $1.3 | $4.1 | $2.5 |
| 2012 | $12.6 | $11.9 | $11.2 | $5.5 | $1.5 | $6.4 | $1.5 |
| 2011 | $13.4 | $12.2 | $12.2 | $5.2 | $1.7 | $8.4 | $1.6 |

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	$8.6	million	in	2013,	$8.5	million	in	2012,	and	$8.3	million	in	2011 for	Entergy	Arkansas	and	$2.2	million	 in	2013,	$1.7	million	 in	2012,	 and	$2.0	million	 in	2011	for	Entergy	Gulf	States	Louisiana.		Oil	tank facilities	lease	payments	for	Entergy	Mississippi	were	$3.4	million	in	2013,	$3.4	million	in	2012,	and	$3.4	million	in	2011.

# Sale	and	Leaseback	Transactions

# Waterford	3	Lease	Obligations

In	1989,	in	three	separate	but	substantially	identical	transactions,	Entergy	Louisiana	sold	and	leased	back	undivided	interests	in	Waterford 3	for	the	aggregate	sum	of	$353.6	million.		The	leases	expire	in	July	2017.		At	the	end	of	the	lease	terms,	Entergy	Louisiana	has	the	option	to repurchase	the	leased	interests	in	Waterford	3	at	fair	market	value	or	to	renew	the	leases	for	either	fair	market	value	or,	under	certain	conditions,	a fixed	rate.		In	the	event	that	Entergy	Louisiana	does	not	renew	or	purchase	the	interests,	Entergy	Louisiana	would	surrender	such	interests	and their	associated	entitlement	of	Waterford	3's	capacity	and	energy.

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	leases.

Upon	the	occurrence	of	certain	events,	Entergy	Louisiana	may	be	obligated	to	assume	the	outstanding	bonds	used	to	finance	the	purchase of	the	interests	in	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	membership interests)	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,	2013,	Entergy	Louisiana	was	in	compliance	with	these	provisions.

As	 of	December	31,	2013,	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:

| 2014 | $31,036 |
| :--- | :--- |
| 2015 | 28,827 |
| 2016 | 16,938 |
| 2017 | 106,335 |
| 2018 | — |
| Years\tthereafter | — |
| Total | 183,136 |
| Less:\tAmount\trepresenting\tinterest | 34,420 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $148,716 |

# Grand	Gulf	Lease	Obligations

In	1988,	in	two	separate	but	substantially	identical	transactions,	System	Energy	sold	and	leased	back	undivided	ownership	interests	in Grand	Gulf	for	the	aggregate	sum	of	$500	million.		The	initial	term	of	the	leases	expire	in	July	2015.		In	December	2013,	System	Energy exercised	its	options	to	renew	the	leases	for	fair	market	value	with	a	renewal	term	for	one	lease	expiring	in	July	2018	and	the	renewal	term	of	the other	lease	expiring	in	July	2036.	At	the	end	of	the	lease	renewal	terms,	System	Energy	has	the	option	to	repurchase	the	leased	interests	in	Grand Gulf	or	renew	the	leases	at	fair	market	value.		In	the	event	that	System	Energy	does	not	renew	or	purchase	the	interests,	System	Energy	would surrender	such	interests	and	their	associated	entitlement	of	Grand	Gulf's	capacity	and	energy.

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	initially	recorded	as	a	net	regulatory	asset	the	difference	between	the	recovery of	the	lease	payments	and	the	amounts	expensed	for	interest	and	depreciation	and	continues	to	record	this	difference	as	a	regulatory	asset	or liability	on	an	ongoing	basis,	resulting	in	a	zero	net	balance	for	the	regulatory	asset	at	the	end	of	the	lease	term.		The	amount	was	a	net	regulatory liability	of	$61.6	million	and	$27.8	million	as	of	December	31,	2013	and	2012,	respectively.

As	of	December	31,	2013,	System	Energy	had	future	minimum	lease	payments	(reflecting	an	implicit	rate	of	5.13%),	which	are	recorded as	long-term	debt,	as	follows:

| 2014 | $51,637 |
| :--- | :--- |
| 2015 | 52,253 |
| 2016 | 13,750 |
| 2017 | 13,750 |
| 2018 | 13,750 |
| Years\tthereafter | 247,500 |
| Total | 392,640 |
| Less:\tAmount\trepresenting\tinterest | 295,226 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $97,414 |

# NOTE 11. 	 RETIREMENT,	 OTHER	 POSTRETIREMENT	 BENEFITS,	 AND	 DEFINED	 CONTRIBUTION	 PLANS (Entergy Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy

# Texas,	and	System	Energy)

# Qualified	Pension	Plans

Entergy	 has	seven	 qualified	 pension	 plans	 covering	 substantially	 all	 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."	 	 The	 Registrant	 Subsidiaries	 participate	 in	 two	 of	 these	 plans:	 "Entergy	 Corporation	 Retirement	 Plan	 for	 Non-Bargaining Employees"	and	"Entergy	Corporation	Retirement	Plan	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.

The	assets	of	the	seven	qualified	pension	plans	are	held	in	a	master	trust	established	by	Entergy.		Each	pension	plan	has	an	undivided beneficial	interest	in	each	of	the	investment	accounts	of	the	master	trust	that	is	maintained	by	a	trustee.		Use	of	the	master	trust	permits	the commingling	of	the	trust	assets	of	the	pension	plans	of	Entergy	Corporation	and	its	Registrant	Subsidiaries	for	investment	and	administrative purposes.		Although	assets	are	commingled	in	the	master	trust,	the	trustee	maintains	supporting	records	for	the	purpose	of	allocating	the	equity	in net	earnings	(loss)	and	the	administrative	expenses	of	the	investment	accounts	to	the	various	participating	pension	plans.		The	fair	value	of	the trust	assets	is	determined	by	the	trustee	and	certain	investment	managers.		The	trustee	calculates	a	daily	earnings	factor,	including	realized	and unrealized	gains	or	losses,	collected	and	accrued	income,	and	administrative	expenses,	and	allocates	earnings	to	each	plan	in	the	master	trust	on	a pro	rata	basis.

Further,	within	each	pension	plan,	the	record	of	each	Registrant	Subsidiary's	beneficial	interest	in	the	plan	assets	is	maintained	by	the plan's	actuary	and	 is	updated	quarterly.	 	Assets	for	each	Registrant	Subsidiary	are	 increased	for	 investment	 income	and	contributions,	and decreased	for	benefit	payments.		A	plan's	investment	net	income/(loss)	(i.e.	interest	and	dividends,	realized	gains	and	losses	and	expenses)	is allocated	to	the	Registrant	Subsidiaries	participating	in	that	plan	based	on	the	value	of	assets	for	each	Registrant	Subsidiary	at	the	beginning	of	the quarter	adjusted	for	contributions	and	benefit	payments	made	during	the	quarter.

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.		The	Registrant	Subsidiaries' pension	costs	are	recovered	from	customers	as	a	component	of	cost	of	service	in	each	of	their	respective	jurisdictions.

# Components of	 Qualified	 Net	 Pension	 Cost and	 Other	 Amounts	 Recognized as a	 Regulatory	 Asset and/or	 Accumulated	 Other Comprehensive	Income	(AOCI)

Entergy	Corporation	and	its	subsidiaries'	total	2013,	2012,	and	2011	qualified	pension	costs	and	amounts	recognized	as	a	regulatory	asset and/or	other	comprehensive	income,	including	amounts	capitalized,	included	the	following	components:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Net\tperiodic\tpension\tcost: |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $172,280 | $150,763 | $121,961 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 263,296 | 260,929 | 236,992 |
| Expected\treturn\ton\tassets | (328,227) | (317,423) | (301,276) |
| Amortization\tof\tprior\tservice\tcost | 2,125 | 2,733 | 3,350 |
| Recognized\tnet\tloss | 213,194 | 167,279 | 92,977 |
| Curtailment\tloss | 16,318 | — | — |
| Special\ttermination\tbenefit | 13,139 | — | — |
| Net\tperiodic\tpension\tcosts | $352,125 | $264,281 | $154,004 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit |  |  |  |
| obligations\trecognized\tas\ta\tregulatory |  |  |  |
| asset\tand/or\tAOCI\t(before\ttax) |  |  |  |
| Arising\tthis\tperiod: |  |  |  |
| Net\t(gain)/loss | ($894,150) | $552,303 | $1,045,624 |
| Amounts\treclassified\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\tperiodic\tpension\ncost\tin\tthe\tcurrent\tyear: |  |  |  |
| Amortization\tof\tprior\tservice\tcost | (2,125) | (2,733) | (3,350) |
| Acceleration\tof\tprior\tservice\tcost\tto\tcurtailment | (1,307) | — | — |
| Amortization\tof\tnet\tloss | (213,194) | (167,279) | (92,977) |
| Total | (1,110,776) | 382,291 | 949,297 |
| Total\trecognized\tas\tnet\tperiodic\tpension\t(income)/cost,\tregulatory\tasset,\nand/or\tAOCI\t(before\ttax) | ($758,651) | $646,572 | $1,103,301 |
| Estimated\tamortization\tamounts\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\nperiodic\tcost\tin\tthe\tfollowing\tyear: |  |  |  |
| Prior\tservice\tcost | $1,600 | $2,268 | $2,733 |
| Net\tloss | $146,958 | $219,805 | $169,064 |

The	Registrant	Subsidiaries'	total	2013,	2012,	and	2011	qualified	pension	costs	and	amounts	recognized	as	a	regulatory	asset	and/or	other comprehensive	income,	including	amounts	capitalized,	for	their	employees	included	the	following	components:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>	Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\nduring\tthe\tperiod | $25,229 | $14,258 | $17,044 | $7,295 | $3,264 | $6,475 | $7,242 |
| Interest\tcost\ton\tprojected\nbenefit\tobligation | 54,473 | 26,741 | 34,857 | 15,802 | 7,462 | 16,303 | 12,170 |
| Expected\treturn\ton\tassets | (66,951) | (34,982) | (41,948) | (21,139) | (9,117) | (22,277) | (17,249) |
| Amortization\tof\tprior\tservice\tcost | 23 | 9 | 83 | 10 | 2 | 6 | 9 |
| Recognized\tnet\tloss | 49,517 | 23,374 | 34,107 | 13,189 | 7,878 | 13,302 | 9,560 |
| Curtailment\tloss | 4,938 | 805 | 3,542 | 767 | 343 | 1,559 | — |
| Special\ttermination\tbenefit | 1,784 | 808 | 1,631 | 359 | 581 | 855 | 1,970 |
| Net\tpension\tcost | $69,013 | $31,013 | $49,316 | $16,283 | $10,413 | $16,223 | $13,702 |
| Other\tchanges\tin\tplan\tassets |  |  |  |  |  |  |  |
| and\tbenefit\tobligations |  |  |  |  |  |  |  |
| recognized\tas\ta\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before |  |  |  |  |  |  |  |
| tax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Net\tgain | ($177,105) | ($98,610) | ($123,234) | ($52,525) | ($25,419) | ($55,772) | ($35,511) |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI\tto |  |  |  |  |  |  |  |
| net\tperiodic\tpension\tcost\tin\tthe |  |  |  |  |  |  |  |
| current\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\ncost | (23) | (9) | (83) | (10) | (2) | (6) | (9) |
| Amortization\tof\tnet\tloss | (49,517) | (23,374) | (34,107) | (13,189) | (7,878) | (13,302) | (9,560) |
| Total | ($226,645) | ($121,993) | ($157,424) | ($65,724) | ($33,299) | ($69,080) | ($45,080) |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tpension\tincome |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) | ($157,632) | ($90,980) | ($108,108) | ($49,441) | ($22,886) | ($52,857) | ($31,378) |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing |  |  |  |  |  |  |  |
| year |  |  |  |  |  |  |  |
| Prior\tservice\tcost | $— | $— | $— | $— | $— | $— | $2 |
| Net\tloss | $35,984 | $15,935 | $24,360 | $9,421 | $5,802 | $9,363 | $9,510 |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\nperiod | $22,169 | $12,273 | $14,675 | $6,410 | $2,824 | $5,684 | $5,920 |
| Interest\tcost\ton\tprojected\nbenefit\tobligation | 55,686 | 25,679 | 35,201 | 16,279 | 7,608 | 16,823 | 12,987 |
| Expected\treturn\ton\tassets | (65,763) | (34,370) | (40,836) | (20,945) | (8,860) | (22,325) | (16,436) |
| Amortization\tof\tprior\tservice\tcost | 200 | 19 | 208 | 30 | 7 | 15 | 13 |
| Recognized\tnet\tloss | 40,772 | 16,173 | 28,197 | 10,532 | 6,878 | 10,179 | 9,001 |
| Net\tpension\tcost | $53,064 | $19,774 | $37,445 | $12,306 | $8,457 | $10,376 | $11,485 |
| Other\tchanges\tin\tplan\tassets\tand |  |  |  |  |  |  |  |
| benefit\tobligations\trecognized\tas\ta |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Net\tloss | $105,133 | $77,207 | $76,163 | $27,106 | $14,282 | $28,745 | $10,266 |
| Amounts\treclassified\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet\tperiodic |  |  |  |  |  |  |  |
| pension\tcost\tin\tthe\tcurrent\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | (200) | (19) | (208) | (30) | (7) | (15) | (13) |
| Amortization\tof\tnet\tloss | (40,772) | (16,173) | (28,197) | (10,532) | (6,878) | (10,179) | (9,001) |
| Total | $64,161 | $61,015 | $47,758 | $16,544 | $7,397 | $18,551 | $1,252 |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tpension\tcost, |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) | $117,225 | $80,789 | $85,203 | $28,850 | $15,854 | $28,927 | $12,737 |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing\tyear |  |  |  |  |  |  |  |
| Prior\tservice\tcost | $23 | $9 | $83 | $10 | $2 | $6 | $10 |
| Net\tloss | $50,175 | $23,731 | $34,906 | $13,375 | $8,046 | $13,494 | $9,717 |

| 2011 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\nthe\tperiod | $18,072 | $9,848 | $11,543 | $5,308 | $2,242 | $4,788 | $4,941 |
| Interest\tcost\ton\tprojected\nbenefit\tobligation | 51,965 | 23,713 | 32,636 | 15,637 | 7,050 | 15,971 | 11,758 |
| Expected\treturn\ton\tassets | (62,434) | (33,358) | (38,866) | (20,152) | (8,455) | (22,005) | (15,138) |
| Amortization\tof\tprior\tservice\tcost | 459 | 79 | 280 | 152 | 35 | 65 | 16 |
| Recognized\tnet\tloss | 25,681 | 9,118 | 17,990 | 6,717 | 4,666 | 5,579 | 5,284 |
| Net\tpension\tcost | $33,743 | $9,400 | $23,583 | $7,662 | $5,538 | $4,398 | $6,861 |
| Other\tchanges\tin\tplan\tassets\tand |  |  |  |  |  |  |  |
| benefit\tobligations\trecognized\tas\ta |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Net\tloss | $217,989 | $102,329 | $137,100 | $56,714 | $29,297 | $64,662 | $52,876 |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI\tto |  |  |  |  |  |  |  |
| net\tperiodic\tpension\tcost\tin\tthe |  |  |  |  |  |  |  |
| current\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | (459) | (79) | (280) | (152) | (35) | (65) | (16) |
| Amortization\tof\tnet\tloss | (25,681) | (9,118) | (17,990) | (6,717) | (4,666) | (5,579) | (5,284) |
| Total | $191,849 | $93,132 | $118,830 | $49,845 | $24,596 | $59,018 | $47,576 |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tpension\tcost, |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) | $225,592 | $102,532 | $142,413 | $57,507 | $30,134 | $63,416 | $54,437 |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing\tyear |  |  |  |  |  |  |  |
| Prior\tservice\tcost | $200 | $19 | $208 | $30 | $7 | $15 | $13 |
| Net\tloss | $41,309 | $16,295 | $28,486 | $10,667 | $6,935 | $10,261 | $9,135 |

# Qualified	Pension	Obligations,	Plan	Assets,	Funded	Status,	Amounts	Recognized	in	the	Balance	Sheet	for	Entergy	Corporation	and	its Subsidiaries	as	of	December	31,	2013	and	2012

| Balance	at	beginning	of	year | $6,096,639 | $5,187,635 |
| :--- | :--- | :--- |
| Service\tcost | 172,280 | 150,763 |
| Interest\tcost | 263,296 | 260,929 |
| Curtailment | 15,011 | — |
| Special\ttermination\tbenefit | 13,139 | — |
| Actuarial\t(gain)/loss | (571,990) | 693,017 |
| Employee\tcontributions | 598 | 789 |
| Benefits\tpaid | (217,974) | (196,494) |
| Balance\tat\tend\tof\tyear | $5,770,999 | $6,096,639 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\tof\tyear | $3,832,860 | $3,399,916 |
| Actual\treturn\ton\tplan\tassets | 650,386 | 458,137 |
| Employer\tcontributions | 163,367 | 170,512 |
| Employee\tcontributions | 598 | 789 |
| Benefits\tpaid | (217,974) | (196,494) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $4,429,237 | $3,832,860 |
| Funded\tstatus | ($1,341,762) | ($2,263,779) |
| Amount\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Non-current\tliabilities | ($1,341,762) | ($2,263,779) |
| Amount\trecognized\tas\ta\tregulatory\tasset |  |  |
| Prior\tservice\tcost | $5,027 | $308 |
| Net\tloss | 1,494,117 | 2,352,234 |
|  | $1,499,144 | $2,352,542 |
| Amount\trecognized\tas\tAOCI\t(before\ttax) |  |  |
| Prior\tservice\tcost | $1,292 | $9,444 |
| Net\tloss | 383,920 | 633,146 |
|  | $385,212 | $642,590 |

# Qualified	Pension	Obligations,	Plan	Assets,	Funded	Status,	and	Amounts	Recognized	in	the	Balance	Sheet	for	the	Registrant	Subsidiaries as	of	December	31,	2013	and	2012

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tProjected\tBenefit\nObligation\t(PBO) |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $1,274,886 | $623,068 | $817,745 | $369,852 | $174,585 | $382,176 | $282,841 |
| Service\tcost | 25,229 | 14,258 | 17,044 | 7,295 | 3,264 | 6,475 | 7,242 |
| Interest\tcost | 54,473 | 26,741 | 34,857 | 15,802 | 7,462 | 16,303 | 12,170 |
| Curtailment | 4,938 | 805 | 3,542 | 767 | 343 | 1,559 | — |
| Special\ttermination\tbenefit | 1,784 | 808 | 1,631 | 359 | 581 | 855 | 1,970 |
| Actuarial\tgain | (110,943) | (64,119) | (80,794) | (31,684) | (16,276) | (33,792) | (23,882) |
| Benefits\tpaid | (57,727) | (21,699) | (32,675) | (16,567) | (6,252) | (17,496) | (9,552) |
| Balance\tat\tend\tof\tyear | $1,192,640 | $579,862 | $761,350 | $345,824 | $163,707 | $356,080 | $270,789 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\tof\nyear | $785,527 | $409,971 | $489,027 | $248,272 | $106,778 | $262,110 | $168,697 |
| Actual\treturn\ton\tplan\tassets | 133,113 | 69,473 | 84,388 | 41,980 | 18,259 | 44,257 | 28,878 |
| Employer\tcontributions | 35,382 | 11,550 | 21,152 | 8,152 | 4,175 | 6,880 | 8,305 |
| Benefits\tpaid | (57,727) | (21,699) | (32,675) | (16,567) | (6,252) | (17,496) | (9,552) |
| Fair\tvalue\tof\tassets\tat\tend\tof\nyear | $896,295 | $469,295 | $561,892 | $281,837 | $122,960 | $295,751 | $196,328 |
| Funded\tstatus | ($296,345) | ($110,567) | ($199,458) | ($63,987) | ($40,747) | ($60,329) | ($74,461) |
| Amounts\trecognized\tin\tthe\n\tbalance\tsheet\t(funded\tstatus) |  |  |  |  |  |  |  |
| Non-current\tliabilities | ($296,345) | ($110,567) | ($199,458) | ($63,987) | ($40,747) | ($60,329) | ($74,461) |
| Amounts\trecognized\tas\n\tregulatory\tasset |  |  |  |  |  |  |  |
| Prior\tservice\tcredit | $— | $— | ($1) | $— | $— | $— | ($4) |
| Net\tloss | 457,485 | 178,990 | 299,740 | 120,290 | 69,856 | 120,619 | 121,327 |
|  | $457,485 | $178,990 | $299,739 | $120,290 | $69,856 | $120,619 | $121,323 |
| Amounts\trecognized\tas\tAOCI\n(before\ttax) |  |  |  |  |  |  |  |
| Net\tloss | — | 25,437 | — | — | — | — | — |
|  | $— | $25,437 | $— | $— | $— | $— | $— |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tProjected\tBenefit\nObligation\t(PBO) |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $1,116,572 | $512,432 | $704,748 | $326,377 | $151,966 | $337,669 | $258,268 |
| Service\tcost | 22,169 | 12,273 | 14,675 | 6,410 | 2,824 | 5,684 | 5,920 |
| Interest\tcost | 55,686 | 25,679 | 35,201 | 16,279 | 7,608 | 16,823 | 12,987 |
| Actuarial\tloss | 134,691 | 92,275 | 93,817 | 36,329 | 18,000 | 38,328 | 13,691 |
| Benefits\tpaid | (54,232) | (19,591) | (30,696) | (15,543) | (5,813) | (16,328) | (8,025) |
| Balance\tat\tend\tof\tyear | $1,274,886 | $623,068 | $817,745 | $369,852 | $174,585 | $382,176 | $282,841 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\nof\tyear | $707,275 | $366,555 | $432,418 | $223,981 | $94,202 | $237,438 | $147,091 |
| Actual\treturn\ton\tplan\tassets | 95,321 | 49,438 | 58,489 | 30,169 | 12,578 | 31,909 | 19,860 |
| Employer\tcontributions | 37,163 | 13,569 | 28,816 | 9,665 | 5,811 | 9,091 | 9,771 |
| Benefits\tpaid | (54,232) | (19,591) | (30,696) | (15,543) | (5,813) | (16,328) | (8,025) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $785,527 | $409,971 | $489,027 | $248,272 | $106,778 | $262,110 | $168,697 |
| Funded\tstatus | ($489,359) | ($213,097) | ($328,718) | ($121,580) | ($67,807) | ($120,066) | ($114,144) |
| Amounts\trecognized\tin\tthe\n\tbalance\tsheet\t(funded\tstatus) |  |  |  |  |  |  |  |
| Non-current\tliabilities | ($489,359) | ($213,097) | ($328,718) | ($121,580) | ($67,807) | ($120,066) | ($114,144) |
| Amounts\trecognized\tas\n\tregulatory\tasset |  |  |  |  |  |  |  |
| Prior\tservice\tcost | $23 | $8 | $83 | $10 | $2 | $7 | $6 |
| Net\tloss | 683,790 | 283,847 | 456,800 | 185,903 | 103,072 | 189,589 | 166,276 |
|  | $683,813 | $283,855 | $456,883 | $185,913 | $103,074 | $189,596 | $166,282 |
| Amounts\trecognized\tas\tAOCI\n\t(before\ttax) |  |  |  |  |  |  |  |
| Prior\tservice\tcost | $— | $1 | $— | $— | $— | $— | $— |
| Net\tloss | — | 42,414 | — | — | — | — | — |
|  | $— | $42,415 | $— | $— | $— | $— | $— |

# Other	Postretirement	Benefits

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

Effective	January	1,	1993,	Entergy	adopted	an	accounting	standard	requiring	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	the	former Entergy	Gulf	States)	and	$128	million	for	the	former	Entergy	Gulf	States	(now	split	into	Entergy	Gulf	States	Louisiana	and	Entergy	Texas).		Such obligations	were	being	amortized	over	a	20-year	period	that	began	in	1993	and	ended	in	2012.		For	the	most	part,	the	Registrant	Subsidiaries

recover	accrued	other	postretirement	benefit	costs	from	customers	and	are	required	to	contribute	the	other	postretirement	benefits	collected	in rates	to	an	external	trust.

Entergy	Arkansas,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	have	received	regulatory	approval	to	recover	accrued other	postretirement	benefit	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	other	postretirement	benefit	costs	and	cash	expenditures	for other	postretirement	benefits	incurred	from	1993	through	1997)	over	a	15-year	period	that	began	in	January	1998	and	ended	in	December	2012.

The	LPSC	ordered	Entergy	Gulf	States	Louisiana	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	other	postretirement	benefits	to	determine	if	special	exceptions	to	this	order	are	warranted.

Pursuant	to	regulatory	directives,	Entergy	Arkansas,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy contribute	the	other	postretirement	benefit	costs	collected	in	rates	into	external	trusts.		System	Energy	is	funding,	on	behalf	of	Entergy	Operations, other	postretirement	benefits	associated	with	Grand	Gulf.

Trust	 assets	 contributed	 by	 participating	 Registrant	 Subsidiaries	 are	 in	 bank-administered	 master	 trusts,	 established	 by	 Entergy Corporation	and	maintained	by	a	trustee.		Each	participating	Registrant	Subsidiary	holds	a	beneficial	interest	in	the	trusts'	assets.		The	assets	in	the master	trusts	are	commingled	for	investment	and	administrative	purposes.		Although	assets	are	commingled,	supporting	records	are	maintained	for the	purpose	of	allocating	the	beneficial	interest	in	net	earnings/(losses)	and	the	administrative	expenses	of	the	investment	accounts	to	the	various participating	plans	and	participating	Registrant	Subsidiaries.	Beneficial	interest	in	an	investment	account's	net	income/(loss)	is	comprised	of interest	and	dividends,	realized	and	unrealized	gains	and	losses,	and	expenses.		Beneficial	interest	from	these	investments	is	allocated	to	the	plans and	participating	Registrant	Subsidiary	based	on	their	portion	of	net	assets	in	the	pooled	accounts.

# Other	postretirement	benefit	changes

In	December	2013,	Entergy	announced	changes	to	its	other	postretirement	benefits	which	include,	among	other	things,	elimination	of other	postretirement	benefits	for	employees	hired	or	rehired	after	June	30,	2014	and	setting	a	dollar	limit	cap	on	Entergy's	contribution	to	retiree medical	costs,	effective	2019	for	those	employees	who	commence	their	Entergy	retirement	benefits	on	or	after	January	1,	2015.	In	accordance with	accounting	standards,	certain	of	the	other	postretirement	benefit	changes	have	been	reflected	in	the	December	31,	2013	other	postretirement obligation.	The	changes	affecting	active	bargaining	unit	employees	will	be	negotiated	with	the	unions	prior	to	implementation,	where	necessary, and	to	the	extent	required	by	law.

# Components	of	Net	Other	Postretirement	Benefit	Cost	and	Other	Amounts	Recognized	as	a	Regulatory	Asset	and/or	AOCI

Entergy	Corporation's	and	its	subsidiaries'	total	 2013,	2012,	and	2011	other	postretirement	benefit	costs,	including	amounts	capitalized and	amounts	recognized	as	a	regulatory	asset	and/or	other	comprehensive	income,	included	the	following	components:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Other\tpost\tretirement\tcosts: |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $74,654 | $68,883 | $59,340 |
| Interest\tcost\ton\tAPBO | 79,453 | 82,561 | 74,522 |
| Expected\treturn\ton\tassets | (40,323) | (34,503) | (29,477) |
| Amortization\tof\ttransition\tobligation | — | 3,177 | 3,183 |
| Amortization\tof\tprior\tservice\tcredit | (14,904) | (18,163) | (14,070) |
| Recognized\tnet\tloss | 44,178 | 36,448 | 21,192 |
| Curtailment\tloss | 12,729 | — | — |
| Net\tother\tpostretirement\tbenefit\tcost | $155,787 | $138,403 | $114,690 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit |  |  |  |
| \tobligations\trecognized\tas\ta\tregulatory\tasset |  |  |  |
| \tand\t/or\tAOCI\t(before\ttax) |  |  |  |
| Arising\tthis\tperiod: |  |  |  |
| Prior\tservice\tcredit\tfor\tperiod | ($116,571) | $— | ($29,507) |
| Net\t(gain)/loss | (405,976) | 92,584 | 236,594 |
| Amounts\treclassified\tfrom\tregulatory\tasset\tand\t/or\tAOCI\tto\tnet\tperiodic\tbenefit\tcost\tin\nthe\tcurrent\tyear: |  |  |  |
| Amortization\tof\ttransition\tobligation | — | (3,177) | (3,183) |
| Amortization\tof\tprior\tservice\tcredit | 14,904 | 18,163 | 14,070 |
| Acceleration\tof\tprior\tservice\tcredit\tdue\tto\tcurtailment | 1,989 | — | — |
| Amortization\tof\tnet\tloss | (44,178) | (36,448) | (21,192) |
| Total | ($549,832) | $71,122 | $196,782 |
| Total\trecognized\tas\tnet\tperiodic\tbenefit\tcost,\n\tregulatory\tasset,\tand/or\tAOCI\t(before\ttax) | ($394,045) | $209,525 | $311,472 |
| Estimated\tamortization\tamounts\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\nperiodic\t\tbenefit\tcost\t\tin\tthe\tfollowing\tyear |  |  |  |
| Transition\tobligation | $— | $— | $3,177 |
| Prior\tservice\tcredit | ($31,589) | ($13,336) | ($18,163) |
| Net\tloss | $11,197 | $45,217 | $43,127 |

Total	2013,	2012,	and	2011	other	postretirement	benefit	costs	of	the	Registrant	Subsidiaries,	including	amounts	capitalized	and	deferred, for	their	employees	included	the	following	components:

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |  |
| during\tthe\tperiod | $9,619 | $7,910 | $8,541 | $3,246 | $1,752 | $3,760 | $3,580 |
| Interest\tcost\ton\tAPBO | 13,545 | 8,964 | 9,410 | 4,289 | 3,135 | 6,076 | 2,945 |
| Expected\treturn\ton\tassets | (16,843) | — | — | (5,335) | (4,101) | (9,391) | (3,350) |
| Amortization\tof\tprior\tcredit | (689) | (942) | (508) | (204) | (24) | (501) | (126) |
| Recognized\tnet\tloss | 7,976 | 4,598 | 5,050 | 2,534 | 1,509 | 3,744 | 1,896 |
| Curtailment\tloss | 4,517 | 1,546 | 1,848 | 596 | 354 | 1,436 | 760 |
| Net\tother\tpostretirement\tbenefit\ncost | $18,125 | $22,076 | $24,341 | $5,126 | $2,625 | $5,124 | $5,705 |
| Other\tchanges\tin\tplan\tassets |  |  |  |  |  |  |  |
| and\tbenefit\tobligations |  |  |  |  |  |  |  |
| recognized\tas\ta\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before |  |  |  |  |  |  |  |
| tax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Prior\tservice\tcredit\tfor\tthe\nperiod | ($11,617) | ($8,705) | ($18,844) | ($4,714) | ($4,469) | ($5,359) | ($4,591) |
| Net\tloss | ($81,236) | ($40,938) | ($43,743) | ($30,018) | ($18,508) | ($34,562) | ($17,579) |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\ncredit | 689 | 942 | 508 | 204 | 24 | 501 | 126 |
| Acceleration\tof\tprior |  |  |  |  |  |  |  |
| service\tcredit/(cost) |  |  |  |  |  |  |  |
| due\tto\tcurtailment | 78 | 91 | 41 | 20 | (4) | 62 | 9 |
| Amortization\tof\tnet\tloss | (7,976) | (4,598) | (5,050) | (2,534) | (1,509) | (3,744) | (1,896) |
| Total | ($100,062) | ($53,208) | ($67,088) | ($37,042) | ($24,466) | ($43,102) | ($23,931) |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |  |
| postretirement\tcost, |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or |  |  |  |  |  |  |  |
| AOCI\t(before\ttax) | ($81,937) | ($31,132) | ($42,747) | ($31,916) | ($21,841) | ($37,978) | ($18,226) |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($2,441) | ($2,236) | ($3,376) | ($918) | ($709) | ($1,301) | ($824) |
| Net\tloss | $1,267 | $1,212 | $1,511 | $149 | $56 | $800 | $464 |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |  |
| during\tthe\tperiod | $9,089 | $7,521 | $7,796 | $3,093 | $1,689 | $3,651 | $3,293 |
| Interest\tcost\ton\tAPBO | 14,452 | 9,590 | 9,781 | 4,716 | 3,422 | 6,650 | 3,028 |
| Expected\treturn\ton\tassets | (14,029) | — | — | (4,521) | (3,711) | (8,415) | (2,601) |
| Amortization\tof\ttransition\nobligation | 820 | 238 | 382 | 351 | 1,189 | 187 | 8 |
| Amortization\tof\tprior\ncost/(credit) | (530) | (824) | (247) | (139) | 38 | (428) | (63) |
| Recognized\tnet\tloss | 8,305 | 4,737 | 4,359 | 2,920 | 1,559 | 4,320 | 1,970 |
| Net\tother\tpostretirement\tbenefit\ncost | $18,107 | $21,262 | $22,071 | $6,420 | $4,186 | $5,965 | $5,635 |
| Other\tchanges\tin\tplan\tassets |  |  |  |  |  |  |  |
| and\tbenefit\tobligations |  |  |  |  |  |  |  |
| recognized\tas\ta\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before |  |  |  |  |  |  |  |
| tax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Net\tloss | $9,066 | $5,818 | $16,215 | $271 | $2,260 | $191 | $2,043 |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\ttransition\nobligation | (820) | (238) | (382) | (351) | (1,189) | (187) | (8) |
| Amortization\tof\tprior\tservice\n(cost)/credit | 530 | 824 | 247 | 139 | (38) | 428 | 63 |
| Amortization\tof\tnet\nloss | (8,305) | (4,737) | (4,359) | (2,920) | (1,559) | (4,320) | (1,970) |
| Total | $471 | $1,667 | $11,721 | ($2,861) | ($526) | ($3,888) | $128 |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |  |
| postretirement\tcost, |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or |  |  |  |  |  |  |  |
| AOCI\t(before\ttax) | $18,578 | $22,929 | $33,792 | $3,559 | $3,660 | $2,077 | $5,763 |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |  |
| Prior\tservice\tcost/(credit) | ($530) | ($824) | ($247) | ($139) | $38 | ($428) | ($62) |
| Net\tloss | $8,163 | $4,693 | $5,149 | $2,650 | $1,587 | $3,905 | $1,915 |

| 2011 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned |  |  |  |  |  |  |  |
| during\tthe\tperiod | $8,053 | $6,158 | $6,540 | $2,632 | $1,448 | $3,074 | $2,642 |
| Interest\tcost\ton\tAPBO | 13,742 | 8,298 | 8,767 | 4,370 | 3,225 | 5,945 | 2,666 |
| Expected\treturn\ton\tassets | (11,528) | — | — | (3,906) | (3,200) | (7,496) | (2,115) |
| Amortization\tof\ttransition\nobligation | 821 | 239 | 383 | 352 | 1,190 | 187 | 9 |
| Amortization\tof\tprior\tservice\ncost/(credit) | (530) | (824) | (247) | (139) | 38 | (428) | (589) |
| Recognized\tnet\tloss | 6,436 | 2,896 | 2,793 | 2,160 | 968 | 2,803 | 1,477 |
| Net\tother\tpostretirement\tbenefit\ncost | $16,994 | $16,767 | $18,236 | $5,469 | $3,669 | $4,085 | $4,090 |
| Other\tchanges\tin\tplan\tassets |  |  |  |  |  |  |  |
| and\tbenefit\tobligations |  |  |  |  |  |  |  |
| recognized\tas\ta\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before |  |  |  |  |  |  |  |
| tax) |  |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |  |
| Net\t(gain)/loss | $32,241 | $28,721 | $24,837 | $12,598 | $8,946 | $23,125 | $8,499 |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |  |
| Amortization\tof\ttransition\nobligation | (821) | (239) | (383) | (352) | (1,190) | (187) | (9) |
| Amortization\tof\tprior\tservice |  |  |  |  |  |  |  |
| (cost)/credit | 530 | 824 | 247 | 139 | (38) | 428 | 589 |
| Amortization\tof\tnet\tloss | (6,436) | (2,896) | (2,793) | (2,160) | (968) | (2,803) | (1,477) |
| Total | $25,514 | $26,410 | $21,908 | $10,225 | $6,750 | $20,563 | $7,602 |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |  |
| postretirement\tcost, |  |  |  |  |  |  |  |
| regulatory\tasset,\tand/or |  |  |  |  |  |  |  |
| AOCI\t(before\ttax) | $42,508 | $43,177 | $40,144 | $15,694 | $10,419 | $24,648 | $11,692 |
| Estimated\tamortization |  |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |  |
| Transition\tobligation | $820 | $238 | $382 | $351 | $1,189 | $187 | $8 |
| Prior\tservice\tcost/(credit) | ($530) | ($824) | ($247) | ($139) | $38 | ($428) | ($63) |
| Net\tloss | $8,365 | $4,778 | $4,398 | $2,926 | $1,562 | $4,329 | $1,994 |

# Other	Postretirement	Benefit	Obligations,	Plan	Assets,	Funded	Status,	and	Amounts	Not	Yet	Recognized	and	Recognized	in	the	Balance Sheet	of	Entergy	Corporation	and	its	Subsidiaries	as	of	December	31,	2013	and	2012

| Balance	at	beginning	of	year | $1,846,922 | $1,652,369 |
| :--- | :--- | :--- |
| Service\tcost | 74,654 | 68,883 |
| Interest\tcost | 79,453 | 82,561 |
| Plan\tamendments | (116,571) | — |
| Curtailment | 14,718 | — |
| Plan\tparticipant\tcontributions | 19,141 | 18,102 |
| Actuarial\t(gain)/loss | (370,004) | 102,833 |
| Benefits\tpaid | (89,713) | (83,825) |
| Medicare\tPart\tD\tsubsidy\treceived | 3,310 | 5,999 |
| Balance\tat\tend\tof\tyear | $1,461,910 | $1,846,922 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\tof\tyear | $488,448 | $427,172 |
| Actual\treturn\ton\tplan\tassets | 76,314 | 44,752 |
| Employer\tcontributions | 75,660 | 82,247 |
| Plan\tparticipant\tcontributions | 19,141 | 18,102 |
| Benefits\tpaid | (89,713) | (83,825) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $569,850 | $488,448 |
| Funded\tstatus | ($892,060) | ($1,358,474) |
| Amounts\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Current\tliabilities | ($40,602) | ($33,813) |
| Non-current\tliabilities | (851,458) | (1,324,661) |
| Total\tfunded\tstatus | ($892,060) | ($1,358,474) |
| Amounts\trecognized\tas\ta\tregulatory\tasset |  |  |
| Prior\tservice\tcredit | (93,332) | (5,307) |
| Net\tloss | 165,270 | 367,519 |
|  | $71,938 | $362,212 |
| Amounts\trecognized\tas\tAOCI\t(before\ttax) |  |  |
| Prior\tservice\tcredit | (60,988) | (49,335) |
| Net\tloss | 107,996 | 355,900 |
|  | $47,008 | $306,565 |

# Other	Postretirement	Benefit	Obligations,	Plan	Assets,	Funded	Status,	and	Amounts	Not	Yet	Recognized	and	Recognized	in	the	Balance Sheets	of	the	Registrant	Subsidiaries	as	of	December	31,	2013	and	2012

| 2013 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $315,308 | $207,987 | $220,017 | $100,508 | $74,200 | $142,114 | $67,934 |
| Service\tcost | 9,619 | 7,910 | 8,541 | 3,246 | 1,752 | 3,760 | 3,580 |
| Interest\tcost | 13,545 | 8,964 | 9,410 | 4,289 | 3,135 | 6,076 | 2,945 |
| Plan\tamendments | (11,617) | (8,705) | (18,844) | (4,714) | (4,469) | (5,359) | (4,591) |
| Curtailment | 4,595 | 1,637 | 1,889 | 616 | 350 | 1,498 | 769 |
| Plan\tparticipant\tcontributions | 4,564 | 1,998 | 2,509 | 1,292 | 915 | 1,498 | 860 |
| Actuarial\tgain | (67,253) | (40,941) | (43,747) | (25,527) | (13,739) | (26,048) | (14,639) |
| Benefits\tpaid | (18,764) | (8,958) | (11,524) | (5,416) | (4,464) | (8,455) | (3,912) |
| Medicare\tPart\tD\tsubsidy |  |  |  |  |  |  |  |
| received | 737 | 410 | 513 | 245 | 194 | 334 | 105 |
| Balance\tat\tend\tof\tyear | $250,734 | $170,302 | $168,764 | $74,539 | $57,874 | $115,418 | $53,051 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\nof\tyear | $194,018 | $— | $— | $62,951 | $58,651 | $115,824 | $39,474 |
| Actual\treturn\ton\tplan\tassets | 30,830 | — | — | 9,826 | 8,870 | 17,905 | 6,292 |
| Employer\tcontributions | 21,015 | 6,960 | 9,015 | 4,785 | 2,567 | 4,846 | 5,387 |
| Plan\tparticipant\tcontributions | 4,564 | 1,998 | 2,509 | 1,292 | 915 | 1,498 | 860 |
| Benefits\tpaid | (18,764) | (8,958) | (11,524) | (5,416) | (4,464) | (8,455) | (3,912) |
| Fair\tvalue\tof\tassets\tat\tend\tof |  |  |  |  |  |  |  |
| year | $231,663 | $— | $— | $73,438 | $66,539 | $131,618 | $48,101 |
| Funded\tstatus | ($19,071) | ($170,302) | ($168,764) | ($1,101) | $8,665 | $16,200 | ($4,950) |
| Amounts\trecognized\tin\tthe |  |  |  |  |  |  |  |
| balance\tsheet |  |  |  |  |  |  |  |
| Current\tliabilities | $— | ($8,803) | ($10,249) | $— | $— | $— | $— |
| Non-current\tliabilities | (19,071) | (161,499) | (158,515) | (1,101) | 8,665 | 16,200 | (4,950) |
| Total\tfunded\tstatus | ($19,071) | ($170,302) | ($168,764) | ($1,101) | $8,665 | $16,200 | ($4,950) |
| Amounts\trecognized\tin |  |  |  |  |  |  |  |
| regulatory\tasset |  |  |  |  |  |  |  |
| Prior\tservice\tcost/(credit) | ($12,996) | $— | $— | ($5,056) | ($4,335) | ($6,505) | ($4,702) |
| Net\tloss | 40,272 | — | — | 9,304 | 6,485 | 22,772 | 10,297 |
|  | $27,276 | $— | $— | $4,248 | $2,150 | $16,267 | $5,595 |
| Amounts\trecognized\tin\tAOCI\n(before\ttax) |  |  |  |  |  |  |  |
| Prior\tservice\tcredit | $— | ($10,359) | ($19,390) | $— | $— | $— | $— |
| Net\tloss | — | 31,577 | 35,001 | — | — | — | — |
|  | $— | $21,218 | $15,611 | $— | $— | $— | $— |

| 2012 | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $290,613 | $191,877 | $196,352 | $94,570 | $69,316 | $133,602 | $60,526 |
| Service\tcost | 9,089 | 7,521 | 7,796 | 3,093 | 1,689 | 3,651 | 3,293 |
| Interest\tcost | 14,452 | 9,590 | 9,781 | 4,716 | 3,422 | 6,650 | 3,028 |
| Plan\tparticipant\tcontributions | 4,440 | 1,945 | 2,725 | 1,269 | 742 | 1,526 | 820 |
| Actuarial\tloss | 13,256 | 5,818 | 16,215 | 1,625 | 3,240 | 2,645 | 2,861 |
| Benefits\tpaid | (17,873) | (9,543) | (13,760) | (5,199) | (4,605) | (6,604) | (2,764) |
| Medicare\tPart\tD\tsubsidy\treceived | 1,331 | 779 | 908 | 434 | 396 | 644 | 170 |
| Balance\tat\tend\tof\tyear | $315,308 | $207,987 | $220,017 | $100,508 | $74,200 | $142,114 | $67,934 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tbeginning\nof\tyear | $164,846 | $— | $— | $54,452 | $53,418 | $105,181 | $32,012 |
| Actual\treturn\ton\tplan\tassets | 18,219 | — | — | 5,874 | 4,691 | 10,869 | 3,419 |
| Employer\tcontributions | 24,386 | 7,598 | 11,035 | 6,555 | 4,405 | 4,852 | 5,987 |
| Plan\tparticipant\tcontributions | 4,440 | 1,945 | 2,725 | 1,269 | 742 | 1,526 | 820 |
| Benefits\tpaid | (17,873) | (9,543) | (13,760) | (5,199) | (4,605) | (6,604) | (2,764) |
| Fair\tvalue\tof\tassets\tat\tend\tof\tyear | $194,018 | $— | $— | $62,951 | $58,651 | $115,824 | $39,474 |
| Funded\tstatus | ($121,290) | ($207,987) | ($220,017) | ($37,557) | ($15,549) | ($26,290) | ($28,460) |
| Amounts\trecognized\tin\tthe |  |  |  |  |  |  |  |
| balance\tsheet |  |  |  |  |  |  |  |
| Current\tliabilities | $— | ($7,546) | ($9,152) | $— | $— | $— | $— |
| Non-current\tliabilities | (121,290) | (200,441) | (210,865) | (37,557) | (15,549) | (26,290) | (28,460) |
| Total\tfunded\tstatus | ($121,290) | ($207,987) | ($220,017) | ($37,557) | ($15,549) | ($26,290) | ($28,460) |
| Amounts\trecognized\tin |  |  |  |  |  |  |  |
| regulatory\tasset |  |  |  |  |  |  |  |
| Prior\tservice\tcost/(credit) | ($2,146) | $— | $— | ($566) | $114 | ($1,709) | ($246) |
| Net\tloss | 129,484 | — | — | 41,855 | 26,502 | 61,077 | 29,773 |
|  | $127,338 | $— | $— | $41,289 | $26,616 | $59,368 | $29,527 |
| Amounts\trecognized\tin\tAOCI |  |  |  |  |  |  |  |
| (before\ttax) |  |  |  |  |  |  |  |
| Prior\tservice\tcredit | $— | ($2,687) | ($1,095) | $— | $— | $— | $— |
| Net\tloss | — | 77,113 | 83,795 | — | — | — | — |
|  | $— | $74,426 | $82,700 | $— | $— | $— | $— |

# Non-Qualified	Pension	Plans

Entergy	 also	 sponsors	 non-qualified,	 non-contributory	 defined	 benefit	 pension	 plans	 that	 provide	 benefits	 to	 certain	 key employees.		Entergy	recognized	net	periodic	pension	cost	related	to	these	plans	of	$54.5	million	in	2013,	$26.5	million	in	2012,	and	$24.0	million in	2011.		In	2013,	2012,	and	2011	Entergy	recognized	$33.0	million,	$6.3	million,	and	$4.6	million,	respectively	in	settlement	charges	related	to the	payment	of	lump	sum	benefits	out	of	the	plan	that	is	included	in	the	non-qualified	pension	plan	cost	above.		The	projected	benefit	obligation was	$154.3	million	and	$199.3	million	as	of	December	31,	2013	and	2012,	respectively.		The	accumulated	benefit	obligation	was	 $131.4	million and	$180.6	million	as	of	December	31,	2013	and	2012,	respectively.

Entergy's	 non-qualified,	 non-current	 pension	 liability	 at	December	 31,	 2013	 and	2012	 was	$127.5	 million	 and	$137.2	 million, respectively;	and	its	current	liability	was	$26.8	million	and	$62.1	million,	respectively.		The	unamortized	transition	asset,	prior	service	cost	and net	loss	are	recognized	in	regulatory	assets	($59.1	million	at	December	31,	2013	and	$81.2	million	at	December	31,	2012)	and	accumulated	other comprehensive	income	before	taxes	($26.1	million	at	December	31,	2013	and	$32.5	million	at	December	31,	2012).

The	Registrant	Subsidiaries	(except	System	Energy)	participate	in	Entergy's	non-qualified,	non-contributory	defined	benefit	pension	plans that	provide	benefits	to	certain	key	employees.		The	net	periodic	pension	cost	for	their	employees	for	the	non-qualified	plans	for	2013,	2012,	and 2011,	was	as	follows:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2013 | $448 | $151 | $12 | $192 | $92 | $1,001 |
| 2012 | $464 | $158 | $12 | $183 | $79 | $648 |
| 2011 | $498 | $167 | $14 | $190 | $65 | $763 |

Included	in	the	2013	net	periodic	pension	cost	above	are	settlement	charges	of	$415	thousand	for	Entergy	Texas	related	to	the	lump	sum benefits	paid	out	of	the	plan.		Included	in	the	2012	net	periodic	pension	cost	above	are	settlement	charges	of	$38	thousand	for	Entergy	Arkansas related	to	the	lump	sum	benefits	paid	out	of	the	plan.		Included	in	the	2011	net	periodic	pension	cost	above	are	settlement	charges	of	$41	thousand for	Entergy	Arkansas	related	to	the	lump	sum	benefits	paid	out	of	the	plan.

The	projected	benefit	obligation	for	their	employees	for	the	non-qualified	plans	as	of	December	31,	2013	and	2012	was	as	follows:

|  | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2013 | $4,162 | $2,511 | $50 | $1,752 | $434 | $7,910 |
| 2012 | $4,323 | $2,909 | $116 | $1,841 | $457 | $9,732 |

The	accumulated	benefit	obligation	for	their	employees	for	the	non-qualified	plans	as	of	December	31,	2013	and	2012	was	as	follows:

| 2012 | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Current\tliabilities | ($209) | ($257) | ($17) | ($118) | ($25) | ($853) |
| Non-current\tliabilities | (4,114) | (2,652) | (99) | (1,723) | (432) | (8,879) |
| Total\tfunded\tstatus | ($4,323) | ($2,909) | ($116) | ($1,841) | ($457) | ($9,732) |
| Regulatory\tasset/(liability) | $2,359 | $679 | ($29) | $800 | $88 | ($465) |
| Accumulated\tother |  |  |  |  |  |  |
| comprehensive\tincome\t(before |  |  |  |  |  |  |
| taxes) | $— | $102 | $— | $— | $— | $— |

# Reclassification	out	of	Accumulated	Other	Comprehensive	Income

Entergy	and	the	Registrant	Subsidiaries	reclassified	the	following	costs	out	of	accumulated	other	comprehensive	income	(before	taxes	and including	amounts	capitalized)	as	of	December	31,	2013:

|  | Qualified<br>Pension<br>Costs | Other<br>Postretirement<br>Costs | Non-Qualified<br>Pension	Costs | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Entergy |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | ($1,866) | $12,925 | ($503) | $10,556 |
| Acceleration\tof\tprior\tservice\tcost\tdue\tto\tcurtailment | (1,304) | 1,797 | (178) | 315 |
| Amortization\tof\tloss | (43,971) | (21,590) | (2,569) | (68,130) |
| Settlement\tloss | — | — | (11,612) | (11,612) |
|  | ($47,141) | ($6,868) | ($14,862) | ($68,871) |
| Entergy\tGulf\tStates\tLouisiana |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | ($1) | $942 | $— | $941 |
| Acceleration\tof\tprior\tservice\tcost\tdue\tto\tcurtailment | — | 91 | — | 91 |
| Amortization\tof\tloss | (3,039) | (4,598) | (7) | (7,644) |
|  | ($3,040) | ($3,565) | ($7) | ($6,612) |
| Entergy\tLouisiana |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | $— | $508 | $— | $508 |
| Acceleration\tof\tprior\tservice\tcost\tdue\tto\tcurtailment | — | 41 | — | 41 |
| Amortization\tof\tloss | — | (5,050) | — | (5,050) |
|  | $— | ($4,501) | $— | ($4,501) |

# Accounting	for	Pension	and	Other	Postretirement	Benefits

Accounting	standards	require	an	employer	to	recognize	in	its	balance	sheet	the	funded	status	of	its	benefit	plans.		This	is	measured	as	the difference	between	plan	assets	at	fair	value	and	the	benefit	obligation.		Entergy	uses	a	December	31	measurement	date	for	its	pension	and	other postretirement	plans.		Employers	are	to	record	previously	unrecognized	gains	and	losses,	prior	service	costs,	and	any	remaining	transition	asset	or obligation	(that	resulted	from	adopting	prior	pension	and	other	postretirement	benefits	accounting	standards)	as	comprehensive	income	and/or	as	a regulatory	asset	reflective	of	the	recovery	mechanism	for	pension	and	other	postretirement	benefit	costs	in	the	Registrant	Subsidiaries'	respective regulatory	jurisdictions.		For	the	portion	of	Entergy	Gulf	States	Louisiana	that	is	not	regulated,	the	unrecognized	prior	service	cost,	gains	and losses,	 and	 transition	 asset/obligation	 for	 its	 pension	 and	 other	 postretirement	 benefit	 obligations	 are	 recorded	 as	 other	 comprehensive income.		Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	recover	other	postretirement	benefit	costs	on	a	pay	as	you	go	basis	and	record	the unrecognized	prior	service	cost,	gains	and	losses,	and	transition	obligation	for	its	other	postretirement	benefit	obligation	as	other	comprehensive income.		Accounting	standards	also	requires	that	changes	in	the	funded	status	be	recorded	as	other	comprehensive	income	and/or	a	regulatory asset	in	the	period	in	which	the	changes	occur.

With	regard	to	pension	and	other	postretirement	costs,	Entergy	calculates	the	expected	return	on	pension	and	other	postretirement	benefit plan	assets	by	multiplying	the	long-term	expected	rate	of	return	on	assets	by	the	market-related	value	(MRV)	of	plan	assets.		Entergy	determines the	MRV	of	pension	plan	assets	by	calculating	a	value	that	uses	a	20-quarter	phase-in	of	the	difference	between	actual	and	expected	returns.		For other	postretirement	benefit	plan	assets	Entergy	uses	fair	value	when	determining	MRV.

# Qualified	Pension	and	Other	Postretirement	Plans'	Assets

The	Plan	Administrator'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	studies,	the	Plan	Administrator	formulates	assumptions	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.	Target	asset	allocations	adjust	dynamically	based	on	the	funded	status	of	the	pension plans.		The	following	targets	and	ranges	were	established	to	produce	an	acceptable,	economically	efficient	plan	to	manage	around	the	targets.		The target	asset	allocation	range	below	for	pension	shows	 the	ranges	within	which	 the	allocation	may	adjust	based	on	funded	status,	with	 the expectation	that	the	allocation	to	fixed	income	securities	will	increase	as	the	pension	funded	status	increases.		The	target	and	range	asset	allocation for	postretirement	assets	reflects	changes	made	in	2012	as	recommended	in	the	latest	optimization	study

Entergy's	qualified	pension	and	postretirement	weighted-average	asset	allocations	by	asset	category	at	 December	31,	2013	and	2012	and the	target	asset	allocation	and	ranges	are	as	follows:

| Pension<br>Asset	Allocation | Target |  | Range |  | Actual<br>2013 | Actual<br>2012 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Domestic\tEquity\tSecurities | 45% | 34% | to | 53% | 46% | 44% |
| International\tEquity\tSecurities | 20% | 16% | to | 24% | 20% | 20% |
| Fixed\tIncome\tSecurities | 35% | 31% | to | 41% | 33% | 35% |
| Other | 0% | 0% | to | 10% | 1% | 1% |

# Postretirement

| Asset	Allocation |  | Non-Taxable | Non-Taxable | Non-Taxable |  |  |  | Taxable | Taxable | Taxable |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Target |  | Range |  | Actual\n2013 | Actual\n2012 | Target |  | Range |  | Actual\n2013 | Actual\n2012 |
| Domestic\tEquity\tSecurities | 39% | 34% | to | 44% | 40% | 38% | 39% | 34% | to | 44% | 39% | 39% |
| International\tEquity\tSecurities | 26% | 21% | to | 31% | 26% | 28% | 26% | 21% | to | 31% | 27% | 27% |
| Fixed\tIncome\tSecurities | 35% | 30% | to | 40% | 34% | 34% | 35% | 30% | to | 40% | 34% | 34% |
| Other | 0% | 0% | to | 5% | 0% | 0% | 0% | 0% | to | 5% | 0% | 0% |

The	expected	long-term	rate	of	return	for	the	qualified	pension	plans'	assets	is	based	primarily	on	the	geometric	average	of	the	historical annual	performance	of	a	representative	portfolio	weighted	by	the	target	asset	allocation	defined	in	the	table	above,	along	with	other	indications	of expected	return	on	current	assets	and	expected	return	available	for	reinvestment.		The	time	period	reflected	is	a	long	dated	period	spanning	several decades.

The	expected	long-term	rate	of	return	for	the	non-taxable	postretirement	trust	assets	is	determined	using	the	same	methodology	described above	for	pension	assets,	but	the	asset	allocation	specific	to	the	non-taxable	postretirement	assets	is	used.

For	the	taxable	postretirement	trust	assets,	the	investment	allocation	includes	tax-exempt	fixed	income	securities.		This	asset	allocation	in combination	 with	 the	 same	 methodology	 employed	 to	 determine	 the	 expected	 return	 for	 other	 trust	 assets	 (as	 described	 above),	 with	 a modification	to	reflect	applicable	taxes,	is	used	to	produce	the	expected	long-term	rate	of	return	for	taxable	postretirement	trust	assets.

# Concentrations	of	Credit	Risk

Entergy's	investment	guidelines	mandate	the	avoidance	of	risk	concentrations.		Types	of	concentrations	specified	to	be	avoided	include, but	are	not	limited	to,	investment	concentrations	in	a	single	entity,	type	of	industry,	foreign	country,	geographic	area	and	individual	security issuance.		As	of	December	31,	2013	all	investment	managers	and	assets	were	materially	in	compliance	with	the	approved	investment	guidelines, therefore	there	were	no	significant	concentrations	(defined	as	greater	 than	10	percent	of	plan	assets)	of	risk	in	Entergy's	pension	and	other postretirement	benefit	plan	assets.

# Fair	Value	Measurements

Accounting	standards	provide	the	framework	for	measuring	fair	value.	That	framework	provides	a	fair	value	hierarchy	that	prioritizes	the inputs	to	valuation	techniques	used	to	measure	fair	value.		The	hierarchy	gives	the	highest	priority	to	unadjusted	quoted	prices	in	active	markets for	identical	assets	or	liabilities	(level	1	measurements)	and	the	lowest	priority	to	unobservable	inputs	(level	3	measurements).

The	three	levels	of	the	fair	value	hierarchy	are	described	below:

•Level	1	-	Level	1	inputs	are	unadjusted	quoted	prices	for	identical	assets	or	liabilities	in	active	markets	that	the	Plan	has	the	ability	to access	at	the	measurement	date.	Active	markets	are	those	in	which	transactions	for	the	asset	or	liability	occur	in	sufficient	frequency	and volume	to	provide	pricing	information	on	an	ongoing	basis.

•Level	2	-	Level	2	inputs	are	inputs	other	than	quoted	prices	included	in	Level	1	that	are,	either	directly	or	indirectly,	observable	for	the asset	or	liability	at	the	measurement	date.		Assets	are	valued	based	on	prices	derived	by	an	independent	party	that	uses	inputs	such	as benchmark	yields,	reported	trades,	broker/dealer	quotes,	and	issuer	spreads.		Prices	are	reviewed	and	can	be	challenged	with	the independent	parties	and/or	overridden	if	it	is	believed	such	would	be	more	reflective	of	fair	value.		Level	2	inputs	include	the	following:

-					quoted	prices	for	similar	assets	or	liabilities	in	active	markets;

-					quoted	prices	for	identical	assets	or	liabilities	in	inactive	markets;

-					inputs	other	than	quoted	prices	that	are	observable	for	the	asset	or	liability;	or

-					inputs	that	are	derived	principally	from	or	corroborated	by	observable	market	data	by	correlation	or	other	means.

If	an	asset	or	liability	has	a	specified	(contractual)	term,	the	Level	2	input	must	be	observable	for	substantially	the	full	term	of	the	asset	or liability.

•Level	3	-	Level	3	refers	to	securities	valued	based	on	significant	unobservable	inputs.

Assets	and	liabilities	are	classified	in	their	entirety	based	on	the	lowest	level	of	input	that	is	significant	to	the	fair	value	measurement.		The following	 tables	 set	 forth	 by	 level	 within	 the	 fair	 value	 hierarchy,	 measured	 at	 fair	 value	 on	 a	 recurring	 basis	 at	December	 31,	 2013,	 and December	31,	2012,	a	summary	of	the	investments	held	in	the	master	trusts	for	Entergy's	qualified	pension	and	other	postretirement	plans	in which	the	Registrant	Subsidiaries	participate.

# Qualified	Pension	Trust

| 2013 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |
| Corporate\tstocks: |  |  |  |  |  |  |
| Preferred | $6,847 | (b) | $6,038 | (a) | $— | $12,885 |
| Common | 915,996 | (b) | — |  | — | 915,996 |
| Common\tcollective\ttrusts | — |  | 1,753,958 | (c) | — | 1,753,958 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 180,718 | (b) | 152,915 | (a) | — | 333,633 |
| Corporate\tdebt\tinstruments | — |  | 464,652 | (a) | — | 464,652 |
| Registered\tinvestment\tcompanies | 316,863 | (d) | 486,748 | (e) | — | 803,611 |
| Other | — |  | 129,169 | (f) | — | 129,169 |
| Other: |  |  |  |  |  |  |
| Insurance\tcompany\tgeneral\taccount\n(unallocated\tcontracts) | — |  | 36,886 | (g) | — | 36,886 |
| Total\tinvestments | $1,420,424 |  | $3,030,366 |  | $— | $4,450,790 |
| Cash |  |  |  |  |  | 280 |
| Other\tpending\ttransactions |  |  |  |  |  | 8,081 |
| Less:\tOther\tpostretirement\tassets\tincluded\tin\ntotal\tinvestments |  |  |  |  |  | (29,914) |
| Total\tfair\tvalue\tof\tqualified\npension\tassets |  |  |  |  |  | $4,429,237 |

| 2012 | Level	1 |  | Level	2 |  | Level	3 |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |  |
| Corporate\tstocks: |  |  |  |  |  |  |  |
| Preferred | $861 | (b) | $5,906 | (a) |  | $— | $6,767 |
| Common | 787,132 | (b) | — |  |  | — | 787,132 |
| Common\tcollective\ttrusts | — |  | 1,620,315 | (c) |  | — | 1,620,315 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 161,593 | (b) | 150,068 | (a) |  | — | 311,661 |
| Corporate\tdebt\tinstruments | — |  | 429,813 | (a) |  | — | 429,813 |
| Registered\tinvestment\tcompanies | 50,029 | (d) | 483,509 | (e) |  | — | 533,538 |
| Other | — |  | 111,001 | (f) |  | — | 111,001 |
| Other: |  |  |  |  |  |  |  |
| Insurance\tcompany\tgeneral\taccount\n(unallocated\tcontracts) | — |  | 36,252 | (g) |  | — | 36,252 |
| Total\tinvestments | $999,615 |  | $2,836,864 |  |  | $— | $3,836,479 |
| Cash |  |  |  |  |  |  | 571 |
| Other\tpending\ttransactions |  |  |  |  |  |  | 4,594 |
| Less:\tOther\tpostretirement\nassets\tincluded\tin\ttotal\tinvestments |  |  |  |  |  |  | (8,784) |
| Total\tfair\tvalue\tof\tqualified\npension\tassets |  |  |  |  |  |  | $3,832,860 |
| Other\tPostretirement\tTrusts |  |  |  |  |  |  |  |
| 2013 | Level\t1 |  | Level\t2 |  | Level\t3 |  | Total |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |  |
| Common\tcollective\ttrust | $— |  | $356,700 | (c) |  | $— | $356,700 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 40,808 | (b) | 43,471 | (a) |  | — | 84,279 |
| Corporate\tdebt\tinstruments | — |  | 50,563 | (a) |  | — | 50,563 |
| Registered\tinvestment\tcompanies | 4,163 | (d) | — |  |  | — | 4,163 |
| Other | — |  | 43,458 | (f) |  | — | 43,458 |
| Total\tinvestments | $44,971 |  | $494,192 |  |  | $— | $539,163 |
| Other\tpending\ttransactions |  |  |  |  |  |  | 773 |
| Plus:\t\tOther\tpostretirement\tassets\tincluded\tin |  |  |  |  |  |  |  |
| the\tinvestments\tof\tthe\tqualified |  |  |  |  |  |  |  |
| pension\ttrust |  |  |  |  |  |  | 29,914 |
| Total\tfair\tvalue\tof\tother\npostretirement\tassets |  |  |  |  |  |  | $569,850 |

| 2012 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |
| Common\tcollective\ttrust | $— |  | $314,478 | (c) | $— | $314,478 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 36,392 | (b) | 43,398 | (a) | — | 79,790 |
| Corporate\tdebt\tinstruments | — |  | 42,163 | (a) | — | 42,163 |
| Registered\tinvestment\ncompanies | 3,229 | (d) | — |  | — | 3,229 |
| Other | — |  | 39,846 | (f) | — | 39,846 |
| Total\tinvestments | $39,621 |  | $439,885 |  | $— | $479,506 |
| Other\tpending\ttransactions |  |  |  |  |  | 158 |
| Plus:\t\tOther\tpostretirement\tassets\tincluded\tin\tthe\ninvestments\tof\tthe\tqualified\tpension\ttrust |  |  |  |  |  | 8,784 |
| Total\tfair\tvalue\tof\tother\npostretirement\tassets |  |  |  |  |  | $488,448 |

(a) Certain	preferred	stocks	and	fixed	income	debt	securities	(corporate,	government,	and	securitized)	are	stated	at	fair	value	as	determined	by broker	quotes.

(b) Common	stocks,	treasury	notes	and	bonds,	and	certain	preferred	stocks	and	fixed	income	debt	securities	are	stated	at	fair	value	determined by	quoted	market	prices.

(c) The	common	collective	trusts	hold	investments	in	accordance	with	stated	objectives.		The	investment	strategy	of	the	trusts	is	to	capture	the growth	potential	of	equity	markets	by	replicating	the	performance	of	a	specified	index.		Net	asset	value	per	share	of	the	common	collective trusts	estimate	fair	value.

(d) The	registered	investment	company	is	a	money	market	mutual	fund	with	a	stable	net	asset	value	of	one	dollar	per	share.

(e) The	registered	investment	company	holds	investments	in	domestic	and	international	bond	markets	and	estimates	fair	value	using	net	asset value	per	share.

(f) The	other	remaining	assets	are	U.S.	municipal	and	foreign	government	bonds	stated	at	fair	value	as	determined	by	broker	quotes.

(g) The	 unallocated	 insurance	 contract	 investments	 are	 recorded	 at	 contract	 value,	 which	 approximates	 fair	 value.	 	The	 contract	 value represents	contributions	made	under	the	contract,	plus	interest,	less	funds	used	to	pay	benefits	and	contract	expenses,	and	less	distributions to	the	master	trust.

# Accumulated	Pension	Benefit	Obligation

The	accumulated	benefit	obligation	for	Entergy's	qualified	pension	plans	was	 $5.2	billion	 and	$5.4	billion	 at	December	31,	2013	and 2012,	respectively.

The	qualified	pension	accumulated	benefit	obligation	for	each	of	the	Registrant	Subsidiaries	for	their	employees	as	of	December	31,	2013 and	2012	was	as	follows:

# December	31,

|  | (In	Thousands) | (In	Thousands) |
| :--- | :--- | :--- |
| Entergy\tArkansas | $1,107,023 | $1,161,448 |
| Entergy\tGulf\tStates\tLouisiana | $530,974 | $559,190 |
| Entergy\tLouisiana | $697,945 | $735,376 |
| Entergy\tMississippi | $318,941 | $336,099 |
| Entergy\tNew\tOrleans | $150,239 | $157,233 |
| Entergy\tTexas | $332,484 | $350,351 |
| System\tEnergy | $247,807 | $251,378 |

# Estimated	Future	Benefit	Payments

Based	upon	the	assumptions	used	to	measure	Entergy's	qualified	pension	and	other	postretirement	benefit	obligations	at	 December	31, 2013,	and	including	pension	and	other	postretirement	benefits	attributable	to	estimated	future	employee	service,	Entergy	expects	that	benefits	to	be paid	and	the	Medicare	Part	D	subsidies	to	be	received	over	the	next	ten	years	for	Entergy	Corporation	and	its	subsidiaries	will	be	as	follows:

# Estimated	Future	Benefits	Payments

|  | Qualified<br>Pension | Non-Qualified<br>Pension | Other<br>Postretirement<br>(before	Medicare<br>Subsidy) | Estimated<br>Future<br>Medicare<br>Subsidy<br>Receipts |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Year(s) |  |  |  |  |
| 2014 | $232,876 | $26,817 | $84,038 | $5,372 |
| 2015 | $246,217 | $11,687 | $79,244 | $426 |
| 2016 | $261,255 | $10,242 | $80,842 | $478 |
| 2017 | $276,451 | $10,522 | $82,974 | $536 |
| 2018 | $293,163 | $13,421 | $87,575 | $1,769 |
| 2019\t-\t2023 | $1,773,632 | $66,317 | $485,409 | $11,725 |

Based	upon	the	same	assumptions,	Entergy	expects	that	benefits	to	be	paid	and	the	Medicare	Part	D	subsidies	to	be	received	over	the	next ten	years	for	the	Registrant	Subsidiaries	for	their	employees	will	be	as	follows:

| Estimated	Future<br>Qualified	Pension<br>Benefits	Payments | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Year(s) |  |  |  |  |  |  |  |
| 2014 | $60,456 | $23,039 | $34,740 | $16,920 | $6,615 | $18,583 | $10,523 |
| 2015 | $61,587 | $24,260 | $35,623 | $17,669 | $7,008 | $19,137 | $10,883 |
| 2016 | $63,083 | $25,556 | $36,833 | $18,515 | $7,437 | $19,744 | $11,463 |
| 2017 | $64,418 | $27,111 | $38,247 | $19,298 | $7,941 | $20,402 | $11,851 |
| 2018 | $66,281 | $28,962 | $39,914 | $20,237 | $8,582 | $21,140 | $12,615 |
| 2019\t-\t2023 | $375,976 | $177,010 | $229,821 | $114,462 | $51,610 | $118,750 | $77,880 |

| Estimated	Future<br>Non-Qualified<br>Pension	Benefits<br>Payments | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |  |
| 2014 | $367 | $262 | $6 | $119 | $20 | $786 |
| 2015 | $345 | $240 | $6 | $115 | $20 | $701 |
| 2016 | $299 | $233 | $6 | $108 | $20 | $775 |
| 2017 | $299 | $279 | $6 | $105 | $20 | $690 |
| 2018 | $279 | $212 | $5 | $99 | $19 | $657 |
| 2019\t-\t2023 | $1,916 | $932 | $21 | $648 | $223 | $2,951 |

# Estimated	Future

| Benefits	Payments<br>(before	Medicare<br>Part	D	Subsidy) | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Year(s) |  |  |  |  |  |  |  |
| 2014 | $17,122 | $9,385 | $10,967 | $4,814 | $5,044 | $7,540 | $2,858 |
| 2015 | $15,513 | $8,899 | $10,049 | $4,267 | $4,475 | $6,818 | $2,783 |
| 2016 | $15,523 | $9,137 | $10,162 | $4,340 | $4,448 | $6,934 | $2,786 |
| 2017 | $15,554 | $9,403 | $10,289 | $4,447 | $4,423 | $7,079 | $2,875 |
| 2018 | $15,987 | $9,912 | $10,796 | $4,767 | $4,502 | $7,471 | $2,984 |
| 2019\t-\t2023 | $82,455 | $55,934 | $59,068 | $25,819 | $21,707 | $40,067 | $16,928 |

| Estimated<br>Future<br>Medicare	Part	D<br>Subsidy | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Year(s) |  |  |  |  |  |  |  |
| 2014 | $1,241 | $582 | $718 | $462 | $387 | $563 | $130 |
| 2015 | $68 | $32 | $39 | $25 | $20 | $30 | $8 |
| 2016 | $74 | $35 | $43 | $27 | $20 | $32 | $9 |
| 2017 | $81 | $38 | $46 | $29 | $21 | $34 | $10 |
| 2018 | $354 | $165 | $199 | $123 | $85 | $141 | $51 |
| 2019\t-\t2023 | $2,252 | $1,061 | $1,235 | $742 | $455 | $816 | $379 |

# Contributions

Entergy	currently	expects	to	contribute	approximately	$400	million	to	its	qualified	pension	plans	and	approximately	 $74.1	million	to	other postretirement	plans	in	2014.		The	expected	2014	pension	and	other	postretirement	plan	contributions	of	the	Registrant	Subsidiaries	for	their employees	are	shown	below.		The	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are completed	by	April	1,	2014.

The	Registrant	Subsidiaries	expect	to	contribute	approximately	the	following	to	the	qualified	pension	and	other	postretirement	plans	for their	employees	in	2014:

|  | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| Pension\tContributions | $93,591 | $31,342 | $52,885 | $21,604 | $10,482 | $18,482 | $21,257 |
| Other\tPostretirement\nContributions | $25,567 | $9,385 | $10,967 | $— | $— | $4,645 | $864 |

# Actuarial	Assumptions

The	significant	actuarial	assumptions	used	in	determining	the	pension	PBO	and	the	other	postretirement	benefit	APBO	as	of	 December	31, 2013,	and	2012	were	as	follows:

The	significant	actuarial	assumptions	used	in	determining	the	net	periodic	pension	and	other	postretirement	benefit	costs	for	 2013,		2012, and	2011	were	as	follows:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| Qualified\tpension | 4.31%\t-\t4.50% | 5.10%\t-\t5.20% | 5.60%\t-\t5.70% |
| Other\tpostretirement | 4.36% | 5.10% | 5.50% |
| Non-qualified\tpension | 3.37% | 4.40% | 4.90% |
| Weighted-average\trate\tof\tincrease\n\t\tin\tfuture\tcompensation\tlevels | 4.23% | 4.23% | 4.23% |
| Expected\tlong-term\trate\tof\n\t\treturn\ton\tplan\tassets: |  |  |  |
| Pension\tassets | 8.50% | 8.50% | 8.50% |
| Other\tpostretirement\tnon-taxable\tassets | 8.50% | 8.50% | 7.75% |
| Other\tpostretirement\ttaxable\tassets | 6.50% | 6.50% | 5.50% |

Entergy's	other	postretirement	benefit	transition	obligations	were	amortized	over	 20	years	ending	in	2012.

The	assumed	health	care	cost	trend	rate	used	in	measuring	Entergy's	 December	31,	2013	APBO	was	7.25%	for	pre-65	retirees	and	7.00% for	post-65	retirees	for	2013,	gradually	decreasing	each	successive	year	until	it	reaches	4.75%	in	2022	and	beyond	for	both	pre-65	and	post-65 retirees.	The	assumed	health	care	cost	trend	rate	used	in	measuring	Entergy's	2013	Net	Other	Postretirement	Benefit	Cost	was	7.50%	for	pre-65 retirees	and	7.25%	for	post-65	retirees	for	2013,	gradually	decreasing	each	successive	year	until	it	reaches	4.75%	in	2022	and	beyond	for	both pre-65	and	post-65	retirees.

A	one	percentage	point	change	in	the	assumed	health	care	cost	trend	rate	for	 2013	would	have	the	following	effects:

|  | 1	Percentage	Point	Increase |  | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
|  | Impact\ton\tthe | Impact\ton\tthe | Impact\ton\tthe | Impact\ton\tthe |
| 2013 | Impact\ton\tthe\nAPBO | sum\tof\tservice\ncosts\tand\ninterest\tcost | Impact\ton\tthe\nAPBO | sum\tof\tservice\ncosts\tand\ninterest\tcost |
|  |  | Increase\t/(Decrease) |  |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tCorporation\tand\tits\n\t\tsubsidiaries | $173,530 | $23,366 | ($143,969) | ($18,781) |

A	one	percentage	point	change	in	the	assumed	health	care	cost	trend	rate	for	 2013	would	have	the	following	effects	for	the	Registrant Subsidiaries	for	their	employees:

|  | 1	Percentage	Point	Increase |  | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
| 2013 | Impact\ton\tthe\nAPBO | Impact\ton\tthe\nsum\tof\tservice\ncosts\tand\ninterest\tcost | Impact\ton\tthe\nAPBO | Impact\ton\tthe\nsum\tof\tservice\ncosts\tand\ninterest\tcost |
|  |  | Increase/(Decrease) |  |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tArkansas | $27,205 | $3,275 | ($22,483) | ($2,622) |
| Entergy\tGulf\tStates\tLouisiana | $21,873 | $2,792 | ($17,958) | ($2,219) |
| Entergy\tLouisiana | $18,025 | $2,514 | ($15,012) | ($2,031) |
| Entergy\tMississippi | $8,235 | $1,072 | ($6,819) | ($858) |
| Entergy\tNew\tOrleans | $4,995 | $562 | ($4,242) | ($461) |
| Entergy\tTexas | $13,439 | $1,483 | ($11,170) | ($1,189) |
| System\tEnergy | $7,022 | $1,064 | ($5,746) | ($847) |

# Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003

In	December	2003,	the	Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003	became	law.		The	Act	introduces	a prescription	drug	benefit	cost	under	Medicare	(Part	D),	which	started	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.

The	actuarially	estimated	effect	of	future	Medicare	subsidies	reduced	the	December	31,	2013	 and	2012	Accumulated	Postretirement Benefit	Obligation	by	$53.7	million	and	$316.6	million,	respectively,	and	reduced	the	2013,	2012,	and	2011	other	postretirement	benefit	cost	by $25.4	million,	$31.2	million,	and	$33.0	million,	respectively.		In	2013,	Entergy	received	$3.3	million	in	Medicare	subsidies	for	prescription	drug claims.

The	actuarially	estimated	effect	of	future	Medicare	subsidies	and	the	actual	subsidies	received	for	the	Registrant	Subsidiaries	for	their employees	was	as	follows:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Increase/(Decrease)\tIn\tThousands | Increase/(Decrease)\tIn\tThousands |  |  |  |
| Impact\ton\n12/31/2013\tAPBO | ($9,639) | ($4,875) | ($5,580) | ($3,060) | ($1,769) | ($3,324) | ($1,973) |
| Impact\ton\n12/31/2012\tAPBO | ($62,877) | ($32,055) | ($36,015) | ($19,507) | ($10,902) | ($21,164) | ($13,586) |
| Impact\ton\t2013 |  |  |  |  |  |  |  |
| other\tpostretirement |  |  |  |  |  |  |  |
| benefit\tcost | ($4,732) | ($2,988) | ($3,025) | ($1,503) | ($729) | ($1,045) | ($1,093) |
| Impact\ton\t2012 |  |  |  |  |  |  |  |
| other\tpostretirement |  |  |  |  |  |  |  |
| benefit\tcost | ($5,791) | ($3,660) | ($3,643) | ($1,799) | ($995) | ($1,321) | ($1,400) |
| Impact\ton\t2011 |  |  |  |  |  |  |  |
| other |  |  |  |  |  |  |  |
| postretirement |  |  |  |  |  |  |  |
| benefit\tcost | ($6,309) | ($3,923) | ($3,889) | ($2,016) | ($1,170) | ($1,528) | ($1,403) |
| Medicare\tsubsidies\nreceived\tin\t2013 | $737 | $410 | $513 | $245 | $194 | $334 | $105 |

# 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.	The	employing	Entergy	subsidiary	makes	matching	contributions for	 all	 non-bargaining	 and	 certain	 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	per	pay	period.		The	70%	match	is	allocated	to	investments	as	directed	by	the	employee.

Entergy	also	sponsors	the	Savings	Plan	of	Entergy	Corporation	and	Subsidiaries	IV	(established	in	2002),	the	Savings	Plan	of	Entergy Corporation	and	Subsidiaries	VI	(established	in	April	2007),	and	the	Savings	Plan	of	Entergy	Corporation	and	Subsidiaries	VII	(established	in April	2007)	to	which	matching	contributions	are	also	made.		The	plans	are	defined	contribution	plans	that	cover	eligible	employees,	as	defined	by each	plan,	of	Entergy	and	its	subsidiaries.

Entergy's	subsidiaries'	contributions	to	defined	contribution	plans	collectively	were $44.5	million	in	2013,	$43.7	million in	2012,	and $42.6	million	in	2011.		The	majority	of	the	contributions	were	to	the	System	Savings	Plan.

The	Registrant	Subsidiaries'	2013,	2012,	and	2011	contributions	to	defined	contribution	plans	for	their	employees	were	as	follows:

| Year | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2013 | $3,351 | $1,906 | $2,393 | $1,954 | $769 | $1,616 |
| 2012 | $3,223 | $1,842 | $2,327 | $1,875 | $740 | $1,601 |
| 2011 | $3,183 | $1,804 | $2,260 | $1,894 | $725 | $1,613 |

# NOTE	12.				STOCK-BASED	COMPENSATION	(Entergy	Corporation)

Entergy	grants	stock	options,	restricted	stock,	performance	units,	and	restricted	unit	awards	to	key	employees	of	the	Entergy	subsidiaries under	its	Equity	Ownership	Plans	which	are	shareholder-approved	stock-based	compensation	plans.		The	Equity	Ownership	Plan,	as	restated	in February	2003	(2003	Plan),	had	784,998	authorized	shares	remaining	for	long-term	incentive	and	restricted	unit	awards	as	of	December	 31, 2013.	 	Effective	January	1,	2007,	Entergy's	shareholders	approved	 the	2007	Equity	Ownership	and	Long-Term	Cash	Incentive	Plan	(2007 Plan).		The	maximum	aggregate	number	of	common	shares	that	can	be	issued	from	the	2007	Plan	for	stock-based	awards	is	7,000,000	with	no more	than	2,000,000	available	for	non-option	grants.		The	2007	Plan,	which	only	applies	to	awards	made	on	or	after	January	1,	2007,	will	expire after	10	years.		As	of	December	31,	2013,	there	were	1,099,255	authorized	shares	remaining	for	stock-based	awards,	all	of	which	are	available	for non-option	grants.		Effective	May	6,	2011,	Entergy's	shareholders	approved	the	2011	Equity	Ownership	and	Long-Term	Cash	Incentive	Plan (2011	Plan).		The	maximum	number	of	common	shares	that	can	be	issued	from	the	2011	Plan	for	stock-based	awards	is	5,500,000	with	no	more than	2,000,000	available	for	incentive	stock	option	grants.		The	2011	Plan,	which	only	applies	to	awards	made	on	or	after	May	6,	2011,	will	expire after	10	years.		As	of	December	31,	2013,	there	were	2,974,841	authorized	shares	remaining	for	stock-based	awards,	including	2,000,000	for incentive	stock	option	grants.

# Stock	Options

Stock	options	are	granted	at	exercise	prices	that	equal	the	closing	market	price	of	Entergy	Corporation	common	stock	on	the	date	of grant.	 	 Generally,	 stock	 options	 granted	 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.

The	following	table	includes	financial	information	for	stock	options	for	each	of	the	years	presented:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tConsolidated\tNet\tIncome | $4.1 | $7.7 | $10.4 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tConsolidated\tNet\tIncome | $1.6 | $3.0 | $4.0 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $0.7 | $1.5 | $2.0 |

Entergy	 determines	 the	 fair	 value	 of	 the	 stock	 option	 grants	 by	 considering	 factors	 such	 as	 lack	 of	 marketability,	 stock	 retention requirements,	 and	 regulatory	 restrictions	 on	 exercisability	 in	 accordance	 with	 accounting	 standards.	 	 The	 stock	 option	 weighted-average assumptions	used	in	determining	the	fair	values	are	as	follows:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Stock\tprice\tvolatility | 24.61% | 25.11% | 24.25% |
| Expected\tterm\tin\tyears | 6.69 | 6.55 | 6.64 |
| Risk-free\tinterest\trate | 1.31% | 1.22% | 2.70% |
| Dividend\tyield | 4.75% | 4.50% | 4.20% |
| Dividend\tpayment\tper\tshare | $3.32 | $3.32 | $3.32 |

Stock	price	volatility	is	calculated	based	upon	the	daily	public	stock	price	volatility	of	Entergy	Corporation	common	stock	over	a	period	equal	to the	expected	term	of	the	award.		The	expected	term	of	the	options	is	based	upon	historical	option	exercises	and	the	weighted	average	life	of options	when	exercised	and	the	estimated	weighted	average	life	of	all	vested	but	unexercised	options.		In	2008,	Entergy	implemented	stock ownership	guidelines	for	 its	senior	executive	officers.	 	These	guidelines	require	an	executive	officer	 to	own	shares	of	Entergy	Corporation common	stock	equal	to	a	specified	multiple	of	his	or	her	salary.		Until	an	executive	officer	achieves	this	ownership	position	the	executive	officer	is required	to	retain	75%	of	the	after-tax	net	profit	upon	exercise	of	the	option	to	be	held	in	Entergy	Corporation	common	stock.		The	reduction	in fair	value	of	the	stock	options	due	to	this	restriction	is	based	upon	an	estimate	of	the	call	option	value	of	the	reinvested	gain	discounted	to	present value	over	the	applicable	reinvestment	period.

A	summary	of	stock	option	activity	for	the	year	ended	December	31,	2013	and	changes	during	the	year	are	presented	below:

|  | Number<br>of	Options | Weighted-<br>Average<br>Exercise<br>Price | Aggregate<br>Intrinsic<br>Value | Weighted-<br>Average<br>Contractual<br>Life |
| :--- | :--- | :--- | :--- | :--- |
| Options\toutstanding\tas\tof\tJanuary\t1,\t2013 | 9,558,346 | $79.77 |  |  |
| Options\tgranted | 600,700 | $64.60 |  |  |
| Options\texercised | (450,228) | $53.69 |  |  |
| Options\tforfeited/expired | (68,969) | $78.38 |  |  |
| Options\toutstanding\tas\tof\tDecember\t31,\t2013 | 9,639,849 | $80.06 | $— | 4.5\tyears |
| Options\texercisable\tas\tof\tDecember\t31,\t2013 | 8,782,153 | $81.32 | $— | 5.2\tyears |

The	weighted-average	grant-date	fair	value	of	options	granted	during	the	year	was	$9.42	for	2012	and	$11.48	for	2011.		The	total	intrinsic	value of	stock	options	exercised	was	$5.7	million	during	2013,	$39.8	million	during	2012,	and	$29.6	million	during	2011.		The	intrinsic	value,	which has	no	effect	on	net	income,	of	the	stock	options	exercised	is	calculated	by	the	difference	in	Entergy	Corporation's	common	stock	price	on	the date	of	exercise	and	the	exercise	price	of	the	stock	options	granted.		Because	Entergy's	year-end	stock	price	was	less	than	the	weighted	average exercise	price,	the	aggregate	intrinsic	value	of	outstanding	stock	options	as	of	December	31,	2013	was	zero.		The	intrinsic	value	of	"in	the	money" stock	options	is	$2.9	million	as	of	December	31,	2013.		Entergy	recognizes	compensation	cost	over	the	vesting	period	of	the	options	based	on their	grant-date	fair	value.		The	total	fair	value	of	options	that	vested	was	approximately	$11	million	during	2013,	$11	million	during	2012,	and $16	million	during	2011.

The	following	table	summarizes	information	about	stock	options	outstanding	as	of	December	31,	2013:

|  |  |  | Options	Outstanding |  | Options	Exercisable |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Weighted-Avg. |  | Number |  |
|  |  |  | Remaining | Weighted | Exercisable | Weighted |
|  |  | As\tof | Contractual | Avg.\tExercise | as\tof | Avg.\tExercise |
|  |  | 12/31/2013 | Life-Yrs. | Price | 12/31/2013 | Price |
| $51\t- | $64.99 | 1,205,581 | 0.6 | $61.55 | 613,481 | $58.60 |
| $65\t- | $78.90 | 5,341,851 | 5.3 | $72.91 | 5,076,255 | $72.93 |
| $79\t- | $91.99 | 1,621,817 | 4.1 | $91.82 | 1,621,817 | $91.82 |
| $92\t- | $108.20 | 1,470,600 | 5.1 | $108.20 | 1,470,600 | $108.20 |
| $51\t- | $108.20 | 9,639,849 | 4.5 | $80.06 | 8,782,153 | $81.32 |

Stock-based	 compensation	 cost	 related	 to	 non-vested	 stock	 options	 outstanding	 as	 of	December	 31,	 2013	 not	 yet recognized is approximately	$5.0	million	and	is	expected	to	be	recognized	over	a	weighted-average	period	of	 1.70	years.

# Restricted	Stock	Awards

In	January	2013	the	Board	approved	and	Entergy	granted	361,700	restricted	stock	awards	under	the	2011	Equity	Ownership	and	Long- term	Cash	Incentive	Plan.		The	restricted	stock	awards	were	made	effective	as	of	January	31,	2013	and	were	valued	at	$64.60	per	share,	which was	 the	closing	price	of	Entergy	Corporation's	common	stock	on	 that	date.	 	One-third	of	 the	restricted	stock	awards	will	vest	upon	each anniversary	of	the	grant	date	and	are	expensed	ratably	over	the	three	year	vesting	period.		Shares	of	restricted	stock	have	the	same	dividend	and voting	rights	as	other	common	stock	and	are	considered	issued	and	outstanding	shares	of	Entergy	upon	vesting.

The	following	table	includes	financial	information	for	restricted	stock	for	each	of	the	years	presented:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tConsolidated\tNet\tIncome | $16.4 | $11.4 | $3.9 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tConsolidated\tNet\tIncome | $6.3 | $4.4 | $1.5 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $2.6 | $2.0 | $0.7 |

# Long-Term	Performance	Unit	Program

Entergy	grants	long-term	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	 end	 of	 the	 performance	 period,	 which	 is	 the	 last	 trading	 day	 of	 the year.		Performance	units	will	pay	out	to	the	extent	that	the	performance	conditions	are	satisfied.		In	addition	to	the	potential	for	equivalent	share appreciation	 or	 depreciation,	 performance	 units	 will	 earn	 the	 cash	 equivalent	 of	 the	 dividends	 paid	 during	 the	3-year	 performance	 period applicable	to	each	plan.		The	costs	of	incentive	awards	are	charged	to	income	over	the	3-year	period.		Beginning	with	the	2012-2014	performance period,	upon	vesting,	the	performance	units	granted	under	the	Long-Term	Performance	Unit	Program	will	be	settled	in	shares	of	Entergy	common stock	rather	than	cash.		In	January	2013	the	Board	approved	and	Entergy	granted	201,474	performance	units	under	the	2011	Equity	Ownership and	Long-Term	Cash	Incentive	Plan.		The	performance	units	were	made	effective	as	of	January	31,	2013,	and	were	valued	at	$65.36	per	share. Entergy	considers	factors,	primarily	market	conditions,	in	determining	the	value	of	the	performance	units.	Shares	of	the	performance	units	have the	same	dividend	and	voting	rights	as	other	common	stock,	are	considered	issued	and	outstanding	shares	of	Entergy	upon	vesting,	and	are expensed	ratably	over	the	3-year	vesting	period.

The	following	table	includes	financial	information	for	the	long-term	performance	units	for	each	of	the	years	presented:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Fair\tvalue\tof\tlong-term\tperformance\tunits\tas\tof\tDecember\t31, | $11.1 | $4.3 | $7.3 |
| Compensation\texpense\tincluded\tin\tEntergy's\tConsolidated\tNet\tIncome | $6.0 | ($5.0) | $0.7 |
| Tax\tbenefit\t(expense)\trecognized\tin\tEntergy's\tConsolidated\tNet\tIncome | $2.3 | ($1.9) | $0.3 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $0.9 | ($0.9) | $0.1 |

There	was	no	payout	in	2013	for	the	performance	units	granted	in	2010	applicable	to	the	2010	–	2012	performance	period.

# Restricted	Unit	Awards

Entergy	grants	restricted	unit	awards	earned	under	 its	stock	benefit	plans	 in	 the	form	of	stock	units	 that	are	subject	 to	 time-based restrictions.		The	restricted	units	are	equal	to	the	cash	value	of	shares	of	Entergy	Corporation	common	stock	at	the	time	of	vesting.		The	costs	of restricted	unit	awards	are	charged	to	income	over	the	restricted	period,	which	varies	from	grant	to	grant.		The	average	vesting	period	for	restricted unit	awards	granted	is	36	months.		As	of	December	31,	2013,	there	were	85,335	unvested	restricted	units	that	are	expected	to	vest	over	an	average period	of	17	months.

The	following	table	includes	financial	information	for	restricted	unit	awards	for	each	of	the	years	presented:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Fair\tvalue\tof\trestricted\tawards\tas\tof\tDecember\t31, | $2.5 | $3.0 | $6.6 |
| Compensation\texpense\tincluded\tin\tEntergy's\tConsolidated\tNet\tIncome | $1.4 | $1.3 | $3.7 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tConsolidated\tNet\tIncome | $0.6 | $0.5 | $1.4 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $0.2 | $0.2 | $0.7 |

Entergy	paid	$2.1	million	in	2013	for	awards	under	the	Restricted	Units	Awards	Plan.

# NOTE	13.	BUSINESS	SEGMENT	INFORMATION		(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	Entergy	Mississippi,		Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Entergy's	reportable	segments	as	of	December	31,	2013	are	Utility	and	Entergy	Wholesale	Commodities.		Utility	includes	the	generation, transmission,	distribution,	and	sale	of	electric	power	in	portions	of	Arkansas,	Louisiana,	Mississippi,	and	Texas,	and	natural	gas	utility	service	in portions	of	Louisiana.		Entergy	Wholesale	Commodities	includes	the	ownership	and	operation	of	six	nuclear	power	plants	located	in	the	northern United	States	and	the	sale	of	the	electric	power	produced	by	those	plants	to	wholesale	customers.		Entergy	Wholesale	Commodities	also	includes the	ownership	of	interests	in	non-nuclear	power	plants	that	sell	the	electric	power	produced	by	those	plants	to	wholesale	customers.		"All	Other" includes	the	parent	company,	Entergy	Corporation,	and	other	business	activity.

In	the	fourth	quarter	2012,	Entergy	moved	two	subsidiaries	from	All	Other	to	the	Entergy	Wholesale	Commodities	segment	to	improve the	alignment	of	certain	intercompany	items	and	income	tax	activity.

Entergy's	segment	financial	information	is	as	follows:

| 2013 | Utility | Entergy<br>Wholesale<br>Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $9,101,786 | $2,312,758 | $3,558 | ($27,155) | $11,390,947 |
| Deprec.,\tamort.\t&amp;\tdecomm. | $1,157,843 | $341,163 | $4,142 | $— | $1,503,148 |
| Interest\tand\tinvestment\tincome | $186,724 | $137,727 | $24,179 | ($149,330) | $199,300 |
| Interest\texpense | $509,173 | $16,323 | $122,291 | ($43,750) | $604,037 |
| Income\ttaxes | $365,917 | ($77,471) | ($62,465) | $— | $225,981 |
| Consolidated\tnet\tincome\t(loss) | $846,215 | $42,976 | ($53,039) | ($105,580) | $730,572 |
| Total\tassets | $35,539,585 | $9,696,705 | ($486,438) | ($1,343,406) | $43,406,446 |
| Investment\tin\taffiliates\t-\tat\tequity | $199 | $40,151 | $— | $— | $40,350 |
| Cash\tpaid\tfor\tlong-lived\tasset\nadditions | $2,268,083 | $626,322 | $49 | $— | $2,894,454 |

| 2012 | Utility | Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $8,005,091 | $2,326,309 | $4,048 | ($33,369) | $10,302,079 |
| Deprec.,\tamort.\t&amp;\tdecomm. | $1,076,845 | $248,143 | $4,357 | $— | $1,329,345 |
| Interest\tand\tinvestment\tincome | $150,292 | $105,062 | $30,656 | ($158,234) | $127,776 |
| Interest\texpense | $476,485 | $17,900 | $126,913 | ($52,014) | $569,284 |
| Income\ttaxes | $49,340 | $61,329 | ($79,814) | $— | $30,855 |
| Consolidated\tnet\tincome\t(loss) | $960,322 | $40,427 | ($26,167) | ($106,219) | $868,363 |
| Total\tassets | $35,438,130 | $9,623,345 | ($509,985) | ($1,348,988) | $43,202,502 |
| Investment\tin\taffiliates\t-\tat\tequity | $199 | $46,539 | $— | $— | $46,738 |
| Cash\tpaid\tfor\tlong-lived\tasset\nadditions | $3,182,695 | $577,652 | $619 | $— | $3,760,966 |

| 2011 | Utility | Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $8,841,828 | $2,413,773 | $4,157 | ($30,685) | $11,229,073 |
| Deprec.,\tamort.\t&amp;\tdecomm. | $1,027,597 | $260,643 | $4,557 | $— | $1,292,797 |
| Interest\tand\tinvestment\tincome | $158,737 | $99,762 | $16,368 | ($145,873) | $128,994 |
| Interest\texpense | $455,739 | $33,067 | $60,113 | ($35,292) | $513,627 |
| Income\ttaxes | $27,311 | $176,286 | $82,666 | $— | $286,263 |
| Consolidated\tnet\tincome | $1,123,866 | $491,846 | ($137,760) | ($110,580) | $1,367,372 |
| Total\tassets | $32,734,549 | $9,796,529 | $228,691 | ($2,058,070) | $40,701,699 |
| Investment\tin\taffiliates\t-\tat\tequity | $199 | $44,677 | $— | $— | $44,876 |
| Cash\tpaid\tfor\tlong-lived\tasset\nadditions | $2,351,913 | $1,048,146 | ($402) | $— | $3,399,657 |

Businesses	marked	with	*	are	sometimes	referred	to	as	the	"competitive	businesses."		Eliminations	are	primarily	intersegment	activity.		Almost	all of	Entergy's	goodwill	is	related	to	the	Utility	segment.

Earnings	were	negatively	affected	in	2013	by	expenses	of	approximately	$110	million	($70	million	after-tax),	including	approximately $85	million	($55	million	after-tax)	for	Utility	and	$25	million	($15	million	after-tax)	for	Entergy	Wholesale	Commodities,	recorded	in	connection with	 a	 strategic	 imperative	 intended	 to	 optimize	 the	 organization	 through	 a	 process	 known	 as	 human	 capital	 management.	In	 July	 2013 management	 completed	 a	 comprehensive	 review	 of	 Entergy's	 organization	 design	 and	 processes.	This	 effort	 resulted	 in	 a	 new	 internal organization	structure,	which	resulted	in	the	elimination	of	approximately	800	employee	positions.	The	restructuring	costs	associated	with	this phase	of	human	capital	management	included	implementation	costs,	severance	expenses,	benefits-related	costs,	including	pension	curtailment losses	and	special	termination	benefits,	and	impairments	of	corporate	property,	plant,	and	equipment.	The	implementation	costs,	severance	costs, and	benefits-related	costs	are	included	in	"Other	operation	and	maintenance"	in	the	consolidated	income	statements.	The	property,	plant,	and equipment	impairments	are	included	in	"Asset	impairment	and	related	charges"	in	the	consolidated	income	statements.	Total	restructuring	charges in	2013	were	comprised	of	the	following:

|  | Restructuring<br>Costs | Paid	In	Cash | Non-Cash	Portion | Remaining<br>Accrual |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Implementation\tcosts | $19 | $19 | $— | $— |
| Severance\tcosts | 45 | 6 | — | 39 |
| Benefits-related\tcosts | 26 | — | 26 | — |
| Property,\tplant,\tand\tequipment\timpairments | 20 | — | 20 | — |
| \t\tTotal | $110 | $25 | $46 | $39 |

# Geographic	Areas

For	the	years	ended	December	31,	2013,	2012,	and	2011,	the	amount	of	revenue	Entergy	derived	from	outside	of	the	United	States	was insignificant.		As	of	December	31,	2013	and	2012,	Entergy	had	no	long-lived	assets	located	outside	of	the	United	States.

# Registrant	Subsidiaries

Each	of	the	Registrant	Subsidiaries	has	one	reportable	segment,	which	is	an	integrated	utility	business,	except	for	System	Energy,	which	is an	electricity	generation	business.		Each	of	the	Registrant	Subsidiaries'	operations	is	managed	on	an	integrated	basis	by	that	company	because	of the	substantial	effect	of	cost-based	rates	and	regulatory	oversight	on	the	business	process,	cost	structures,	and	operating	results.

# NOTE	14.		EQUITY	METHOD	INVESTMENTS	(Entergy	Corporation)

As of	December	 31,	 2013,	 Entergy	 owns investments in the	 following	 companies that it	 accounts	 for	 under the	 equity	 method	 of accounting:

Investment Ownership Description RS	Cogen	LLC 50% member	interest Co-generation	 project	 that	 produces	 power	 and	 steam	 on	 an industrial	 and merchant	basis	in	the	Lake	Charles,	Louisiana	area. Top	Deer 50% member	interest 	 Wind-powered	electric	generation	joint	venture. Following	is	a	reconciliation	of	Entergy's	investments	in	equity	affiliates:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Beginning\tof\tyear | $46,738 | $44,876 | $40,697 |
| Income\t(loss)\tfrom\tthe\tinvestments | (1,702) | 1,162 | (88) |
| Dispositions\tand\tother\tadjustments | (4,686) | 700 | 4,267 |
| End\tof\tyear | $40,350 | $46,738 | $44,876 |

# Transactions	with	equity	method	investees

Entergy	 Gulf	 States	 Louisiana	 purchased	 approximately	$3.2	 million,	 $2.8	 million,	 and	$41.1	 million	 of	 electricity	 generated	 from Entergy's	share	of	RS	Cogen	in	2013,	2012,	and	2011,	respectively.		Entergy's	operating	transactions	with	its	other	equity	method	investees	were not	significant	in	2013,	2012,	or	2011.

# NOTE 15. 	 ACQUISITIONS	 AND	 DISPOSITIONS (Entergy	 Corporation,	 Entergy	 Arkansas,	 Entergy	 Louisiana, and	 Entergy Mississippi)

# Acquisitions

# Hot	Spring	Energy	Facility

In	November	2012,	Entergy	Arkansas	purchased	the	Hot	Spring	Energy	Facility,	a	 620	MW	combined-cycle	natural	gas	turbine	unit located	in	Malvern,	Arkansas,	from	KGen	Hot	Spring	LLC	for	approximately	$253	million.		The	FERC	and	the	APSC	approved	the	transaction.

# Hinds	Energy	Facility

In	November	2012,	Entergy	Mississippi	purchased	the	Hinds	Energy	Facility,	a	 450	MW	combined-cycle	natural	gas	turbine	unit	located in	Jackson,	Mississippi,	from	KGen	Hinds	LLC	for	approximately	$206	million.		The	FERC	and	the	MPSC	approved	the	transaction.

# Acadia

In	April	 2011,	 Entergy	 Louisiana	 purchased	 Unit	 2	 of	 the	Acadia	 Energy	 Center,	 a	 580	MW	generating	unit	 located	near	Eunice, Louisiana,	 from	 an	 independent	 power	 producer.	 	 The	Acadia	 Energy	 Center,	 which	 entered	 commercial	 service	 in	 2002,	 consists	 of	two combined-cycle	gas-fired	generating	units,	each	nominally	rated	at	580	MW.		Entergy	Louisiana	purchased	100	percent	of	Acadia	Unit	2	and	a	50 percent	ownership	interest	in	the	facility's	common	assets	for	approximately	$300	million.		In	a	separate	transaction,	Cleco	Power	acquired Acadia	Unit	1	and	the	other	50	percent	interest	in	the	facility's	common	assets.		Cleco	Power	will	serve	as	operator	for	the	entire	facility.		The FERC	and	the	LPSC	approved	the	transaction.

# Rhode	Island	State	Energy	Center

In	December	2011	a	subsidiary	 in	 the	Entergy	Wholesale	Commodities	business	segment	purchased	 the	Rhode	Island	State	Energy Center,	 a	583	MW	natural	gas-fired	combined-cycle	generating	plant	located	in	Johnston,	Rhode	Island,	from	a	subsidiary	of	NextEra	Energy Resources,	for	approximately	$346	million.		The	Rhode	Island	State	Energy	Center	began	commercial	operation	in	2002.

# Palisades	Purchased	Power	Agreement

Entergy's	purchase	of	the	Palisades	plant	in	2007	included	a	unit-contingent,	 15-year	purchased	power	agreement	(PPA)	with	Consumers Energy	for	100%	of	the	plant's	output,	excluding	any	future	uprates.		Prices	under	the	PPA	range	from	 $43.50/MWh	in	2007	to	$61.50/MWh	in 2022,	and	the	average	price	under	the	PPA	is	$51/MWh.		For	the	PPA,	which	was	at	below-market	prices	at	the	time	of	the	acquisition,	Entergy will	amortize	a	liability	to	revenue	over	the	life	of	the	agreement.		The	amount	that	will	be	amortized	each	period	is	based	upon	the	difference between	the	present	value	calculated	at	the	date	of	acquisition	of	each	year's	difference	between	revenue	under	the	agreement	and	revenue	based on	estimated	market	prices.		Amounts	amortized	to	revenue	were	$18	million	 in	2013,	$17	million	 in	2012,	 and	$43	million	 in	2011.	 	The amounts	to	be	amortized	to	revenue	for	the	next	five	years	will	be	$16	million	in	2014,	$15	million	for	2015,	$13	million	for	2016,	$12	million for	2017,	and	$8	million	for	2018.

# NYPA	Value	Sharing	Agreements

Entergy's	purchase	of	the	FitzPatrick	and	Indian	Point	3	plants	from	NYPA	included	value	sharing	agreements	with	NYPA.		In	October 2007,	Entergy	subsidiaries	and	NYPA	amended	and	restated	the	value	sharing	agreements	to	clarify	and	amend	certain	provisions	of	the	original terms.		Under	the	amended	value	sharing	agreements,	Entergy	subsidiaries	will	make	annual	payments	to	NYPA	based	on	the	generation	output	of the	Indian	Point	3	and	FitzPatrick	plants	from	January	2007	through	December	2014.		Entergy	subsidiaries	will	pay	NYPA	$6.59	per	MWh	for power	sold	from	Indian	Point	3,	up	to	an	annual	cap	of	$48	million,	and	$3.91	per	MWh	for	power	sold	from	FitzPatrick,	up	to	an	annual	cap	of $24	million.		The	annual	payment	for	each	year's	output	is	due	by	January	15	of	the	following	year.		Entergy	will	record	the	liability	for	payments to	NYPA	as	power	is	generated	and	sold	by	Indian	Point	3	and	FitzPatrick.		An	amount	equal	to	the	liability	will	be	recorded	to	the	plant	asset account	 as	 contingent	 purchase	 price	 consideration	 for	 the	 plants.	 In	2013,	 2012,	 and	2011,	 Entergy	 Wholesale	 Commodities	 recorded approximately	$72	million	as	plant	for	generation	during	each	of	those	years.		This	amount	will	be	depreciated	over	the	expected	remaining	useful life	of	the	plants.

# Dispositions

In	November	2013,	Entergy	sold	Entergy	Solutions	District	Energy,	a	business	wholly-owned	by	Entergy	in	the	Entergy	Wholesale Commodities	segment	that	owns	and	operates	district	energy	assets	serving	the	business	districts	in	Houston	and	New	Orleans.	Entergy	 sold Entergy	Solutions	District	Energy	for	$140	million	and	realized	a	pre-tax	gain	of	$44	million	on	the	sale.

# NOTE	16.	 	RISK	MANAGEMENT	AND	FAIR	VALUES	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana, Entergy	Louisiana,	Entergy	Mississippi,		Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

# Market	Risk

In	the	normal	course	of	business,	Entergy	is	exposed	to	a	number	of	market	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	including	commodity	price	risk,	equity	price	and	interest	rate	risk.	Entergy	uses	derivatives primarily	to	mitigate	commodity	price	risk,	particularly	power	price	and	fuel	price	risk.

As	a	wholesale	generator,	Entergy	Wholesale	Commodities's	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.	 Entergy Wholesale	Commodities	enters	into	forward	contracts	with	its	customers	and	sells	energy	and	capacity	in	the	day	ahead	or	spot	markets.	In addition	to	its	forward	physical	power	contracts,	Entergy	Wholesale	Commodities	also	uses	a	combination	of	financial	contracts,	including	swaps, collars,	put	and/or	call	options,	to	mitigate	forward	commodity	price	risk.	When	market	price	falls,	the	combination	of	instruments	is	expected	to settle	in	gains	offsetting	lower	revenue	from	generation	and	resulting	in	a	more	predictable	cash	flow.

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.	Hedging	instruments	and	volumes	are	chosen	based	on	ability	to	mitigate	risk	associated	with	future energy	and	capacity	prices;	however,	other	considerations	are	factored	into	hedge	product	and	volume	decisions	including	corporate	liquidity, corporate	credit	ratings,	counterparty	credit	risk,	hedging	costs,	firm	settlement	risk,	and	product	availability	in	the	marketplace.	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.

# Derivatives

Some	derivative	instruments	are	classified	as	cash	flow	hedges	due	to	their	financial	settlement	provisions	while	others	are	classified	as normal	purchase/normal	sale	transactions	due	to	their	physical	settlement	provisions.	Normal	purchase/normal	sale	risk	management	tools	include power	purchase	and	sales	agreements,	fuel	purchase	agreements,	capacity	contracts,	and	tolling	agreements.	Financially-settled	cash	flow	hedges can	include	natural	gas	and	electricity	swaps	and	options	and	interest	rate	swaps.	Entergy	may	enter	into	financially	settled	swap	and	option contracts	to	manage	market	risk	that	may	or	may	not	be	designated	as	hedging	instruments.

Entergy	enters	into	derivatives	only	to	manage	natural	risks	inherent	in	its	physical	or	financial	assets	or	liabilities.	The	maximum	length of	 time	 over	 which	 Entergy	 is	 currently	 hedging	 the	 variability	 in	 future	 cash	 flows	 with	 derivatives	 for	 forecasted	 power	 transactions	 at December	31,	2013	is	approximately	3	years.		Planned	generation	currently	under	contract	from	Entergy	Wholesale	Commodities	nuclear	power plants	is	74%	 for	2014,	of	which	approximately	62%	is	sold	under	financial	derivatives	and	the	remainder	under	normal	purchase/normal	sale contracts.		Total	planned	generation	for	2014	is	39	TWh.

Entergy	manages	fuel	price	volatility	for	its	Louisiana	jurisdictions	(Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	Entergy	New Orleans)	and	Entergy	Mississippi	primarily	through	the	purchase	of	short-term	natural	gas	swaps	that	financially	settle	against	NYMEX	futures. These	swaps	are	marked-to-market	with	offsetting	regulatory	assets	or	liabilities.	All	benefits	or	costs	of	the	program	are	recorded	in	fuel	costs. The	notional	volumes	of	these	swaps	are	based	on	a	portion	of	projected	annual	exposure	to	gas	for	electric	generation	and	projected	winter purchases	for	gas	distribution	at	Entergy	Gulf	States	Louisiana	and	Entergy	New	Orleans.	The	total	volume	of	natural	gas	swaps	outstanding	as	of December	31,	2013	is	27,480,000	MMBtu	for	Entergy,	including	10,340,000	MMBtu	for	Entergy	Gulf	States	Louisiana,	13,050,000	MMBtu	for Entergy	Louisiana,	3,590,000	MMBtu	for	Entergy	Mississippi,	and	500,000	MMBtu	for	Entergy	New	Orleans.		Credit	support	for	these	natural gas	swaps	is	covered	by	master	agreements	that	do	not	require	collateralization	based	on	mark-to-market	value,	but	do	carry	adequate	assurance language	that	may	lead	to	collateralization	requests.

In	connection	with	joining	MISO,	Entergy	received	a	direct	allocation	of	FTRs	in	November	2013.	FTRs	are	derivative	instruments	which represent	economic	hedges	of	future	congestion	charges	that	will	be	incurred	in	serving	Entergy's	load.	They	are	not	designated	as	hedging instruments.	Entergy	initially	records	FTRs	at	their	estimated	fair	value	and	subsequently	adjusts	the	carrying	value	to	their	estimated	fair	value	at the	end	of	each	accounting	period

prior	to	settlement.	Unrealized	gains	or	losses	on	FTRs	held	by	Entergy	Wholesale	Commodities	are	included	in	operating	revenues.	The	Utility operating	companies	recognize	regulatory	liabilities	or	assets	for	unrealized	gains	or	losses	on	FTRs.	The	total	volume	of	FTRs	outstanding	as	of December	31,	2013	is	37,647	GWh	for	Entergy,	including	8,769	GWh	for	Entergy	Arkansas,	6,125	GWh	for	Entergy	Gulf	States	Louisiana, 9,202	GWh	for	Entergy	Louisiana,	6,112	GWh	for	Entergy	Mississippi,	1,402	GWh	for	Entergy	New	Orleans,	and	6,038	GWh	for	Entergy	Texas. Credit	support	for	FTRs	held	by	the	Utility	operating	companies	is	covered	by	cash	or	letters	of	credit	issued	by	each	Entergy	Utility	operating company	as	required	by	MISO.	Credit	support	for	FTRs	held	by	Entergy	Wholesale	Commodities	is	covered	by	cash.

The	fair	values	of	Entergy's	derivative	instruments	in	the	consolidated	balance	sheet	as	of	 December	31,	2013	are	shown	in	the	table below.	Certain	investments,	including	those	not	designated	as	hedging	instruments,	are	subject	to	master	netting	arrangements	and	are	presented	in the	balance	sheet	on	a	net	basis	in	accordance	with	accounting	guidance	for	derivatives	and	hedging.

| Instrument | Balance	Sheet	Location | Fair	Value<br>(a) | Offset	(b) | Net	(c)	(d) | Business |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Derivatives\tdesignated\tas\nhedging\tinstruments |  |  |  |  |  |
| Assets:\nElectricity\tswaps\tand\toptions | Prepayments\tand\tother | $118 | ($99) | $19 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tdeferred\tdebits\tand | $17 | ($17) | $— | Entergy\tWholesale |
|  | other\tassets\t(non-current |  |  |  | Commodities |
|  | portion) |  |  |  |  |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tcurrent\tliabilities | $197 | ($131) | $66 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tnon-current\tliabilities | $46 | ($17) | $29 | Entergy\tWholesale |
|  | (non-current\tportion) |  |  |  | Commodities |
| Derivatives\tnot\tdesignated\tas\nhedging\tinstruments |  |  |  |  |  |
| Assets:\nElectricity\tswaps\tand\toptions | Prepayments\tand\tother | $177 | ($122) | $55 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Natural\tgas\tswaps | Prepayments\tand\tother | $6 | $— | $6 | \t Utility |
| FTRs | Prepayments\tand\tother | $36 | ($2) | $34 | Utility\tand\tEntergy |
|  |  |  |  |  | Wholesale\tCommodities |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tcurrent\tliabilities | $201 | ($89) | $112 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |

| Instrument | Balance	Sheet	Location | Fair	Value<br>(a) | Offset	(b) | Net	(c)	(d) | Business |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Derivatives\tdesignated\tas\nhedging\tinstruments |  |  |  |  |  |
| Assets:\nElectricity\tswaps\tand\toptions | Prepayments\tand\tother | $123 | $— | $123 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tdeferred\tdebits\tand | $46 | ($10) | $36 | Entergy\tWholesale |
|  | other\tassets\t(non-current |  |  |  | Commodities |
|  | portion) |  |  |  |  |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tnon-current\tliabilities | $18 | ($11) | $7 | Entergy\tWholesale |
|  | (non-current\tportion) |  |  |  | Commodities |
| Derivatives\tnot\tdesignated\tas\nhedging\tinstruments |  |  |  |  |  |
| Assets:\nElectricity\tswaps\tand\toptions | Prepayments\tand\tother | $22 | $— | $22 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tdeferred\tdebits\tand | $24 | ($14) | $10 | Entergy\tWholesale |
|  | other\tassets\t(non-current |  |  |  | Commodities |
|  | portion) |  |  |  |  |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tnon-current\tliabilities | $19 | ($13) | $6 | Entergy\tWholesale |
|  | (non-current\tportion) |  |  |  | Commodities |
| Natural\tgas\tswaps | Other\tcurrent\tliabilities | $8 | $— | $8 | \t Utility |

(b) Represents	the	netting	of	fair	value	balances	with	the	same	counterparty

(c) Represents	the	net	amounts	of	assets/liabilities	presented	on	the	Entergy	Consolidated	Balance	Sheets

(d) Excludes	cash	collateral	in	the	amounts	of	$47	million	posted	and	$4	million	held	as	of	December	31,	2013	and	$56	million	held	as	of December	31,	2012

The	effect	of	Entergy's	derivative	instruments	designated	as	cash	flow	hedges	on	the	consolidated	income	statements	for	the	years	ended December	31,	2013,	2012,	and	2011	are	as	follows:

Electricity	over-the-counter	instruments	that	financially	settle	against	day-ahead	power	pool	prices	are	used	to	manage	price	exposure	for Entergy	Wholesale	Commodities	generation.		Unrealized	gains	or	losses	recorded	in	other	comprehensive	income	result	from	hedging	power output	at	the	Entergy	Wholesale	Commodities	power	plants.		The	related	gains	or	losses	from	hedging	power	are	included	in	operating	revenues when	realized.	Gains	totaling	approximately	$47	million,	$268	million,	 and	$168	million	were	realized	on	the	maturity	of	cash	flow	hedges, before	taxes	of	$18	million,	$94	million,	and	$59	million,	for	the	years	ended	December	31,	2013,	2012,	and	2011,	respectively.	The	change	in fair	value	of	Entergy's	cash	flow	hedges	due	to	ineffectiveness	was	($6)	million,	($14)	million,	and	($6)	million	for	the	years	ended	December	31, 2013,	2012,	and	2011,	respectively.	The	ineffective	portion	of	cash	flow	hedges	is	recorded	in	competitive	businesses	operating	revenues.

Based	on	market	prices	as	of	December	31,	2013,	unrealized	gains	recorded	in	AOCI	on	cash	flow	hedges	relating	to	power	sales	totaled $118	million	of	net	unrealized	gains.		Approximately	$80	million	is	expected	to	be	reclassified	from	AOCI	to	operating	revenues	in	the	next twelve	months.		The	actual	amount	reclassified	from	AOCI,	however,	could	vary	due	to	future	changes	in	market	prices.

Certain	of	the	agreements	to	sell	the	power	produced	by	Entergy	Wholesale	Commodities	power	plants	contain	provisions	that	require	an Entergy	subsidiary	to	provide	collateral	to	secure	its	obligations	when	the	current	market	prices	exceed	the	contracted	power	prices.		The	primary form	 of	 collateral	 to	 satisfy	 these	 requirements	 is	 an	 Entergy	 Corporation	 guarantee.	 	As	 of	December	 31,	 2013,	 hedge	 contracts	 with	9 counterparties	were	in	a	liability	position	(approximately	$187	million	total)	and,	in	addition	to	the	corporate	guarantee,	$47	million	in	cash collateral	was	required	to	be	posted.	As	of	December	31,	2012,	hedge	contracts	with	2	counterparties	were	in	a	liability	position	(approximately $2	million	total),	but	were	significantly	below	the	amount	of	the	guarantee	provided	under	the	contract	and	no	cash	collateral	was	required.	If	the Entergy	Corporation	credit	rating	falls	below	investment	grade,	the	effect	of	the	corporate	guarantee	is	typically	ignored	and	Entergy	would	have to	post	collateral	equal	to	the	estimated	outstanding	liability	under	the	contract	at	the	applicable	date.

Entergy	may	effectively	liquidate	a	cash	flow	hedge	instrument	by	entering	into	a	contract	offsetting	the	original	hedge,	and	then	de- designating	the	original	hedge	in	this	situation.		Gains	or	losses	accumulated	in	other	comprehensive	income	prior	to	de-designation	continue	to	be deferred	in	other	comprehensive	income	until	they	are	included	in	income	as	the	original	hedged	transaction	occurs.	From	the	point	of	de- designation,	the	gains	or	losses	on	the	original	hedge

and	the	offsetting	contract	are	recorded	as	assets	or	liabilities	on	the	balance	sheet	and	offset	as	they	flow	through	to	earnings.

The	effect	of	Entergy's	derivative	instruments	not	designated	as	hedging	instruments	on	the	consolidated	income	statements	for	the	years ended	December	31,	2013,	2012,	and	2011	is	as	follows:

Due	to	regulatory	treatment,	the	natural	gas	swaps	are	marked-to-market	through	fuel,	fuel-related	expenses,	and	gas	purchased	for	resale and	then	such	amounts	are	simultaneously	reversed	and	recorded	as	an	offsetting	regulatory	asset	or	liability.		The	gains	or	losses	recorded	as	fuel expenses	when	the	swaps	are	settled	are	recovered	or	refunded	through	fuel	cost	recovery	mechanisms.

Due	to	regulatory	treatment,	the	changes	in	the	estimated	fair	value	of	FTRs	are	recorded	through	purchased	power	expenses	and	then such	amounts	are	simultaneously	reversed	and	recorded	as	an	offsetting	regulatory	asset	or	liability.		The	gains	or	losses	recorded	as	purchased power	expense	when	the	FTRs	are	settled	are	recovered	or	refunded	through	fuel	cost	recovery	mechanisms.

The	fair	values	of	the	Registrant	Subsidiaries'	derivative	instruments	not	designated	as	hedging	instruments	on	their	balance	sheets	as	of December	31,	2013	and	2012	are	as	follows:

The	effects	of	the	Registrant	Subsidiaries'	derivative	instruments	not	designated	as	hedging	instruments	on	their	income	statements	for	the years	ended	December	31,	2013,	2012,	and	2011	are	as	follows:

The	estimated	fair	values	of	Entergy's	financial	instruments	and	derivatives	are	determined	using	historical	prices,	bid	prices,	market quotes,	 and	 financial	 modeling.	Considerable	 judgment	 is	 required	 in	 developing	 the	 estimates	 of	 fair	 value.	Therefore,	 estimates	 are	 not necessarily	indicative	of	the	amounts	that	Entergy	could	realize	in	a	current	market	exchange.	Gains	or	losses	realized	on	financial	instruments other	than	those	instruments	held	by	the	Entergy	Wholesale	Commodities	business	are	reflected	in	future	rates	and	therefore	do	not	affect	net income.	Entergy	considers	the	carrying	amounts	of	most	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.

Accounting	standards	define	fair	value	as	an	exit	price,	or	the	price	that	would	be	received	to	sell	an	asset	or	the	amount	that	would	be paid	to	transfer	a	liability	in	an	orderly	transaction	between	knowledgeable	market	participants	at	the	date	of	measurement.	Entergy	and	the Registrant	Subsidiaries	use	assumptions	or	market	input	data	that	market	participants	would	use	in	pricing	assets	or	liabilities	at	fair	value.	The inputs	can	be	readily	observable,	corroborated	by	market	data,	or	generally	unobservable.	Entergy	and	the	Registrant	Subsidiaries	endeavor	to	use the	best	available	information	to	determine	fair	value.

Accounting	standards	establish	a	fair	value	hierarchy	that	prioritizes	the	inputs	used	to	measure	fair	value.	The	hierarchy	establishes	the highest	priority	for	unadjusted	market	quotes	in	an	active	market	for	the	identical	asset	or	liability	and	the	lowest	priority	for	unobservable	inputs. The	three	levels	of	the	fair	value	hierarchy	are:

•Level	1	-	Level	1	inputs	are	unadjusted	quoted	prices	in	active	markets	for	identical	assets	or	liabilities	that	the	entity	has	the	ability	to access	at	the	measurement	date.	Active	markets	are	those	in	which	transactions	for	the	asset	or	liability	occur	in	sufficient	frequency	and volume	to	provide	pricing	information	on	an	ongoing	basis.	Level	1	primarily	consists	of	individually	owned	common	stocks,	cash equivalents	(temporary	cash	investments,	securitization	recovery	trust	account,	and	escrow	accounts),	debt	instruments,	and	gas	hedge contracts.	Cash	equivalents	includes	all	unrestricted	highly	liquid	debt	instruments	with	an	original	or	remaining	maturity	of	three	months or	less	at	the	date	of	purchase.

•Level	2	-	Level	2	inputs	are	inputs	other	than	quoted	prices	included	in	Level	1	that	are,	either	directly	or	indirectly,	observable	for	the asset	or	liability	at	the	measurement	date.	Assets	are	valued	based	on	prices	derived	by	independent	third	parties	that	use	inputs	such	as benchmark	yields,	reported	trades,	broker/dealer	quotes,	and	issuer	spreads.	Prices	are	reviewed	and	can	be	challenged	with	the independent	parties	and/or	overridden	by	Entergy	if	it	is	believed	such	would	be	more	reflective	of	fair	value.	Level	2	inputs	include	the following:

- inputs	that	are	derived	principally	from	or	corroborated	by	observable	market	data

by	correlation	or	other	means.

Level	2	consists	primarily	of	individually-owned	debt	instruments	or	shares	in	common	trusts.	Common	trust	funds	are	stated	at	estimated	fair value	based	on	the	fair	market	value	of	the	underlying	investments.

•Level	3	-	Level	3	inputs	are	pricing	inputs	that	are	generally	less	observable	or	unobservable	from	objective	sources.	These	inputs	are	used with	internally	developed	methodologies	to	produce	management's	best	estimate	of	fair	value	for	the	asset	or	liability.	Level	3	consists primarily	of	FTRs	and	derivative	power	contracts	used	as	cash	flow	hedges	of	power	sales	at	merchant	power	plants.

The	values	for	power	contract	assets	or	liabilities	are	based	on	both	observable	inputs	including	public	market	prices	and	interest	rates,	and unobservable	inputs	such	as	implied	volatilities,	unit	contingent	discounts,	expected	basis

differences,	and	credit	adjusted	counterparty	interest	rates.		They	are	classified	as	Level	3	assets	and	liabilities.		The	valuations	of	these	assets	and liabilities	were	performed	by	the	Entergy	Wholesale	Commodities	Risk	Control	Group	and	sent	to	the	Entergy	Wholesale	Commodities	Back Office	and	Entergy	Nuclear	Finance	groups	for	evaluation.		The	primary	functions	of	the	Entergy	Wholesale	Commodities	Risk	Control	Group included:	 gathering,	 validating	 and	 reporting	 market	 data,	 providing	 market	 and	 credit	 risk	 analyses	 and	 valuations	 in	 support	 of	 Entergy Wholesale	 Commodities'	 commercial	 transactions,	 developing	 and	 administering	 protocols	 for	 the	 management	 of	 market	 and	 credit	 risks, implementing	 and	 maintaining	 controls	 around	 changes	 to	 market	 data	 in	 the	 energy	 trading	 and	 risk	 management	 system,	 reviewing creditworthiness	 of	 counterparties,	 supporting	 contract	 negotiations	 with	 new	 counterparties,	 administering	 credit	 support	 for	 contracts,	 and managing	the	daily	margining	process.		The	Risk	Control	group	was	also	responsible	for	managing	the	energy	trading	and	risk	management system,	forecasting	revenues,	forward	positions	and	analysis.		The	primary	functions	of	the	Entergy	Wholesale	Commodities	Back	Office	were market	and	counterparty	settlements,	revenue	reporting	and	analysis	and	general	ledger.	The	Entergy	Wholesale	Commodities	Risk	Control	Group reported	to	the	Vice	President	-	Entergy	Wholesale	Commodities	Chief	Financial	Officer	while	the	Entergy	Wholesale	Commodities	Back	Office reported	to	the	Controller,	Competitive	Operations.		Entergy	Nuclear	Finance	was	primarily	responsible	for	the	financial	planning	of	Entergy's utility	and	non-utility	nuclear	businesses.	The	VP,	Chief	Financial	Officer	-	Nuclear	Operations	within	Entergy	Nuclear	Finance	reported	to	the Chief	Accounting	Officer.

The	amounts	reflected	as	the	fair	value	of	electricity	swaps	are	based	on	the	estimated	amount	that	the	contracts	are	in-the-money	at	the balance	sheet	date	(treated	as	an	asset)	or	out-of-the-money	at	the	balance	sheet	date	(treated	as	a	liability)	and	would	equal	the	estimated	amount receivable	to	or	payable	by	Entergy	if	the	contracts	were	settled	at	that	date.	These	derivative	contracts	include	cash	flow	hedges	that	swap	fixed for	floating	cash	flows	for	sales	of	the	output	from	the	Entergy	Wholesale	Commodities	business.	The	fair	values	are	based	on	the	mark-to-market comparison	between	the	fixed	contract	prices	and	the	floating	prices	determined	each	period	from	quoted	forward	power	market	prices.	The differences	between	the	fixed	price	in	the	swap	contract	and	these	market-related	prices	multiplied	by	the	volume	specified	in	the	contract	and discounted	at	the	counterparties'	credit	adjusted	risk	free	rate	are	recorded	as	derivative	contract	assets	or	liabilities.	For	contracts	that	have	unit contingent	terms,	a	further	discount	is	applied	based	on	the	historical	relationship	between	contract	and	market	prices	for	similar	contract	terms.

The	amounts	reflected	as	the	fair	values	of	electricity	options	are	valued	based	on	a	Black	Scholes	model,	and	are	calculated	at	the	end	of each	month	for	accounting	purposes.		Inputs	to	the	valuation		include	end	of	day	forward	market	prices	for	the	period	when	the	transactions	will settle,	implied	volatilities	based	on	market	volatilities	provided	by	a	third	party	data	aggregator,	and	US	Treasury	rates	for	a	risk-free	return rate.	 	As	described	further	below,	prices	and	implied	volatilities	are	reviewed	and	can	be	adjusted	 if	 it	 is	determined	 that	 there	 is	a	better representation	of	fair	value.

On	a	daily	basis,	Entergy	Wholesale	Commodities	calculated	the	mark-to-market	for	all	derivative	transactions.	 	Entergy	Wholesale Commodities	Risk	Control	Group	also	validated	forward	market	prices	by	comparing	them	to	other	sources	of	forward	market	prices	and/or	to settlement	prices	of	actual	market	transactions.	Significant	differences	were	analyzed	and	potentially	adjusted	based	on	these	other	sources	of forward	market	prices	and/or	settlement	prices	of	actual	market	transactions.	Implied	volatilities	used	to	value	options	were	also	validated	using actual	 counterparty	 quotes	 for	 Entergy	 Wholesale	 Commodities	 transactions	 when	 available,	 and	 used	 multiple	 sources	 of	 market	 implied volatilities.	Moreover,	on	at	least	a	monthly	basis,	the	Office	of	Corporate	Risk	Oversight	confirmed	the	mark-to-market	calculations	and	prepared price	scenarios	and	credit	downgrade	scenario	analysis.		The	scenario	analysis	was	communicated	to	senior	management	within	Entergy	and within	Entergy	Wholesale	Commodities.		Finally,	for	all	proposed	derivative	transactions,	an	analysis	was	completed	to	assess	the	risk	of	adding the	proposed	derivative	to	Entergy	Wholesale	Commodities's	portfolio.		In	particular,	the	credit,	liquidity,	and	financial	metrics	impacts	were calculated	for	this	analysis.		This	analysis	was	communicated	to	senior	management	within	Entergy	and	Entergy	Wholesale	Commodities.

The	values	of	FTRs	are	based	on	unobservable	inputs,	including	estimates	of	future	congestion	costs	in	MISO	between	applicable	sink and	source	pricing	nodes	based	on	prices	published	by	MISO.	They	are	classified	as	Level

3	assets	and	liabilities.	The	valuations	of	these	assets	and	liabilities	were	performed	by	the	Entergy	Wholesale	Commodities	Back	Office	for	the unregulated	business,	and	by	the	Risk	Control	Group	within	System	Planning	and	Operations	for	the	Utility	operating	companies.	Entergy's Accounting	Policy	group	evaluated	these	valuations,	with	the	assistance	of	others	within	the	organization	with	knowledge	of	the	various	inputs and	assumptions	used	in	the	valuation.	The	Risk	Control	Group	within	System	Planning	and	Operations	performed	a	similar	role	for	the	Utility operating	companies	that	the	Entergy	Wholesale	Commodities	Back	Office	performed	for	the	unregulated	business.	The	Risk	Control	Group within	System	Planning	and	Operations	reported	to	the	Vice	President	-	System	Planning.	The	Accounting	Policy	group	reported	to	the	Vice President,	Corporate	Controller.

The	following	tables	set	forth,	by	level	within	the	fair	value	hierarchy,	Entergy's	assets	and	liabilities	that	are	accounted	for	at	fair	value on	a	recurring	basis	as	of	December	31,	2013	and	December	31,	2012.		The	assessment	of	the	significance	of	a	particular	input	to	a	fair	value measurement	requires	judgment	and	may	affect	their	placement	within	the	fair	value	hierarchy	levels.

(a) The	decommissioning	trust	funds	hold	equity	and	fixed	income	securities.	Equity	securities	are	invested	to	approximate	the	returns	of major	market	indices.		Fixed	income	securities	are	held	in	various	governmental	and	corporate	securities.		See	Note	17	for	additional information	on	the	investment	portfolios.

(b) Commingled	equity	funds	may	be	redeemed	bi-monthly.

The	following	table	sets	forth	a	reconciliation	of	changes	in	the	net	assets	(liabilities)	for	the	fair	value	of	derivatives	classified	as	Level	3 in	the	fair	value	hierarchy	for	the	years	ended	December	31,	2013,	2012,	and	2011:

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Balance\tas\tof\tJanuary\t1, | $178 | $312 | $197 |
| Realized\tgains\t(losses)\tincluded\tin\tearnings | (38) | (11) | (13) |
| Unrealized\tgains\t(losses)\tincluded\tin\tearnings | (35) | (4) | 6 |
| Unrealized\tgains\t(losses)\tincluded\tin\tOCI | (204) | 140 | 275 |
| Issuances\tof\tFTRs | 37 | — | — |
| Purchases | 14 | 9 | 15 |
| Settlements | (50) | (268) | (168) |
| Balance\tas\tof\tDecember\t31, | ($98) | $178 | $312 |

The	following	table	sets	forth	a	description	of	the	types	of	transactions	classified	as	Level	3	in	the	fair	value	hierarchy	and	significant unobservable	inputs	to	each	which	cause	that	classification,	as	of	December	31,	2013:

| Transaction	Type | Fair	Value<br>as	of<br>December	31,<br>2013 | Significant<br>Unobservable	Inputs | Range<br>from<br>Average<br>% | Effect	on<br>Fair	Value |
| :--- | :--- | :--- | :--- | :--- |
| Electricity\tswaps | ($159\tmillion) | \t Unit\tcontingent\tdiscount | +/-3% | ($5\tmillion) |
| Electricity\toptions | $26\tmillion | Implied\tvolatility | +/-79% | $26\tmillion |

The	following	table	sets	forth	an	analysis	of	each	of	the	types	of	unobservable	inputs	impacting	the	fair	value	of	items	classified	as	Level	3 within	the	fair	value	hierarchy,	and	the	sensitivity	to	changes	to	those	inputs:

| Input | Transaction	Type | Position | Change	to	Input | Fair	Value |
| :--- | :--- | :--- | :--- | :--- |
| Unit\tcontingent\tdiscount | \t Electricity\tswaps | Sell | Increase\t(Decrease) | \t Decrease\t(Increase) |
| Implied\tvolatility | \t Electricity\toptions | Sell | Increase\t(Decrease) | Increase\t(Decrease) |
| Implied\tvolatility | \t Electricity\toptions | Buy | Increase\t(Decrease) | Increase\t(Decrease) |

The	following	table	sets	forth,	by	level	within	the	fair	value	hierarchy,	the	Registrant	Subsidiaries'	assets	that	are	accounted	for	at	fair value	on	a	recurring	basis	as	of	December	31,	2013	and	December	31,	2012.		The	assessment	of	the	significance	of	a	particular	input	to	a	fair value	measurement	requires	judgment	and	may	affect	its	placement	within	the	fair	value	hierarchy	levels.

| 2013 | Level	1 | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |
| Assets: |  |  |  |  |  |
| Escrow\taccounts | $51.8 |  | $— | $— | $51.8 |
| Gas\thedge\tcontracts | 0.7 |  | — | — | 0.7 |
| FTRs | — |  | — | 1.0 | 1.0 |
|  | $52.5 |  | $— | $1.0 | $53.5 |
| 2012 | Level\t1 | Level\t2 |  | Level\t3 | Total |
|  |  |  | (In\tMillions) | (In\tMillions) |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $52.4 |  | $— | $— | $52.4 |
| Escrow\taccounts | 61.8 |  | — | — | 61.8 |
|  | $114.2 |  | $— | $— | $114.2 |
| Liabilities: |  |  |  |  |  |
| Gas\thedge\tcontracts | $2.2 |  | $— | $— | $2.2 |
| Entergy\tNew\tOrleans |  |  |  |  |  |
| 2013 | Level\t1 | Level\t2 |  | Level\t3 | Total |
|  |  |  | (In\tMillions) | (In\tMillions) |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $33.2 |  | $— | $— | $33.2 |
| Escrow\taccounts | 10.5 |  | — | — | 10.5 |
| Gas\thedge\tcontracts | 0.1 |  | — | — | 0.1 |
| FTRs | — |  | — | 2.0 | 2.0 |
|  | $43.8 |  | $— | $2.0 | $45.8 |
| 2012 | Level\t1 | Level\t2 |  | Level\t3 | Total |
|  |  |  | (In\tMillions) | (In\tMillions) |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $9.1 |  | $— | $— | $9.1 |
| Escrow\taccounts | 10.6 |  | — | — | 10.6 |
|  | $19.7 |  | $— | $— | $19.7 |
| Entergy\tTexas |  |  |  |  |  |
| 2013 | Level\t1 | Level\t2 |  | Level\t3 | Total |
|  |  |  | (In\tMillions) | (In\tMillions) |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $44.1 |  | $— | $— | $44.1 |
| Securitization\trecovery\ttrust\taccount | 37.5 |  | — | — | 37.5 |
| FTRs | — |  | — | 18.4 | 18.4 |
|  | $81.6 |  | $— | $18.4 | $100.0 |

| 2012 | Level	1 | Level	2 | Level	3 |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $59.7 | $— |  | $— | $59.7 |
| Securitization\trecovery\ttrust\taccount | 37.3 | — |  | — | 37.3 |
|  | $97.0 | $— |  | $— | $97.0 |
| System\tEnergy |  |  |  |  |  |
| 2013 | Level\t1 | Level\t2 | Level\t3 |  | Total |
|  |  | (In\tMillions) |  |  |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $64.6 | $— |  | $— | $64.6 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |  |
| Equity\tsecurities | 2.2 | 377.8 |  | — | 380.0 |
| Debt\tsecurities | 152.9 | 71.0 |  | — | 223.9 |
|  | $219.7 | $448.8 |  | $— | $668.5 |
| 2012 | Level\t1 | Level\t2 | Level\t3 |  | Total |
|  |  | (In\tMillions) |  |  |  |
| Assets: |  |  |  |  |  |
| Temporary\tcash\tinvestments | $83.5 | $— |  | $— | $83.5 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |  |
| Equity\tsecurities | 1.6 | 282.0 |  | — | 283.6 |
| Debt\tsecurities | 141.1 | 65.9 |  | — | 207.0 |
|  | $226.2 | $347.9 |  | $— | $574.1 |

The	following	table	sets	forth	a	reconciliation	of	changes	in	the	net	assets	(liabilities)	for	the	fair	value	of	derivatives	classified	as	Level	3 in	the	fair	value	hierarchy	for	the	year	ended	December	31,	2013.

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |
| Balance\tas\tof\tJanuary\t1, | $— | $— | $— | $— | $— | $— |
| Issuances\tof\tFTRs | — | 7.2 | 6.2 | 1.1 | 2.2 | 20.0 |
| Unrealized\tgains\t(losses)\tincluded\tas\ta\nregulatory\tliability/asset | (0.1) | (0.2) | (0.3) | 0.9 | 1.0 | (0.8) |
| Settlements | 0.1 | (0.3) | (0.2) | (1.0) | (1.2) | (0.8) |
| Balance\tas\tof\tDecember\t31, | $— | $6.7 | $5.7 | $1.0 | $2.0 | $18.4 |

# NOTE	17.				DECOMMISSIONING	TRUST	FUNDS	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	and	System	Energy)

Entergy	holds	debt	and	equity	securities,	classified	as	available-for-sale,	in	nuclear	decommissioning	trust	accounts.		The	NRC	requires Entergy	subsidiaries	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,	Vermont	Yankee,	and	Palisades	(NYPA	currently	retains	the	decommissioning	trusts	and	liabilities	for	Indian	Point	3	and FitzPatrick).		The	funds	are	invested	primarily	in	equity	securities,	fixed-rate	debt	securities,	and	cash	and	cash	equivalents.

Entergy	records	decommissioning	trust	funds	on	the	balance	sheet	at	their	fair	value.		Because	of	the	ability	of	the	Registrant	Subsidiaries to	recover	decommissioning	costs	 in	rates	and	 in	accordance	with	 the	regulatory	 treatment	for	decommissioning	 trust	funds,	 the	Registrant Subsidiaries	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	Louisiana	has	recorded	an	offsetting	amount	of	unrealized	gains/(losses)	 in	other deferred	credits.		Decommissioning	trust	funds	for	Pilgrim,	Indian	Point	1	and	2,	Vermont	Yankee,	and	Palisades	do	not	meet	the	criteria	for regulatory	accounting	treatment.		Accordingly,	unrealized	gains	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.		Unrealized	losses	(where	cost exceeds	fair	market	value)	on	the	assets	in	these	trust	funds	are	also	recorded	in	the	accumulated	other	comprehensive	income	component	of shareholders'	equity	unless	the	unrealized	loss	is	other	than	temporary	and	therefore	recorded	in	earnings.		Generally,	Entergy	records	realized gains	and	losses	on	its	debt	and	equity	securities	using	the	specific	identification	method	to	determine	the	cost	basis	of	its	securities.

The	securities	held	as	of	December	31,	2013	and	2012	are	summarized	as	follows:

| 2012 |  |  |  |
| :--- | :--- | :--- | :--- |
| Equity\tSecurities | $2,459 | $662 | $1 |
| Debt\tSecurities | 1,731 | 116 | 5 |
| Total | $4,190 | $778 | $6 |

Deferred	taxes	on	unrealized	gains/(losses)	are	recorded	in	other	comprehensive	income	for	the	decommissioning	trusts	which	do	not	meet	the criteria	for	regulatory	accounting	treatment	as	described	above.	Unrealized	gains/(losses)	above	are	reported	before	deferred	taxes	of	$329	million and	$211	million	as	of	December	31,	2013	and	2012,	respectively.		The	amortized	cost	of	debt	securities	was	 $1,843	million	as	of	December	31, 2013	and	$1,637	million	as	of	December	31,	2012.		As	of	December	31,	2013,	the	debt	securities	have	an	average	coupon	rate	of	approximately 3.43%,	an	average	duration	of	approximately	4.98	years,	and	an	average	maturity	of	approximately	7.51	years.		The	equity	securities	are	generally held	in	funds	that	are	designed	to	approximate	or	somewhat	exceed	the	return	of	the

Standard	&	Poor's	500	Index.		A	relatively	small	percentage	of	the	securities	are	held	in	funds	intended	to	replicate	the	return	of	the	Wilshire	4500 Index	or	the	Russell	3000	Index.

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	as	of	December	31,	2013:

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $— | $— | $892 | $24 |
| More\tthan\t12\tmonths | — | — | 60 | 5 |
| Total | $— | $— | $952 | $29 |

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $37 | $1 | $175 | $1 |
| More\tthan\t12\tmonths | 20 | — | 48 | 4 |
| Total | $57 | $1 | $223 | $5 |

The	unrealized	losses	in	excess	of	twelve	months	on	equity	securities	above	relate	to	Entergy's	Utility	operating	companies	and	System	Energy.

The	fair	value	of	debt	securities,	summarized	by	contractual	maturities,	as	of	December	31,	2013	and	2012	are	as	follows:

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $83 | $53 |
| 1\tyear\t-\t5\tyears | 752 | 681 |
| 5\tyears\t-\t10\tyears | 620 | 562 |
| 10\tyears\t-\t15\tyears | 169 | 164 |
| 15\tyears\t-\t20\tyears | 52 | 61 |
| 20\tyears+ | 154 | 210 |
| Total | $1,830 | $1,731 |

During	the	years	ended	December	31,	2013,	2012,	and	2011,	proceeds	from	the	dispositions	of	securities	amounted	to	$2,032	million, $2,074	million,	and	$1,360	million,	respectively.		During	the	years	ended	December	31,	2013,	2012,	and	2011,	gross	gains	of	$91	million,	$39 million,	and	$29	million,	respectively,	and	gross	losses	of	 $11	million,	$7	million,	and	$11	million,	respectively,	were	reclassified	out	of	other comprehensive	income	into	earnings.

Entergy	Arkansas	holds	debt	and	equity	securities,	classified	as	available-for-sale, in	nuclear	decommissioning trust	accounts. 	The securities	held	as	of	December	31,	2013	and	2012	are	summarized	as	follows:

| Equity	Securities | $463.3 | $214.0 | $— |
| :--- | :--- | :--- | :--- |
| Debt\tSecurities | 247.6 | 5.3 | 5.2 |
| Total | $710.9 | $219.3 | $5.2 |
| 2012 |  |  |  |
| Equity\tSecurities | $384.0 | $116.1 | $— |
| Debt\tSecurities | 216.6 | 14.5 | 0.2 |
| Total | $600.6 | $130.6 | $0.2 |

The	 amortized	 cost	 of	 debt	 securities	 was	$248.9	million	 as	 of	December	 31,	 2013	 and	$202.3	 million	 as	 of	December	 31,	 2012.	 	As	 of December	31,	2013,	the	debt	securities	have	an	average	coupon	rate	of	approximately	2.73%,	an	average	duration	of	approximately	4.82	years, and	an	average	maturity	of	approximately	5.52	years.		The	equity	securities	are	generally	held	in	funds	that	are	designed	to	approximate	the	return of	the	Standard	&	Poor's	500	Index.		A	relatively	small	percentage	of	the	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $— | $— | $153.2 | $4.8 |
| More\tthan\t12\tmonths | — | — | 6.9 | 0.4 |
| Total | $— | $— | $160.1 | $5.2 |

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.2 | $— | $24.4 | $0.2 |
| More\tthan\t12\tmonths | — | — | 1.0 | — |
| Total | $0.2 | $— | $25.4 | $0.2 |

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| less\tthan\t1\tyear | $8.1 | $8.8 |
| 1\tyear\t-\t5\tyears | 110.9 | 98.6 |
| 5\tyears\t-\t10\tyears | 118.0 | 93.1 |
| 10\tyears\t-\t15\tyears | 3.9 | 5.1 |
| 15\tyears\t-\t20\tyears | 0.9 | — |
| 20\tyears+ | 5.8 | 11.0 |
| Total | $247.6 | $216.6 |

Entergy	 Gulf	 States	 Louisiana	 holds	 debt	 and	 equity	 securities,	 classified	 as	 available-for-sale, in	 nuclear	 decommissioning trust accounts.		The	securities	held	as	of	December	31,	2013	and	2012	are	summarized	as	follows:

| 2013 |  |  |  |
| :--- | :--- | :--- | :--- |
| Equity\tSecurities | $370.8 | $141.8 | $— |
| Debt\tSecurities | 202.9 | 7.4 | 3.5 |
| Total | $573.7 | $149.2 | $3.5 |
| 2012 |  |  |  |
| Equity\tSecurities | $288.5 | $69.8 | $— |
| Debt\tSecurities | 188.9 | 15.8 | 0.1 |
| Total | $477.4 | $85.6 | $0.1 |

The	 amortized	 cost	 of	 debt	 securities	 was	$199.1	million	 as	 of	December	 31,	 2013	 and	$174.1	 million	 as	 of	December	 31,	 2012.	 	As	 of December	31,	2013,	the	debt	securities	have	an	average	coupon	rate	of	approximately	4.03%,	an	average	duration	of	approximately	5.13	years, and	an	average	maturity	of	approximately	7.31	years.		The	equity	securities	are	generally	held	in	funds	that	are	designed	to	approximate	the	return of	the	Standard	&	Poor's	500	Index.		A	relatively	small	percentage	of	the	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $— | $— | $91.9 | $3.1 |
| More\tthan\t12\tmonths | — | — | 4.6 | 0.4 |
| Total | $— | $— | $96.5 | $3.5 |

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $1.2 | $— | $9.1 | $0.1 |
| More\tthan\t12\tmonths | 1.0 | — | — | — |
| Total | $2.2 | $— | $9.1 | $0.1 |

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $7.9 | $8.0 |
| 1\tyear\t-\t5\tyears | 51.2 | 43.5 |
| 5\tyears\t-\t10\tyears | 75.5 | 63.5 |
| 10\tyears\t-\t15\tyears | 55.8 | 55.8 |
| 15\tyears\t-\t20\tyears | 4.6 | 8.5 |
| 20\tyears+ | 7.9 | 9.6 |
| Total | $202.9 | $188.9 |

Entergy	Louisiana	holds	debt	and	equity	securities,	classified	as	available-for-sale,	in	nuclear	decommissioning	trust	accounts. 	The securities	held	as	of	December	31,	2013	and	2012	are	summarized	as	follows:

| Equity	Securities | $224.2 | $96.1 | $— |
| :--- | :--- | :--- | :--- |
| Debt\tSecurities | 123.1 | 4.7 | 1.9 |
| Total | $347.3 | $100.8 | $1.9 |
| 2012 |  |  |  |
| Equity\tSecurities | $175.5 | $48.9 | $0.1 |
| Debt\tSecurities | 111.9 | 9.4 | 0.1 |
| Total | $287.4 | $58.3 | $0.2 |

The	 amortized	 cost	 of	 debt	 securities	 was	$120.6	million	 as	 of	December	 31,	 2013	 and	$102.6	 million	 as	 of	December	 31,	 2012.	 	As	 of December	31,	2013,	the	debt	securities	have	an	average	coupon	rate	of	approximately	2.99%,	an	average	duration	of	approximately	4.48	years, and	an	average	maturity	of	approximately	7.48	years.		The	equity	securities	are	generally	held	in	funds	that	are	designed	to	approximate	the	return of	the	Standard	&	Poor's	500	Index.		A	relatively	small	percentage	of	the	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $— | $— | $38.3 | $1.7 |
| More\tthan\t12\tmonths | — | — | 1.7 | 0.2 |
| Total | $— | $— | $40.0 | $1.9 |

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $0.7 | $— | $3.4 | $— |
| More\tthan\t12\tmonths | 5.6 | 0.1 | 0.5 | 0.1 |
| Total | $6.3 | $0.1 | $3.9 | $0.1 |

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $14.8 | $1.9 |
| 1\tyear\t-\t5\tyears | 41.9 | 42.3 |
| 5\tyears\t-\t10\tyears | 37.0 | 24.9 |
| 10\tyears\t-\t15\tyears | 6.6 | 18.8 |
| 15\tyears\t-\t20\tyears | 6.2 | 1.7 |
| 20\tyears+ | 16.6 | 22.3 |
| Total | $123.1 | $111.9 |

# System	Energy

System	Energy	holds	debt	and	equity	securities,	classified	as	available-for-sale,	in	nuclear	decommissioning	trust	accounts.		The	securities held	as	of	December	31,	2013	and	2012	are	summarized	as	follows:

| 2013 |  |  |  |
| :--- | :--- | :--- | :--- |
| Equity\tSecurities | $380.0 | $150.8 | $— |
| Debt\tSecurities | 223.9 | 3.5 | 1.8 |
| Total | $603.9 | $154.3 | $1.8 |
| 2012 |  |  |  |
| Equity\tSecurities | $283.6 | $63.6 | $0.2 |
| Debt\tSecurities | 207.0 | 9.3 | 0.1 |
| Total | $490.6 | $72.9 | $0.3 |

The	 amortized	 cost	 of	 debt	 securities	 was	$223.4	million	 as	 of	December	 31,	 2013	 and	$197.8	 million	 as	 of	December	 31,	 2012.	 	As	 of December	31,	2013,	the	debt	securities	have	an	average	coupon	rate	of	approximately	2.44%,	an	average	duration	of	approximately	4.42	years, and	an	average	maturity	of	approximately	6.02	years.		The	equity	securities	are	generally	held	in	funds	that	are	designed	to	approximate	the	return of	the	Standard	&	Poor's	500	Index.		A	relatively	small	percentage	of	the	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $— | $— | $121.7 | $1.7 |
| More\tthan\t12\tmonths | — | — | 0.9 | 0.1 |
| Total | $— | $— | $122.6 | $1.8 |

|  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  | (In\tMillions) |  |  |
| Less\tthan\t12\tmonths | $1.4 | $— | $15.5 | $0.1 |
| More\tthan\t12\tmonths | 13.0 | 0.2 | — | — |
| Total | $14.4 | $0.2 | $15.5 | $0.1 |

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $5.5 | $1.3 |
| 1\tyear\t-\t5\tyears | 144.9 | 128.7 |
| 5\tyears\t-\t10\tyears | 44.3 | 53.9 |
| 10\tyears\t-\t15\tyears | 9.3 | 2.3 |
| 15\tyears\t-\t20\tyears | 1.6 | 1.4 |
| 20\tyears+ | 18.3 | 19.4 |
| Total | $223.9 | $207.0 |

# Other-than-temporary	impairments	and	unrealized	gains	and	losses

Entergy,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy	evaluate	unrealized	losses	at	the	end	of each	period	to	determine	whether	an	other-than-temporary	impairment	has	occurred.		The	assessment	of	whether	an	investment	in	a	debt	security has	suffered	an	other-than-temporary	impairment	is	based	on	whether	Entergy	has	the	intent	to	sell	or	more	likely	than	not	will	be	required	to	sell the	debt	security	before	recovery

of	its	amortized	costs.		Further,	if	Entergy	does	not	expect	to	recover	the	entire	amortized	cost	basis	of	the	debt	security,	an	other-than-temporary impairment	is	considered	to	have	occurred	and	it	is	measured	by	the	present	value	of	cash	flows	expected	to	be	collected	less	the	amortized	cost basis	(credit	loss).		Entergy	did	not	have	any	material	other-than-temporary	impairments	relating	to	credit	losses	on	debt	securities	for	the	years ended	December	31,	2013,	2012,	and	2011.		The	assessment	of	whether	an	investment	in	an	equity	security	has	suffered	an	other-than-temporary impairment	continues	to	be	based	on	a	number	of	factors	including,	first,	whether	Entergy	has	the	ability	and	intent	to	hold	the	investment	to recover	its	value,	the	duration	and	severity	of	any	losses,	and,	then,	whether	it	is	expected	that	the	investment	will	recover	its	value	within	a reasonable	period	of	time.		Entergy's	trusts	are	managed	by	third	parties	who	operate	in	accordance	with	agreements	that	define	investment guidelines	and	place	restrictions	on	the	purchases	and	sales	of	investments.		Entergy	did	not	record	material	charges	to	other	income	in	2013, 2012,	 and	2011,	respectively,	resulting	from	 the	recognition	of	 the	other-than-temporary	 impairment	of	certain	equity	securities	held	 in	 its decommissioning	trust	funds.

# NOTE	 18.	 	VARIABLE	 INTEREST	 ENTITIES	 (Entergy	 Corporation,	 Entergy	Arkansas,	 Entergy	 Gulf	 States,	 Entergy	 Louisiana, Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Under	applicable	authoritative	accounting	guidance,	a	variable	interest	entity	(VIE)	is	an	entity	that	conducts	a	business	or	holds	property that	possesses	any	of	the	following	characteristics:	an	insufficient	amount	of	equity	at	risk	to	finance	its	activities,	equity	owners	who	do	not	have the	power	to	direct	the	significant	activities	of	the	entity	(or	have	voting	rights	that	are	disproportionate	to	their	ownership	interest),	or	where equity	holders	do	not	receive	expected	losses	or	returns.	An	entity	may	have	an	interest	in	a	VIE	through	ownership	or	other	contractual	rights	or obligations,	and	is	required	to	consolidate	a	VIE	if	it	is	the	VIE's	primary	beneficiary.	The	primary	beneficiary	of	a	VIE	is	the	entity	that	has	the power	to	direct	the	activities	of	the	VIE	that	most	significantly	affect	the	VIE's	economic	performance,	and	has	the	obligation	to	absorb	losses	or has	the	right	to	residual	returns	that	would	potentially	be	significant	to	the	entity.

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy	consolidate	the	respective	companies	from which	they	lease	nuclear	fuel,	usually	in	a	sale	and	leaseback	transaction.	This	is	because	Entergy	directs	the	nuclear	fuel	companies	with	respect to	nuclear	fuel	purchases,	assists	the	nuclear	fuel	companies	in	obtaining	financing,	and,	if	financing	cannot	be	arranged,	the	lessee	(Entergy Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	or	System	Energy)	is	responsible	to	repurchase	nuclear	fuel	to	allow	the	nuclear	fuel company	(the	VIE)	to	meet	its	obligations.	During	the	term	of	the	arrangements,	none	of	the	Entergy	operating	companies	have	been	required	to provide	 financial	 support	 apart	 from	 their	 scheduled	 lease	 payments.	See	Note	4	 to	 the	financial	statements	for	details	of	 the	nuclear	fuel companies'	credit	facility	and	commercial	paper	borrowings	and	long-term	debt	that	are	reported	by	Entergy,	Entergy	Arkansas,	Entergy	Gulf States	Louisiana,	Entergy	Louisiana,	and	System	Energy.	These	amounts	also	represent	Entergy's	and	the	respective	Registrant	Subsidiary's maximum	exposure	to	losses	associated	with	their	respective	interests	in	the	nuclear	fuel	companies.

Entergy	 Gulf	 States	 Reconstruction	 Funding	 I,	 LLC,	 and	 Entergy	 Texas	 Restoration	 Funding,	 LLC,	 companies	 wholly-owned	 and consolidated	by	Entergy	Texas,	are	variable	interest	entities	and	Entergy	Texas	is	the	primary	beneficiary.	 In	June	2007,	Entergy	Gulf	States Reconstruction	Funding	issued	senior	secured	transition	bonds	(securitization	bonds)	to	finance	Entergy	Texas's	Hurricane	Rita	reconstruction costs.	In	November	2009,	Entergy	Texas	Restoration	Funding	issued	senior	secured	transition	bonds	(securitization	bonds)	to	finance	Entergy Texas's	Hurricane	Ike	and	Hurricane	Gustav	restoration	costs.	With	the	proceeds,	the	variable	interest	entities	purchased	from	Entergy	Texas	the transition	property,	which	is	the	right	to	recover	from	customers	through	a	transition	charge	amounts	sufficient	to	service	the	securitization	bonds. The	transition	property	is	reflected	as	a	regulatory	asset	on	the	consolidated	Entergy	Texas	balance	sheet.	The	creditors	of	Entergy	Texas	do	not have	recourse	to	the	assets	or	revenues	of	the	variable	interest	entities,	including	the	transition	property,	and	the	creditors	of	the	variable	interest entities	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Texas.	Entergy	Texas	has	no	payment	obligations	to	the	variable	interest	entities except	to	remit	transition	charge	collections.	See	Note	5	to	the	financial	statements	for	additional	details	regarding	the	securitization	bonds.

Entergy	Arkansas	Restoration	Funding,	LLC,	a	company	wholly-owned	and	consolidated	by	Entergy	Arkansas,	is	a	variable	interest	entity and	Entergy	Arkansas	is	the	primary	beneficiary.	In	August	2010,	Entergy	Arkansas	Restoration	Funding	issued	storm	cost	recovery	bonds	to finance	 Entergy	 Arkansas's	 January	 2009	 ice	 storm	 damage	 restoration	 costs.	With	 the	 proceeds,	 Entergy	 Arkansas	 Restoration	 Funding purchased	from	Entergy	Arkansas	the	storm	recovery	property,	which	is	the	right	to	recover	from	customers	through	a	storm	recovery	charge amounts	sufficient	to	service	the	securitization	bonds.		The	storm	recovery	property	is	reflected	as	a	regulatory	asset	on	the	consolidated	Entergy Arkansas	 balance	 sheet.	The	creditors	of	Entergy	Arkansas	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Arkansas	Restoration Funding,	including	the	storm	recovery	property,	and	the	creditors	of	Entergy	Arkansas	Restoration	Funding	do	not	have	recourse	to	the	assets	or revenues	of	Entergy	Arkansas.		Entergy	Arkansas	has	no	payment	obligations	to	Entergy	Arkansas	Restoration	Funding	except	to	remit	storm recovery	charge	collections.	See	Note	5	to	the	financial	statements	for	additional	details	regarding	the	storm	cost	recovery	bonds.

Entergy	Louisiana	Investment	Recovery	Funding	I,	L.L.C.,	a	company	wholly-owned	and	consolidated	by	Entergy	Louisiana,	is	a	variable interest	entity	and	Entergy	Louisiana	is	the	primary	beneficiary.	In	September	2011,	Entergy	Louisiana	Investment	Recovery	Funding	issued investment	recovery	bonds	 to	recover	Entergy	Louisiana's	 investment	recovery	costs	associated	with	 the	canceled	Little	Gypsy	repowering project.	 	 With	 the	 proceeds,	 Entergy	 Louisiana	 Investment	 Recovery	 Funding	 purchased	 from	 Entergy	 Louisiana	 the	 investment	 recovery property,	which	is	the	right	to	recover	from	customers	through	an	investment	recovery	charge	amounts	sufficient	to	service	the	bonds.	 The investment	recovery	property	is	reflected	as	a	regulatory	asset	on	the	consolidated	Entergy	Louisiana	balance	sheet.		The	creditors	of	Entergy Louisiana	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	Louisiana	Investment	Recovery	Funding,	including	the	investment	recovery property,	 and	 the	 creditors	 of	 Entergy	 Louisiana	 Investment	 Recovery	 Funding	 do	 not	 have	 recourse	 to	 the	 assets	 or	 revenues	 of	 Entergy Louisiana.	 	 Entergy	 Louisiana	 has	 no	 payment	 obligations	 to	 Entergy	 Louisiana	 Investment	 Recovery	 Funding	 except	 to	 remit	 investment recovery	charge	collections.	See	Note	5	to	the	financial	statements	for	additional	details	regarding	the	investment	recovery	bonds.

Entergy	Louisiana	and	System	Energy	are	also	considered	to	each	hold	a	variable	interest	in	the	lessors	from	which	they	lease	undivided interests	in	the	Waterford	3	and	Grand	Gulf	nuclear	plants,	respectively.		Entergy	Louisiana	and	System	Energy	are	the	lessees	under	these arrangements,	which	are	described	in	more	detail	in	Note	10	to	the	financial	statements.		Entergy	Louisiana	made	payments	on	its	lease,	including interest,	 of	$26.3	million	 in	2013,	$39.1	million	 in	2012,	 and	$50.4	million	 in	2011.		System	Energy	made	payments	on	its	lease,	including interest,	of	$50.5	million	in	2013,	$50.0	million	in	2012,	and	$49.4	million	in	2011.		The	lessors	are	banks	acting	in	the	capacity	of	owner	trustee for	 the	 benefit	 of	 equity	 investors	 in	 the	 transactions	 pursuant	 to	 trust	 agreements	 entered	 solely	 for	 the	 purpose	 of	 facilitating	 the	 lease transactions.		It	is	possible	that	Entergy	Louisiana	and	System	Energy	may	be	considered	as	the	primary	beneficiary	of	the	lessors,	but	Entergy	is unable	to	apply	the	authoritative	accounting	guidance	with	respect	to	these	VIEs	because	the	lessors	are	not	required	to,	and	could	not,	provide	the necessary	 financial	 information	 to	 consolidate	 the	 lessors.	 	 Because	 Entergy	 accounts	 for	 these	 leasing	 arrangements	 as	 capital	 financings, however,	Entergy	believes	that	consolidating	the	lessors	would	not	materially	affect	the	financial	statements.		In	the	unlikely	event	of	default under	a	lease,	remedies	available	to	the	lessor	include	payment	by	the	lessee	of	the	fair	value	of	the	undivided	interest	in	the	plant,	payment	of	the present	value	of	the	basic	rent	payments,	or	payment	of	a	predetermined	casualty	value.		Entergy	believes,	however,	that	the	obligations	recorded on	the	balance	sheets	materially	represent	each	company's	potential	exposure	to	loss.

Entergy	has	also	reviewed	various	lease	arrangements,	power	purchase	agreements,	and	other	agreements	in	which	it	holds	a	variable interest.		In	these	cases,	Entergy	has	determined	that	it	is	not	the	primary	beneficiary	of	the	related	VIE	because	it	does	not	have	the	power	to direct	the	activities	of	the	VIE	that	most	significantly	affect	the	VIE's	economic	performance,	or	it	does	not	have	the	obligation	to	absorb	losses	or the	right	to	residual	returns	that	would	potentially	be	significant	to	the	entity,	or	both.

# NOTE	19.			TRANSACTIONS	WITH	AFFILIATES	(Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Each	Registrant	Subsidiary	purchases	electricity	from	or	sells	electricity	to	the	other	Registrant	Subsidiaries,	or	both,	under	rate	schedules filed	with	FERC.		The	Registrant	Subsidiaries	receive	management,	technical,	advisory,	operating,	and	administrative	services	from	Entergy Services;	receive	management,	technical,	and	operating	services	from	Entergy	Operations;	and	until	the	first	quarter	2011	purchased	fuel	from System	Fuels.		These	transactions	are	on	an	"at	cost"	basis.		In	addition,	Entergy	Power	sells	electricity	to	Entergy	Arkansas,	Entergy	Louisiana, and	Entergy	New	Orleans.		RS	Cogen	sells	electricity	to	Entergy	Gulf	States	Louisiana.

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

As	described	in	Note	4	to	the	financial	statements,	the	Registrant	Subsidiaries	participate	in	Entergy's	money	pool	and	earn	interest income	from	the	money	pool.		Entergy	Arkansas,	Entergy	Mississippi,	and	Entergy	New	Orleans	also	received	interest	income	from	System	Fuels until	the	first	quarter	2011,	when	System	Fuels	repaid	each	company's	investment	in	System	Fuels.		As	described	in	Note	2	to	the	financial statements,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	receive	preferred	membership	distributions	from	Entergy	Holdings	Company.

The	tables	below	contain	the	various	affiliate	transactions	of	the	Utility	operating	companies,	System	Energy,	and	other	Entergy	affiliates.

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| 2013 | $349.9 | $383.1 | $114.9 | $107.3 | $27.0 | $369.4 | $735.1 |
| 2012 | $324.0 | $380.6 | $138.2 | $36.1 | $43.9 | $313.2 | $622.1 |
| 2011 | $293.8 | $574.5 | $139.0 | $125.1 | $96.9 | $264.1 | $563.4 |

# Intercompany	Operating	Expenses

|  | (a) | (b) | (c) |  | (d) |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 | $656.1 | $672.8 | $667.6 | $399.0 | $279.6 | $418.1 | $175.2 |
| 2012 | $580.7 | $532.3 | $597.4 | $352.7 | $247.2 | $386.1 | $147.4 |
| 2011 | $752.7 | $563.1 | $574.0 | $337.2 | $226.6 | $486.6 | $131.5 |

# Intercompany	Interest	and	Investment	Income

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| 2013 | $— | $27.5 | $78.2 | $— | $— | $— | $— |
| 2012 | $— | $28.2 | $78.2 | $— | $— | $0.1 | $— |
| 2011 | $0.1 | $32.5 | $78.1 | $0.1 | $0.1 | $— | $0.6 |

# NOTE	20.		QUARTERLY	FINANCIAL	DATA	(UNAUDITED)	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,

# Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Operating	results	for	the	four	quarters	of	2013	and	2012	for	Entergy	Corporation	and	subsidiaries	were:

| First	Quarter | $2,608,874 | $394,045 | $166,982 | $161,400 |
| :--- | :--- | :--- | :--- | :--- |
| Second\tQuarter | $2,738,208 | $346,512 | $168,055 | $163,723 |
| Third\tQuarter | $3,351,959 | $388,894 | $244,182 | $239,850 |
| Fourth\tQuarter | $2,691,906 | $225,548 | $151,353 | $146,929 |
| 2012: |  |  |  |  |
| First\tQuarter | $2,383,659 | ($56,857) | ($146,740) | ($151,683) |
| Second\tQuarter | $2,518,600 | $342,984 | $370,583 | $365,001 |
| Third\tQuarter | $2,963,560 | $690,852 | $342,670 | $337,088 |
| Fourth\tQuarter | $2,436,260 | $324,202 | $301,850 | $296,267 |

# Earnings	per	Average	Common	Share

|  | 2013 |  | 2012 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Basic | Diluted | Basic | Diluted |
| First\tQuarter | $0.91 | $0.90 | ($0.86) | ($0.86) |
| Second\tQuarter | $0.92 | $0.92 | $2.06 | $2.06 |
| Third\tQuarter | $1.35 | $1.34 | $1.90 | $1.89 |
| Fourth\tQuarter | $0.82 | $0.82 | $1.67 | $1.67 |

As	discussed	in	more	detail	in	Note	1	to	the	financial	statements,	operating	results	for	 2013	and	2012	include	a	$321.5	million	($202.2 million	after-tax)	and	$355.5	million	($223.5	million	after-tax),	respectively,	of	impairment	and	other	related	charges	primarily	to	write	down	the carrying	value	of	Vermont	Yankee	and	related	assets	to	their	fair	values.	 Also,	as	discussed	in	more	detail	in	Note	13	to	the	financial	statements, operating	 results	 include	approximately	$110	million	($70	million	after-tax)	in	costs	in	2013	associated	with	the	human	capital	management strategic	initiative,	primarily	implementation	costs,	severance	expenses,	pension	curtailment	losses,	and	special	termination	benefits	expense.	In December	 2013,	 Entergy	 deferred	 for	 future	 recovery	 approximately	$45	million	($30	million	after-tax)	of	 these	costs	 in	 the	Arkansas	and Louisiana	jurisdictions,	as	approved	by	the	APSC	and	the	LPSC,	respectively.

The	business	of	the	Utility	operating	companies	is	subject	to	seasonal	fluctuations	with	the	peak	periods	occurring	during	the	third quarter.		Operating	results	for	the	Registrant	Subsidiaries	for	the	four	quarters	of	2013	and	2012	were:

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| 2013: |  |  |  |  |  |  |  |
| First\tQuarter | $542,392 | $419,955 | $606,085 | $291,641 | $146,466 | $306,173 | $168,578 |
| Second\tQuarter | $508,653 | $492,361 | $635,805 | $326,039 | $142,841 | $455,100 | $172,177 |
| Third\tQuarter | $647,671 | $558,331 | $782,789 | $397,833 | $178,641 | $526,978 | $192,679 |
| Fourth\tQuarter | $491,443 | $470,486 | $602,256 | $319,027 | $152,208 | $440,548 | $201,655 |
| 2012: |  |  |  |  |  |  |  |
| First\tQuarter | $475,178 | $399,622 | $482,358 | $261,760 | $129,156 | $326,924 | $126,034 |
| Second\tQuarter | $502,022 | $401,356 | $561,787 | $277,204 | $129,244 | $358,067 | $113,699 |
| Third\tQuarter | $656,201 | $434,451 | $614,044 | $321,771 | $161,565 | $489,078 | $188,680 |
| Fourth\tQuarter | $493,603 | $419,465 | $491,254 | $259,631 | $149,775 | $407,427 | $193,705 |

# Operating	Income	(Loss)

|  | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| 2013: |  |  |  |  |  |  |  |
| First\tQuarter | $43,314 | $52,083 | $64,728 | $37,123 | $4,272 | $26,277 | $52,052 |
| Second\tQuarter | $80,942 | $53,856 | $88,691 | $46,809 | $3,627 | $38,355 | $51,632 |
| Third\tQuarter | $157,681 | $85,284 | $145,847 | $70,186 | $15,895 | $79,430 | $52,029 |
| Fourth\tQuarter | $23,123 | $56,114 | $56,128 | $36,112 | $3,070 | $30,071 | $47,367 |
| 2012: |  |  |  |  |  |  |  |
| First\tQuarter | $39,816 | $55,226 | $36,142 | $28,338 | $3,250 | $25,063 | $35,456 |
| Second\tQuarter | $87,899 | $56,037 | ($41,253) | $42,225 | $10,009 | $48,983 | $38,245 |
| Third\tQuarter | $152,836 | $85,561 | $121,725 | $59,331 | $19,565 | $61,234 | $58,934 |
| Fourth\tQuarter | $26,833 | $52,138 | $32,397 | $30,621 | $3,066 | $34,533 | $58,776 |

# Net	Income	(Loss)

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tThousands) |  |  |  |
| 2013: |  |  |  |  |  |  |  |
| First\tQuarter | $14,719 | $27,165 | $45,376 | $13,934 | $1,307 | $922 | $28,006 |
| Second\tQuarter | $40,483 | $29,720 | $61,377 | $18,954 | $598 | $10,953 | $27,734 |
| Third\tQuarter | $82,577 | $62,642 | $100,597 | $33,813 | $8,086 | $35,801 | $35,105 |
| Fourth\tQuarter | $24,169 | $42,135 | $45,114 | $15,458 | $1,692 | $10,205 | $22,819 |
| 2012: |  |  |  |  |  |  |  |
| First\tQuarter | $13,874 | $28,358 | $33,295 | $8,682 | $40 | $1,745 | $26,536 |
| Second\tQuarter | $45,755 | $50,389 | $130,714 | $15,914 | $7,186 | $16,204 | $35,368 |
| Third\tQuarter | $82,551 | $50,210 | $80,208 | $27,080 | $10,555 | $19,234 | $30,616 |
| Fourth\tQuarter | $10,185 | $30,020 | $36,864 | ($4,908) | ($716) | $4,788 | $19,346 |

# Earnings	(Loss)	Applicable	to	Common	Equity

|  | Entergy<br>Arkansas | Entergy<br>Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2013: |  |  |  |  |  |
| First\tQuarter | $13,001 | $26,959 | $43,638 | $13,227 | $1,066 |
| Second\tQuarter | $38,765 | $29,514 | $59,639 | $18,247 | $357 |
| Third\tQuarter | $80,859 | $62,436 | $98,859 | $33,106 | $7,845 |
| Fourth\tQuarter | $22,450 | $41,928 | $43,378 | $14,751 | $1,450 |
| 2012: |  |  |  |  |  |
| First\tQuarter | $12,156 | $28,152 | $31,557 | $7,975 | ($201) |
| Second\tQuarter | $44,037 | $50,183 | $128,976 | $15,207 | $6,945 |
| Third\tQuarter | $80,833 | $50,004 | $78,470 | $26,373 | $10,314 |
| Fourth\tQuarter | $8,466 | $29,813 | $35,128 | ($5,615) | ($958) |

Part	I	Item	1

Entergy	Corporation,	Utility	operating	companies,	and	System	Energy

# ENTERGY'S	BUSINESS

Entergy	 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	aggregate	electric	generating	capacity,	including	over 10,000	MW	of	nuclear-fueled	capacity.	Entergy's	Utility	business	delivers	electricity	to	2.8	million	utility	customers	in	Arkansas,	Louisiana, Mississippi,	and	Texas.		Entergy	generated	annual	revenues	of	$11.4	billion	in	2013	and	had	approximately	14,000	employees	as	of	December	31, 2013.

See	Note	13	to	the	financial	statements	for	financial	information	regarding	Entergy's	business	segments.

# Strategy

Entergy's	mission	is	to	operate	a	world-class	energy	business	that	creates	sustainable	value	for	its	owners,	customers,	employees	and communities.	Entergy	aspires	to	achieve	top	quartile	total	shareholder	returns	in	a	socially	and	environmentally	responsible	fashion	by	leveraging the	scale	and	expertise	inherent	in	its	core	utility	and	nuclear	operations.		Entergy's	current	scope	includes	electricity	generation,	transmission, and	distribution	as	well	as	natural	gas	distribution.		Entergy	focuses	on	operational	excellence	with	an	emphasis	on	safety,	reliability,	customer service,	sustainability,	cost	efficiency,	risk	management,	and	engaged	employees.		Entergy	also	continually	seeks	opportunities	to	grow	its	utility business	to	benefit	all	stakeholders	and	to	optimize	its	portfolio	of	assets	in	an	ever-dynamic	market	through	periodic	buy,	build,	hold,	or	disposal decisions.

The	 Utility	 business	 segment	 includes	 six	 wholly-owned	 retail	 electric	 utility	 subsidiaries:	 Entergy	Arkansas,	 Entergy	 Gulf	 States Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas.		These	companies	generate,	transmit,	distribute	and sell	electric	power	to	retail	and	wholesale	customers	in	Arkansas,	Louisiana,	Mississippi,	and	Texas.		Entergy	Gulf	States	Louisiana	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	Utility	is	System	Energy,	a	wholly-owned	subsidiary	of	Entergy	Corporation	that	owns	or	leases	90	percent	of Grand	Gulf.	 	System	Energy	sells	 its	power	and	capacity	from	Grand	Gulf	at	wholesale	 to	Entergy	Arkansas,	Entergy	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans.		The	six	retail	utility	subsidiaries	are	each	regulated	by	the	FERC	and	by	state	utility	commissions,	or,	in the	case	of	Entergy	New	Orleans,	the	City	Council.		System	Energy	is	regulated	by	the	FERC	because	all	of	its	transactions	are	at	wholesale.		The overall	generation	portfolio	of	the	Utility,	which	relies	heavily	on	natural	gas	and	nuclear	generation,	is	consistent	with	Entergy's	strong	support for	the	environment.

# Customers

As	of	December	31,	2013,	the	Utility	operating	companies	provided	retail	electric	and	gas	service	to	customers	in	Arkansas,	Louisiana,

Mississippi,	and	Texas,	as	follows:

(a) Excludes	the	Algiers	area	of	the	city,	where	Entergy	Louisiana	provides	electric	service.

# Electric	Energy	Sales

The	electric	energy	sales	of	the	Utility	operating	companies	are	subject	to	seasonal	fluctuations,	with	the	peak	sales	period	normally occurring	during	the	third	quarter	of	each	year.		On	August	8,	2013,	Entergy	reached	a	2013	peak	demand	of	21,581	MWh,	compared	to	the	2012 peak	of	21,866	MWh	recorded	on	July	30,	2012.		Selected	electric	energy	sales	data	is	shown	in	the	table	below:

# Selected	2013	Electric	Energy	Sales	Data

|  | Entergy<br>Arkansas | Gulf	States<br>Louisiana | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy | Entergy<br>(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tGWh) |  |  |  |  |
| Sales\tto\tretail\n\tcustomers | 20,860 | 19,663 | 32,222 | 13,118 | 5,104 | 16,814 | — | 107,781 |
| Sales\tfor\tresale: |  |  |  |  |  |  |  |  |
| Affiliates | 7,918 | 6,580 | 1,844 | 1,543 | 495 | 6,287 | 9,794 | — |
| Others | 1,011 | 888 | 92 | 304 | 13 | 712 | — | 3,020 |
| Total | 29,789 | 27,131 | 34,158 | 14,965 | 5,612 | 23,813 | 9,794 | 110,801 |
| Average\tuse\tper |  |  |  |  |  |  |  |  |
| residential\tcustomer |  |  |  |  |  |  |  |  |
| (kWh) | 13,537 | 15,531 | 15,019 | 15,226 | 12,479 | 15,544 | — | 14,683 |

(a) Includes	the	effect	of	intercompany	eliminations.

The	following	table	illustrates	the	Utility	operating	companies'	2013	combined	electric	sales	volume	as	a	percentage	of	total	electric	sales volume,	and	2013	combined	electric	revenues	as	a	percentage	of	total	2013	electric	revenue,	each	by	customer	class.

| Customer	Class | %	of	Sales	Volume | %	of	Revenue |
| :--- | :--- | :--- |
| Residential | 31.7 | 38.0 |
| Commercial | 25.8 | 27.0 |
| Industrial\t(a) | 37.6 | 26.9 |
| Governmental | 2.2 | 2.4 |
| Wholesale/Other | 2.7 | 5.7 |

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

See	"Selected	Financial	Data"	for	each	of	the	Utility	operating	companies	for	the	detail	of	their	sales	by	customer	class	for	2009-2013.

# Selected	2013	Natural	Gas	Sales	Data

Entergy	New	Orleans	and	Entergy	Gulf	States	Louisiana	provide	both	electric	power	and	natural	gas	to	retail	customers.		Entergy	New Orleans	and	Entergy	Gulf	States	Louisiana	sold	10,436,919	and	6,816,023	Mcf,	respectively,	of	natural	gas	to	retail	customers	in	2013.		In	2013, 97%	of	Entergy	Gulf	States	Louisiana's	operating	revenue	was	derived	from	the	electric	utility	business,	and	only	3%	from	the	natural	gas distribution	business.		For	Entergy	New	Orleans,	85%	of	operating	revenue	was	derived	from	the	electric	utility	business	and	15%	from	the natural	gas	distribution	business	in	2013.		Following	is	data	concerning	Entergy	New	Orleans's	2013	retail	operating	revenue	sources.

| Customer	Class | Electric	Operating<br>Revenue | Natural	Gas<br>Revenue |
| :--- | :--- | :--- |
| Residential | 41% | 50% |
| Commercial | 38% | 26% |
| Industrial | 7% | 7% |
| Governmental/Municipal | 14% | 17% |

# Retail	Rate	Regulation

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

Each	Utility	operating	company	regularly	participates	in	retail	rate	proceedings.		The	status	of	material	retail	rate	proceedings	is	described in	Note	2	to	the	financial	statements.		Certain	aspects	of	the	Utility	operating	companies'	retail	rate	mechanisms	are	discussed	below.

Entergy	Arkansas's	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.		The	energy	cost	recovery	rider	tariff	also	allows	an	interim	rate	request depending	upon	the	level	of	over-	or	under-recovery	of	fuel	and	purchased	energy	costs.		In	December	2007	the	APSC	issued	an	order	stating	that Entergy	Arkansas's	energy	cost	recovery	rider	will	remain	in	effect,	and	any	future	termination	of	the	rider	would	be	subject	to	eighteen	months advance	notice	by	the	APSC,	which	would	occur	following	notice	and	hearing.

# Storm	Cost	Recovery

See	Note	2	to	the	financial	statements	for	a	discussion	of	proceedings	regarding	recovery	of	Entergy	Arkansas's	storm	restoration	costs.

# Fuel	Recovery

Entergy	Gulf	States	Louisiana's	electric	rates	include	a	fuel	adjustment	clause	designed	to	recover	the	cost	of	fuel	and	purchased	power costs.		The	fuel	adjustment	clause	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,	including	carrying	charges.	See	Note	2	to	the	financial statements	for	a	discussion	of	proceedings	related	to	audits	of	Entergy	Gulf	States	Louisiana's	fuel	adjustment	clause	filings.

To	help	stabilize	electricity	costs,	Entergy	Gulf	States	Louisiana	received	approval	from	the	LPSC	to	hedge	its	exposure	to	natural	gas price	volatility	through	the	use	of	financial	instruments.		Entergy	Gulf	States	Louisiana	hedges	approximately	one-third	of	the	projected	exposure to	natural	gas	price	changes	for	the	gas	used	to	serve	its	native	electric	load	for	all	months	of	the	year.		The	hedge	quantity	is	reviewed	on	an annual	basis.

Entergy	Gulf	States	Louisiana's	gas	rates	include	a	purchased	gas	adjustment	clause	based	on	estimated	gas	costs	for	the	billing	month adjusted	by	a	surcharge	or	credit	that	arises	from	an	annual	reconciliation	of	fuel	costs	incurred	with	fuel	cost	revenues	billed	to	customers, including	carrying	charges.

To	help	stabilize	retail	gas	costs,	Entergy	Gulf	States	Louisiana	received	approval	from	the	LPSC	to	hedge	its	exposure	to	natural	gas price	volatility	for	its	gas	purchased	for	resale	through	the	use	of	financial	instruments.		Entergy	Gulf	States	Louisiana	hedges	approximately	one- half	of	the	projected	natural	gas	volumes	used	to	serve	its	natural	gas	customers	for	November	through	March.		The	hedge	quantity	is	reviewed	on an	annual	basis.

See	Note	2	to	the	financial	statements	for	a	discussion	of	Entergy	Gulf	States	Louisiana's	filings	to	recover	storm-related	costs.

Entergy	Louisiana's	rate	schedules	include	a	fuel	adjustment	clause	designed	to	recover	the	cost	of	fuel	and	purchased	power	costs.		The fuel	 adjustment	 clause	 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,	including	carrying	charges.	See	Note	2	to	the	financial statements	for	a	discussion	of	proceedings	related	to	audits	of	Entergy	Louisiana's	fuel	adjustment	clause	filings.

To	 help	 stabilize	 electricity	 costs,	 Entergy	 Louisiana	 received	 approval	 from	 the	 LPSC	 to	 hedge	 its	 exposure	 to	 natural	 gas	 price volatility	through	the	use	of	financial	instruments.		Entergy	Louisiana	hedges	approximately	one-third	of	the	projected	exposure	to	natural	gas price	changes	for	the	gas	used	to	serve	its	native	electric	load	for	all	months	of	the	year.		The	hedge	quantity	is	reviewed	on	an	annual	basis.

See	Note	2	to	the	financial	statements	for	a	discussion	of	Entergy	Louisiana's	filings	to	recover	storm-related	costs.

Entergy	Mississippi's	rate	schedules	include	energy	cost	recovery	riders	to	recover	fuel	and	purchased	energy	costs.		The	energy	cost	rate for	each	calendar	year	is	redetermined	annually	and	includes	a	true-up	adjustment	reflecting	the	over-recovery	or	under-recovery	of	the	energy costs	as	of	the	12-month	period	ended	September	30.		Entergy	Mississippi's	fuel	cost	recoveries	are	subject	to	annual	audits	conducted	pursuant	to the	authority	of	the	MPSC.

# Power	Management	Rider

The	MPSC	approved	the	purchase	of	the	Attala	power	plant	in	November	2005.		In	December	2005	the	MPSC	issued	an	order	approving the	investment	cost	recovery	through	Entergy	Mississippi's	power	management	rider.	 	Entergy	Mississippi	is	allowed	to	recover	the	annual ownership	costs	of	the	Attala	plant	through	the	power	management	rider	until	it	files	a	general	rate	case.		The	MPSC	approved	the	purchase	of	the Hinds	power	plant	in	February	2012.		In	August	and	October	2012,	the	MPSC	issued	orders	approving	the	investment	cost	recovery	through Entergy	Mississippi's	power	management	rider.		The	orders	have	the	effect	of	allowing	Entergy	Mississippi	to	recover	the	annual	ownership	costs of	the	Hinds	plant	until	it	files	a	general	rate	case.		Entergy	Mississippi	acquired	the	Hinds	plant	on	November	30,	2012.		Recovery	of	the	Hinds plant	costs	through	the	power	management	rider	commenced	with	January	2013	bills.

To	help	stabilize	electricity	costs,	Entergy	Mississippi	received	approval	from	the	MPSC	to	hedge	its	exposure	to	natural	gas	price volatility	through	the	use	of	financial	instruments.		Entergy	Mississippi	hedges	approximately	one-third	of	the	projected	exposure	to	natural	gas price	changes	for	the	gas	used	to	serve	its	native	electric	load	for	all	months	of	the	year.		The	hedge	quantity	is	reviewed	on	an	annual	basis.

Entergy	 Mississippi	 maintains	 a	 storm	 damage	 reserve	 pursuant	 to	 orders	 of	 the	 MPSC	 and	 consistent	 with	 regulatory	 accounting requirements.		Entergy	Mississippi's	storm	damage	provision	is	funded	through	its	storm	damage	rider	schedule.		In	two	orders	issued	in	July 2012,	the	MPSC	temporarily	increased	Entergy	Mississippi's	storm	damage	provision	monthly	accrual	from	$750,000	to	$2.0	million	for	bills rendered	during	the	billing	months	of	August	2012	through	December	2012,	and	approved	recovery	of	$14.9	million	in	prudently	incurred	storm costs	to	be	amortized	over	five	months,	beginning	with	August	2012	bills.		Beginning	with	January	2013	bills,	the	monthly	accrual	to	the	storm damage	provision	reverted	back	to	$750,000.		On	July	1,	2013,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a	joint stipulation,	in	which	both	parties	agreed	that	approximately	$32	million	in	storm	restoration	costs	incurred	in	2011	and	2012	were	prudently incurred	and	chargeable	to	storm	damages,	while	approximately	$700,000	in	prudently	incurred	costs	were	more	properly	recoverable	through	the formula	rate	plan.	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	also	agreed	that	the	storm	damage	accrual	should	be	increased from	$750,000	per	month	to	$1.75	million	per	month.	In	September	2013	the	MPSC	approved	the	joint	stipulation	with	the	increase	in	the	storm damage	accrual	effective	with	October	2013	bills.

The	MPSC	has	also	ordered	that	Entergy	Mississippi	will	annually	submit	its	storm	costs	for	audit.

Entergy	New	Orleans's	gas	rate	schedules	include	a	purchased	gas	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	October	2005	the	City Council	approved	modification	of	the	current	gas	cost	collection	mechanism	effective	November	2005	in	order	to	address	concerns	regarding	its fluctuations,	particularly	during	the	winter	heating	season.		The	modifications	are	intended	to	minimize	fluctuations	in	gas	rates	during	the	winter months.

See	Note	2	to	the	financial	statements	for	a	discussion	of	Entergy	New	Orleans's	efforts	to	recover	storm-related	costs.

Entergy	Texas's	rate	schedules	include	a	fixed	fuel	factor	to	recover	fuel	and	purchased	power	costs,	including	interest,	that	are	not included	in	base	rates.		Semi-annual	revisions	of	the	fixed	fuel	factor	are	made	in	March	and	September	based	on	the	market	price	of	natural	gas and	changes	in	fuel	mix.		The	amounts	collected	under	Entergy	Texas's	fixed	fuel	factor	and	any	interim	surcharge	or	refund	are	subject	to	fuel reconciliation	proceedings	before	the	PUCT.		The	PUCT	fuel	cost	reviews	are	discussed	in	Note	2	to	the	financial	statements.

See	Note	2	to	the	financial	statements	for	a	discussion	of	proceedings	regarding	recovery	of	Entergy	Texas's	storm	restoration	costs.

# Electric	Industry	Restructuring

In	June	2009,	a	law	was	enacted	in	Texas	that	required	Entergy	Texas	to	cease	all	activities	relating	to	Entergy	Texas's	transition	to competition.		The	law	allows	Entergy	Texas	to	remain	a	part	of	the	SERC	Region,	although	it	does	not	prevent	Entergy	Texas	from	joining another	power	region.		The	law	provides	that	proceedings	to	certify	a	power	region	that	Entergy	Texas	belongs	to	as	a	qualified	power	region	can be	initiated	by	the	PUCT,	or	on	motion	by	another	party,	when	the	conditions	supporting	such	a	proceeding	exist.		Under	the	law,	the	PUCT	may not	approve	a	transition	to	competition	plan	for	Entergy	Texas	until	the	expiration	of	four	years	from	the	PUCT's	certification	of	Entergy	Texas's power	region.

The	law	also	contains	provisions	that	allow	Entergy	Texas	to	take	advantage	of	a	cost	recovery	mechanism	that	permits	annual	filings	for the	 recovery	 of	 reasonable	 and	 necessary	 expenditures	 for	 transmission	 infrastructure	 improvement	 and	 changes	 in	 wholesale	 transmission charges.		This	mechanism	was	previously	available	to	other	non-ERCOT	Texas	utility	companies,	but	not	to	Entergy	Texas.

In	September	2011,	the	PUCT	adopted	a	proposed	rule	implementing	a	Distribution	Cost	Recovery	Factor	to	recover	capital	and	capital- related	costs	related	to	distribution	infrastructure.		The	Distribution	Cost	Recovery	Factor

permits	utilities	once	per	year	to	implement	an	increase	or	decrease	in	rates	above	or	below	amounts	reflected	in	base	rates	to	reflect	depreciation expense,	federal	income	tax	and	other	taxes,	and	return	on	investment.		The	Distribution	Cost	Recovery	Factor	rider	may	be	changed	a	maximum of	four	times	between	base	rate	cases,	and	expires	in	January	2017,	unless	otherwise	extended	by	the	Texas	Legislature.

The	law	further	amended	already	existing	law	that	had	required	Entergy	Texas	to	propose	for	PUCT	approval	a	tariff	to	allow	eligible customers	the	ability	to	contract	for	competitive	generation.		The	amending	language	in	the	law	provides,	among	other	things,	that:		1)	the	tariff shall	not	be	implemented	in	a	manner	that	harms	the	sustainability	or	competitiveness	of	manufacturers	who	choose	not	to	participate	in	the	tariff; 2)	Entergy	Texas	shall	"purchase	competitive	generation	service,	selected	by	the	customer,	and	provide	the	generation	at	retail	to	the	customer"; and	3)		Entergy	Texas	shall	provide	and	price	transmission	service	and	ancillary	services	under	that	tariff	at	a	rate	that	is	unbundled	from	its	cost of	service.				The	law	directs	that	the	PUCT	may	not	issue	an	order	on	the	tariff	that	is	contrary	to	an	applicable	decision,	rule,	or	policy	statement of	a	federal	regulatory	agency	having	jurisdiction.

Entergy	Texas	and	the	other	parties	to	the	PUCT	proceeding	to	determine	the	design	of	the	competitive	generation	tariff	were	involved	in negotiations	throughout	2011	and	2012	with	the	objective	of	resolving	as	many	disputed	issues	as	possible	regarding	the	tariff.		The	PUCT determined	that	unrecovered	costs	that	could	be	recovered	through	the	rider	consist	only	of	those	costs	necessary	to	implement	and	administer	the competitive	generation	program	and	do	not	include	lost	revenues	or	embedded	generation	costs.	 	The	PUCT	also	ruled	 that	 the	amount	of customer	load	that	may	be	included	in	the	competitive	generation	service	program	is	limited	to	115	MW.		After	additional	negotiations,	and ultimately	the	scheduling	of	a	hearing	to	resolve	remaining	contested	issues,	the	PUCT	issued	the	order	approving	the	competitive	generation service	rider	in	July	2013.	Entergy	Texas	filed	for	rehearing	of	the	PUCT's	July	2013	order,	which	the	PUCT	denied.	Entergy	Texas	has	since filed	its	appeal	of	that	PUCT	order	to	the	Travis	County	District	Courts,	where	this	matter	remains	pending.

# 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	pursuant	to	the	terms	of	the	franchise	agreement	and	applicable	statutes.

Entergy	Gulf	States	Louisiana	holds	non-exclusive	franchises	to	provide	electric	service	in	approximately	56	incorporated	municipalities and	the	unincorporated	areas	of	approximately	18	parishes,	and	to	provide	gas	service	in	the	City	of	Baton	Rouge	and	the	unincorporated	areas	of two	parishes.		Most	of	Entergy	Gulf	States	Louisiana's	franchises	have	a	term	of	60	years.		Entergy	Gulf	States	Louisiana's	current	electric franchises	expire	during	2015-2055.

Entergy	 Louisiana	 holds	 non-exclusive	 franchises	 to	 provide	 electric	 service	 in	 approximately 116 incorporated	 Louisiana municipalities.		Most	of	these	franchises	have	25-year	terms.		Entergy	Louisiana	also	supplies	electric	service	in	approximately	45	Louisiana parishes	in	which	it	holds	non-exclusive	franchises.		Entergy	Louisiana's	electric	franchises	expire	during	2015-2039.

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	indeterminate	permits	set	forth	in	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's	electric	and	gas	utility	properties.

Entergy	Texas	holds	a	certificate	of	convenience	and	necessity	from	the	PUCT	to	provide	electric	service	to	areas	within	approximately 27 counties	 in	 eastern	 Texas,	 and	 holds	 non-exclusive	 franchises	 to	 provide	 electric	 service	 in	 approximately 68 incorporated municipalities.		Entergy	Texas	was	typically	granted	50-year	franchises,	but	recently	has	been	receiving	25-year	franchises.		Entergy	Texas's electric	franchises	expire	during	2014-2058.

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	 Utility	 operating companies and	 System	 Energy as	 of December	31,	2013,	is	indicated	below:

|  |  | Owned	and	Leased	Capability	MW(a) | Owned	and	Leased	Capability	MW(a) |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Company | Total | Gas/Oil | Nuclear | Coal | Hydro |
| Entergy\tArkansas | 4,736 | 1,646 | 1,819 | 1,197 | 74 |
| Entergy\tGulf\tStates\tLouisiana | 2,969 | 1,634 | 968 | 367 | — |
| Entergy\tLouisiana | 6,059 | 4,903 | 1,156 | — | — |
| Entergy\tMississippi | 3,420 | 3,000 | — | 420 | — |
| Entergy\tNew\tOrleans | 781 | 781 | — | — | — |
| Entergy\tTexas | 2,554 | 2,283 | — | 271 | — |
| System\tEnergy | 1,272 | — | 1,272 | — | — |
| Total | 21,791 | 14,247 | 5,215 | 2,255 | 74 |

(a) "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.

The	Entergy	System'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 load,	and	the	economy.		Summer	peak	load	in	the	Entergy	System	service	territory	has	averaged	21,408	MW	from	2003-2013.		In	the	2002	time period	the	Entergy	System's	long-term	capacity	resources,	allowing	for	an	adequate	reserve	margin,	were	approximately	3,000	MW	less	than	the total	capacity	required	for	peak	period	demands.		In	this	time	period	the	Entergy	System	met	its	capacity	shortages	almost	entirely	through	short- term	power	purchases	in	the	wholesale	spot	market.		In	the	fall	of	2002	the	Entergy	System	began	a	program	to	add	new	resources	to	its	existing generation	portfolio	and	began	a	process	of	issuing	requests	for	proposals	(RFP)	to	procure	supply-side	resources	from	sources	other	than	the	spot market	to	meet	the	unique	regional	needs	of	the	Utility	operating	companies.		The	Entergy	System	has	adopted	a	long-term	resource	strategy,	the "Portfolio	 Transformation	 Strategy,"	 that	 calls	 for	 the	 bulk	 of	 capacity	 needs	 to	 be	 met	 through	 long-term	 resources,	 whether	 owned	 or contracted.		Over	the	past	eleven	years,	the	Portfolio	Transformation	has	resulted	in	the	addition	of	about	5,798	MW	of	new	long-term	resources. The	Entergy	Operating	Companies,	in	aggregate,	are	projected	to	have	approximately	580	MW	more	than	their	minimum	capacity	requirements needed	to	meet	MISO	Resource	Adequacy	for	2014.	The	Entergy	System	will	rely	upon	MISO's	Day	2	market	to	economically	purchase	energy to	minimize	customer	cost.	Finally,	the	resource	planning	processes	consider	the	Entergy	Arkansas	exit	from	the	System	Agreement	on	December 19,	2013	and	both	Entergy	Mississippi's	and	Entergy	Texas's	notices	of	their	future	withdrawal	from	the	System	Agreement.

# RFP	Procurements

The	RFPs	 issued	by	 the	Entergy	System	since	 the	fall	of	2002	have	sought	resources	needed	 to	meet	near-term	summer	reliability requirements	as	well	as	longer-term	requirements	through	a	broad	range	of	wholesale	power	products,	including	limited-term	(1	to	3	years)	and long-term	contractual	products	and	asset	acquisitions.		Detailed	evaluation	processes	have	been	developed	to	analyze	submitted	proposals,	and, with	the	exception	of	the	January	2008	RFP,	the	2008	Western	Region	RFP,	the	2010	Renewable	RFP,	and	the	2011	Entergy	Arkansas	RFP,	each RFP	has	been	overseen	by	an	independent	monitor.		The	following	table	illustrates	the	results	of	the	RFP	process	for	resources	acquired	since	the Fall	2002	RFP.		The	contracts	below	were	primarily	with	non-affiliated	suppliers,	with	the	exception	of	contracts	with	EWO	Marketing	for	the sale	 of	 185	 MW	 to	 206	 MW	 from	 the	 RS	 Cogen	 plant,	 contracts	 with	 Entergy	 Power	 for	 the	 sale	 of	 approximately	 100	 MW	 from	 the Independence	plant,	and	an	MSS-4	agreement	between	Entergy	Arkansas	and	Entergy	Mississippi	for	the	purchase	of	approximately	60	MW	of Grand	Gulf	capacity	and	energy	(with	deliveries	starting	January	1,	2013).

| RFP | Short-<br>term	3rd<br>party | Limited-term<br>affiliate | Limited-<br>term	3rd<br>party | Long-term<br>affiliate | Long-term<br>3rd	party | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Fall\t2002 |  | 185-206\tMW\t(a) | 231\tMW | 101-121\tMW\t(b) | 718\tMW\t(d) | 1,235-1,276\tMW |
| January\t2003\tsupplemental | 222\tMW | — | — | — | — | 222\tMW |
| Spring\t2003 | — | — | 381\tMW | (c) | — | 381\tMW |
| Fall\t2003 | — | — | 390\tMW | — | — | 390\tMW |
| Fall\t2004 | — | — | 1,250\tMW | — | — | 1,250\tMW |
| 2006\tLong-Term | — | — | — | 538\tMW\t(e) | 789\tMW\t(f) | 1,327\tMW |
| Fall\t2006 | — | — | 780\tMW | — | — | 780\tMW |
| January\t2008\t(g) | — | — | — | — | — | — |
| 2008\tWestern\tRegion | — | — | 300\tMW | — | — | 300\tMW |
| Summer\t2008\t(h) | — | — | 200\tMW | — | — | 200\tMW |
| January\t2009\tWestern\nRegion | — | — | — | — | 150-300\tMW | 150-300\tMW |
| July\t2009\tBaseload | — | 336\tMW\t(i) | — | — | — | 336\tMW |
| Summer\t2009\tLong-Term\t(j) | — | — | — | 551\tMW | 1,555\tMW | 2,106\tMW |
| 2010\tRenewable\tRFP | — | — | — | — | 37-40\tMW\t(k) | 37-40\tMW |
| 2011\tEntergy\tArkansas\tRFP | — | — | 495\tMW | — | — | 495\tMW |
| 2011\tWestern\tRFP\t(1) | — | — | — | — | — | — |
| 2012\tBaseload\tRFP\t(m) | — | — | — | 60\tMW | — | 60\tMW |

(a) Includes	a	conditional	option	to	increase	the	capacity	up	to	the	upper	bound	of	the	range.

(c) This	table	does	not	reflect	(i)	the	River	Bend	30%	life-of-unit	purchased	power	agreements	totaling	approximately	300	MW	between Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	(200	MW),	and	between	Entergy	Gulf	States	Louisiana	and	Entergy	New	Orleans (100	MW)	related	to	Entergy	Gulf	States	Louisiana's	unregulated	portion	of	the	River	Bend	nuclear	station,	which	portion	was	formerly owned	by	Cajun	or	(ii)	the	Entergy	Arkansas	wholesale	base	load	capacity	life-of-unit	purchased	power	agreements	executed	in	2003 totaling	approximately	220	MW	between	Entergy	Arkansas	and	Entergy	Louisiana	(110	MW)	and	between	Entergy	Arkansas	and	Entergy New	Orleans	(110	MW)	related	to	the	sale	of	a	portion	of	Entergy	Arkansas's	coal	and	nuclear	base	load	resources	(which	were	not included	in	retail	rates);	or	(iii)	12-month	agreements	originally	executed	in	2005	and	which	are	renewed	annually	between	Entergy Arkansas	and	Entergy	Gulf

States	Louisiana	and	Entergy	Texas,	and	between	Entergy	Arkansas	and	Entergy	Mississippi,	relating	to	the	sale	of	a	portion	of	Entergy Arkansas's	coal	and	nuclear	base	load	resources	(which	were	not	included	in	retail	rates)	to	those	companies.		These	resources	were identified	outside	of	the	formal	RFP	process	but	were	submitted	as	formal	proposals	in	response	to	the	Spring	2003	RFP,	which	confirmed the	economic	merits	of	these	resources.

(d) Entergy	Louisiana's	June	2005	purchase	of	the	718	MW,	gas-fired	Perryville	plant,	of	which	a	total	of	75%	of	the	output	is	sold	to	Entergy Gulf	States	Louisiana	and	Entergy	Texas.

(e) In	2011,	the	LPSC	approved	Entergy	Louisiana's	cancellation	of	the	Little	Gypsy	Unit	3	re-powering	project	selected	from	the	2006 Long-Term	RFP.

(f) Entergy	Arkansas's	September	2008	purchase	of	the	789	MW,	combined-cycle,	gas-fired	Ouachita	Generating	Facility,	of	which	one-third of	the	output	was	sold	to	Entergy	Gulf	States	Louisiana	prior	to	the	purchase	of	one-third	of	the	facility	by	Entergy	Gulf	States	Louisiana in	November	2009.

(g) At	the	direction	of	the	LPSC,	but	with	full	reservation	of	all	legal	rights,	Entergy	Services	issued	the	January	2008	RFP	for	Supply-Side Resources	seeking	fixed	price	unit	contingent	products.		Although	the	LPSC	request	was	directed	to	Entergy	Gulf	States	Louisiana	and Entergy	Louisiana,	Entergy	Services	issued	the	RFP	on	behalf	of	all	of	the	Utility	operating	companies.		No	proposals	were	selected	from this	RFP.

(h) In	October	2008,	in	response	to	the	U.S.	financial	crisis,	Entergy	Services	on	behalf	of	the	Utility	operating	companies	terminated	all	long- term	procurement	efforts,	including	the	long-term	portion	of	the	Summer	2008	RFP.

(i) Represents	the	self-supply	alternative	considered	in	the	RFP,	consisting	of	a	cost-based	purchase	by	Entergy	Texas,	Entergy	Louisiana, and	Entergy	Mississippi	of	wholesale	baseload	capacity	from	Entergy	Arkansas.

(j) Includes	the	Ninemile	self-build	option,	acquisitions	from	KGen	of	its	Hinds	and	Hot	Spring	facilities,	and	a	long-term	PPA	with	Calpine Carville.

(k) Three	transactions	executed	as	a	result	of	the	RFP	are	reflected	in	the	table,	however	one	transaction	is	still	pending	regulatory	approval.

(l) Negotiations	with	the	potential	supplier	for	a	definitive	agreement	arising	out	of	the	2011	Western	Region	RFP	have	been	discontinued. Entergy	Texas	does	not	intend	to	pursue	any	other	proposal	submitted	in	the	RFP.

(m) Only	includes	the	agreement	resulting	from	the	RFP	for	Entergy	Mississippi	to	purchase	capacity	and	energy	from	Entergy	Arkansas	from Grand	Gulf	(60	MW).

On	March	21,	2012	the	LPSC	approved	Entergy	Louisiana's	application	to	construct	a	nominally-sized	550	MW	combined-cycle	gas turbine	generating	facility	(Ninemile	6)	at	its	existing	Ninemile	Point	electric	generating	station	that	was	selected	in	the	Summer	2009	Long-Term RFP.	The	facility	is	expected	to	be	substantially	completed	as	early	as	the	fourth	quarter	of	2014.	For	additional	discussion	of	the	Ninemile	6 project	 see	 "Capital	 Expenditure	 Plans	 and	 Other	 Uses	 of	 Capital"	in	 Entergy	 Corporation	 and	 Subsidiaries	 Management's	 Financial Discussion	and	Analysis.

In	December	2010	on	behalf	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana,	Entergy	Services	issued	the	2010	RFP	for	Long- Term	Renewable	Energy	Resources	seeking	up	to	233	MW	of	renewable	generation	resources	to	meet	the	requirements	of	an	LPSC	general	order issued	on	December	9,	2010.		In	September	2012,	Entergy	Gulf	States	Louisiana	executed	a	20-year	contract	for	28	MW,	with	the	potential	to purchase	an	additional	9	megawatts	when	available,	from	Rain	CII	Carbon	LLC's	pet	coke	calcining	facility	in	Sulphur,	Louisiana.		The	facility began	commercial	operation	in	May	2013.		LPSC	certification	of	the	contract	was	received	in	December	2012.	In	 March	2013,	Entergy	Gulf States	Louisiana	executed	a	20-year	contract	for	8.5	MW	from	Agrilectric	Power	Partners,	LP's	refurbished	rice	hull-fueled	electric	generation facility	located	in	Lake	Charles,	Louisiana.	LPSC	certification	of	the	contract	was	received	in	July	2013.	In	September	2013,	Entergy	Louisiana executed	a	10-year	contract	with	TX	LFG	Energy,	LP,	a	wholly-owned	subsidiary	of	Montauk	Energy	Holdings,	LLC,	to	purchase	approximately 3	MW	from	its	landfill	gas-fueled	power	generation	facility	located	in	Cleveland,	Texas	and	filed	with	the	LPSC	an	application	seeking	approval and	cost	recovery	for	the	contract.

In	June	2011	on	behalf	of	Entergy	Arkansas,	Entergy	Services	issued	the	2011	RFP	for	Transition	Plan	Resources.		The	RFP	sought	up	to 750	MW	of	flexible	generation	resources	through	one	or	more	purchased	power

agreements	to	address	Entergy	Arkansas's	requirements	for	its	2014-2016	time	frame.		Entergy	Arkansas	concluded	its	review	and	evaluation	of the	proposals	submitted	in	response	to	the	RFP	in	November	2011	and	selected	two	proposals	totaling	approximately	795	MW	for	negotiation	of definitive	agreements.		In	October	2012,		Entergy	Arkansas	and	Union	Power	Partners,	L.P.	executed	a	3	½	year	agreement	for	495	MW	from	the Union	Power	Station	located	in	El	Dorado,	Arkansas.		Cost	recovery	for	this	agreement	was	approved	within	Entergy	Arkansas's	general	rate	case filed	in	March	2013.

In	August	2012,	Entergy	Services	issued	a	request	for	proposals	for	long-term,	stable	price,	baseload	resources	on	behalf	of	Entergy	Gulf States	Louisiana,	Entergy	Louisiana,	Entergy	New	Orleans,	Entergy	Texas,	and	Entergy	Mississippi.	The	RFP	sought	between	50	and	150	MW	of baseload	capacity	through	a	PPA	commencing	in	2013	for	a	minimum	of	10	years	up	to	life	of	unit.	As	part	of	the	RFP	process,	Entergy	Services market-tested	a	self-supply	alternative,	which	was	a	cost-based	purchase	of	60	MW	from	Entergy	Arkansas's	share	of	Grand	Gulf.	Based	on	the RFP	evaluation	results,	in	November	2012,	Entergy	elected	to	proceed	with	the	self-supply	alternative	and	elected	not	to	move	forward	with	any other	 proposal.	The	capacity	and	associated	energy	was	subsequently	allocated	to	Entergy	Mississippi,	and	MPSC	and	FERC	approval	was received	for	the	 transaction	 in	December	2012.	Entergy	Mississippi	also	transacted	for	an	additional	30	MW	purchase,	which	did	not	come through	the	RFP	process,	of	capacity	and	energy	from	Entergy	Arkansas's	share	of	Grand	Gulf.	Deliveries	under	both	agreements,	totaling	90 MW,	began	on	January	1,	2013,	and	cost	recovery	for	the	90	MW	was	approved	by	the	MPSC	in	January	2013.

# Other	Procurements	From	Third	Parties

The	above	table	does	not	include	resource	acquisitions	made	outside	of	the	RFP	process,	including	Entergy	Mississippi's	January	2006 acquisition	of	the	480	MW,	combined-cycle,	gas-fired	Attala	power	plant;	Entergy	Gulf	States	Louisiana's	March	2008	acquisition	of	the	322 MW,	simple-cycle,	gas-fired	Calcasieu	Generating	Facility;	and	Entergy	Louisiana's	April	2011	acquisition	of	the	580	MW,	combined-cycle,	gas- fired	Acadia	Energy	Center	Unit	2.		The	above	table	also	does	not	reflect	various	limited-	and	long-term	contracts	that	have	been	entered	into	in recent	years	by	the	Utility	operating	companies	as	a	result	of	bilateral	negotiations.

# Interconnections

The	Entergy	System'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	provided	dispatch	instructions	by	 the	MISO.	Entergy's	Utility operating	companies	are	MISO	market	participants	and	are	 interconnected	with	many	neighboring	utilities.	 	MISO's	primary	purpose	as	a Regional	Transmission	Organization	is	to	guarantee	a	safe,	cost-effective	delivery	of	electrical	power	and	assure	consumers	of	unbiased	regional grid	management	and	open	access	to	the	transmission	facilities.	In	addition,	the	Utility	operating	companies	are	members	of	the	SERC	Reliability Corporation.		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	Corporation.

# Gas	Property

As	of	December	31,	2013,	Entergy	New	Orleans	distributed	and	transported	natural	gas	for	distribution	within	Algiers	and	New	Orleans, Louisiana,	through	approximately	2,500	miles	of	gas	pipeline.		As	of	December	31,	2013,	the	gas	properties	of	Entergy	Gulf	States	Louisiana, which	are	located	in	and	around	Baton	Rouge,	Louisiana,	were	not	material	to	Entergy	Gulf	States	Louisiana's	financial	position.

# Title

The	 Entergy	 System's	 generating	 stations	 are	 generally	 located	 on	 properties	 owned	 in	 fee	 simple.	 	 Most	 of	 the	 substations	 and transmission	and	distribution	lines	are	constructed	on	private	property	or	public	rights-of-way	pursuant	to	easements,	servitudes,	or	appropriate franchises.		Some	substation	properties	are	owned	in	fee	simple.		The

Utility	operating	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	Louisiana,	Entergy	Louisiana, Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	are	subject	to	the	liens	of	mortgages	securing	bonds	issued	by those	companies.		The	Lewis	Creek	generating	station	is	owned	by	GSG&T,	Inc.,	a	subsidiary	of	Entergy	Texas,	and	is	not	subject	to	its	mortgage lien.		Lewis	Creek	is	leased	to	and	operated	by	Entergy	Texas.

# Fuel	Supply

The	sources	of	generation	and	average	fuel	cost	per	kWh	for	the	Utility	operating	companies	and	System	Energy	for	the	years	2011-2013 were:

|  | Natural	Gas | Natural	Gas | Nuclear | Nuclear |  | Coal | Purchased<br>Power | Purchased<br>Power |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year | %\nof\nGen | Cents\nPer\nkWh | %\nof\nGen | Cents\nPer\nkWh | %\nof\nGen | Cents\nPer\nkWh | %\nof\nGen | Cents\nPer\nkWh |
| 2013 | 26 | 4.12 | 39 | 0.92 | 10 | 2.70 | 25 | 4.32 |
| 2012 | 27 | 3.15 | 33 | 0.85 | 11 | 2.60 | 29 | 3.58 |
| 2011 | 25 | 4.85 | 34 | 0.81 | 13 | 2.31 | 28 | 4.59 |

Actual	2013	and	projected	2014	sources	of	generation	for	the	Utility	operating	companies	and	System	Energy,	including	certain	power purchases	from	affiliates	under	life	of	unit	power	purchase	agreements,	including	the	Unit	Power	Sales	Agreement,	are:

|  | Natural	Gas |  | Nuclear |  | Coal |  | Purchased<br>Power |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2013 | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | 2014 |
| Entergy\tArkansas\t(a) | 10% | 13% | 50% | 57% | 24% | 24% | 16% | 5% |
| Entergy\tGulf\tStates\tLouisiana | 28% | 31% | 27% | 17% | 7% | 13% | 38% | 39% |
| Entergy\tLouisiana | 28% | 21% | 37% | 38% | —% | 1% | 35% | 40% |
| Entergy\tMississippi | 45% | 33% | 24% | 24% | 16% | 16% | 15% | 27% |
| Entergy\tNew\tOrleans | 26% | 24% | 53% | 50% | 4% | 3% | 17% | 23% |
| Entergy\tTexas | 29% | 17% | 12% | 14% | 8% | 11% | 51% | 58% |
| System\tEnergy\t(b) | — | — | 100% | 100% | — | — | — | — |
| Utility\t(a) | 26% | 22% | 39% | 34% | 10% | 12% | 25% | 32% |

(a) Hydroelectric	power	provided	less	than	1%	of	Entergy	Arkansas's	generation	in	2013	and	is	expected	to	provide	less	than	1%	of	its generation	in	2014.

(b) Capacity	and	energy	from	System	Energy's	interest	in	Grand	Gulf	is	allocated	as	follows	under	the	Unit	Power	Sales	Agreement:	Entergy Arkansas	-	36%;	Entergy	Louisiana	-	14%;	Entergy	Mississippi	-	33%;	and	Entergy	New	Orleans	-	17%.		Pursuant	to	purchased	power agreements,	Entergy	Arkansas	is	selling	a	portion	of	its	owned	capacity	and	energy	from	Grand	Gulf	to	Entergy	Gulf	States	Louisiana, Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans.

Some	of	the	Utility's	gas-fired	plants	are	capable	of	also	using	fuel	oil,	if	necessary.		Although	based	on	current	economics	the	Utility	does	not expect	fuel	oil	use	in	2014,	it	is	possible	that	various	operational	events	including	weather	or	pipeline	maintenance	may	require	the	use	of	fuel	oil.

# Natural	Gas

The	Utility	operating	companies	have	long-term	firm	and	short-term	interruptible	gas	contracts	for	both	supply	and	transportation.		Long- term	firm	contracts	for	power	plants	comprise	less	than	25%	of	the	Utility	operating	companies'	total	requirements.		Short-term	contracts	and	spot- market	purchases	satisfy	additional	gas	requirements.		Entergy	Texas	owns	a	gas	storage	facility	that	provides	reliable	and	flexible	natural	gas service	to	certain	generating	stations.

Entergy	Louisiana	entered	into	a	long-term	natural	gas	supply	contract	beginning	January	1,	2013,	in	which	Entergy	Louisiana	purchases natural	gas	in	annual	amounts	equal	to	approximately	one-half	of	its	projected	annual	fuel	requirements	for	certain	generating	units.

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	and	availability	of other	energy	sources.		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	Utility	operating	companies	will	use	alternate	fuels,	such as	oil,	or	rely	to	a	larger	extent	on	coal,	nuclear	generation,	and	purchased	power.

Entergy	Arkansas	has	committed	to	six	one-	to	three-year	contracts	that	will	supply	approximately	90%	of	the	total	coal	supply	needs	in 2014.		These	contracts	are	staggered	in	term	so	that	not	all	contracts	have	to	be	renewed	the	same	year.		The	remaining	10%	of	total	coal requirements	will	be	satisfied	by	contracts	with	a	term	of	less	than	one	year.		Based	on	continued	improved	Powder	River	Basin	(PRB)	coal deliveries	by	rail	and	the	high	cost	of	alternate	sources	and	modes	of	transportation,	no	alternative	coal	consumption	is	expected	at	Entergy Arkansas	during	2014.		Entergy	Arkansas	has	an	existing	railroad	transportation	contract	that	is	expected	to	provide	all	of	Entergy	Arkansas's	coal transportation	requirements	for	2014.

Entergy	Gulf	States	Louisiana	has	committed	to	four	one-	to	three-year	contracts	that	will	supply	approximately	90%	of	Nelson	Unit	6 coal	needs	in	2014.		Additional	PRB	coal	will	be	purchased	through	contracts	with	a	term	of	less	than	one	year	to	provide	the	remaining	supply needs.		For	the	same	reasons	as	for	Entergy	Arkansas's	plants,	no	alternative	coal	consumption	is	expected	at	Nelson	Unit	6	during	2014.		Coal will	be	transported	to	Nelson	via	an	existing	transportation	agreement	that	is	expected	to	provide	all	of	Entergy	Gulf	States	Louisiana's	rail transportation	requirements	for	2014.

For	the	year	2013,	coal	transportation	delivery	to	Entergy	Arkansas	and	Entergy	Gulf	States	Louisiana	operated	coal-fired	units	met	coal demand	at	the	plants	and	it	is	expected	that	delivery	times	experienced	in	2013	will	continue	through	2014.		Both	Entergy	Arkansas	and	Entergy Gulf	States	Louisiana	control	a	sufficient	number	of	railcars	to	satisfy	the	rail	transportation	requirement.

The	operator	of	Big	Cajun	2	-	Unit	3,	Louisiana	Generating,	LLC,	has	advised	Entergy	Gulf	States	Louisiana	and	Entergy	Texas	that	it has	adequate	rail	car	and	barge	capacity	to	meet	the	volumes	of	PRB	coal	requested	for	2014.		Entergy	Gulf	States	Louisiana's	and	Entergy Texas's	coal	nomination	requests	to	Big	Cajun	2	-	Unit	3	are	made	on	an	annual	basis.

# 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	uranium	hexafluoride	gas;

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

The	Registrant	Subsidiaries	that	own	nuclear	plants	(Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System Energy)	are	responsible	through	a	shared	regulated	uranium	pool	for	contracts	to	acquire	nuclear	material	to	be	used	in	fueling	Entergy's	Utility nuclear	units.		These	companies	own	the	materials	and	services	in	this	shared	regulated	uranium	pool	on	a	pro	rata	fractional	basis	determined	by the	nuclear	generation	capability	of	each	company.		Any	liabilities	for	obligations	of	the	pooled	contracts	are	on	a	several	but	not	joint	basis.		The shared	regulated	uranium	pool	maintains	inventories	of	nuclear	materials	during	the	various	stages	of	processing.		The	Registrant	Subsidiaries purchase	enriched	uranium	hexafluoride	for	their	nuclear	plant	reload	requirements	at	 the	average	 inventory	cost	from	 the	shared	regulated uranium	pool.	 	Entergy	Operations	Inc.	contracts	separately	for	the	fabrication	of	nuclear	fuel	as	agent	on	behalf	of	each	of	the	Registrant Subsidiaries	that	owns	a	nuclear	plant.		All	contracts	for	the	disposal	of	spent	nuclear	fuel	are	between	the	Department	of	Energy	(DOE)	and	the owner	of	a	nuclear	power	plant.

Based	upon	currently	planned	fuel	cycles,	the	nuclear	units	in	both	the	Utility	and	Entergy	Wholesale	Commodities	segments	have	a diversified	portfolio	of	contracts	and	inventory	that	provides	substantially	adequate	nuclear	fuel	materials	and	conversion	and	enrichment	services at	what	Entergy	believes	are	reasonably	predictable	or	fixed	prices	through	most	of	2014.		Entergy's	ability	to	purchase	nuclear	fuel	at	reasonably predictable	prices,	however,	depends	upon	the	performance	reliability	of	uranium	miners.		There	are	a	number	of	possible	alternate	suppliers	that may	 be	 accessed	 to	 mitigate	 any	 supplier	 performance	 failure,	 including	 potentially	 drawing	 upon	 Entergy's	 inventory	 intended	 for	 later generation	periods	depending	upon	its	risk	management	strategy	at	that	time,	although	the	pricing	of	any	alternate	uranium	supply	from	the	market will	be	dependent	upon	the	market	for	uranium	supply	at	that	time.		In	addition,	some	nuclear	fuel	contracts	are	on	a	non-fixed	price	basis	subject to	prevailing	prices	at	the	time	of	delivery.

The	effects	of	market	price	changes	may	be	reduced	and	deferred	by	risk	management	strategies,	such	as	negotiation	of	floor	and	ceiling amounts	for	long-term	contracts,	buying	for	inventory	or	entering	into	forward	physical	contracts	at	fixed	prices	when	Entergy	believes	it	is appropriate	and	useful.		Entergy	buys	uranium	from	a	diversified	mix	of	sellers	located	in	a	diversified	mix	of	countries,	and	from	time	to	time purchases	from	nearly	all	qualified	reliable	major	market	participants	worldwide	that	sell	into	the	U.S.

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy	each	have	made	arrangements	to	lease	nuclear fuel	and	related	equipment	and	services.		The	lessors,	which	are	consolidated	in	the	financial	statements	of	Entergy	and	the	applicable	Registrant Subsidiary,	finance	the	acquisition	and	ownership	of	nuclear	fuel	through	credit	agreements	and	the	issuance	of	notes.		These	arrangements	are subject	to	periodic	renewal.

# 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	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	also	makes	interruptible	spot	market	purchases.		In	recent	years,	natural	gas	deliveries	to	Entergy	New Orleans	have	been	subject	primarily	to	weather-related	curtailments.

Entergy	Gulf	States	Louisiana	purchases	natural	gas	for	resale	under	a	firm	contract	from	Enbridge	Marketing	(U.S.)	Inc.		The	gas	is delivered	through	a	combination	of	intrastate	and	interstate	pipelines.

As	a	result	of	the	implementation	of	FERC-mandated	interstate	pipeline	restructuring	in	1993,	curtailments	of	interstate	gas	supply	could occur	if	Entergy	Gulf	States	Louisiana's	or	Entergy	New	Orleans's	suppliers	failed	to	perform	their	obligations	to	deliver	gas	under	their	supply agreements.		Gulf	South	Pipeline	Co.	could	curtail	transportation	capacity	only	in	the	event	of	pipeline	system	constraints.

# Federal	Regulation	of	the	Utility

State	or	local	regulatory	authorities,	as	described	above,	regulate	the	retail	rates	of	the	Utility	operating	companies.		The	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	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy New	Orleans,	and	Entergy	Texas)

The	Utility	operating	companies	historically	have	engaged	in	the	coordinated	planning,	construction,	and	operation	of	generating	and	bulk transmission	facilities	under	the	terms	of	the	System	Agreement,	which	is	a	rate	schedule	that	has	been	approved	by	the	FERC.		Under	the	terms of	the	System	Agreement,	generating	capacity	and	other	power	resources	are	jointly	operated	by	the	Utility	operating	companies.		The	System Agreement	provides,	among	other	things,	that	parties	having	generating	reserves	greater	than	their	allocated	share	of	reserves	(long	companies) shall	receive	payments	from	those	parties	having	generating	reserves	that	are	less	than	their	allocated	share	of	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	 equity,	 and	 a	 fair	 rate	 of	 return	 on	 common	 equity investment.		Under	the	System	Agreement,	the	rates	used	to	compensate	long	companies	are	based	on	costs	associated	with	the	long	companies' steam	electric	generating	units	fueled	by	oil	or	gas	and	having	an	annual	average	heat	rate	above	10,000	Btu/kWh.		In	addition,	for	all	energy exchanged	among	the	Utility	operating	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.

See	 "System	Agreement"	 in	 Entergy	 Corporation	 and	 Subsidiaries	 Management's	 Financial	 Discussion	 and	Analysis	 for	 additional discussion	of	the	System	Agreement,	including	Entergy	Arkansas	terminating	its	participation	in	December	2013	and	other	Utility	operating companies'	notices	to	terminate	participation	in	the	future.	See	Note	2	to	the	financial	statements	for	discussion	of	legal	proceedings	at	the	FERC involving	the	System	Agreement.

# Transmission

See	"Entergy's	Integration	into	the	MISO	Regional	Transmission	Organization"	in	the	"Rate,	Cost-recovery,	and	Other	Regulation	- Federal	Regulation"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

# 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	Utility	operating 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's	and	Entergy	Mississippi's	acceleration	of	Grand	Gulf	purchased	power	obligations	ceased	effective	July 2001	and	July	2003,	respectively,	as	approved	by	the	FERC.

# Unit	Power	Sales	Agreement

The	Unit	Power	Sales	Agreement	allocates	capacity,	energy,	and	the	related	costs	from	System	Energy's	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.		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's	cost	from	its	retained	share.		Entergy	Arkansas	has	life-of-resources	purchased	power	agreements	with	Entergy Louisiana	and	Entergy	New	Orleans	that	sell	a	portion	of	the	output	of	Entergy	Arkansas's	retained	share	of	Grand	Gulf	to	those	companies,	with the	remainder	of	the	retained	share	being	sold	to	Entergy	Mississippi	through	a	separate	life-of-resources	purchased	power	agreement.		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	at	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.	Entergy	Arkansas	also	has	a	life-of-resources	purchased	power agreement	with	Entergy	Mississippi	to	sell	a	portion	of	the	output	of	Entergy	Arkansas's	non-retained	share	of	Grand	Gulf.	Entergy	Mississippi was	granted	rate	relief	for	those	purchases	by	the	MPSC	through	its	annual	rate	mechanism.

# 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	provides	that System	Energy	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	expenses	incurred	in	a	permanent	shutdown	of	Grand	Gulf)	and	interest	charges.	The	September	1989	write-off	of	System	Energy's investment	in	Grand	Gulf	2,	amounting	to	approximately	$900	million,	is	being	amortized	for	Availability	Agreement	purposes	over	27	years.

The	allocation	percentages	under	the	Availability	Agreement	are	fixed	as	follows:	Entergy	Arkansas	-	17.1%;	Entergy	Louisiana	-	26.9%; Entergy	Mississippi	-	31.3%;	and	Entergy	New	Orleans	-	24.7%.	The	allocation	percentages

under	the	Availability	Agreement	would	remain	in	effect	and	would	govern	payments	made	under	such	agreement	in	the	event	of	a	shortfall	of funds	available	to	System	Energy	from	other	sources,	including	payments	under	the	Unit	Power	Sales	Agreement.

System	Energy	has	assigned	its	rights	to	payments	and	advances	from	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and Entergy	New	Orleans	under	the	Availability	Agreement	as	security	for	its	first	mortgage	bonds	and	reimbursement	obligations	to	certain	banks providing	letters	of	credit	in	connection	with	the	equity	funding	of	the	sale	and	leaseback	transactions	described	in	Note	10	to	the	financial statements	 under	 "Sale	 and	 Leaseback	 Transactions	 -	 Grand	 Gulf	 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	the	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	the	FERC	for	approval	with	respect	to	the	terms of	such	sale.	No	such	filing	with	the	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	the	FERC	for	approval.

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	and,	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	10	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	Utility	operating	companies,	but	also	provides	services	to	Entergy	Wholesale	Commodities. 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	Louisiana, Entergy	Louisiana,	and	System	Energy,	respectively.		Entergy	Services	and	Entergy	Operations	provide	their	services	to	the	Utility	operating companies	and	System	Energy	on	an	"at	cost"	basis,	pursuant	to	cost	allocation	methodologies	for	these	service	agreements	that	were	approved	by the	FERC.

# Jurisdictional	Separation	of	Entergy	Gulf	States,	Inc.	into	Entergy	Gulf	States	Louisiana	and	Entergy	Texas

Effective	 December	 31,	 2007,	 Entergy	 Gulf	 States,	 Inc.	 completed	 a	 jurisdictional	 separation	 into	 two	 vertically	 integrated	 utility companies,	one	operating	under	the	sole	retail	jurisdiction	of	the	PUCT,	Entergy	Texas,	and	the	other	operating	under	the	sole	retail	jurisdiction	of the	LPSC,	Entergy	Gulf	States	Louisiana.		Entergy	Texas	now	owns	all	Entergy	Gulf	States,	Inc.	distribution	and	transmission	assets	located	in Texas,	the	gas-fired	generating	plants	located	in	Texas,	undivided	42.5%	ownership	shares	of	Entergy	Gulf	States,	Inc.'s	70%	ownership	interest in	Nelson	6	and	42%	ownership	interest	in	Big	Cajun	2,	Unit	3,	which	are	coal-fired	generating	plants	located	in	Louisiana,	and	other	assets	and contract	rights	to	the	extent	related	to	utility	operations	in	Texas.		Entergy	Gulf	States	Louisiana	now	owns	all	of	the	remaining	assets	that	were owned	by	Entergy	Gulf	States,	Inc.		On	a	book	value	basis,	approximately	58.1%	of	the	Entergy	Gulf	States,	Inc.	assets	were	allocated	to	Entergy Gulf	States	Louisiana	and	approximately	41.9%	were	allocated	to	Entergy	Texas.

Entergy	Texas	purchases	from	Entergy	Gulf	States	Louisiana	pursuant	to	a	life-of-unit	purchased	power	agreement	(PPA)	a	42.5%	share of	capacity	and	energy	from	the	70%	of	River	Bend	subject	to	retail	regulation.		Entergy	Texas	was	allocated	a	share	of	River	Bend's	nuclear	and environmental	liabilities	that	is	identical	to	the	share	of	the	plant's	output	purchased	by	Entergy	Texas	under	the	PPA.		Entergy	Gulf	States Louisiana	purchases	a	57.5%	share	of	capacity	and	energy	from	the	gas-fired	generating	plants	owned	by	Entergy	Texas,	and	Entergy	Texas purchases	a	42.5%	share	of	capacity	and	energy	from	the	gas-fired	generating	plants	owned	by	Entergy	Gulf	States	Louisiana.	 	The	PPAs associated	with	the	gas-fired	generating	plants	will	terminate	when	the	unit(s)	is/are	removed	from	Entergy	System	dispatch.		The	dispatch	and operation	of	the	generating	plants	did	not	change	as	a	result	of	the	jurisdictional	separation.		The	LPSC	staff	has	asserted	that	the	PPAs	would terminate	 if	 Entergy	 Texas	 and	 Entergy	 Gulf	 States	 Louisiana	 join	 MISO.	 	 Entergy	 Gulf	 States	 Louisiana	 filed	 testimony	 opposing	 that position.		The	LPSC	stayed	consideration	of	this	issue	until	December	31,	2013.	No	further	action	has	been	taken	regarding	this	matter.	See additional	discussion	of	the	PPAs	in	the	"Federal	Regulation	-	Entergy's	Integration	Into	the	MISO	Regional

Transmission	Organization"	section	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

# Earnings	Ratios	of	Registrant	Subsidiaries

The	Registrant	Subsidiaries'	ratios	of	earnings	to	fixed	charges	and	ratios	of	earnings	to	combined	fixed	charges	and	preferred	dividends or	distributions	pursuant	to	Item	503	of	SEC	Regulation	S-K	are	as	follows:

|  |  | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, | Ratios	of	Earnings	to	Fixed	Charges<br>Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| Entergy\tArkansas | 3.62 | 3.79 | 4.31 | 3.91 | 2.39 |
| Entergy\tGulf\tStates\tLouisiana | 3.63 | 3.48 | 4.36 | 3.58 | 2.99 |
| Entergy\tLouisiana | 3.13 | 2.08 | 1.86 | 3.41 | 3.52 |
| Entergy\tMississippi | 3.19 | 2.79 | 3.55 | 3.35 | 3.31 |
| Entergy\tNew\tOrleans | 1.93 | 3.02 | 5.37 | 4.43 | 3.61 |
| Entergy\tTexas | 1.94 | 1.76 | 2.34 | 2.10 | 1.92 |
| System\tEnergy | 5.66 | 5.12 | 3.85 | 3.64 | 3.73 |

# Ratios	of	Earnings	to	Combined	Fixed

# Charges	and	Preferred	Dividends	or	Distributions

# Years	Ended	December	31,

|  |  | Ratios	of	Earnings	to	Combined	Fixed | Ratios	of	Earnings	to	Combined	Fixed | Ratios	of	Earnings	to	Combined	Fixed |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Charges\tand\tPreferred\tDividends\tor\tDistributions | Years\tEnded\tDecember\t31, |  |  |
|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| Entergy\tArkansas | 3.25 | 3.36 | 3.83 | 3.60 | 2.09 |
| Entergy\tGulf\tStates\tLouisiana | 3.57 | 3.43 | 4.30 | 3.54 | 2.95 |
| Entergy\tLouisiana | 2.92 | 1.93 | 1.70 | 3.19 | 3.27 |
| Entergy\tMississippi | 2.97 | 2.59 | 3.27 | 3.16 | 3.06 |
| Entergy\tNew\tOrleans | 1.74 | 2.67 | 4.74 | 4.08 | 3.33 |

The	Registrant	Subsidiaries	accrue	interest	expense	related	to	unrecognized	tax	benefits	in	income	tax	expense	and	do	not	include	it	in	fixed charges.

Entergy	Wholesale	Commodities	includes	the	ownership	and	operation	of	six	nuclear	power	plants,	five	of	which	are	located	in	the Northeast	United	States,	with	the	sixth	located	in	Michigan,	and	is	primarily	focused	on	selling	electric	power	produced	by	those	plants	to wholesale	customers.		Entergy	Wholesale	Commodities	revenues	are	primarily	derived	from	sales	of	energy	and	generation	capacity	from	these plants.		This	business	also	provides	services	to	other	nuclear	power	plant	owners.	Entergy	Wholesale	Commodities	also	owns	interests	in	non- nuclear	power	plants	that	sell	the	electric	power	produced	by	those	plants	to	wholesale	customers.

Entergy	Wholesale	Commodities	also	provides	operations	and	management	services,	including	decommissioning	services,	to	nuclear power	plants	owned	by	other	utilities	in	the	United	States.

Entergy	Wholesale	Commodities	also	includes	the	ownership	of,	or	participation	in	joint	ventures	that	own,	non-nuclear	power	plants	and the	sale	to	wholesale	customers	of	the	electric	power	produced	by	these	plants.

# Property

# Nuclear	Generating	Stations

Entergy	Wholesale	Commodities	includes	the	ownership	of	the	following	nuclear	power	plants:

(a) In	August	2013,	Entergy	announced	plans	to	close	and	decommission	Vermont	Yankee.	 The	plant	is	expected	to	cease	power	production in	the	fourth	quarter	2014	after	its	current	fuel	cycle.

(b) The	original	expiration	date	of	the	NRC	operating	license	for	Indian	Point	2	was	September	28,	2013.	Indian	Point	Unit	2	has	now	entered its	"period	of	extended	operation"	after	expiration	of	the	plant's	initial	license	term	under	"timely	renewal,"	which	is	a	federal	statutory rule	of	general	applicability	providing	for	extension	of	a	license	for	which	a	renewal	application	has	been	timely	filed	with	the	licensing agency.	The	Indian	Point	license	renewal	application	qualifies	for	timely	renewal	protection	because	it	met	NRC	regulatory	standards	for timely	filing.

Entergy	Wholesale	Commodities	also	includes	the	ownership	of	two	non-operating	nuclear	facilities,	Big	Rock	Point	in	Michigan	and Indian	Point	1	in	New	York	that	were	acquired	when	Entergy	purchased	the	Palisades	and	Indian	Point	2	nuclear	plants,	respectively.		These facilities	are	in	various	stages	of	the	decommissioning	process.

In	March	2011	and	May	2012	the	NRC	renewed	the	operating	licenses	of	Vermont	Yankee	and	Pilgrim,	respectively,	for	an	additional	20 years,	as	a	result	of	which	each	license	now	expires	in	2032.		For	additional	discussion	regarding	the	decision	to	cease	operation	of	the	Vermont Yankee	plant	in	the	fourth	quarter	2014,	see	"Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial	statements.

The	original	expiration	date	of	the	NRC	operating	license	for	Indian	Point	2	was	in	September	2013	and	the	original	expiration	date	of	the NRC	operating	license	for	Indian	Point	3	is	in	December	2015.	NRC	license	renewal	applications	are	in	process	for	both	of	these	plants.	Under federal	law,	nuclear	power	plants	may	continue	to	operate	beyond	their	original	license	expiration	dates	while	their	renewal	applications	are pending	NRC	approval.	Indian	Point	Unit	2	has	now	entered	its	"period	of	extended	operation"	after	expiration	of	the	plant's	initial	license	term under	"timely	renewal,"	which	 is	a	federal	statutory	rule	of	general	applicability	providing	for	extension	of	a	 license	for	which	a	renewal application	has	been	timely	filed	with	the	licensing	agency.	The	Indian	Point	license	renewal	application	qualifies	for	timely	renewal	protection because	it	met	NRC	regulatory	standards	for	timely	filing.	For	additional	discussion	of	the	license	renewal	applications,	see	"Entergy	Wholesale Commodities	Authorizations	to	Operate	Its	Nuclear	Plants"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and Analysis.

# Non-nuclear	Generating	Stations

Entergy	Wholesale	Commodities	includes	the	ownership,	or	interests	in	joint	ventures	that	own,	the	following	non-nuclear	power	plants:

| Plant | Location | Ownership | Net	Owned<br>Capacity(a) | Type |
| :--- | :--- | :--- | :--- | :--- |
| Rhode\tIsland\tState\tEnergy\tCenter;\t583\tMW | Johnston,\tRI | 100% | 583\tMW | \t Gas |
| Independence\tUnit\t2;\t\t\t842\tMW | \t Newark,\tAR | 14% | 121\tMW(b) | \t Coal |
| Top\tof\tIowa;\t\t\t80\tMW\t(c) | \t Worth\tCounty,\tIA | 50% | 40\tMW | \t Wind |
| White\tDeer;\t\t\t80\tMW\t(c) | \t Amarillo,\tTX | 50% | 40\tMW | \t Wind |
| RS\tCogen;\t\t\t425\tMW\t(c) | \t Lake\tCharles,\tLA | 50% | 213\tMW | \t Gas/Steam |
| Nelson\t6;\t\t\t550\tMW | \t Westlake,\tLA | 11% | 60\tMW(b) | \t Coal |

(a) "Net	Owned	Capacity"	refers	to	the	nameplate	rating	on	the	generating	unit.

(b) The	owned	MW	capacity	is	the	portion	of	the	plant	capacity	owned	by	Entergy	Wholesale	Commodities.		For	a	complete	listing	of Entergy's	jointly-owned	generating	stations,	refer	to	"Jointly-Owned	Generating	Stations"	in	Note	1	to	the	financial	statements.

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

Entergy	retired	the	544	MW	Ritchie	Unit	2	gas/oil	plant	in	November	2013.

# Independent	System	Operators

The	Pilgrim	and	Vermont	Yankee	and	Rhode	Island	plants	fall	under	the	authority	of	the	Independent	System	Operator	(ISO)	New England	and	the	FitzPatrick	and	Indian	Point	plants	fall	under	the	authority	of	the	New	York	Independent	System	Operator	(NYISO).		The Palisades	plant	falls	under	the	authority	of	the	MISO.		The	primary	purpose	of	ISO	New	England,	NYISO,	and	MISO	is	to	direct	the	operations	of the	major	generation	and	transmission	facilities	in	their	respective	regions;	ensure	grid	reliability;	administer	and	monitor	wholesale	electricity markets;	and	plan	for	their	respective	region's	energy	needs.

# Energy	and	Capacity	Sales

As	a	wholesale	generator,	Entergy	Wholesale	Commodities's	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.		Entergy Wholesale	Commodities	enters	into	forward	contracts	with	its	customers	and	sells	energy	in	the	day	ahead	or	spot	markets.		In	addition	to	selling the	energy	produced	by	its	plants,	Entergy	Wholesale	Commodities	sells	unforced	capacity,	which	allows	load-serving	entities	to	meet	specified reserve	and	related	requirements	placed	on	them	by	the	ISOs	in	their	respective	areas.		Entergy	Wholesale	Commodities's	forward	fixed	price power	contracts	consist	of	contracts	to	sell	energy	only,	contracts	to	sell	capacity	only,	and	bundled	contracts	in	which	it	sells	both	capacity	and energy.		While	the	terminology	and	payment	mechanics	vary	in	these	contracts,	each	of	these	types	of	contracts	requires	Entergy	Wholesale Commodities	to	deliver	MWh	of	energy,	make	capacity	available,	or	both.		See	"Market	and	Credit	Risk	Sensitive	Instruments"	in	Entergy Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	additional	information	regarding	these	contracts.

As	part	of	the	purchase	of	the	Palisades	plant,	Entergy	executed	a	15-year	PPA	with	the	seller,	Consumers	Energy,	for	100%	of	the	plant's output,	excluding	any	future	uprates.		Under	the	purchased	power	agreement,	Consumers	Energy	will	receive	the	value	of	any	new	environmental credits	for	the	first	ten	years	of	the	agreement.		Palisades	and	Consumers	Energy	will	share	on	a	50/50	basis	the	value	of	any	new	environmental credits	for	years	11	through	15	of	the	agreement.		The	environmental	credits	are	defined	as	benefits	from	a	change	in	law	that	causes	capability	of the

plant	as	of	the	purchase	date	to	become	a	tradable	attribute	(e.g.,	emission	credit,	renewable	energy	credit,	environmental	credit,	"green"	credit, etc.)	or	otherwise	to	have	a	market	value.

Entergy	Wholesale	 Commodities's	 customers	 for	 the	 sale	 of	 both	 energy	 and	 capacity	 from	 its	 nuclear	 plants	 include	 retail	 power providers,	utilities,	electric	power	co-operatives,	power	trading	organizations	and	other	power	generation	companies.		These	customers	include Consolidated	 Edison	 and	 Consumers	 Energy,	 companies	 from	 which	 Entergy	 purchased	 plants,	 and	 ISO	 New	 England,	 NYISO,	 and MISO.	 	 Substantially	 all	 of	 the	 counterparties	 or	 their	 guarantors	 for	 the	 planned	 energy	 output	 under	 contract	 for	 Entergy	 Wholesale Commodities	nuclear	plants	have	public	investment	grade	credit	ratings.

# Competition

The	ISO	New	England	and	NYISO	markets	are	highly	competitive.		Entergy	Wholesale	Commodities	has	numerous	competitors	in	New England	and	New	York,	including	generation	companies	affiliated	with	regulated	utilities,	other	independent	power	producers,	municipal	and	co- operative	generators,	owners	of	co-generation	plants	and	wholesale	power	marketers.		Entergy	Wholesale	Commodities	is	an	independent	power producer,	which	means	it	generates	power	for	sale	to	third	parties	at	day	ahead	or	spot	market	prices	to	the	extent	that	the	power	is	not	sold	under	a fixed	price	contract.		Municipal	and	co-operative	generators	also	generate	power	but	use	most	of	it	to	deliver	power	to	their	municipal	or	co- operative	power	customers.		Owners	of	co-generation	plants	produce	power	primarily	for	their	own	consumption.		Wholesale	power	marketers	do not	 own	 generation;	 rather	 they	 buy	 power	 from	 generators	 or	 other	 market	 participants	 and	 resell	 it	 to	 retail	 providers	 or	 other	 market participants.		Competition	in	the	New	England	and	New	York	power	markets	is	affected	by,	among	other	factors,	the	amount	of	generation	and transmission	capacity	in	these	markets.		MISO	does	not	have	a	centralized	clearing	capacity	market,	but	load	serving	entities	do	meet	the	majority of	their	capacity	needs	through	bilateral	contracts	and	self-supply	with	a	smaller	portion	coming	through	voluntary	MISO	auctions.		The	majority of	Palisades's	current	output	is	contracted	to	Consumers	Energy	through	2022	and,	therefore,	Entergy	Wholesale	Commodities	does	not	expect	to be	materially	affected	by	competition	in	the	MISO	market	in	the	near	term.

# Seasonality

Entergy	Wholesale	Commodities's	revenues	and	operating	income	are	subject	to	fluctuations	during	the	year	due	to	seasonal	factors, weather	conditions,	and	contract	pricing.		Refueling	outages	are	generally	scheduled	for	the	spring	and	the	fall,	and	cause	volumetric	decreases during	those	seasons.		When	outdoor	and	cooling	water	temperatures	are	lower,	generally	during	colder	months,	Entergy	Wholesale	Commodities nuclear	power	plants	operate	more	efficiently,	and	consequently,	generate	more	electricity.		Many	of	Entergy	Wholesale	Commodities's	contracts provide	for	shaped	pricing	over	the	course	of	the	year.		As	a	result	of	these	factors,	Entergy	Wholesale	Commodities's	revenues	are	typically higher	in	the	first	and	third	quarters	than	in	the	second	and	fourth	quarters.

See	"Fuel	Supply,	Nuclear	Fuel"	in	the	Utility	portion	of	Part	I,	Item	1	for	a	discussion	of	the	nuclear	fuel	cycle	and	markets.		Entergy Nuclear	Fuels	Company,	a	wholly-owned	subsidiary,	is	responsible	for	contracts	to	acquire	nuclear	materials,	except	for	fuel	fabrication,	for Entergy	Wholesale	Commodities	nuclear	power	plants,	while	Entergy	Nuclear	Operations,	Inc.	acts	as	the	agent	for	the	purchase	of	nuclear	fuel assembly	fabrication	services.		All	contracts	for	the	disposal	of	spent	nuclear	fuel	are	between	the	DOE	and	each	of	the	nuclear	power	plants.

# Other	Business	Activities

Entergy	Nuclear	Power	Marketing,	LLC	(ENPM)	was	formed	in	2005	to	centralize	the	power	marketing	function	for	Entergy	Wholesale Commodities	 nuclear	 plants.	 	 Upon	 its	 formation,	 ENPM	 entered	 into	 long-term	 power	 purchase	 agreements	 with	 the	 Entergy	 Wholesale Commodities	subsidiaries	that	own	nuclear	power	plants	(generating	subsidiaries).		As	part	of	a	series	of	agreements,	ENPM	agreed	to	assume and/or	 otherwise	 service	 the	 existing	 power	 purchase	 agreements	 that	 were	 in	 effect	 between	 the	 generating	 subsidiaries	 and	 their customers.		ENPM	functions	include	origination	of	new	energy	and	capacity	transactions	and	generation	scheduling.

Entergy	Nuclear,	Inc.	pursues	service	agreements	with	other	nuclear	power	plant	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	 Entergy	 Wholesale Commodities	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.	 provided	 decommissioning	 services	 for	 the	 Maine	 Yankee	 nuclear	 power	 plant	 and	 continues	 to	 pursue opportunities	for	Entergy	Wholesale	Commodities	with	other	nuclear	plant	owners	through	operating	agreements.

Entergy	Nuclear,	Inc.	also	offers	operating	license	renewal	and	life	extension	services	to	nuclear	power	plant	owners.		TLG	Services,	a subsidiary	of	Entergy	Nuclear	Inc.,	offers	decommissioning,	engineering,	and	related	services	to	nuclear	power	plant	owners.		In	April	2009, Entergy	announced	that	it	will	team	with	energy	firm	ENERCON	to	offer	nuclear	development	services	ranging	from	plant	relicensing	to	full- service,	new	plant	deployment.		ENERCON	has	experience	in	engineering,	environmental,	technical	and	management	services.

In	September	2003,	Entergy	agreed	to	provide	plant	operation	support	services	for	the	800	MW	Cooper	Nuclear	Station	located	near Brownville,	Nebraska.		The	original	contract	was	to	expire	in	2014	corresponding	to	the	original	operating	license	life	of	the	plant.		In	2006	an Entergy	subsidiary	signed	an	agreement	to	provide	license	renewal	services	for	the	Cooper	Nuclear	Station.		The	Cooper	Nuclear	Station	received its	license	renewal	from	the	NRC	on	November	29,	2010.		Entergy	continues	to	provide	implementation	services	for	the	renewed	license.		In 2010	 an	 Entergy	 subsidiary	 signed	 an	 agreement	 to	 extend	 the	 management	 support	 services	 to	 Cooper	 Nuclear	 Station	 by	 15	 years, through	January	2029.

# Regulation	of	Entergy's	Business

# Federal	Power	Act

The	Federal	Power	Act	provides	the	FERC	the	authority	to	regulate:

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

•sales	or	acquisition	of	certain	assets;

•the	licensing	of	certain	hydroelectric	projects;

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

•changes	in	control	of	FERC	jurisdictional	entities	or	rate	schedules.

The	Federal	Power	Act	gives	the	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	Louisiana.		The	FERC	also	regulates	the	provisions	of	the	System	Agreement,	including	the	rates,	and	the	provision	of transmission	service	to	wholesale	market	participants.	The	FERC	also	regulates	the	MISO	RTO,	an	independent	entity	that	maintains	functional control	over	the	combined	transmission	systems	of	its	members	and	administers	wholesale	energy,	capacity,	and	ancillary	services	markets	for market	participants	in	the	MISO	region,	including	the	Utility	operating	companies.	FERC

regulation	of	the	MISO	RTO	includes	regulation	of	the	design	and	implementation	of	the	wholesale	markets	administered	by	the	MISO	RTO,	as well	as	the	rates,	terms,	and	conditions	of	open	access	transmission	service	over	the	member	systems	and	the	allocation	of	costs	associated	with transmission	upgrades.

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;

•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.

Additionally,	Entergy	Arkansas	serves	a	limited	number	of	retail	customers	in	Tennessee	and	as	a	result,	may	be	required	to	submit	certain matters	approved	by	 the	APSC	for	consideration	by	 the	Tennessee	Regulatory	Authority.	Additionally,	Entergy	Arkansas	maintains	 limited facilities	in	Missouri	but	does	not	provide	retail	electric	service	to	customers	in	Missouri.	Although	Entergy	Arkansas	obtained	a	certificate	with respect	to	its	Missouri	facilities,	Entergy	Arkansas	is	not	subject	to	the	retail	rate	or	regulatory	scheme	in	Missouri.

Entergy	Gulf	States	Louisiana's	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;

•certification	of	power	or	capacity	purchase	contracts;

•audit	of	the	fuel	adjustment	charge,	environmental	adjustment	charge,	and	avoided	cost	payment	to	Qualifying	Facilities;

•integrated	resource	planning;

•utility	mergers	and	acquisitions	and	other	changes	of	control;	and

•depreciation	and	other	matters.

Entergy	Louisiana	is	also	subject	to	the	jurisdiction	of	the	City	Council	with	respect	to	such	matters	within	Algiers	in	Orleans	Parish, although	the	precise	scope	of	that	jurisdiction	differs	from	that	of	the	LPSC.

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

•service	areas;

•facilities;

•certification	of	generating	facilities	and	certain	transmission	projects;

•fuel	cost	recovery;

•depreciation	rates;	and

•mergers	and	changes	of	control.

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	City	Council	as	to	the	following:

•standards	of	service;

•depreciation,

•issuance	and	sale	of	certain	securities;	and

•other	matters.

To	the	extent	authorized	by	governing	legislation,	Entergy	Texas	is	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.		Entergy	Texas	is	also	subject	to regulation	by	the	PUCT	as	to:

•retail	rates	and	service	in	unincorporated	areas	of	its	service	territory,	and	in	municipalities	that	have	ceded	jurisdiction	to	the	PUCT; •customer	service	standards;

•certification	of	certain	transmission	projects;	and

•extensions	of	service	into	new	areas.

# 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	Louisiana,	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	subsidiaries	in the	Entergy	Wholesale	Commodities	segment	are	subject	to	the	NRC's	jurisdiction	as	the	owners	and	operator	of	Pilgrim,	Indian	Point	Energy Center,	FitzPatrick,	Vermont	Yankee,	and	Palisades.	 	Substantial	capital	expenditures	at	Entergy's	nuclear	plants	because	of	revised	safety requirements	of	the	NRC	could	be	required	in	the	future.

# Nuclear	Waste	Policy	Act	of	1982

# Spent	Nuclear	Fuel

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	is	to	furnish	disposal	services	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	one	of	the	Utility operating	companies	that	generated	electric	power	with	nuclear	fuel	prior	to	that	date	and	has	a	recorded

liability	as	of	December	31,	2013	of	$181.3	million	for	the	one-time	fee.		Entergy	accepted	assignment	of	the	Pilgrim,	FitzPatrick	and	Indian Point	3,	Indian	Point	1	and	2,	Vermont	Yankee,	Palisades,	and	Big	Rock	Point	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	Utility	plants.		Entergy's	total	spent	fuel	fees	to	date,	including	the	one-time	fee	liability	of	Entergy Arkansas,	have	surpassed	$1.6	billion	(exclusive	of	amounts	relating	to	Entergy	plants	that	were	paid	or	are	owed	by	prior	owners	of	those	plants).

The	permanent	spent	fuel	repository	in	the	U.S.	has	been	legislated	to	be	Yucca	Mountain,	Nevada.	The	DOE	is	required	by	law	to proceed	with	the	licensing	(the	DOE	filed	the	license	application	in	June	2008)	and,	after	the	license	is	granted	by	the	NRC,	proceed	with	the repository	construction	and	commencement	of	receipt	of	spent	fuel.	Because	the	DOE	has	not	begun	accepting	spent	fuel,	it	is	in	non-compliance with	the	Nuclear	Waste	Policy	Act	of	1982	and	has	breached	its	spent	fuel	disposal	contracts.	The	DOE	continues	to	delay	meeting	its	obligation. Moreover,	the	Obama	administration	has	taken	specific	steps	to	discontinue	the	Yucca	Mountain	project	and	study	a	new	spent	fuel	strategy.	 Such actions	included	a	motion	to	the	NRC	to	withdraw	the	license	application	with	prejudice	and	the	establishment	of	a	commission	to	develop recommendations	for	alternative	spent	fuel	storage	solutions.	In	August	2013	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit	ordered	the	NRC	to continue	with	the	Yucca	Mountain	license	review,	but	only	to	the	extent	of	funds	previously	appropriated	by	Congress	for	that	purpose	and	not	yet used.	This	 amount	 of	 money	 is	 not	 expected	 to	 complete	 the	 review.	The	 government	 has	 taken	 no	 effective	 action	 to	 date	 related	 to	 the recommendations	of	the	appointed	spent	fuel	study	commission.	Accordingly,	large	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,	continuing	future	expenditures	will	be	required	to increase	spent	fuel	storage	capacity	at	Entergy's	nuclear	sites.

Following	 the	 current	 Presidential	 administration's	 defunding	 of	 the	 Yucca	 Mountain	 spent	 fuel	 repository	 program,	 the	 National Association	of	Regulatory	Utility	Commissioners	and	others	sued	the	government	seeking	cessation	of	collection	of	the	one	mill	fees	mentioned above.	On	November	19,	2013,	the	D.C.	Circuit	Court	of	Appeals	ordered	the	DOE	to	submit	a	proposal	to	Congress	to	reset	the	fee	to	zero	until the	DOE	complies	with	the	Nuclear	Waste	Policy	Act	or	Congress	enacts	an	alternative	waste	disposal	plan.	On	January	3,	2014,	the	DOE submitted	the	proposal	to	Congress	under	protest,	but	on	that	same	date,	filed	a	petition	for	rehearing	with	the	D.C.	Circuit.	Unless	the	fee proposal	is	withdrawn	or	other	contrary	court	or	legislative	action	is	taken,	the	proposal	will	become	the	new	fee	after	a	statutorily	required waiting	period.

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.	In	November	2003 these	subsidiaries,	except	for	the	owner	of	Palisades,	began	litigation	to	recover	the	damages	caused	by	the	DOE's	delay	in	performance.	In October	2007	the	U.S.	Court	of	Federal	Claims	awarded	$48.7	million	jointly	to	System	Fuels	and	Entergy	Arkansas	in	damages	related	to	the DOE's	breach	of	its	obligations.	In	a	revised	decision	issued	in	March	2010,	the	court	awarded	$9.7	million	jointly	to	System	Fuels,	System Energy,	and	SMEPA.	Also	in	March	2010,	in	two	separate	decisions,	the	court	awarded	$106.1	million	to	Entergy	Nuclear	Indian	Point	2,	and $4.2	million	to	Entergy	Nuclear	Generation	Company	(the	owner	of	Pilgrim).	In	September	2010	the	court	awarded	$46.6	million	to	Entergy Nuclear	Vermont	Yankee.	All	of	these	decisions	were	appealed	by	the	DOE	to	the	U.S.	Court	of	Appeals	for	the	Federal	Circuit	(Federal	Circuit). In	September	2011	the	Federal	Circuit	affirmed	most	of	the	Entergy	Nuclear	Generation	Company	award	for	Pilgrim,	but	remanded	to	the	trial court	 for	 recalculation	 of	 certain	 damages.	In	 April	 2012	 the	 U.S.	 Court	 of	 Federal	 Claims	 entered	 a	 final	 judgment	 in	 the	 amount	 of approximately	$4	million	in	the	Pilgrim	case,	and	Entergy	received	payment	of	that	amount	in	April	2013.	In	January	2012	the	Federal	Circuit affirmed	the	System	Fuels	and	Entergy	Arkansas	award	in	large	part,	and	reversed	the	trial	court's	denial	of	certain	damages	sought,	but	remanded to	the	trial	court	for	recalculation	of	certain	damages.	In	April	2013	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	favor	of	Entergy Arkansas	and	against	the	DOE	in	the	remanded	spent	fuel	case	for	damages	in	the	amount	of	$47.8	million	and	Entergy	Arkansas	received

payment	from	the	U.S.	Treasury	in	August	2013.	Also	in	January	2012,	the	Federal	Circuit	affirmed	the	System	Fuels,	System	Energy	and SMEPA	award,	and	reversed	the	trial	court's	denial	of	certain	damages,	raising	the	final	award	to	$10.2	million,	and	in	April	2012	the	U.S.	Court of	Federal	Claims	issued	a	final	judgment	and	Entergy	received	payment	of	that	amount	from	the	U.S.	Treasury	in	June	2012.	In	April	2012	the Federal	Circuit	issued	a	decision	in	the	appeal	in	the	Entergy	Nuclear	Indian	Point	2	case.	In	that	decision,	the	Federal	Circuit	reversed	certain damages	awarded	to	Entergy,	but	also	reversed	the	trial	court's	denial	of	certain	overhead	costs.	The	revisions	to	the	award	reduced	the	net	amount from	approximately	$106	million	to	approximately	$103	million,	and	Entergy	received	payment	of	that	amount	from	the	U.S.	Treasury	in	August 2012.	In	June	2012	the	Federal	Circuit	issued	a	decision	in	the	appeal	of	the	Vermont	Yankee	case.	 In	that	decision,	the	Federal	Circuit	reversed certain	damages	awarded	to	Entergy,	but	again	reversed	the	trial	court's	denial	of	certain	overhead	costs.	The	revisions	to	the	award	reduced	the net	amount	from	approximately	$47	million	to	approximately	$41	million.	On	December	31,	2012,	time	for	any	appeals	of	the	Vermont	Yankee judgment	expired	without	any	appeals	being	filed,	and	that	judgment	became	final.	Entergy	received	payment	of	the	$41	million	in	April	2013.	In September	2012,	Entergy	Nuclear	Palisades,	LLC	filed	suit	against	the	DOE	for	damages	from	the	DOE's	breach	of	the	spent	fuel	disposal contract	accruing	at	Palisades	and	Big	Rock	Point	since	the	date	of	acquisition	of	those	sites	from	Consumers	Energy	Company	in	2007.	In	April 2013	the	U.S.	Court	of	Appeals	for	the	Federal	Circuit	issued	a	ruling	in	favor	of	Entergy	Nuclear	FitzPatrick	and	Entergy	Nuclear	Indian	Point	3 and	against	the	DOE	that	the	DOE	may	not	raise	as	a	defense	to	damages	claims	in	the	spent	fuel	litigation	a	claim	that	it	was	unavoidably	delayed in	 commencing	 performance.	Management	cannot	predict	the	timing	or	amount	of	any	potential	recoveries	on	other	claims	filed	by	Entergy subsidiaries,	and	cannot	predict	the	timing	of	any	eventual	receipt	from	the	DOE	of	the	U.S.	Court	of	Federal	Claims	damage	awards.

Pending	 DOE	 acceptance	 and	 disposal	 of	 spent	 nuclear	 fuel,	 the	 owners	 of	 nuclear	 plants	 are	 providing	 their	 own	 spent	 fuel storage.		Storage	capability	additions	using	dry	casks	began	operations	at	Palisades	in	1993,	at	ANO	in	1996,	at	FitzPatrick	in	2002,	at	River	Bend in	2005,	at	Grand	Gulf	in	2006,	at	Indian	Point	and	Vermont	Yankee	in	2008,	and	at	Waterford	3	in	2011.		These	facilities	will	be	expanded	as needed.		Current	on-site	spent	fuel	storage	capacity	at	Pilgrim	is	estimated	to	be	sufficient	until	2014,	by	which	time	dry	cask	storage	facilities	are planned	to	be	placed	into	service	at	that	unit.

# Nuclear	Plant	Decommissioning

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Texas,	and	System	Energy	are	entitled	to	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.	 	The	collections	are	deposited	 in	 trust	funds	 that	can	only	be	used	for	future	decommissioning costs.		Entergy	periodically	reviews	and	updates	the	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.

Following	a	review	in	2009,	Entergy	concluded	that	there	was	a	funding	shortfall	for	Vermont	Yankee	of	approximately	$40	million, which	it	satisfied	with	a	$40	million	guarantee	from	Entergy	Corporation	that	is	still	in	place.		On	July	28,	2010,	the	LPSC	approved	increased decommissioning	collections	for	Waterford	3	and	the	Louisiana	regulated	share	of	River	Bend	and	on	December	13,	2010,	the	PUCT	approved increased	decommissioning	collections	for	the	Texas	share	of	River	Bend,	to	address	previously	identified	funding	shortfalls.		Entergy	currently believes	its	decommissioning	funding	will	be	sufficient	for	its	nuclear	plants	subject	to	retail	rate	regulation,	although	decommissioning	cost inflation	and	trust	fund	performance	will	ultimately	determine	the	adequacy	of	the	funding	amounts.

For	the	Indian	Point	3	and	FitzPatrick	plants	purchased	in	2000,	NYPA	retained	the	decommissioning	trusts	and	the	decommissioning liabilities.		NYPA	and	Entergy	subsidiaries	executed	decommissioning	agreements,	which	specify	their	decommissioning	obligations.		NYPA	has the	 rights	 to	 require	 the	 Entergy	 subsidiaries	 to	 assume	 each	 of	 the	 decommissioning	 liabilities	 provided	 that	 it	 assigns	 the	 corresponding decommissioning	 trust,	 up	 to	 a	 specified	 level,	 to	 the	 Entergy	 subsidiaries.	 	 If	 the	 decommissioning	 liabilities	 are	 retained	 by	 NYPA,	 the responsible	Entergy

subsidiary	 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.

In	March	2013,	Entergy	Operations	and	Entergy	Nuclear	Operations	made	filings	with	the	NRC	reporting	on	decommissioning	funding for	Entergy's	nuclear	plants.	Those	reports	all	showed	that	decommissioning	funding	for	the	nuclear	plants	met	the	NRC's	financial	assurance requirements.

Additional	information	with	respect	to	Entergy's	decommissioning	costs	and	decommissioning	trust	funds	is	found	in	Note	9	and	Note	17 to	the	financial	statements.

# Price-Anderson	Act

The	 Price-Anderson	Act	 requires	 that	 reactor	 licensees	 purchase	 and	 maintain	 the	 maximum	 amount	 of	 nuclear	 liability	 insurance available	and	participate	in	an	industry	assessment	program	called	Secondary	Financial	Protection	in	order	to	protect	the	public	in	the	event	of	a nuclear	power	plant	accident.		The	costs	of	this	insurance	are	borne	by	the	nuclear	power	industry.		Congress	amended	and	renewed	the	Price- Anderson	Act	in	2005	for	a	term	through	2025.		The	Price-Anderson	Act	limits	the	contingent	liability	for	a	single	nuclear	incident	to	a	maximum assessment	of	approximately	$127.318	million	per	reactor	(with	104	nuclear	industry	reactors	currently	participating).		In	the	case	of	a	nuclear event	in	which	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	System	Energy,	or	Entergy	Wholesale	Commodities	is liable,	protection	is	afforded	through	a	combination	of	private	insurance	and	the	Secondary	Financial	Protection	program.	In	addition	to	this, insurance	for	property	damage,	costs	of	replacement	power,	and	other	risks	relating	to	nuclear	generating	units	is	also	purchased.		The	Price- Anderson	Act	and	insurance	applicable	to	the	nuclear	programs	of	Entergy	are	discussed	in	more	detail	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	Entergy's businesses	 are	 in	 substantial	 compliance	 with	 environmental	 regulations	 currently	 applicable	 to	 its	 facilities	 and	 operations.	 	 Because environmental	regulations	are	subject	to	change,	future	compliance	requirements	and	costs	cannot	be	precisely	estimated.		Except	to	the	extent discussed	below,	at	this	time	compliance	with	federal,	state,	and	local	provisions	regulating	the	discharge	of	materials	into	the	environment,	or otherwise	protecting	the	environment,	is	incorporated	into	the	routine	cost	structure	of	Entergy's	businesses	and	is	not	expected	to	have	a	material effect	on	their	competitive	position,	results	of	operations,	cash	flows,	or	financial	position.

# Clean	Air	Act	and	Subsequent	Amendments

The	Clean	Air	Act	and	its	amendments	establish	several	programs	that	currently	or	in	the	future	may	affect	Entergy's	fossil-fueled generation	 facilities	 and,	 to	 a	 much	 lesser	 extent,	 certain	 operations	 at	 nuclear	 and	 other	 	 facilities.	 	 Individual	 states	 also	 operate	 similar independent	 state	 programs	 or	 delegated	 federal	 programs	 that	 may	 include	 requirements	 more	 stringent	 than	 federal	 regulatory requirements.		These	programs	include:

•New	source	review	and	preconstruction	permits	for	new	sources	of	criteria	air	pollutants,	new	and	existing	sources	of	greenhouse	gases, and	significant	modifications	to	existing	facilities;

•Acid	rain	program	for	control	of	sulfur	dioxide	(SO2)	and	nitrogen	oxides	(NOx);

•Nonattainment	area	programs	for	control	of	criteria	air	pollutants,	which	could	include	fee	assessments	for	air	pollutant	emission	sources under	Section	185	of	the	Clean	Air	Act	if	attainment	is	not	reached	in	a	timely	manner;

•Hazardous	air	pollutant	emissions	reduction	programs;

•Interstate	Air	Transport;

•Operating	permits	program	for	administration	and	enforcement	of	these	and	other	Clean	Air	Act	programs;

•Regional	Haze	and	Best	Available	Retrofit	Technology	programs;	and •New	and	existing	source	standards	for	greenhouse	gas	emissions.

# New	Source	Review	(NSR)

Preconstruction	permits	are	required	for	new	facilities	and	for	existing	facilities	that	undergo	a	modification	that	results	in	a	significant	net emissions	increase	and	is	not	classified	as	routine	repair,	maintenance,	or	replacement.		Units	that	undergo	certain	non-routine	modifications	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,	the	EPA has	begun	an	enforcement	initiative,	aimed	primarily	at	coal	plants,	to	identify	modifications	that	it	does	not	consider	routine	for	which	the	unit did	not	obtain	a	modified	permit.	 	Various	courts	and	 the	EPA	have	been	 inconsistent	 in	 their	 judgments	regarding	modifications	 that	are considered	routine.

In	February	2011,	Entergy	received	a	request	from	the	EPA	for	several	categories	of	information	concerning	capital	and	maintenance projects	at	the	White	Bluff	and	Independence	facilities,	both	located	in	Arkansas,	in	order	to	determine	compliance	with	the	Clean	Air	Act.		In August	2011,	Entergy's	Nelson	facility,	located	in	Louisiana,	received	a	similar	request	for	information	from	the	EPA.		Entergy	responded	to	both requests.		Neither	EPA	request	for	information	alleged	that	the	facilities	are	in	violation	of	law.

# Acid	Rain	Program

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

# Ozone	Nonattainment

Entergy	Texas	operates	one	fossil-fueled	generating	unit	(Lewis	Creek)	in	a	geographic	area	that	is	not	in	attainment	of	the	currently- enforced	 national	 ambient	 air	 quality	 standards	 (NAAQS)	 for	 ozone.	 	 The	 nonattainment	 area	 that	 affects	 Entergy	 Texas	 is	 the	 Houston- Galveston-Brazoria	area.		Areas	in	nonattainment	are	classified	as	"marginal,"	"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.

The	Houston-Galveston-Brazoria	area	was	originally	classified	as	"moderate"	nonattainment	under	the	8-hour	ozone	standard	with	an attainment	date	of	June	15,	2010.		On	June	15,	2007,	the	Texas	governor	petitioned	the	EPA	to	reclassify	Houston-Galveston-Brazoria	from "moderate"	to	"severe"	and	the	EPA	granted	the	request	on	October	1,	2008.		The	area's	new	attainment	date	for	the	8-hour	ozone	standard	is	as expeditiously	as	practicable,	but	no	later	than	June	15,	2019.

In	March	2008,	the	EPA	revised	the	NAAQS	for	ozone,	creating	the	potential	for	additional	counties	and	parishes	in	which	Entergy operates	to	be	placed	in	nonattainment	status.		On	April	30,	2012,	the	EPA	released	its	final	non-attainment	designations	for	the	2008	ozone NAAQS. In	 Entergy's	 utility	 service	 area,	 the	 Houston-Galveston-Brazoria,	 Texas;	 Baton	 Rouge,	 Louisiana;	 and	 Memphis, Tennessee/Mississippi/Arkansas	areas	were	designated	as	in	"marginal"	nonattainment.

For	these	marginal	areas	attainment	must	be	demonstrated	no	later	than	December	31,	2015	(with	EPA	evaluating	whether	the	area attained	the	standard	based	on	monitored	ozone	data	from	2013-2015).		In	the	final	designation	rule,	EPA	states	that	it	anticipates	the	marginal areas	 will	 be	 able	 to	 attain	 by	 that	 date	 based	 upon	 reductions	 attendant	 with	 other	 rules	 and	 programs	 such	 as	 the	 interstate	 transport rules.		Entergy	facilities	in	these	areas	may	be	subject	to	installation	of	NOx	controls,	but	the	degree	of	control	will	remain	unknown	until	the states	are	further	along	in	implementing	in	the	marginal	areas.			Entergy	will	continue	to	monitor	and	engage	in	the	state's	implementation	process in	Entergy	states.

# Potential	SO2	Nonattainment

The	EPA	issued	a	final	rule	in	June	2010	adopting	an	SO 2	1-hour	national	ambient	air	quality	standard	of	75	parts	per	billion.		The	EPA designations	 for	 counties	 in	 attainment	 and	 nonattainment	 were	 originally	 due	 in	 June	 2012,	 but	 the	 EPA	 has	 indicated	 that	 it	 will	 delay designations	except	for	those	areas	with	existing	monitoring	data	from	2009	to	2011	indicating	violations	of	the	new	standard.	In	July	2013	EPA issued	final	designations	for	these	areas.	In	Entergy's	utility	service	territory,	only	St.	Bernard	Parish	in	Louisiana	is	designated	as	non-attainment for	the	SO2	1-hour	national	ambient	air	quality	standard	of	75	parts	per	billion.	Entergy	does	not	have	a	generation	asset	in	that	parish.	In	all	other areas,	analysis	is	required	once	EPA	issues	additional	final	regulations	and	guidance.	Additional	capital	projects	or	operational	changes	may	be required	for	Entergy	facilities	in	these	areas.

# Hazardous	Air	Pollutants

The	EPA	released	the	final	Mercury	and	Air	Toxics	Standard	(MATS)	rule	in	December	2011	and	the	rule	became	effective	in	April	2012. Entergy	currently	is	on	schedule	to	have	the	required	controls	in	place	for	compliance	at	Entergy's	coal-fired	units.	Compliance	with	MATS	is required	by	 the	Clean	Air	Act	within	 three	years,	or	by	2015,	although	certain	extensions	of	 this	deadline	are	available	from	state	permit authorities	and	the	EPA.	Entergy	has	applied	for	and	received	a	one-year	extension,	as	allowed	by	the	Clean	Air	Act,	for	its	affected	facilities	in Arkansas	and	Louisiana.

# Cross-State	Air	Pollution

In	March	2005,	the	EPA	finalized	the	Clean	Air	Interstate	Rule	(CAIR),	which	was	intended	to	reduce	SO2	and	NOx	emissions	from electric	generation	plants	in	order	to	improve	air	quality	in	twenty-nine	eastern	states.		The	rule	required	a	combination	of	investment	of	capital	to install	pollution	control	equipment	and	increased	operating	costs	through	the	purchase	of	emission	allowances.		Entergy	began	implementation	in 2007,	including	installation	of	controls	at	several	facilities	and	the	development	of	an	emission	allowance	procurement	strategy.

Based	on	several	court	challenges,	the	CAIR	was	vacated	and	remanded	to	the	EPA	by	the	D.C.	Circuit	in	2008.		The	court	allowed	the CAIR	to	become	effective	in	January	2009,	while	the	EPA	revised	the	rule.		On	July	7,	2011,	the	EPA	released	its	final	Cross-State	Air	Pollution Rule	(CSAPR,	which	previously	was	referred	to	as	the	Transport	Rule).		The	rule	was	directed	at	limiting	the	interstate	transport	of	emissions	of NOx	and	SO2	as	precursors	to	ozone	and	fine	particulate	matter.		The	final	rule	provided	a	significantly	lower	number	of	allowances	to	Entergy's Utility	states	than	did	the	draft	rule.		Entergy's	capital	investment	and	annual	allowance	purchase	costs	under	the	CSAPR	would	depend	on	the economic	assessment	of	NOx	and	SO2	allowance	markets,	the	cost	of	control	technologies,	generation	unit	utilization,	and	the	availability	and	cost of	purchased	power.

Entergy	 filed	 a	 petition	 for	 review	 with	 the	 United	 States	 Court	 of	Appeals	 for	 the	 D.C.	 Circuit	 and	 a	 petition	 with	 the	 EPA	 for reconsideration	of	the	rule	and	stay	of	its	effectiveness.	Several	other	parties	filed	similar	petitions.	In	December	2011	the	Court	of	Appeals	for	the D.C.	Circuit	Court	stayed	CSAPR	and	instructed	the	EPA	to	continue	administering	CAIR,	pending	further	judicial	review.	 In	August	2012	the court	issued	a	decision	vacating	CSAPR	and	leaving	CAIR	in	place	pending	the	promulgation	of	a	lawful	replacement	for	both	rules.	In	January 2013	the	court	denied	petitions	for	reconsideration	filed	by	the	EPA	and	certain	states	and	intervenors.	In	March	2013	the	EPA	and	other	parties filed	petitions	for	certiorari	with	the	U.S.	Supreme	Court.	The	U.S.	Supreme	Court	issued	an	order	in

June	2013	granting	the	EPA's	and	environmental	groups'	petitions	for	review	of	the	D.C.	Circuit's	decision	vacating	CSAPR.	 Oral	argument occurred	in	December	2013	and	a	decision	is	expected	by	mid-2014.	Entergy	is	complying	with	CAIR	as	it	continues	to	be	implemented	until further	instruction	from	the	court	or	the	EPA.

# Regional	Haze

In	June	2005,	the	EPA	issued	its	final	Clean	Air	Visibility	Rule	(CAVR)	regulations	that	could	potentially	result	in	a	requirement	to	install SO2	and	NOx	pollution	control	technology	as	Best	Available	Retrofit	Control	Technology	(BART)	on	certain	of	Entergy's	coal	and	oil	generation units.		The	rule	leaves	certain	CAVR	determinations	to	the	states.		The	Arkansas	Department	of	Environmental	Quality	(ADEQ)	prepared	a	State Implementation	Plan	(SIP)	for	Arkansas	facilities	to	implement	its	obligations	under	the	CAVR.		The	ADEQ	determined	that	Entergy	Arkansas's White	Bluff	power	plant	affects	a	Class	I	Area's	visibility	and	will	be	subject	to	the	EPA's	presumptive	BART	limits,	which	likely	would	require the	installation	of	scrubbers	and	low	NOx	burners.		Under	then-current	state	regulations,	the	scrubbers	would	have	had	to	be	operational	by October	2013.		Entergy	Arkansas	filed	a	petition	in	December	2009	with	the	Arkansas	Pollution	Control	and	Ecology	Commission	requesting	a variance	from	this	deadline	because	the	EPA	had	expressed	concerns	about	Arkansas's	Regional	Haze	SIP	and	questioned	the	appropriateness	of issuing	an	air	permit	prior	to	that	approval.		Entergy	Arkansas's	petition	requested	that,	consistent	with	federal	law,	the	compliance	deadline	be changed	to	as	expeditiously	as	practicable,	but	in	no	event	later	than	five	years	after	EPA	approval	of	the	Arkansas	Regional	Haze	SIP.		The Arkansas	Pollution	Control	and	Ecology	Commission	approved	the	variance	in	March	2010.		In	October	2011	the	EPA	released	a	proposed	rule addressing	the	Arkansas	Regional	Haze	SIP.		In	the	proposal	the	EPA	disapproved	a	large	portion	of	the	Arkansas	Regional	Haze	SIP,	including the	emission	limits	for	NOx	and	SO2	at	White	Bluff.		The	final	rule	was	published,	mostly	unchanged,	on	March	12,	2012	and	became	final	on April	11,	2012.		The	EPA	did	not	issue	a	Federal	Implementation	Plan	for	regional	haze	requirements	because	Arkansas	has	indicated	it	wishes	to revise	and	resubmit	its	SIP.		There	will	be	a	two-year	timeframe	in	which	the	EPA	must	either	approve	a	revised	SIP	issued	by	Arkansas	or	issue	a Federal	Implementation	Plan.		These	decisions	will	impact	the	timing	and	level	of	control	installation	at	White	Bluff.

# Fine	Particle	(PM2.5)	National	Ambient	Air	Quality	Standard

On	December	14,	2012,	the	EPA	released	regulations	that	lowered	the	NAAQS	for	fine	particle	pollution	or	PM2.5.		Currently,	the Houston-Galveston-Brazoria	counties	area	in	Texas	and	Pulaski	County	in	Arkansas	could	potentially	be	designated	as	non-attainment	of	the	new NAAQS.		The	EPA	projections	are	that	these	areas	will	be	in	attainment	by	2020	due	to	emission	reductions	from	other	EPA	and	state	regulations.

The	EPA	anticipates	making	initial	attainment/nonattainment	designations	by	December	2014,	with	those	designations	likely	becoming effective	 in	early	2015.	 	Following	nonattainment	designation,	states	with	areas	designated	nonattainment	will	be	required	 to	develop	state implementation	plans	that	outline	control	requirements	that	enable	the	affected	counties	and	parishes	to	reach	attainment	status.		States	would	have until	2020	(five	years	after	designations	are	effective)	to	meet	the	revised	annual	PM2.5	standard.		A	state	may	request	a	possible	extension	to 2025	depending	on	the	severity	of	an	area's	fine	particle	pollution	problems	and	the	availability	of	pollution	controls.		Entergy	will	continue	to monitor	and	engage	in	the	state's	implementation	process	in	Entergy	states.

# Potential	Legislative,	Regulatory,	and	Judicial	Developments

In	addition	to	the	specific	instances	described	above,	there	are	a	number	of	legislative	and	regulatory	initiatives	concerning	air	emissions, as	well	as	other	media,	that	are	under	consideration	at	the	federal,	state,	and	local	level.	 	Because	of	the	nature	of	Entergy's	business,	the imposition	of	any	of	these	initiatives	could	affect	Entergy's	operations.		Entergy	continues	to	monitor	these	initiatives	and	activities	in	order	to analyze	their	potential	operational	and	cost	implications.		These	initiatives	include:

•designation	by	the	EPA	and	state	environmental	agencies	of	areas	that	are	not	in	attainment	with	national	ambient	air	quality	standards;

•introduction	of	bills	in	Congress	and	development	of	regulations	by	the	EPA	proposing	further	limits	on	NOx,	SO2,	mercury,	and	carbon dioxide	and	other	air	emissions.		New	legislation	or	regulations	applicable	to	stationary	sources	could	take	the	form	of	market-based	cap- and-trade	programs,	direct	requirements	for	the	installation	of	air	emission	controls	onto	air	emission	sources,	or	other	or	combined regulatory	programs.		Entergy	cannot	estimate	the	effect	of	any	future	legislation	at	this	time	due	to	the	uncertainty	of	the	regulatory format;

•efforts	in	Congress	or	at	the	EPA	to	establish	a	mandatory	federal	carbon	dioxide	emission	control	structure	or	unit	performance standards;

•revisions	to	the	estimates	of	the	Social	Cost	of	Carbon	used	for	regulatory	impact	analysis	of	Federal	laws	and	regulations;

•implementation	of	the	Regional	Greenhouse	Gas	Initiative	by	several	states	in	the	northeastern	United	States	and	similar	actions	in	other regions	of	the	United	States;

•efforts	on	the	state	and	federal	level	to	codify	renewable	portfolio	standards,	a	clean	energy	standard,	or	a	similar	mechanism	requiring utilities	to	produce	or	purchase	a	certain	percentage	of	their	power	from	defined	renewable	energy	sources	or	energy	sources	with	lower emissions;

•efforts	to	develop	more	stringent	state	water	quality	standards,	effluent	limitations	for	Entergy's	industry	sector,	stormwater	runoff	control regulations,	and	cooling	water	intake	structure	requirements;

•efforts	to	restrict	the	previously-approved	continued	use	of	oil-filled	equipment	containing	certain	levels	of	PCBs;	and •efforts	by	certain	external	groups	to	encourage	reporting	and	disclosure	of	carbon	dioxide	emissions	and	risk.		Entergy	has	prepared responses	for	the	Carbon	Disclosure	Project's	(CDP)	annual	questionnaire	for	the	past	several	years	and	has	given	permission	for	those responses	to	be	posted	to	CDP's	website.

Entergy	continues	to	support	national	legislation	that	would	increase	planning	certainty	for	electric	utilities	while	addressing	carbon dioxide	emissions	in	a	responsible	and	flexible	manner.		By	virtue	of	its	proportionally	large	investment	in	low-emitting	gas-fired	and	nuclear generation	technologies,	Entergy	has	a	low	overall	carbon	dioxide	emission	"intensity,"	or	rate	of	carbon	dioxide	emitted	per	kilowatt-hour	of electricity	generated.		In	anticipation	of	the	potential	imposition	of	carbon	dioxide	emission	limits	on	the	electric	industry	in	the	future,	Entergy initiated	actions	designed	to	reduce	its	exposure	to	potential	new	governmental	requirements	related	to	carbon	dioxide	emissions.		These	voluntary actions	included	establishment	of	a	formal	program	to	stabilize	power	plant	carbon	dioxide	emissions	at	2000	levels	through	2005,	and	Entergy succeeded	in	actually	reducing	emissions	below	2000	levels.	Total	carbon	dioxide	emissions	representing	Entergy's	ownership	share	of	power plants	in	the	United	States	were	approximately	53.2	million	tons	in	2000	and	35.6	million	tons	in	2005.		In	2006,	Entergy	changed	its	method	of calculating	emissions	and	now	includes	emissions	from	controllable	power	purchases	as	well	as	its	ownership	share	of	generation.		Entergy established	 a	 second	 formal	 voluntary	 program	 to	 stabilize	 power	 plant	 carbon	 dioxide	 emissions	 and	 emissions	 from	 controllable	 power purchases	at	20%	below	2000	levels	through	2010.	 	Entergy	has	extended	this	commitment	through	2020.	 	Total	carbon	dioxide	emissions representing	Entergy's	ownership	share	of	power	plants	and	controllable	power	purchases	in	the	United	States	were	approximately	46.1	million tons	in	2011,	approximately	45.5	million	tons	in	2012,	and	approximately	46.2	million	tons	in	2013.

# Greenhouse	Gas	Reporting

In	September	2009,	the	EPA	finalized	a	rule	to	require	reporting	of	several	greenhouse	gases.	 	This	rule	requires	Entergy	to	report annually	greenhouse	gas	emissions	from	operating	power	plants,	various	combustion	sources,	certain	transmission	and	distribution	equipment, and	natural	gas	distribution	operations.

# New	Source	Performance	Standards	for	Greenhouse	Gas	Emissions

As	a	part	of	a	climate	plan	announced	June	25,	2013,	President	Obama	directed	the	EPA	to	(i)	reissue	proposed	carbon	pollution	standards for	new	power	plants	by	September	20,	2013,	with	finalization	of	the	rules	to	occur	in	a	timely	manner;	(ii)	issue	proposed	carbon	pollution standards,	regulations,	or	guidelines,	as	appropriate,	for	modified,	reconstructed,	and	existing	power	plants	no	later	than	June	1,	2014;	(iii)	finalize those	rules	by	no	later	than	June	1,

2015;	and	(iv)	include	in	the	guidelines	addressing	existing	power	plants	a	requirement	that	states	submit	to	the	EPA	the	implementation	plans required	under	Section	111(d)	of	the	Clean	Air	Act	and	its	implementing	regulations	by	no	later	than	June	30,	2016.	In	September	2013	the	EPA issued	the	proposed	NSPS	rule	for	new	sources.	The	rule	was	published	in	the	Federal	Register	on	January	8,	2014,	with	comments	due	on	March 10,	2014.	Entergy	is	reviewing	the	proposal	and	is	engaged	with	industry	associations	in	the	commenting	process.	Entergy	is	actively	engaged	in the	rulemaking	process.

# Nelson	Unit	6	(Entergy	Gulf	States	Louisiana)

Entergy	Gulf	States	Louisiana	has	self-reported	to	the	LDEQ	an	annual	carbon	monoxide	(CO)	emission	limit	deviation	at	the	Nelson Unit	6	coal-fired	facility	for	 the	years	2006-2010	and	 the	failure	 to	report	 these	deviations	 in	semi-annual	reporting	and	 in	annual	Title	V compliance	 certifications.	Entergy	Gulf	States	Louisiana	is	not	required	to	monitor	carbon	monoxide	emissions	from	Nelson	Unit	6	using	a continuous	emissions	monitoring	system	(CEMS).	Stack	tests	performed	in	2010	appear	to	indicate	CO	emissions	in	excess	of	the	maximum hourly	limit	for	three	-	1	hour	test	runs;	however,	comparison	of	the	2010	stack	tests	with	the	most	recent	previous	tests,	from	2006,	appear	to indicate	that	the	permit	limits	were	calculated	incorrectly	in	the	Title	V	Permit	application	and	should	have	been	higher	using	the	2006	stack	test as	the	basis.	The	2010	test	emission	levels	did	not	cause	a	violation	of	NAAQS.	Additionally,	the	2010	stack	testing,	which	was	performed	in compliance	with	an	EPA	data	request	connected	to	the	agency's	development	of	a	new	air	emissions	rule,	was	not	taken	during	a	period	of	normal and	representative	operations	for	Nelson	6.	Settlement	negotiations	continue	with	the	LDEQ.

# Clean	Water	Act

The	1972	amendments	to	the	Federal	Water	Pollution	Control	Act	(known	as	the	Clean	Water	Act)	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	Clean	Water	Act	requires	virtually	all	discharges	of	pollutants	to	waters	of	the	United	States	to be	permitted.		Section	316(b)	of	the	Clean	Water	Act	regulates	cooling	water	intake	structures,	section	401	of	the	Clean	Water	Act	requires	a	water quality	certification	from	the	state	in	support	of	certain	federal	actions	and	approvals,	and	section	404	regulates	the	dredge	and	fill	of	waters	of	the United	States,	including	jurisdictional	wetlands.

# NPDES	Permits	and	Section	401	Water	Quality	Certifications

NPDES	permits	are	subject	to	renewal	every	five	years.		Consequently,	Entergy	is	currently	in	various	stages	of	the	data	evaluation	and discharge	permitting	process	for	its	power	plants.		Additionally,	the	State	of	New	York	has	taken	the	position	that	a	new	state-issued	water	quality certification	is	required	as	part	of	the	NRC	license	renewal	process.		Entergy	Wholesale	Commodities's	Indian	Point	nuclear	facility	in	New	York is	seeking	a	new	Section	401	certification	prior	to	license	renewal	under	full	reservation	of	rights.

# Indian	Point

Entergy	 is	 involved	 in	 an	 administrative	 permitting	 process	 with	 the	 New	 York	 State	 Department	 of	 Environmental	 Conservation (NYSDEC)	for	renewal	of	the	Indian	Point	2	and	Indian	Point	3	discharge	permit.	 	In	November	2003	the	NYSDEC	issued	a	draft	permit indicating	that	closed	cycle	cooling	would	be	considered	the	"best	technology	available"	for	minimizing	alleged	adverse	environmental	effects attributable	to	the	intake	of	cooling	water	at	Indian	Point,	subject	to	a	feasibility	determination	and	alternatives	analysis	for	that	technology,	if Entergy	applied	for	and	received	NRC	license	renewal	for	Indian	Point	2	and	Indian	Point	3.		Upon	becoming	effective,	the	draft	permit	also would	have	required	payment	of	approximately	$24	million	annually,	and	an	annual	42	unit-day	outage	period,	until	closed	cycle	cooling	is implemented.		Entergy	is	participating	in	the	administrative	process	to	request	that	the	draft	permit	be	modified	prior	to	final	issuance,	and	opposes any	requirement	to	install	cooling	towers	at	Indian	Point.

An	August	2008	ruling	by	the	NYSDEC's	Assistant	Commissioner	restructured	the	permitting	and	administrative	process,	including	the application	of	a	new	economic	test	designed	to	implement	the	U.S.	Second	Circuit	Court	of	Appeals	standard	in	that	court's	review	of	the	EPA's cooling	water	intake	structure	rules,	which	is	discussed	in	the	316(b)	Cooling	Water	Intake	Structures	section	below.		The	NYSDEC	has	directed Entergy	to	develop	detailed	feasibility	information	regarding	the	construction	and	operation	of	cooling	towers,	and	alternatives	to	closed	cycle cooling,	prior	to	the	issuance	of	a	new	draft	permit	by	the	NYSDEC	staff	and	commencement	of	the	adjudicatory	proceeding.		The	reports	include a	visual	impact	and	aesthetics	report	filed	in	June	2009,	a	plume	and	emissions	report	filed	in	September	2009,	a	technical	feasibility	report	and alternatives	analysis	filed	in	February	2010,	and	an	economic	report	to	establish	whether	the	technology,	if	feasible,	satisfies	the	economic	test that	is	part	of	the	New	York	standard.		Entergy	requested	that	the	NYSDEC	Assistant	Commissioner	reconsider	the	New	York	standard	in	light	of the	U.S.	Supreme	Court	decision	reversing	the	Second	Circuit's	alternative	economic	test	adopted	in	the	August	2008	ruling.		In	November	2012 the	NYSDEC	Assistant	Commissioner's	delegate	issued	a	decision	overturning	the	alternative	economic	test	adopted	in	the	August	2008	ruling and	reestablishing	the	"wholly	disproportionate"	test	derived	from	previous	New	York	precedent.	The	wholly	disproportionate	test	considers whether	the	costs	of	a	technology	are	wholly	disproportionate	to	the	environmental	benefits	gained	from	the	technology.

In	February	2010,	Entergy	provided	to	the	NYSDEC	an	updated	estimate	of	the	capital	cost	to	retrofit	Indian	Point	2	and	Indian	Point	3 with	cooling	towers.	Construction	costs	for	retrofitting	with	cooling	towers	are	estimated	to	be	at	least	$1.19	billion,	in	addition	to	lost	generation of	approximately	14.5	terawatt-hours	(TWh)	during	the	forced	outage	of	both	units	that	is	estimated	to	take	at	least	42	weeks.	Entergy	 also proposed	an	alternative	to	the	cooling	towers,	the	use	of	cylindrical	wedgewire	screens,	the	construction	costs	of	which	are	now	expected	to	be approximately	$250	million	to	$300	million.	Because	a	cooling	tower	retrofitting	of	this	size	and	complexity	has	never	been	undertaken	at	an operating	nuclear	facility,	significant	uncertainties	exist	in	the	capital	cost	estimates	and,	therefore,	the	actual	capital	costs	could	be	materially higher	than	estimated.	Moreover,	construction	outage-related	costs	to	Entergy	have	not	been	calculated	because	of	the	significant	variability	in power	pricing	at	any	given	time,	but	they	are	expected	to	be	significant	and	may	exceed	the	capital	costs.	The	capital	cost	estimate	for	the wedgewire	screen	construction	is	also	subject	to	uncertainty.	Hearings	on	certain	issues	began	in	2011	in	consolidation	with	certain	issues	in	the water	quality	certification	matter	that	is	discussed	further	below.

Entergy	submitted	its	application	for	a	water	quality	certification	to	the	NYSDEC	in	April	2009,	with	a	reservation	of	rights	regarding	the applicability	of	Section	401	in	this	case.		After	Entergy	submitted	certain	additional	information	in	response	to	NYSDEC	requests	for	additional information,	in	February	2010	the	NYSDEC	staff	determined	that	Entergy's	water	quality	certification	application	was	complete.		In	April	2010 the	NYSDEC	staff	issued	a	proposed	notice	of	denial	of	Entergy's	water	quality	certification	application	(the	Notice).		NYSDEC	staff's	Notice triggered	an	administrative	adjudicatory	hearing	before	NYSDEC	ALJs	on	the	proposed	Notice.		The	NYSDEC	staff	decision	does	not	restrict Indian	Point	operations,	but	the	issuance	of	a	certification	is	potentially	required	prior	to	NRC	issuance	of	renewed	unit	licenses.

In	June	2011,	Entergy	filed	notice	with	the	NRC	that	the	NYSDEC,	the	agency	that	would	issue	or	deny	a	water	quality	certification	for the	 Indian	 Point	 license	 renewal	 process,	 has	 taken	 longer	 than	 one	 year	 to	 take	 final	 action	 on	 Entergy's	 application	 for	 a	 water	 quality certification	and,	therefore,	had	waived	its	opportunity	to	require	a	certification	under	the	provisions	of	Section	401	of	the	Clean	Water	Act.		The NYSDEC	 had	 notified	 the	 NRC	 that	 it	 disagrees	 with	 Entergy's	 position	 and	 does	 not	 believe	 that	 it	 has	 waived	 the	 right	 to	 require	 a certification.		The	NYSDEC	ALJs	overseeing	the	agency's	certification	adjudicatory	process	stated	in	a	ruling	issued	in	July	2011	that	while	the waiver	issue	is	pending	before	the	NRC,	the	NYSDEC	hearing	process	will	continue	on	selected	issues.		The	ALJs	held	a	Legislative	Hearing (agency	public	comment	session)	and	an	Issues	Conference	(pre-trial	conference)	in	July	2010	and	set	certain	issues	for	trial	in	October	2011.

Hearings	were	held	in	July	2013	before	NYSDEC	ALJs	on	environmental	issues	related	to	Indian	Point's	wedgewire	screen	proposal	for "best	technology	available."	The	ALJs	have	issued	no	partial	decisions	on	the	several	issues	that	have	been	litigated	during	the	past	two	years	and have	not	announced	a	schedule	for	doing	so.	Hearings	are	scheduled	to	continue	in	2014	and	will	be	followed	by	post-hearing	briefing.	After	the full	hearing	on	the	merits,	the

ALJs	will	issue	a	recommended	decision	to	the	Commissioner	who	will	then	issue	the	final	agency	decision.		A	party	to	the	proceeding	can	appeal the	decision	of	the	Commissioner	to	state	court.

# Pilgrim	Nuclear	Power	Station

On	October	9,	2012,	EcoLaw,	a	coalition	of	several	environmental	groups,	served	Entergy	Nuclear	Generating	Company	and	Entergy Nuclear	Operations,	Inc.	with	a	notice	of	intent	(NOI)	to	sue	under	the	Clean	Water	Act	for	alleged	violations	at	the	Pilgrim	Nuclear	Power Station.		The	NOI	alleges	33,253	discharge	permit	violations	since	1994	(including	alleged	violations	prior	to	Entergy's	ownership;	Entergy purchased	the	plant	in	1999)	and	seeks	$25,000	per	violation	for	a	total	of	$831,325,000.		The	Clean	Water	Act	states	that	an	alleged	violator	must be	given	60	days	notice	prior	to	a	citizen's	suit	being	filed.		Review	of	the	NOI	indicates	that	many	of	the	alleged	violations	were	discharges	in compliance	with	the	current	EPA	facility	discharge	permit,	which	the	putative	plaintiff	alleges	was	improperly	issued	or	modified.		An	additional NOI	was	served	by	EcoLaw	to	the	same	Entergy	parties	and	the	Massachusetts	Department	of	Environmental	Protection	alleging	violations	of state	water	quality	standards	and	requesting	revocation	of	the	state-issued	Section	401	Water	Quality	Certification	associated	with	the	plant's	water discharge	permit.		On	November	2,	2012	and	December	7,	2012,	Entergy	filed	responses	to	the	state	and	federal	notices	of	intent	to	sue.		To	date, Pilgrim	has	not	received	notice	that	EcoLaw	has	initiated	any	lawsuits	against	Pilgrim.

# 316(b)	Cooling	Water	Intake	Structures

The	EPA	finalized	regulations	in	July	2004	governing	the	intake	of	water	at	large	existing	power	plants	employing	cooling	water	intake structures.	The	rule	sought	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	challenged	various	aspects	of	the	rule.	In	January 2007	the	U.S.	Second	Circuit	Court	of	Appeals	remanded	the	rule	to	the	EPA	for	reconsideration.	The	court	instructed	the	EPA	to	reconsider several	aspects	of	the	rule	that	were	beneficial	to	businesses	affected	by	the	rule	after	finding	that	these	provisions	of	the	rule	were	contrary	to	the language	of	the	Clean	Water	Act	or	were	not	sufficiently	explained	in	the	rule.	In	April	2008	the	U.S.	Supreme	Court	agreed	to	review	the	Second Circuit	decision	on	 the	question	of	whether	 the	EPA	may	 take	 into	consideration	a	cost-benefit	analysis	 in	developing	 these	regulations,	a consideration	of	potential	benefit	to	businesses	affected	by	the	rule	that	the	Second	Circuit	disallowed.	In	March	2009	the	Supreme	Court	ruled	in favor	of	 the	petitioners	 that	cost-benefit	analysis	may	be	 taken	 into	consideration.	The	EPA	reissued	the	proposed	rule	in	April	2011,	with finalization	anticipated	by	July	27,	2012;	however,	 the	EPA	extended	 the	deadline	 to	June	27,	2013.	 EPA	further	extended	the	deadline	to November	4,	2013	and	then	again	to	January	14,	2014	in	order	to	consult	with	federal	resource	agencies	regarding	threatened	and	endangered species	issues.	The	EPA	did	not	meet	the	January	14,	2014	deadline.	On	February	10,	2014,	the	EPA	announced	a	revised	agreement	to	issue	the final	rule	by	April	17,	2014.	The	revised	agreement	also	states	that	the	EPA	does	not	intend	to	ask	for	any	more	extensions.	Entergy	 filed comments	with	the	EPA	on	the	proposed	rule.

Entergy	will	continue	to	review	the	revised	proposed	rule	and	monitor	the	activities	of	the	EPA	and	the	states	toward	the	implementation of	Section	316(b)	of	the	Clean	Water	Act.		Until	the	final	rule	is	issued	by	the	EPA	,	deadlines	for	determining	compliance	with	Section	316(b) and	for	any	required	capital	or	operational	expenditures	are	unknown	at	this	time.		As	a	result,	management	cannot	predict	the	amounts	Entergy will	ultimately	be	required	to	spend	to	comply	with	Section	316(b)	and	any	related	state	regulations,	although	such	amounts	could	be	significant.

# Coastal	Zone	Management	Act

Before	a	federal	licensing	agency	(such	as	the	NRC)	may	issue	a	major	license	or	permit	for	an	activity	within	the	federally	designated coastal	zone,	the	agency	must	be	satisfied	that	the	requirements	of	the	Coastal	Zone	Management	Act	(CZMA),	as	applicable,	have	been	met.	In many	cases,	CZMA	requirements	are	satisfied	by	the	state's	written	concurrence	with	a	"consistency	determination"	filed	by	the	federal	license applicant	explaining	why	the	activity	proposed	to	be	federally	licensed	is	consistent	with	the	state's	coastal	management	program.	The	CZMA gives	the

state	six	months	to	act	once	the	consistency	determination	is	deemed	complete;	failure	to	act	is	treated	as	a	deemed	concurrence.	Entergy	 is pursuing	three	independent	paths	to	ensure	that	CZMA	requirements	for	Indian	Point	license	renewal	are	met.	For	additional	discussion	of	the CZMA	 proceedings	 related	 to	 Indian	 Point	 license	 renewal	 see	 "Part	 1, Item	 1,	Entergy	Wholesale	 Commodities –	Property	 -	 Nuclear Generating	Stations."

# Effluent	Limitation	Guidelines

In	April	2013	the	EPA	issued	proposed	effluent	limitation	guidelines	that,	if	adopted	as	final,	would	apply	to	discharges	from	Entergy's generating	facilities	that	hold	national	pollutant	discharge	elimination	system	permits	under	the	Clean	Water	Act.		The	proposal	includes	several options	for	public	consideration.		Entergy	submitted	comments	on	the	proposed	rule	and	will	continue	to	engage	in	the	public	comment	process	as appropriate.

# Federal	Jurisdiction	of	Waters	of	the	United	States

In	September	2013	the	EPA	and	the	U.S.	Army	Corps	of	Engineers	announced	the	intention	to	propose	a	rule	to	clarify	federal	Clean Water	Act	jurisdiction	over	waters	of	the	United	States.	The	announcement	was	made	in	conjunction	with	the	EPA's	release	of	a	draft	scientific report	on	the	"connectivity"	of	waters	that	the	agency	says	will	inform	the	rulemaking.	Entergy	is	continuing	to	evaluate	these	documents	and agency	actions,	but	preliminary	review	indicates	that	this	proposal	could	significantly	increase	the	number	and	types	of	waters	included	in	the EPA's	and	the	U.S.	Army	Corps	of	Engineers'	jurisdiction,	which	in	turn	could	pose	additional	permitting	and	pollutant	management	burdens	on Entergy's	operations.

# Groundwater	at	Certain	Nuclear	Sites

The	NRC	requires	nuclear	power	plants	to	regularly	monitor	and	report	the	presence	of	radioactive	material	in	the	environment.		Entergy joined	 other	 nuclear	 utilities	 and	 the	 Nuclear	 Energy	 Institute	 in	 2006	 to	 develop	 a	 voluntary	 groundwater	 monitoring	 and	 protection program.		This	initiative	began	after	detection	of	very	low	levels	of	radioactive	material,	primarily	tritium,	in	groundwater	at	several	plants	in	the United	States.		Tritium	is	a	radioactive	form	of	hydrogen	that	occurs	naturally	and	is	also	a	byproduct	of	nuclear	plant	operations.		In	addition	to tritium,	other	radionuclides	have	been	found	in	site	groundwater	at	nuclear	plants.

As	part	of	the	groundwater	monitoring	and	protection	program,	Entergy	has:	(1)	performed	reviews	of	plant	groundwater	characteristics (hydrology)	and	historical	records	of	past	events	on	site	that	may	have	potentially	impacted	groundwater;	(2)	implemented	fleet	procedures	on how	to	handle	events	that	could	impact	groundwater;	and	(3)	installed	groundwater	monitoring	wells	and	began	periodic	sampling.		The	program also	includes	protocols	for	notifying	local	officials	if	contamination	is	found.	 	To	date,	radionuclides	such	as	tritium	have	been	detected	at Arkansas	Nuclear	One,	FitzPatrick,	Indian	Point,	Palisades,	Pilgrim,	Grand	Gulf,	Vermont	Yankee,	and	River	Bend.		Each	of	these	sites	has installed	groundwater	monitoring	wells	and	implemented	a	program	for	testing	groundwater	at	the	sites	for	the	presence	of	tritium.		Based	on current	information,	the	concentrations	and	locations	of	tritium	detected	at	these	plants	pose	no	threat	to	public	health	or	safety,	but	each	site continues	to	evaluate	the	results	from	its	groundwater	monitoring	program.

# Indian	Point	Units	1	and	2	Hazardous	Waste	Remediation

Prior	to	Entergy's	purchase	of	Indian	Point	Unit	1,	the	previous	owner	completed	the	cleanup	and	desludging	of	the	Unit	1	water	storage pool,	generating	mixed	waste.	The	existing	mixed	waste	storage	permit	and	an	associated	order	on	consent	were	transferred	to	Entergy	upon purchasing	the	unit.	The	waste	is	stored	in	the	Unit	1	containment	building	in	accordance	with	NRC	regulations	controlling	low	level	radioactive waste.	An	 order	 on	 consent	 with	 NYSDEC	 requires	 a	 quarterly	 survey	 of	 the	 availability	 of	 any	 commercial	 facility	 capable	 of	 treating, processing,	and	disposing	of	this	waste	in	a	commercially	reasonable	manner.	However,	in	2005,	NYSDEC	revised	its	regulations	to	conditionally exempt	the	storage	and	disposal	of	mixed	waste	that	is	regulated	by	the	NRC.	Thus,	in	October	2005	and	again	in	January	2013,	Entergy	requested that	NYSDEC	terminate	the	mixed	waste	permit	and	order	on	consent	because	the	waste	falls	within	the	mixed	waste	exemption.	On	April	26, 2013,	NYSDEC	agreed	with	Entergy's	request	to	terminate	the	permit	finding	that	as	long	as	the	facility	continues	to	meet	the	exemption,	the mixed	waste	permit	is

not	required.	NYSDEC	denied	the	request	to	terminate	the	consent	order,	however,	reasoning	that	it	contains	provisions	for	storage	and	reporting that	are	still	applicable.	Entergy	continues	to	manage	the	waste	according	to	applicable	regulatory	requirements.

# 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	to mandate	clean-up	by,	or	to	collect	reimbursement	of	clean-up	costs	from,	owners	or	operators	of	sites	at	which	hazardous	substances	may	be	or have	been	released.		Certain	private	parties	also	may	use	CERCLA	to	recover	response	costs.		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.		Many	states	have	adopted	programs	similar	to	CERCLA.		Entergy	subsidiaries	in	the	Utility	and Entergy	Wholesale	Commodities	businesses	have	sent	waste	materials	to	various	disposal	sites	over	the	years,	and	releases	have	occurred	at Entergy	 facilities.	 	 In	 addition,	 environmental	 laws	 now	 regulate	 certain	 of	 Entergy's	 operating	 procedures	 and	 maintenance	 practices	 that historically	were	not	subject	to	regulation.		Some	disposal	sites	used	by	Entergy	subsidiaries	have	been	the	subject	of	governmental	action	under CERCLA	or	similar	state	programs,	resulting	in	site	clean-up	activities.		Entergy	subsidiaries	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	 Entergy subsidiaries	have	established	provisions	for	the	liabilities	for	such	environmental	clean-up	and	restoration	activities.		Details	of	CERCLA	and similar	state	program	liabilities	that	are	not	de	minimis	are	discussed	in	the	"Other	Environmental	Matters"	section	below.

# Coal	Combustion	Residuals

In	June	2010	the	EPA	issued	a	proposed	rule	on	coal	combustion	residuals	(CCRs)	that	contains	two	primary	regulatory	options:	(1) regulating	CCRs	destined	for	disposal	in	landfills	or	received	(including	stored)	in	surface	impoundments	as	so-called	"special	wastes"	under	the hazardous	waste	program	of	RCRA	Subtitle	C;	or	(2)	regulating	CCRs	destined	for	disposal	 in	 landfills	or	surface	 impoundments	as	non- hazardous	wastes	under	Subtitle	D	of	RCRA.		Under	both	options,	CCRs	that	are	beneficially	used	in	certain	processes	would	remain	excluded from	hazardous	waste	regulation.

The	 proposed	 regulations	 would	 create	 new	 compliance	 requirements	 including	 modified	 storage,	 new	 notification	 and	 reporting practices,	new	financial	assurance	requirements,	and	product	disposal	considerations.		According	to	EPA	estimates,	the	annualized	cost	(in	2010 $)of	on-site	disposal	under	the	two	proposals	would	be	$3.6	million	to	$9	million	for	the	White	Bluff	and	Independence	facilities	and	$1.7	million to	$3.3	million	for	the	Nelson	Unit	6	facility.		If	Entergy	utilized	off-site	disposal,	which	it	would	not	plan	to	do,	the	EPA's	total	cost	estimates	for disposal	of	CCRs	under	Subtitle	C	regulation	ranges	from	$250	to	$350	million	per	year.		Entergy	believes	that	on-site	disposal	options	will	be available	at	its	facilities,	to	the	extent	needed	for	CCR	that	cannot	be	transferred	for	beneficial	reuse.		Entergy	commented	on	the	proposed	rule and	will	continue	to	monitor	and	participate	in	the	rulemaking	process,	which	is	expected	to	be	finalized	by	December	2014.

# Other	Environmental	Matters

# Entergy	Gulf	States	Louisiana	and	Entergy	Texas

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

Entergy	Gulf	States	Louisiana	is	currently	involved	in	the	second	phase	of	the	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,	Inc.	signed	a	second	administrative	consent	order	with	the	EPA	to	perform	a	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.		In	August	2005	an	administrative	order	was	issued	by	the	EPA	requiring that	a	10-year	groundwater	study	be	conducted	at	this	site.		The	groundwater	monitoring	study	commenced	in	January	2006	and	is	continuing.		In 2010	the	EPA	conducted	a	Five	Year	Review	(FYR)	of	the	10-year	groundwater	monitoring	program	at	Lake	Charles.		Negotiations	are	on-going regarding	 whether	 additional	 actions	 will	 be	 necessary	 at	 the	 site. If	 additional	 actions	 are	 necessary,	 site	 expenditures	 will	 increase commensurate	with	the	additional	chosen	site	remedies.	Entergy	does	not	have	sufficient	information	at	this	time	to	estimate	additional	site	costs, if	any.	Entergy	also	has	made	a	payment	to	the	EPA	of	$275,000	for	past	agency	oversight	costs.	Entergy	Gulf	States	Louisiana	and	Entergy	Texas each	believe	that	its	remaining	responsibility	for	this	site	will	not	materially	exceed	the	existing	clean-up	provisions	of	$0.3	million	for	Entergy Gulf	States	Louisiana	and	$0.2	million	for	Entergy	Texas.

# Entergy	Gulf	States	Louisiana,	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's	premises	(see	"Litigation"	below).

During	 1993,	 the	 LDEQ	 issued	 new	 rules	 for	 solid	 waste	 regulation,	 including	 regulation	 of	 wastewater	 impoundments.	 	 Entergy Louisiana	determined	that	some	of	its	power	plant	wastewater	impoundments	were	affected	by	these	regulations	and	required	remediation,	repair, or	closure.	 	Entergy	Gulf	States	Louisiana	and	Entergy	New	Orleans	were	also	affected.	 	In	2013,	Entergy	Gulf	States	Louisiana,	Entergy Louisiana,	and	Entergy	New	Orleans	eliminated	their	provisions	for	the	liability	associated	with	ongoing	wastewater	remediation	and	repairs	and closures.		Elimination	of	the	provisions	occurred	because	several	wastewater	impoundments	were	satisfactorily	closed	in	place	and	removed	from the	Louisiana	Solid	Waste	Program	and	all	necessary	approvals	have	been	received	from	the	LDEQ.

Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas

The	Texas	Commission	on	Environmental	Quality	(TCEQ)	notified	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana, Entergy	New	Orleans,	and	Entergy	Texas	that	the	TCEQ	believes	those	entities	are	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	subsidiaries	sent	transformers	to	this	facility.		Entergy	Gulf States	Louisiana,	Entergy	Texas,	Entergy	Louisiana,	and	Entergy	Arkansas	responded	to	an	information	request	from	the	TCEQ	and	continue	to cooperate	in	this	investigation.		Entergy	Gulf	States	Louisiana,	Entergy	Texas,	and	Entergy	Louisiana	joined	a	group	of	PRPs	responding	to	site conditions	 in	 cooperation	 with	 the	 State	 of	 Texas,	 creating	 cost	 allocation	 models	 based	 on	 review	 of	 SESCO	 documents	 and	 employee interviews,	and	investigating	contribution	actions	against	other	PRPs.		Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	Entergy	Texas	have agreed	 to	 contribute	 to	 the	 remediation	 of	 contaminated	 soil	 and	 groundwater	 at	 the	 site	 in	 a	 measure	 proportionate	 to	 those	 companies' involvement	at	the	site,	while	Entergy	Arkansas	likely	will	pay	a	de	minimis	amount.		Current	estimates,	although	preliminary	and	variable depending	on	the	level	of	third-party	cost	contributions,	indicate	that	Entergy's	total	share	of	remediation	costs	likely	will	be	in	the	range	of	$1.5 million	to	$2	million.		Remediation	activities	continue	at	the	site.

Entergy	Mississippi,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas

The	EPA	notified	Entergy	Mississippi,	Entergy	Gulf	States	Louisiana,	Entergy	Texas,	and	Entergy	New	Orleans	that	the	EPA	believes those	entities	are	PRPs	concerning	contamination	of	an	area	known	as	"Devil's	Swamp	Lake"	near	the	Port	of	Baton	Rouge,	Louisiana.		The	area allegedly	was	contaminated	by	the	operations	of	Rollins

Environmental	(LA),	Inc,	which	operated	a	disposal	facility	to	which	many	companies	contributed	waste.		Documents	provided	by	the	EPA indicate	that	Entergy	Louisiana	may	also	be	a	PRP.		Entergy	continues	to	monitor	this	developing	situation.

Entergy	uses	legal	and	appropriate	means	to	contest	litigation	threatened	or	filed	against	it,	but	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.	 	The	 litigation environment	in	these	states	poses	a	significant	business	risk	to	Entergy.

Ratepayer	and	Fuel	Cost	Recovery	Lawsuits		(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New Orleans,	and	Entergy	Texas)

See	Note	2	to	the	financial	statements	for	a	discussion	of	this	proceeding.

Asbestos	 Litigation (Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy	 Louisiana,	 Entergy	 Mississippi,	 Entergy	 New	 Orleans,	 and Entergy	Texas)

See	Note	8	to	the	financial	statements	for	a	discussion	of	this	litigation.

Employment	and	Labor-related	Proceedings	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

See	Note	8	to	the	financial	statements	for	a	discussion	of	these	proceedings.

# Employees

Employees	are	an	integral	part	of	Entergy's	commitment	to	serving	customers.		As	of	 December	31,	2013,	Entergy	subsidiaries	employed 13,808	people.

| Utility: |  |
| :--- | :--- |
| Entergy\tArkansas | 1,274 |
| Entergy\tGulf\tStates\tLouisiana | 763 |
| Entergy\tLouisiana | 923 |
| Entergy\tMississippi | 724 |
| Entergy\tNew\tOrleans | 318 |
| Entergy\tTexas | 607 |
| System\tEnergy | — |
| Entergy\tOperations | 2,880 |
| Entergy\tServices | 2,728 |
| Entergy\tNuclear\tOperations | 3,522 |
| Other\tsubsidiaries | 69 |
| Total\tEntergy | 13,808 |

Approximately	5,200	employees	are	represented	by	the	International	Brotherhood	of	Electrical	Workers,	the	Utility	Workers	Union	of America,	the	International	Brotherhood	of	Teamsters,	the	United	Government	Security	Officers	of	America,	and	the	International	Union,	Security, Police,	Fire	Professionals	of	America.

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

Entergy	electronically	files	reports	with	the	SEC,	including	annual	reports	on	Form	10-K,	quarterly	reports	on	Form	10-Q,	current	reports on	Form	8-K,	proxies,	and	amendments	to	such	reports.		The	public	may	read	and	copy	any	materials	that	Entergy	files	with	the	SEC	at	the	SEC's Public	Reference	Room	at	100	F	Street,	NE,	Washington,	D.C.	20549.	 	The	public	may	obtain	information	on	the	operation	of	the	Public Reference	Room	by	calling	the	SEC	at	1-800-SEC-0330.		The	SEC	also	maintains	an	internet	site	that	contains	reports,	proxy	and	information statements,	and	other	information	regarding	registrants	that	file	electronically	with	the	SEC	at	http://www.sec.gov.

Entergy	uses	its	website,	http://www.entergy.com,	as	a	routine	channel	for	distribution	of	important	information,	including	news	releases, analyst	presentations	and	financial	information.		Filings	made	with	the	SEC	are	posted	and	available	without	charge	on	Entergy's	website	as	soon as	reasonably	practicable	after	they	are	electronically	filed	with,	or	furnished	to,	the	SEC.		These	filings	include	our	annual	and	quarterly	reports on	Forms	10-K	and	10-Q	(including	related	filings	in	XBRL	format)	and	current	reports	on	Form	8-K;	our	proxy	statements;	and	any	amendments to	those	reports	or	statements.		All	such	postings	and	filings	are	available	on	Entergy's	Investor	Relations	website	free	of	charge.		Entergy	is providing	the	address	to	its	Internet	site	solely	for	the	information	of	investors	and	does	not	intend	the	address	to	be	an	active	link.		The	contents of	the	website	are	not	incorporated	into	this	report.

# RISK	FACTORS

Investors	should	review	carefully	the	following	risk	factors	and	the	other	information	in	this	Form	10-K.		The	risks	that	Entergy	faces	are not	limited	to	those	in	this	section.		There	may	be	additional	risks	and	uncertainties	(either	currently	unknown	or	not	currently	believed	to	be material)	 that	 could	 adversely	 affect	 Entergy's	 financial	 condition,	 results	 of	 operations,	 and	 liquidity.	 	 See "FORWARD-LOOKING INFORMATION."

# Utility	Regulatory	Risks

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

# The	terms	and	conditions	of	service,	including	electric	and	gas	rates,	of	the	Utility	operating	companies	and	System	Energy	are determined	 through	regulatory	approval	proceedings	 that	are	 lengthy	and	subject	 to	appeal	 that	could	result	 in	delays	 in	effecting	rate changes	and	uncertainty	as	to	ultimate	results.

The	rates	that	the	Utility	operating	companies	and	System	Energy	charge	reflect	their	capital	expenditures,	operations	and	maintenance costs,	allowed	rates	of	return,	financing	costs,	and	related	costs	of	service.		These	rates	significantly	influence	the	financial	condition,	results	of operations,	and	liquidity	of	Entergy	and	each	of	the	Utility	operating	companies	and	System	Energy.		These	rates	are	determined	in	regulatory proceedings	and	are	subject	to	periodic	regulatory	review	and	adjustment.

In	addition,	regulators	can	initiate	proceedings	to	investigate	the	prudence	of	costs	in	the	Utility	operating	companies'	base	rates	and examine,	among	other	things,	the	reasonableness	or	prudence	of	the	companies'	operation	and	maintenance	practices,	level	of	expenditures (including	storm	costs	and	costs	associated	with	capital	projects),	allowed	rates	of	return	and	rate	base,	proposed	resource	acquisitions,	and previously	incurred	capital	expenditures	that	the	operating	companies	seek	to	place	in	rates.		The	regulators	can	disallow	costs	subject	to	their jurisdiction	found	not	to	have	been	prudently	incurred	or	found	not	to	have	been	incurred	in	compliance	with	applicable	tariffs,	creating	some	risk to	the	ultimate	recovery	of	those	costs.		Regulatory	proceedings	relating	to	rates	and	other	matters	typically	involve	multiple	parties	seeking	to limit	or	reduce	rates.		The	proceedings	generally	have	long	timelines,	are	primarily	based	on	historical	costs,	and	may	or	may	not	be	limited	in scope	or	duration	by	statute.	The	length	of	the	proceedings	can	cause	the	Utility	operating	companies	and	System	Energy	to	experience	regulatory lag	in	recovering	costs	through	rates.		Decisions	are	typically	subject	to	appeal,	potentially	leading	to	additional	uncertainty	associated	with	rate case	proceedings.

The	base	rates	of	Entergy	Arkansas	and	Entergy	Texas	are	established	in	traditional	base	rate	case	proceedings.	Entergy	Arkansas	recovers fuel	and	purchased	energy	and	certain	non-fuel	costs	through	other	APSC-approved	tariffs.	Entergy	Mississippi	infrequently	has	traditional	base rate	cases.	More	commonly,	it	obtains	base	rate	adjustments	through	its	formula	rate	plan	which	operates	annually.	In	the	event	that	this	formula rate	plan	were	terminated,	Entergy	Mississippi	would	at	that	time	revert	to	the	more	traditional	rate	case	environment.

In	January	2013,	Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	current	formula	rate	plans	expired,	and	each	company	filed	full rate	cases	in	February	2013.	As	part	of	the	rate	cases	that	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	filed,	each	company	requested	that the	LPSC	approve	new	formula	rate	plans.		In	December	2013	the	LPSC	voted	to	approve	a	settlement	that	provides	for	the	continued	use,	through the	test	year	2016	filing,	of	formula	rate	plans	by	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana.	Entergy	Louisiana's	formula	rate	plan changes	are	capped	at	a	cumulative	total	of	$30	million	through	the	formula	rate	plan	cycle.	Entergy	Gulf	States	Louisiana	has	no	cap	but	is	not permitted	to	increase	rates	prior	to	the	test	year	2015	filing.	As	part	of	the	settlement,	both	companies	established	riders	to	recover	non-fuel MISO-related	 costs	 separately	 from	 the	 formula	 rate	 plan	 requirements	 and	 may	 recover	 MISO	 fuel	 and	 energy-related	 costs	 in	 their	 fuel adjustment	clauses.	The	formula	rate	plans	continue	to	retain	exceptions	for	certain	large	capital	investment	projects,	including	the	Ninemile	6 generating	facility.	In	the	event	that	these	formula	rate	plans	were	terminated,	or	expire	without	renewal	or	extension,	Entergy

Gulf	States	Louisiana	and	Entergy	Louisiana	would	at	that	time	revert	to	the	more	traditional	rate	case	environment.	Entergy	New	Orleans	has operated	under	a	formula	rate	plan	that	ended	with	the	2011	test	year	and	has	not	yet	been	extended.	If	no	formula	rate	plan	is	approved	going forward,	Entergy	New	Orleans	will	be	operating	in	the	more	traditional	rate	case	environment.

The	Utility	operating	companies	and	System	Energy,	and	the	energy	industry	as	a	whole,	have	experienced	a	period	of	rising	costs	and investments,	and	an	upward	trend,	especially	with	respect	to	infrastructure	investments,	which	is	likely	to	continue	in	the	foreseeable	future	and could	result	in	more	frequent	rate	cases	and	requests	for,	and	the	continuation	of,	cost	recovery	mechanisms.		For	information	regarding	rate	case proceedings	and	formula	rate	plans	applicable	to	certain	of	the	Utility	operating	companies,	see	Note	2	to	the	financial	statements.

# The	Utility	operating	companies	recover	fuel	and	purchased	power	costs	through	rate	mechanisms	that	are	subject	to	risks	of	delay	or disallowance	in	regulatory	proceedings.

The	Utility	operating	companies	recover	their	fuel	and	purchased	power	costs	from	their	customers	through	rate	mechanisms	subject	to periodic	regulatory	review	and	adjustment.		Because	regulatory	review	can	result	in	the	disallowance	of	incurred	costs	found	not	to	have	been prudently	incurred	with	the	possibility	of	refunds	to	ratepayers,	there	exists	some	risk	to	the	ultimate	recovery	of	those	costs.		Regulators	can initiate	proceedings	to	investigate	the	continued	usage	or	the	adequacy	and	operation	of	the	fuel	and	purchased	power	recovery	clauses	of	the Utility	operating	companies.

The	 Utility	 operating	 companies'	 cash	 flows	 can	 be	 negatively	 affected	 by	 the	 time	 delays	 between	 when	 gas,	 power,	 or	 other commodities	are	purchased	and	the	ultimate	recovery	from	customers	of	the	costs	in	rates.		On	occasion,	when	the	level	of	incurred	costs	for	fuel and	purchased	power	rises	very	dramatically,	some	of	the	Utility	operating	companies	may	agree	to	defer	recovery	of	a	portion	of	that	period's fuel	and	purchased	power	costs	for	recovery	at	a	later	date,	which	could	increase	the	near-term	working	capital	and	borrowing	requirements	of those	companies.		For	a	description	of	fuel	and	purchased	power	recovery	mechanisms	and	information	regarding	the	regulatory	proceedings	for fuel	and	purchased	power	costs	recovery,	see	Note	2	to	the	financial	statements.

As	a	result	of	a	challenge	by	the	LPSC,	the	manner	in	which	the	Utility	operating	companies	have	traditionally	shared	the	costs associated	with	coordinated	planning,	construction,	and	operation	of	generating	resources	has	been	changed	by	the	FERC,	which	could require	adjustment	of	retail	and	wholesale	rates	in	the	jurisdictions	where	the	Utility	operating	companies	provide	service	and	has	introduced additional	uncertainty	in	the	ratemaking	process.

The	 Utility	 operating	 companies	 historically	 have	 engaged	 in	 the	 coordinated	 planning,	 construction,	 and	 operation	 of	 generating resources	and	bulk	transmission	facilities	under	the	terms	of	the	System	Agreement,	which	is	a	rate	schedule	that	has	been	approved	by	the FERC.		In	2005	the	FERC	issued	a	decision	requiring	changes	to	the	cost	allocation	methodology	used	in	that	rate	schedule.

In	2007	through	2012,	payments	were	made	by	Entergy	Arkansas	to	certain	of	the	Utility	operating	companies	in	compliance	with	the 2005	FERC	decision	on	the	cost	allocation	methodology,	and	in	2013	a	payment	was	made	by	Entergy	Texas	to	Entergy	New	Orleans.		There have	been	challenges	to	the	level	and	timing	of	payments	made	by	Entergy	Arkansas	under	the	FERC's	decision	and	the	prudence	of	the	Utility operating	companies'	production	costs.		The	ability	to	recover	in	rates	any	changes	to	the	cost	allocation	resulting	from	the	challenges,	and	timing of	such	recovery,	could	be	uncertain	and	could	be	the	subject	of	additional	regulatory	and	other	proceedings.		For	information	regarding	these	and other	proceedings	associated	with	the	System	Agreement,	as	well	as	additional	information	regarding	the	System	Agreement	itself,	see	Note	2	to financial statements,	System	Agreement	Cost	Equalization	Proceedings.	The	outcome	and timing	of	 this	FERC	proceeding	and	resulting recovery	and	impact	on	rates	cannot	be	predicted	at	this	time.

# The	withdrawal	and	notices	of	withdrawal	of	certain	Utility	operating	companies	from	the	System	Agreement	creates	uncertainty	as	to the	long-term	viability	of	the	System	Agreement.

Entergy	Arkansas'	participation	in	the	System	Agreement	terminated	in	December	2013,	and	Entergy	Mississippi's	participation	in	the System	Agreement	is	scheduled	to	terminate	in	November	2015.

In	 October	 2013,	 the	 Utility	 operating	 companies	 filed	 at	 the	 FERC	 seeking	 to	 shorten	 to	 60	 months	 the	 provision	 in	 the	 System Agreement	that	requires	a	Utility	operating	company	seeking	to	withdraw	from	the	System	Agreement	to	provide	96	months	advance	notice	of termination	 of	 participation.	 In	 October	 2013,	 Entergy	 Texas	 provided	 its	 notice	 to	 the	 other	 Utility	 operating	 companies	 to	 terminate	 its participation	in	the	System	Agreement	after	expiration	of	the	proposed	60-month	notice	period	or	such	other	period	as	approved	by	the	FERC. Subsequently,	Entergy	Texas	filed	its	notice	to	terminate	its	participation	in	the	System	Agreement	at	FERC	in	October	2013.	In	January	2014,	the LPSC	directed	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	to	provide	no	later	than	February	15,	2014	notice	of	their	intention	to terminate	their	participation	in	the	System	Agreement,	and	to	use	their	reasonable	best	efforts	to	achieve	a	consensual	resolution	permitting	early termination	 of	 the	 System	 Agreement.	Entergy	 Louisiana	 and	 Entergy	 Gulf	 States	 Louisiana	 provided	 such	 notice	 on	 February	 14,	 2014. Accordingly,	there	is	uncertainty	as	to	the	long-term	continued	viability	of	the	System	Agreement	and	the	effect	of	the	absence	of	such	an arrangement	on	the	Utility	operating	companies.

For	further	information	regarding	the	regulatory	proceedings	relating	to	the	System	Agreement,	see	the	" Rate,	Cost-recovery,	and	Other Regulation	-	Federal	Regulation	-	System	Agreement"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy	Corporation	and Subsidiaries.

The	Utility	operating	companies	are	subject	to	economic	risks	associated	with	participation	in	the	MISO	markets	and	the	allocation	of transmission	upgrade	costs.	The	operation	of	the	Utility	operating	companies'	transmission	system	pursuant	to	the	MISO	RTO	tariff	and	their participation	in	the	MISO	RTO's	wholesale	markets	may	be	adversely	affected	by	regulatory	or	market	design	changes,	as	well	as	liability under,	or	any	future	inability	to	comply	with,	existing	or	future	regulations	or	requirements.

On	December	19,	2013,	the	Utility	operating	companies	integrated	into	the	MISO	RTO.	For	further	information	regarding	the	FERC	and proceedings	related	to	the	ICT	and	MISO,	see	the	"Rate,	Cost-recovery,	and	Other	Regulation	-	Federal	Regulation	-	Entergy's	Integration Into	the	MISO	Regional	Transmission	Organization"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy	Corporation	and Subsidiaries.	MISO	maintains	functional	control	over	the	combined	transmission	systems	of	its	members	and	administers	wholesale	energy	and ancillary	services	markets	for	market	participants	in	the	MISO	region,	including	the	Utility	operating	companies.	The	Utility	operating	companies sell	capacity,	energy,	and	ancillary	services	on	a	bilateral	basis	to	certain	wholesale	customers	and	offer	available	electricity	production	of	their generating	facilities	 into	 the	MISO	day-ahead	and	real-time	energy	markets.	The	Utility	operating	companies	are	subject	to	economic	risks associated	with	participation	in	the	MISO	markets.	RTO	rules	and	system	conditions,	including	transmission	congestion,	could	affect	the	Utility operating	 companies'	 ability	 to	 sell	 power	 in	 certain	 markets,	 and	 RTO	 market	 rules	 may	 change	 in	 a	 way,	 including	 the	 introduction	 of competition	among	transmission	providers,	that	causes	additional	risk.

The	Utility	operating	companies	participate	in	the	MISO	regional	transmission	planning	process	and	are	subject	to	risks	associated	with planning	decisions	that	MISO	makes	in	the	exercise	of	control	over	the	planning	of	the	Utility	operating	companies'	transmission	assets	that	are under	MISO's	functional	control.	The	Utility	operating	companies	may	be	required	to	contribute	to	the	cost	of	transmission	projects	that	the Utility	operating	companies	will	not	own,	which	could	increase	cash	or	financing	needs.	The	terms	and	conditions	of	the	MISO	RTO	tariff, including	provisions	related	to	the	design	and	implementation	of	wholesale	markets	and	the	allocation	of	transmission	upgrade	costs,	are	subject	to regulation	 by	 FERC.	 The	 operation	 of	 the	 Utility	 operating	 companies'	 transmission	 system	 pursuant	 to	 the	 MISO	 RTO	 tariff	 and	 their participation	in	the	MISO	RTO's	wholesale	markets	may	be	adversely	affected	by	regulatory	or	market	design	changes,	as	well	as	liability	under, or	any	future	inability	to	comply	with,	existing	or	future	regulations	or	requirements.

# (Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New Orleans,	and	Entergy	Texas)

# A	delay	or	failure	in	recovering	amounts	for	storm	restoration	costs	incurred	as	a	result	of	severe	weather	could	have	material	effects on	Entergy	and	those	Utility	operating	companies	affected	by	severe	weather.

Entergy's	and	its	Utility	operating	companies'	results	of	operations,	liquidity,	and	financial	condition	can	be	materially	affected	by	the destructive	effects	of	severe	weather.		Severe	weather	can	also	result	in	significant	outages	for	the	customers	of	the	Utility	operating	companies and,	therefore,	reduced	revenues	for	the	Utility	operating	companies	during	the	period	of	the	outages.		A	delay	or	failure	in	recovering	amounts	for storm	restoration	costs	incurred	or	revenues	lost	as	a	result	of	severe	weather	could	have	a	material	effect	on	Entergy	and	those	Utility	operating companies	affected	by	severe	weather.

# Nuclear	Operating	and	Regulatory	Risks

# (Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States 	Louisiana,	Entergy	Louisiana,	and	System	Energy)

Certain	of	 the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities	must	consistently	operate	 their nuclear	power	plants	at	high	capacity	factors	in	order	to	be	successful,	and	lower	capacity	factors	could	materially	affect	Entergy's	and	their results	of	operations,	financial	condition,	and	liquidity.

Nuclear	capacity	factors	significantly	affect	the	results	of	operations	of	certain	Utility	operating	companies,	System	Energy,	and	Entergy Wholesale	Commodities.		Nuclear	plant	operations	involve	substantial	fixed	operating	costs.		Consequently,	to	be	successful,	a	plant	owner	must consistently	operate	its	nuclear	power	plants	at	high	capacity	factors.		For	the	Utility	operating	companies	that	own	nuclear	plants,	lower	capacity factors	can	increase	production	costs	by	requiring	the	affected	companies	to	generate	additional	energy,	sometimes	at	higher	costs,	from	their fossil	facilities	or	purchase	additional	energy	in	the	spot	or	forward	markets	in	order	to	satisfy	their	supply	needs.		For	the	Entergy	Wholesale Commodities	nuclear	plants,	lower	capacity	factors	directly	affect	revenues	and	cash	flow	from	operations.		Entergy	Wholesale	Commodities's forward	sales	are	comprised	of	various	hedge	products,	many	of	which	have	some	degree	of	operational-contingent	price	risk.	Certain	 unit- contingent	contracts	guarantee	specified	minimum	capacity	factors.	In	the	event	plants	with	these	contracts	were	operating	below	the	guaranteed capacity	factors,	Entergy	would	be	subject	to	price	risk	for	the	undelivered	power.			Further,	Entergy	Wholesale	Commodities's	nuclear	forward sales	contracts	can	also	be	on	a	firm	LD	basis,	which	subjects	Entergy	to	increasing	price	risk	as	capacity	factors	decrease.	Many	of	these	firm hedge	products	have	damages	risk,	capped	through	the	use	of	risk	management	products.

Certain	of	the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities	nuclear	plant	owners	periodically shut	 down	 their	 nuclear	 power	 plants	 to	 replenish	 fuel.	 	 Plant	 maintenance	 and	 upgrades	 are	 often	 scheduled	 during	 such	 refueling outages.		If	refueling	outages	last	longer	than	anticipated	or	if	unplanned	outages	arise,	Entergy's	and	their	results	of	operations,	financial condition,	and	liquidity	could	be	materially	affected.

Outages	at	nuclear	power	plants	to	replenish	fuel	require	the	plant	to	be	"turned	off."		Refueling	outages	generally	are	planned	to	occur once	every	18	to	24	months	and	average	approximately	30	days	in	duration.		Plant	maintenance	and	upgrades	are	often	scheduled	during	such planned	outages.		When	refueling	outages	last	longer	than	anticipated	or	a	plant	experiences	unplanned	outages,	capacity	factors	decrease	and maintenance	costs	may	increase.	 	Lower	than	forecasted	capacity	factors	may	cause	Entergy	Wholesale	Commodities	to	experience	reduced revenues	and	may	also	create	damages	risk	with	certain	hedge	products	as	previously	discussed.

Certain	of	the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities	face	risks	related	to	the	purchase	of uranium	fuel	(and	its	conversion	and	enrichment),	and	the	risk	of	being	unable	to	effectively	manage	these	risks	by	purchasing	from	a diversified	mix	of	sellers	located	in	a	diversified	mix	of	countries	could	materially	affect	Entergy's	and	their	results	of	operations,	financial condition,	and	liquidity.

Based	upon	currently	planned	fuel	cycles,	Entergy's	nuclear	units	have	a	diversified	portfolio	of	contracts	and	inventory	that	provides substantially	adequate	nuclear	fuel	materials	and	conversion	and	enrichment	services	at	what	Entergy	believes	are	reasonably	predictable	prices through	most	of	2014.	 	Entergy's	ability	to	purchase	nuclear	fuel	at	reasonably	predictable	prices,	however,	depends	upon	the	performance reliability	of	uranium	miners	and	enrichers.		While	there	are	a	number	of	possible	alternate	suppliers	that	may	be	accessed	to	mitigate	any	supplier performance	failure,	the	pricing	of	any	such	alternate	uranium	supply	from	the	market	will	be	dependent	upon	the	market	for	uranium	supply	at that	time.	Entergy	also	may	draw	upon	its	own	inventory	intended	for	later	generation	periods,	depending	upon	its	risk	management	strategy	at that	time.		Entergy	buys	uranium	from	a	diversified	mix	of	sellers	located	in	a	diversified	mix	of	countries,	and	from	time	to	time	purchases	from nearly	all	qualified	reliable	major	market	participants	worldwide	that	sell	into	the	U.S.	Market	prices	for	nuclear	fuel	have	been	extremely	volatile from	time	to	time	in	the	past.		Although	Entergy's	nuclear	fuel	contract	portfolio	provides	a	degree	of	hedging	against	market	risks	for	several years,	costs	for	nuclear	fuel	in	the	future	cannot	be	predicted	with	certainty	due	to	normal	inherent	market	uncertainties,	and	price	increases	could materially	affect	the	liquidity,	financial	condition,	and	results	of	operations	of	certain	of	the	Utility	operating	companies,	System	Energy,	and Entergy	Wholesale	Commodities.

# Certain	of	the	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	face	the	risk	that	the NRC	will	change	or	modify	its	regulations	or	suspend	or	revoke	their	licenses,	which	could	materially	affect	Entergy's	and	their	results	of operations,	financial	condition,	and	liquidity.

Under	the	Atomic	Energy	Act	and	Energy	Reorganization	Act,	the	NRC	regulates	the	operation	of	nuclear	power	plants.		The	NRC	may modify,	suspend,	or	revoke	licenses,	shut	down	a	nuclear	facility	and	impose	civil	penalties	for	failure	to	comply	with	the	Atomic	Energy	Act, related	regulations,	or	the	terms	of	the	licenses	for	nuclear	facilities.	 	A	change	in	the	Atomic	Energy	Act,	other	applicable	statutes,	or	the applicable	 regulations	 or	 licenses	 may	 require	 a	 substantial	 increase	 in	 capital	 expenditures	 or	 may	 result	 in	 increased	 operating	 or decommissioning	 costs	 and	 could	 materially	 affect	 the	 results	 of	 operations,	 liquidity,	 or	 financial	 condition	 of	 Entergy	 (through	 Entergy Wholesale	Commodities),	its	Utility	operating	companies,	or	System	Energy.		Events	at	nuclear	plants	owned	by	others,	as	well	as	those	owned by	one	of	these	companies,	may	cause	the	NRC	to	initiate	such	actions.		As	a	result,	if	an	incident	were	to	occur	at	any	nuclear	generating	unit, whether	an	Entergy	nuclear	generating	unit	or	not,	it	could	materially	affect	the	financial	condition,	results	of	operations,	and	liquidity	of	Entergy, certain	of	the	Utility	operating	companies,	System	Energy,	or	Entergy	Wholesale	Commodities.		For	example,	the	earthquake	of	March	11,	2011 that	affected	the	Fukushima	Daiichi	nuclear	plants	in	Japan	resulted	in	the	NRC	issuing	three	orders	effective	on	March	12,	2012	requiring	U.S. nuclear	operators,	including	Entergy,	to	undertake	plant	modifications	or	perform	additional	analyses	that	will,	among	other	things,	result	in increased	capital	and	operating	costs	associated	with	operating	Entergy's	nuclear	plants,	some	of	which	could	be	material.

Certain	of	the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities	are	exposed	to	risks	and	costs	related to	operating	and	maintaining	their	nuclear	power	plants,	and	their	failure	to	maintain	operational	efficiency	at	their	nuclear	power	plants could	materially	affect	Entergy's	and		their	results	of	operations,	financial	condition,	and	liquidity.

The	 nuclear	 generating	 units	 owned	 by	 certain	 of	 the	 Utility	 operating	 companies,	 System	 Energy, 	 and	 the	 Entergy	 Wholesale Commodities	business	began	commercial	operations	in	the	1970s-1980s.		Older	equipment	may	require	more	capital	expenditures	to	keep	each	of these	nuclear	power	plants	operating	efficiently.		This	equipment	is	also	likely	to	require	periodic	upgrading	and	improvement.		Any	unexpected failure,	 including	 failure	 associated	 with	 breakdowns,	 forced	 outages,	 or	 any	 unanticipated	 capital	 expenditures,	 could	 result	 in	 reduced profitability.		Operations	at	any	of	the	nuclear	generating	units	owned	and	operated	by	Entergy's	subsidiaries	could	degrade	to	the	point	where	the affected	unit	needs	to	be	shut	down	or	operated	at	less	than	full	capacity.		If	this	were	to	happen,	identifying	and	correcting	the	causes	may	require significant	time	and	expense.		A	decision	may	be	made	to	close	a	unit	rather	than	incur	the	expense	of	restarting	it	or	returning	the	unit	to	full capacity.		For	Entergy	Wholesale	Commodities,	this	could	result	in	lost	revenue	and	increased	fuel	and	purchased	power	expense	to	meet	supply commitments	and	penalties	for	failure	to	perform	under	their	contracts	with	customers.		Moreover,	Entergy	is	becoming	more	dependent	on	fewer suppliers	for	key	parts	of	Entergy's	nuclear	power	plants	that	may	need	to	be	replaced	or	refurbished.		In	addition,

certain	 major	 parts	 have	 long	 lead-times	 to	 manufacture	 if	 an	 unplanned	 replacement	 is	 needed.	This	 dependence	 on	 a	 reduced	 number	 of suppliers	and	long	lead-times	on	certain	major	parts	for	unplanned	replacements	could	result	in	delays	in	obtaining	qualified	replacement	parts and,	therefore,	greater	expense	for	Entergy.

The	costs	associated	with	the	storage	of	the	spent	nuclear	fuel	of	certain	of	the	Utility	operating	companies,	System	Energy,	and	the owners	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants,	as	well	as	the	costs	of	and	their	ability	to	fully	decommission	their nuclear	power	plants,	could	be	significantly	affected	by	the	timing	of	the	opening	of	a	spent	nuclear	fuel	disposal	facility,	as	well	as	interim storage	and	transportation	requirements.

Certain	of	the	Utility	operating	companies,	System	Energy	and	the	owners	of	the	Entergy	Wholesale	Commodities	nuclear	plants	incur costs	on	a	periodic	basis	for	the	on-site	storage	of	spent	nuclear	fuel.		The	approval	of	a	license	for	a	national	repository	for	the	disposal	of	spent nuclear	fuel,	such	as	the	one	proposed	for	Yucca	Mountain,	Nevada,	or	any	interim	storage	facility,	and	the	timing	of	such	facility	opening,	will significantly	affect	the	costs	associated	with	on-site	storage	of	spent	nuclear	fuel.		For	example,	while	the	DOE	is	required	by	law	to	proceed	with the	licensing	of	Yucca	Mountain	and,	after	the	license	is	granted	by	the	NRC,	to	construct	the	repository	and	commence	the	receipt	of	spent	fuel, the	Obama	administration	has	expressed	its	intention	and	taken	specific	steps	to	discontinue	the	Yucca	Mountain	project	and	study	a	new	spent fuel	 strategy.	 	 These	 actions	 may	 prolong	 the	 time	 before	 spent	 fuel	 is	 removed	 from	 Entergy's	 plant	 sites.	 	 Because	 the	 DOE	 has	 not accomplished	its	objectives,	it	is	in	non-compliance	with	the	Nuclear	Waste	Policy	Act	of	1982	and	has	breached	its	spent	fuel	disposal	contracts, and	Entergy	has	sued	the	DOE	for	such	breach.		Furthermore,	Entergy	is	uncertain	as	to	when	the	DOE	plans	to	commence	acceptance	of	spent fuel	from	its	facilities	for	storage	or	disposal.		As	a	result,	continuing	future	expenditures	will	be	required	to	increase	spent	fuel	storage	capacity	at the	companies'	nuclear	sites.	 	The	costs	of	on-site	storage	are	also	affected	by	regulatory	requirements	for	such	storage.	 	In	addition,	 the availability	of	a	repository	or	other	off-site	storage	facility	for	spent	nuclear	fuel	may	affect	the	ability	to	fully	decommission	the	nuclear	units	and the	costs	relating	to	decommissioning.		For	further	information	regarding	spent	fuel	storage,	see	the	"Critical	Accounting	Estimates	–	Nuclear Decommissioning	Costs	 –	Spent	Fuel	Disposal"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy,	Entergy	Arkansas, Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy.

Certain	of	the	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	nuclear	plant	owners	may	be required	to	pay	substantial	retrospective	premiums	imposed	under	the	Price-Anderson	Act	in	the	event	of	a	nuclear	incident,	and	losses	not covered	by	insurance	could	have	a	material	effect	on	Entergy's	and	their	results	of	operations,	financial	condition,	or	liquidity.

Accidents	and	other	unforeseen	problems	at	nuclear	power	plants	have	occurred	both	in	the	United	States	and	elsewhere.		The	Price- Anderson	Act	limits	each	reactor	owner's	public	liability	(off-site)	for	a	single	nuclear	incident	to	the	payment	of	retrospective	premiums	into	a secondary	insurance	pool	of	up	to	approximately	$127.318	million	per	reactor.			With	104	reactors	currently	participating,	this	translates	to	a	total public	liability	cap	of	approximately	$13.241	billion	per	incident	.		The	limit	is	subject	to	change	to	account	for	the	effects	of	inflation,	a	change	in the	primary	limit	of	insurance	coverage,	and	changes	in	the	number	of	licensed	reactors.		As	required	by	the	Price-Anderson	Act,	the	Utility operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities	carry	the	maximum	available	amount	of	primary	nuclear	off-site liability	insurance	with	American	Nuclear	Insurers	(currently	$375	million	for	each	operating	site).		Claims	for	any	nuclear	incident	exceeding	that amount	are	covered	under	the	retrospective	premiums	paid	into	the	secondary	insurance	pool.		As	a	result,	in	the	event	of	a	nuclear	incident	that causes	damages	(off-site)	in	excess	of	the	$375	million	in	primary	insurance	coverage,	each	owner	of	a	nuclear	plant	reactor,	including	Entergy's Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	plant	owners,	regardless	of	fault	or	proximity	to	the incident,	will	be	required	to	pay	a	retrospective	premium,	equal	to	its	proportionate	share	of	the	loss	in	excess	of	the	$375	million	primary	level, up	to	a	maximum	of	$127.318	million	per	reactor	per	incident	(Entergy's	maximum	total	contingent	obligation	per	incident	is	$1.4	billion).		The retrospective	premium	payment	is	currently	limited	to	$18.963	million	per	year	per	incident	per	reactor	until	the	aggregate	public	liability	for	each licensee	is	paid	up	to	the	$127.318	million	cap.

NEIL	 is	a	utility	 industry	mutual	 insurance	company,	owned	by	 its	members.	 	All	member	plants	could	be	subject	 to	assessments (retrospective	premium	of	up	to	10	times	current	annual	premium	for	all	policies)	should	the	surplus	(reserve)	be	significantly	depleted	due to	insured	losses.		As	of	April	1,	2013,	the	maximum	assessment	amounts	total	$91.4	million	for	the	Utility	plants	and	$111.1	million	for	the Entergy	Wholesale	Commodities	plants.		Retrospective	Premium	Insurance	available	through	NEIL's	reinsurance	treaty	can	cover	the	potential assessments.	 	 The	 Entergy	 Wholesale	 Commodities	 plants	 currently	 maintain	 the	 Retrospective	 Premium	 Insurance	 to	 cover	 this	 potential assessment.

As	an	owner	of	nuclear	power	plants,	Entergy	participates	in	industry	self-insurance	programs	and	could	be	liable	to	fund	claims	should	a plant	owned	by	a	different	company	experience	a	major	event.		Any	resulting	liability	from	a	nuclear	accident	may	exceed	the	applicable	primary insurance	coverage	and	require	contribution	of	additional	funds	through	the	industry-wide	program	that	could	significantly	affect	the	results	of operations,	financial	condition,	or	liquidity	of	Entergy,	certain	of	the	Utility	operating	companies,	System	Energy,	or	the	Entergy	Wholesale Commodities	subsidiaries.

# Market	performance	and	other	changes	may	decrease	the	value	of	assets	in	the	decommissioning	trusts,	which	then	could	require significant	additional	funding.

Owners	of	nuclear	generating	plants	have	an	obligation	to	decommission	those	plants.		Certain	of	the	Utility	operating	companies,	System Energy,	and	owners	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants	maintain	decommissioning	trust	funds	for	this	purpose.		Certain of	the	Utility	operating	companies	collect	funds	from	their	customers,	which	are	deposited	into	the	trusts	covering	the	units	operated	for	or	on behalf	 of	 those	 companies.	 	 Those	 rate	 collections	 are	 based	 upon	 operating	 license	 lives	 as	 well	 as	 estimated	 trust	 fund	 earnings	 and decommissioning	costs.		In	connection	with	the	acquisition	of	certain	nuclear	plants,	the	Entergy	Wholesale	Commodities	plant	owners	also acquired	decommissioning	trust	funds	that	are	funded	in	accordance	with	NRC	regulations.		Assets	in	these	trust	funds	are	subject	to	market fluctuations,	will	yield	uncertain	returns	that	may	fall	below	projected	return	rates,	and	may	result	in	losses	resulting	from	the	recognition	of impairments	of	the	value	of	certain	securities	held	in	these	trust	funds.		As	part	of	the	Pilgrim,	Indian	Point	1	and	2,	Vermont	Yankee,	and Palisades/Big	Rock	Point	purchases,	the	former	owners	transferred	decommissioning	trust	funds,	along	with	the	liability	to	decommission	the plants,	to	the	respective	Entergy	Wholesale	Commodities	nuclear	power	plant	owners.		In	addition,	the	former	owner	of	Indian	Point	3	and FitzPatrick	retained	the	decommissioning	trusts	and	related	liability	to	decommission	these	plants,	but	has	the	right	to	require	the	respective Entergy	 Wholesale	 Commodities	 nuclear	 plant	 owners	 to	 assume	 the	 decommissioning	 liability	 provided	 that	 it	 assigns	 the	 funds	 in	 the corresponding	decommissioning	 trust,	up	 to	a	specified	 level,	 to	such	owners.	 	Alternatively,	 the	former	owner	may	contract	with	Entergy Nuclear,	Inc.	for	the	decommissioning	work	at	a	price	equal	to	the	funds	in	the	corresponding	decommissioning	trust	up	to	a	specified	amount.	As part	of	the	Indian	Point	1	and	2	purchase,	the	Entergy	Wholesale	Commodities	nuclear	power	plant	owner	also	funded	an	additional	$25	million	to a	 supplemental	 decommissioning	 trust	 fund.	 	As	 part	 of	 the	 Palisades	 transaction,	 the	 Entergy	 Wholesale	 Commodities	 business	 assumed responsibility	for	spent	fuel	at	the	decommissioned	Big	Rock	Point	nuclear	plant,	which	is	located	near	Charlevoix,	Michigan.		Once	the	spent	fuel is	 removed	 from	 the	 site,	 the	 Entergy	 Wholesale	 Commodities	 business	 will	 dismantle	 the	 spent	 fuel	 storage	 facility	 and	 complete	 site decommissioning.		The	Entergy	Wholesale	Commodities	business	expects	to	fund	this	activity	from	operating	revenue,	and	Entergy	is	providing $5	million	in	credit	support	to	provide	financial	assurance	to	the	NRC	for	this	obligation.

In	2008,	Entergy	experienced	declines	in	the	market	value	of	assets	held	in	the	trust	funds	for	meeting	its	decommissioning	funding assurance	obligations	for	its	plants.		This	decline	adversely	affected	Entergy's	ability	to	demonstrate	compliance	with	the	NRC's	requirements	for providing	financial	assurance	for	decommissioning	funding	for	some	of	its	plants,	which	deficiencies	have	now	been	corrected.		An	early	plant shutdown,	poor	investment	results	or	higher	than	anticipated	decommissioning	costs	could	cause	trust	fund	assets	to	be	insufficient	to	meet	the decommissioning	obligations,	with	the	result	that	the	Entergy	Wholesale	Commodities	nuclear	plant	owners	may	be	required	to	provide	additional funds	or	credit	support	to	satisfy	regulatory	requirements	for	decommissioning.		For	further	information	regarding	nuclear	decommissioning	costs, see	the	"Critical	Accounting	Estimates	–	Nuclear

Decommissioning	Costs"	 section	 of	 Management's	 Financial	 Discussion	 and	Analysis	 for	 Entergy,	 Entergy	Arkansas,	 Entergy	 Gulf	 States Louisiana,	Entergy	Louisiana,	and	System	Energy	and	Note	9	to	the	financial	statements.

# Changes	in	NRC	regulations	or	other	binding	regulatory	requirements	may	cause	increased	funding	requirements	for	nuclear	plant decommissioning	trusts.

NRC	regulations	require	certain	minimum	financial	assurance	requirements	for	meeting	obligations	 to	decommission	nuclear	power plants.		Those	financial	assurance	requirements	may	change	from	time	to	time,	and	certain	changes	may	result	in	a	material	increase	in	the financial	assurance	required	for	decommissioning	 the	Utility	operating	companies',	System	Energy's	and	owners	of	 the	Entergy	Wholesale Commodities	nuclear	power	plants.		Such	changes	could	result	in	the	need	for	additional	contributions	to	decommissioning	trusts,	or	the	posting of	parent	guarantees,	letters	of	credit,	or	other	surety	mechanisms.		For	further	information	regarding	nuclear	decommissioning	costs,	see	the "Critical	Accounting	Estimates	–	Nuclear	Decommissioning	Costs"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy, Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	System	Energy	and	Note	9	to	the	financial	statements.

# New	 or	 existing	 safety	 concerns	 regarding	 operating	 nuclear	 power	 plants	 and	 nuclear	 fuel	 could lead to	 restrictions	 upon the operation	of	Entergy's	nuclear	power	plants.

New	and	existing	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	five	of	the	six	units	in	the	current	fleet	of	Entergy	Wholesale	Commodities	nuclear	power	plants are	located.		These	concerns	have	led	to,	and	are	expected	to	continue	to	lead	to,	various	proposals	to	Federal	regulators	and	governing	bodies	in some	localities	where	Entergy's	subsidiaries	own	nuclear	generating	units	for	legislative	and	regulatory	changes	that	could	lead	to	the	shutdown	of nuclear	units,	denial	of	license	renewal	applications,	restrictions	on	nuclear	units	as	a	result	of	unavailability	of	sites	for	spent	nuclear	fuel	storage and	disposal,	or	other	adverse	effects	on	owning	and	operating	nuclear	generating	units.		Entergy	vigorously	responds	to	these	concerns	and proposals.		If	any	of	the	existing	proposals,	or	any	proposals	that	may	arise	in	the	future	with	respect	to	legislative	and	regulatory	changes,	become effective,	they	could	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition,	and	liquidity.

# (Entergy	Corporation)

A	failure	to	obtain	renewed	licenses	or	other	approvals	required	for	the	continued	operation	of	the	Entergy	Wholesale	Commodities nuclear	power	plants	could	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition,	and	liquidity	and	could	lead	to	an increase	in	depreciation	rates	or	an	acceleration	of	the	timing	for	the	funding	of	decommissioning	obligations.

The	license	renewal	and	related	processes	for	the	Entergy	Wholesale	Commodities	nuclear	power	plants	have	been	and	may	continue	to	be the	subject	of	significant	public	debate	and	regulatory	and	legislative	review	and	scrutiny	at	the	federal	and,	in	certain	cases,	state	level.		The original	 expiration	 dates	 of	 the	 operating	 licenses	 for	 Indian	 Point	 2	 and	 Indian	 Point	 3	 are	 in	 September	 2013	 and	 December	 2015, respectively.		Because	these	plants	filed	timely	license	renewal	applications,	the	NRC's	rules	provide	that	these	plants	may	continue	to	operate under	their	existing	operating	licenses	until	their	renewal	applications	have	been	finally	determined.		Various	parties	have	expressed	opposition	to renewal	of	these	licenses.		Renewal	of	the	Indian	Point	licenses	is	the	subject	of	ongoing	proceedings	before	the	Atomic	Safety	and	Licensing Board	(ASLB)	of	the	NRC	and,	with	respect	to	issues	resolved	by	the	ASLB,	before	the	NRC	on	appeal.

In	relation	to	Indian	Point	2	and	Indian	Point	3,	the	New	York	State	Department	of	Environmental	Conservation	has	taken	the	position that	these	plant	owners	must	obtain	a	new	state-issued	Clean	Water	Act	Section	401	water	quality	certification	as	part	of	the	license	renewal process.		For	the	Indian	Point	plants,	the	Entergy	Wholesale	Commodities	plant	owners	also	must	ensure	that	requirements	of	the	Coastal	Zone Management	Act,	which	is	administered	in	New	York	State	primarily	by	the	New	York	Department	of	State,	are	satisfied	(to	the	extent	required) prior	to	getting	the

renewed	licenses.		For	further	information	regarding	these	environmental	regulations	see	" Entergy	Wholesale	Commodities	–	 Property	 – Nuclear	Generating	Stations"	in	Part	I,	Item	1.

If	the	NRC	finally	denies	the	applications	for	the	renewal	of	operating	licenses	for	one	or	more	of	the	Entergy	Wholesale	Commodities nuclear	power	plants,	or	a	state	in	which	any	such	nuclear	power	plant	is	located	is	able	to	prevent	the	continued	operation	of	such	plant,	Entergy's results	of	operations,	financial	condition,	and	liquidity	could	be	materially	affected	by	loss	of	revenue	and	cash	flow	associated	with	the	plant	or plants,	potential	impairments	of	the	carrying	value	of	the	plants,	increased	depreciation	rates,	and	an	accelerated	need	for	decommissioning	funds, which	could	require	additional	funding.	In	addition,	Entergy	may	incur	increased	operating	costs	depending	on	any	conditions	that	may	be imposed	 in	 connection	 with	 license	 renewal.	 	 For	 further	 discussion	 regarding	 the	 license	 renewal	 processes	 for	 the	 Entergy	 Wholesale Commodities	nuclear	power	plants,	see	the	"Entergy	Wholesale	Commodities	–	Property	–	Nuclear	Generating	Stations"	section	in	Part	I,	Item 1.

The	decommissioning	trust	fund	assets	for	the	nuclear	power	plants	owned	by	Entergy	Wholesale	Commodities	nuclear	plant	owners may	not	be	adequate	to	meet	decommissioning	obligations	if	one	or	more	of	their	nuclear	power	plants	is	retired	earlier	than	the	anticipated shutdown	date,	the	plants	cost	more	to	decommission	than	estimated,	or	if	current	regulatory	requirements	change,	which	then	could	require additional	funding.

Under	NRC	regulations,	Entergy's	nuclear	subsidiaries	are	permitted	to	project	the	NRC-required	decommissioning	amount,	based	on	an NRC	formula	or	a	site-specific	estimate,	and	the	amount	in	each	of	the	Entergy	Wholesale	Commodities	nuclear	power	plant's	decommissioning trusts	combined	with	other	decommissioning	financial	assurances	in	place.		The	projections	are	made	based	on	the	operating	license	expiration date	and	the	mid-point	of	the	subsequent	decommissioning	process,	or	the	anticipated	actual	completion	of	decommissioning	if	a	site-specific estimate	is	used,	for	each	of	these	nuclear	power	plants.		As	a	result,	if	the	projected	amount	of	our	decommissioning	trusts	exceeds	the	NRC- required	decommissioning	amount,	then	its	decommissioning	obligations	are	considered	to	be	funded	in	accordance	with	NRC	regulations.		In	the event	 the	 projected	 costs	 do	 not	 sufficiently	 reflect	 the	 actual	 costs	 the	 applicable	 Entergy	 subsidiaries	 would	 be	 required	 to	 incur	 to decommission	these	nuclear	power	plants,	and	funding	is	otherwise	inadequate,	or	if	the	formula	or	site-specific	estimate	is	changed	to	require increased	funding,	additional	resources	would	be	required.		Furthermore,	depending	upon	the	level	of	funding	available	in	the	trust	funds,	the NRC	may	not	permit	the	trust	funds	to	be	used	to	pay	for	related	costs	such	as	the	management	of	spent	nuclear	fuel	that	are	not	included	in	the NRC's	formula.		The	NRC	may	also	require	a	plan	for	the	provision	of	separate	funding	for	spent	fuel	management	costs.		In	addition	to	NRC requirements,	there	are	other	decommissioning-related	obligations	for	certain	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants,	which management	believes	it	will	be	able	to	satisfy.

With	respect	to	the	decommissioning	trusts	for	Indian	Point	1	and	Indian	Point	2	and	Palisades,	the	total	amount	in	each	of	those	trusts	as of	December	31,	2012	would	not	have	been	sufficient	to	initiate	and	complete	the	immediate	near-term	radiological	decommissioning	of	the respective	unit	as	of	the	license	termination	date	of	each	respective	plant	as	measured	by	NRC	formula	amounts,	but	rather	the	funds	would	have been	sufficient	to	place	the	unit	in	a	condition	of	safe	storage	status	pending	future	completion	of	decommissioning.		(By	February	28,	2013, however,	 increases	 in	 the	 market	 value	 of	 the	 Palisades	 trusts	 made	 that	 fund	 sufficient	 to	 complete	 the	 immediate	 near-term	 radiological decommissioning	of	the	unit	as	of	the	license	termination	date	as	measured	by	the	NRC	formula	amount).	For	example,	if	an	Entergy	subsidiary decides	to	shut	down	and	begin	decommissioning	one	of	those	nuclear	power	plants	on	its	license	expiration	date	with	the	benefit	of	a	safe	storage period,	its	trust	funds	for	the	plant	as	of	December	31,	2012	would	have	been	insufficient	and	the	applicable	Entergy	subsidiary	would	have	been required	 to	rely	on	other	capital	resources	 to	fund	 the	remainder	of	 the	radiological	decommissioning	obligations	unless	 the	completion	of decommissioning	could	be	deferred	during	some	number	of	years	of	safe	storage	status	(as	is	permitted	by	NRC	regulations).		As	of	December	31, 2013,	the	total	amount	in	the	decommissioning	trust	for	Indian	Point	1	would	not	have	been	sufficient	to	initiate	and	complete	the	immediate	near- term	radiological	decommissioning	of	that	unit	as	measured	by	the	NRC	formula	amount,	but	rather	the	funds	would	have	been	sufficient	to continue	holding	the	unit	in	a	condition	of	safe	storage	status	pending	future	completion	of	decommissioning;	however,	growth	in	the	trust	funds for	Indian	Point	2	and	Palisades	by	December	31,	2013	had	made	them	sufficient	for	initiation	and	completion	of

immediate	near-term	radiological	decommissioning	as	measured	by	the	NRC	formula	amount.	If	any	Entergy	subsidiary	decides	to	shut	down	one of	its	nuclear	power	plants	earlier	than	the	scheduled	shutdown	date	and	conduct	decommissioning	without	the	benefit	of	a	safe	storage	period,	the applicable	Entergy	subsidiary	may	be	unable	to	rely	upon	only	the	decommissioning	trust	to	fund	the	entire	decommissioning	obligations,	which would	require	it	to	obtain	funding	from	other	sources.

On	August	27,	2013,	Entergy	announced	its	plan	to	close	and	decommission	Vermont	Yankee.		Vermont	Yankee	is	expected	to	cease power	production	in	the	fourth	quarter	2014	at	the	end	of	its	current	fuel	cycle.	Assuming	the	end	of	Vermont	Yankee	operations	in	the	fourth quarter	2014,	the	amount	required	to	meet	the	NRC	minimum	for	decommissioning	financial	assurance	for	license	termination	is	$569.1	million. The	Vermont	Yankee	decommissioning	trust	had	a	balance	of	approximately	 $612.1	million	as	of	December	31,	2013,	excluding	the	$40	million guarantee	by	Entergy	Corporation	to	satisfy	NRC	requirements	following	the	2009	review	of	financial	assurance	levels.	Filings	with	the	NRC	for planned	shutdown	activities	will	determine	whether	any	other	financial	assurance	may	be	required	and	will	specifically	address	funding	for	spent fuel	management,	which	will	be	required	until	the	federal	government	takes	possession	of	the	fuel	and	removes	it	from	the	site,	per	its	current obligation.

Further,	federal	or	state	regulatory	changes,	including	mandated	increases	in	decommissioning	funding	or	changes	in	the	methods	or standards	for	decommissioning	operations,	may	also	increase	the	funding	requirements	of,	or	accelerate	the	timing	for	funding	of,	the	obligations related	 to	 the	 decommissioning	 of	 Entergy	Wholesale	 Commodities	 nuclear	 power	 plants.	 	As	 a	 result,	 under	 any	 of	 these	 circumstances, Entergy's	results	of	operations,	liquidity,	and	financial	condition	could	be	materially	affected.

# Entergy	Wholesale	Commodities	nuclear	power	plants	are	exposed	to	price	risk.

Entergy	and	its	subsidiaries	do	not	have	a	regulator-authorized	rate	of	return	on	their	capital	investments	in	non-utility	businesses.		In particular,	the	sale	of	capacity	and	energy	from	the	Entergy	Wholesale	Commodities	nuclear	power	plants,	unless	otherwise	contracted,	is	subject to	the	fluctuation	of	market	power	prices.	In	order	to	reduce	future	price	risk	to	desired	levels,	Entergy	Wholesale	Commodities	utilizes	contracts that	are	unit-contingent	and	Firm	LD	and	various	products	such	as	forward	sales,	options,	and	collars.	 	As	of	December	31,	2013,	Entergy Wholesale	Commodities	nuclear	power	generation	plants	had	sold	forward	74%,	74%,	40%,	29%	and	17%	of	its	generation	portfolio's	planned energy	output	for	2014,	2015,	2016,	2017,	and	2018,	respectively.

Market	 conditions	 such	 as	 product	 cost,	 market	 liquidity,	 and	 other	 portfolio	 considerations	 influence	 the	 product	 and	 contractual mix.		The	obligations	under	unit-contingent	agreements	depend	on	a	generating	asset	that	is	operating;	if	the	generation	asset	is	not	operating,	the seller	generally	is	not	liable	for	damages.		For	some	unit-contingent	obligations,	however,	there	is	also	a	guarantee	of	availability	that	provides	for the	payment	to	the	power	purchaser	of	contract	damages,	if	incurred,	in	the	event	the	unit	owner	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.		Firm	LD	sales	transactions	may	be	exposed	to substantial	operational	price	risk,	a	portion	of	which	may	be	capped	through	the	use	of	risk	management	products,	to	the	extent	that	the	plants	do not	run	as	expected	and	market	prices	exceed	contract	prices.

Market	 prices	 may	 fluctuate	 substantially,	 sometimes	 over	 relatively	 short	 periods	 of	 time,	 and	 at	 other	 times	 experience	 sustained increases	or	decreases.	 	Demand	for	electricity	and	its	fuel	stock	can	fluctuate	dramatically,	creating	periods	of	substantial	under-	or	over- supply.		During	periods	of	over-supply,	prices	might	be	depressed.		Also,	from	time	to	time	there	may	be	political	pressure,	or	pressure	from regulatory	authorities	with	jurisdiction	over	wholesale	and	retail	energy	commodity	and	transportation	rates,	to	impose	price	limitations,	credit requirements,	bidding	rules	and	other	mechanisms	to	address	volatility	and	other	issues	in	these	markets.

The	price	that	different	counterparties	offer	for	various	products	including	forward	sales	is	influenced	both	by	market	conditions	as	well	as the	contract	terms	such	as	damage	provisions,	credit	support	requirements,	and	the	number	of	available	counterparties	interested	in	contracting	for the	desired	forward	period.	 	Depending	on	differences	between	market	factors	at	the	time	of	contracting	versus	current	conditions,	Entergy Wholesale	Commodities's	contract	portfolio

may	have	average	contract	prices	above	or	below	current	market	prices,	including	at	the	expiration	of	the	contracts,	which	may	significantly	affect Entergy	Wholesale	Commodities's	results	of	operations,	financial	condition,	or	liquidity.		New	hedges	are	generally	layered	into	on	a	rolling forward	basis,	which	tends	to	drive	hedge	over-performance	to	market	in	a	falling	price	environment,	and	hedge	underperformance	to	market	in	a rising	price	environment;	however,	hedge	timing,	product	choice,	and	hedging	costs	will	also	affect	these	results.	See	the	"Results	of	Operations -	Realized	Revenue	per	MWh	for	Entergy	Wholesale	Commodities	Nuclear	Plants"	section	of	Management's	Financial	Discussion	and	Analysis for	Entergy	Corporation	and	Subsidiaries.		With	operating	licenses	for	Indian	Point	2	and	Indian	Point	3	expiring	in	2013	and	2015,	respectively (see	discussion	above	regarding	the	continued	operation	of	Indian	Point	2	and	3	past	the	license	expiration	dates),	and	as	a	consequence	of	any delays	in	obtaining	extension	of	the	operating	licenses	and	any	other	approvals	required	for	continued	operation	of	the	plants,	Entergy	Wholesale Commodities	may	enter	into	fewer	unit-contingent	forward	sales	contracts	for	output	from	such	plants	for	periods	beyond	the	license	expiration.

Among	the	factors	that	could	affect	market	prices	for	electricity	and	fuel,	all	of	which	are	beyond	Entergy's	control	to	a	significant	degree,

•prevailing	market	prices	for	natural	gas,	uranium	(and	its	conversion,	enrichment,	and	fabrication),	coal,	oil,	and	other	fuels	used	in electric	generation	plants,	including	associated	transportation	costs,	and	supplies	of	such	commodities;

•seasonality	and	realized	weather	deviations	compared	to	normalized	weather	forecasts;

•availability	of	competitively	priced	alternative	energy	sources	and	the	requirements	of	a	renewable	portfolio	standard;

•changes	in	production	and	storage	levels	of	natural	gas,	lignite,	coal	and	crude	oil,	and	refined	products;

•liquidity	in	the	general	wholesale	electricity	market,	including	the	number	of	creditworthy	counterparties	available	and	interested	in entering	into	forward	sales	agreements	for	Entergy's	full	hedging	term;

•the	actions	of	external	parties,	such	as	the	FERC	and	local	independent	system	operators	and	other	state	or	Federal	energy	regulatory bodies,	that	may	impose	price	limitations	and	other	mechanisms	to	address	some	of	the	volatility	in	the	energy	markets;

•electricity	transmission,	competing	generation	or	fuel	transportation	constraints,	inoperability,	or	inefficiencies;

•the	general	demand	for	electricity,	which	may	be	significantly	affected	by	national	and	regional	economic	conditions;

•weather	conditions	affecting	demand	for	electricity	or	availability	of	hydroelectric	power	or	fuel	supplies;

•the	rate	of	growth	in	demand	for	electricity	as	a	result	of	population	changes,	regional	economic	conditions,	and	the	implementation	of conservation	programs	or	distributed	generation;

•regulatory	policies	of	state	agencies	that	affect	the	willingness	of	Entergy	Wholesale	Commodities	customers	to	enter	into	long-term contracts	generally,	and	contracts	for	energy	in	particular;

•increases	in	supplies	due	to	actions	of	current	Entergy	Wholesale	Commodities	competitors	or	new	market	entrants,	including	the development	of	new	generation	facilities,	expansion	of	existing	generation	facilities,	the	disaggregation	of	vertically	integrated	utilities,

and	improvements	in	transmission	that	allow	additional	supply	to	reach	Entergy	Wholesale	Commodities's	nuclear	markets; •union	and	labor	relations;

•changes	in	Federal	and	state	energy	and	environmental	laws	and	regulations	and	other	initiatives,	including	but	not	limited	to,	the	price impacts	of	proposed	emission	controls	such	as	the	Regional	Greenhouse	Gas	Initiative	(RGGI);

•changes	in	law	resulting	from	federal	or	state	energy	legislation	or	legislation	subjecting	energy	derivatives	used	in	hedging	and	risk management	transactions	to	governmental	regulation;	and

•natural	disasters,	terrorist	actions,	wars,	embargoes,	and	other	catastrophic	events.

# The	Entergy	Wholesale	Commodities	business	is	subject	to	substantial	governmental	regulation	and	may	be	adversely	affected	by legislative,	regulatory	or	market	design	changes,	as	well	as	liability	under,	or	any	future	inability	to	comply	with,	existing	or	future	regulations or	requirements.

The	Entergy	Wholesale	Commodities	business	is	subject	to	extensive	federal,	state,	and	local	laws	and	regulation.		Compliance	with	the requirements	under	these	various	regulatory	regimes	may	cause	the	Entergy	Wholesale	Commodities	business	to	incur	significant	additional	costs, and	failure	to	comply	with	such	requirements	could	result	in	the	shutdown	of	the	non-complying	facility,	the	imposition	of	liens,	fines	and/or	civil or	criminal	liability.

Public	utilities	under	 the	Federal	Power	Act	are	required	 to	obtain	FERC	acceptance	of	 their	rate	schedules	for	wholesale	sales	of electricity.		Each	of	the	owners	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants,	as	well	as	Entergy	Nuclear	Power	Marketing,	LLC, is	a	"public	utility"	under	the	Federal	Power	Act	by	virtue	of	making	wholesale	sales	of	electric	energy.		The	FERC	has	granted	these	generating and	power	marketing	companies	the	authority	to	sell	electricity	at	market-based	rates.		The	FERC's	orders	that	grant	the	Entergy	Wholesale Commodities's	generating	and	power	marketing	companies	market-based	rate	authority	reserve	the	right	to	revoke	or	revise	that	authority	if	the FERC	subsequently	determines	that	the	Entergy	Wholesale	Commodities	business	can	exercise	market	power	in	transmission	or	generation, create	barriers	to	entry,	or	engage	in	abusive	affiliate	transactions.		In	addition,	the	Entergy	Wholesale	Commodities's	market-based	sales	are subject	to	certain	market	behavior	rules,	and	if	any	of	its	generating	and	power	marketing	companies	were	deemed	to	have	violated	one	of	those rules,	they	would	be	subject	to	potential	disgorgement	of	profits	associated	with	the	violation	and/or	suspension	or	revocation	of	their	market- based	rate	authority	and	potential	penalties	of	up	to	$1	million	per	day	per	violation.		If	the	Entergy	Wholesale	Commodities's	generating	or	power marketing	companies	were	to	lose	their	market-based	rate	authority,	such	companies	would	be	required	to	obtain	the	FERC's	acceptance	of	a	cost- of-service	rate	schedule	and	could	become	subject	to	the	accounting,	record-keeping,	and	reporting	requirements	that	are	imposed	on	utilities	with cost-based	rate	schedules.		This	could	have	an	adverse	effect	on	the	rates	the	Entergy	Wholesale	Commodities	business	charges	for	power	from	its facilities.

The	Entergy	Wholesale	Commodities	business	is	also	affected	by	legislative	and	regulatory	changes,	as	well	as	changes	to	market	design, market	 rules,	 tariffs,	 cost	 allocations,	 and	 bidding	 rules	 imposed	 by	 the	 existing	 Independent	 System	 Operators.	 	The	 Independent	 System Operators	that	oversee	most	of	the	wholesale	power	markets	impose,	and	in	the	future	may	continue	to	impose,	mitigation,	including	price limitations,	offer	caps	and	other	mechanisms,	to	address	some	of	the	volatility	and	the	potential	exercise	of	market	power	in	these	markets.		These types	of	price	limitations	and	other	regulatory	mechanisms	may	have	an	adverse	effect	on	the	profitability	of	the	Entergy	Wholesale	Commodities business'	generation	facilities	that	sell	energy	and	capacity	into	the	wholesale	power	markets.		For	further	information	regarding	federal,	state	and local	laws	and	regulation	applicable	to	the	Entergy	Wholesale	Commodities	business,	see	the	"Regulation	of	Entergy's	Business"	section	in	Part I,	Item	1.

The	regulatory	environment	applicable	to	the	electric	power	industry	has	undergone	substantial	changes	over	the	past	several	years	as	a result	of	restructuring	initiatives	at	both	the	state	and	federal	levels.		These	changes	are	ongoing	and	Entergy	cannot	predict	the	future	design	of the	wholesale	power	markets	or	the	ultimate	effect	that	the	changing	regulatory	environment	will	have	on	the	Entergy	Wholesale	Commodities business.		In	addition,	in	some	of	these	markets,	interested	parties	have	proposed	material	market	design	changes,	including	the	elimination	of	a single	clearing	price	mechanism	and	have	raised	claims	that	the	competitive	marketplace	is	not	working	because	energy	prices	in	wholesale markets	exceed	the	marginal	cost	of	operating	nuclear	power	plants,	as	well	as	proposals	to	re-regulate	the	markets,	impose	a	generation	tax,	or require	divestitures	by	generating	companies	to	reduce	their	market	share.		Other	proposals	to	re-regulate	may	be	made	and	legislative	or	other attention	to	the	electric	power	market	restructuring	process	may	delay	or	reverse	the	deregulation	process,	which	could	require	material	changes	to business	planning	models.		If	competitive	restructuring	of	the	electric	power	markets	is	reversed,	modified,	discontinued,	or	delayed,	the	Entergy Wholesale	Commodities	business'	results	of	operations,	financial	condition,	and	liquidity	could	be	materially	affected.

# The	power	plants	owned	by	the	Entergy	Wholesale	Commodities	business	are	subject	to	impairment	charges	in	certain	circumstances, which	could	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition	or	liquidity.

Entergy	 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	the	operations	of	such	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	and	capacity	over	the	remaining	life	of	the	assets.		In particular,	the	assets	of	the	Entergy	Wholesale	Commodities	business	are	subject	to	impairment	if	adverse	market	conditions	arise	and	continue (such	as	expected	long-term	declines	in	market	prices	for	electricity),	if	adverse	regulatory	events	occur	(including	with	respect	to	environmental regulation),	if	a	unit	ceases	operation	or	if	a	unit's	operating	license	is	not	renewed.		Moreover,	the	failure	of	the	Entergy	Wholesale	Commodities business	to	achieve	forecasted	operating	results	and	cash	flows,	an	unfavorable	change	in	forecasted	operating	results	or	cash	flows,	or	a	decline	in observable	industry	market	multiples	could	all	result	in	potential	impairment	charges	for	the	affected	assets.

As	 discussed	 in the	"Entergy	Wholesale	Commodities -	Property"	section	 in	 Part	 I,	 Item	 1,	 the	 original	 expiration	 dates	 of	 the operating	licenses	for	Indian	Point	2	and	Indian	Point	3	are	2013	and	2015,	respectively	(see	discussion	above	regarding	the	continued	operation of	Indian	Point	2	and	3	past	the	license	expiration	dates),and	are	currently	the	subject	of	license	renewal	processes	at	the	NRC	and	the	state	in which	the	plants	operate.	On	August	27,	2013,	Entergy	announced	its	plan	to	close	and	decommission	Vermont	Yankee.		Vermont	Yankee	is expected	to	cease	power	production	in	the	fourth	quarter	2014	at	the	end	of	its	current	fuel	cycle.		This	decision	was	approved	by	the	Board	in August	2013,	and	resulted	in	the	recognition	of	impairment	charges	in	2013.	If	Entergy	concludes	that	any	of	its	nuclear	power	plants	is	unlikely to	operate	through	its	current	useful	life,	which	conclusion	would	be	based	on	a	variety	of	factors,	such	a	conclusion	could	result	in	an	impairment of	part	or	all	of	the	carrying	value	of	the	plant.		Any	impairment	charge	taken	by	Entergy	with	respect	to	its	long-lived	assets,	including	the	power plants	owned	by	 the	Entergy	Wholesale	Commodities	business,	would	 likely	be	material	 in	 the	quarter	 that	 the	charge	 is	 taken	and	could otherwise	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition,	or	liquidity.

# General	Business

Entergy	and	 the	Utility	operating	companies	depend	on	access	 to	 the	capital	markets	and,	at	 times,	may	face	potential	 liquidity constraints,	which	could	make	it	more	difficult	to	handle	future	contingencies	such	as	natural	disasters	or	substantial	increases	in	gas	and fuel	prices.		Disruptions	in	the	capital	and	credit	markets	may	adversely	affect	Entergy's	and	its	subsidiaries'	ability	to	meet	liquidity	needs, access	capital	and	operate	and	grow	their	businesses,	and	the	cost	of	capital.

Entergy's	business	is	capital	intensive	and	dependent	upon	its	ability	to	access	capital	at	reasonable	rates	and	other	terms.		At	times	there are	also	spikes	in	the	price	for	natural	gas	and	other	commodities	that	increase	the	liquidity	requirements	of	the	Utility	operating	companies	and Entergy	Wholesale	Commodities.		In	addition,	Entergy's	and	the	Utility	operating	companies'	liquidity	needs	could	significantly	increase	in	the event	of	a	hurricane	or	other	weather-related	or	unforeseen	disaster	similar	to	that	experienced	in	Entergy's	service	territory	with	Hurricane Katrina	and	Hurricane	Rita	in	2005,	Hurricane	Gustav	and	Hurricane	Ike	in	2008,	and	Hurricane	Isaac	in	2012.		The	occurrence	of	one	or	more contingencies,	including	a	delay	in	regulatory	recovery	of	fuel	or	purchased	power	costs	or	storm	restoration	costs,	higher	than	expected	pension contributions,	an	acceleration	of	payments	or	decreased	credit	lines,	less	cash	flow	from	operations	than	expected,	or	other	unknown	events,	such as	future	storms,	could	cause	the	financing	needs	of	Entergy	and	its	subsidiaries	to	increase.		In	addition,	accessing	the	debt	capital	markets	more frequently	in	these	situations	may	result	in	an	increase	in	leverage.		Material	leverage	increases	could	negatively	affect	the	credit

ratings	of	Entergy	and	the	Utility	operating	companies,	which	in	turn	could	negatively	affect	access	to	the	capital	markets.

The	global	capital	and	credit	markets	experienced	extreme	volatility	and	disruption	in	the	fourth	quarter	of	2008	and	much	of	2009.		The inability	to	raise	capital	on	favorable	terms,	particularly	during	times	of	uncertainty	in	the	capital	markets,	could	negatively	affect	Entergy	and	its subsidiaries'	ability	to	maintain	and	to	expand	their	businesses.		Events	beyond	Entergy's	control,	such	as	the	volatility	and	disruption	in	global capital	and	credit	markets	in	2008	and	2009,	may	create	uncertainty	that	could	increase	its	cost	of	capital	or	impair	its	ability	to	access	the	capital markets,	including	the	ability	to	draw	on	its	bank	credit	facilities.		Entergy	and	its	subsidiaries	are	unable	to	predict	the	degree	of	success	they	will have	in	renewing	or	replacing	their	credit	facilities	as	they	come	up	for	renewal.		Moreover,	the	size,	terms,	and	covenants	of	any	new	credit facilities	may	not	be	comparable	to,	and	may	be	more	restrictive	than,	existing	facilities.		If	Entergy	and	its	subsidiaries	are	unable	to	access	the credit	and	capital	markets	on	terms	that	are	reasonable,	they	may	have	to	delay	raising	capital,	issue	shorter-term	securities	and/or	bear	an unfavorable	cost	of	capital,	which,	in	turn,	could	impact	their	ability	to	grow	their	businesses,	decrease	earnings,	significantly	reduce	financial flexibility	and/or	limit	Entergy	Corporation's	ability	to	sustain	its	current	common	stock	dividend	level.

# A	 downgrade in	 Entergy	 Corporation's	 or its	 subsidiaries' credit	 ratings	 could	 negatively	 affect	 Entergy	 Corporation's	 and its subsidiaries' ability to	 access	 capital	 and/or	 could	 require	 Entergy	 Corporation	 or its	 subsidiaries to	 post	 collateral,	 accelerate	 certain payments,	or	repay	certain	indebtedness.

There	are	a	number	of	factors	that	rating	agencies	evaluate	to	arrive	at	credit	ratings	for	each	of	Entergy	Corporation	and	the	Registrant Subsidiaries,	including	each	Registrant's	regulatory	framework,	ability	to	recover	costs	and	earn	returns,	diversification	and	financial	strength	and liquidity.		If	one	or	more	rating	agencies	downgrade	Entergy	Corporation's,	any	of	the	Utility	operating	companies',	or	System	Energy's	ratings, particularly	below	investment	grade,	borrowing	costs	would	increase,	the	potential	pool	of	investors	and	funding	sources	would	likely	decrease, and	cash	or	letter	of	credit	collateral	demands	may	be	triggered	by	the	terms	of	a	number	of	commodity	contracts,	leases,	and	other	agreements.

Most	of	Entergy	Corporation's	and	its	subsidiaries'	large	customers,	suppliers,	and	counterparties	require	sufficient	creditworthiness	to enter	 into	 transactions. If	 Entergy	 Corporation's	 or	 its	 subsidiaries'	 ratings	 decline,	 particularly	 below	 investment	 grade,	 or	 if	 certain counterparties	believe	Entergy	Corporation	or	the	Utility	operating	companies	are	losing	creditworthiness	and	demand	adequate	assurance	under fuel,	gas,	and	purchased	power	contracts,	the	counterparties	may	require	posting	of	collateral	in	cash	or	letters	of	credit,	prepayment	for	fuel,	gas or	purchased	power	or	accelerated	payment,	or	counterparties	may	decline	business	with	Entergy	Corporation	or	its	subsidiaries.	At	December	31, 2013,	based	on	power	prices	at	that	time,	Entergy	had	liquidity	exposure	of	$274	million	under	the	guarantees	in	place	supporting	Entergy Wholesale	Commodities	transactions	and	$104	million	of	posted	cash	collateral.	As	of	December	31,	2013,	the	liquidity	exposure	associated	with Entergy	Wholesale	Commodities	assurance	requirements,	including	return	of	previously	posted	collateral	from	counterparties,	would	increase	by $123	 million	 for	 a	 $1	 per	 MMBtu	 increase	 in	 gas	 prices	 in	 both	 the	 short-	 and	 long-term	 markets.	In	 the	 event	 of	 a	 decrease	 in	 Entergy Corporation's	credit	rating	to	below	investment	grade,	based	on	power	prices	as	of	December	31,	2013,	Entergy	would	have	been	required	to provide	approximately	$113	million	of	additional	cash	or	letters	of	credit	under	some	of	the	agreements.

# The	construction	of,	and	capital	improvements	to,	power	generation	facilities	involve	substantial	risks.		Should	construction	or	capital improvement	efforts	be	unsuccessful,	the	financial	condition,	results	of	operations,	or	liquidity	of	Entergy	and	the	Utility	operating	companies could	be	materially	affected.

Entergy's	and	the	Utility	operating	companies'	ability	to	complete	construction	of	power	generation	facilities	in	a	timely	manner	and within	 budget	 is	 contingent	 upon	 many	 variables	 and	 subject	 to	 substantial	 risks.	 	These	 variables	 include,	 but	 are	 not	 limited	 to,	 project management	 expertise	 and	 escalating	 costs	 for	 materials,	 labor,	 and	 environmental	 compliance.	 	 Delays	 in	 obtaining	 permits,	 shortages	 in materials	and	qualified	labor,	suppliers	and	contractors	not	performing	as	required	under	their	contracts,	changes	in	the	scope	and	timing	of projects,	poor	quality	 initial	cost	estimates	from	contractors,	 the	 inability	 to	raise	capital	on	favorable	 terms,	changes	 in	commodity	prices affecting	revenue,	fuel	costs,	or	materials	costs,		downward	changes	in	the	economy,	changes	in	law	or	regulation,	including	environmental compliance	requirements,	and	other	events	beyond	the	control	of	the	Utility	operating	companies	or	the	Entergy	Wholesale	Commodities	business may	occur	that	may	materially	affect	the	schedule,	cost,	and	performance	of	these	projects.		If	these	projects	are	significantly	delayed	or	become subject	to	cost	overruns	or	cancellation,	Entergy	and	the	Utility	operating	companies	could	incur	additional	costs	and	termination	payments,	or face	increased	risk	of	potential	write-off	of	the	investment	in	the	project.		For	further	information	regarding	capital	expenditure	plans	and	other uses	of	capital	in	connection	with	the	potential	construction	of	additional	generation	supply	sources	within	the	Utility	operating	companies' service	territory,	and	as	to	the	Entergy	Wholesale	Commodities	business,	see	the	"Capital	Expenditure	Plans	and	Other	Uses	of	Capital" section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy	and	each	of	the	Registrant	Subsidiaries.

# The	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	may	incur	substantial	costs	to fulfill	their	obligations	related	to	environmental	and	other	matters.

The	businesses	in	which	the	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	operate	are subject	to	extensive	environmental	regulation	by	local,	state,	and	Federal	authorities.		These	laws	and	regulations	affect	the	manner	in	which	the Utility	 operating	 companies,	 System	 Energy,	 and	 the	 Entergy	Wholesale	 Commodities	 business	 conduct	 their	 operations	 and	 make	 capital expenditures.	 	 These	 laws	 and	 regulations	 also	 affect	 how	 the	 Utility	 operating	 companies,	 System	 Energy,	 and	 the	 Entergy	 Wholesale Commodities	business	manage	air	emissions,	discharges	to	water,	wetlands	impacts,	solid	and	hazardous	waste	storage	and	disposal,	cooling	and service	water	intake,	the	protection	of	threatened	and	endangered	species,	hazardous	materials	transportation,	and	similar	matters.		Federal,	state, and	local	authorities	continually	revise	these	laws	and	regulations,	and	the	laws	and	regulations	are	subject	to	judicial	interpretation	and	to	the permitting	and	enforcement	discretion	vested	in	the	implementing	agencies.		Developing	and	implementing	plans	for	facility	compliance	with these	requirements	can	lead	to	capital,	personnel,	and	operation	and	maintenance	expenditures.		Violations	of	these	requirements	can	subject	the Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	to	enforcement	actions,	capital	expenditures	to bring	existing	facilities	into	compliance,	additional	operating	costs	or	operating	restrictions	to	achieve	compliance,	remediation	and	clean-up	costs, civil	penalties,	and	exposure	to	third	parties'	claims	for	alleged	health	or	property	damages	or	for	violations	of	applicable	permits	or	standards.		In addition,	the	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	are	subject	to	liability	under	these laws	for	 the	costs	of	remediation	of	environmental	contamination	of	property	now	or	formerly	owned	or	operated	by	 the	Utility	operating companies,	System	Energy,	and	 the	Entergy	Wholesale	Commodities	business	and	of	property	contaminated	by	hazardous	substances	 they generate.		The	Utility	operating	companies	are	currently	involved	in	proceedings	relating	to	sites	where	hazardous	substances	have	been	released and	may	be	subject	 to	additional	proceedings	 in	 the	future.	 	The	Utility	operating	companies,	System	Energy,	and	 the	Entergy	Wholesale Commodities	business	have	incurred	and	expect	to	incur	significant	costs	related	to	environmental	compliance.

Emissions	of	nitrogen	and	sulfur	oxides,	mercury,	particulates,	greenhouse	gases,	and	other	regulated	air	emissions	from	generating	plants are	potentially	subject	to	increased	regulation,	controls	and	mitigation	expenses.		In	addition,	existing	air	regulations	and	programs	promulgated	by the	EPA	often	are	challenged	legally,	sometimes	resulting	in	large-scale	changes	to	anticipated	regulatory	regimes	and	the	resulting	need	to	shift course,	both	operationally	and

economically,	depending	on	the	nature	of	the	changes.		Risks	relating	to	global	climate	change,	initiatives	to	compel	greenhouse	gas	emission reductions,	and	water	availability	issues	are	discussed	below.

Entergy	and	its	subsidiaries	may	not	be	able	to	obtain	or	maintain	all	required	environmental	regulatory	approvals.		If	there	is	a	delay	in obtaining	any	required	environmental	regulatory	approvals,	or	if	Entergy	and	its	subsidiaries	fail	to	obtain,	maintain,	or	comply	with	any	such approval,	the	operation	of	its	facilities	could	be	stopped	or	become	subject	to	additional	costs.		For	further	information	regarding	environmental regulation	and	environmental	matters,	see	the	"Regulation	of	Entergy's	Business	–	Environmental	Regulation"	section	of	Part	I,	Item	1.

# The	Utility	operating	companies,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	may	incur	substantial	costs	related to	reliability	standards.

Entergy's	business	 is	subject	 to	extensive	and	mandatory	reliability	standards.	 	Such	standards,	which	are	established	by	 the	North American	Electric	Reliability	Corporation	(NERC),	 the	SERC	Reliability	Corporation	(SERC),	and	other	regional	enforcement	entities,	are approved	by	the	FERC	and	frequently	are	reviewed,	amended,	and	supplemented.		Failure	to	comply	with	such	standards	could	result	in	the imposition	of	fines	or	civil	penalties,	and	potential	exposure	to	third	party	claims	for	alleged	violations	of	such	standards.		The	standards,	as	well as	the	laws	and	regulations	that	govern	them,	are	subject	to	judicial	interpretation	and	to	the	enforcement	discretion	vested	in	the	implementing agencies.		In	addition	to	exposure	to	civil	penalties	and	fines,	the	Utility	operating	companies	have	incurred	and	expect	to	incur	significant	costs related	to	compliance	with	new	and	existing	reliability	standards,	including	costs	associated	with	the	Utility	operating	companies'	transmission system	and	generation	assets.		The	changes	to	the	reliability	standards	applicable	to	the	electric	power	industry	are	ongoing,	and	Entergy	cannot predict	the	ultimate	effect	that	the	reliability	standards	will	have	on	its	Utility	and	Entergy	Wholesale	Commodities	business.

# The	effects	of	weather	and	economic	conditions,	and	the	related	impact	on	electricity	and	gas	usage,	may	materially	affect	the	Utility operating	companies'	results	of	operations.

Temperatures	above	normal	levels	in	the	summer	tend	to	increase	summer	cooling	electricity	demand	and	revenues,	and	temperatures below	 moderate	 levels	 in	 the	 winter	 tend	 to	 increase	 winter	 heating	 electricity	 and	 gas	 demand	 and	 revenues.	 	As	 a	 corollary,	 moderate temperatures	tend	to	decrease	usage	of	energy	and	resulting	revenues.		Seasonal	pricing	differentials,	coupled	with	higher	consumption	levels, typically	cause	the	Utility	operating	companies	to	report	higher	revenues	in	the	third	quarter	of	the	fiscal	year	than	in	the	other	quarters.		Extreme weather	conditions	or	storms,	 	however,	may	stress	 the	Utility	operating	companies'	generation	facilities	and	 transmission	and	distribution systems,	resulting	in	increased	maintenance	and	capital	costs	(and	potential	increased	financing	needs),	limits	on	their	ability	to	meet	peak customer	demand,	increased	regulatory	oversight,	and	lower	customer	satisfaction.		These	extreme	conditions	could	have	a	material	effect	on	the Utility	operating	companies'	financial	condition,	results	of	operations,	and	liquidity.

Entergy's	electricity	sales	volumes	are	affected	by	a	number	of	factors,	 including	 the	state	of	 the	national	and	regional	economies, weather,	customer	bill	sizes	(large	bills	tend	to	induce	conservation),	trends	in	energy	efficiency,	and	the	willingness	and	ability	of	large	industrial customers	to	develop	co-generation	facilities	that	greatly	reduce	their	demand	from	Entergy.	Some	of	these	factors	are	inherently	cyclical	or temporary	in	nature,	such	as	the	weather	or	economic	conditions,	and	rarely	have	a	long-lasting	impact	on	Entergy's	operating	results.		Others, such	as	the	increasing	adoption	of	energy	efficient	appliances	and	building	codes,	are	having	a	more	permanent	impact	of	reducing	sales	growth rates	from	historical	norms.	Newer	technologies	such	as	distributed	generation	have	not	yet	had	a	substantive	impact	on	Entergy's	electricity sales,	but	further	advances	have	the	potential	to	do	so	in	the	future.	 	Since	the	national	economy	emerged	from	the	last	recession	in	2009, Entergy's	industrial	sales	in	particular	have	benefited	from	steady	economic	growth	and	relatively	low	natural	gas	prices	from	an	historical perspective.		Any	substantial	negative	change	in	any	of	these	factors	has	the	potential	to	result	in	slower	or	declining	sales	growth	and	increased bad	debt	expense,

which	could	materially	affect	Entergy's	and	the	Utility	operating	companies'	results	of	operations,	financial	condition,	and	liquidity.

# The	effects	of	climate	change	and	environmental	and	regulatory	obligations	intended	to	compel	greenhouse	gas	emission	reductions or	to	place	a	price	on	greenhouse	gas	emissions	could	materially	affect	the	financial	condition,	results	of	operations,	and	liquidity	of	Entergy, the	Utility	operating	companies,	and	System	Energy.

In	an	effort	to	address	climate	change	concerns,	Federal,	state,	and	local	authorities	are	calling	for	additional	laws	and	regulations	aimed	at known	or	suspected	causes	of	climate	change.		For	example,	in	response	to	the	United	States	Supreme	Court's	2007	decision	holding	that	the	EPA has	authority	to	regulate	emissions	of	CO2	and	other	"greenhouse	gases"	under	the	Clean	Air	Act,	the	EPA,	various	environmental	interest groups,	and	other	organizations	are	focusing	considerable	attention	on	CO2	emissions	from	power	generation	facilities	and	their	potential	role	in climate	change.		In	2010,	EPA	promulgated	its	first	regulations	controlling	greenhouse	gas	emissions	from	certain	vehicles	and	from	new	and significantly	modified	stationary	sources	of	emissions,	including	electric	generating	units.		In	2012	and	2013,	EPA	proposed	a	CO2	emission standard	for	new	sources;	this	standard	is	expected	to	be	finalized	in	2014.	Additionally,	EPA	is	expected	to	propose	a	CO2	emission	standard	for existing	power	generation	facilities	in	2014	for	finalization	in	2015.		As	examples	of	state	action,	in	the	Northeast,	the	Regional	Greenhouse	Gas Initiative	(RGGI)	establishes	a	cap	on	CO2	emissions	from	electric	power	plants	and	requires	generators	to	purchase	emission	permits	to	cover their	CO2	emissions,	and	a	similar	program	has	been	developed	in	California.

Developing	and	implementing	plans	for	compliance	with	greenhouse	gas	emissions	reduction	requirements	can	lead	to	additional	capital, personnel,	and	operation	and	maintenance	expenditures	and	could	significantly	affect	the	economic	position	of	existing	facilities	and	proposed projects;	moreover,	long-term	planning	to	meet	environmental	requirements	can	be	negatively	impacted	and	costs	may	increase	to	the	extent	laws and	regulations	change	prior	to	full	implementation.		Violations	of	such	requirements	may	subject	Entergy	Wholesale	Commodities	and	the Utility	operating	companies	to	enforcement	actions,	capital	expenditures	to	bring	existing	facilities	into	compliance,	additional	operating	costs	or operating	restrictions	to	achieve	compliance,	civil	penalties,	and	exposure	to	third	parties'	claims	for	alleged	health	or	property	damages	or	for violations	of	applicable	permits	or	standards.		To	the	extent	Entergy	believes	any	of	these	costs	are	recoverable	in	rates,	however,	additional material	rate	increases	for	customers	could	be	resisted	by	Entergy's	regulators	and,	in	extreme	cases,	Entergy's	regulators	might	deny	or	defer timely	recovery	of	these	costs.		Future	changes	in	environmental	regulation	governing	the	emission	of	CO2	and	other	greenhouse	gases	could make	some	of	Entergy's	electric	generating	units	uneconomical	to	maintain	or	operate,	and	could	increase	the	difficulty	that	Entergy	and	its subsidiaries	have	with	obtaining	or	maintaining	required	environmental	regulatory	approvals,	which	could	also	materially	affect	the	financial condition,	results	of	operations	and	liquidity	of	Entergy	and	its	subsidiaries.		In	addition,	lawsuits	currently	are	pending	or	are	reasonably	expected against	emitters	of	greenhouse	gases	alleging	 that	 these	companies	are	 liable	for	personal	 injuries	and	property	damage	caused	by	climate change.		These	lawsuits	may	seek	injunctive	relief,	monetary	compensation,	and	punitive	damages.

In	addition	to	the	regulatory	and	financial	risks	associated	with	climate	change	discussed	above,	physical	risks	from	climate	change include	an	increase	in	sea	level,	wind	and	storm	surge	damages,	wetland	and	barrier	island	erosion,	risks	of	flooding	and	changes	in	weather conditions,	 such	 as	 changes	 in	 precipitation,	 average	 temperatures,	 and	 potential	 increased	 impacts	 of	 extreme	 weather	 conditions	 or storms.		Entergy	subsidiaries	own	assets	in,	and	serve,	communities	that	are	at	risk	from	sea	level	rise,	changes	in	weather	conditions,	storms,	and loss	of	the	protection	offered	by	coastal	wetlands.		A	significant	portion	of	the	nation's	oil	and	gas	infrastructure	is	located	in	these	areas	and susceptible	to	storm	damage	that	could	be	aggravated	by	wetland	and	barrier	island	erosion,	which	could	give	rise	to	fuel	supply	interruptions	and price	spikes.	Entergy	and	its	subsidiaries	also	face	the	risk	that	climate	change	could	impact	the	availability	and	quality	of	water	supply	necessary for	operations.

These	and	other	physical	changes	could	result	in	changes	in	customer	demand,	increased	costs	associated	with	repairing	and	maintaining generation	facilities	and	 transmission	and	distribution	systems	resulting	 in	 increased	maintenance	and	capital	costs	(and	potential	 increased financing	needs),	limits	on	the	Entergy	System's	ability	to	meet	peak	customer	demand,	increased	regulatory	oversight,	and	lower	customer satisfaction.		Also,	to	the	extent	that	climate

change	adversely	impacts	the	economic	health	of	a	region	or	results	in	energy	conservation	or	demand	side	management	programs,	it	may adversely	 impact	 customer	 demand	 and	 revenues.	 	 Such	 physical	 or	 operational	 risks	 could	 have	 a	 material	 effect	 on	 Entergy's,	 Entergy Wholesale	Commodities,	System	Energy,	and	the	Utility	operating	companies'	financial	condition,	results	of	operations,	and	liquidity.

# Continued	and	future	availability	and	quality	of	water	for	cooling,	process,	and	sanitary	uses	could	materially	affect	the	financial condition,	 results	 of	 operations,	 and	 liquidity	 of	 the	 Utility	 operating	 companies,	 System	 Energy,	 and	 Entergy	 Wholesale	 Commodities business.

Water	 is	 a	 vital	 natural	 resource	 that	 also	 is	 critical	 to	 the	 Utility	 operating	 companies,	 System	 Energy,	 and	 Entergy	 Wholesale Commodities's	business	operations.		Entergy's	facilities	use	water	for	cooling,	boiler	make-up,	sanitary	uses,	potable	supply,	and	many	other uses.		Two	of	Entergy's	Utility	operating	companies	own	and/or	operate	hydroelectric	facilities.		Accordingly,	water	availability	and	quality	are critical	to	Entergy's	business	operations.		Impacts	to	water	availability	or	quality	could	negatively	impact	both	operations	and	revenues.

Entergy	secures	water	through	various	mechanisms	(ground	water	wells,	surface	waters	intakes,	municipal	supply,	etc.)	and	operates under	the	provisions	and	conditions	set	forth	by	the	provider	and/or	regulatory	authorities.		Entergy	also	obtains	and	operates	in	substantial compliance	with	water	discharge	permits	issued	under	various	provisions	of	the	Clean	Water	Act.		Regulations	and	authorizations	for	both	water intake	 and	 use	 and	 for	 waste	 discharge	 can	 become	 more	 stringent	 in	 times	 of	 water	 shortages,	 low	 flows	 in	 rivers,	 low	 lake	 levels,	 low groundwater	aquifer	volumes,	and	similar	conditions.		The	increased	use	of	water	by	industry,	agriculture,	and	the	population	at	large,	population growth,	and	the	potential	impacts	of	climate	change	on	water	resources	may	cause	water	use	restrictions	that	affect	Entergy	and	its	subsidiaries.

# Entergy	 and	 its	 subsidiaries	 may	 not	 be	 adequately	 hedged	 against	 changes in	 commodity	 prices,	 which	 could	 materially	 affect Entergy's	and	its	subsidiaries'	results	of	operations,	financial	condition,	and	liquidity.

To	manage	near-term	financial	exposure	related	 to	commodity	price	fluctuations,	Entergy	and	 its	subsidiaries,	 including	 the	Utility operating	companies	and	the	Entergy	Wholesale	Commodities	business,	may	enter	into	contracts	to	hedge	portions	of	their	purchase	and	sale commitments,	fuel	requirements,	and	inventories	of	natural	gas,	uranium	(and	its	conversion),	coal,	refined	products,	and	other	commodities, within	established	risk	management	guidelines.		As	part	of	this	strategy,	Entergy	and	its	subsidiaries	may	utilize	fixed-	and	variable-price	forward physical	 purchase	 and	 sales	 contracts,	 futures,	 financial	 swaps,	 and	 option	 contracts	 traded	 in	 the	 over-the-counter	 markets	 or	 on exchanges.		However,	Entergy	and	its	subsidiaries	normally	cover	only	a	portion	of	the	exposure	of	their	assets	and	positions	to	market	price volatility,	and	the	coverage	will	vary	over	time.		In	addition,	Entergy	also	elects	to	leave	certain	volumes	during	certain	years	unhedged.		To	the extent	Entergy	and	its	subsidiaries	have	unhedged	positions,	fluctuating	commodity	prices	can	materially	affect	Entergy's	and	its	subsidiaries' results	of	operations	and	financial	position.

Although	Entergy	and	its	subsidiaries	devote	a	considerable	effort	to	these	risk	management	strategies,	they	cannot	eliminate	all	the	risks associated	with	these	activities.		As	a	result	of	these	and	other	factors,	Entergy	and	its	subsidiaries	cannot	predict	with	precision	the	impact	that risk	management	decisions	may	have	on	their	business,	results	of	operations,	or	financial	position.

Entergy	 has	 guaranteed	 or	 indemnified	 the	 performance	 of	 a	 portion	 of	 the	 obligations	 relating	 to	 hedging	 and	 risk	 management activities.		Reductions	in	Entergy's	or	its	subsidiaries'	credit	quality	or	changes	in	the	market	prices	of	energy	commodities	could	increase	the	cash or	letter	of	credit	collateral	required	to	be	posted	in	connection	with	hedging	and	risk	management	activities,	which	could	materially	affect Entergy's	or	its	subsidiaries'	liquidity	and	financial	position.

# The	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities	business	are	exposed	to	the	risk	that	counterparties	may	not meet	their	obligations,	which	may	materially	affect	the	Utility	operating	companies	and	Entergy	Wholesale	Commodities.

The	hedging	and	risk	management	practices	of	the	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities	business	are exposed	 to	 the	 risk	 that	 counterparties	 that	 owe	 Entergy	 and	 its	 subsidiaries	 money,	 energy,	 or	 other	 commodities	 will	 not	 perform	 their obligations.		Currently,	some	hedging	agreements	contain	provisions	that	require	the	counterparties	to	provide	credit	support	to	secure	all	or	part of	their	obligations	to	Entergy	or	its	subsidiaries.		If	the	counterparties	to	these	arrangements	fail	to	perform,	Entergy	or	its	subsidiaries	may enforce	and	recover	the	proceeds	from	the	credit	support	provided	and	acquire	alternative	hedging	arrangements	or	draw	on	the	credit	support provided	by	the	counterparties,	which	credit	support	may	not	always	be	adequate	to	cover	the	related	obligations.		In	such	event,	Entergy	and	its subsidiaries	might	incur	losses	in	addition	to	amounts,	if	any,	already	paid	to	the	counterparties.		In	addition,	the	credit	commitments	of	Entergy's lenders	under	its	bank	facilities	may	not	be	honored	for	a	variety	of	reasons,	including	unexpected	periods	of	financial	distress	affecting	such lenders,	which	could	materially	affect	the	adequacy	of	its	liquidity	sources.

# The	Wall	Street	Transparency	and	Accountability	Act	of	2010	and	rules	and	regulations	promulgated	under	the	act	may	adversely affect	the	ability	of	the	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities	business	to	utilize	certain	commodity	derivatives for	hedging	and	mitigating	commercial	risk.

The	Wall	Street	Transparency	and	Accountability	Act	of	2010,	which	was	enacted	on	July	21,	2010	as	part	of	the	Dodd-Frank	Wall	Street Reform	and	Consumer	Protection	Act,	and	the	rules	and	regulations	promulgated	under	the	act	impose	governmental	regulation	on	the	over-the- counter	derivative	market,	including	the	commodity	swaps	used	by	the	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities business	 to	 hedge	 and	 mitigate	 commercial	 risk.	 	 Under	 the	 act,	 certain	 swaps	 are	 subject	 to	 mandatory	 clearing	 and	 exchange	 trading requirements.		Swap	dealers	and	major	market	participants	in	the	swap	market	are	subject	to	capital,	margin,	registration,	reporting,	recordkeeping, and	business	conduct	requirements	with	respect	to	their	swap	activities.		Entergy	is	not	a	swap	dealer	or	a	major	swap	participant,	and	does	not expect	 to	 qualify	 as	 either	 in	 the	 future.	Non-swap	 dealers	 and	 non-major	 swap	 participants,	 such	 as	 Entergy,	 are	 subject	 to	 reporting, recordkeeping,	and	business	conduct	requirements	(i.e.,	anti-manipulation,	anti-disruptive	trading	practices,	and	whistleblower	provisions)	with respect	to	their	swap	activities.	Position	limits	may	also	apply	to	certain	swaps	activities.	Position	limit	rules	promulgated	by	the	Commodity Futures	Trading	Commission	were	vacated	by	the	US	District	Court	for	the	District	of	Columbia.	The	Commodity	Futures	Trading	Commission has	subsequently	proposed	new	position	limit	rules.	If	the	Commodity	Futures	Trading	Commission's	issues	final	position	limit	rules,	those	rules may	apply	to	certain	of	Entergy's	swaps	activities.

The	act	required	the	applicable	regulators,	which	in	the	case	of	commodity	swaps	will	be	the	Commodity	Futures	Trading	Commission,	to engage	in	substantial	rulemaking	in	order	to	implement	the	provisions	of	the	act	and	such	rulemaking	has	been	largely	completed.		Both	the	Utility operating	companies	and	the	Entergy	Wholesale	Commodities	business	currently	utilize	commodity	swaps	to	hedge	and	mitigate	commodity	price risk.		It	is	not	known	whether	the	act	and	regulations	promulgated	under	the	act	will	have	an	adverse	effect	upon	the	market	for	the	commodity swaps	used	by	the	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities	business.	 	However,	to	the	extent	that	the	act	and regulations	promulgated	under	the	act	have	the	effect	of	increasing	the	price	of	such	commodity	swaps	or	limiting	or	reducing	the	availability	of such	 commodity	 swaps,	 whether	 through	 the	 imposition	 of	 additional	 capital,	 margin,	 or	 compliance	 costs	 upon	 market	 participants,	 the imposition	 of	 position	 limits,	 or	 otherwise,	 the	 financial	 performance	 of	 the	 Utility	 operating	 companies	 and/or	 the	 Entergy	 Wholesale Commodities	business	may	be	adversely	affected.		To	the	extent	that	the	Utility	operating	companies	and	the	Entergy	Wholesale	Commodities business	may	be	required	to	post	margin	in	connection	with	existing	or	future	commodity	swaps	in	addition	to	any	margin	currently	posted	by such	entities,	such	entities	may	need	to	secure	additional	sources	of	capital	to	meet	such	liquidity	needs	or	cease	utilizing	such	commodity	swaps.

# Market	performance	and	other	changes	may	decrease	the	value	of	benefit	plan	assets,	which	then	could	require	additional	funding.

The	performance	of	the	capital	markets	affects	the	values	of	the	assets	held	in	trust	under	Entergy's	pension	and	postretirement	benefit plans.		A	decline	in	the	market	value	of	the	assets	may	increase	the	funding	requirements	relating	to	Entergy's	benefit	plan	liabilities.		Volatility	in the	 capital	 markets	 has	 affected	 the	 market	 value	 of	 these	 assets,	 which	 may	 affect	 Entergy's	 planned	 levels	 of	 contributions	 in	 the future.		Additionally,	changes	in	interest	rates	affect	the	liabilities	under	Entergy's	pension	and	postretirement	benefit	plans;	as	interest	rates decrease,	the	liabilities	increase,	potentially	requiring	additional	funding.		The	funding	requirements	of	the	obligations	related	to	the	pension benefit	 plans	 can	 also	 increase	 as	 a	 result	 of	 changes	 in,	 among	 other	 factors,	 retirement	 rates,	 life	 expectancy	 assumptions,	 or	 Federal regulations.	 	For	further	 information	regarding	Entergy's	pension	and	other	postretirement	benefit	plans,	refer	 to the	"Critical	Accounting Estimates	–	Qualified	Pension	and	Other	Postretirement	Benefits "	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy and	each	of	its	Registrant	Subsidiaries	and	Note	11	to	the	financial	statements.

# The	litigation	environment	in	the	states	in	which	certain	Entergy	subsidiaries	operate	poses	a	significant	risk	to	those	businesses.

Entergy	and	its	subsidiaries	are	involved	in	the	ordinary	course	of	business	in	a	number	of	lawsuits	involving	employment,	commercial, asbestos,	hazardous	material	and	ratepayer	matters,	and	 injuries	and	damages	 issues,	among	other	matters.	 	The	states	 in	which	 the	Utility operating	companies	operate,	in	particular	Louisiana,	Mississippi,	and	Texas,	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	and	its	subsidiaries	use	legal	and	appropriate	means	to	contest	litigation	threatened	or	filed	against	them, but	the	litigation	environment	in	these	states	poses	a	significant	business	risk.

# Terrorist	attacks,	including	cyber	attacks,	and	failures	or	breaches	of	Entergy's	and	its	subsidiaries'	technology	systems	may	adversely affect	Entergy's	results	of	operations.

As	power	generators	and	distributors,	Entergy	and	its	subsidiaries	face	heightened	risk	of	an	act	or	threat	of	terrorism,			including	physical and	cyber	attacks,	either	as	a	direct	act	against	one	of	Entergy's	generation	facilities,	an	act	against	the	transmission	and	distribution	infrastructure used	to	transport	power	that	affects	its	ability	to	operate,	or	an	act	against	the	information	technology	systems	and	network	infrastructure	of Entergy	and	its	subsidiaries.

Entergy	and	its	subsidiaries	operate	in	a	highly	regulated	industry	that	requires	the	continued	operation	of	sophisticated	information technology	systems	and	network	infrastructure.		Despite	the	implementation	of	security	measures	by	Entergy	and	its	subsidiaries,	all	technology systems	are	vulnerable	to	disability,	failures,	or	unauthorized	access	due	to	such	activities.	If	Entergy's	or	its	subsidiaries'	technology	systems were	to	fail	or	be	breached	and	be	unable	to	recover	in	a	timely	way,	Entergy	or	its	subsidiaries	may	be	unable	to	fulfill	critical	business	functions, and	sensitive	confidential	and	other	data	could	be	compromised.

If	any	such	attacks,	failures	or	breaches	were	to	occur,	Entergy's	and	the	Utility	operating	companies'	business,	financial	condition,	and results	of	operations	could	be	materially	affected.		The	risk	of	such	attacks,	failures,	or	breaches	also	may	cause	Entergy	and	the	Utility	operating companies	to	incur	increased	capital	and	operating	costs	to	implement	increased	security	for	its	nuclear	power	plants	and	other	facilities,	such	as additional	 physical	 facility	 security	 and	 additional	 security	 personnel,	 and	 for	 systems	 to	 protect	 its	 information	 technology	 and	 network infrastructure	systems.

# Changes	in	taxation	as	well	as	the	inherent	difficulty	in	quantifying	potential	tax	effects	of	business	decisions	could	negatively	impact Entergy's,	the	Utility	operating	companies',	and	System	Energy's	results	of	operations,	financial	condition	and	liquidity.

Entergy	and	its	subsidiaries	make	judgments	regarding	the	potential	tax	effects	of	various	transactions	and	results	of	operations	to	estimate their	 obligations	 to	 taxing	 authorities.	 	These	 tax	 obligations	 include	 income,	 franchise,	 real	 estate,	 sales	 and	 use,	 and	 employment-related taxes.		These	judgments	include	reserves	for	potential	adverse	outcomes	regarding	tax	positions	that	have	been	taken.		Entergy	and	its	subsidiaries also	estimate	their	ability	to	utilize	tax	benefits,	including	those	in	the	form	of	carryforwards	for	which	the	benefits	have	already	been	reflected	in the	financial	statements.		Changes	in	federal,	state,	or	local	tax	laws,	adverse	tax	audit	results	or	adverse	tax	rulings	on	positions	taken	by	Entergy and	its	subsidiaries	could	negatively	affect	Entergy's,	the	Utility	operating	companies',	and	System	Energy's	results	of	operations,	financial condition,	and	liquidity.		For	further	information	regarding	Entergy's	accounting	for	tax	obligations,	refer	to	Note	3	to	the	financial	statements.

# (Entergy	Gulf	States	Louisiana	and	Entergy	New	Orleans)

# The	effect	of	higher	purchased	gas	cost	charges	to	customers	may	adversely	affect	Entergy	Gulf	States	Louisiana's	and	Entergy	New Orleans's	results	of	operations	and	liquidity.

Gas	rates	charged	to	retail	gas	customers	are	comprised	primarily	of	purchased	gas	cost	charges,	which	provide	no	return	or	profit	to Entergy	Gulf	States	Louisiana	or	Entergy	New	Orleans,	and	distribution	charges,	which	provide	a	return	or	profit	to	the	utility.		Distribution charges	are	affected	by	the	amount	of	gas	sold	to	customers.		Purchased	gas	cost	charges,	which	comprise	most	of	a	customer's	bill	and	may	be adjusted	 monthly,	 represent	 gas	 commodity	 costs	 that	 Entergy	 Gulf	 States	 Louisiana	 or	 Entergy	 New	 Orleans	 recovers	 from	 its customers.		Entergy	Gulf	States	Louisiana's	or	Entergy	New	Orleans's	cash	flows	can	be	affected	by	differences	between	the	time	period	when gas	is	purchased	and	the	time	when	ultimate	recovery	from	customers	occurs.		When	purchased	gas	cost	charges	increase	substantially	reflecting higher	gas	procurement	costs	incurred	by	Entergy	Gulf	States	Louisiana	or	Entergy	New	Orleans,	customer	usage	may	decrease,	especially	in weaker	economic	times,	resulting	in	lower	distribution	charges	for	Entergy	Gulf	States	Louisiana	or	Entergy	New	Orleans	which	could	adversely affect	results	of	operations.

# System	Energy	owns	and	operates	a	single	nuclear	generating	facility,	and it is	dependent	on	affiliated	companies	for	all	of its revenues.

System	Energy's	operating	revenues	are	derived	from	the	allocation	of	the	capacity,	energy,	and	related	costs	associated	with	its	90% ownership/leasehold	interest	in	Grand	Gulf.		Charges	under	the	Unit	Power	Sales	Agreement	are	paid	by	the	Utility	operating	companies	as consideration	for	their	respective	entitlements	to	receive	capacity	and	energy.		The	useful	economic	life	of	Grand	Gulf	is	finite	and	is	limited	by the	terms	of	its	operating	license,	which	is	currently	due	to	expire	on	November	1,	2024.		System	Energy	filed	in	October	2011	an	application	with the	NRC	for	an	extension	of	Grand	Gulf's	operating	license	to	2044.	 	System	Energy's	financial	condition	depends	both	on	the	receipt	of payments	from	the	Utility	operating	companies	under	the	Unit	Power	Sales	Agreement	and	on	the	continued	commercial	operation	of	Grand	Gulf.

For	information	regarding	the	Unit	Power	Sales	Agreement,	the	sale	and	leaseback	transactions	and	certain	other	agreements	relating	to the	Entergy	System	companies'	support	of	System	Energy	(including	the	Capital	Funds	Agreement),	see	the	"Grand	Gulf-Related	Agreements" section	of	Note	8	to	the	financial	statements	and	the	"Sale	and	Leaseback	Transactions"	section	of	Note	10	to	the	financial	statements,	and	the "Utility	-	System	Energy	and	Related	Agreements"	section	of	Part	I,	Item	1.

# As	a	holding	company,	Entergy	Corporation	depends	on	cash	distributions	from	its	subsidiaries	to	meet	its	debt	service	and	other financial	obligations	and	to	pay	dividends	on	its	common	stock.

Entergy	Corporation	is	a	holding	company	with	no	material	revenue	generating	operations	of	its	own	or	material	assets	other	than	the stock	of	its	subsidiaries.		Accordingly,	all	of	its	operations	are	conducted	by	its	subsidiaries.		Entergy	Corporation's	ability	to	satisfy	its	financial obligations,	including	the	payment	of	interest	and	principal	on	its	outstanding	debt,	and	to	pay	dividends	on	its	common	stock	depends	on	the payment	 to	 it	 of	 dividends	 or	 distributions	 by	 its	 subsidiaries.	 	The	 payments	 of	 dividends	 or	 distributions	 to	 Entergy	 Corporation	 by	 its subsidiaries	in	turn	depend	on	their	results	of	operations	and	cash	flows	and	other	items	affecting	retained	earnings,	and	on	any	applicable	legal, regulatory,	or	contractual	limitations	on	subsidiaries'	ability	to	pay	such	dividends	or	distributions.		Provisions	in	the	organizational	documents, indentures	for	debt	issuances,	and	other	agreements	of	certain	of	Entergy	Corporation's	subsidiaries	restrict	the	payment	of	cash	dividends	to Entergy	Corporation.		For	further	information	regarding	dividend	or	distribution	restrictions	to	Entergy	Corporation,	see	the	"Retained	Earnings and	Dividend	Restrictions"	section	of	Note	7	to	the	financial	statements.

# ENTERGY	ARKANSAS,	INC.	AND	SUBSIDIARIES

# Plan	to	Spin	Off	the	Utility's	Transmission	Business

# Net	Income

Net	income	increased	$9.6	million	primarily	due	to	higher	net	revenue,	higher	other	income,	lower	nuclear	refueling	outage	expenses,	and a	 lower	effective	 income	 tax	rate,	partially	offset	by	higher	other	operation	and	maintenance	expenses,	higher	 interest	expense,	and	higher depreciation	and	amortization	expenses.

Net	 income	decreased	$12.5	million	primarily	due to	higher	other	operation	and	maintenance	expenses	and	higher taxes	other than income	taxes,	partially	offset	by	a	lower	effective	income	tax	rate.

Net	revenue	consists	of	operating	revenues	net	of:	1)	fuel,	fuel-related	expenses,	and	gas	purchased	for	resale,	2)	purchased	power expenses,	and	3)	other	regulatory	credits.		Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2013	to	2012.

| 2012	net	revenue | $1,253.0 |
| :--- | :--- |
| Retail\telectric\tprice | 46.4 |
| MISO\tdeferral | 11.1 |
| Net\twholesale\trevenue | 6.5 |
| Volume/weather | (10.7) |
| ANO\tdecommissioning\ttrust | (10.4) |
| Other | 5.6 |
| 2013\tnet\trevenue | $1,301.5 |

•an	increase	in	the	capacity	acquisition	rider,	as	approved	by	the	APSC,	effective	with	the	first	billing	cycle	of	December	2012,	relating	to the	Hot	Spring	plant	acquisition.	The	net	income	effect	of	the	Hot	Spring	plant	cost	recovery	is	limited	to	a	portion	representing	an allowed	return	on	equity	on	the	net	plant

investment	with	the	remainder	offset	by	the	Hot	Spring	plant	costs	in	other	operation	and	maintenance	expenses,	depreciation	expenses, and	taxes	other	than	income	taxes;	and

•increases	in	the	energy	efficiency	rider,	as	approved	by	the	APSC,	effective	July	2013	and	July	2012.	Energy	efficiency	revenues	are largely	offset	by	costs	included	in	other	operation	and	maintenance	expenses	and	have	no	effect	on	net	income.

The	MISO	deferral	variance	is	due	to	the	deferral	in	April	2013,	as	approved	by	the	APSC,	of	costs	incurred since	March	2010	related	to	the	transition	and	implementation	of	joining	the	MISO	RTO.

The	net	wholesale	variance	is	primarily	due	to	higher	margins	on	co-owner	contracts.

The	volume/weather	variance	is	due	to	lower	weather-adjusted	usage	across	all	sectors,	partially	offset	by	the	effect	of	more	favorable weather	on	residential	sales.	The	decrease	in	the	industry	usage	was	primarily	driven	by	the	pulp	and	paper	industry,	the	chemicals	industry,	and the	food	products	industry.

The	ANO	decommissioning	trust	variance	is	primarily	due	to	lower	regulatory	credits	resulting	from	an	increase	in	realized	gains	earned on	decommissioning	trust	fund	investments.	There	is	no	effect	on	net	income	as	the	credits	are	offset	by	interest	and	investment	income.

# Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	credits

Gross	operating	revenues	increased	primarily	due	to:

•an	increase	of	$33.7	million	in	gross	wholesale	revenues	primarily	due	to	increased	sales	to	affiliated	customers	and	higher	prices; •the	June	2012	AmerenUE	refund	of	$30.6	million,	including	interest,	in	rough	production	cost	equalization	payments	collected	from AmerenUE.	Entergy	Arkansas	had	previously	recorded	a	regulatory	provision	for	the	potential	refund	to	AmerenUE.	The	result	of	the refund	in	2012	was	a	decrease	in	gross	revenues	with	an	offsetting	increase	in	other	regulatory	credits.	See	Note	2	to	the	financial statements	for	a	discussion	of	the	FERC	order	in	the	System	Agreement	production	cost	equalization	proceedings;

•an	increase	of	$27.2	million	due	to	the	increase	in	the	capacity	acquisition	rider,	as	discussed	above;

•an	increase	of	$24.6	million	in	rider	revenues	primarily	due	to	an	increase	in	the	Grand	Gulf	rate	effective	January	2013;

•an	increase	of	$20.5	million	in	rider	revenues	due	to	increases	in	the	energy	efficiency	rider	effective	July	2013	and	July	2012,	as discussed	above;	and

•an	increase	of	$14.3	million	in	rider	revenues	related	to	higher	System	Agreement	production	cost	equalization	payments.	These	revenues are	offset	in	deferred	fuel	expenses.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the	FERC	orders	in	the	System	Agreement production	cost	equalization	proceedings.

The	increase	was	partially	offset	by	a	decrease	of	$87.5	million	in	fuel	cost	recovery	revenues	as	a	result	of	lower fuel	rates	and	the	decrease	related	to	volume/weather,	as	discussed	above.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	a	decrease	in	the	recovery	from	customers	of	deferred	fuel	costs.

•increased	purchased	power	costs	and	gas-fired	generation	due	to	an	increase	in	demand	as	a	result	of	the	ANO	extended	outage	as	well	as increases	in	the	average	market	prices	of	natural	gas	and	purchased	power;	and

•higher	costs	related	to	System	Agreement	production	cost	equalization	payments,	as	discussed	above.

Other	regulatory	credits	decreased	primarily	due	to	the	June	2012	refund	to	AmerenUE,	as	discussed	above,	and	higher	deferred	gains	in 2013	on	decommissioning	trust	fund	investments.	These	decreases	were	partially	offset	by	the	deferral	of	MISO	costs	in	April	2013,	as	discussed above.

| 2011	net	revenue | $1,252.3 |
| :--- | :--- |
| Retail\telectric\tprice | 23.4 |
| Net\twholesale\trevenue | 5.7 |
| Transmission\trevenue | (9.6) |
| Volume/weather | (19.0) |
| Other | 0.2 |
| 2012\tnet\trevenue | $1,253.0 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	the	energy	efficiency	rider,	as	approved	by	the	APSC,	effective	July 2012.	The	energy	efficiency	rider	revenues	are	largely	offset	by	costs	included	in	other	operation	and	maintenance	expenses	and	have	no	effect	on net	income.

The	net	wholesale	revenue	variance	is	primarily	due	to	higher	wholesale	billings	to	affiliate	companies	due	to	higher	expenses	and	lower wholesale	energy	costs.

The	 transmission	revenue	variance	 is	primarily	due	 to	a	revision	 to	 transmission	 investment	equalization	billings	under the	System Agreement	among	the	Utility	operating	companies	(for	the	approximate	period	of	1996	-	2011)	recorded	in	the	fourth	quarter	2011.

The	volume/weather	variance	is	primarily	due	to	the	effects	of	milder	weather,	as	compared	to	the	prior	period,	primarily	on	residential sales.

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$39.2	million	in	rider	revenues	related	to	higher	System	Agreement production	cost	equalization	payments	and	an	increase	of	$16.1	million	in	rider	revenues	due	to	an	increase	in	the	energy	efficiency	rider	effective July	2012.	The	increase	was	partially	offset	by	the	June	2012	refund	to	AmerenUE	of	$30.6	million,	including	interest,	of	rough	production	cost equalization	payments	collected	from	AmerenUE.	Entergy	Arkansas	had	previously	recorded	a	regulatory	provision	for	the	potential	refund	to AmerenUE.	The	result	of	the	refund	was	a	decrease	in	gross	revenues	with	an	offsetting	increase	in	other	regulatory	credits.	See	"2007	Rate	Filing Based	on	Calendar	Year	2006	Production	Costs"	in	Note	2	to	the	financial	statements	for	a	discussion	of	the	FERC	order	in	the	System	Agreement production	cost	equalization	proceedings.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	an	increase	in	the	recovery	from	customers	of	deferred	fuel	costs,	partially offset	by	a	decrease	in	the	average	market	price	of	purchased	power.

Other	regulatory	credits	increased	primarily	due	to	the	June	2012	refund	to	AmerenUE,	as	discussed	above.

# Other	Income	Statement	Variances

Nuclear	refueling	outage	expenses	decreased	primarily	due	to	lower	costs	associated	with	the	most	recent	outage	as	compared	to	the previous	outages.

Other	operation	and	maintenance	expenses	increased	primarily	due	to:

•an	increase	of	$24.3	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative,	partially	offset	by	the	deferral,	as	approved	by	the	APSC,	of	$21.8	million of	these	costs.	See	"Human	Capital	Management	Strategic	Imperative"	section	of	Entergy	Corporation	and	Subsidiaries	Management's Financial	Discussion	and	Analysis	for	further	discussion;

•an	increase	of	$16.2	million	in	fossil-fueled	generation	expenses	primarily	due	to	the	addition	of	the	Hot	Spring	plant	in	November	2012; •an	increase	of	$16.1	million	in	energy	efficiency	costs.	These	costs	are	recovered	through	the	energy	efficiency	rider	and	have	no	effect on	net	income;

•an	increase	of	$10.8	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	the	discount	rates	used	to	determine	net periodic	pension	and	other	postretirement	benefit	costs	and	a	settlement	charge,	recognized	in	September	2013,	related	to	the	payment	of lump	sum	benefits	out	of	the	non-qualified	pension	plan.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs;	and

The	increase	was	partially	offset	by:

•a	decrease	of	$4.6	million	due	to	costs	incurred	in	2012	related	to	the	transition	and	implementation	of	joining	the	MISO	RTO.	In	April 2013,	Entergy	Arkansas	began	deferring	these	costs	as	approved	by	the	APSC;	and

•the	effects	of	recording	the	final	court	decision	in	the	Entergy	Arkansas	lawsuit	against	the	U.S.	Department	of	Energy	related	to	spent nuclear	fuel	disposal.	The	damages	awarded	include	the	reimbursement	of	approximately	$3.2	million	of	spent	nuclear	fuel	storage	costs previously	recorded	as	other	operation	and	maintenance	expense.

Also,	other	operation	and	maintenance	expenses	include	$8.6	million	in	2013	and	$13.3	million	in	2012	of	costs	incurred	related	to	the	now terminated	plan	to	spin	off	and	merge	the	transmission	business.

Depreciation	and	amortization	expenses	increased	primarily	due	to	the	acquisition	of	the	Hot	Spring	plant	in	November	2012,	partially offset	by	the	effects	of	recording	the	final	court	decision	in	the	Entergy	Arkansas	lawsuit	against	the	U.S.	Department	of	Energy	related	to	spent nuclear	 fuel	 disposal.	 The	 damages	 awarded	 include	 the	 reimbursement	 of	 approximately	 $3.6	 million	 of	 spent	 nuclear	 fuel	 storage	 costs previously	recorded	as	depreciation	expense.

Other	income	increased	primarily	due	to	higher	realized	gains	in	2013	on	the	ANO	1	and	ANO	2	decommissioning	trust	fund	investments. There	is	no	effect	on	net	income	as	these	investment	gains	are	offset	by	a	corresponding	amount	of	regulatory	charges.

Interest	expense	increased	primarily	due	to:

•the	issuance	of	$200	million	of	4.90%	Series	first	mortgage	bonds	in	December	2012; •the	issuance	of	$250	million	of	3.05%	Series	first	mortgage	bonds	bonds	in	May	2013;	and •the	issuance	of	$125	million	of	4.75%	Series	first	mortgage	bonds	in	June	2013.

This	increase	was	offset	by	the	retirement,	at	maturity,	of	$300	million	of	5.40%	Series	first	mortgage	bonds	in	August	2013.

•an	increase	of	$14.8	million	in	compensation	and	benefits	costs	resulting	from	a	decrease	in	the	discount	rate	and	changes	in	certain actuarial	assumptions	resulting	from	an	experience	study.		See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs;

•an	increase	of	$13.9	million	in	energy	efficiency	costs.		These	costs	are	recovered	through	the	energy	efficiency	rider	and	have	no	effect on	net	income;

•$13.3	million	of	costs	incurred	in	2012	related	to	the	now	terminated	plan	to	spin	off	and	merge	the	transmission	business;	and •an	increase	of	$10.3	million	in	nuclear	generation	expenses	primarily	due	to	higher	contract	costs.

The	increase	was	partially	offset	by	a	decrease	of	$8.0	million	in	fossil-fueled	generation	expenses	primarily	due	to	higher	plant	outage	costs	in 2011	due	to	a	greater	scope	of	work.

Nuclear	refueling	outage	expenses	increased	primarily	due	to	higher	costs	associated	with	the	most	recent	outage	as	compared	to	the previous	outages.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	resulting	from	higher	assessments	and	an increase	in	local	franchise	taxes	resulting	from	higher	residential	and	commercial	electric	revenues	compared	to	2011.		Franchise	taxes	have	no effect	on	net	income	as	these	taxes	are	recovered	through	the	franchise	tax	rider.

The	effective	 income	 tax	rates	for	2013,	2012,	and	2011	were	36.2%,	38.4%,	and	44.6%,	respectively.	See	Note	3 to the	financial statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rates.

On	March	31,	2013,	during	a	scheduled	refueling	outage	at	ANO	1,	a	contractor-owned	and	operated	heavy-lifting	apparatus	collapsed while	moving	the	generator	stator	out	of	the	turbine	building.		The	collapse	resulted	in	the	death	of	an	ironworker	and	injuries	to	several	other contract	workers,	caused	ANO	2	to	shut	down,	and	damaged	the	ANO	turbine	building.		The	turbine	building	serves	both	ANO	1	and	2	and	is	a non-radiological	area	of	the	plant.	ANO	2	reconnected	to	the	grid	on	April	28,	2013	and	ANO	1	reconnected	to	the	grid	on	August	7,	2013.		The total	cost	of	assessment,	restoration	of	off-site	power,	site	restoration,	debris	removal,	and	replacement	of	damaged	property	and	equipment	is currently	estimated	to	be	approximately	$94	million	as	of	December	31,	2013.		In	addition,	Entergy	Arkansas	incurred	replacement	power	costs for	ANO	2	power	during	its	outage	and	incurred	incremental	replacement	power	costs	for	ANO	1	power	because	the	outage	extended	beyond	the originally-planned	duration	of	the	refueling	outage.		Each	of	the	Utility	operating	companies	has	recovery	mechanisms	in	place	designed	to recover	its	prudently-

Entergy	Arkansas,	Inc.	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

incurred	fuel	and	purchased	power	costs.	See	"Energy	Costs	Recovery	Rider"	section	below	for	additional	information	regarding	proposed treatment	of	estimated	replacement	power	costs	associated	with	the	incident.

# Cash	Flow

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $34,533 | $22,599 | $106,102 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 401,250 | 509,117 | 564,124 |
| Investing\tactivities | (524,473) | (723,248) | (503,524) |
| Financing\tactivities | 215,712 | 226,065 | (144,103) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 92,489 | 11,934 | (83,503) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $127,022 | $34,533 | $22,599 |

# Operating	Activities

Net	cash	flow	provided	by	operating	activities	decreased	$107.9	million	in	2013	compared	to	2012	primarily	due	to:

•income	tax	payments	of	$184.6	million	in	2013	compared	to	income	tax	refunds	of	$20.5	million	in	2012.	Entergy	Arkansas	had	income tax	payments	in	2013	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement.	The	income	tax	payments	in	2013	resulted	primarily	from	the	reversal	of	temporary	differences	for	which	Entergy	Arkansas had	previously	claimed	a	tax	deduction;

•approximately	$25	million	in	spending	related	to	the	generator	stator	incident	at	ANO,	as	discussed	above;

•$22.6	million	in	storm	restoration	spending	in	2013	resulting	from	the	December	2012	winter	storm	which	caused	significant	damage	to Entergy	Arkansas's	distribution	lines,	equipment,	poles	and	other	facilities;	and

•a	decrease	in	the	recovery	of	fuel	and	purchased	power	costs.

# These	decreases	were	offset	by:

•proceeds	of	$38	million	associated	with	the	payments	received	in	2013	from	the	U.S.	Department	of	Energy	resulting	from	litigation regarding	the	storage	of	spent	nuclear	fuel;	and

•the	$30.6	million	June	2012	refund	to	AmerenUE,	as	discussed	above.

Net	cash	provided	by	operating	activities	decreased	$55.0	million	in	2012	compared	to	2011	primarily	due	to	the	$156	million	System Agreement	bandwidth	remedy	payment	made	in	January	2012	as	a	result	of	the	payment	required	to	implement	the	FERC's	remedy	for	the	period June	–	December	2005,	a	decrease	of	$69.5	million	in	income	tax	refunds,	and	the	$30.6	million	refund,	including	interest,	to	AmerenUE,	as discussed	above.		These	decreases	were	partially	offset	by	a	decrease	of	$83.2	million	in	pension	contributions	and	the	increased	recovery	of	fuel and	purchased	power	costs,	including	partial	recovery	of	the	System	Agreement	bandwidth	remedy	payment	made	in	January	2012.		See	"Critical Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits funding.

Net	cash	used	in	investing	activities	decreased	$198.8	million	in	2013	compared	to	2012	primarily	due	to	the	purchase	of	the	Hot	Spring Energy	Facility	for	approximately	$253	million	in	November	2012	and	fluctuations	in	nuclear	fuel	activity	because	of	variations	from	year	to	year in	the	timing	and	pricing	of	fuel	reload	requirements	in	the	Utility	business,	material	and	services	deliveries,	and	the	timing	of	cash	payments during	the	nuclear	fuel	cycle.	See	Note	15	to	the	financial	statements	for	a	discussion	of	the	purchase	of	the	Hot	Spring	Energy	Facility.

•$39.6	million	in	storm	restoration	spending	in	2013	resulting	from	the	December	2012	winter	storm;

•$7.6	million	in	storm	restoration	spending	in	2013	resulting	from	the	December	2013	winter	storm;	and •money	pool	activity.

Increases	in	Entergy	Arkansas's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Arkansas's	receivable	from	the money	pool	increased	by	$9.5	million	in	2013	as	compared	to	decreasing	by	$9.3	million	in	2012.	The	money	pool	is	an	inter-company	borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	increased	$219.7	million	in	2012	compared	to	2011	primarily	due	to	the	purchase	of	Hot	Spring Energy	Facility	for	approximately	$253	million	in	November	2012	and	money	pool	activity.		The	increase	was	partially	offset	by	fluctuations	in nuclear	fuel	activity	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements	in	the	Utility	business,	material and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle.

Decreases	in	Entergy	Arkansas's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Arkansas's	receivable	from	the money	pool	decreased	by	$9.3	million	in	2012	compared	to	decreasing	by	$24.1	million	in	2011.

Net	cash	provided	by	financing	activities	decreased	$10.4	million	in	2013	compared	to	2012	primarily	due	to:

•the	retirement,	at	maturity,	of	$30	million	of	9%	Series	H	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	June	2013; •the	retirement,	at	maturity,	of	$300	million	of	5.40%	Series	first	mortgage	bonds	in	August	2013;

•the	issuance	of	$200	million	of	4.9%	Series	first	mortgage	bonds	in	December	2012;

•the	issuance	of	$60	million	of	2.62%	Series	K	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	December	2012;	and •the	net	repayment	of	$36.7	million	of	borrowings	on	the	nuclear	fuel	company	variable	interest	entity	credit	facility	in	2013	compared	to net	borrowings	of	$2.8	million	in	2012.

•borrowings	on	a	$250	million	term	loan	credit	facility	entered	into	in	July	2013.

Financing	activities	provided	cash	of	$226.1	million	in	2012	compared	to	using	cash	of	$144.1	million	in	2011	primarily	due	to:

•the	issuance	of	$200	million	of	4.9%	Series	first	mortgage	bonds	in	December	2012	and	$60	million	2.62%	Series	K	note	by	the	nuclear fuel	company	variable	interest	entity	in	December	2012	compared	to	the	issuance	of	$55	million	3.23%	Series	J	note	by	the	nuclear	fuel company	variable	interest	entity	in	June	2011;

•a	decrease	of	$107.8	million	in	common	stock	dividends	paid	in	2012;

•the	repayment,	at	maturity,	of	a	$35	million	5.60%	Series	G	note	by	the	nuclear	fuel	company	variable	interest	entity	in	September	2011; and

•an	increase	in	borrowings	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility.

See	Note	5	to	the	financial	statements	for	details	of	long-term	debt.

Entergy	Arkansas's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 56.7% | 56.0% |
| Effect\tof\texcluding\tthe\tsecuritization\tbonds | (0.9%) | (1.2%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 55.8% | 54.8% |
| Effect\tof\tsubtracting\tcash | (1.4%) | (0.4%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 54.4% | 54.4% |

(a) Calculation	excludes	the	securitization	bonds,	which	are	non-recourse	to	Entergy	Arkansas.

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	short-term	borrowings	and	long-term	debt,	including	the	currently maturing	portion.	Capital	consists	of	debt,	preferred	stock	without	sinking	fund,	and	common	equity.	Net	capital	consists	of	capital	less	cash	and cash	equivalents.	Entergy	Arkansas	uses	the	debt	to	capital	ratios	excluding	securitization	bonds	in	analyzing	its	financial	condition	and	believes they	provide	useful	information	to	its	investors	and	creditors	in	evaluating	Entergy	Arkansas's	financial	condition	because	the	securitization	bonds are	non-

recourse	to	Entergy	Arkansas,	as	more	fully	described	in	Note	5	to	the	financial	statements.	Entergy	Arkansas	also	uses	the	net	debt	to	net	capital ratio	excluding	securitization	bonds	in	analyzing	its	financial	condition	and	believes	it	provides	useful	information	to	its	investors	and	creditors	in evaluating	Entergy	Arkansas's	financial	condition	because	net	debt	indicates	Entergy	Arkansas's	outstanding	debt	position	that	could	not	be readily	satisfied	by	cash	and	cash	equivalents	on	hand.

# Uses	of	Capital

Entergy	Arkansas	requires	capital	resources	for:

•construction	and	other	capital	investments;

•debt	and	preferred	stock	maturities	or	retirements;

•working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;	and •dividend	and	interest	payments.

Following	are	the	amounts	of	Entergy	Arkansas's	planned	construction	and	other	capital	investments.

| Generation | $145 | $220 | $300 |
| :--- | :--- | :--- | :--- |
| Transmission | 130 | 190 | 145 |
| Distribution | 160 | 155 | 150 |
| Other | 25 | 20 | 15 |
| Total | $460 | $585 | $610 |

Following	are	the	amounts	of	Entergy	Arkansas's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | after	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $157 | $469 | $385 | $2,959 | $3,970 |
| Capital\tlease\tpayments | $0.2 | $0.2 | $— | $— | $0.4 |
| Operating\tleases | $32 | $51 | $18 | $4 | $105 |
| Purchase\tobligations\t(b) | $756 | $963 | $610 | $1,771 | $4,100 |

(b) 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	financial	statements.

In	addition,	Entergy	Arkansas	currently	expects	to	contribute	approximately	$93.6	million	to	its	pension	plans	and	approximately	$25.6 million	to	other	postretirement	plans	in	2014	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January 1,	2014	valuations	are	completed	by	April	1,	2014.		See	"Critical	Accounting	Estimates	–	Qualified	Pension	and	Other	Postretirement Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also	in	addition	to	the	contractual	obligations,	Entergy	Arkansas	has	$2.0	million	of	unrecognized	tax	benefits	and	interest	net	of	unused tax	attributes	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably

estimated	due	 to	uncertainties	 in	 the	 timing	of	effective	settlement	of tax	positions. 	See	Note	3 to the	financial	statements	for	additional information	regarding	unrecognized	tax	benefits.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	Arkansas	includes specific	investments	and	initiatives	such	as	NRC	post-Fukushima	requirements	and	transmission	spending	to	support	economic	development projects,	reliability,	and	new	compliance	projects.	 	Entergy's	Utility	supply	plan	 initiative	will	continue	 to	seek	 to	 transform	 its	generation portfolio	with	new	or	repowered	generation	resources.		Opportunities	resulting	from	the	supply	plan	initiative,	including	new	projects	or	the exploration	of	alternative	financing	sources,	could	result	in	increases	or	decreases	in	the	capital	expenditure	estimates	given	above.		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,	changes	in	project	plans,	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	financial	statements.

As	a	wholly-owned	subsidiary,	Entergy	Arkansas	pays	dividends	to	Entergy	Corporation	from	its	earnings	at	a	percentage	determined monthly.		Entergy	Arkansas's	long-term	debt	indenture	restricts	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,	2013,	Entergy	Arkansas	had	restricted	retained	earnings	unavailable for	distribution	to	Entergy	Corporation	of	$394.9	million.

Entergy	Arkansas's	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	may	refinance,	redeem,	or	otherwise	retire	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	Entergy	Arkansas's	corporate	charters,	bond	indentures,	and	other	agreements.		Entergy Arkansas	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital	needs.

Entergy	Arkansas's	receivables	from	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years.

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $17,531 | $8,035 | $17,362 | $41,463 |

See	Note	4	to	the	financial	statements	for	a	description	of	the	money	pool.

Entergy	Arkansas	has	credit	facilities	in	the	amount	of	$20	million	and	$150	million	scheduled	to	expire	in	April	2014	and	March	2018, respectively.		The	$150	million	credit	facility	allows	Entergy	Arkansas	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the facility.	As	of	December	31,	2013,	there	were	no	cash	borrowings	and	$0.2	million	of	letters	of	credit	outstanding	under	the	credit	facilities.		See Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit	facilities.

The	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	$85	million	scheduled	to	expire in	June	2016.		As	of	December	31,	2013,	there	were	no	borrowings	outstanding	on	the	credit	facility.		See	Note	4	to	the	financial	statements	for additional	discussion	of	the	nuclear	fuel	company	variable	interest	entity	credit	facility.

Entergy	Arkansas	has	obtained	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow	through	October	2015,	up to	the	aggregate	amount,	at	any	one	time	outstanding,	of	$250	million.		See	Note	4	to	the	financial	statements	for	further	discussion	of	Entergy Arkansas's	short-term	borrowing	limits.		Entergy	Arkansas	has	also	obtained	an	order	from	the	APSC	authorizing	long-term	securities	issuances through	December	2015.		Entergy	Arkansas	has	also	obtained	long-term	financing	authorization	from	the	FERC	that	extends	through	October 2015	for	issuances	by	its	nuclear	fuel	company	variable	interest	entity.

In	January	2013,	Entergy	Arkansas	arranged	for	the	issuance	by	(i)	Independence	County,	Arkansas	of	$45	million	of	2.375%	Pollution Control	Revenue	Refunding	Bonds	(Entergy	Arkansas,	Inc.	Project)	Series	2013	due	January	2021,	and	(ii)	Jefferson	County,	Arkansas	of	$54.7 million	of	1.55%	Pollution	Control	Revenue	Refunding	Bonds	(Entergy	Arkansas,	Inc.	Project)	Series	2013	due	October	2017,	each	of	which series	is	secured	by	a	separate	series	of	non-interest	bearing	first	mortgage	bonds	of	Entergy	Arkansas.		The	proceeds	of	these	issuances	were applied	to	the	refunding	of	outstanding	series	of	pollution	control	revenue	bonds	previously	issued	by	the	respective	issuers.

In	May	2013,	Entergy	Arkansas	issued	$250	million	of	3.05%	Series	first	mortgage	bonds	due	June	2023.	Entergy	Arkansas	used	the proceeds	to	pay,	at	maturity,	a	portion	of	its	$300	million	of	5.40%	Series	first	mortgage	bonds	due	August	2013	and	for	general	corporate purposes.

In	June	2013,	Entergy	Arkansas	issued	$125	million	of	4.75%	Series	first	mortgage	bonds	due	June	2063.	Entergy	Arkansas	used	the proceeds	to	pay,	at	maturity,	a	portion	of	its	$300	million	of	5.40%	Series	first	mortgage	bonds	due	August	2013	and	for	general	corporate purposes.

In	June	2013	the	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	redeemed,	at	maturity,	its	$30	million	of	9%	Series	H notes.

In	July	2013,	Entergy	Arkansas	entered	into	a	$250	million	term	loan	credit	facility	terminating	January	26,	2015	with	the	collateral support	of	a	series	of	$255	million	non-interest	bearing	Entergy	Arkansas	first	mortgage	bonds.	On	July	31,	2013,	Entergy	Arkansas	borrowed $250	million	against	the	credit	facility.	Entergy	Arkansas	used	the	borrowings	to	pay,	at	maturity,	a	portion	of	its	$300	million	of	5.40%	Series first	mortgage	bonds	due	August	2013	and	for	general	corporate	purposes.

In	March	2013,	Entergy	Arkansas	filed	with	the	APSC	for	a	general	change	in	rates,	charges,	and	tariffs.	The	filing	assumed	Entergy Arkansas's	transition	to	MISO	in	December	2013,	and	requested	a	rate	increase	of	$174	million,	including	$49	million	of	revenue	being	transferred from	collection	in	riders	to	base	rates.	The	filing	also	proposed	a	new	transmission	rider	and	a	capacity	cost	recovery	rider.	The	filing	requested	a 10.4%	 return	 on	 common	 equity.	In	September	2013,	Entergy	Arkansas	filed	testimony	reflecting	an	updated	rate	increase	request	of	$145 million,	with	no	change	to	its	requested	return	on	common	equity	of	10.4%.	Hearings	in	the	proceeding	began	in	October	2013,	and	in	December 2013	the	APSC	issued	an	order.	The	order	authorizes	a	base	rate	increase	of	$81	million	and	includes	an	authorized	return	on	common	equity	of 9.3%.	The	order	allows	Entergy	Arkansas	to	amortize	its	human	capital	management	costs	over	a	three-and-a-half	year	period,	but	also	orders Entergy	Arkansas	to	file	a	detailed	report	of	the	Arkansas-specific	costs,	savings	and	final	payroll	changes	upon	conclusion	of	the	human	capital management	initiative.

The	substance	of	the	report	will	be	addressed	in	Entergy	Arkansas's	next	base	rate	filing.	New	rates	will	be	implemented	in	the	first	billing	cycle of	March	2014	and	are	effective	as	of	January	2014.	Additionally,	in	January	2014,	Entergy	Arkansas	filed	a	petition	for	rehearing	or	clarification of	several	aspects	of	the	APSC's	order,	including	the	9.3%	authorized	return	on	common	equity.	 In	February	2014	the	APSC	granted	Entergy Arkansas's	petition	for	the	purpose	of	further	consideration.

The	APSC	approved	a	production	cost	allocation	rider	for	recovery	from	customers	of	the	retail	portion	of	the	costs	allocated	to	Entergy Arkansas	as	a	result	of	the	System	Agreement	proceedings.		These	costs	cause	an	increase	in	Entergy	Arkansas's	deferred	fuel	cost	balance because	Entergy	Arkansas	pays	the	costs	over	seven	months	but	collects	them	from	customers	over	twelve	months.	See	Note	2	to	the	financial statements	 and	 Entergy	 Corporation	 and	 Subsidiaries "MANAGEMENT'S	 FINANCIAL	 DISCUSSION	 AND	 ANALYSIS - System Agreement"	for	discussions	of	the	System	Agreement	proceedings.

In	January	2007	the	APSC	issued	an	order	in	its	review	of	the	energy	cost	rate.		The	APSC	found	that	Entergy	Arkansas	failed	to	maintain an	adequate	coal	inventory	level	going	into	the	summer	of	2005	and	that	Entergy	Arkansas	should	be	responsible	for	any	incremental	energy	costs that	resulted	from	two	outages	caused	by	employee	and	contractor	error.		The	coal	plant	generation	curtailments	were	caused	by	railroad	delivery problems	and	Entergy	Arkansas	has	since	resolved	litigation	with	the	railroad	regarding	the	delivery	problems.		The	APSC	staff	was	directed	to perform	an	analysis	with	Entergy	Arkansas's	assistance	to	determine	the	additional	fuel	and	purchased	energy	costs	associated	with	these	findings and	file	the	analysis	within	sixty	days	of	the	order.		After	a	final	determination	of	the	costs	is	made	by	the	APSC,	Entergy	Arkansas	will	be directed	to	refund	that	amount	with	interest	to	its	customers	as	a	credit	on	the	energy	cost	recovery	rider.		Entergy	Arkansas	requested	rehearing	of the	order.		In	February	2010	the	APSC	denied	Entergy	Arkansas's	request	for	rehearing,	and	held	a	hearing	in	September	2010	to	determine	the amount	of	damages,	if	any,	that	should	be	assessed	against	Entergy	Arkansas.		A	decision	is	pending.		Entergy	Arkansas	expects	the	amount	of damages,	if	any,	to	have	an	immaterial	effect	on	its	results	of	operations,	financial	position,	or	cash	flows.

In	January	2014,	Entergy	Arkansas	filed	a	motion	with	the	APSC	relating	to	its	upcoming	March	2014	calculation	of	its	revised	energy cost	rate.	In	that	motion,	Entergy	Arkansas	requested	that	the	APSC	authorize	Entergy	Arkansas	to	exclude	$65.9	million	of	deferred	fuel	and purchased	energy	costs	 incurred	 in	2013	from	 the	calculation	of	 its	2014	revised	energy	cost	rate.	The	$65.9	million	 is	an	estimate	of	 the incremental	fuel	and	replacement	energy

costs	 that	 Entergy	Arkansas	 incurred	 as	 a	 result	 of	 the	ANO	 stator	 incident.	Entergy	Arkansas	requested	 that	 the	APSC	authorize	Entergy Arkansas	to	retain	that	amount	in	its	deferred	fuel	balance,	with	recovery	to	be	reviewed	in	a	later	period	after	more	information	is	available regarding	various	claims	associated	with	the	ANO	stator	incident.	The	APSC	approved	Entergy	Arkansas's	request	in	February	2014.	See	the "ANO	Damage	and	Outage"	section	above	for	further	discussion	of	the	ANO	stator	incident.

# Opportunity	Sales	Proceeding

The	FERC	 issued	a	decision	 in	June	2012	and	held	 that,	while	 the	System	Agreement is	ambiguous, it	does	provide	authority	for individual	Utility	operating	companies	to	make	opportunity	sales	for	their	own	account	and

Entergy	Arkansas	made	and	priced	these	sales	in	good	faith.		The	FERC	found,	however,	that	the	System	Agreement	does	not	provide	authority for	an	individual	Utility	operating	company	to	allocate	the	energy	associated	with	such	opportunity	sales	as	part	of	its	load,	but	provides	a	different allocation	authority.		The	FERC	further	found	that	the	after-the-fact	accounting	methodology	used	to	allocate	the	energy	used	to	supply	the	sales was	inconsistent	with	the	System	Agreement.		Quantifying	the	effect	of	the	FERC's	decision	will	require	re-running	intra-system	bills	for	a	ten- year	period,	and	the	FERC	in	its	decision	established	further	hearing	procedures	to	determine	the	calculation	of	the	effects.		In	July	2012,	Entergy and	the	LPSC	filed	requests	for	rehearing	of	the	FERC's	June	2012	decision,	which	are	pending	with	the	FERC.

See	"Entergy's	Integration	Into	the	MISO	Regional	Transmission	Organization",	"System	Agreement",	and	"U.S.	Department	of	Justice Investigation"	in	the	"Rate,	Cost-recovery,	and	Other	Regulation	–	Federal	Regulation"	section	of	Entergy	Corporation	and	Subsidiaries Management's	Financial	Discussion	and	Analysis	for	a	discussion	of	these	topics.

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,	regulatory	requirement	changes,	including	changes	resulting	from	events	at	other	plants,	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.

The	nuclear	industry	continues	to	address	susceptibility	to	stress	corrosion	cracking	of	certain	materials	within	the	reactor	coolant	system. The	 issue	 is	 applicable	 to	ANO	 and	 is	 managed	 in	 accordance	 with	 industry	 standard	 practices	 and	 guidelines	 which	 include	 in-service examinations,	replacements,	and	mitigation	strategies.		Developments	in	the	industry	or	identification	of	issues	at	the	nuclear	units	could	require unanticipated	remediation	efforts	that	cannot	be	quantified	in	advance.

# Environmental	Risks

Entergy	Arkansas'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	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'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	Arkansas's	financial	position	or results	of	operations.

See	 "Nuclear	 Decommissioning	 Costs" in	 the	 "Critical	Accounting	 Estimates"	 section	 of	 Entergy	 Corporation	 and	 Subsidiaries Management's	Financial	Discussion	and	Analysis	for	discussion	of	the	estimates	inherent	in	accounting	for	nuclear	decommissioning	costs.

As	discussed	in	Note	1	to	the	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.

Entergy	sponsors	qualified,	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	 and	 meet	 certain eligibility	requirements	while	still	working	for	Entergy.		Entergy's	reported	costs	of	providing	these	benefits,	as	described	in	Note	11	to	the financial	statements,	are	impacted	by	numerous	factors	including	the	provisions	of	the	plans,	changing	employee	demographics,	and	various actuarial	calculations,	assumptions,	and	accounting	mechanisms.	 	See the	"Qualified	 Pension	 and	 Other	 Postretirement	 Benefits" in	 the "Critical	Accounting	Estimates"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	further discussion.		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	qualified	pension	cost	and	qualified	projected	benefit	obligation	to	changes	in	certain actuarial	assumptions	(dollars	in	thousands).

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Qualified	Pension	Cost | Impact	on	2013<br>Qualified	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $3,773 | $37,642 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,967 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $1,507 | $5,908 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $665 | $7,768 |
| Health\tcare\tcost\ttrend | 0.25% | $1,239 | $6,541 |

Total	qualified	pension	cost	for	Entergy	Arkansas	in	2013	was	$69	million,	including	a	$4.9	million	curtailment	charge	and	a	$1.8	million special	 termination	 charge	 related	 to	 workforce	 downsizing. Entergy	 Arkansas	 anticipates	 2014	 qualified	 pension	 cost	 to	 be	$42.4 million.		Entergy	Arkansas	contributed	$35.4	million	to	its	pension	plan	in	2013	and	estimates	2014	pension	contributions	to	be	approximately $93.6	million;	although	 the	required	pension	contributions	will	not	be	known	with	more	certainty	until	 the	January	1,	2014	valuations	are completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Arkansas	in	2013	were	$18.1	million,	including	a	$4.5	million curtailment	charge	related	to	workforce	downsizing.		Entergy	Arkansas	expects	2014	postretirement	health	care	and	life	insurance	benefit	income to	approximate	$2.1	million.	 	Entergy	Arkansas	contributed	$21	million	to	its	other	postretirement	plans	in	2013	and	expects	to	contribute approximately	$25.6	million	in	2014.

See the	 "Qualified	 Pension	 and	 Other	 Postretirement	 Benefits -	 Federal	 Healthcare	 Legislation" in the	 "Critical	 Accounting Estimates"	 section	 of	 Entergy	 Corporation	 and	 Subsidiaries	 Management's	 Financial	 Discussion	 and	Analysis for	 a	 discussion	 of	 Federal Healthcare	Legislation.

See	"New	Accounting	Pronouncements"	 section	 of	 Entergy	 Corporation	 and	 Subsidiaries	 Management's	 Financial	 Discussion	 and Analysis	for	further	discussion.

# Little	Rock,	Arkansas

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Arkansas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31, 2013	and	2012,	and	the	related	consolidated	income	statements,	consolidated	statements	of	cash	flows,	and	consolidated	statements	of	changes	in common	equity	(pages	298	through	302	and	applicable	items	in	pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December 31,	2013.	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	consolidated	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Arkansas,	Inc.	and Subsidiaries	as	of	December	31,	2013	and	2012,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period ended	December	31,	2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

We	have	also	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	the	Company's internal	control	over	financial	reporting	as	of	December	31,	2013,	based	on	the	criteria	established	in	Internal	Control	-	Integrated	Framework (1992)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	and	our	report	dated	February	27,	2014	expressed	an unqualified	opinion	on	the	Company's	internal	control	over	financial	reporting.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $2,190,159 | $2,127,004 | $2,084,310 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 426,316 | 480,464 | 186,036 |
| Purchased\tpower | 473,326 | 431,932 | 659,464 |
| Nuclear\trefueling\toutage\texpenses | 40,499 | 47,103 | 42,557 |
| Other\toperation\tand\tmaintenance | 592,892 | 545,782 | 511,592 |
| Decommissioning | 43,058 | 40,484 | 38,064 |
| Taxes\tother\tthan\tincome\ttaxes | 89,471 | 89,527 | 82,847 |
| Depreciation\tand\tamortization | 230,512 | 222,734 | 218,902 |
| Other\tregulatory\tcredits\t-\tnet | (10,975) | (38,406) | (13,506) |
| TOTAL | 1,885,099 | 1,819,620 | 1,725,956 |
| OPERATING\tINCOME | 305,060 | 307,384 | 358,354 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 10,913 | 9,070 | 7,660 |
| Interest\tand\tinvestment\tincome | 30,148 | 15,169 | 16,533 |
| Miscellaneous\t-\tnet | (4,275) | (4,049) | (4,172) |
| TOTAL | 36,786 | 20,190 | 20,021 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 91,318 | 82,860 | 83,545 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (3,207) | (2,457) | (2,826) |
| TOTAL | 88,111 | 80,403 | 80,719 |
| INCOME\tBEFORE\tINCOME\tTAXES | 253,735 | 247,171 | 297,656 |
| Income\ttaxes | 91,787 | 94,806 | 132,765 |
| NET\tINCOME | 161,948 | 152,365 | 164,891 |
| Preferred\tdividend\trequirements | 6,873 | 6,873 | 6,873 |
| EARNINGS\tAPPLICABLE\tTO |  |  |  |
| COMMON\tSTOCK | $155,075 | $145,492 | $158,018 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $161,948 | $152,365 | $164,891 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 357,639 | 357,913 | 339,819 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 130,707 | (67,482) | 94,410 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (26,320) | (30,786) | (11,021) |
| Fuel\tinventory | 7,471 | (68) | (11,190) |
| Accounts\tpayable | 141,041 | (179,009) | 160,983 |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (204,990) | 178,688 | 122,974 |
| Interest\taccrued | (6,382) | (1,463) | 2,861 |
| Deferred\tfuel\tcosts | 28,609 | 112,471 | (148,274) |
| Other\tworking\tcapital\taccounts | (34,909) | 55,735 | (3,855) |
| Provisions\tfor\testimated\tlosses | (76) | 182 | (2,330) |
| Other\tregulatory\tassets | 214,131 | (88,119) | (215,841) |
| Pension\tand\tother\tpostretirement\tliabilities | (295,435) | 75,725 | 123,156 |
| Other\tassets\tand\tliabilities | (72,184) | (57,035) | (52,459) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 401,250 | 509,117 | 564,124 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (489,079) | (361,858) | (382,776) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 14,550 | 12,441 | 9,607 |
| Nuclear\tfuel\tpurchases | (88,637) | (215,968) | (148,657) |
| Proceeds\tfrom\tsale\tof\tnuclear\tfuel | 36,478 | 96,700 | — |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 266,391 | 144,275 | 125,408 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (274,519) | (154,608) | (140,724) |
| Payment\tfor\tpurchase\tof\tplant | — | (253,043) | — |
| Change\tin\tmoney\tpool\treceivable\t-\tnet |  |  |  |
|  | (9,496) | 9,327 | 24,101 |
| Investment\tin\taffiliates | — | — | 10,994 |
| Changes\tin\tsecuritization\taccount | 568 | (514) | (1,477) |
| Litigation\tproceeds\tfor\treimbursement\tof\tspent\tnuclear\tfuel\tstorage\tcosts | 10,271 | — | — |
| Counterparty\tcollateral\tdeposit | 9,000 | — | — |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (524,473) | (723,248) | (503,524) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 716,595 | 252,347 | 54,743 |
| Retirement\tof\tlong-term\tdebt | (442,302) | (12,230) | (45,310) |
| Changes\tin\tshort-term\tborrowings\t-\tnet | (36,735) | 2,821 | (28,863) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (15,000) | (10,000) | (117,800) |
| Preferred\tstock | (6,873) | (6,873) | (6,873) |
| Other | 27 | — | — |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | 215,712 | 226,065 | (144,103) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 92,489 | 11,934 | (83,503) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 34,533 | 22,599 | 106,102 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $127,022 | $34,533 | $22,599 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $92,353 | $79,271 | $75,650 |
| Income\ttaxes | $184,592 | ($20,480) | ($89,994) |

| Cash | $4,181 | $9,597 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 122,841 | 24,936 |
| Total\tcash\tand\tcash\tequivalents | 127,022 | 34,533 |
| Securitization\trecovery\ttrust\taccount | 3,835 | 4,403 |
| Accounts\treceivable: |  |  |
| Customer | 102,328 | 98,036 |
| Allowance\tfor\tdoubtful\taccounts | (30,113) | (28,343) |
| Associated\tcompanies | 68,875 | 67,277 |
| Other | 94,256 | 71,956 |
| Accrued\tunbilled\trevenues | 82,298 | 72,902 |
| Total\taccounts\treceivable | 317,644 | 281,828 |
| Accumulated\tdeferred\tincome\ttaxes | 33,556 | 72,196 |
| Deferred\tfuel\tcosts | 68,696 | 97,305 |
| Fuel\tinventory\t-\tat\taverage\tcost | 41,504 | 48,975 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 152,429 | 148,682 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 31,135 | 38,410 |
| System\tagreement\tcost\tequalization | 30,000 | — |
| Prepayments\tand\tother | 58,911 | 10,586 |
| TOTAL | 864,732 | 736,918 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 710,913 | 600,578 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 1,664 | 1,671 |
| Other | 29,181 | 41,182 |
| TOTAL | 741,758 | 643,431 |
| UTILITY\tPLANT |  |  |
| Electric | 8,798,458 | 8,693,659 |
| Property\tunder\tcapital\tlease | 1,064 | 1,154 |
| Construction\twork\tin\tprogress | 209,036 | 205,982 |
| Nuclear\tfuel | 321,901 | 303,825 |
|  | 9,330,459 | 9,204,620 |
| TOTAL\tUTILITY\tPLANT |  |  |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 4,034,880 | 4,104,882 |
| UTILITY\tPLANT\t-\tNET | 5,295,579 | 5,099,738 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 73,864 | 80,751 |
| \t\tOther\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof |  |  |
| \t\t\t\t\t\t\t$80,963\tas\tof\tDecember\t31,\t2013\tand\t$93,238\tas\tof |  |  |
| December\t31,\t2012) | 1,014,392 | 1,221,636 |
| Other | 44,565 | 36,971 |
| TOTAL | 1,132,821 | 1,339,358 |
| TOTAL\tASSETS | $8,034,890 | $7,819,445 |

| Currently	maturing	long-term	debt | $70,000 | $330,000 |
| :--- | :--- | :--- |
| Short-term\tborrowings | — | 36,735 |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 149,802 | 39,288 |
| Other | 228,160 | 200,964 |
| Customer\tdeposits | 86,512 | 85,198 |
| Taxes\taccrued | 9,979 | 214,969 |
| Accumulated\tdeferred\tincome\ttaxes | 9,231 | 5,927 |
| Interest\taccrued | 22,036 | 28,418 |
| Other | 55,656 | 45,208 |
| TOTAL | 631,376 | 986,707 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,906,562 | 1,829,281 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 38,958 | 40,947 |
| Other\tregulatory\tliabilities | 219,370 | 143,901 |
| Decommissioning | 723,771 | 680,712 |
| Accumulated\tprovisions | 5,746 | 5,822 |
| Pension\tand\tother\tpostretirement\tliabilities | 319,211 | 614,805 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$88,961\tas\tof |  |  |
| December\t31,\t2013\tand\t$101,547\tas\tof\tDecember\t31,\t2012) | 2,335,802 | 1,793,895 |
| Other | 18,026 | 27,409 |
| TOTAL | 5,567,446 | 5,136,772 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 116,350 | 116,350 |
| COMMON\tEQUITY |  |  |
| Common\tstock,\t$0.01\tpar\tvalue,\tauthorized\t325,000,000 |  |  |
| shares;\tissued\tand\toutstanding\t46,980,196\tshares\tin\t2013 |  |  |
| and\t2012 | 470 | 470 |
| Paid-in\tcapital | 588,471 | 588,444 |
| Retained\tearnings | 1,130,777 | 990,702 |
| TOTAL | 1,719,718 | 1,579,616 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $8,034,890 | $7,819,445 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	COMMON	EQUITY

|  | Common	Stock | Paid-in	Capital | Retained	Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Balance\tat\tDecember\t31,\t2010 | $470 | $588,444 | $814,992 | $1,403,906 |
| Net\tincome | — | — | 164,891 | 164,891 |
| Common\tstock\tdividends | — | — | (117,800) | (117,800) |
| Preferred\tstock\tdividends | — | — | (6,873) | (6,873) |
| Balance\tat\tDecember\t31,\t2011 | $470 | $588,444 | $855,210 | $1,444,124 |
| Net\tincome | — | — | 152,365 | 152,365 |
| Common\tstock\tdividends | — | — | (10,000) | (10,000) |
| Preferred\tstock\tdividends | — | — | (6,873) | (6,873) |
| Balance\tat\tDecember\t31,\t2012 | $470 | $588,444 | $990,702 | $1,579,616 |
| Net\tincome | — | — | 161,948 | 161,948 |
| Common\tstock\tdividends | — | — | (15,000) | (15,000) |
| Preferred\tstock\tdividends | — | — | (6,873) | (6,873) |
| Other | — | 27 | — | 27 |
| Balance\tat\tDecember\t31,\t2013 | $470 | $588,471 | $1,130,777 | $1,719,718 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,190,159 | $2,127,004 | $2,084,310 | $2,082,447 | $2,211,263 |
| Net\tincome | $161,948 | $152,365 | $164,891 | $172,618 | $66,875 |
| Total\tassets | $8,034,890 | $7,819,445 | $7,212,212 | $6,751,368 | $6,492,802 |
| Long-term\tobligations\t(a) | $2,452,152 | $1,910,245 | $1,992,271 | $1,946,494 | $1,736,520 |

(a)	Includes	long-term	debt	(excluding	currently	maturing	debt)	and	preferred	stock	without	sinking	fund.

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $772 | $766 | $756 | $773 | $769 |
| Commercial | 469 | 472 | 450 | 441 | 475 |
| Industrial | 433 | 439 | 421 | 415 | 433 |
| Governmental | 19 | 20 | 20 | 20 | 21 |
| Total\tretail | 1,693 | 1,697 | 1,647 | 1,649 | 1,698 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 346 | 320 | 279 | 302 | 350 |
| Non-associated\tcompanies | 83 | 49 | 96 | 78 | 102 |
| Other | 68 | 61 | 62 | 53 | 61 |
| Total | $2,190 | $2,127 | $2,084 | $2,082 | $2,211 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 7,921 | 7,859 | 8,229 | 8,501 | 7,464 |
| Commercial | 5,929 | 6,046 | 6,051 | 6,144 | 5,817 |
| Industrial | 6,769 | 6,925 | 7,029 | 7,082 | 6,376 |
| Governmental | 241 | 257 | 275 | 277 | 269 |
| Total\tretail | 20,860 | 21,087 | 21,584 | 22,004 | 19,926 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 7,918 | 7,926 | 6,893 | 7,853 | 9,980 |
| Non-associated\tcompanies | 1,011 | 1,093 | 1,304 | 850 | 1,631 |
| Total | 29,789 | 30,106 | 29,781 | 30,707 | 31,537 |

# ENTERGY	GULF	STATES	LOUISIANA,	L.L.C.

Net	 income	 increased	 $2.7	 million	 primarily	 due	 to	 higher	 net	 revenue	 and	 higher	 other	 income.	The	 increase	 in	 net	 income	 was substantially	offset	by	higher	other	operation	and	maintenance	expenses,	higher	depreciation	and	amortization	expenses,	higher	taxes	other	than income	taxes,	and	a	higher	effective	income	tax	rate	partially	due	to	the	prior	year	tax	settlement	discussed	below.

Net	income	decreased	$42.6	million	primarily	due	to	lower	net	revenue	and	higher	other	operation	and	maintenance	expenses.	These items	were	partially	offset	by	the	$19.8	million	income	tax	savings	resulting	from	an	IRS	settlement	in	June	2012	related	to	the	uncertain	tax position	regarding	the	Hurricane	Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing,	which	also	resulted	in	a	$27.7	million	($17	million	net- of-tax)	regulatory	charge	that	reduced	net	revenue	because	Entergy	Gulf	States	Louisiana	agreed	to	share	the	savings	with	customers.	See	Note	3 to	the	financial	statements	for	additional	discussion	of	the	tax	settlement.

Net	revenue	consists	of	operating	revenues	net	of:	1)	fuel,	fuel-related	expenses,	and	gas	purchased	for	resale,	2)	purchased	power expenses,	and	3)	other	regulatory	charges.	Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2013	to	2012.

|  | Amount |
| :--- | :--- |
|  | (In\tMillions) |
| 2012\tnet\trevenue | $865.9 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | 27.8 |
| Net\twholesale\trevenue | 8.3 |
| Volume/weather | 7.5 |
| Other | 3.9 |
| 2013\tnet\trevenue | $913.4 |

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	recorded	in	the	second	quarter	2012	because Entergy	Gulf	States	Louisiana	agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding the	Hurricane	Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax settlement.

The	net	wholesale	revenue	variance	is	primarily	due	to	higher	prices.

The	volume/weather	variance	is	primarily	due	to	an	increase	of	82	GWh,	or	0.4%,	in	billed	electricity	usage	as	a	result	of	the	effect	of more	favorable	weather,	as	compared	to	the	prior	period,	primarily	on	residential	sales.	The	increase	was	also	driven	by	higher	industrial	usage primarily	in	the	chemicals	industry.

# Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	charges

•an	increase	of	$173.6	million	in	electric	fuel	cost	recovery	revenues	primarily	due	to	higher	fuel	rates; •an	increase	of	$69.6	million	in	rider	revenues	primarily	due	to	System	Agreement	credits	to	customers	in	2012; •an	increase	of	$10	million	in	gross	wholesale	revenues	primarily	due	to	higher	prices;	and •an	increase	of	$7.6	million	in	gas	fuel	cost	recovery	revenues	primarily	due	to	higher	fuel	rates.

See	Note	2	to	the	financial	statements	for	additional	discussion	of	Entergy	Gulf	States	Louisiana's	fuel	and	purchased	power	recovery	mechanism.

Fuel	and	purchased	power	expenses	increased	primarily	due	to:

•an	increase	in	the	average	market	price	of	purchased	power	and	increased	demand;	and

•an	increase	in	deferred	fuel	expense	due	to	the	timing	of	receipt	of	System	Agreement	payments	and	credits	to	customers	and	higher	fuel cost	recovery	revenues	due	to	higher	fuel	rates	as	compared	to	the	prior	year.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the System	Agreement	proceedings.

Other	regulatory	charges	decreased	primarily	due	to	a	regulatory	charge	recorded	in	the	second	quarter	2012	because	Entergy	Gulf	States Louisiana	agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane	Katrina and	Hurricane	Rita	Louisiana	Act	55	financing.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax	settlement.

Net	revenue	consists	of	operating	revenues	net	of:	1)	fuel,	fuel-related	expenses,	and	gas	purchased	for	resale,	2)	purchased	power expenses,	and	3)	other	regulatory	charges	(credits).	Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2012	to	2011.

| 2011	net	revenue | $933.4 |
| :--- | :--- |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | (26.7) |
| Retail\telectric\tprice | (12.0) |
| Volume/weather | (7.9) |
| Net\twholesale\trevenue | (7.8) |
| Transmission\trevenue | (7.2) |
| Other | (5.9) |
| 2012\tnet\trevenue | $865.9 |

The	 Louisiana	Act	 55	 financing	 savings	 obligation	 results	 from	 a	 regulatory	 charge	 recorded	 in	 2012	 because	 Entergy	 Gulf	 States Louisiana	agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane	Katrina and	 Hurricane	 Rita	 Louisiana	Act	 55	 financing	 with	 customers.	See	Note	3	 to	 the	financial	statements	for	additional	discussion	of	 the	 tax settlement.

The	retail	electric	price	variance	is	primarily	due	to	increased	affiliate	purchased	power	capacity	costs	recovered	through	base	rates	set	in the	annual	formula	rate	plan	mechanism.	See	Note	2	to	the	financial	statements	for	additional	discussion	of	Entergy	Gulf	States	Louisiana's formula	rate	plan.

The	 volume/weather	 variance	 is	 primarily	 due	 to	 the	 effect	 of	 milder	 weather,	 as	 compared to the	 prior	 period,	 on	 residential	 and commercial	sales	and	the	effects	of	the	power	outages	caused	by	Hurricane	Isaac.

The	 transmission	revenue	variance	 is	primarily	due	 to	a	revision	 to	 transmission	 investment	equalization	billings	under	 the	System Agreement	among	the	Utility	operating	companies	(for	the	approximate	period	of	1996	-	2011)	recorded	in	the	fourth	quarter	2011.	See	Note	2	to the	financial	statements	for	further	discussion	of	the	revision.

# Gross	operating	revenues,	fuel	and	purchased	power	expenses,	and	other	regulatory	charges	(credits)

Gross	operating	revenues	decreased	primarily	due	to	a	decrease	of	$203.8	million	in	gross	wholesale	revenues	primarily	due	to	a	decrease in	sales	to	affiliated	customers,	a	decrease	of	$168.4	million	in	fuel	cost	recovery	revenues	primarily	due	to	lower	fuel	rates,	and	a	decrease	of $59.3	million	in	rider	revenues	primarily	due	to	higher	System	Agreement	credits	in	2012.	See	Note	2	to	the	financial	statements	for	additional discussion	of	Entergy	Gulf	States	Louisiana's	fuel	and	purchased	power	recovery	mechanism.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to:

•a	decrease	in	the	average	market	prices	of	purchased	power	and	natural	gas;	and

•a	decrease	in	deferred	fuel	expense	due	to	the	timing	of	receipt	of	System	Agreement	payments	and	credits	to	customers	and	lower	fuel cost	recovery	revenues	in	2012.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the	System	Agreement	proceedings.

Other	regulatory	charges	increased	primarily	due	to	a	settlement	with	the	IRS	related	to	the	uncertain	tax	position	regarding	the	Hurricane Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing	because	Entergy	Gulf	States	Louisiana	agreed	to	share	the	savings	with	customers.	See Note	3	to	the	financial	statements	for	additional	discussion	of	the	settlement.

•the	deferral	recorded	in	the	second	quarter	2012,	as	approved	by	the	LPSC	and	the	FERC,	of	costs	related	to	the	transition	and implementation	of	joining	the	MISO	RTO,	which	reduced	expenses	by	$4.2	million	in	2012;

•an	increase	of	$13.5	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative,	partially	offset	by	the	deferral,	as	approved	by	the	LPSC,	of	$9.8	million	of these	costs.	See	the	"Human	Capital	Management	Strategic	Imperative"	section	of	Entergy	Corporation	and	Subsidiaries Management's	Financial	Discussion	and	Analysis	for	further	discussion;

•an	increase	of	$3.5	million	in	fossil-fueled	generation	expenses	due	to	an	overall	higher	scope	of	work	done	during	plant	outages	as compared	to	the	prior	year;

•an	increase	of	$2.9	million	in	loss	reserves;	and

•several	individually	insignificant	items.

Taxes	other	 than	 income	 taxes	 increased	primarily	due	 to	an	 increase	 in	 local	franchise	 taxes	resulting	from	higher	residential	and commercial	revenues	as	compared	to	prior	year	and	an	increase	in	ad	valorem	taxes	resulting	from	higher	assessments.	Franchise	taxes	have	no effect	on	net	income	as	these	taxes	are	recovered	through	the	franchise	tax	rider.

Depreciation	and	amortization	expenses	increased	primarily	due	to	increased	plant	in	service.

Other	income	increased	primarily	due	to	higher	realized	gains	in	2013	on	the	River	Bend	decommissioning	trust	fund	investments.	There is	no	effect	on	net	income	as	these	investment	gains	are	offset	by	a	corresponding	amount	of	regulatory	charges.

•an	increase	of	$10.4	million	in	nuclear	generation	expenses	primarily	due	to	higher	labor	costs,	including	higher	contract	labor; •an	increase	of	$9.3	million	in	compensation	and	benefits	costs	primarily	due	to	decreasing	discount	rates	and	changes	in	certain	actuarial assumptions	resulting	from	an	experience	study.		See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for further	discussion	of	benefits	costs;

•$4.7	million	of	costs	incurred	in	2012	related	to	the	now	terminated	plan	to	spin	off	and	merge	the	transmission	business;	and •an	increase	of	$3.7	million	in	fossil-fueled	generation	expenses	resulting	primarily	from	more	plant	outages	and	an	increased	scope	of work	as	compared	to	the	prior	year.

•$5.8	million	of	transmission	investment	equalization	expenses	recorded	in	the	fourth	quarter	2011	as	a	result	of	a	billing	adjustment related	to	prior	transmissions	costs	(for	the	approximate	period	of	1996	–	2011)	allocable	to	Entergy	Gulf	States	Louisiana	under	the System	Agreement;

•the	deferral,	as	approved	by	the	LPSC	and	the	FERC,	of	costs	related	to	the	transition	and	implementation	of	joining	the	MISO	RTO,

which	reduced	expenses	by	$4.2	million;	and

The	effective	income	tax	rates	were	26%,	24.9%,	and	30.8%	for	2013,	2012,	and	2011,	respectively.	See	Note	3	to	the	financial	statements for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rates.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $35,686 | $24,845 | $155,173 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 434,726 | 346,208 | 482,115 |
| Investing\tactivities | (336,644) | (201,440) | (267,262) |
| Financing\tactivities | (118,187) | (133,927) | (345,181) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (20,105) | 10,841 | (130,328) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $15,581 | $35,686 | $24,845 |

Net	cash	flow	provided	by	operating	activities	increased	$88.5	million	in	2013	compared	to	2012	primarily	due	to:

•income	tax	payments	of	$5.1	million	in	2013	compared	to	income	tax	payments	of	$89.2	million	in	2012.	Entergy	Gulf	States	Louisiana had	income	tax	payments	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement.	In	2013,	the	payments	resulted	primarily	from	the	reversal	of	temporary	differences	for	which	Entergy	Gulf	States	Louisiana had	previously	claimed	a	tax	deduction.	In	2012,	Entergy	Gulf	States	Louisiana	no	longer	had	a	net	operating	loss	carryover	from	prior years	to	reduce	current	taxable	income;	and

•decreased	Hurricane	Isaac	storm	spending	in	2013.

The	increase	was	partially	offset	by	higher	nuclear	refueling	outage	spending	at	River	Bend.	River	Bend	had	a	refueling	outage	in	2013	and	did not	have	one	in	2012.

Net	cash	provided	by	operating	activities	decreased	$135.9	million	in	2012	compared	to	2011	primarily	due	to	income	tax	payments	in 2012	of	$89.2	million	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement compared	to	income	tax	refunds	of	$56.3	million	in	2011.	Also

contributing	to	the	decrease	in	cash	flow	was	Hurricane	Isaac	storm	restoration	spending	in	2012.	In	2011,	Entergy	Gulf	States	Louisiana	received tax	cash	refunds	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement.		The refunds	resulted	from	the	reversal	of	temporary	differences	for	which	Entergy	Gulf	States	Louisiana	previously	made	cash	tax	payments.

•an	increase	in	the	recovery	of	fuel	and	purchased	power	costs	due	to	System	Agreement	bandwidth	remedy	payments	of	$75	million received	in	January	2012	as	a	result	of	receipts	required	to	implement	the	FERC's	remedy	in	an	October	2011	order	for	the	period	June	- December	2005.	In	the	fourth	quarter	2012,	Entergy	Gulf	States	Louisiana	customers	were	credited	$69.6	million.	See	Note	2	to	the financial	statements	for	a	discussion	of	the	System	Agreement	proceedings;	and

•a	decrease	of	$13.7	million	in	pension	contributions.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements for	a	discussion	of	qualified	pension	and	other	postretirement	benefits.

Net	cash	flow	used	in	investing	activities	increased	$135.2	million	in	2013	compared	to	2012	primarily	due	to:

•fluctuations	in	nuclear	fuel	activity	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements	in	the Utility	business,	material	and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle; •$51	million	in	proceeds	in	2012	from	the	sale	of	a	portion	of	Entergy	Gulf	States	Louisiana's	investment	in	Entergy	Holdings	Company's Class	A	preferred	membership	interests	to	a	third	party.	See	Note	2	to	the	financial	statements	for	discussion	of	Entergy	Gulf	States Louisiana's	investment	in	Entergy	Holdings	Company's	Class	A	preferred	membership	interests;

•money	pool	activity;

•an	increase	in	nuclear	construction	expenditures	as	a	result	of	spending	on	nuclear	projects	during	the	River	Bend	refueling	outage	in 2013;	and

•an	increase	in	transmission	construction	expenditures	due	to	additional	reliability	work	performed	in	2013.

•the	withdrawal	of	$65.5	million	from	the	storm	reserve	escrow	account	in	2013;

•a	decrease	in	distribution	construction	expenditures	due	to	prior	year	Hurricane	Isaac	spending;	and

•a	decrease	in	fossil-fueled	generation	construction	expenditures	as	a	result	of	decreased	scope	of	work	in	2013.

Increases	in	Entergy	Gulf	States	Louisiana's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Gulf	States	Louisiana's receivable	from	the	money	pool	increased	by	$1.9	million	in	2013	compared	to	decreasing	by	$23.6	million	in	2012.	The	money	pool	is	an	inter- company	borrowing	arrangement	designed	to	reduce	the	Utility	operating	companies'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	decreased	$65.8	million	in	2012	compared	to	2011	primarily	due	to:

•fluctuations	in	nuclear	fuel	activity	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements	in	the Utility	business,	material	and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle; •$51	million	in	proceeds	from	the	sale	of	a	portion	of	Entergy	Gulf	States	Louisiana's	investment	in	Entergy	Holdings	Company's	Class	A preferred	membership	interests	to	a	third	party	in	2012;	see	Note	2	to	the	financial	statements	for	discussion	of	Entergy	Gulf	States Louisiana's	investment	in	Entergy	Holdings

# Company's	Class	A	preferred	membership	interests;	and

•a	decrease	in	nuclear	construction	expenditures	as	a	result	of	the	River	Bend	refueling	outage	in	2011.	River	Bend	had	a	refueling	outage in	2011	and	did	not	have	one	in	2012.

•higher	distribution	construction	expenditures	due	to	Hurricane	Isaac	and	increased	reliability	work	performed	in	2012; •money	pool	activity;

•an	increase	in	fossil-fueled	generation	construction	expenditures	due	to	an	increased	scope	of	work	in	2012;	and

•an	increase	in	transmission	construction	expenditures	due	to	increased	transmission	plant	upgrades	in	2012.

Decreases	in	Entergy	Gulf	States	Louisiana's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Gulf	States	Louisiana's receivable	from	the	money	pool	decreased	by	$23.6	million	in	2012	compared	to	decreasing	by	$39.4	million	in	2011.

Net	cash	flow	used	in	financing	activities	decreased	$15.7	million	in	2013	compared	to	2012	primarily	due	to	$14.8	million	in	credit borrowings	in	2013	compared	to	payments	of	$29.4	million	on	credit	borrowings	in	2012	against	the	nuclear	fuel	company	variable	interest	entity credit	facility.

•an	increase	of	$5.7	million	in	common	equity	distributions;

•net	cash	redemptions	of	$5.2	million	of	long-term	debt	in	2013;	and •net	cash	issuances	of	$3.4	million	of	long-term	debt	in	2012.

See	Note	5	to	the	financial	statements	for	more	details	on	long-term	debt.

Decreases	in	Entergy	Gulf	States	Louisiana's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Gulf	States	Louisiana's payable	to	the	money	pool	decreased	by	$7.1	million	in	2013	compared	to	increasing	by	$7.1	million	in	2012.

Net	cash	used	in	financing	activities	decreased	$211.3	million	in	2012	compared	to	2011	primarily	due	to	a	decrease	of	$187.8	million	in common	equity	distributions	and	the	issuance	of	$75	million	3.25%	Series	Q	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	July 2012,	partially	offset	by:

•the	repayment,	at	maturity,	of	$60	million	5.41%	Series	O	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	July	2012; •the	redemption	of	$10.84	million	of	pollution	control	revenue	bonds	in	2012	compared	to	the	redemption	of	$47.34	million	of	pollution control	revenue	bonds	in	2011;	and

•the	nuclear	fuel	company	variable	interest	entity	making	payments	of	$29.4	million	on	its	credit	facility	in	2012	compared	to	an	increase of	$5.2	million	in	credit	facility	borrowings	in	2011.

Entergy	Gulf	States	Louisiana's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 51.8% | 52.3% |
| Effect\tof\tsubtracting\tcash | (0.2%) | (0.6%) |
| Net\tdebt\tto\tnet\tcapital | 51.6% | 51.7% |

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	short-term	borrowings	and	long-term	debt,	including	the	currently maturing	portion.	Capital	consists	of	debt	and	equity.	Net	capital	consists	of	capital	less	cash	and	cash	equivalents.	Entergy	Gulf	States	Louisiana uses	the	debt	to	capital	ratio	in	analyzing	its	financial	condition	and	believes	it	provides	useful	information	to	its	investors	and	creditors	in evaluating	Entergy	Gulf	States	Louisiana's	financial	condition.	Entergy	Gulf	States	Louisiana	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	Gulf	States	Louisiana's	financial condition	because	net	debt	indicates	Entergy	Gulf	States	Louisiana's	outstanding	debt	position	that	could	not	be	readily	satisfied	by	cash	and	cash equivalents	on	hand.

Entergy	Gulf	States	Louisiana	requires	capital	resources	for:

•debt	and	preferred	equity	maturities	or	retirements;

•working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;	and •distribution	and	interest	payments.

Following	are	the	amounts	of	Entergy	Gulf	States	Louisiana's	planned	construction	and	other	capital	investments.

|  | 2014 | 2015 | 2016 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $95 | $80 | $80 |
| Transmission | 105 | 130 | 90 |
| Distribution | 70 | 70 | 75 |
| Other | 20 | 25 | 20 |
| Total | $290 | $305 | $265 |

Following	are	the	amounts	of	Entergy	Gulf	States	Louisiana's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments) and	other	purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | After	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $79 | $210 | $599 | $1,486 | $2,374 |
| Operating\tleases | $20 | $20 | $16 | $35 | $91 |
| Purchase\tobligations\t(b) | $116 | $211 | $46 | $255 | $628 |

(b) Purchase	obligations	represent	the	minimum	purchase	obligation	or	cancellation	charge	for	contractual	obligations	to	purchase	goods	or services.		For	Entergy	Gulf	States	Louisiana,	it	primarily	includes	unconditional	fuel	and	purchased	power	obligations.

In	addition	to	the	contractual	obligations	given	above,	Entergy	Gulf	States	Louisiana	expects	to	contribute	$31.3	million	to	its	pension	plans	and $9.4	million	to	other	postretirement	plans	in	2014	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the January	1,	2014	valuations	are	completed	by	April	1,	2014.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and	Other	Postretirement Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also,	in	addition	to	the	contractual	obligations,	Entergy	Gulf	States	Louisiana	has	$328.9	million	of	unrecognized	tax	benefits	and	interest net	of	unused	tax	attributes	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably	estimated	due	to	uncertainties	in	the	timing of	effective	settlement	of	tax	positions.	See	Note	3	to	the	financial	statements	for	additional	information	regarding	unrecognized	tax	benefits.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	Gulf	States	Louisiana includes	 specific	 investments	 and	 initiatives	 such	 as	 NRC	 post-Fukushima	 requirements	 and	 transmission	 spending	 to	 support	 economic development	projects,	reliability,	and	new	compliance	projects.		Entergy's	Utility	supply	plan	initiative	will	continue	to	seek	to	transform	its generation	portfolio	with	new	or	repowered	generation	resources.	Opportunities	resulting	from	the	supply	plan	initiative,	including	new	projects	or the	exploration	of	alternative	financing	sources,	could	result	in	increases	or	decreases	in	the	capital	expenditure	estimates	given	above.	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,	changes	in	project	plans,	and	the	ability	to access	capital.

Management	provides	more	information	on	long-term	debt	maturities	in	Note	5	to	the	financial	statements.

As	an	indirect,	wholly-owned	subsidiary	of	Entergy	Corporation,	Entergy	Gulf	States	Louisiana	pays	distributions	from	its	earnings	at	a percentage	determined	monthly.	Entergy	Gulf	States	Louisiana's	long-term	debt	indenture	contains	restrictions	on	the	payment	of	cash	dividends or	other	distributions	on	its	common	and	preferred	membership	interests.

# New	Nuclear	Development

Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	have	been	developing	and	are	preserving	a	project	option	for	new	nuclear	generation at	River	Bend.	In	the	first	quarter	2010,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	each	paid	for	and	recognized	on	its	books	$24.9 million	in	costs	associated	with	the	development	of	new	nuclear	generation	at	the	River	Bend	site;	these	costs	previously	had	been	recorded	on	the books	of	Entergy	New	Nuclear	Utility	Development,	LLC,	a	System	Energy	subsidiary.	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	will share	costs	going	forward	on	a	50/50	basis,	which	reflects	each	company's	current	participation	level	in	the	project.

In	March	2010,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	with	the	LPSC	seeking	approval	to	continue	the	limited development	activities	necessary	to	preserve	an	option	to	construct	a	new	unit	at	River	Bend.	The	testimony	and	legal	briefs	of	the	LPSC	staff generally	support	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana,	although	other	parties	filed	briefs,	without	supporting testimony,	in	opposition	to	the	request.	At	an	evidentiary	hearing	in	October	2011,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	the LPSC	staff	presented	testimony	in	support	of	certification	of	activities	to	preserve	an	option	for	a	new	nuclear	plant	at	River	Bend.	The	ALJ recommended,	however,	that	the	LPSC	decline	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	on	the	basis	that	the	LPSC's rule	on	new	nuclear	development	does	not	apply	to	activities	to	preserve	an	option	to	develop	and	on	the	further	grounds	that	the	companies improperly	engaged	in	advanced	preparation	activities	prior	to	certification.	There	has	been	no	suggestion	that	the	planning	activities	or	costs incurred	 were	 imprudent.	At	its	June	28,	2012	meeting	the	LPSC	voted	to	uphold	the	ALJ's	decision	and	directed	that	Entergy	Gulf	States Louisiana	and

Entergy	Louisiana	be	permitted	to	seek	recovery	of	these	costs	in	their	anticipated,	upcoming	rate	case	filings,	fully	reserving	the	LPSC's	right	to determine	the	recoverability	of	such	costs	in	rates.	The	LPSC	decided	to	extend	the	current	formula	rate	plans	of	Entergy	Gulf	States	Louisiana and	Entergy	Louisiana	and	provided	for	an	eight-year	amortization	of	costs	incurred	in	connection	with	the	potential	development	of	a	new nuclear	unit	at	River	Bend,	without	carrying	costs,	beginning	in	December	2014,	provided,	however,	that	amortization	of	these	costs	shall	not result	in	a	future	rate	increase.	As	of	December	31,	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	each	have	a	regulatory	asset	of $29.5	million	on	its	balance	sheet	related	to	these	new	nuclear	generation	development	costs.

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

•debt	or	preferred	membership	interest	issuances;	and

Entergy	Gulf	States	Louisiana	may	refinance,	redeem,	or	otherwise	retire	debt	and	preferred	equity/membership	interests	prior	to	maturity, to	the	extent	market	conditions	and	interest	and	dividend	rates	are	favorable.

All	debt	and	common	and	preferred	equity/membership	interest	issuances	by	Entergy	Gulf	States	Louisiana	require	prior	regulatory approval.	Preferred	equity/membership	interest	and	debt	issuances	are	also	subject	to	issuance	tests	set	forth	in	its	bond	indentures	and	other agreements.	Entergy	Gulf	States	Louisiana	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital	needs.

Entergy	Gulf	States	Louisiana's	receivables	from	or	(payables	to)	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the following	years.

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $1,925 | ($7,074) | $23,596 | $63,003 |

Entergy	Gulf	States	Louisiana	has	a	credit	facility	in	the	amount	of	$150	million	scheduled	to	expire	in	March	2018.	The	credit	facility allows	Entergy	Gulf	States	Louisiana	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the	facility.		As	of	December	31,	2013, there	were	no	cash	borrowings	and	$15.2	million	of	letters	of	credit	outstanding	under	the	credit	facility.		See	Note	4	to	the	financial	statements	for additional	discussion	of	the	credit	facility.

The	Entergy	Gulf	States	Louisiana	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	$100	million scheduled	to	expire	in	June	2016.	As	of	December	31,	2013,	$14.8	million	was	outstanding	on	the	credit	facility.	See	Note	4	to	the	financial statements	for	additional	discussion	of	the	variable	interest	entity	credit	facility.

Entergy	Gulf	States	Louisiana	obtained	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow	through	October 2015,	up	to	the	aggregate	amount,	at	any	one	time	outstanding,	of	$200	million.	See	Note	4	to	the	financial	statements	for	further	discussion	of Entergy	Gulf	States	Louisiana's	short-term	borrowing	limits.	Entergy	Gulf	States	Louisiana	has	also	obtained	an	order	from	the	FERC	authorizing long-term	securities	issuances	through	October	2015.	Entergy	Gulf	States	Louisiana	has	also	obtained	long-term	financing	authorization	from	the FERC	that	extends	through	October	2015	for	issuances	by	its	nuclear	fuel	company	variable	interest	entity.

In	February	2013	the	Entergy	Gulf	States	Louisiana	nuclear	fuel	company	variable	interest	entity	issued	$70	million	of	3.38%	Series	R notes	due	August	2020.	The	Entergy	Gulf	States	Louisiana	nuclear	fuel	company	variable	interest	entity	used	the	proceeds	principally	to	purchase additional	nuclear	fuel.

In	May	2013	the	Entergy	Gulf	States	Louisiana	nuclear	fuel	company	variable	interest	entity	redeemed,	at	maturity,	its	$75	million	5.56% Series	N	notes.

In	August	 2012,	 Hurricane	 Isaac	 caused	 extensive	 damage	 to	 Entergy	 Gulf	 States	 Louisiana's	 service	 area.	The	 storm	 resulted	 in widespread	power	outages,	significant	damage	primarily	to	distribution	infrastructure,	and	the	loss	of	sales	during	the	power	outages.	In	April 2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	a	joint	application	with	the	LPSC	relating	to	Hurricane	Isaac	system	restoration costs.		Specifically,	Entergy	Gulf	States	Louisiana	requested	that	the	LPSC	determine	the	amount	of	such	costs	that	were	prudently	incurred	and are,	thus,	eligible	for	recovery	from	customers.		Including	carrying	costs	and	additional	storm	escrow	funds,	Entergy	Gulf	States	Louisiana	is seeking	determination	that	$73.8	million	in	system	restoration	costs	were	prudently	incurred.		Entergy	Gulf	States	Louisiana	intends	to	replenish its	storm	escrow	accounts	to	$90	million	primarily	through	traditional	debt	markets	and	has	requested	special	rate	treatment	of	any	borrowings	for that	purpose.	 	In	May	2013,	Entergy	Gulf	States	Louisiana	filed	a	supplemental	application	proposing	a	specific	means	 to	finance	system restoration	costs	and	related	requests.	Entergy	Gulf	States	Louisiana	is	proposing	to	finance	Hurricane	Isaac	restoration	costs	through	Louisiana Act	55	financing,	which	was	the	same	method	it	used	for	Hurricanes	Katrina,	Rita,	Gustav,	and	Ike.

# Entergy	Louisiana's	Ninemile	Point	Unit	6	Self-Build	Project

In	June	2011,	Entergy	Louisiana	filed	with	the	LPSC	an	application	seeking	certification	that	the	public	necessity	and	convenience	would be	served	by	Entergy	Louisiana's	construction	of	a	combined-cycle	gas	turbine	generating	facility	(Ninemile	6)	at	its	existing	Ninemile	Point electric	generating	station.	Ninemile	6	will	be	a	nominally-sized	550	MW	unit	that	is	estimated	to	cost	approximately	$721	million	to	construct, excluding	interconnection	and	transmission	upgrades.	Entergy	Gulf	States	Louisiana	joined	in	the	application,	seeking	certification	of	its	purchase under	a	life-of-unit	power	purchase	agreement	of	up	to	25%	of	the	capacity	and	energy	generated	by	Ninemile	6.	The	Ninemile	6	capacity	and energy	is	proposed	to	be	allocated	55%	to	Entergy	Louisiana,	25%	to	Entergy	Gulf	States	Louisiana,	and	20%	to	Entergy	New	Orleans.	In February	2012	the	City	Council	passed	a	resolution	authorizing	Entergy	New	Orleans	to	purchase	20%	of	the	Ninemile	6	energy	and	capacity.	In March	 2012	 the	 LPSC	 unanimously	 voted	 to	 grant	 the	 certifications	 requested	 by	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana. Following	approval	by	the	LPSC,	Entergy	Louisiana	issued	full	notice	to	proceed	to	the	project's	engineering,	procurement,	and	construction contractor.	All	major	permits	and	approvals	required	to	begin	construction	have	been	obtained	and	construction	is	in	progress.

Under	the	terms	approved	by	the	LPSC,	costs	may	be	recovered	through	Entergy	Louisiana's	and	Entergy	Gulf	States	Louisiana's	formula rate	plans	beginning	in	the	month	after	the	unit	is	placed	in	service.	In	November	2013,	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	filed a	joint	application	with	the	LPSC	to	certify	the	estimated	first	year	revenue	requirement	associated	with	Ninemile	6	that	will	be	placed	into	rates.

The	rates	that	Entergy	Gulf	States	Louisiana	charges	for	its	services	significantly	influence	its	financial	position,	results	of	operations,	and liquidity.	Entergy	 Gulf	 States	 Louisiana	 is	 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.

•authorization	to	implement	a	three-year	formula	rate	plan	with	a	midpoint	return	on	common	equity	of	10.4%,	plus	or	minus	75	basis points	(the	deadband),	that	would	provide	a	means	for	the	annual	re-setting	of	rates	(commencing	with	calendar	year	2013	as	its	first	test year),	that	would	include	a	mechanism	to	recover	incremental	transmission	revenue	requirement	on	the	basis	of	a	forward-looking	test year	as	compared	to	the	initial	base	year	of	2014	with	an	annual	true-up,	that	would	retain	the	primary	aspects	of

the	prior	formula	rate	plan,	including	a	60%	to	customers/40%	to	Entergy	Gulf	States	Louisiana	sharing	mechanism	for	earnings	outside the	deadband,	and	a	capacity	rider	mechanism	that	would	permit	recovery	of	incremental	capacity	additions	approved	by	the	LPSC.

# Retail	Rates	-	Gas

# Industrial	and	Commercial	Customers

Entergy	Gulf	States	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	Gulf	States	Louisiana's	industrial	customer	base.	Entergy	Gulf	States 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.	Entergy	Gulf	States	Louisiana	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 Louisiana	does	not	currently	expect	additional	significant	losses	to	cogeneration	because	of	the	current	economics	of	the	electricity	markets	and Entergy	Gulf	States	Louisiana's	marketing	efforts	in	retaining	industrial	customers.

Entergy	Gulf	States	Louisiana	owns	and,	through	an	affiliate,	operates	the	River	Bend	nuclear	power	plant.	Entergy	Gulf	States	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,	 regulatory	 requirement	 changes,	 including	 changes	 resulting	 from	 events	 at	 other	 plants, 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	Louisiana	may	be	required	to	provide additional	funds	or	credit	support	to	satisfy	regulatory	requirements	for	decommissioning.

The	nuclear	industry	continues	to	address	susceptibility	to	stress	corrosion	cracking	of	certain	materials	within	the	reactor	coolant	system. The	issue	is	applicable	to	River	Bend	and	is	managed	in	accordance	with	industry	standard	practices	and	guidelines	which	include	in-service examinations,	replacements,	and	mitigation	strategies.		Developments	in	the	industry	or	identification	of	issues	at	the	nuclear	units	could	require unanticipated	remediation	efforts	that	cannot	be	quantified	in	advance.

Entergy	Gulf	States	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	Gulf	States	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	preparation	of	Entergy	Gulf	States	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	that	could	produce	estimates	that	would	have	a	material	effect	on	the	presentation	of	Entergy's	financial	position or	results	of	operations.

As	discussed	in	Note	1	to	the	financial	statements,	Entergy	Gulf	States	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.		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.

Entergy	 sponsors	 qualified	 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	 and	 meet	 certain eligibility	requirements	while	still	working	for	Entergy.		Entergy's	reported	costs	of	providing	these	benefits,	as	described	in	Note	11	to	the financial	statements,	are

impacted	 by	 numerous	 factors	 including the	 provisions	 of the	 plans,	 changing	 employee	 demographics,	 and	 various	 actuarial	 calculations, assumptions,	and	accounting	mechanisms. 	See	the	"Qualified	Pension	and	Other	Postretirement	Benefits"	in the	"Critical	Accounting Estimates"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	further	discussion.		Because	of the	complexity	of	these	calculations,	the	long-term	nature	of	these	obligations,	and	the	importance	of	the	assumptions	utilized,	Entergy's	estimate of	these	costs	is	a	critical	accounting	estimate.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Qualified	Pension	Cost | Impact	on	2013<br>Qualified	Projected<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $2,087 | $19,764 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,027 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $824 | $3,292 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $558 | $5,653 |
| Health\tcare\tcost\ttrend | 0.25% | $1,017 | $5,223 |

Total	qualified	pension	cost	for	Entergy	Gulf	States	Louisiana	in	2013	was	$31	million,	including	an	$805	thousand	curtailment	charge and	an	$808	 thousand	special	 termination	benefit	charge	related	 to	workforce	downsizing.	 	Entergy	Gulf	States	Louisiana	anticipates	2014 qualified	pension	cost	to	be	$18.6	million.		Entergy	Gulf	States	Louisiana	contributed	$11.6	million	to	its	pension	plans	in	2013	and	estimates 2014	pension	contributions	to	be	approximately	$31.3	million;	although	the	required	pension	contributions	will	not	be	known	with	more	certainty until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase out	of	pension	funding	relief	under	MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Gulf	States	Louisiana	in	2013	were	$22.1	million,	including	a $1.5	million	curtailment	charge	related	to	workforce	downsizing.			Entergy	Gulf	States	Louisiana	expects	2014	postretirement	health	care	and	life insurance	benefit	costs	to	approximate	$12.2	million.	Entergy	Gulf	States	Louisiana	contributed	$7	million	to	its	other	postretirement	plans	in 2013	and	expects	to	contribute	approximately	$9.4	million	in	2014.

# See	"New	Accounting	Pronouncements"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and

# Analysis.

# To	the	Board	of	Directors	and	Members	of

# Baton	Rouge,	Louisiana

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Gulf	States	Louisiana,	L.L.C.	(the	"Company")	as	of	December	31,	2013	and	2012, and	the	related	income	statements,	statements	of	comprehensive	income,	statements	of	cash	flows,	and	statements	of	changes	in	equity	(pages	323 through	328	and	applicable	items	in	pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December	31,	2013.	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	Louisiana,	L.L.C.	as of	December	31,	2013	and	2012,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

# INCOME	STATEMENTS

# For	the	Years	Ended	December	31,

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $1,881,895 | $1,606,165 | $2,069,548 |
| Natural\tgas | 59,238 | 48,729 | 64,861 |
| TOTAL | 1,941,133 | 1,654,894 | 2,134,409 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 286,625 | 194,878 | 437,301 |
| Purchased\tpower | 731,611 | 562,247 | 780,711 |
| Nuclear\trefueling\toutage\texpenses | 20,345 | 17,565 | 18,227 |
| Other\toperation\tand\tmaintenance | 398,589 | 361,415 | 351,070 |
| Decommissioning | 15,908 | 15,024 | 14,189 |
| Taxes\tother\tthan\tincome\ttaxes | 80,307 | 76,295 | 75,858 |
| Depreciation\tand\tamortization | 150,929 | 146,673 | 143,387 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | 9,482 | 31,835 | (17,045) |
| TOTAL | 1,693,796 | 1,405,932 | 1,803,698 |
| OPERATING\tINCOME | 247,337 | 248,962 | 330,711 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 8,062 | 8,694 | 9,094 |
| Interest\tand\tinvestment\tincome | 52,953 | 42,773 | 40,945 |
| Miscellaneous\t-\tnet | (11,567) | (8,928) | (8,799) |
| TOTAL | 49,448 | 42,539 | 41,240 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 81,118 | 83,251 | 84,356 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (2,814) | (3,343) | (3,745) |
| TOTAL | 78,304 | 79,908 | 80,611 |
| INCOME\tBEFORE\tINCOME\tTAXES | 218,481 | 211,593 | 291,340 |
| Income\ttaxes | 56,819 | 52,616 | 89,736 |
| NET\tINCOME | 161,662 | 158,977 | 201,604 |
| Preferred\tdistribution\trequirements\tand\tother | 825 | 825 | 825 |
| EARNINGS\tAPPLICABLE\tTO |  |  |  |
| COMMON\tEQUITY | $160,837 | $158,152 | $200,779 |

# STATEMENTS	OF	COMPREHENSIVE	INCOME

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| Net\tIncome | $161,662 | $158,977 | $201,604 |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t$34,126,\t$8,732,\tand\t($16,556)) | 37,027 | 4,381 | (29,306) |
| Other\tcomprehensive\tincome\t(loss) | 37,027 | 4,381 | (29,306) |
| Comprehensive\tIncome | $198,689 | $163,358 | $172,298 |

# STATEMENTS	OF	CASH	FLOWS

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $161,662 | $158,977 | $201,604 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 223,420 | 214,929 | 207,753 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 86,125 | 92,523 | (4,845) |
| Changes\tin\tworking\tcapital: |  |  |  |
| Receivables | (61,561) | 87,089 | (82,221) |
| Fuel\tinventory | 412 | (3,718) | 2,578 |
| Accounts\tpayable | 24,694 | (1,725) | (58,981) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (43,029) | (86,346) | 148,313 |
| Interest\taccrued | 371 | (647) | (1,177) |
| Deferred\tfuel\tcosts | (10,573) | (96,230) | 74,877 |
| Other\tworking\tcapital\taccounts | (5,434) | (5,548) | (4,600) |
| Changes\tin\tprovisions\tfor\testimated\tlosses | (60,084) | (2,222) | 1,353 |
| Changes\tin\tother\tregulatory\tassets | 123,254 | (73,082) | (77,713) |
| Changes\tin\tpension\tand\tother\tpostretirement\tliabilities | (140,643) | 83,440 | 112,736 |
| Other | 136,112 | (21,232) | (37,562) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 434,726 | 346,208 | 482,115 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (267,122) | (284,458) | (219,307) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 8,062 | 8,694 | 9,094 |
| Nuclear\tfuel\tpurchases | (141,176) | (51,610) | (87,901) |
| Proceeds\tfrom\tsale\tof\tnuclear\tfuel | 19,401 | 67,632 | 9,647 |
| Payment\tto\tstorm\treserve\tescrow\taccount | (29) | (99) | (124) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 65,475 | 3,364 | — |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 193,792 | 131,042 | 76,844 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (213,122) | (150,601) | (94,922) |
| Change\tin\tmoney\tpool\treceivable\t-\tnet | (1,925) | 23,596 | 39,407 |
| Proceeds\tfrom\tthe\tsale\tof\tinvestment | — | 51,000 | — |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (336,644) | (201,440) | (267,262) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 69,770 | 74,251 | — |
| Retirement\tof\tlong-term\tdebt | (75,000) | (70,840) | (47,340) |
| Change\tin\tmoney\tpool\tpayable\t-\tnet | (7,074) | 7,074 | — |
| Changes\tin\tcredit\tborrowings\t-\tnet | 14,800 | (29,400) | 5,200 |
| Dividends/distributions\tpaid: |  |  |  |
| Common\tequity | (119,900) | (114,200) | (301,950) |
| Preferred\tmembership\tinterests | (825) | (825) | (825) |
| Other | 42 | 13 | (266) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | (118,187) | (133,927) | (345,181) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (20,105) | 10,841 | (130,328) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 35,686 | 24,845 | 155,173 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $15,581 | $35,686 | $24,845 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $77,882 | $80,848 | $82,413 |
| Income\ttaxes | $5,064 | $89,191 | ($56,289) |

# BALANCE	SHEETS

| Cash | $1,739 | $35,085 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 13,842 | 601 |
| Total\tcash\tand\tcash\tequivalents | 15,581 | 35,686 |
| Accounts\treceivable: |  |  |
| Customer | 69,648 | 53,480 |
| Allowance\tfor\tdoubtful\taccounts | (909) | (711) |
| Associated\tcompanies | 107,723 | 71,697 |
| Other | 22,945 | 18,736 |
| Accrued\tunbilled\trevenues | 58,867 | 51,586 |
| Total\taccounts\treceivable | 258,274 | 194,788 |
| Deferred\tfuel\tcosts | 9,625 | — |
| Fuel\tinventory\t-\tat\taverage\tcost | 26,555 | 26,967 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 122,909 | 121,289 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 25,975 | 5,953 |
| Prepaid\ttaxes | 22,008 | — |
| Gas\thedge\tcontracts | 2,238 | — |
| Prepayments\tand\tother | 12,452 | 7,911 |
| TOTAL | 495,617 | 392,594 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliate\tpreferred\tmembership\tinterests | 289,664 | 289,664 |
| Decommissioning\ttrust\tfunds | 573,744 | 477,391 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 174,134 | 165,410 |
| Storm\treserve\tescrow\taccount | 21,538 | 86,984 |
| Other | 14,145 | 13,404 |
| TOTAL | 1,073,225 | 1,032,853 |
| UTILITY\tPLANT |  |  |
| Electric | 7,400,689 | 7,279,953 |
| Natural\tgas | 143,902 | 135,723 |
| Construction\twork\tin\tprogress | 105,314 | 125,448 |
| Nuclear\tfuel | 196,508 | 146,768 |
| TOTAL\tUTILITY\tPLANT | 7,846,413 | 7,687,892 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 4,071,762 | 4,003,385 |
| UTILITY\tPLANT\t-\tNET | 3,774,651 | 3,684,507 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 165,456 | 171,051 |
| Other\tregulatory\tassets | 321,466 | 409,653 |
| Deferred\tfuel\tcosts | 100,124 | 100,124 |
| Other | 12,049 | 12,337 |
| TOTAL | 599,095 | 693,165 |
| TOTAL\tASSETS | $5,942,588 | $5,803,119 |

| Currently	maturing	long-term	debt | $— | $75,000 |
| :--- | :--- | :--- |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 95,853 | 89,377 |
| Other | 103,314 | 97,509 |
| Customer\tdeposits | 51,839 | 48,265 |
| Taxes\taccrued | — | 21,021 |
| Accumulated\tdeferred\tincome\ttaxes | 36,330 | 22,249 |
| Interest\taccrued | 25,808 | 25,437 |
| Deferred\tfuel\tcosts | — | 948 |
| Pension\tand\tother\tpostretirement\tliabilities | 9,065 | 7,803 |
| System\tagreement\tcost\tequalization | 15,000 | — |
| Gas\thedge\tcontracts | — | 2,620 |
| Other | 19,032 | 11,999 |
| TOTAL | 356,241 | 402,228 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,512,547 | 1,403,195 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 75,295 | 78,312 |
| Other\tregulatory\tliabilities | 159,429 | 103,444 |
| Decommissioning\tand\tasset\tretirement\tcost\tliabilities | 403,084 | 380,822 |
| Accumulated\tprovisions | 37,146 | 97,230 |
| Pension\tand\tother\tpostretirement\tliabilities | 274,315 | 416,220 |
| Long-term\tdebt | 1,527,465 | 1,442,429 |
| Long-term\tpayables\t-\tassociated\tcompanies | 27,900 | 29,510 |
| Other | 108,189 | 66,725 |
| TOTAL | 4,125,370 | 4,017,887 |
| Commitments\tand\tContingencies |  |  |
| EQUITY |  |  |
| Preferred\tmembership\tinterests\twithout\tsinking\tfund | 10,000 | 10,000 |
| Member's\tequity | 1,479,179 | 1,438,233 |
| Accumulated\tother\tcomprehensive\tloss | (28,202) | (65,229) |
| TOTAL | 1,460,977 | 1,383,004 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $5,942,588 | $5,803,119 |

# STATEMENTS	OF	CHANGES	IN	EQUITY

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 | For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Common\tEquity |  |  |
|  | Preferred\nMembership\nInterests | Member's\tEquity | Accumulated\tOther\nComprehensive\nIncome\t(Loss) | Total |
|  |  | (In\tThousands) |  |  |
| Balance\tat\tDecember\t31,\t2010 | $10,000 | $1,494,593 | ($40,304) | $1,464,289 |
| Net\tincome | — | 201,604 | — | 201,604 |
| Other\tcomprehensive\tloss | — | — | (29,306) | (29,306) |
| Dividends/distributions\tdeclared\ton\tcommon\tequity | — | (301,950) | — | (301,950) |
| Dividends/distributions\tdeclared\ton\tpreferred\tmembership\ninterests | — | (825) | — | (825) |
| Other | — | (36) | — | (36) |
| Balance\tat\tDecember\t31,\t2011 | $10,000 | $1,393,386 | ($69,610) | $1,333,776 |
| Net\tincome | — | 158,977 | — | 158,977 |
| Member\tcontribution | — | 1,000 | — | 1,000 |
| Other\tcomprehensive\tincome | — | — | 4,381 | 4,381 |
| Dividends/distributions\tdeclared\ton\tcommon\tequity | — | (114,200) | — | (114,200) |
| Dividends/distributions\tdeclared\ton\tpreferred\tmembership\ninterests | — | (825) | — | (825) |
| Other | — | (105) | — | (105) |
| Balance\tat\tDecember\t31,\t2012 | $10,000 | $1,438,233 | ($65,229) | $1,383,004 |
| Net\tincome | — | 161,662 | — | 161,662 |
| Other\tcomprehensive\tincome | — | — | 37,027 | 37,027 |
| Dividends/distributions\tdeclared\ton\tcommon\tequity | — | (119,900) | — | (119,900) |
| Dividends/distributions\tdeclared\ton\tpreferred\tmembership\ninterests | — | (825) | — | (825) |
| Other | — | 9 | — | 9 |
| Balance\tat\tDecember\t31,\t2013 | $10,000 | $1,479,179 | ($28,202) | $1,460,977 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,941,133 | $1,654,894 | $2,134,409 | $2,097,021 | $1,844,386 |
| Net\tincome | $161,662 | $158,977 | $201,604 | $174,319 | $153,281 |
| Total\tassets | $5,942,588 | $5,803,119 | $5,763,719 | $5,690,376 | $5,522,751 |
| Long-term\tobligations\t(a) | $1,527,465 | $1,442,429 | $1,482,430 | $1,584,332 | $1,740,592 |

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

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $465 | $389 | $479 | $498 | $393 |
| Commercial | 417 | 349 | 416 | 426 | 354 |
| Industrial | 502 | 392 | 490 | 489 | 383 |
| Governmental | 22 | 18 | 22 | 21 | 18 |
| Total\tretail | 1,406 | 1,148 | 1,407 | 1,434 | 1,148 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 375 | 377 | 562 | 463 | 475 |
| Non-associated\tcompanies | 45 | 34 | 52 | 79 | 105 |
| Other | 56 | 47 | 49 | 40 | 49 |
| Total | $1,882 | $1,606 | $2,070 | $2,016 | $1,777 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 5,206 | 5,176 | 5,383 | 5,538 | 5,090 |
| Commercial | 5,208 | 5,287 | 5,239 | 5,274 | 5,058 |
| Industrial | 9,021 | 8,890 | 9,041 | 8,801 | 7,601 |
| Governmental | 228 | 228 | 222 | 210 | 213 |
| Total\tretail | 19,663 | 19,581 | 19,885 | 19,823 | 17,962 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 6,580 | 7,727 | 8,595 | 8,516 | 7,084 |
| Non-associated\tcompanies | 887 | 941 | 1,013 | 1,705 | 2,546 |
| Total | 27,130 | 28,249 | 29,493 | 30,044 | 27,592 |

# ENTERGY	LOUISIANA,	LLC	AND	SUBSIDIARIES

Net	 income	 decreased	 $28.6	 million	 primarily	 due	 to	 higher	 other	 operation	 and	 maintenance	 expenses,	 higher	 depreciation	 and amortization	 expenses,	 higher	 interest	 expense,	 and	 higher	 nuclear	 refueling	 outage	 expenses,	 partially	 offset	 by	 higher	 net	 revenue.	Also contributing	to	the	decrease	in	net	income	was	the	IRS	tax	settlement,	in	June	2012,	related	to	the	uncertain	tax	position	regarding	the	Hurricane Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing,	which	resulted	in	a	$142.7	million	reduction	of	income	tax	expense	in	2012.	The	prior year	income	tax	benefit	was	partially	offset	by	a	$137.1	million	($84.3	million	net-of-tax)	regulatory	charge,	which	reduced	net	revenue	in	2012, because	Entergy	Louisiana	agreed	to	share	the	savings	with	customers.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax settlement.

Net	income	decreased	$192.8	million	primarily	due	to	a	prior	year	settlement	with	the	IRS	related	to	the	mark-to-market	income	tax treatment	of	power	purchase	contracts,	which	resulted	in	a	$422	million	reduction	in	income	tax	expense	in	the	third	quarter	2011.		The	net	income effect	was	partially	offset	by	a	$199	million	regulatory	charge,	which	reduced	net	revenue	in	2011,	because	Entergy	Louisiana	is	sharing	the benefit	with	customers.		Partially	offsetting	the	decrease	in	net	income	was	an	IRS	tax	settlement,	in	second	quarter	2012,	related	to	the	uncertain tax	position	regarding	the	Hurricane	Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing,	which	resulted	in	a	$142.7	million	income	tax savings,	partially	offset	by	a	$137.1	million	($84.3	million	net-of-tax)	regulatory	charge,	which	reduced	net	revenue	in	2012,	because	Entergy Louisiana	agreed	to	share	the	savings	with	customers.		See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	settlements.

| 2012	net	revenue | $933.3 |
| :--- | :--- |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | 137.6 |
| Retail\telectric\tprice | 91.5 |
| Volume/weather | 23.9 |
| Net\twholesale\trevenue | 18.1 |
| Fuel\trecovery | 9.4 |
| Other | (5.0) |
| 2013\tnet\trevenue | $1,208.8 |

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	recorded	in	the	second	quarter	2012	because Entergy	Louisiana	agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane Katrina	and	Hurricane	Rita	Louisiana	Act	55	financing.		See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax	settlement	and savings	obligation.

The	retail	electric	price	variance	is	primarily	due	to	a	formula	rate	plan	increase	effective	January	2013.	See	Note	2	to	the	financial statements	for	discussion	of	the	formula	rate	plan	increase.

The	volume/weather	variance	is	primarily	due	to	an	increase	of	512	GWh	in	billed	electricity	usage	in	all	sectors	due	to	the	effect	of	more favorable	weather	as	compared	to	the	previous	year	on	residential	sales	and	the	effect	of	Hurricane	Isaac,	which	decreased	sales	volume	in	2012. The	increase	in	industrial	usage	was	also	driven	by	a	higher	capacity	factor	in	the	petroleum	industry.

The	net	wholesale	revenue	variance	is	primarily	due	to	the	sale	to	Entergy	Gulf	States	Louisiana	of	one-third	of	Acadia	Unit	2	capacity and	energy.

The	fuel	recovery	variance	is	primarily	due	to	the	expiration	of	the	Evangeline	gas	contract	on	January	1,	2013.

•an	increase	of	$356.9	million	in	fuel	cost	recovery	revenues	primarily	due	to	higher	fuel	rates.		Entergy	Louisiana's	fuel	and	purchased power	recovery	mechanism	is	discussed	in	Note	2	to	the	financial	statements;

•the	formula	rate	plan	increase,	as	discussed	above;

•an	increase	of	$29.8	million	in	affiliated	sales	as	a	result	of	the	Acadia	contract	with	Entergy	Gulf	States	Louisiana	effective	January	2013; and

•the	increase	related	to	volume/weather,	as	discussed	above.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	an	increase	in	the	average	market	prices	of	natural	gas	and	purchased power	and	an	increase	in	the	recovery	from	customers	of	deferred	fuel	costs.

Other	regulatory	charges	decreased	primarily	due	to	a	regulatory	charge	recorded	in	the	second	quarter	2012	because	Entergy	Louisiana agreed	to	share	with	customers	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane	Katrina	and Hurricane	Rita	Louisiana	Act	55	financing.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	tax	settlement	and	savings obligation.

| 2011	net	revenue | $886.2 |
| :--- | :--- |
| Mark-to-market\ttax\tsettlement\tsharing | 199.5 |
| Retail\telectric\tprice | 6.7 |
| Volume/weather | (21.4) |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | (134.1) |
| Other | (3.6) |
| 2012\tnet\trevenue | $933.3 |

The	mark-to-market	tax	settlement	sharing	variance	results	from	a	regulatory	charge	recorded	in	the	third	quarter	2011	because	Entergy Louisiana	is	sharing	the	benefits	of	a	settlement	with	the	IRS	related	to	mark-to-market	income	tax	treatment	of	power	purchase	contracts	with customers.	See	Notes	3	and	8	to	the	financial	statements	for	additional	discussion	of	the	settlement	and	benefit	sharing.

The	retail	electric	price	variance	is	primarily	due	to	a	special	formula	rate	plan	increase	effective	May	2011	in	accordance	with	a	previous LPSC	order	relating	to	the	acquisition	of	Unit	2	of	the	Acadia	Energy	Center.	See	Note	2	to	the	financial	statements	for	discussion	of	the	formula rate	plan	increase.

The	volume/weather	variance	 is	primarily	due	 to	 the	effect	of	milder	weather	as	compared	 to	 the	previous	year	on	residential	and commercial	sales	and	the	effects	of	the	power	outages	caused	by	Hurricane	Isaac,	partially	offset	by	increased	usage	in	the	industrial	sector	as	a result	of	increased	consumption	by	a	large	industrial	customer	in	the	chemical	industry	as	a	result	of	plant	expansion.

The	Louisiana	Act	55	financing	savings	obligation	sharing	variance	results	from	a	regulatory	charge	recorded	in	the	second	quarter	2012 because	Entergy	Louisiana	agreed	to	share	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane Katrina	and	Hurricane	Rita	Louisiana	Act	55	financings	with	customers.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the settlement	and	savings	obligation.

Gross	operating	revenues	decreased	primarily	due	to:

•a	decrease	of	$330.3	million	in	fuel	cost	recovery	revenues	primarily	due	to	lower	fuel	rates.	Entergy	Louisiana's	fuel	and	purchased power	recovery	mechanism	is	discussed	in	Note	2	to	the	financial	statements;

•a	decrease	of	$42	million	in	rider	revenues	primarily	due	to	higher	System	Agreement	credits	in	2012;	and

•the	decrease	related	to	volume/weather,	as	discussed	above.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	a	decrease	in	the	average	market	prices	of	natural	gas	and	purchased	power and	a	decrease	in	the	recovery	from	customers	of	deferred	fuel	costs.

Other	regulatory	charges	decreased	primarily	due	to	a	regulatory	charge	recorded	in	the	third	quarter	2011	because	Entergy	Louisiana	is sharing	the	benefits	of	a	settlement	with	the	IRS	related	to	mark-to-market	income	tax

treatment	of	power	purchase	contracts	with	customers,	partially	offset	by	a	regulatory	charge	recorded	in	the	second	quarter	2012	because	Entergy Louisiana	agreed	to	share	the	savings	from	an	IRS	settlement	related	to	the	uncertain	tax	position	regarding	the	Hurricane	Katrina	and	Hurricane Rita	Louisiana	Act	55	financing	with	customers.	See	Notes	3	and	8	to	the	financial	statements	for	additional	discussion	of	the	settlements	and savings	obligation.

Nuclear	refueling	outage	expenses	increased	primarily	due	to	the	amortization	of	higher	expenses	associated	with	the	refueling	outage	at Waterford	3.

•an	increase	of	$20.9	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	the	discount	rates	used	to	determine	net periodic	pension	and	other	postretirement	benefit	costs	and	a	settlement	charge,	recognized	in	September	2013,	related	to	the	payment	of lump	sum	benefits	out	of	the	non-qualified	pension	plan.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs;

•an	increase	of	$16.5	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative,	substantially	offset	by	the	deferral,	as	approved	by	the	LPSC,	of	$13 million	of	these	costs.	See	the	"Human	Capital	Management	Strategic	Imperative"	section	of	Entergy	Corporation	and	Subsidiaries Management's	Financial	Discussion	and	Analysis	for	further	discussion;

•an	increase	of	$5.4	million	in	nuclear	generation	expenses	primarily	due	to	higher	labor	and	materials	costs;	and •the	prior	year	deferral,	as	approved	by	the	LPSC	and	the	FERC,	of	costs	related	to	the	transition	and	implementation	of	joining	the	MISO RTO,	which	reduced	2012	expenses	by	$5.2	million.

The	increase	was	partially	offset	by	a	decrease	of	$9.2	million	in	fossil-fueled	generation	expenses	due	to	an	overall	lower	scope	of	work	done during	plant	outages	as	compared	to	the	prior	year.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	placing	in	service	the	Waterford 3	steam	generator	project	in	December	2012.

Interest	expense	increased	primarily	due	to	the	following	long-term	debt	issuances:

Other	operation	and	maintenance	expenses	decreased	primarily	due	to:

•$17.1	million	of	transmission	investment	equalization	expenses	recorded	in	the	fourth	quarter	2011	as	a	result	of	a	billing	adjustment related	to	prior	transmission	costs	(for	the	approximate	period	of	1996-2011)	allocable	to	Entergy	Louisiana	under	the	System	Agreement;

•a	decrease	of	$7.3	million	in	fossil-fueled	generation	expenses	due	to	an	overall	lower	scope	of	outages	compared	to	prior	year;

•a	decrease	of	$2.7	million	as	a	result	of	lower	write-offs	of	uncollectible	accounts	in	2012.

•an	increase	of	$11.2	million	in	compensation	and	benefits	costs	primarily	due	to	decreasing	discount	rates	and	changes	in	certain	actuarial assumptions	resulting	from	an	experience	study.		See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for further	discussion	of	benefits	costs;	and

•$6.7	million	of	costs	incurred	in	2012	related	to	the	now	terminated	plan	to	spin	off	and	merge	the	transmission	business.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	the	acquisition	of	the	Acadia Unit	2	in	April	2011.

•cessation	in	2011	of	interest	on	transmission	credits	per	a	FERC	order	relating	to	an	interconnection	and	operating	agreement	between	a power	producer	and	Entergy	Louisiana;

•the	issuance	of	$200	million	of	4.8%	Series	first	mortgage	bonds	in	March	2011;

•the	issuance	by	Entergy	Louisiana	Investment	Recovery	Funding,	L.L.C.,	a	wholly	owned	subsidiary	of	Entergy	Louisiana,	of	$207.2 million	of	senior	secured	investment	recovery	bonds	with	a	coupon	rate	of	2.04%	in	September	2011;

•the	issuance	of	$250	million	of	1.875%	Series	first	mortgage	bonds	in	January	2012;	and

•the	issuance	of	$200	million	of	5.25%	Series	first	mortgage	bonds	in	July	2012.

The	effective	income	tax	rates	for	2013,	2012,	and	2011,	were	24.5%,	(84.7%),	and	(357.0%),	respectively.	The	effective	income	tax	rate of	(84.7%)	for	2012	was	primarily	due	to	the	settlement	of	the	tax	treatment	of	the	Louisiana	Act	55	financing	of	the	Hurricane	Katrina	and Hurricane	Rita	storm	costs	and	the	reversal	of	the	provision	for	the	uncertain	tax	positions	related	to	that	item.	The	effective	income	tax	rate	of (357.0%)	for	2011	is	primarily	due	to	the	reversal	in	the	third	quarter	2011	for	uncertain	tax	positions	resulting	from	a	settlement	with	the	IRS related	to	the	mark-to-market	income	tax	treatment	of	power	purchase	contracts.	See	Note	3	to	the	financial	statements	for	a	reconciliation	of	the federal	statutory	rate	of	35%	to	the	effective	income	tax	rates	and	for	a	discussion	of	the	IRS	settlement	and	audits.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $30,086 | $878 | $123,254 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 662,772 | 447,698 | 479,342 |
| Investing\tactivities | (540,807) | (850,866) | (811,203) |
| Financing\tactivities | (28,044) | 432,376 | 209,485 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 93,921 | 29,208 | (122,376) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $124,007 | $30,086 | $878 |

Net	 cash	 flow	 provided	 by	 operating	 activities	 increased	 $215.1	 million	 in	 2013	 primarily	 due	 to	 decreased	 Hurricane	 Isaac	 storm spending	in	2013	and	a	decrease	of	$7.7	million	in	pension	contributions.	The	increase	was	partially	offset	by	an	increase	of	$12.4	million	in interest	paid	resulting	from	the	increase	in	interest	expense,	as	discussed	above,	and	a	decrease	of	$7.8	million	in	income	tax	refunds.	See "Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and	other	postretirement benefits	funding.

Net	cash	provided	by	operating	activities	decreased	$31.6	million	in	2012	primarily	due	to	decreased	recovery	of	fuel	costs	due	to	a	lower fuel	rate	for	the	period,	Hurricane	Isaac	storm	restoration	spending	in	2012,	and	an	increase	of	$22.9	million	in	interest	paid	resulting	from	the increase	in	interest	expense,	as	discussed	above.	The	decrease	was	partially	offset	by	a	decrease	of	$31.8	million	in	pension	contributions	and	the purchase	in	2011	of	$28.1	million	of	fuel	oil	from	System	Fuels	because	System	Fuels	will	no	longer	procure	fuel	oil	for	the	Utility	companies. See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and	other	postretirement benefits.

Net	cash	flow	used	in	investing	activities	decreased	$310.1	million	in	2013	primarily	due	to:

•receipts	of	$187	million	from	the	storm	reserve	escrow	account	in	2013	compared	to	receipts	of	$14.5	million	in	2012; •a	decrease	in	nuclear	construction	expenditures	due	to	the	Waterford	3	steam	generator	replacement	project	in	2012; •a	decrease	in	nuclear	fuel	activity	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements	in	the Utility	business,	material	and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle;	and •a	decrease	in	distribution	construction	expenditures	due	to	higher	Hurricane	Isaac	spending	in	prior	year.

The	decrease	was	offset	by	an	increase	in	fossil-fueled	generation	construction	expenditures	due	to	spending	on	the	Ninemile	Unit	6	self-build project	and	an	increase	in	transmission	construction	expenditures	as	a	result	of	additional	reliability	work	performed	in	2013.

Net	cash	used	in	investing	activities	increased	$39.7	million	in	2012	primarily	due	to:

•an	increase	in	fossil	construction	expenditures	due	to	spending	on	the	Ninemile	Unit	6	self-build	project;

•an	increase	in	nuclear	construction	expenditures	due	to	the	Waterford	3	steam	generator	replacement	project	in	2012.	The	increase	is partially	offset	by	various	nuclear	projects	in	2011;

•higher	distribution	construction	expenditures	due	to	Hurricane	Isaac;	and

•the	purchase	of	the	Acadia	Unit	2	for	approximately	$300	million	in	April	2011;

•a	decrease	in	nuclear	fuel	activity	because	of	variations	from	year	to	year	in	the	timing	and	pricing	of	fuel	reload	requirements	in	the Utility	business,	material	and	services	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle; •a	decrease	in	transmission	construction	expenditures	due	to	increased	work	performed	in	2011;	and •receipts	of	$13.7	million	in	2012	from	the	storm	reserve	escrow	account.

Increases	in	Entergy	Louisiana's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Louisiana's	receivable	from	the money	pool	increased	by	$9.4	million	in	2012	compared	to	decreasing	by	$49.9	million	in	2011.	The	money	pool	is	an	inter-company	borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Entergy	Louisiana's	financing	activities	used	$28	million	of	cash	in	2013	compared	to	providing	$432.4	million	of	cash	in	2012	primarily due	to:

•an	increase	of	$340.7	million	in	common	equity	distributions	in	2013;

•the	net	issuance	of	$386.9	million	of	long-term	debt	in	2013	compared	to	the	net	issuance	of	$613.1	million	of	long-term	debt	in	2012;	and •money	pool	activity.

Decreases	in	Entergy	Louisiana's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Louisiana's	payable	to	the	money	pool decreased	by	$118.4	million	in	2012.

Net	cash	provided	by	financing	activities	increased	$222.9	million	in	2012	primarily	due	to:

•a	decrease	of	$342.6	million	in	common	equity	distributions	in	2012;

•the	net	issuance	of	$613.1	million	of	long-term	debt	in	2012	compared	to	the	net	issuance	of	$384.9	million	of	long-term	debt	in	2011; •an	increase	in	borrowings	of	$10.3	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2012	compared	to	an increase	in	borrowings	of	$21.3	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2011;

•borrowings	of	$50	million	on	Entergy	Louisiana's	credit	facility	in	2011	and	the	repayment	of	credit	facility	borrowings	of	$50	million	in 2012;	and

Decreases	in	Entergy	Louisiana's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Louisiana's	payable	to	the	money	pool decreased	by	$118.4	million	in	2012	compared	to	increasing	by	$118.4	million	in	2011.

Entergy	Louisiana's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.	The	increase	in	the	debt	to	capital ratio	for	Entergy	Louisiana	is	primarily	due	to	an	increase	in	long-term	debt	as	a	result	of	the	issuance	of	$100	million	of	4.70%	Series	first mortgage	bonds	in	May	2013	and	$325	million	of	4.05%	Series	first	mortgage	bonds	in	August	2013.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 52.0% | 48.4% |
| Effect\tof\texcluding\tsecuritization\tbonds | (1.3%) | (1.6%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 50.7% | 46.8% |
| Effect\tof\tsubtracting\tcash | (1.1%) | (0.3%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 49.6% | 46.5% |

(a) Calculation	excludes	the	securitization	bonds,	which	are	non-recourse	to	Entergy	Louisiana.

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.		Debt	consists	of	short-term	borrowings	and	long-term	debt,	including	the	currently maturing	portion.		Capital	consists	of	debt,	preferred	stock	without	sinking	fund,	and	common	equity.		Net	capital	consists	of	capital	less	cash	and cash	equivalents.		Entergy	Louisiana	uses	the	debt	to	capital	ratio	in	analyzing	its	financial	condition	and	believes	it	provides	useful	information	to its	 investors	 and	 creditors	 in	 evaluating	 Entergy	 Louisiana's	 financial	 condition.	Entergy	Louisiana	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	evaluation	Entergy	Louisiana's financial	condition	because	net	debt	indicates	Entergy	Louisiana's	outstanding	debt	position	that	could	not	be	readily	satisfied	by	cash	and	cash equivalents.

Entergy	Louisiana	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Louisiana's	planned	construction	and	other	capital	investments.

| Generation | $240 | $220 | $105 |
| :--- | :--- | :--- | :--- |
| Transmission | 140 | 80 | 70 |
| Distribution | 135 | 115 | 130 |
| Other | 20 | 20 | 15 |
| Total | $535 | $435 | $320 |

Following	are	the	amounts	of	Entergy	Louisiana's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | After	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $473 | $337 | $695 | $3,947 | $5,452 |
| Operating\tleases | $11 | $16 | $8 | $4 | $39 |
| Purchase\tobligations\t(b) | $573 | $986 | $1,094 | $5,357 | $8,010 |

(b) 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	financial	statements.

In	addition	to	the	contractual	obligations	given	above,	Entergy	Louisiana	currently	expects	to	contribute	approximately	$52.9	million	to	its pension	plans	and	approximately	$11	million	to	other	postretirement	plans	in	2014	although	the	required	pension	contributions	will	not	be	known with	more	certainty	until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.	See	"Critical	Accounting	Estimates	 -	 Qualified Pension	and	Other	Postretirement	Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	Louisiana	includes specific	investments	and	initiatives	such	as	the	Ninemile	6	self-build	project	which	is	discussed	below,	NRC	post-Fukushima	requirements,	and transmission	 spending	 to	 support	 economic	 development	 projects,	 reliability,	 and	 new	 compliance	 projects.	 	 Entergy's	 Utility	 supply	 plan initiative	will	continue	to	seek	to	transform	its	generation	portfolio	with	new	or	repowered	generation	resources.	Opportunities	resulting	from	the supply	plan	initiative,	including	new	projects	or	the	exploration	of	alternative	financing	sources,	could	result	in	increases	or	decreases	in	the capital	expenditure	estimates	given	above.	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,	changes	in project	plans,	and	the	ability	to	access	capital.

As	an	indirect,	wholly-owned	subsidiary	of	Entergy	Corporation,	Entergy	Louisiana	pays	distributions	from	its	earnings	at	a	percentage determined	monthly.	Entergy	Louisiana's	long-term	debt	indenture	contains	restrictions	on	the	payment	of	cash	dividends	or	other	distributions	on its	common	and	preferred	membership	interests.

In	June	2011,	Entergy	Louisiana	filed	with	the	LPSC	an	application	seeking	certification	that	the	public	necessity	and	convenience	would be	served	by	Entergy	Louisiana's	construction	of	a	combined-cycle	gas	turbine	generating	facility	(Ninemile	6)	at	its	existing	Ninemile	Point electric	generating	station.	Ninemile	6	will	be	a	nominally-sized	550	MW	unit	that	is	estimated	to	cost	approximately	$721	million	to	construct, excluding	interconnection	and	transmission	upgrades.	Entergy	Gulf	States	Louisiana	joined	in	the	application,	seeking	certification	of	its	purchase under	a	life-of-unit	power	purchase	agreement	of	up	to	25%	of	the	capacity	and	energy	generated	by	Ninemile	6.	The	Ninemile	6	capacity	and energy	is	proposed	to	be	allocated	55%	to	Entergy	Louisiana,	25%	to	Entergy	Gulf	States	Louisiana,	and	20%	to	Entergy	New	Orleans.	In February	2012	the	City	Council	passed	a	resolution	authorizing	Entergy	New	Orleans	to	purchase	20%	of	the	Ninemile	6	energy	and	capacity.	In March	 2012	 the	 LPSC	 unanimously	 voted	 to	 grant	 the	 certifications	 requested	 by	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana. Following	approval	by	the	LPSC,	Entergy	Louisiana	issued	full	notice	to	proceed	to	the	project's	engineering,	procurement,	and	construction

contractor.	All	major	permits	and	approvals	required	to	begin	construction	have	been	obtained	and	construction	is	in	progress.

In	March	2010,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	with	the	LPSC	seeking	approval	to	continue	the	limited development	activities	necessary	to	preserve	an	option	to	construct	a	new	unit	at	River	Bend.	The	testimony	and	legal	briefs	of	the	LPSC	staff generally	support	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana,	although	other	parties	filed	briefs,	without	supporting testimony,	in	opposition	to	the	request.	At	an	evidentiary	hearing	in	October	2011,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	and	the LPSC	staff	presented	testimony	in	support	of	certification	of	activities	to	preserve	an	option	for	a	new	nuclear	plant	at	River	Bend.	The	ALJ recommended,	however,	that	the	LPSC	decline	the	request	of	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	on	the	basis	that	the	LPSC's rule	on	new	nuclear	development	does	not	apply	to	activities	to	preserve	an	option	to	develop	and	on	the	further	grounds	that	the	companies improperly	engaged	in	advanced	preparation	activities	prior	to	certification.	There	has	been	no	suggestion	that	the	planning	activities	or	costs incurred	 were	 imprudent.	At	its	June	28,	2012	meeting	the	LPSC	voted	to	uphold	the	ALJ's	decision	and	directed	that	Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	be	permitted	to	seek	recovery	of	these	costs	in	their	anticipated,	upcoming	rate	case	filings,	fully	reserving	the LPSC's	right	to	determine	the	recoverability	of	such	costs	in	rates.	The	LPSC	decided	to	extend	the	current	formula	rate	plans	of	Entergy	Gulf States	 Louisiana	 and	 Entergy	 Louisiana	 and	 provided	 for	 an	 eight-year	 amortization	 of	 costs	 incurred	 in	 connection	 with	 the	 potential development	of	a	new	nuclear	unit	at	River	Bend,	without	carrying	costs,	beginning	in	December	2014,	provided,	however,	that	amortization	of these	costs	shall	not	result	in	a	future	rate	increase.	As	of	December	31,	2013,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	each	have	a regulatory	asset	of	$29.5	million	on	its	balance	sheet	related	to	these	new	nuclear	generation	development	costs.

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

•bank	financing	under	new	and	existing	facilities.

Entergy	Louisiana	may	refinance,	redeem,	or	otherwise	retire	debt	and	preferred	membership	interests	prior	to	maturity,	to	the	extent market	conditions	and	interest	and	distribution	rates	are	favorable.

All	debt	and	common	and	preferred	membership	interest	issuances	by	Entergy	Louisiana	require	prior	regulatory	approval.	Preferred membership	interest	and	debt	issuances	are	also	subject	to	issuance	tests	set	forth	in	its	bond	indentures	and	other	agreements.	Entergy	Louisiana has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital	needs.

Entergy	Louisiana's	receivables	from	or	(payables	to)	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years.

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $17,648 | $9,433 | ($118,415) | $49,887 |

Entergy	Louisiana	has	a	credit	facility	in	the	amount	of	$200	million	scheduled	to	expire	in	March	2018.	The	credit	facility	allows	Entergy Louisiana	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2013,	there	were	no	cash	borrowings and	$7	million	of	letters	of	credit	outstanding	under	the	credit	facility.	See	Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit facility.

The	Entergy	Louisiana	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	$90	million	scheduled	to	expire in	June	2016.	As	of	December	31,	2013,	$2.9	million	of	letters	of	credit	was	outstanding	under	the	credit	facility	to	support	a	like	amount	of commercial	paper	issued	by	the	Entergy	Louisiana	nuclear	fuel	company	variable	interest	entity.	See	Note	4	to	the	financial	statements	for additional	discussion	of	the	nuclear	fuel	company	variable	interest	entity	credit	facility.

Entergy	Louisiana	obtained	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow	through	October	2015,	up	the aggregate	 amount,	 at	 any	 one	 time	 outstanding,	 of	 $250	 million.	See	 Note	 4	 to	 the	 financial	 statements	 for	 further	 discussion	 of	 Entergy Louisiana's	short-term	borrowing	limits.	Entergy	Louisiana	has	also	obtained	an	order	from	the	FERC	authorizing	long-term	securities	issuances through	October	2015.	Entergy	Louisiana	has	also	obtained	long-term	financing	authorization	from	the	FERC	that	extends	through	October	2015 for	issuances	by	its	nuclear	fuel	company	variable	interest	entity.

In	August	2012,	Hurricane	Isaac	caused	extensive	damage	to	Entergy	Louisiana's	service	area.	The	storm	resulted	in	widespread	power outages,	significant	damage	primarily	to	distribution	infrastructure,	and	the	loss	of	sales	during	the	power	outages.	In	April	2013,	Entergy	Gulf States	Louisiana	and	Entergy	Louisiana	filed	a	joint	application	with	the	LPSC	relating	to	Hurricane	Isaac	system	restoration	costs.		Specifically, Entergy	Louisiana	requested	that	the	LPSC	determine	the	amount	of	such	costs	that	were	prudently	incurred	and	are,	thus,	eligible	for	recovery from	customers.		Including	carrying	costs	and	additional	storm	escrow	funds,	Entergy	Louisiana	is	seeking	determination	that	$247.7	million	in system	restoration	costs	were	prudently	incurred.		Entergy	Louisiana	intends	to	replenish	its	storm	escrow	accounts	to	$200	million	primarily through	traditional	debt	markets	and	has	requested	special	rate	treatment	of	any	borrowings	for	that	purpose.		In	May	2013,	Entergy	Louisiana filed	 a	 supplemental	 application	 proposing	 a	 specific	 means	 to	 finance	 system	 restoration	 costs	 and	 related	 requests.	Entergy	 Louisiana	 is proposing	to	finance	Hurricane	Isaac	restoration	costs	through	Louisiana	Act	55	financing,	which	was	the	same	method	it	used	for	Hurricanes Katrina,	Rita,	Gustav,	and	Ike.

The	LPSC	Staff	filed	direct	testimony	in	September	2013	concluding	that	Hurricane	Isaac	system	restoration	costs	incurred	by	Entergy Gulf	States	Louisiana	and	Entergy	Louisiana	were	reasonable	and	prudent,	subject	to	proposed	minor	adjustments	which	totaled	approximately 1%	of	each	company's	costs.	The	LPSC	Staff	also	supported	the	requests	to	re-establish	storm	reserves	of	$90	million	for	Entergy	Gulf	States Louisiana	and	$200	million	for	Entergy	Louisiana.	One	intervenor	filed	testimony	recommending	storm	reserve	levels	of	$70	million	for	Entergy Gulf	States

Louisiana	and	$100	million	for	Entergy	Louisiana,	but	takes	no	position	on	the	prudence	of	the	Hurricane	Isaac	system	restoration	costs.	An evidentiary	hearing	took	place	in	December	2013,	and	an	LPSC	decision	is	expected	in	2014.

# Little	Gypsy	Repowering	Project

In	April	2007,	Entergy	Louisiana	announced	that	it	intended	to	pursue	the	solid	fuel	repowering	of	a	538	MW	unit	at	its	Little	Gypsy plant.	In	March	2009	the	LPSC	voted	in	favor	of	a	motion	directing	Entergy	Louisiana	to	temporarily	suspend	the	repowering	project	and,	based upon	an	analysis	of	the	project's	economic	viability,	to	make	a	recommendation	regarding	whether	to	proceed	with	the	project.	This	action	was based	upon	a	number	of	factors	including	the	recent	decline	in	natural	gas	prices,	as	well	as	environmental	concerns,	the	unknown	costs	of	carbon legislation	and	changes	in	the	capital/financial	markets.	In	April	2009,	Entergy	Louisiana	complied	with	the	LPSC's	directive	and	recommended that	the	project	be	suspended	for	an	extended	period	of	time	of	three	years	or	more.	In	May	2009	the	LPSC	issued	an	order	declaring	that	Entergy Louisiana's	decision	to	place	the	Little	Gypsy	project	into	a	longer-term	suspension	of	three	years	or	more	is	in	the	public	interest	and	prudent.

In	October	2009,	Entergy	Louisiana	made	a	filing	with	the	LPSC	seeking	permission	to	cancel	the	Little	Gypsy	repowering	project	and seeking	project	cost	recovery	over	a	five-year	period.	In	June	2010	and	August	2010,	the	LPSC	Staff	and	Intervenors	filed	testimony.	The	LPSC Staff	(1)	agreed	that	it	was	prudent	to	move	the	project	from	long-term	suspension	to	cancellation	and	that	the	timing	of	the	decision	to	suspend	on a	longer-term	basis	was	not	imprudent;	(2)	indicated	that,	except	for	$0.8	million	in	compensation-related	costs,	the	costs	incurred	should	be deemed	prudent;	(3)	recommended	recovery	from	customers	over	ten	years	but	stated	that	the	LPSC	may	want	to	consider	15	years;	(4)	allowed for	recovery	of	carrying	costs	and	earning	a	return	on	project	costs,	but	at	a	reduced	rate	approximating	the	cost	of	debt,	while	also	acknowledging that	the	LPSC	may	consider	ordering	no	return;	and	(5)	indicated	that	Entergy	Louisiana	should	be	directed	to	securitize	project	costs,	if	legally feasible	and	in	the	public	interest.	In	the	third	quarter	2010,	in	accordance	with	accounting	standards,	Entergy	Louisiana	determined	that	it	was probable	 that	 the	 Little	 Gypsy	 repowering	 project	 would	 be	 abandoned	 and	 accordingly	 reclassified	 $199.8	 million	 of	 project	 costs	 from construction	work	in	progress	to	a	regulatory	asset.	A	hearing	on	the	issues,	except	for	cost	allocation	among	customer	classes,	was	held	before the	ALJ	in	November	2010.	In	January	2011	all	parties	participated	in	a	mediation	on	the	disputed	issues,	resulting	in	a	settlement	of	all	disputed issues,	including	cost	recovery	and	cost	allocation.	The	settlement	provides	for	Entergy	Louisiana	to	recover	$200	million	as	of	March	31,	2011, and	carrying	costs	on	that	amount	on	specified	terms	thereafter.	The	settlement	also	provides	for	Entergy	Louisiana	to	recover	the	approved project	 costs	 by	 securitization.	In	April	 2011,	 Entergy	 Louisiana	 filed	 an	 application	 with	 the	 LPSC	 to	 authorize	 the	 securitization	 of	 the investment	 recovery	 costs	 associated	 with	 the	 project	 and	 to	 issue	 a	 financing	 order	 by	 which	 Entergy	 Louisiana	 could	 accomplish	 such securitization.	In	August	2011	the	LPSC	issued	an	order	approving	the	settlement	and	also	issued	a	financing	order	for	the	securitization.	See	Note 5	to	the	financial	statements	for	a	discussion	of	the	September	2011	issuance	of	the	securitization	bonds.

The	rates	that	Entergy	Louisiana	charges	for	its	services	significantly	influence	its	financial	position,	results	of	operations,	and	liquidity. Entergy	Louisiana	is	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	May	2005	the	LPSC	approved	a	rate	filing	settlement	that	included	the	adoption	of	a	three-year	formula	rate	plan,	the	terms	of	which included	an	ROE	mid-point	of	10.25%	for	the	initial	three-year	term	of	the	plan	and	permit	Entergy	Louisiana	to	recover	incremental	capacity costs	outside	of	a	traditional	base	rate	proceeding.	Under	the	formula	rate	plan,	over-	and	under-earnings	outside	an	allowed	regulatory	range	of 9.45%	to	11.05%	will	be	allocated	60%	to	customers	and	40%	to	Entergy	Louisiana.	The	initial	formula	rate	plan	filing	was	made	in	May	2006. As	discussed	below	the	formula	rate	plan	has	been	extended,	with	return	on	common	equity	provisions	consistent	with	previously	approved provisions,	to	cover	the	2008,	2009,	2010,	and	2011	test	years.

In	November	2011	the	LPSC	approved	a	one-year	extension	of	Entergy	Louisiana's	formula	rate	plan.		In	May	2012,	Entergy	Louisiana made	its	formula	rate	plan	filing	with	the	LPSC	for	the	2011	test	year.		The	filing	reflected	a	9.63%	earned	return	on	common	equity,	which	is within	the	earnings	bandwidth	and	resulted	in	no	cost	of	service	rate	change	under	the	formula	rate	plan.		The	filing	also	reflected	an	$18.1	million rate	increase	for	the	incremental	capacity	rider.		In	August	2012,	Entergy	Louisiana	submitted	a	revised	filing	that	reflected	an	earned	return	on common	equity	of	10.38%,	which	is	still	within	the	earnings	bandwidth,	resulting	in	no	cost	of	service	rate	change.		The	revised	filing	also indicated	that	an	increase	of	$15.9	million	should	be	reflected	in	the	incremental	capacity	rider.		The	rate	change	was	implemented,	subject	to refund,	effective	for	bills	rendered	the	first	billing	cycle	of	September	2012.		Subsequently,	in	December	2012,	Entergy	Louisiana	submitted	a revised	evaluation	report	that	reflected	two	items:	1)	a	$17	million	reduction	for	the	first-year	capacity	charges	for	the	purchase	by	Entergy	Gulf States	Louisiana	from	Entergy	Louisiana	of	one-third	of	Acadia	Unit	2	capacity	and	energy,	and	2)	an	$88	million	increase	for	the	first-year	retail revenue	requirement	associated	with	the	Waterford	3	replacement	steam	generator	project,	which	was	in-service	in	December	2012.		These	rate changes	were	implemented,	subject	to	refund,	effective	with	the	first	billing	cycle	of	January	2013.		In	April	2013,	Entergy	Louisiana	and	the LPSC	staff	filed	a	joint	report	resolving	the	2011	test	year	formula	rate	plan	and	recovery	related	to	the	Grand	Gulf	uprate.	This	report	was approved	 by	 the	 LPSC	 in	April	 2013.	With	completion	of	the	Waterford	3	replacement	steam	generator	project,	the	LPSC	is	conducting	a prudence	review	in	connection	with	a	filing	made	by	Entergy	Louisiana	in	April	2013	with	regard	to	the	following	aspects	of	the	replacement project:	1)	project	management;	2)	cost	controls;	3)	success	in	achieving	stated	objectives;	4)	the	costs	of	the	replacement	project;	and	5)	the outage	length	and	replacement	power	costs.	An	evidentiary	hearing	is	scheduled	for	November	2014.

In	April	2010	the	LPSC	authorized	its	staff	to	initiate	an	audit	of	Entergy	Louisiana's	fuel	adjustment	clause	filings.		The	audit	includes	a review	of	the	reasonableness	of	charges	flowed	through	the	fuel	adjustment	clause	by	Entergy	Louisiana	for	the	period	from	2005	through 2009.		The	LPSC	Staff	issued	its	audit	report	in	January	2013.		The	LPSC	staff	recommended	that	Entergy	Louisiana	refund	approximately	$1.9 million,	plus	interest,	to	customers	and	realign	the	recovery	of	approximately	$1.0	million	from	Entergy	Louisiana's	fuel	adjustment	clause	to	base rates.		The	recommended	refund	was	made	by	Entergy	Louisiana	in	May	2013	in	the	form	of	a	credit	to	customers	through	its	fuel	adjustment clause	filing.	Two	parties	intervened	in	the	proceeding.	A	procedural	schedule	was	established	for	the	identification	of	issues	by	the	intervenors and	for	Entergy	Louisiana	to	submit	comments	regarding	the	LPSC	Staff	report	and	any	issues	raised	by	intervenors.	One	intervenor	is	seeking further	proceedings	regarding	certain	issues	it	raised	in	its	comments	on	the	LPSC	Staff	report.	Entergy	Louisiana	has	filed	responses	to	both	the LPSC	Staff	report	and	the	issues	raised	by	the	intervenor.	As	required	by	the	procedural	schedule,	a	joint	status	report	was	submitted	in	October 2013	by	 the	parties.	That	report	requests	that	a	status	conference	be	convened	by	the	ALJ	to	address	open	issues,	including	whether	further proceedings	will	be	required.	A	status	conference	was	held	in	December	2013.	Discovery	is	in	progress,	but	a	procedural	schedule	has	not	been established.

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.	Entergy	 Louisiana	 actively	 participates	 in	 economic	 development,	 customer	 retention,	 and	 reclamation	 activities	 to	 increase industrial	and	commercial	demand,	from	both	new	and	existing	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	owns	and,	through	an	affiliate,	operates	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,	regulatory	requirement	changes,	including	changes	resulting	from	events	at	other	plants,	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.

The	nuclear	industry	continues	to	address	susceptibility	to	stress	corrosion	cracking	of	certain	materials	within	the	reactor	coolant	system. The	issue	is	applicable	to	Waterford	3	and	is	managed	in	accordance	with	industry	standard	practices	and	guidelines	which	include	in-service examinations,	replacements,	and	mitigation	strategies.		Developments	in	the	industry	or	identification	of	issues	at	the	nuclear	units	could	require unanticipated	remediation	efforts	that	cannot	be	quantified	in	advance.

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	 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	that	could	produce	estimates	that	would	have	a	material	effect	on	the	presentation	of	Entergy	Louisiana's	financial	position	or results	of	operations.

In	the	fourth	quarter	2013,	Entergy	Louisiana	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Waterford	3	as	a	result of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$39.4	million	increase	in	its	decommissioning	cost	liability,	along with	a	corresponding	increase	in	the	related	asset	retirement	costs	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

In	the	second	quarter	2012,	Entergy	Louisiana	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Waterford	3	as	a result	of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$48.9	million	increase	in	its	decommissioning	cost	liability, along	with	a	corresponding	increase	in	the	related	asset	retirement	obligation	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

As	discussed	in	Note	1	to	the	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.		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.

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Qualified	Pension	Cost | Impact	on	2013<br>Projected	Qualified	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $2,655 | $25,365 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $1,230 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $1,095 | $4,575 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Impact	on	2013	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $446 | $5,077 |
| Health\tcare\tcost\ttrend | 0.25% | $891 | $4,336 |

Total	qualified	pension	cost	for	Entergy	Louisiana	in	2013	was	$49.3	million,	including	a	$3.5	million	curtailment	charge	and	a	$1.6 million	special	termination	charge	related	to	workforce	downsizing.	 	Entergy	Louisiana	anticipates	2014	qualified	pension	cost	to	be	$30.8 million.		Entergy	Louisiana	contributed	$21.2	million	to	its	pension	plans	in	2013	and	estimates	2014	pension	contributions	to	be	approximately $52.9	million;	although	 the	required	pension	contributions	will	not	be	known	with	more	certainty	until	 the	January	1,	2014	valuations	are completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Louisiana	in	2013	were	$24.3	million,	including	a	$1.8 million	curtailment	charge	related	to	workforce	downsizing.			Entergy	Louisiana	expects	2014	postretirement	health	care	and	life	insurance	benefit costs	to	approximate	$10.9	million.		Entergy	Louisiana	contributed	$9	million	to	its	other	postretirement	plans	in	2013	and	expects	to	contribute approximately	$11	million	in	2014.

See	"New	Accounting	Pronouncements"	 section	 of	 Entergy	 Corporation	 and	 Subsidiaries	 Management's	 Financial	 Discussion	 and Analysis.

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Louisiana,	LLC	and	Subsidiaries	(the	"Company")	as	of	December	31, 2013	and	2012	and	the	related	consolidated	income	statements,	consolidated	statements	of	comprehensive	income,	consolidated	statements	of cash	flows,	and	consolidated	statements	of	changes	in	equity	(pages	349	through	354	and	applicable	items	in	pages	57	through	217)	for	each	of	the three	years	 in	 the	period	ended	December	31,	2013.	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	consolidated	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Louisiana,	LLC	and Subsidiaries	as	of	December	31,	2013	and	2012,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period ended	December	31,	2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $2,626,935 | $2,149,443 | $2,508,915 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 570,956 | 360,964 | 596,808 |
| Purchased\tpower | 850,998 | 728,170 | 843,099 |
| Nuclear\trefueling\toutage\texpenses | 34,566 | 24,344 | 27,903 |
| Other\toperation\tand\tmaintenance | 480,166 | 449,172 | 470,783 |
| Decommissioning | 21,612 | 23,406 | 24,658 |
| Taxes\tother\tthan\tincome\ttaxes | 74,241 | 69,186 | 69,769 |
| Depreciation\tand\tamortization | 242,787 | 218,140 | 206,986 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (3,785) | 127,050 | 182,800 |
| TOTAL | 2,271,541 | 2,000,432 | 2,422,806 |
| OPERATING\tINCOME | 355,394 | 149,011 | 86,109 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 31,544 | 39,610 | 33,033 |
| Interest\tand\tinvestment\tincome | 91,599 | 84,478 | 87,487 |
| Miscellaneous\t-\tnet | (3,990) | (2,584) | (3,520) |
| TOTAL | 119,153 | 121,504 | 117,000 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 153,529 | 136,967 | 116,803 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (13,323) | (18,611) | (17,406) |
| TOTAL | 140,206 | 118,356 | 99,397 |
| INCOME\tBEFORE\tINCOME\tTAXES | 334,341 | 152,159 | 103,712 |
| Income\ttaxes | 81,877 | (128,922) | (370,211) |
| NET\tINCOME | 252,464 | 281,081 | 473,923 |
| Preferred\tdistribution\trequirements\tand\tother | 6,950 | 6,950 | 6,950 |
| EARNINGS\tAPPLICABLE\tTO |  |  |  |
| COMMON\tEQUITY | $245,514 | $274,131 | $466,973 |

| ENTERGY	LOUISIANA,	LLC	AND	SUBSIDIARIES | ENTERGY	LOUISIANA,	LLC	AND	SUBSIDIARIES |  |  |
| :--- | :--- | :--- | :--- |
| CONSOLIDATED\tSTATEMENTS\tOF\tCOMPREHENSIVE\tINCOME | CONSOLIDATED\tSTATEMENTS\tOF\tCOMPREHENSIVE\tINCOME |  |  |
|  | For\tthe\tYears\tEnded\tDecember\t31, | For\tthe\tYears\tEnded\tDecember\t31, | For\tthe\tYears\tEnded\tDecember\t31, |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| Net\tIncome | $252,464 | $281,081 | $473,923 |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t$30,591,\t$5,095,\tand\t($7,363)) | 36,497 | (6,625) | (14,545) |
| Other\tcomprehensive\tincome\t(loss) | 36,497 | (6,625) | (14,545) |
| Comprehensive\tIncome | $288,961 | $274,456 | $459,378 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $252,464 | $281,081 | $473,923 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 337,333 | 293,774 | 288,459 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 310,964 | (59,069) | (327,046) |
| Changes\tin\tworking\tcapital: |  |  |  |
| Receivables | (121,118) | 43,850 | (50,014) |
| Fuel\tinventory | 272 | 336 | (23,916) |
| Accounts\tpayable | (29,151) | 40,085 | 21,489 |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (176,566) | (39,275) | 56,348 |
| Interest\taccrued | 4,808 | 729 | 4,646 |
| Deferred\tfuel\tcosts | 56,960 | (93,103) | 7,308 |
| Other\tworking\tcapital\taccounts | 41,693 | (79,771) | 34,824 |
| Changes\tin\tprovisions\tfor\testimated\tlosses | (188,741) | (16,586) | (10,496) |
| Changes\tin\tother\tregulatory\tassets | 111,049 | (116,249) | (95,909) |
| Changes\tin\tother\tregulatory\tliabilities | 156,446 | 81,259 | 206,643 |
| Changes\tin\tpension\tand\tother\tpostretirement\tliabilities | (180,601) | 80,027 | 114,489 |
| Other | 86,960 | 30,610 | (221,406) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 662,772 | 447,698 | 479,342 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (711,470) | (787,075) | (433,876) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 31,544 | 39,610 | 33,033 |
| Nuclear\tfuel\tpurchases | (51,016) | (159,501) | (155,932) |
| Proceeds\tfrom\tthe\tsale\tof\tnuclear\tfuel | 23,438 | 62,248 | 11,570 |
| Payment\tfor\tpurchase\tof\tplant | — | — | (299,589) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 187,008 | 14,478 | — |
| Changes\tto\tsecuritization\taccount | (157) | 818 | (5,200) |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 109,856 | 27,577 | 19,909 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (121,773) | (39,374) | (30,728) |
| Change\tin\tmoney\tpool\treceivable\t-\tnet | (8,215) | (9,433) | 49,887 |
| Other | (22) | (214) | (277) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (540,807) | (850,866) | (811,203) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 417,740 | 663,975 | 1,170,441 |
| Retirement\tof\tlong-term\tdebt | (30,846) | (50,899) | (785,547) |
| Change\tin\tmoney\tpool\tpayable\t-\tnet | — | (118,415) | 118,415 |
| Changes\tin\tcredit\tborrowings\t-\tnet | (51,734) | (39,735) | 71,326 |
| Distributions\tpaid: |  |  |  |
| Common\tequity | (356,254) | (15,600) | (358,200) |
| Preferred\tmembership\tinterests | (6,950) | (6,950) | (6,950) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (28,044) | 432,376 | 209,485 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 93,921 | 29,208 | (122,376) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 30,086 | 878 | 123,254 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $124,007 | $30,086 | $878 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $143,257 | $130,934 | $108,072 |
| Income\ttaxes | ($33,622) | ($41,423) | ($39,555) |

| Cash | $427 | $814 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 123,580 | 29,272 |
| Total\tcash\tand\tcash\tequivalents | 124,007 | 30,086 |
| Securitization\trecovery\ttrust\taccount | 4,539 | 4,382 |
| Accounts\treceivable: |  |  |
| Customer | 144,836 | 86,072 |
| Allowance\tfor\tdoubtful\taccounts | (965) | (867) |
| Associated\tcompanies | 87,820 | 42,938 |
| Other | 21,420 | 9,354 |
| Accrued\tunbilled\trevenues | 93,073 | 79,354 |
| Total\taccounts\treceivable | 346,184 | 216,851 |
| Accumulated\tdeferred\tincome\ttaxes | 100,022 | 113,319 |
| Deferred\tfuel\tcosts | — | 26,568 |
| Fuel\tinventory | 23,311 | 23,583 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 156,487 | 152,170 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 13,670 | 44,457 |
| Prepaid\ttaxes | 184,503 | 7,937 |
| Gas\thedge\tcontracts | 2,889 | — |
| Prepayments\tand\tother | 15,223 | 12,129 |
| TOTAL | 970,835 | 631,482 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliate\tpreferred\tmembership\tinterests | 807,423 | 807,423 |
| Decommissioning\ttrust\tfunds | 347,274 | 287,418 |
| Storm\treserve\tescrow\taccount | — | 186,985 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 396 | 578 |
| TOTAL | 1,155,093 | 1,282,404 |
| UTILITY\tPLANT |  |  |
| Electric | 8,799,393 | 8,603,319 |
| Property\tunder\tcapital\tlease | 331,895 | 324,440 |
| Construction\twork\tin\tprogress | 672,883 | 404,714 |
| Nuclear\tfuel | 147,385 | 204,019 |
| TOTAL\tUTILITY\tPLANT | 9,951,556 | 9,536,492 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 3,763,234 | 3,590,146 |
| UTILITY\tPLANT\t-\tNET | 6,188,322 | 5,946,346 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 309,617 | 193,114 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof |  |  |
| $156,103\tas\tof\tDecember\t31,\t2013\tand |  |  |
| $172,838\tas\tof\tDecember\t31,\t2012) | 715,503 | 913,562 |
| Deferred\tfuel\tcosts | 67,998 | 67,998 |
| Other | 43,025 | 39,178 |
| TOTAL | 1,136,143 | 1,213,852 |
| TOTAL\tASSETS | $9,450,393 | $9,074,084 |

| Currently	maturing	long-term	debt | $320,231 | $14,236 |
| :--- | :--- | :--- |
| Short-term\tborrowings | 2,923 | 54,657 |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 83,655 | 103,454 |
| Other | 162,507 | 266,904 |
| Customer\tdeposits | 90,393 | 88,805 |
| Accumulated\tdeferred\tincome\ttaxes | 338 | — |
| Interest\taccrued | 42,072 | 37,264 |
| Deferred\tfuel\tcosts | 30,392 | — |
| Pension\tand\tother\tpostretirement\tliabilities | 10,255 | 9,170 |
| System\tagreement\tcost\tequalization | 17,000 | — |
| Gas\thedge\tcontracts | — | 3,442 |
| Other | 19,443 | 13,382 |
| TOTAL | 779,209 | 591,314 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,275,584 | 930,606 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 67,347 | 70,193 |
| Other\tregulatory\tliabilities | 533,247 | 376,801 |
| Decommissioning | 479,086 | 418,122 |
| Accumulated\tprovisions | 7,733 | 196,474 |
| Pension\tand\tother\tpostretirement\tliabilities | 358,017 | 539,703 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof |  |  |
| $164,965\tas\tof\tDecember\t31,\t2013\tand |  |  |
| $181,553\tas\tof\tDecember\t31,\t2012) | 2,899,285 | 2,811,859 |
| Other | 75,233 | 68,516 |
| TOTAL | 5,695,532 | 5,412,274 |
| Commitments\tand\tContingencies |  |  |
| EQUITY |  |  |
| Preferred\tmembership\tinterests\twithout\tsinking\tfund | 100,000 | 100,000 |
| Member's\tequity | 2,885,287 | 3,016,628 |
| Accumulated\tother\tcomprehensive\tloss | (9,635) | (46,132) |
| TOTAL | 2,975,652 | 3,070,496 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $9,450,393 | $9,074,084 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 | For	the	Years	Ended	December	31,	2013,	2012,	and	2011 | For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Common\tEquity | Common\tEquity |  |
|  | Preferred\nMembership\nInterests | Member's\nEquity | Accumulated\tOther\nComprehensive\nIncome\t(Loss) | Total |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2010 | $100,000 | $2,061,833 | ($24,962) | $2,136,871 |
| Net\tincome | — | 473,923 | — | 473,923 |
| Additional\tcontribution\tfrom\tparent | — | 333,830 | — | 333,830 |
| Other\tcomprehensive\tloss | — | — | (14,545) | (14,545) |
| Distributions\tto\tparent | — | (358,200) | — | (358,200) |
| Distributions\tdeclared\ton\tpreferred\tmembership\tinterests | — | (6,950) | — | (6,950) |
| Balance\tat\tDecember\t31,\t2011 | $100,000 | $2,504,436 | ($39,507) | $2,564,929 |
| Net\tincome | — | 281,081 | — | 281,081 |
| Additional\tcontribution\tfrom\tparent | — | 253,661 | — | 253,661 |
| Other\tcomprehensive\tloss | — | — | (6,625) | (6,625) |
| Distributions\tto\tparent | — | (15,600) | — | (15,600) |
| Distributions\tdeclared\ton\tpreferred\tmembership\tinterests | — | (6,950) | — | (6,950) |
| Balance\tat\tDecember\t31,\t2012 | $100,000 | $3,016,628 | ($46,132) | $3,070,496 |
| Net\tincome | — | 252,464 | — | 252,464 |
| Other\tcomprehensive\tincome | — | — | 36,497 | 36,497 |
| Distributions\tto\tparent | — | (376,855) | — | (376,855) |
| Distributions\tdeclared\ton\tpreferred\tmembership\tinterests | — | (6,950) | — | (6,950) |
| Balance\tat\tDecember\t31,\t2013 | $100,000 | $2,885,287 | ($9,635) | $2,975,652 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $2,626,935 | $2,149,443 | $2,508,915 | $2,538,766 | $2,183,586 |
| Net\tincome | $252,464 | $281,081 | $473,923 | $231,435 | $232,845 |
| Total\tassets | $9,450,393 | $9,074,084 | $8,063,867 | $7,488,423 | $6,861,903 |
| Long-term\tobligations\t(a) | $2,899,285 | $2,811,859 | $2,177,003 | $1,771,566 | $1,622,709 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $839 | $687 | $830 | $840 | $669 |
| Commercial | 586 | 482 | 549 | 543 | 456 |
| Industrial | 955 | 731 | 867 | 817 | 664 |
| Governmental | 46 | 38 | 42 | 42 | 36 |
| Total\tretail | $2,426 | $1,938 | $2,288 | $2,242 | $1,825 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 114 | 137 | 137 | 220 | 252 |
| Non-associated\tcompanies | 3 | 2 | 8 | 5 | 5 |
| Other | 84 | 72 | 76 | 72 | 102 |
| Total | $2,627 | $2,149 | $2,509 | $2,539 | $2,184 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 8,820 | 8,703 | 9,303 | 9,533 | 8,684 |
| Commercial | 6,194 | 6,112 | 6,155 | 6,164 | 5,867 |
| Industrial | 16,713 | 16,416 | 15,813 | 14,473 | 13,386 |
| Governmental | 495 | 479 | 473 | 479 | 459 |
| Total\tretail | 32,222 | 31,710 | 31,744 | 30,649 | 28,396 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 1,844 | 2,156 | 2,145 | 2,860 | 1,513 |
| Non-associated\tcompanies | 92 | 65 | 185 | 101 | 109 |
| Total | 34,158 | 33,931 | 34,074 | 33,610 | 30,018 |

# ENTERGY	MISSISSIPPI,	INC.

Net	income	increased	$35.4	million	primarily	due	to	higher	net	revenue	and	a	lower	effective	income	tax	rate,	partially	offset	by	higher other	operation	and	maintenance	expenses.

Net	income	decreased	$62.0	million	primarily	due	to	a	higher	effective	income	tax	rate	and	higher	other	operation	and	maintenance expenses.

|  | Amount |
| :--- | :--- |
|  | (In\tMillions) |
| 2012\tnet\trevenue | $578.0 |
| Retail\telectric\tprice | 55.1 |
| Reserve\tequalization | 8.0 |
| Other | 3.3 |
| 2013\tnet\trevenue | $644.4 |

The	retail	electric	price	variance	is	primarily	due	to	the	recovery	of	Hinds	plant	costs	through	the	power	management	rider,	as	approved by	the	MPSC,	effective	with	the	first	billing	cycle	of	2013	and	a	formula	rate	plan	increase	effective	September	2013.	The	net	income	effect	of	the Hinds	plant	cost	recovery	is	limited	to	a	portion	representing	an	allowed	return	on	equity	on	the	net	plant	investment	with	the	remainder	offset	by the	Hinds	plant	costs	in	other	operation	and	maintenance	expenses,	depreciation	expenses,	and	taxes	other	than	income	taxes.		The	increase	is partially	offset	by	a	temporary	increase	in	2012	in	the	storm	cost	recovery	rider,	as	approved	by	the	MPSC	for	a	five-month	period	effective August	2012.		This	temporary	increase	in	revenues	in	2012	was	offset	by	costs	included	in	other	operation	and	maintenance	expenses	and	had	no effect	on	net	income.	See	Note	2	to	the	financial	statements	for	discussion	of	the	formula	rate	plan	increase.

The	reserve	equalization	variance	is	primarily	due	to	increased	reserve	equalization	revenue	resulting	from	the	acquisition	of	the	Hinds plant	in	November	2012.

# Gross	operating	revenues,	fuel	and	purchased	power	expense,	and	other	regulatory	credits

•an	increase	of	$69.6	million	in	gross	wholesale	revenues	due	to	an	increase	in	sales	to	affiliated	customers;

•an	increase	of	$60.4	million	in	power	management	rider	revenue,	as	approved	by	the	MPSC,	primarily	resulting	from	the	acquisition	of the	Hinds	plant	in	November	2012,	as	discussed	previously;

•an	increase	of	$58.6	million	in	fuel	cost	recovery	revenues	primarily	due	to	higher	fuel	rates;	and

•an	increase	of	$28.2	million	in	rider	revenue	primarily	due	to	an	increase	in	the	Grand	Gulf	rider	effective	October	2012.

•increases	in	the	average	market	prices	of	natural	gas	and	purchased	power;

•an	increase	in	Grand	Gulf	capacity	costs	as	a	result	of	the	Grand	Gulf	uprate;	and

•an	increase	in	deferred	fuel	expenses	as	a	result	of	higher	fuel	revenues	primarily	due	to	lower	2012	fuel	rates	as	a	result	of	bandwidth remedy	payments	refunded	to	customers	in	August	through	December	2012.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the System	Agreement	proceedings.

Other	regulatory	credits	increased	primarily	due	to	decreased	recovery	of	costs	associated	with	the	power	management	rider.	There	is	no material	effect	on	net	income	because	the	power	management	recovery	rider	is	an	exact	recovery	rider	and	any	differences	in	revenues	and expenses	are	deferred	for	future	recovery.

|  | Amount |
| :--- | :--- |
|  | (In\tMillions) |
| 2011\tnet\trevenue | $554.9 |
| Retail\telectric\tprice | 28.3 |
| Volume/weather | (4.4) |
| Other | (0.8) |
| 2012\tnet\trevenue | $578.0 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	the	storm	cost	recovery	rider,	as	approved	by	the	MPSC	for	a	five- month	period	effective	August	2012.	The	recovery	of	storm	costs	is	offset	in	other	operation	and	maintenance	expenses.

The	volume/weather	variance	is	primarily	due	to	a	decrease	of	301	GWh,	or	2%,	in	billed	electricity	usage,	including	the	effect	of	milder weather	compared	to	prior	year	on	residential	and	commercial	sales.

Gross	operating	revenues	decreased	primarily	due	to	a	decrease	of	$84.1	million	in	gross	wholesale	revenues	due	to	a	decrease	in	sales	to affiliated	customers	and	a	decrease	of	$89.5	million	in	fuel	cost	recovery	revenues	primarily

attributable	to	lower	fuel	rates.	 	The	decrease	was	partially	offset	by	an	increase	of	$20.7	million	in	storm	cost	recovery	rider	revenue,	as discussed	above.		Entergy	Mississippi's	fuel	recovery	mechanism	and	storm	cost	recovery	rider	are	discussed	further	in	Note	2	to	the	financial statements.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	a	decrease	in	average	market	prices	of	natural	gas	and	purchased	power and	a	decrease	in	deferred	fuel	expense	due	to	the	timing	of	receipt	of	System	Agreement	payments	and	credits	to	customers.		See	Note	2	to	the financial	statements	for	a	discussion	of	the	System	Agreement	proceedings.

Other	regulatory	charges	decreased	primarily	due	to	decreased	recovery	of	costs	associated	with	the	power	management	rider.	There	is	no material	effect	on	net	income	because	the	power	management	recovery	rider	is	an	exact	recovery	rider	and	any	differences	in	revenues	and expenses	are	deferred	for	future	recovery.

•an	increase	of	$30.6	million	in	fossil-fueled	generation	expenses	resulting	from	a	higher	scope	of	work	done	during	plant	outages	in	2013 as	compared	to	2012,	the	acquisition	of	the	Hinds	plant	in	November	2012,	and	the	Baxter	Wilson	(Unit	1)	unplanned	outage	in September	2013;

•an	increase	of	$7.1	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative.	See	the	"Human	Capital	Management	Strategic	Imperative"	section	of Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	further	discussion;	and •an	increase	of	$5.9	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	the	discount	rates	used	to	determine	net periodic	pension	and	other	postretirement	benefit	costs	and	a	settlement	charge,	recognized	in	September	2013,	related	to	the	payment	of lump	sum	benefits	out	of	the	non-qualified	pension	plan.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs.

The	increase	was	partially	offset	by	a	temporary	increase	in	2012	of	$17.8	million	in	storm	damage	accruals,	as	approved	by	the	MPSC	for	a	five- month	period	effective	August	2012,	and	several	individually	insignificant	items.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	as	a	result	of	a	higher	assessment	in	2013 primarily	due	to	the	acquisition	of	the	Hinds	plant	in	November	2012.

Depreciation	and	amortization	expenses	increased	primarily	due	to	an	increase	in	plant	in	service,	including	the	acquisition	of	the	Hinds plant	in	November	2012.

•an	increase	of	$21.1	million	resulting	from	a	temporary	increase	in	the	storm	damage	reserve	authorized	by	the	MPSC	effective	August 2012;

•$7.6	million	of	costs	incurred	in	2012	related	to	the	now	terminated	plan	to	spin	off	and	merge	the	transmission	business;	and

•an	increase	of	$4.8	million	in	compensation	and	benefits	costs	primarily	resulting	from	decreasing	discount	rates	and	changes	in	certain actuarial	assumptions	resulting	from	an	experience	study.		See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial statements	for	further	discussion	of	benefits	costs.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	due	to	a	higher	2012	assessment	as	compared	to 2011.

Depreciation	and	amortization	expenses	increased	primarily	due	to	an	increase	in	plant	in	service.

Other	income	decreased	primarily	due	to	a	decrease	in	allowance	for	equity	funds	used	during	construction	due	to	less	construction	work in	progress	in	2012	as	compared	to	2011.

Interest	expense	increased	primarily	due	to	a	revision	in	2011	caused	by	FERC's	acceptance	of	a	change	in	the	treatment	of	funds	received from	independent	power	producers	for	transmission	interconnection	projects.

The	effective	 income	 tax	rates	for	2013,	2012,	and	2011	were	37.7%,	55.6%,	and	20.9%,	respectively.	See	Note	3 to the	financial statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rates.

On	September	11,	2013,	Entergy	Mississippi's	Baxter	Wilson	(Unit	1)	power	plant	experienced	a	significant	unplanned	outage	event.		The cause	of	the	event	is	currently	under	investigation.		Entergy	Mississippi	is	still	in	the	process	of	assessing	the	nature	and	extent	of	the	damage	to the	unit.	The	current	estimate	of	costs	to	return	the	unit	to	service	is	between	$45	million	and	$60	million.	 	This	estimate	may	change	as restorative	activities	occur.		The	costs	necessary	to	return	the	plant	to	service	are	expected	to	continue	into	the	third	quarter	2014.		Entergy Mississippi	believes	that	the	damage	is	primarily	covered	by	its	property	insurance	policy,	subject	to	a	$20	million	deductible.	In	December	2013, Entergy	Mississippi	made	a	filing	with	the	MPSC	requesting	approval	for	Entergy	Mississippi	to	defer	and	accumulate	the	costs	incurred	in connection	with	Baxter	Wilson	repair	activities,	net	of	applicable	 insurance	proceeds,	with	such	costs	 to	be	recoverable	 in	a	manner	 to	be determined	by	the	MPSC.	The	MPSC	has	not	acted	on	Entergy	Mississippi's	request.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $52,970 | $16 | $1,216 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 219,665 | 202,406 | 99,596 |
| Investing\tactivities | (149,410) | (391,127) | (151,830) |
| Financing\tactivities | (123,194) | 241,675 | 51,034 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (52,939) | 52,954 | (1,200) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $31 | $52,970 | $16 |

Net	cash	provided	by	operating	activities	increased	$17.3	million	in	2013	primarily	due	to	the	timing	of	collections	of	receivables	from customers	and	a	$1.5	million	decrease	in	pension	contributions	in	2013	as	compared	to	2012.	The	increase	was	partially	offset	by	income	tax payments	of	$4.7	million	in	2013	as	compared	to	income	tax	refunds	of	$0.7	million	in	2012.	Entergy	Mississippi	had	income	tax	payments	in 2013	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement.	The	payments resulted	primarily	from	the	reversal	of	temporary	differences	for	which	Entergy	Mississippi	had	previously	claimed	a	tax	deduction.	See	"Critical Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits funding.

Net	cash	provided	by	operating	activities	increased	$102.8	million	in	2012	primarily	due	to:

•the	purchase	in	2011	of	$42.6	million	of	fuel	oil	from	System	Fuels	because	System	Fuels	will	no	longer	procure	fuel	oil	for	the	Utility companies;

•a	decrease	of	$19.5	million	in	pension	contributions.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements for	further	discussion	of	pension	funding.

Net	cash	used	in	investing	activities	decreased	$241.7	million	in	2013	primarily	due	to	the	payment	for	the	purchase	of	Hinds	Energy Facility	in	November	2012	of	approximately	$203	million,	including	adjustments	to	the	purchase	price,	and	money	pool	activity.	See	Note	15	to the	financial	statements	for	a	discussion	of	the	purchase	of	Hinds	Energy	Facility.

Decreases	in	Entergy	Mississippi's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Mississippi's	receivable	from the	money	pool	decreased	by	$16.9	million	in	2013	compared	to	increasing	by	$16.9	million	in	2012.	The	money	pool	is	an	inter-company borrowing	arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	increased	$239.3	million	in	2012	primarily	due	to	the	payment	for	the	purchase	of	Hinds	Energy Facility	in	November	2012	of	approximately	$203	million,	including	adjustments	to	the

purchase	price,	and	money	pool	activity.	See	Note	15	to	the	financial	statements	for	a	discussion	of	the	purchase	of	Hinds	Energy	Facility.

Increases	in	Entergy	Mississippi's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Mississippi's	receivable	from	the money	pool	increased	$16.9	million	in	2012.

Entergy	Mississippi's	financing	activities	used	$123.2	million	of	cash	in	2013	as	compared	to	providing	$241.7	million	of	cash	in	2012 primarily	due	to	the	payment,	at	maturity,	of	$100	million	of	5.15%	Series	first	mortgage	bonds	in	February	2013	and	the	issuance	of	$250	million of	3.1%	Series	first	mortgage	bonds	in	December	2012.

Net	cash	provided	by	financing	activities	increased	$190.6	million	in	2012	compared	to	2011	primarily	due	to:

•redemptions	of	$80	million	of	4.65%	Series	first	mortgage	bonds	and	$100	million	of	5.92%	Series	first	mortgage	bonds	in	second	quarter 2011;

•the	issuance	of	$250	million	of	3.1%	Series	first	mortgage	bonds	in	December	2012	compared	to	the	issuance	of	$150	million	of	6.0% Series	first	mortgage	bonds	in	April	2011	and	the	issuance	of	$125	million	of	3.25%	Series	first	mortgage	bonds	in	May	2011;	and •money	pool	activity.

Decreases	in	Entergy	Mississippi's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Mississippi's	payable	to	the	money	pool decreased	by	$2.0	million	in	2012	compared	to	decreasing	by	$31.3	million	in	2011.

See	Note	5	to	the	financial	statements	for	details	on	long-term	debt.

Entergy	Mississippi's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.	The	decrease	in	the	debt	to capital	ratio	is	due	to	the	retirement	of	$100	million	of	5.15%	Series	first	mortgage	bonds	in	February	2013	and	$16.03	million	of	4.60%	Series pollution	control	revenue	bonds	in	October	2013.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 51.4% | 55.9% |
| Effect\tof\tsubtracting\tcash | —% | (1.2%) |
| Net\tdebt\tto\tnet\tcapital | 51.4% | 54.7% |

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	short-term	borrowings,	capital	lease	obligations,	and	long-term	debt, including	the	currently	maturing	portion.	Capital	consists	of	debt,	preferred	stock	without	sinking	fund,	and	common	equity.	Net	capital	consists of	capital	less	cash	and	cash	equivalents.	Entergy	Mississippi	uses	the	debt	to	capital	ratio	in	analyzing	its	financial	condition	and	believes	it provides	useful	information	to	its	investors	and	creditors	in	evaluating	Entergy	Mississippi's	financial	condition.	Entergy	Mississippi	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	Mississippi's	financial	condition	because	net	debt	indicates	Entergy	Mississippi's	outstanding	debt	position	that	could	not	be	readily satisfied	by	cash	and	cash	equivalents	on	hand.

Entergy	Mississippi	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Mississippi's	planned	construction	and	other	capital	investments.

|  | 2014 | 2015 | 2016 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $35 | $25 | $35 |
| Transmission | 35 | 75 | 115 |
| Distribution | 100 | 95 | 95 |
| Other | 20 | 20 | 15 |
| Total | $190 | $215 | $260 |

Following	are	the	amounts	of	Entergy	Mississippi's	existing	debt	obligations	and	lease	obligations	(includes	estimated	interest	payments) and	other	purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | After	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $53 | $228 | $189 | $1,434 | $1,904 |
| Capital\tlease\tpayments | $2 | $3 | $2 | $— | $7 |
| Operating\tleases | $7 | $11 | $5 | $4 | $27 |
| Purchase\tobligations\t(b) | $278 | $535 | $530 | $1,849 | $3,192 |

(b) 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	financial	statements.

In	addition	to	the	contractual	obligations	given	above,	Entergy	Mississippi	currently	expects	to	contribute	approximately	$21.6	million	to	its pension	plans	in	2014	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are completed	by	April	1,	2014.		See	"Critical	Accounting	Estimates	–	Qualified	Pension	and	Other	Postretirement	Benefits "	below	for	a discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	Mississippi	includes specific	investments	and	initiatives	such	as	transmission	spending	to	support	economic	development	projects,	reliability,	and	new	compliance projects.		Entergy's	Utility	supply	plan	initiative	will	continue	to	seek	to	transform	its	generation	portfolio	with	new	or	repowered	generation resources.		Opportunities	resulting	from	the	supply	plan	initiative,	including	new	projects	or	the	exploration	of	alternative	financing	sources,	could result	in	increases	or	decreases	in	the	capital	expenditure	estimates	given	above.		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,	changes	in	project	plans,	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	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	indenture	restricts	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,	2013,	Entergy	Mississippi	had	restricted	retained	earnings	unavailable for	distribution	to	Entergy	Corporation	of	$68.5	million.

Pursuant	 to	 the	 Mississippi	 Baseload	Act	 and	 the	 Mississippi	 Public	 Utilities	Act,	 Entergy	 Mississippi	 has	 been	 developing	 and	 is preserving	a	project	option	for	new	nuclear	generation	at	Grand	Gulf	Nuclear	Station.		This	project	is	in	the	early	stages,	and	several	issues	remain to	be	addressed	over	time	before	significant	additional	capital	would	be	committed	to	this	project.		In	October	2010,	Entergy	Mississippi	filed	an application	with	the	MPSC	requesting	that	the	MPSC	determine	that	it	is	in	the	public	interest	to	preserve	the	option	to	construct	new	nuclear generation	at	Grand	Gulf	and	that	the	MPSC	approve	the	deferral	of	Entergy	Mississippi's	costs	incurred	to	date	and	in	the	future	related	to	this project,	including	the	accrual	of	AFUDC	or	similar	carrying	charges.		In	October	2011,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities Staff	filed	with	the	MPSC	a	joint	stipulation	that	the	MPSC	approved	in	November	2011.		The	stipulation	states	that	there	should	be	a	deferral	of the	$57	million	of	costs	incurred	through	September	2011	in	connection	with	planning,	evaluation,	monitoring,	and	other	and	related	generation resource	development	activities	for	new	nuclear	generation	at	Grand	Gulf.		The	costs	shall	be	treated	as	a	regulatory	asset	until	the	proceeding	is resolved.		The	Mississippi	Public	Utilities	Staff	and	Entergy	Mississippi	also	agree	that	the	MPSC	should	conduct	a	hearing	to	consider	the	relief requested	by	Entergy	Mississippi	in	its	application,	including	evidence	regarding	whether	costs	incurred	in	connection	with	planning,	evaluation, monitoring,	and	other	and	related	generation	resource	development	activities	for	new	nuclear	generation	at	Grand	Gulf	were	prudently	incurred and	are	otherwise	allowable.		The	Mississippi	Public	Utilities	Staff	and	Entergy	Mississippi	further	agree	that	such	prudently	incurred	costs	shall be	recoverable	in	a	manner	to	be	determined	by	the	MPSC.		In	the	Stipulation,	the	Mississippi	Public	Utilities	Staff	and	Entergy	Mississippi	agree that	the	development	of	a	nuclear	unit	project	option	is	consistent	with	the	Mississippi	Baseload	Act.		The	Mississippi	Public	Utilities	Staff	and Entergy	Mississippi	further	agree	that	the	deferral	of	costs	incurred	in	connection	with	planning,	evaluation,	monitoring,	and	other	and	related generation	 resource	 development	 activities	 for	 new	 nuclear	 generation	 at	 Grand	 Gulf	 also	 is	 consistent	 with	 the	 Mississippi	 Baseload Act.	 	 Entergy	 Mississippi	 will	 not	 accrue	 carrying	 charges	 or	 continue	 to	 accrue	 AFUDC	 on	 the	 costs,	 pending	 the	 outcome	 of	 the proceeding.		Further	proceedings	before	the	MPSC	have	not	been	scheduled.

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

Entergy	Mississippi	may	refinance,	redeem,	or	otherwise	retire	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	its	corporate	charter,	bond	indenture,	and	other	agreements.		Entergy	Mississippi	has sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital	needs.

In	May	2013,	Entergy	Mississippi	renewed	its	three	separate	credit	facilities	through	May	2014	and	increased	the	aggregate	amount available	under	these	credit	facilities	to	$92.5	million.		No	borrowings	were	outstanding	under	the	credit	facilities	as	of	December	31,	2013.		See Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit	facilities.		In	addition,	Entergy	Mississippi	entered	into	an	uncommitted letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	under	MISO.		As	of	December	31,	2013,	a	$21	million	letter	of	credit was	outstanding	under	Entergy	Mississippi's	letter	of	credit	facility.

Entergy	Mississippi	has	obtained	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow	through	October	2015, up	to	the	aggregate	amount,	at	any	one	time	outstanding,	of	$175	million.	See	Note	4	to	the	financial	statements	for	further	discussion	of	Entergy Mississippi's	 short-term	 borrowing	 limits.	Entergy	 Mississippi	 has	 also	 obtained	 an	 order	 from	 the	 FERC	 authorizing	 long-term	 securities issuances	through	October	2015.

In	February	2013,	Entergy	Mississippi	redeemed,	at	maturity,	its	$100	million	of	5.15%	Series	first	mortgage	bonds.

In	October	2013,	Entergy	Mississippi	redeemed,	prior	to	maturity,	its	$16.03	million	of	4.60%	Series	pollution	control	revenue	bonds	due April	2022.

The	rates	that	Entergy	Mississippi	charges	for	electricity	significantly	influence	its	financial	position,	results	of	operations,	and	liquidity. Entergy	Mississippi	is	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.

In	March	2013,	Entergy	Mississippi	submitted	its	formula	rate	plan	filing	for	the	2012	test	year.	The	filing	requested	a	$36.3	million revenue	increase	to	reset	Entergy	Mississippi's	return	on	common	equity	to	10.55%,	which	is	a	point	within	the	formula	rate	plan	bandwidth.	In June	2013,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a	joint	stipulation,	in	which	both	parties	agreed	that	the MPSC	should	approve	a	$22.3	million	rate	increase	for	Entergy	Mississippi	which,	with	other	adjustments	reflected	in	the	stipulation,	would	have the	effect	of	resetting	Entergy	Mississippi's	return	on	common	equity	to	10.59%	when	adjusted	for	performance	under	the	formula	rate	plan.	In August	2013	the	MPSC	approved	the	joint	stipulation	between	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	authorizing	the	rate increase	effective	with	September	2013	bills.		Additionally,	the	MPSC	authorized	Entergy	Mississippi	to	defer	approximately	$1.2	million	in MISO-related	implementation	costs	incurred	in	2012	along	with	other	MISO-related	implementation	costs	incurred	in	2013.

# Storm	Damage	Accrual	and	Storm	Cost	Recovery

In	two	orders	issued	in	July	2012	the	MPSC	temporarily	increased	Entergy	Mississippi's	storm	damage	reserve	monthly	accrual	from $0.75	million	to	$2.0	million	for	bills	rendered	during	the	billing	months	of	August	2012	through	December	2012,	and	approved	recovery	of $14.9	million	in	prudently	incurred	storm	costs	to	be	amortized	over	five	months,	beginning	with	August	2012	bills.

In	August	2012,	Hurricane	Isaac	caused	damage	to	Entergy	Mississippi's	service	area.	The	storm	resulted	in	widespread	power	outages, significant	damage	primarily	to	distribution	infrastructure,	and	the	loss	of	sales	during	the	power	outages.	Total	restoration	costs	for	the	repair and/or	replacement	of	Entergy	Mississippi's	electric	facilities	damaged	by	Hurricane	Isaac	were	$22	million.

On	July	1,	2013,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a	joint	stipulation,	wherein	both	parties	agreed that	approximately	$32	million	in	storm	restoration	costs	incurred	in	2011	and	2012	were	prudently	incurred	and	chargeable	to	the	storm	damage reserve,	 while	 approximately	 $700,000	 in	 prudently	 incurred	 costs	 were	 more	 properly	 recoverable	 through	 the	 formula	 rate	 plan.	Entergy Mississippi	and	the	Mississippi	Public	Utilities	Staff	also	agreed	that	the	storm	damage	accrual	should	be	increased	from	$750,000	per	month	to $1.75	million	per	month.	In	September	2013	the	MPSC	approved	the	joint	stipulation	with	the	increase	in	the	storm	damage	accrual	effective	with October	2013	bills.

See	the	"Nuclear	Matters"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	a discussion	of	nuclear	matters.

Entergy	Mississippi'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	Mississippi	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	 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	that	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	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.

The	following	chart	reflects	the	sensitivity	of	qualified	pension	cost	and	qualified	projected	qualified	benefit	obligation	to	changes	in certain	actuarial	assumptions	(dollars	in	thousands).

| Discount	rate | (0.25%) | $1,048 | $10,725 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $621 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $426 | $1,793 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $208 | $2,310 |
| Health\tcare\tcost\ttrend | 0.25% | $393 | $1,979 |

Total	qualified	pension	cost	for	Entergy	Mississippi	in	2013	was	$16.3	million,	including	a	$767	thousand	curtailment	charge	and	a	$359 thousand	special	 termination	charge	related	 to	workforce	downsizing.	Entergy	Mississippi	anticipates	2014	qualified	pension	cost	to	be	$10 million.	Entergy	Mississippi	contributed	$8.2	million	to	its	qualified	pension	plans	 in	2013	and	estimates	2014	pension	contributions	 to	be approximately	$21.6	million;	although	 the	required	pension	contributions	will	not	be	known	with	more	certainty	until	 the	January	1,	2014 valuations	are	completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding relief	under	MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Mississippi	in	2013	were	$5.1	million,	including	a	$596 thousand	curtailment	charge	related	to	workforce	downsizing.	Entergy	Mississippi	expects	2014	postretirement	health	care	and	life	insurance benefit	income	to	approximate	$982	thousand.	Entergy	Mississippi	contributed	$4.8	million	to	its	other	postretirement	plans	in	2013	and	no required	contribution	is	anticipated	in	2014.

# Jackson,	Mississippi

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Mississippi,	Inc.	(the	"Company")	as	of	December	31,	2013	and	2012,	and	the related	income	statements,	statements	of	cash	flows,	and	statements	of	changes	in	common	equity	(pages	370	through	374	and	applicable	items	in pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December	31,	2013.	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,	2013	and	2012,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $1,334,540 | $1,120,366 | $1,266,470 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 328,934 | 227,133 | 363,025 |
| Purchased\tpower | 375,745 | 320,923 | 339,061 |
| Other\toperation\tand\tmaintenance | 261,832 | 244,722 | 210,657 |
| Taxes\tother\tthan\tincome\ttaxes | 83,630 | 75,006 | 69,759 |
| Depreciation\tand\tamortization | 108,714 | 97,768 | 93,119 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (14,545) | (5,701) | 9,460 |
| TOTAL | 1,144,310 | 959,851 | 1,085,081 |
| OPERATING\tINCOME | 190,230 | 160,515 | 181,389 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 2,182 | 3,955 | 7,755 |
| Interest\tand\tinvestment\tincome | 817 | 170 | 249 |
| Miscellaneous\t-\tnet | (3,821) | (3,951) | (3,904) |
| TOTAL | (822) | 174 | 4,100 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 59,031 | 57,345 | 52,273 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (1,539) | (2,103) | (4,314) |
| TOTAL | 57,492 | 55,242 | 47,959 |
| INCOME\tBEFORE\tINCOME\tTAXES | 131,916 | 105,447 | 137,530 |
| Income\ttaxes | 49,757 | 58,679 | 28,801 |
| NET\tINCOME | 82,159 | 46,768 | 108,729 |
| Preferred\tdividend\trequirements\tand\tother | 2,828 | 2,828 | 2,828 |
| EARNINGS\tAPPLICABLE\tTO |  |  |  |
| COMMON\tSTOCK | $79,331 | $43,940 | $105,901 |

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $82,159 | $46,768 | $108,729 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation\tand\tamortization | 108,714 | 97,768 | 93,119 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 47,878 | 58,221 | (3,443) |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (31,647) | 42,222 | 5,488 |
| Fuel\tinventory | (121) | (6,202) | (35,621) |
| Accounts\tpayable | 38,727 | (3,796) | (7,059) |
| Taxes\taccrued | 920 | 6,791 | 13,535 |
| Interest\taccrued | 2,157 | (3,324) | 456 |
| Deferred\tfuel\tcosts | (11,567) | (42,331) | 18,998 |
| Other\tworking\tcapital\taccounts | (12,820) | (6,859) | (27,480) |
| Provisions\tfor\testimated\tlosses | (146) | (2,469) | (1,177) |
| Other\tregulatory\tassets | 87,907 | (6,501) | (83,399) |
| Pension\tand\tother\tpostretirement\tliabilities | (94,143) | 16,782 | 39,183 |
| Other\tassets\tand\tliabilities | 1,647 | 5,336 | (21,733) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 219,665 | 202,406 | 99,596 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (168,510) | (175,544) | (165,998) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 2,182 | 3,955 | 7,755 |
| Proceeds\tfrom\tsale\tof\tassets | — | — | 868 |
| Payment\tfor\tpurchase\tof\tplant | — | (202,668) | — |
| Change\tin\tmoney\tpool\treceivable\t-\tnet | 16,878 | (16,878) | — |
| Investments\tin\taffiliates | — | — | 5,527 |
| Other | 40 | 8 | 18 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (149,410) | (391,127) | (151,830) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | — | 246,502 | 268,418 |
| Retirement\tof\tlong-term\tdebt | (116,030) | — | (180,000) |
| Change\tin\tmoney\tpool\tpayable\t-\tnet | 3,536 | (1,999) | (31,256) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (7,400) | — | (3,300) |
| Preferred\tstock | (2,828) | (2,828) | (2,828) |
| Other | (472) | — | — |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (123,194) | 241,675 | 51,034 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (52,939) | 52,954 | (1,200) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 52,970 | 16 | 1,216 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $31 | $52,970 | $16 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $54,120 | $58,043 | $49,192 |
| Income\ttaxes | $4,657 | ($696) | $22,094 |

| Cash | $22 | $585 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 9 | 52,385 |
| Total\tcash\tand\tcash\tequivalents | 31 | 52,970 |
| Accounts\treceivable: |  |  |
| Customer | 76,534 | 49,836 |
| Allowance\tfor\tdoubtful\taccounts | (906) | (910) |
| Associated\tcompanies | 13,794 | 25,504 |
| Other | 9,117 | 11,072 |
| Accrued\tunbilled\trevenues | 44,777 | 43,045 |
| Total\taccounts\treceivable | 143,316 | 128,547 |
| Deferred\tfuel\tcosts | 38,057 | 26,490 |
| Accumulated\tdeferred\tincome\ttaxes | — | 44,027 |
| Fuel\tinventory\t-\tat\taverage\tcost | 48,899 | 48,778 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 40,849 | 40,331 |
| System\tagreement\tcost\tequalization | 15,000 | — |
| Prepayments\tand\tother | 4,813 | 5,329 |
| TOTAL | 290,965 | 346,472 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 4,670 | 4,698 |
| Escrow\taccounts | 51,795 | 61,836 |
| TOTAL | 56,465 | 66,534 |
| UTILITY\tPLANT |  |  |
| Electric | 3,875,737 | 3,708,743 |
| Property\tunder\tcapital\tlease | 5,329 | 8,112 |
| Construction\twork\tin\tprogress | 37,316 | 62,876 |
| TOTAL\tUTILITY\tPLANT | 3,918,382 | 3,779,731 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 1,413,484 | 1,324,627 |
| UTILITY\tPLANT\t-\tNET | 2,504,898 | 2,455,104 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 58,716 | 63,614 |
| Other\tregulatory\tassets | 318,462 | 401,471 |
| Other | 20,819 | 20,832 |
| TOTAL | 397,997 | 485,917 |
| TOTAL\tASSETS | $3,250,325 | $3,354,027 |

| Currently	maturing	long-term	debt | $— | $100,000 |
| :--- | :--- | :--- |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 74,144 | 42,377 |
| Other | 52,129 | 44,856 |
| Customer\tdeposits | 74,211 | 71,182 |
| Taxes\taccrued | 53,247 | 52,327 |
| Accumulated\tdeferred\tincome\ttaxes | 15,413 | 218 |
| Interest\taccrued | 20,383 | 18,226 |
| Other | 19,021 | 21,511 |
| TOTAL | 308,548 | 350,697 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 746,939 | 761,812 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 8,530 | 7,257 |
| Obligations\tunder\tcapital\tlease | 4,185 | 5,329 |
| Other\tregulatory\tliabilities | 2,509 | 1,235 |
| Asset\tretirement\tcost\tliabilities | 6,401 | 6,039 |
| Accumulated\tprovisions | 35,674 | 35,820 |
| Pension\tand\tother\tpostretirement\tliabilities | 66,722 | 160,866 |
| Long-term\tdebt | 1,053,670 | 1,069,519 |
| Other | 15,189 | 25,426 |
| TOTAL | 1,939,819 | 2,073,303 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 50,381 | 50,381 |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t12,000,000 |  |  |
| shares;\tissued\tand\toutstanding\t8,666,357\tshares\tin\t2013\tand\t2012 | 199,326 | 199,326 |
| Capital\tstock\texpense\tand\tother | (690) | (690) |
| Retained\tearnings | 752,941 | 681,010 |
| TOTAL | 951,577 | 879,646 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $3,250,325 | $3,354,027 |

# STATEMENTS	OF	CHANGES	IN	COMMON	EQUITY

|  | Common	Stock | Capital	Stock<br>Expense	and	Other | Retained	Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2010 | $199,326 | ($690) | $534,469 | $733,105 |
| Net\tincome | — | — | 108,729 | 108,729 |
| Common\tstock\tdividends | — | — | (3,300) | (3,300) |
| Preferred\tstock\tdividends | — | — | (2,828) | (2,828) |
| Balance\tat\tDecember\t31,\t2011 | $199,326 | ($690) | $637,070 | $835,706 |
| Net\tincome | — | — | 46,768 | 46,768 |
| Preferred\tstock\tdividends | — | — | (2,828) | (2,828) |
| Balance\tat\tDecember\t31,\t2012 | $199,326 | ($690) | $681,010 | $879,646 |
| Net\tincome | — | — | 82,159 | 82,159 |
| Common\tstock\tdividends | — | — | (7,400) | (7,400) |
| Preferred\tstock\tdividends | — | — | (2,828) | (2,828) |
| Balance\tat\tDecember\t31,\t2013 | $199,326 | ($690) | $752,941 | $951,577 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,334,540 | $1,120,366 | $1,266,470 | $1,232,922 | $1,180,107 |
| Net\tincome | $82,159 | $46,768 | $108,729 | $85,377 | $79,367 |
| Total\tassets | $3,250,325 | $3,354,027 | $2,943,394 | $2,772,778 | $2,689,933 |
| Long-term\tobligations\t(a) | $1,108,236 | $1,125,229 | $978,932 | $806,506 | $900,634 |

(a)	Includes	long-term	debt	(excluding	currently	maturing	debt),	non-current	capital	lease	obligations,	and	preferred	stock	without	sinking	fund.

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $527 | $454 | $490 | $509 | $467 |
| Commercial | 432 | 381 | 401 | 406 | 395 |
| Industrial | 156 | 140 | 146 | 145 | 147 |
| Governmental | 42 | 37 | 37 | 38 | 37 |
| Total\tretail | 1,157 | 1,012 | 1,074 | 1,098 | 1,046 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 92 | 23 | 104 | 55 | 52 |
| Non-associated\tcompanies | 24 | 24 | 27 | 33 | 28 |
| Other | 62 | 61 | 61 | 47 | 54 |
| Total | $1,335 | $1,120 | $1,266 | $1,233 | $1,180 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 5,629 | 5,550 | 5,848 | 6,077 | 5,358 |
| Commercial | 4,815 | 4,915 | 4,985 | 5,000 | 4,756 |
| Industrial | 2,265 | 2,400 | 2,326 | 2,250 | 2,178 |
| Governmental | 409 | 408 | 415 | 416 | 405 |
| Total\tretail | 13,118 | 13,273 | 13,574 | 13,743 | 12,697 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 1,543 | 232 | 431 | 268 | 198 |
| Non-associated\tcompanies | 304 | 265 | 332 | 402 | 330 |
| Total | 14,965 | 13,770 | 14,337 | 14,413 | 13,225 |

# ENTERGY	NEW	ORLEANS,	INC.

Net	income	decreased	$5.4	million	primarily	due	to	higher	other	operation	and	maintenance	expenses,	higher	taxes	other	than	income taxes,	and	higher	interest	expense,	partially	offset	by	higher	net	revenue	and	a	lower	effective	income	tax	rate.

Net	income	decreased	$18.9	million	primarily	due	to	higher	other	operation	and	maintenance	expenses	and	lower	net	revenue.

| 2012	net	revenue | $237.9 |
| :--- | :--- |
| Volume/weather | 6.6 |
| Rider\trevenue | 2.7 |
| Net\tgas\trevenue | 2.6 |
| Retail\telectric\tprice | (1.9) |
| Other | 1.3 |
| 2013\tnet\trevenue | $249.2 |

The	volume/weather	variance	 is	primarily	due	 to	an	 increase	of	125	GWh,	or	3%,	 in	billed	electricity	usage	 in	 the	residential	and commercial	sectors	primarily	due	to	the	effects	of	Hurricane	Isaac,	which	decreased	sales	volume	in	2012,	and	in	part	to	a	2%	increase	in	the average	number	of	both	residential	and	commercial	customers.

The	rider	revenue	variance	is	primarily	due	to	an	increase	in	franchise	tax	rider	revenue	as	a	result	of	higher	retail	revenues.	There	is	a corresponding	increase	in	taxes	other	than	income	taxes,	resulting	in	no	effect	on	net	income.

The	net	gas	revenue	variance	is	primarily	due	to	the	effect	of	more	favorable	weather	primarily	in	the	residential	and	commercial	sectors in	2013	as	compared	to	the	same	period	in	prior	year.

The	retail	electric	price	variance	is	primarily	due	to	a	formula	rate	plan	decrease	effective	September	2013.	See	Note	2	to	the	financial statements	for	a	discussion	of	the	formula	rate	plan	filing.

# Gross	operating	revenues	and	fuel	and	purchased	power	expenses

Gross	operating	revenues	increased	primarily	due	to	an	increase	of	$46.1	million	in	electric	fuel	cost	recovery	revenues	due	to	higher	fuel rates,	an	increase	of	$10.3	million	in	gas	fuel	cost	recovery	revenues	due	to	higher	fuel	rates,	and	the	increase	related	to	volume/weather,	as discussed	above.	The	increase	was	partially	offset	by	a	decrease	of	$16.7	million	in	gross	wholesale	revenue	primarily	due	to	decreased	sales	to affiliate	customers.	Entergy	New	Orleans's	fuel	and	purchased	power	recovery	mechanism	is	discussed	in	Note	2	to	the	financial	statements.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	an	increase	in	Grand	Gulf	capacity	and	energy	purchases	as	a	result	of	the Grand	Gulf	uprate	and	an	increase	in	deferred	fuel	expense	as	a	result	of	higher	fuel	revenues.

| 2011	net	revenue | $247.0 |
| :--- | :--- |
| Retail\telectric\tprice | (6.2) |
| Volume/weather | (4.8) |
| Other | 1.9 |
| 2012\tnet\trevenue | $237.9 |

The	retail	electric	price	variance	is	primarily	due	to	a	formula	rate	plan	decrease	effective	October	2011.	See	Note	2	to	the	financial statements	for	a	discussion	of	the	formula	rate	plan	filing.

The	volume/weather	variance	is	primarily	due	to	effect	of	milder	weather,	as	compared	to	the	prior	period,	on	residential	and	commercial sales	and	the	effects	of	the	power	outages	caused	by	Hurricane	Isaac.

•a	decrease	of	$53.3	million	in	gross	wholesale	revenue	primarily	due	to	decreased	sales	to	affiliate	customers;	and •a	decrease	of	$18.9	million	in	gross	gas	revenues	primarily	due	to	lower	fuel	cost	recovery	revenues	as	a	result	of	lower	fuel	rates	and	the effect	of	milder	weather.	Entergy	New	Orleans's	fuel	and	purchased	power	recovery	mechanism	is	discussed	in	Note	2	to	the	financial statements.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	a	decrease	in	demand	for	gas-fired	generation	and	a	decrease	in	the	average market	price	of	natural	gas,	partially	offset	by	an	increase	in	the	average	market	price	of	purchased	power.

•an	increase	of	$9	million	in	fossil-fueled	generation	expenses	due	to	an	overall	higher	scope	of	work	done	during	plant	outages	as compared	to	prior	year;

The	increase	was	partially	offset	by	a	decrease	of	$3	million	in	loss	reserves	and	a	decrease	of	$1.5	million	due	to	expenses	recorded	in	2012 related	to	the	Energy	Smart	Program.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	local	franchise	taxes	resulting	from	higher	electric	and	gas	retail revenues	as	compared	to	prior	year	and	an	increase	in	ad	valorem	taxes	resulting	from	higher	assessments.	Franchise	taxes	have	no	effect	on	net income	as	these	taxes	are	recovered	through	the	franchise	tax	rider.

Interest	expense	increased	primarily	due	to	the	issuance	of	$100	million	of	3.90%	Series	first	mortgage	bonds	in	June	2013	and	the issuance	of	$30	million	of	5.00%	Series	first	mortgage	bonds	in	November	2012,	partially	offset	by	the	retirement,	at	maturity,	of	$70	million	of 5.25%	Series	first	mortgage	bonds	in	August	2013.

Other	operation	and	maintenance	expenses	increased	primarily	due	to	the	deferral	in	2011	of	$13.4	million	of	2010	Michoud	plant maintenance	costs	pursuant	to	the	settlement	of	Entergy	New	Orleans's	2010	test	year	formula	rate	plan	filing	approved	by	the	City	Council	in September	2011.	See	Note	2	to	the	financial	statements	for	more	discussion	of	the	2010	test	year	formula	rate	plan	filing	and	settlement.

# Hurricane	Katrina

In	August	2005,	Hurricane	Katrina	caused	catastrophic	damage	to	Entergy	New	Orleans's	service	territory.	Entergy	pursued	a	broad	range of	initiatives	to	recover	storm	restoration	and	business	continuity	costs,	including	obtaining	assistance	through	federal	legislation	for	damage caused	by	Hurricane	Katrina.

# Gas	System	Rebuild

In	addition	to	the	Hurricane	Katrina	storm	restoration	costs	that	Entergy	New	Orleans	incurred,	Entergy	New	Orleans	expects	that	over	a longer	term	rebuilding	of	the	gas	system	in	New	Orleans	will	be	necessary	due	to	the	massive	salt	water	intrusion	into	the	system	caused	by	the flooding	in	New	Orleans.	The	salt	water	intrusion	is	expected	to	shorten	the	life	of	the	gas	system,	making	it	necessary	to	rebuild	portions	of	that system	over	time,	earlier	than	otherwise	would	be	expected,	with	the	project	extending	many	years	into	the	future.	Entergy	New	Orleans	received insurance	proceeds	for	a	portion	of	the	estimated	future	construction	expenditures	associated	with	rebuilding	its	gas	system,	and	the	October	2006 City	Council	resolution	approving	the	settlement	of	Entergy	New	Orleans's	rate	and	storm-cost	recovery	filings	requires	Entergy	New	Orleans	to record	those	proceeds	in	a	designated	sub-account	of	other	deferred	credits	until	the	proceeds	are	spent	on	the	rebuild	project.	This	other	deferred credit	is	shown	as	"Gas	system	rebuild	insurance	proceeds"	on	Entergy	New	Orleans's	balance	sheet.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $9,391 | $9,834 | $54,986 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 86,326 | 52,089 | 44,927 |
| Investing\tactivities | (89,666) | (78,040) | (46,019) |
| Financing\tactivities | 27,438 | 25,508 | (44,060) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 24,098 | (443) | (45,152) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $33,489 | $9,391 | $9,834 |

Net	cash	provided	by	operating	activities	increased	$34.2	million	in	2013	primarily	due	to	the	increased	recovery	of	fuel	costs	and decreased	Hurricane	Isaac	storm	spending	in	2013,	partially	offset	by	a	decrease	of	$11.5	million	in	income	tax	refunds.	The	income	tax	refunds of	$13	million	in	2012	resulted	primarily	from	a	decrease	of	previously	estimated	2011	taxable	income	due	to	the	recognition	of	additional	bonus depreciation.

Net	cash	provided	by	operating	activities	increased	$7.2	million	in	2012	primarily	due	to	income	tax	refunds	of	$13	million	in	2012 compared	to	income	tax	payments	of	$39.4	million	in	2011	and	a	decrease	of	$6.3	million	in	pension	contributions,	offset	by	Hurricane	Isaac storm	restoration	spending	in	2012,	the	timing	of	collections	of	customer	receivables	and	the	decreased	recovery	of	fuel	costs.	The	income	tax refunds	of	$13	million	in	2012	resulted	primarily	from	a	decrease	of	previously	estimated	2011	taxable	income	due	to	the	recognition	of	additional bonus	depreciation.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for	a	discussion	of	qualified	pension	and other	postretirement	benefits	funding.

Net	cash	flow	used	in	investing	activities	increased	$11.6	million	in	2013	primarily	due	to:

•an	increase	in	transmission	construction	expenditures	as	a	result	of	additional	reliability	work	performed	in	2013;	and •an	increase	in	fossil-fueled	generation	construction	expenditures	due	to	an	increased	scope	of	work	in	2013.

The	increase	was	partially	offset	by	a	decrease	in	distribution	construction	expenditures	due	to	higher	spending	related	to	Hurricane	Isaac	in	2012.

Increases	in	Entergy	New	Orleans's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	New	Orleans's	receivable	from the	money	pool	increased	$1.8	million	in	2013	compared	to	decreasing	$6.2	million	in	2012.	The	money	pool	is	an	inter-company	borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	increased	$32.0	million	in	2012	primarily	due	to:

•higher	distribution	construction	expenditures	due	to	Hurricane	Isaac;

•money	pool	activity;	and

•the	repayment	by	System	Fuels	of	Entergy	New	Orleans's	$3.3	million	investment	in	System	Fuels	in	2011.

The	increase	was	partially	offset	by	net	receipts	from	the	storm	escrow	account	of	$1.4	million	in	2012	compared	to	net	payments	to	the	storm escrow	account	of	$6.0	million	in	2011.

Decreases	in	Entergy	New	Orleans's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	New	Orleans's	receivable from	the	money	pool	decreased	$6.2	million	in	2012	compared	to	decreasing	$12.7	million	in	2011.

Net	cash	provided	by	financing	activities	increased	$1.9	million	in	2013	primarily	due	to	the	issuance	of	$100	million	of	3.90%	Series	first mortgage	bonds	in	June	2013	compared	to	the	issuance	of	$30	million	of	5.0%	Series	first	mortgage	bonds	in	November	2012.	The	increase	was substantially	offset	by	the	retirement	of	$70	million	of	5.25%	Series	first	mortgage	bonds	in	August	2013.

Entergy	New	Orleans's	financing	activities	provided	$25.5	million	in	2012	compared	to	using	$44.1	million	in	2011	primarily	due	to	a decrease	of	$40.3	million	in	common	stock	dividends	paid	and	the	issuance	of	$30	million	of	5.0%	Series	first	mortgage	bonds	in	November 2012.

Entergy	New	Orleans's	capitalization	is	balanced	between	equity	and	debt	as	shown	in	the	following	table.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 50.0% | 47.7% |
| Effect\tof\tsubtracting\tcash | (4.0%) | (1.2%) |
| Net\tdebt\tto\tnet\tcapital | 46.0% | 46.5% |

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.		Debt	consists	of	short-term	borrowings	and	long-term	debt,	including	the	currently maturing	portion.		Capital	consists	of	debt,	preferred	stock	without	sinking	fund,	and	common	equity.		Net	capital	consists	of	capital	less	cash	and cash	 equivalents.	 	 Entergy	 New	 Orleans	 uses	 the	 debt	 to	 capital	 ratio	 in	 analyzing	 its	 financial	 condition	 and	 believes	 it	 provides	 useful information	to	its	investors	and	creditors	in	evaluating	Entergy	New	Orleans's	financial	condition.	Entergy	New	Orleans	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	evaluation	Entergy	New Orleans's	financial	condition	because	net	debt	indicates	Entergy	New	Orleans's	outstanding	debt	position	that	could	not	be	readily	satisfied	by cash	and	cash	equivalents.

Entergy	New	Orleans	requires	capital	resources	for:

•working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;

•debt	and	preferred	stock	maturities	or	retirements;	and

•dividend	payments.

Following	are	the	amounts	of	Entergy	New	Orleans's	planned	construction	and	other	capital	investments.

|  | 2014 | 2015 | 2016 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $15 | $15 | $15 |
| Transmission | 25 | 15 | 15 |
| Distribution | 30 | 25 | 25 |
| Other | 25 | 25 | 25 |
| Total | $95 | $80 | $80 |

Following	are	the	amounts	of	Entergy	New	Orleans's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | After	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $11 | $21 | $21 | $331 | $384 |
| Operating\tleases | $2 | $4 | $2 | $2 | $10 |
| Purchase\tobligations\t(b) | $206 | $407 | $400 | $1,617 | $2,630 |

(b) 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	financial	statements.

In	addition	to	the	contractual	obligations	given	above,	Entergy	New	Orleans	currently	expects	to	contribute	approximately	$10.5	million	to	its pension	plan	in	2014	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are completed	 by	April	 1,	 2014.	See	"Critical	Accounting	 Estimates	 -	 Qualified	 Pension	 and	 Other	 Postretirement	 Benefits "	 below	 for	 a discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also	in	addition	to	the	contractual	obligations,	Entergy	New	Orleans	has	$29.6	million	of	unrecognized	tax	benefits	and	interest	net	of unused	tax	attributes	and	payments	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably	estimated	due	to	uncertainties	in	the timing	of	effective	settlement	of	 tax	positions.	See	Note	3	to	the	financial	statements	for	additional	information	regarding	unrecognized	tax benefits.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	New	Orleans	includes specific	investments	and	initiatives	such	as	transmission	spending	to	support	economic	development	projects,	reliability,	and	new	compliance projects.		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,	changes	in	project	plans,	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	financial	statements.

As	an	indirect,	wholly-owned	subsidiary	of	Entergy	Corporation,	Entergy	New	Orleans	pays	dividends	from	its	earnings	at	a	percentage determined	monthly.	Entergy	New	Orleans's	long-term	debt	indenture	contains	restrictions	on	the	payment	of	cash	dividends	or	other	distributions on	its	common	and	preferred	stock.

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

•cash	on	hand;	and

•debt	and	preferred	stock	issuances.

Entergy	New	Orleans	may	refinance,	redeem,	or	otherwise	retire	debt	and	preferred	stock	prior	to	maturity,	to	the	extent	market	conditions and	interest	and	dividend	rates	are	favorable.

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $4,737 | $2,923 | $9,074 | $21,820 |

Entergy	New	Orleans	has	a	credit	facility	in	the	amount	of	$25	million	scheduled	to	expire	in	November	2014.	No	borrowings	were outstanding	under	the	facility	as	of	December	31,	2013.	See	Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit	facility.	In addition,	Entergy	New	Orleans	entered	into	an	uncommitted	letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	under MISO.		As	of	December	31,	2013,	an$8.5	million	letter	of	credit	was	outstanding	under	Entergy	New	Orleans's	letter	of	credit	facility.

Entergy	New	Orleans	has	obtained	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow	through	October	2015, up	to	the	aggregate	amount,	at	any	one	time	outstanding,	of	$100	million.	See	Note	4	to	the	financial	statements	for	further	discussion	of	Entergy New	Orleans's	short-term	borrowing	limits.	The	long-term	securities	issuances	of	Entergy	New	Orleans	are	limited	to	amounts	authorized	by	the City	Council,	and	the	current	authorization	extends	through	July	2014.

In	June	2011,	Entergy	Louisiana	filed	with	the	LPSC	an	application	seeking	certification	that	the	public	necessity	and	convenience	would be	served	by	Entergy	Louisiana's	construction	of	a	combined-cycle	gas	turbine	generating	facility	(Ninemile	6)	at	its	existing	Ninemile	Point electric	generating	station.	Ninemile	6	will	be	a	nominally-sized	550	MW	unit	that	is	estimated	to	cost	approximately	$721	million	to	construct, excluding	interconnection	and	transmission	upgrades.	Entergy	Gulf	States	Louisiana	joined	in	the	application,	seeking	certification	of	its	purchase under	a	life-of-unit	power	purchase	agreement	of	up	to	25%	of	the	capacity	and	energy	generated	by	Ninemile	6.	The	Ninemile	6	capacity	and energy	is	proposed	to	be	allocated	55%	to	Entergy	Louisiana,	25%	to	Entergy	Gulf	States	Louisiana,	and	20%	to	Entergy	New	Orleans.	In February	2012	the	City	Council	passed	a	resolution	authorizing	Entergy	New	Orleans	to	purchase	20%	of	the	Ninemile	6	energy	and	capacity. Entergy	New	Orleans	expects	to	initiate	a	rate	proceeding	prior	to	the	in-service	date	of	Ninemile	6.	In	March	2012	the	LPSC	unanimously	voted to	grant	the	certifications	requested	by	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana.	Following	approval	by	the	LPSC,	Entergy	Louisiana issued	full	notice	to	proceed	to	the	project's	engineering,	procurement,	and	construction	contractor.	All	major	permits	and	approvals	required	to begin	construction	have	been	obtained	and	construction	is	in	progress.

# State	and	Local	Rate	Regulation

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	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.

# Rate	Cases,	Formula	Rate	Plans	and	Storm-related	Riders

In	May	2012,	Entergy	New	Orleans	filed	its	electric	and	gas	formula	rate	plan	evaluation	reports	for	the	2011	test	year.		Subsequent adjustments	agreed	upon	with	the	City	Council	Advisors	indicate	a	$4.9	million	electric	base	revenue	increase	and	a	$0.05	million	gas	base revenue	increase	as	necessary	under	the	formula	rate	plan.		As	part	of

the	original	filing,	Entergy	New	Orleans	also	requested	to	increase	annual	funding	for	its	storm	reserve	by	approximately	$5.7	million	for	five years.		On	September	26,	2012,	Entergy	New	Orleans	made	a	filing	with	the	City	Council	that	implemented	the	$4.9	million	electric	formula	rate plan	rate	increase	and	the	$0.05	million	gas	formula	rate	plan	rate	increase.		The	new	rates	were	effective	with	the	first	billing	cycle	in	October 2012.		In	August	2013	the	City	Council	unanimously	approved	a	settlement	of	all	issues	in	the	formula	rate	plan	proceeding.		Pursuant	to	the terms	of	the	settlement,	Entergy	New	Orleans	implemented	an	approximately	$1.625	million	net	decrease	to	the	electric	rates	that	were	in	effect prior	to	the	electric	rate	increase	implemented	in	October	2012,	with	no	change	in	gas	rates.	 	Entergy	New	Orleans	refunded	to	customers approximately	$6.0	million	over	the	four-month	period	from	September	2013	through	December	2013	to	make	the	electric	rate	decrease	effective as	of	the	first	billing	cycle	of	October	2012.		Entergy	New	Orleans	had	previously	recorded	provisions	for	the	majority	of	the	refund	to	customers, but	recorded	an	additional	$1.1	million	provision	in	second	quarter	2013	as	a	result	of	the	settlement.	The	City	Council	has	not	yet	acted	on Entergy	New	Orleans's	request	for	an	increase	in	storm	reserve	funding.		Entergy	New	Orleans's	formula	rate	plan	ended	with	the	2011	test	year and	has	not	yet	been	extended.		Entergy	New	Orleans	expects	to	initiate	a	rate	proceeding	prior	to	the	in-service	date	of	the	Ninemile	6	generating facility.

In	October	2006,	the	City	Council	approved	a	rate	filing	settlement	agreement	that,	among	other	things,	authorized	a	$75	million	storm reserve	for	damage	from	future	storms,	which	will	be	created	over	a	ten-year	period	through	a	storm	reserve	rider	that	began	in	March	2007.	These storm	reserve	funds	are	held	in	a	restricted	escrow	account	until	needed	in	response	to	a	storm.	Entergy	New	Orleans	withdrew	a	total	of	$17.4 million	from	the	storm	reserve	escrow	account	in	2012	and	2013	to	partially	offset	the	costs	associated	with	Hurricane	Isaac.

Entergy	New	Orleans'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	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	preparation	of	Entergy	New	Orleans'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	that	could	produce	estimates	that	would	have	a	material	impact	on	the	presentation	of	Entergy	New	Orleans's financial	position	or	results	of	operations.

As	discussed	in	Note	1	to	the	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.		Therefore,	revenue	recognized	may	be	affected	by	the	estimated price	and	usage	at	the	beginning	and	end	of	each,	in	addition	to	changes	in	certain	components	of	the	calculation.

| Discount	rate | (0.25%) | $537 | $5,396 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $267 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $215 | $917 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Impact	on	2013	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $71 | $1,448 |
| Health\tcare\tcost\ttrend | 0.25% | $219 | $1,210 |

Total	qualified	pension	cost	for	Entergy	New	Orleans	in	2013	was	$10.4	million,	including	a	$343	thousand	curtailment	loss	and	a	$581 thousand	special	termination	benefit	related	to	workforce	downsizing.		Entergy	New	Orleans	anticipates	2014	qualified	pension	cost	to	be	$6.6 million.		Entergy	New	Orleans	contributed	$4.2	million	to	its	pension	plans	in	2013	and	estimates	2014	pension	contributions	to	be	approximately $10.5	million;	although	 the	required	pension	contributions	will	not	be	known	with	more	certainty	until	 the	January	1,	2014	valuations	are completed	by	April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	New	Orleans	in	2013	were	$2.6	million,	including	a	$354 thousand	curtailment	charge	due	to	workforce	downsizing.			Entergy	New	Orleans	expects	2014	postretirement	health	care	and	life	insurance benefit	 income	 to	 approximate	 $1.4	 million.	 Entergy	 New	 Orleans	 contributed	 $2.6	 million	 to	 its	 other	 postretirement	 plans	 in	 2013	 and anticipates	no	required	contribution	in	2014.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	New	Orleans,	Inc.	(the	"Company")	as	of	December	31,	2013	and	2012,	and	the related	income	statements,	statements	of	cash	flows,	and	statements	of	changes	in	common	equity	(pages	388	through	392	and	applicable	items	in pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December	31,	2013.	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,	2013	and	2012,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $525,041 | $487,633 | $529,228 |
| Natural\tgas | 95,115 | 82,107 | 100,957 |
| TOTAL | 620,156 | 569,740 | 630,185 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 116,715 | 107,616 | 173,668 |
| Purchased\tpower | 253,202 | 222,193 | 207,604 |
| Other\toperation\tand\tmaintenance | 136,003 | 122,143 | 106,817 |
| Taxes\tother\tthan\tincome\ttaxes | 48,659 | 43,189 | 42,032 |
| Depreciation\tand\tamortization | 37,717 | 36,726 | 35,026 |
| Other\tregulatory\tcharges\t-\tnet | 996 | 1,983 | 1,910 |
| TOTAL | 593,292 | 533,850 | 567,057 |
| OPERATING\tINCOME | 26,864 | 35,890 | 63,128 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 920 | 791 | 622 |
| Interest\tand\tinvestment\tincome | 89 | 47 | 154 |
| Miscellaneous\t-\tnet | (1,401) | (1,453) | (1,234) |
| TOTAL | (392) | (615) | (458) |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 13,675 | 11,344 | 11,114 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (505) | (374) | (282) |
| TOTAL | 13,170 | 10,970 | 10,832 |
| INCOME\tBEFORE\tINCOME\tTAXES | 13,302 | 24,305 | 51,838 |
| Income\ttaxes | 1,619 | 7,240 | 15,862 |
| NET\tINCOME | 11,683 | 17,065 | 35,976 |
| Preferred\tdividend\trequirements\tand\tother |  |  |  |
|  | 965 | 965 | 965 |
| EARNINGS\tAPPLICABLE\tTO |  |  |  |
| COMMON\tSTOCK | $10,718 | $16,100 | $35,011 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $11,683 | $17,065 | $35,976 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\nactivities: |  |  |  |
| Depreciation\tand\tamortization | 37,717 | 36,726 | 35,026 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | (7,427) | 15,016 | (35,276) |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (6,508) | (29,046) | 24,275 |
| Fuel\tinventory | (1,222) | 2,029 | (1,160) |
| Accounts\tpayable | 5,987 | 4,828 | (3,502) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 2,886 | (1,377) | — |
| Interest\taccrued | 578 | 180 | 12 |
| Deferred\tfuel\tcosts | 20,988 | (9,464) | 4,694 |
| Other\tworking\tcapital\taccounts | 269 | 14,239 | (7,764) |
| Provisions\tfor\testimated\tlosses | (31) | (812) | 4,637 |
| Other\tregulatory\tassets | 64,810 | (23,188) | (42,667) |
| Pension\tand\tother\tpostretirement\tliabilities | (51,293) | 9,773 | 25,202 |
| Other\tassets\tand\tliabilities | 7,889 | 16,120 | 5,474 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 86,326 | 52,089 | 44,927 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (88,864) | (86,373) | (56,600) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 920 | 791 | 622 |
| Investments\tin\taffiliates | — | — | 3,256 |
| Change\tin\tmoney\tpool\treceivable\t-\tnet | (1,814) | 6,151 | 12,746 |
| Payments\tto\tstorm\treserve\tescrow\taccount | (7,663) | (8,609) | (6,043) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 7,755 | 10,000 | — |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (89,666) | (78,040) | (46,019) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 98,471 | 28,422 | — |
| Retirement\tof\tlong-term\tdebt | (70,068) | — | — |
| Dividends\tpaid: |  |  |  |
| Common\tstock | — | (1,700) | (42,000) |
| Preferred\tstock | (965) | (965) | (965) |
| Other | — | (249) | (1,095) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | 27,438 | 25,508 | (44,060) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 24,098 | (443) | (45,152) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 9,391 | 9,834 | 54,986 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $33,489 | $9,391 | $9,834 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $12,050 | $10,183 | $10,109 |
| Income\ttaxes | ($1,448) | ($12,952) | $39,403 |

| Cash | $317 | $319 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 33,172 | 9,072 |
| Total\tcash\tand\tcash\tequivalents | 33,489 | 9,391 |
| Accounts\treceivable: |  |  |
| Customer | 38,872 | 33,142 |
| Allowance\tfor\tdoubtful\taccounts | (974) | (446) |
| Associated\tcompanies | 32,273 | 29,326 |
| Other | 2,667 | 3,115 |
| Accrued\tunbilled\trevenues | 18,745 | 18,124 |
| Total\taccounts\treceivable | 91,583 | 83,261 |
| Accumulated\tdeferred\tincome\ttaxes | 12,018 | 9,517 |
| Fuel\tinventory\t-\tat\taverage\tcost | 2,999 | 1,777 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 11,696 | 10,889 |
| Prepaid\ttaxes | — | 1,377 |
| Prepayments\tand\tother | 4,178 | 3,201 |
| TOTAL | 155,963 | 119,413 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Non-utility\tproperty\tat\tcost\t(less\taccumulated\tdepreciation) | 1,016 | 1,016 |
| Storm\treserve\tescrow\taccount | 10,513 | 10,605 |
| TOTAL | 11,529 | 11,621 |
| UTILITY\tPLANT |  |  |
| Electric | 889,629 | 860,358 |
| Natural\tgas | 222,463 | 217,769 |
| Construction\twork\tin\tprogress | 29,312 | 11,135 |
| TOTAL\tUTILITY\tPLANT | 1,141,404 | 1,089,262 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 566,948 | 549,587 |
| UTILITY\tPLANT\t-\tNET | 574,456 | 539,675 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Deferred\tfuel\tcosts | 4,080 | 4,080 |
| Other\tregulatory\tassets | 137,191 | 202,003 |
| Other | 5,577 | 4,997 |
| TOTAL | 146,848 | 211,080 |
| TOTAL\tASSETS | $888,796 | $881,789 |

| Currently	maturing	long-term	debt | $— | $70,000 |
| :--- | :--- | :--- |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 36,193 | 28,778 |
| Other | 27,840 | 31,209 |
| Customer\tdeposits | 22,959 | 21,974 |
| Taxes\taccrued | 1,509 | — |
| Interest\taccrued | 3,598 | 3,020 |
| Deferred\tfuel\tcosts | 23,145 | 2,157 |
| System\tagreement\tcost\tequalization | 17,040 | 16,880 |
| Other | 4,387 | 3,479 |
| TOTAL\tCURRENT\tLIABILITIES | 136,671 | 177,497 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 183,636 | 172,790 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 1,082 | 1,300 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 2,495 | 24,291 |
| Other\tregulatory\tliabilities | 26,361 | 11,060 |
| Asset\tretirement\tcost\tliabilities | 2,347 | 2,193 |
| Accumulated\tprovisions | 15,000 | 15,031 |
| Pension\tand\tother\tpostretirement\tliabilities | 32,497 | 83,790 |
| Long-term\tdebt | 225,944 | 126,300 |
| Gas\tsystem\trebuild\tinsurance\tproceeds | 32,760 | 44,207 |
| Other | 3,940 | 7,985 |
| TOTAL\tNON-CURRENT\tLIABILITIES | 526,062 | 488,947 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 19,780 | 19,780 |
| COMMON\tEQUITY |  |  |
| Common\tstock,\t$4\tpar\tvalue,\tauthorized\t10,000,000 |  |  |
| shares;\tissued\tand\toutstanding\t8,435,900\tshares\tin\t2013 |  |  |
| and\t2012 | 33,744 | 33,744 |
| Paid-in\tcapital | 36,294 | 36,294 |
| Retained\tearnings | 136,245 | 125,527 |
| TOTAL | 206,283 | 195,565 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $888,796 | $881,789 |

|  | Common	Stock | Paid-in	Capital | Retained<br>Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2010 | $33,744 | $36,294 | $118,116 | $188,154 |
| Net\tincome | — | — | 35,976 | 35,976 |
| Common\tstock\tdividends | — | — | (42,000) | (42,000) |
| Preferred\tstock\tdividends | — | — | (965) | (965) |
| Balance\tat\tDecember\t31,\t2011 | $33,744 | $36,294 | $111,127 | $181,165 |
| Net\tincome | — | — | 17,065 | 17,065 |
| Common\tstock\tdividends | — | — | (1,700) | (1,700) |
| Preferred\tstock\tdividends | — | — | (965) | (965) |
| Balance\tat\tDecember\t31,\t2012 | $33,744 | $36,294 | $125,527 | $195,565 |
| Net\tincome | — | — | 11,683 | 11,683 |
| Preferred\tstock\tdividends | — | — | (965) | (965) |
| Balance\tat\tDecember\t31,\t2013 | $33,744 | $36,294 | $136,245 | $206,283 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $620,156 | $569,740 | $630,185 | $659,449 | $640,422 |
| Net\tincome | $11,683 | $17,065 | $35,976 | $31,114 | $30,479 |
| Total\tassets | $888,796 | $881,789 | $806,035 | $850,076 | $995,818 |
| Long-term\tobligations\t(a) | $245,724 | $146,080 | $186,317 | $186,995 | $187,803 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $197 | $174 | $176 | $196 | $168 |
| Commercial | 183 | 164 | 154 | 174 | 166 |
| Industrial | 35 | 31 | 30 | 36 | 37 |
| Governmental | 67 | 63 | 59 | 70 | 70 |
| Total\tretail | 482 | 432 | 419 | 476 | 441 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 27 | 44 | 95 | 56 | 87 |
| Non-associated\tcompanies | — | — | 1 | 1 | 1 |
| Other | 16 | 12 | 14 | 10 | 7 |
| Total | $525 | $488 | $529 | $543 | $536 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 1,867 | 1,772 | 1,888 | 1,858 | 1,577 |
| Commercial | 1,998 | 1,968 | 1,939 | 1,899 | 1,813 |
| Industrial | 481 | 484 | 498 | 503 | 526 |
| Governmental | 758 | 785 | 795 | 809 | 805 |
| Total\tretail | 5,104 | 5,009 | 5,120 | 5,069 | 4,721 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 495 | 978 | 1,167 | 906 | 1,528 |
| Non-associated\tcompanies | 13 | 8 | 19 | 13 | 15 |
| Total | 5,612 | 5,995 | 6,306 | 5,988 | 6,264 |

# ENTERGY	TEXAS,	INC.	AND	SUBSIDIARIES

Net	income	increased	$15.9	million	primarily	due	to	higher	net	revenue	and	a	lower	effective	income	tax	rate,	partially	offset	by	higher other	operation	and	maintenance	expenses	and	higher	depreciation	and	amortization	expenses.

Net	 income	 decreased	 $38.9	 million	 primarily	 due	 to	 lower	 net	 revenue,	 higher	 other	 operation	 and	 maintenance	 expenses,	 higher depreciation	and	amortization	expenses,	and	lower	other	income,	partially	offset	by	lower	taxes	other	than	income	taxes.

|  | Amount |
| :--- | :--- |
|  | (In\tMillions) |
| 2012\tnet\trevenue | $551.0 |
| Volume/weather | 13.9 |
| Retail\telectric\tprice | 13.3 |
| Fuel\trecovery | 6.5 |
| Hurricane\tRita\tregulatory\tasset\tadjustment | 6.4 |
| Net\twholesale\trevenue | 4.7 |
| Purchased\tpower\tcapacity | (10.5) |
| Other | 1.2 |
| 2013\tnet\trevenue | $586.5 |

The	volume/weather	variance	is	primarily	due	to	an	increase	of	470	GWh,	or	2.8%,	in	billed	electricity	usage,	including	the	effect	of	more favorable	weather	compared	to	last	year	on	residential	sales	and	increased	usage	in	the	industrial	sector	compared	to	prior	year	as	a	result	of	an unplanned	outage	in	the	refining	industry	in	2012.

The	retail	electric	price	variance	is	primarily	due	to	an	annual	base	rate	increase	of	$28	million,	effective	July	2012,	as	a	result	of	the PUCT's	order	in	the	November	2011	rate	case.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order.

The	fuel	recovery	variance	is	primarily	the	result	of	a	$6	million	adjustment	to	deferred	fuel	costs	recorded	in	third	quarter	2012	in accordance	with	a	rate	order	from	the	PUCT	issued	in	September	2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT order	issued	in	Entergy	Texas's	2011	rate	case.

The	Hurricane	Rita	regulatory	asset	adjustment	of	$6.4	million	was	recorded	in	third	quarter	2012	in	accordance	with	the	rate	order	from the	PUCT	issued	in	September	2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order.

The	net	wholesale	revenue	variance	is	primarily	due	to	contract	changes	for	municipals	and	co-op	customers.

The	purchased	power	capacity	variance	is	primarily	due	to	additional	capacity	purchases	as	well	as	price	increases	for	ongoing	purchased power	capacity.

•an	increase	of	$67.5	million	in	gross	wholesale	revenues	as	a	result	of	an	increase	in	sales	to	affiliated	customers	and	higher	prices;

•an	increase	of	$20.9	million	in	rider	revenues	primarily	due	to	System	Agreement	credits	in	2012;

•an	increase	of	$15.2	million	in	fuel	cost	recovery	revenue	due	to	higher	fuel	rates;

•favorable	weather/volume,	as	discussed	above;	and

•the	annual	base	rate	increase	effective	July	2012,	as	discussed	above.

Fuel	and	purchased	power	expenses	increased	primarily	due	to	increases	in	the	average	market	prices	of	natural	gas	and	purchased	power and	increased	demand,	partially	offset	by	a	decrease	in	the	recovery	from	customers	of	deferred	fuel	costs.

| 2011	net	revenue | $577.8 |
| :--- | :--- |
| Volume/weather | (22.7) |
| Purchased\tpower\tcapacity | (20.1) |
| Fuel\trecovery | (6.5) |
| Retail\telectric\tprice | 15.1 |
| Reserve\tequalization | 20.2 |
| Other | (12.8) |
| 2012\tnet\trevenue | $551.0 |

The	volume/weather	variance	is	primarily	due	to	a	decrease	of	519	GWh,	or	3.1%,	in	billed	electricity	usage,	including	the	effect	of	milder weather	compared	to	prior	year	on	residential	and	commercial	sales.

The	fuel	recovery	variance	is	primarily	the	result	of	a	$6	million	adjustment	to	deferred	fuel	costs	in	accordance	with	a	rate	order	from	the PUCT	issued	in	September	2012.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order.

The	retail	electric	price	variance	is	primarily	due	to	rate	actions,	including	an	annual	base	rate	increase	of	$9	million	beginning	May	2011 as	a	result	of	the	settlement	of	the	December	2009	rate	case	and	an	annual	base	rate	increase	of	$28	million,	effective	July	2012,	as	a	result	of	the PUCT's	order	in	the	December	2011	rate	case.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate	cases.

The	reserve	equalization	variance	is	primarily	due	to	decreased	reserve	equalization	expense	as	a	result	of	changes	in	the	Entergy	System generation	mix	compared	to	the	same	period	in	2011.

•a	decrease	of	$156.2	million	in	fuel	cost	recovery	revenues	primarily	attributable	to	lower	fuel	rates	and	lower	usage,	offset	by	lower interim	fuel	refunds	in	2012	versus	2011.		Entergy	Texas's	fuel	and	purchased	power	recovery	mechanism	is	discussed	in	Note	2	to	the financial	statements.		The	interim	fuel	refunds	and	the	PUCT	approvals	are	discussed	in	Note	2	to	the	financial	statements;	and •less	favorable	volume/weather,	as	discussed	above.

The	decrease	was	partially	offset	by	an	increase	of	$12.2	million	in	gross	wholesale	revenues	as	a	result	of	an	increase	in	sales	to	affiliated customers,	offset	by	a	decrease	in	sales	volume	to	municipal	and	co-op	customers.

Fuel	and	purchased	power	expenses	decreased	primarily	due	to	decreases	in	the	average	market	prices	of	natural	gas	and	purchased	power, partially	offset	by	an	increase	in	deferred	fuel	expense.		The	increase	in	deferred	fuel	expense	is	due	to	an	adjustment	to	deferred	fuel	costs	in accordance	with	a	rate	order	from	the	PUCT	issued	in	September	2012	and	as	a	result	of	lower	interim	fuel	refunds	in	2012	versus	2011,	offset	by lower	fuel	revenues,	as	discussed	above.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order.

Other	regulatory	charges	increased	primarily	due	to	the	distribution	in	the	first	quarter	2011	of	$17.4	million	to	customers	of	the	2007 rough	production	cost	equalization	remedy	receipts.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rough	production	cost equalization	proceedings.

•an	increase	of	$9	million	in	compensation	and	benefit	costs	primarily	due	to	a	decrease	in	the	discount	rates	used	to	determine	net	periodic pension	and	other	postretirement	benefit	costs	and	a	settlement	charge,	recognized	in	September	2013,	related	to	the	payment	of	lump	sum benefits	out	of	the	non-qualified	pension	plan.	See	"Critical	Accounting	Estimates"	below	and	Note	11	to	the	financial	statements	for further	discussion	of	benefits	costs;

•an	increase	of	$8.8	million	resulting	from	implementation	costs,	severance	costs,	and	curtailment	and	special	termination	benefits	in	2013 related	to	the	human	capital	management	strategic	imperative.	See	the	"Human	Capital	Management	Strategic	Imperative"	section	of Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	further	discussion;

•an	increase	of	$2.3	million	primarily	due	to	storm	damage	accruals	in	accordance	with	a	rate	order	from	PUCT	issued	in	September	2012. See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order;

•an	increase	of	$1.7	million	in	distribution	contract	work	relating	primarily	to	vegetation	maintenance;	and •an	increase	of	$1.4	million	in	insurance	expenses	primarily	due	to	increases	in	premiums.

•the	amortization	of	$4.3	million	of	Hurricane	Rita	storm	costs	in	prior	year	in	accordance	with	a	rate	order	from	the	PUCT	issued	in September	2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order;	and •a	decrease	of	$2.7	million	in	fossil-fueled	expenses	due	to	a	reduced	scope	of	work	and	fewer	outages	compared	to	2012.

Other	income	increased	primarily	due	to	the	reversal	in	2012	of	$6.7	million	of	disallowed	carrying	charges	on	Hurricane	Rita	storm restoration	costs	in	accordance	with	a	rate	order	from	the	PUCT	issued	in	September	2012.	See	Note	2	to	the	financial	statements	for	further discussion	of	the	PUCT	rate	order.

Taxes	other	than	income	taxes	increased	primarily	due	to	a	reduction	in	the	provision	recorded	for	sales	and	use	taxes	in	2012.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service	and	an	increase	in	depreciation	rates	as	a result	of	the	2011	rate	case	order	issued	by	the	PUCT	in	September	2012.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the PUCT	rate	order.

•an	increase	of	$7.2	million	in	fossil-fueled	generation	expenses	due	to	a	greater	scope	of	work	and	an	additional	outage	in	2012	compared to	2011;

•the	amortization	of	$4.3	million	of	Hurricane	Rita	storm	costs	in	accordance	with	a	rate	order	from	the	PUCT	issued	in	September 2012.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order;

•an	increase	of	$3.5	million	in	compensation	and	benefit	costs	primarily	due	to	decreasing	discount	rates	and	changes	in	certain	actuarial assumptions	resulting	from	an	experience	study.			See	"Critical	Accounting	Estimates"	below	for	further	discussion	of	benefits	costs; •an	increase	of	$2.7	million	in	loss	reserves	in	2012;	and

•an	increase	of	$2.3	million	in	storm	damage	reserves	in	accordance	with	a	rate	order	from	the	PUCT	issued	in	September	2012.		See	Note 2	to	the	financial	statements	for	further	discussion	of	the	PUCT	rate	order.

The	increase	was	partially	offset	by	a	decrease	of	$1.8	million	in	energy	efficiency	costs.		These	costs	are	recovered	through	the	energy efficiency	rider	and	have	no	effect	on	net	income.

Taxes	other	than	income	taxes	decreased	primarily	due	to	a	reduction	in	the	provision	recorded	for	sales	and	use	taxes.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service	and	an	increase	in	depreciation	rates	as	a result	of	the	rate	order	approved	by	the	PUCT	in	September	2012.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate	order.

Other	income	decreased	primarily	due	to	the	reversal	of	$6.7	million	of	disallowed	carrying	charges	on	Hurricane	Rita	storm	restoration costs	in	accordance	with	a	rate	order	from	the	PUCT	issued	in	September	2012.		See	Note	2	to	the	financial	statements	for	further	discussion	of	the PUCT	rate	order.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $60,236 | $65,289 | $35,342 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 237,054 | 271,081 | 238,837 |
| Investing\tactivities | (164,309) | (128,904) | (219,783) |
| Financing\tactivities | (86,493) | (147,230) | 10,893 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (13,748) | (5,053) | 29,947 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $46,488 | $60,236 | $65,289 |

Net	cash	flow	provided	by	operating	activities	decreased	$34	million	in	2013	primarily	due	to:

•the	receipt,	in	January	2012,	of	$43	million	in	System	Agreement	bandwidth	remedy	payments	required	to	implement	the	FERC's	remedy in	an	October	2011	order	for	the	period	June-December	2005.	As	of	March	31,	2013,	all	of	the	$43	million,	plus	interest,	had	been credited	to	Entergy	Texas	customers,	with	the	final	$9.5	million	being	credited	in	the	first	quarter	2013.	See	Note	2	to	the	financial statements	for	a	discussion	of	the	System	Agreement	proceedings;

•$86.1	million	of	fuel	cost	refunds	in	2013,	compared	to	$67.2	million	of	fuel	cost	refunds	in	2012.	See	Note	2	to	the	financial	statements for	discussion	of	the	fuel	cost	refunds;	and

•the	timing	of	collections	of	receivables	from	customers.

The	decrease	was	partially	offset	by	an	increase	of	$55.3	million	in	income	tax	refunds.	Entergy	Texas	had	income	tax	refunds	in	2013	in accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement.	The	refunds	resulted	from the	utilization	of	Entergy	Texas's	taxable	losses	against	taxable	income	of	other	members	of	the	Entergy	consolidated	group.

Entergy	Texas,	Inc.	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

Net	cash	provided	by	operating	activities	increased	$32.2	million	in	2012	primarily	due	to:

•an	increase	in	the	recovery	of	fuel	costs	due	to	System	Agreement	bandwidth	remedy	payments	of	$43	million	received	in	January	2012	as a	result	of	receipts	required	to	implement	the	FERC's	remedy	in	an	October	2011	order	for	the	period	June-December	2005.		In	the	fourth quarter	2012,	Entergy	Texas	customers	were	credited	$28.4	million.		See	Note	2	to	the	financial	statements	for	a	discussion	of	the	System Agreement	proceedings;

•a	decrease	of	$9.1	million	in	pension	contributions.		See	"Critical	Accounting	Estimates"	below	for	a	discussion	of	qualified	pension and	other	postretirement	benefits;	and

•$67.2	million	of	fuel	cost	refunds	in	2012	compared	to	$73.4	million	of	fuel	cost	refunds	in	2011.		See	Note	2	to	the	financial	statements for	discussion	of	the	fuel	cost	refunds.

The	increase	was	partially	offset	by	a	decrease	of	$11.3	million	in	income	tax	refunds.

•an	increase	in	transmission	construction	expenditures	due	to	reliability	work	performed	in	2013;	and •an	increase	in	distribution	construction	expenditures	due	to	an	increased	scope	of	work	in	2013.

The	increase	was	offset	by	lower	fossil-fueled	generation	construction	expenditures	due	to	a	greater	scope	of	projects	in	2012.

Decreases	in	Entergy	Texas's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Texas's	receivable	from	the	money pool	decreased	by	$12.9	million	 in	2013	compared	 to	decreasing	by	$44	million	 in	2012.	The	money	pool	 is	an	 inter-company	borrowing arrangement	designed	to	reduce	Entergy's	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	decreased	$90.9	million	in	2012	primarily	due	to	money	pool	activity,	partially	offset	by	higher fossil-fueled	generation	construction	expenditures	due	to	a	greater	scope	of	projects	in	2012.

Decreases	in	Entergy	Texas's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Texas's	receivable	from	the	money pool	decreased	by	$44	million	in	2012	compared	to	increasing	by	$49.5	million	in	2011.

Net	cash	flow	used	in	financing	activities	decreased	$60.7	million	in	2013	primarily	due	to	a	decrease	of	$62.2	million	in	common	stock dividends	paid.

Entergy	Texas's	financing	activities	used	$147.2	million	in	2012	compared	to	providing	$10.9	million	in	2011	primarily	due	to	an	increase of	$81.4	million	in	common	stock	dividends	paid	and	the	issuance	of	$75	million	of	4.10%	Series	first	mortgage	bonds	in	September	2011.

Entergy	Texas's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.

|  | December	31,<br>2013 | December	31,<br>2012 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 63.7% | 65.4% |
| Effect\tof\texcluding\tthe\tsecuritization\tbonds | (12.6%) | (13.3%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 51.1% | 52.1% |
| Effect\tof\tsubtracting\tcash | (1.3%) | (1.7%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 49.8% | 50.4% |

(a) Calculation	excludes	the	securitization	bonds,	which	are	non-recourse	to	Entergy	Texas.

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	long-term	debt,	including	the	currently	maturing	portion.	Capital	consists of	debt	and	common	equity.	Net	capital	consists	of	capital	less	cash	and	cash	equivalents.	Entergy	Texas	uses	the	debt	to	capital	ratios	excluding securitization	bonds	in	analyzing	its	financial	condition	and	believes	they	provide	useful	information	to	its	investors	and	creditors	in	evaluating Entergy	Texas's	financial	condition	because	the	securitization	bonds	are	non-recourse	to	Entergy	Texas,	as	more	fully	described	in	Note	5	to	the financial	statements.	Entergy	Texas	also	uses	the	net	debt	to	net	capital	ratio	excluding	securitization	bonds	in	analyzing	its	financial	condition and	believes	it	provides	useful	information	to	its	investors	and	creditors	in	evaluating	Entergy	Texas's	financial	condition	because	net	debt indicates	Entergy	Texas's	outstanding	debt	position	that	could	not	be	readily	satisfied	by	cash	and	cash	equivalents	on	hand.

Entergy	Texas	requires	capital	resources	for:

•debt	maturities	or	retirements;

•working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;	and

•dividend	and	interest	payments.

Following	are	the	amounts	of	Entergy	Texas's	planned	construction	and	other	capital	investments.

|  | 2014 | 2015 | 2016 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $55 | $30 | $15 |
| Transmission | 65 | 135 | 135 |
| Distribution | 80 | 85 | 90 |
| Other | 10 | 30 | 20 |
| Total | $210 | $280 | $260 |

Following	are the	amounts	of	Entergy	Texas's	existing	debt	and lease	obligations	(includes	estimated interest	payments)	and	other purchase	obligations.

|  | 2014 | 2015-2016 | 2017-2018 | After	2018 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $86 | $414 | $252 | $1,532 | $2,284 |
| Operating\tleases | $6 | $10 | $6 | $3 | $25 |
| Purchase\tobligations\t(b) | $64 | $98 | $101 | $197 | $460 |

(b) Purchase	obligations	represent	the	minimum	purchase	obligation	or	cancellation	charge	for	contractual	obligations	to	purchase	goods	or services.		For	Entergy	Texas,	it	primarily	includes	unconditional	fuel	and	purchased	power	obligations.

In	addition	to	the	contractual	obligations	given	above,	Entergy	Texas	expects	to	contribute	approximately	$18.5	million	to	its	pension	plans	and approximately	$4.6	million	to	other	postretirement	plans	in	2014	although	the	required	pension	contributions	will	not	be	known	with	more certainty	until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.	See	"Critical	Accounting	Estimates	-	Qualified	Pension	and Other	Postretirement	Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also	in	addition	to	the	contractual	obligations,	Entergy	Texas	has	$12.8	million	of	unrecognized	tax	benefits	and	interest	net	of	unused	tax attributes	and	payments	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably	estimated	due	to	uncertainties	in	the	timing	of effective	settlement	of	tax	positions.	See	Note	3	to	the	financial	statements	for	additional	information	regarding	unrecognized	tax	benefits.

In	addition	to	routine	capital	spending	to	maintain	operations,	the	planned	capital	investment	estimate	for	Entergy	Texas	includes	specific investments	 and	 initiatives	 such	 as	 transmission	 spending	 to	 support	 economic	 development	 projects,	 reliability,	 and	 new	 compliance projects.		Entergy's	Utility	supply	plan	initiative	will	continue	to	seek	to	transform	its	generation	portfolio	with	new	or	repowered	generation resources.	Opportunities	resulting	from	the	supply	plan	initiative,	including	new	projects	or	the	exploration	of	alternative	financing	sources,	could result	in	increases	or	decreases	in	the	capital	expenditure	estimates	given	above.	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,	changes	in	project	plans,	and	the	ability	to	access	capital.	Management	provides	more	information	on	long-term debt	in	Note	5	to	the	financial	statements.

As	a	wholly-owned	subsidiary,	Entergy	Texas	pays	dividends to	Entergy	Corporation	from its	earnings	at	a	percentage	determined monthly.

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

Entergy	Texas	may	refinance,	redeem,	or	otherwise	retire	debt	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	Texas	require	prior	regulatory	approval.	Debt	issuances	are	also	subject	to issuance	tests	set	forth	in	its	bond	indentures	and	other	agreements.	Entergy	Texas	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable capital	needs.

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $6,287 | $19,175 | $63,191 | $13,672 |

Entergy	Texas	has	a	credit	facility	in	the	amount	of	$150	million	scheduled	to	expire	in	March	2018.	The	credit	facility	allows	Entergy Texas	to	issue	letters	of	credit	against	50%	of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2013,	there	were	no	borrowings	and	$25 million	of	letters	of	credit	outstanding	under	the	facility.	See	Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit	facility.

Entergy	Texas	has	obtained	short-term	borrowing	authorization	through	October	2015	from	the	FERC	under	which	it	may	borrow	at	any one	time	outstanding,	$200	million	in	the	aggregate.	See	Note	4	to	the	financial	statements	for	further	discussion	of	Entergy	Texas's	short-term borrowing	limits.	Entergy	Texas	has	also	obtained	an	order	from	the	FERC	authorizing	long-term	securities	issuances	through	October	2015.

The	rates	that	Entergy	Texas	charges	for	its	services	significantly	influence	its	financial	position,	results	of	operations,	and	liquidity. Entergy	Texas	is	regulated	and	the	rates	charged	to	its	customers	are	determined	in	regulatory	proceedings.	The	PUCT,	a	governmental	agency,	is primarily	responsible	for	approval	of	the	rates	charged	to	customers.

# Filings	with	the	PUCT

In	November	2011,	Entergy	Texas	filed	a	rate	requesting	a	$112	million	base	rate	increase	reflecting	a	10.6%	return	on	common	equity based	on	an	adjusted	June	2011	test	year.	The	rate	case	also	proposed	a	purchased	power	recovery	rider.	On	January	12,	2012,	the	PUCT	voted not	to	address	the	purchased	power	recovery	rider	in	the	current	rate	case,	but	the	PUCT	voted	to	set	a	baseline	in	the	rate	case	proceeding	that would	be	applicable	if	a	purchased	power	capacity	rider	is	approved	in	a	separate	proceeding.	In	April	2012	the	PUCT	Staff	filed	direct	testimony recommending	a	base	rate	increase	of	$66	million	and	a	9.6%	return	on	common	equity.	The	PUCT	Staff,	however,

subsequently	filed	a	statement	of	position	in	the	proceeding	indicating	that	it	was	still	evaluating	the	position	it	would	ultimately	take	in	the	case regarding	Entergy	Texas's	recovery	of	purchased	power	capacity	costs	and	Entergy	Texas's	proposal	to	defer	its	MISO	transition	expenses.	 In April	2012,	Entergy	Texas	filed	rebuttal	testimony	indicating	a	revised	request	for	a	$105	million	base	rate	increase.	A	hearing	was	held	in	late- April	through	early-May	2012.

In	September	2012,	the	PUCT	issued	an	order	approving	a	$28	million	rate	increase,	effective	July	2012.	The	order	includes	a	finding	that "a	return	on	common	equity	(ROE)	of	9.80	percent	will	allow	[Entergy	Texas]	a	reasonable	opportunity	to	earn	a	reasonable	return	on	invested capital."	The	order	also	provides	for	increases	in	depreciation	rates	and	the	annual	storm	reserve	accrual.	The	order	also	reduced	Entergy	Texas's proposed	purchased	power	capacity	costs,	stating	that	they	are	not	known	and	measureable;	reduced	Entergy	Texas's	regulatory	assets	associated with	Hurricane	Rita;	excluded	from	rate	recovery	capitalized	financially-based	incentive	compensation;	included	$1.6	million	of	MISO	transition expense	in	base	rates,	and	reduced	Entergy's	Texas's	fuel	reconciliation	recovery	by	$4.0	million	because	it	disagreed	with	the	line-loss	factor used	in	the	calculation.	After	considering	the	progress	of	the	proceeding	in	light	of	the	PUCT	order,	Entergy	Texas	recorded	in	the	third	quarter 2012	an	approximate	$24	million	charge	to	recognize	that	assets	associated	with	Hurricane	Rita,	financially-based	incentive	compensation,	and fuel	recovery	are	no	longer	probable	of	recovery.	Entergy	Texas	continues	to	believe	that	it	is	entitled	to	recover	these	prudently	incurred	costs, however,	and	it	filed	a	motion	for	rehearing	regarding	these	and	several	other	issues	in	the	PUCT's	order	on	October	4,	2012.	Several	other	parties have	also	filed	motions	for	rehearing	of	 the	PUCT's	order.	The	PUCT	subsequently	denied	rehearing	of	substantive	 issues.	Several	 parties, including	Entergy	Texas,	have	appealed	the	PUCT's	order	to	the	Travis	County	District	Court.	A	hearing	is	expected	in	April	2014.

In	September	2013,	Entergy	Texas	filed	a	rate	case	requesting	a	$38.6	million	base	rate	increase	reflecting	a	10.4%	return	on	common equity	based	on	an	adjusted	test	year	ending	March	31,	2013.	The	rate	case	also	proposed	(1)	a	rough	production	cost	equalization	adjustment rider	recovering	Entergy	Texas's	payment	to	Entergy	New	Orleans	to	achieve	rough	production	cost	equalization	based	on	calendar	year	2012 production	costs	and	(2)	a	rate	case	expense	rider	recovering	the	cost	of	the	2013	rate	case	and	certain	costs	associated	with	previous	rate	cases. The	rate	case	filing	also	includes	a	request	to	reconcile	$0.9	billion	of	fuel	and	purchased	power	costs	and	fuel	revenues	covering	the	period	July 2011	 through	 March	 2013.	The	 fuel	 reconciliation	 also	 reflects	 special	 circumstances	 fuel	 cost	 recovery	 of	 approximately	 $22	 million	 of purchased	power	capacity	costs.	If	approved,	new	rates	could	go	into	effect	as	early	as	April	2014.	In	January	2014	the	PUCT	staff	filed	direct testimony	recommending	a	retail	rate	reduction	of	$0.3	million	and	a	9.2%	return	on	common	equity.	In	February	2014	the	ALJs	approved	a request	to	abate	the	procedural	schedule	indefinitely	while	settlement	discussions	continue.

Entergy	Texas's	rate	schedules	include	a	fixed	fuel	factor	to	recover	fuel	and	purchased	power	costs,	including	interest,	not	recovered	in base	rates.		Semi-annual	revisions	of	the	fixed	fuel	factor	are	made	in	March	and	September	based	on	the	market	price	of	natural	gas	and	changes in	fuel	mix.		The	amounts	collected	under	Entergy	Texas's	fixed	fuel	factor	and	any	interim	surcharge	or	refund	are	subject	to	fuel	reconciliation proceedings	before	the	PUCT.

In	December	2011,	Entergy	Texas	filed	with	the	PUCT	a	request	to	refund	approximately	$43	million,	including	interest,	of	fuel	cost recovery	over-collections	through	October	2011.		Entergy	Texas	and	the	parties	to	the	proceeding	reached	an	agreement	that	Entergy	Texas	would refund	$67	million,	including	interest	and	additional	over-recoveries	through	December	2011,	over	a	three-month	period.		Entergy	Texas	and	the parties	requested	that	interim	rates	consistent

with	the	settlement	be	approved	effective	with	the	March	2012	billing	month,	and	the	PUCT	approved	the	application	in	March	2012.		Entergy Texas	completed	this	refund	to	customers	in	May	2012.

In	July	2012,	Entergy	Texas	filed	with	the	PUCT	an	application	to	credit	its	customers	approximately	$37.5	million,	including	interest, resulting	from	the	FERC's	October	2011	order	 in	 the	System	Agreement	rough	production	cost	equalization	proceeding.	See	Note	2	 to	 the financial	statements	for	a	discussion	of	the	FERC's	October	2011	order.		In	September	2012	the	parties	submitted	a	stipulation	resolving	the proceeding.	 	 The	 stipulation	 provided	 that	 most	 Entergy	 Texas	 customers	 would	 be	 credited	 over	 a	 four-month	 period	 beginning	 October 2012.		The	credits	were	initiated	with	the	October	2012	billing	month	on	an	interim	basis,	and	the	PUCT	subsequently	approved	the	stipulation, also	in	October	2012.

Entergy	 Texas'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	Texas's	industrial	customer	base.	Entergy	Texas	responds	by	working	with	industrial and	commercial	customers	and	negotiating	electric	service	contracts	 to	provide,	under	existing	rate	schedules,	competitive	rates	 that	match specific	customer	needs	and	load	profiles.	Entergy	Texas	actively	participates	in	economic	development,	customer	retention,	and	reclamation activities	 to	 increase	 industrial	 and	 commercial	 demand,	 from	 both	 new	 and	 existing	 customers.	Entergy	 Texas	 does	 not	 currently	 expect additional	significant	losses	to	cogeneration	because	of	the	current	economics	of	the	electricity	markets	and	Entergy	Texas's	marketing	efforts	in retaining	industrial	customers.

Entergy	Texas'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	Texas	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	Texas'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	Texas's	financial	position	or	results	of operations.

As	discussed	in	Note	1	to	the	financial	statements,	Entergy	Texas	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	and	fuel	price	fluctuations,	in	addition	to	changes	in	certain	components	of	the	calculation.

The	following	chart	reflects	the	sensitivity	of	qualified	pension	and	qualified	projected	benefit	obligation	cost	to	changes	in	certain actuarial	assumptions	(dollars	in	thousands).

| Discount	rate | (0.25%) | $1,006 | $10,691 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $655 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $401 | $1,561 |

The	following	chart	reflects	the	sensitivity	of	postretirement	benefit	cost	and	accumulated	postretirement	benefit	obligation	changes	in certain	actuarial	assumptions	(dollars	in	thousands).

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2013<br>Postretirement	Benefit	Cost | Impact	on	2013	Accumulated<br>Postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $274 | $3,490 |
| Health\tcare\tcost\ttrend | 0.25% | $578 | $3,222 |

Total	qualified	pension	cost	for	Entergy	Texas	 in	2013	was	$16.2	million,	 including	a	$1.6	million	curtailment	charge	and	a	$855 thousand	special	termination	charge	related	to	workforce	downsizing.	Entergy	Texas	anticipates	2014	qualified	pension	cost	to	be	$8.5	million. Entergy	Texas	contributed	$6.9	million	to	its	qualified	pension	plans	in	2013	and	estimates	2014	pension	contributions	to	be	approximately	$18.5 million;	although	the	required	pension	contributions	will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are	completed	by April	1,	2014.	The	expected	increase	in	pension	contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under	MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Texas	in	2013	were	$5.1	million,	including	a	$1.4	million curtailment	charge	related	to	workforce	downsizing.	Entergy	Texas	expects	2014	postretirement	health	care	and	life	insurance	benefit	income	to approximate	 $2.8	 million.	Entergy	 Texas	 contributed $4.8	 million to	 its	 other	 postretirement	 plans	 in	 2013	 and	 expects	 to	 contribute approximately	$4.6	million	in	2014.

# To	the	Board	of	Directors	and	Shareholder	of

# Beaumont,	Texas

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Texas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31, 2013	and	2012,	and	the	related	consolidated	income	statements,	consolidated	statements	of	cash	flows,	and	consolidated	statements	of	changes	in common	equity	(pages	408	through	412	and	applicable	items	in	pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December 31,	2013.	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	consolidated	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	Entergy	Texas,	Inc.	and Subsidiaries	as	of	December	31,	2013	and	2012,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period ended	December	31,	2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $1,728,799 | $1,581,496 | $1,757,199 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 207,310 | 243,877 | 352,022 |
| Purchased\tpower | 857,512 | 717,876 | 775,067 |
| Other\toperation\tand\tmaintenance | 253,786 | 233,503 | 214,191 |
| Taxes\tother\tthan\tincome\ttaxes | 63,823 | 59,348 | 69,329 |
| Depreciation\tand\tamortization | 94,744 | 88,307 | 79,263 |
| Other\tregulatory\tcharges\t-\tnet | 77,491 | 68,772 | 52,307 |
| TOTAL | 1,554,666 | 1,411,683 | 1,542,179 |
| OPERATING\tINCOME | 174,133 | 169,813 | 215,020 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 4,647 | 4,537 | 3,781 |
| Interest\tand\tinvestment\tincome | 1,369 | (2,220) | 5,528 |
| Miscellaneous\t-\tnet | (3,328) | (4,264) | (3,047) |
| TOTAL | 2,688 | (1,947) | 6,262 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 92,156 | 96,035 | 93,554 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (3,324) | (3,258) | (2,609) |
| TOTAL | 88,832 | 92,777 | 90,945 |
| INCOME\tBEFORE\tINCOME\tTAXES | 87,989 | 75,089 | 130,337 |
| Income\ttaxes | 30,108 | 33,118 | 49,492 |
| NET\tINCOME | $57,881 | $41,971 | $80,845 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $57,881 | $41,971 | $80,845 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\nactivities: |  |  |  |
| Depreciation\tand\tamortization | 94,744 | 88,307 | 79,263 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 86,152 | 123,167 | 56,219 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (49,252) | 32,912 | (39,640) |
| Fuel\tinventory | 53 | (1,504) | (12) |
| Accounts\tpayable | 29,718 | 19,980 | (11,442) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (1,967) | (93,979) | 11,760 |
| Interest\taccrued | (920) | (929) | (582) |
| Deferred\tfuel\tcosts | (89,241) | 28,670 | (12,766) |
| Other\tworking\tcapital\taccounts | 6,918 | (58,691) | 42,518 |
| Provisions\tfor\testimated\tlosses | 2,470 | 1,585 | (296) |
| Other\tregulatory\tassets | 197,520 | 62,166 | (15,611) |
| Pension\tand\tother\tpostretirement\tliabilities | (104,055) | 17,330 | 64,686 |
| Other\tassets\tand\tliabilities | 7,033 | 10,096 | (16,105) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 237,054 | 271,081 | 238,837 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (181,546) | (181,404) | (173,462) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 4,647 | 4,537 | 3,781 |
| Change\tin\tmoney\tpool\treceivable\t-\tnet | 12,888 | 44,016 | (49,519) |
| Changes\tin\tsecuritization\taccount | (256) | 3,960 | (583) |
| Other | (42) | (13) | — |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (164,309) | (128,904) | (219,783) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | — | — | 74,092 |
| Retirement\tof\tlong-term\tdebt | (61,316) | (59,322) | (57,419) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (25,000) | (87,180) | (5,780) |
| Other | (177) | (728) | — |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (86,493) | (147,230) | 10,893 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (13,748) | (5,053) | 29,947 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 60,236 | 65,289 | 35,342 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $46,488 | $60,236 | $65,289 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $89,021 | $92,632 | $89,792 |
| Income\ttaxes | ($57,473) | ($2,207) | ($13,538) |

| Cash | $2,432 | $528 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 44,056 | 59,708 |
| Total\tcash\tand\tcash\tequivalents | 46,488 | 60,236 |
| Securitization\trecovery\ttrust\taccount | 37,511 | 37,255 |
| Accounts\treceivable: |  |  |
| Customer | 76,957 | 53,836 |
| Allowance\tfor\tdoubtful\taccounts | (443) | (680) |
| Associated\tcompanies | 76,494 | 68,750 |
| Other | 10,897 | 10,450 |
| Accrued\tunbilled\trevenues | 43,067 | 38,252 |
| Total\taccounts\treceivable | 206,972 | 170,608 |
| Accumulated\tdeferred\tincome\ttaxes | — | 34,988 |
| Fuel\tinventory\t-\tat\taverage\tcost | 55,335 | 55,388 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 34,068 | 32,853 |
| System\tagreement\tcost\tequalization | 16,040 | 16,880 |
| Prepaid\ttaxes | 55,635 | 53,668 |
| Prepayments\tand\tother | 34,458 | 18,206 |
| TOTAL | 486,507 | 480,082 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investments\tin\taffiliates\t-\tat\tequity | 687 | 678 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 376 | 638 |
| Other | 18,161 | 17,263 |
| TOTAL | 19,224 | 18,579 |
| UTILITY\tPLANT |  |  |
| Electric | 3,616,061 | 3,475,776 |
| Construction\twork\tin\tprogress | 94,743 | 90,469 |
| TOTAL\tUTILITY\tPLANT | 3,710,804 | 3,566,245 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 1,387,303 | 1,332,349 |
| UTILITY\tPLANT\t-\tNET | 2,323,501 | 2,233,896 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | 129,069 | 131,287 |
| \t\tOther\tregulatory\tassets\t(includes\tsecuritization\tproperty |  |  |
| \t\t\t\t\t\t\tof\t$585,152\tas\tof\tDecember\t31,\t2013\tand |  |  |
| \t\t\t\t\t\t\t$648,863\tas\tof\tDecember\t31,\t2012) | 919,234 | 1,114,536 |
| Long-term\treceivables\t-\tassociated\tcompanies | 27,900 | 29,510 |
| Other | 16,425 | 17,891 |
| TOTAL | 1,092,628 | 1,293,224 |
| TOTAL\tASSETS | $3,921,860 | $4,025,781 |

| Associated	companies | $112,309 | $88,743 |
| :--- | :--- | :--- |
| Other | 73,682 | 65,261 |
| Customer\tdeposits | 38,721 | 38,859 |
| Accumulated\tdeferred\tincome\ttaxes | 33,847 | — |
| Interest\taccrued | 31,246 | 32,166 |
| Deferred\tfuel\tcosts | 4,093 | 93,334 |
| Pension\tand\tother\tpostretirement\tliabilities | 786 | 853 |
| System\tagreement\tcost\tequalization | 12,000 | 8,968 |
| Other | 23,490 | 2,839 |
| TOTAL | 330,174 | 331,023 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,022,955 | 1,009,081 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 16,147 | 17,743 |
| Other\tregulatory\tliabilities | 5,194 | 6,150 |
| Asset\tretirement\tcost\tliabilities | 4,349 | 4,103 |
| Accumulated\tprovisions | 9,079 | 6,609 |
| Pension\tand\tother\tpostretirement\tliabilities | 51,253 | 155,241 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof |  |  |
| \t\t\t\t\t\t\t$629,087\tas\tof\tDecember\t31,\t2013\tand |  |  |
| \t\t\t\t\t\t\t$690,380\tas\tof\tDecember\t31,\t2012) | 1,556,939 | 1,617,813 |
| Other | 38,743 | 23,872 |
| TOTAL | 2,704,659 | 2,840,612 |
| Commitments\tand\tContingencies |  |  |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t200,000,000\tshares; |  |  |
| issued\tand\toutstanding\t46,525,000\tshares\tin\t2013\tand\t2012 | 49,452 | 49,452 |
| Paid-in\tcapital | 481,994 | 481,994 |
| Retained\tearnings | 355,581 | 322,700 |
| TOTAL | 887,027 | 854,146 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $3,921,860 | $4,025,781 |

|  | Common	Stock | Paid-in	Capital | Retained<br>Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2010 | $49,452 | $481,994 | $292,844 | $824,290 |
| Net\tincome | — | — | 80,845 | 80,845 |
| Common\tstock\tdividends | — | — | (5,780) | (5,780) |
| Balance\tat\tDecember\t31,\t2011 | $49,452 | $481,994 | $367,909 | $899,355 |
| Net\tincome | — | — | 41,971 | 41,971 |
| Common\tstock\tdividends | — | — | (87,180) | (87,180) |
| Balance\tat\tDecember\t31,\t2012 | $49,452 | $481,994 | $322,700 | $854,146 |
| Net\tincome | — | — | 57,881 | 57,881 |
| Common\tstock\tdividends | — | — | (25,000) | (25,000) |
| Balance\tat\tDecember\t31,\t2013 | $49,452 | $481,994 | $355,581 | $887,027 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,728,799 | $1,581,496 | $1,757,199 | $1,690,431 | $1,563,823 |
| Net\tincome | $57,881 | $41,971 | $80,845 | $66,200 | $63,841 |
| Total\tassets | $3,921,860 | $4,025,781 | $4,059,006 | $3,783,864 | $3,920,133 |
| Long-term\tobligations\t(a) | $1,556,939 | $1,617,813 | $1,677,127 | $1,659,230 | $1,490,283 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $596 | $553 | $638 | $559 | $533 |
| Commercial | 327 | 325 | 369 | 321 | 337 |
| Industrial | 325 | 299 | 352 | 305 | 332 |
| Governmental | 24 | 24 | 26 | 23 | 23 |
| Total\tretail | 1,272 | 1,201 | 1,385 | 1,208 | 1,225 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 369 | 313 | 262 | 373 | 294 |
| Non-associated\tcompanies | 47 | 36 | 74 | 76 | 10 |
| Other | 41 | 31 | 36 | 33 | 35 |
| Total | $1,729 | $1,581 | $1,757 | $1,690 | $1,564 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 5,726 | 5,604 | 6,034 | 5,958 | 5,453 |
| Commercial | 4,402 | 4,396 | 4,433 | 4,271 | 4,165 |
| Industrial | 6,404 | 6,066 | 6,102 | 5,642 | 5,570 |
| Governmental | 282 | 278 | 294 | 271 | 258 |
| Total\tretail | 16,814 | 16,344 | 16,863 | 16,142 | 15,446 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 6,287 | 5,702 | 4,158 | 3,758 | 3,630 |
| Non-associated\tcompanies | 712 | 827 | 1,258 | 1,300 | 231 |
| Total | 23,813 | 22,873 | 22,279 | 21,200 | 19,307 |

# SYSTEM	ENERGY	RESOURCES,	INC.

System	Energy's	principal	asset	currently	consists	of	an	ownership	interest	and	a	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	pursuant	to	the	Unit	Power	Sales	Agreement.		Payments	under	the	Unit	Power	Sales Agreement	are	System	Energy's	only	source	of	operating	revenues.

Net	income	increased	$1.8	million	primarily	due	to	higher	operating	income	and	a	lower	effective	income	tax	rate,	partially	offset	by lower	other	income.	Operating	income	was	higher	because	of	higher	rate	base	compared	to	2012	resulting	from	capital	spending	at	Grand	Gulf, including	the	uprate	project.	The	lower	effective	income	tax	rate	was	primarily	due	to	the	reversal	of	a	portion	of	the	provision	for	uncertain	tax positions.	Other	income	was	lower	due	to	AFUDC	accrued	on	the	Grand	Gulf	uprate	project	in	2012.	Grand	Gulf's	Spring	2012	refueling	outage was	completed	in	June	2012,	and	the	majority	of	uprate-related	capital	improvements	were	completed	during	this	outage.

Net	income	increased	$47.7	million	primarily	due	to	increased	operating	income,	higher	other	income,	and	a	lower	effective	income	tax rate.		Operating	income	was	higher	because	of	higher	rate	base	compared	to	2011	resulting	from	capital	spending	at	Grand	Gulf,	including	the uprate	project.		Other	income	was	higher	due	to	AFUDC	accrued	on	the	Grand	Gulf	uprate	project	in	2012.

The	effective	income	tax	rates	for	2013,	2012,	and	2011	were	37.7%,	40.8%,	and	53.9%,	respectively.	The	income	tax	rate	for	2011	is primarily	due	to	an	intercompany	settle	up	for	federal	income	taxes	for	years	prior	to	2008	which	include	an	allocation	of	the	tax	benefit	of Entergy	Corporation's	expenses	to	the	subsidiaries	generating	taxable	income	for	the	respective	years.	The	effects	of	various	tax	positions	settled with	the	IRS	pertaining	to	the	2006/2007	audit	require	System	Energy	to	pay	back	prior	benefits	of	the	Entergy	Corporation's	expenses	it	received when	the	benefits	were	originally	allocated	based	upon	the	tax	return	as	filed.	See	Note	3	to	the	financial	statements	for	a	reconciliation	of	the federal	statutory	rate	of	35.0%	to	the	effective	income	tax	rates.

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $83,622 | $185,157 | $263,772 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 279,638 | 412,000 | 430,681 |
| Investing\tactivities | (96,852) | (502,637) | (311,397) |
| Financing\tactivities | (139,266) | (10,898) | (197,899) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 43,520 | (101,535) | (78,615) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $127,142 | $83,622 | $185,157 |

Net	cash	provided	by	operating	activities	decreased	$132.4	million	in	2013	primarily	due	to	income	tax	payments	of	$211.2	million	in 2013	compared	to	income	tax	refunds	of	$56.8	million	in	2012,	partially	offset	by	spending	on	the	Grand	Gulf	refueling	outage	in	2012.	System Energy	had	income	tax	payments	in	2013	in	accordance	with	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax Allocation	Agreement.	The	income	tax	payments	resulted	primarily	from	the	reversal	of	temporary	differences	for	which	System	Energy	had previously	claimed	a	tax	deduction.	The	income	tax	refunds	of	$56.8	million	in	2012	resulted	primarily	from	a	decrease	of	previously	estimated 2011	taxable	income	due	to	the	recognition	of	additional	bonus	depreciation.

Net	cash	provided	by	operating	activities	decreased	$18.7	million	in	2012	primarily	due	to	a	decrease	of	$44.1	million	in	income	tax refunds,	partially	offset	by	a	decrease	of	$18.6	million	in	pension	contributions.	See	"Critical	Accounting	Estimates"	below	for	a	discussion	of qualified	pension	and	other	postretirement	benefits.

Net	cash	used	in	investing	activities	decreased	$405.8	million	in	2013	primarily	due	to	a	decrease	in	construction	expenditures	resulting from	spending	on	the	uprate	project	at	Grand	Gulf	completed	during	the	refueling	outage	in	2012	and	a	decrease	in	nuclear	fuel	activity	primarily due	to	the	Grand	Gulf	refueling	outage	in	2012.	The	decrease	was	partially	offset	by	money	pool	activity.

Decreases	in	System	Energy's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	System	Energy's	receivable	from	the	money pool	 decreased	 $17.7	 million	 in	 2013	 compared	 to	 decreasing	 by	 $93.5	 million	 in	 2012.	The	 money	 pool	 is	 an	 inter-company	 borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	used	in	investing	activities	increased	$191.2	million	in	2012	primarily	due	to	an	increase	in	construction	expenditures	resulting from	the	uprate	project	at	Grand	Gulf	and	an	increase	of	$94.3	million	in	nuclear	fuel	activity	primarily	due	to	the	2012	Grand	Gulf	refueling outage.	The	increase	was	partially	offset	by	money	pool	activity.

Decreases	in	System	Energy's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	System	Energy's	receivable	from	the	money pool	decreased	$93.5	million	in	2012	compared	to	increasing	by	$22.5	million	in	2011.

Net	cash	used	in	financing	activities	increased	$128.4	million	in	2013	primarily	due	to:

•the	issuance	of	$250	million	of	4.10%	Series	first	mortgage	bonds	in	September	2012;

•the	issuance	of	$50	million	of	4.02%	Series	H	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	February	2012;	and •the	redemption	of	$70	million	of	6.29%	Series	F	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	September	2013.

# This	increase	was	offset	by:

•the	redemption	of	$152.975	million	of	pollution	control	revenue	bonds	in	2012;

•the	redemption	of	$70	million	of	6.2%	Series	first	mortgage	bonds	in	October	2012;

•an	increase	in	borrowings	of	$40	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2013	compared	to	the repayment	of	borrowings	of	$40	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2012;	and •a	decrease	of	$9.4	million	in	common	stock	dividends	paid	in	2013.

Net	cash	used	in	financing	activities	decreased	$187	million	in	2012	primarily	due	to:

•the	issuance	of	$50	million	of	4.02%	Series	H	notes	by	the	nuclear	fuel	company	variable	interest	entity	in	February	2012; •an	increase	in	borrowings	of	$40	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2012	compared	to	the repayment	of	borrowings	of	$38.3	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2011; •the	redemption	of	$152.975	million	of	pollution	control	revenue	bonds	in	2012;

•the	redemption	of	$70	million	of	6.2%	Series	first	mortgage	bonds	in	October	2012;	and

•the	partial	redemption	of	$40	million	of	6.2%	pollution	control	revenue	bonds	in	2011.

System	Energy's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.	The	decrease	in	the	debt	to	capital ratio	for	System	Energy	as	of	December	31,	2013	is	primarily	due	to	a	decrease	in	long-term	debt	as	a	result	of	the	redemption	of	$70	million	of 6.29%	Series	F	notes,	as	discussed	above,	and	an	increase	in	retained	earnings.

Net	debt	consists	of	debt	 less	cash	and	cash	equivalents.	Debt	consists	of	short-term	borrowings	and	 long-term	debt,	 including	 the currently	maturing	portion.	Capital	consists	of	debt	and	common	equity.	Net	capital	consists	of	capital	less	cash	and	cash	equivalents.	System Energy	uses	the	debt	to	capital	ratio	in	analyzing	its	financial	condition	and	believes	it	provides	useful	information	to	its	investors	and	creditors	in evaluating	System	Energy's	financial	condition.	System	Energy	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	System	Energy's	financial	condition	because

net	debt	indicates	System	Energy's	outstanding	debt	position	that	could	not	be	readily	satisfied	by	cash	and	cash	equivalents	on	hand.

System	Energy	requires	capital	resources	for:

•working	capital	purposes,	including	the	financing	of	fuel	costs;	and

Following	are	the	amounts	of	System	Energy's	planned	construction	and	other	capital	investments.

|  | 2014 | 2015 | 2016 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $65 | $50 | $40 |
| Other | 5 | 5 | 5 |
| Total | $70 | $55 | $45 |

Following	are the	amounts	of	System	Energy's	existing	debt	and lease	obligations	(includes	estimated interest	payments)	and	other purchase	obligations.

(b) Purchase	obligations	represent	the	minimum	purchase	obligation	or	cancellation	charge	for	contractual	obligations	to	purchase	goods	or services.	For	System	Energy,	it	includes	nuclear	fuel	purchase	obligations.

In	addition	to	the	contractual	obligations	given	above,	System	Energy	expects	to	contribute	approximately	$21.3	million	to	its	pension plans	and	approximately	$1	million	to	its	other	postretirement	plans	in	2014	although	the	required	pension	contributions	will	not	be	known	with more	certainty	until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.		See	"Critical	Accounting	Estimates	–	Qualified	Pension and	Other	Postretirement	Benefits"	below	for	a	discussion	of	qualified	pension	and	other	postretirement	benefits	funding.

Also	in	addition	to	the	contractual	obligations,	System	Energy	has	$39.9	million	of	unrecognized	tax	benefits	and	interest	net	of	unused tax	attributes	and	payments	for	which	the	timing	of	payments	beyond	12	months	cannot	be	reasonably	estimated	due	to	uncertainties	in	the	timing of	effective	settlement	of	tax	positions.		See	Note	3	to	the	financial	statements	for	additional	information	regarding	unrecognized	tax	benefits.

In	 addition	 to	 routine	 spending	 to	 maintain	 operations,	 the	 planned	 capital investment	 estimate includes specific investments	 and initiatives	such	as	NRC	post-Fukushima	requirements	and	plant	improvements.

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	may	refinance,	redeem,	or	otherwise	retire	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	its	bond	indentures	and	other	agreements.		System	Energy	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable	capital needs.

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

| 2013 | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $9,223 | $26,915 | $120,424 | $97,948 |

The	System	Energy	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	$125	million	scheduled	to	expire	in June	2016.	No	borrowings	were	outstanding	on	the	variable	interest	entity	credit	facility	as	of	December	31,	2013.	See	Note	4	to	the	financial statements	for	additional	discussion	of	the	variable	interest	entity	credit	facilities.

System	Energy	has	obtained	a	short-term	borrowing	authorization	from	the	FERC	under	which	it	may	borrow,	through	October	2015,	up to	the	aggregate	amount,	at	any	one	time	outstanding,	of	$200	million.		See	Note	4	to	the	financial	statements	for	further	discussion	of	System Energy's	short-term	borrowing	limits.		System	Energy	has	also	obtained	an	order	from	the	FERC	authorizing	long-term	securities	issuances.		The current	long-term	authorization	extends	through	October	2015.		System	Energy	has	obtained	long-term	financing	authorization	from	the	FERC that	extends	through	October	2015	for	issuances	by	its	nuclear	fuel	company	variable	interest	entity.

In	September	2013	the	System	Energy	Resources	nuclear	fuel	company	variable	interest	entity	redeemed,	at	maturity,	its	$70	million 6.29%	Series	F	notes.

In	October	2013	the	System	Energy	Resources	nuclear	fuel	company	variable	interest	entity	issued	$85	million	of	3.78%	Series	I	notes due	October	2018.	The	System	Energy	nuclear	fuel	company	variable	interest	entity	used	the	proceeds	to	repay	outstanding	commercial	paper	and to	purchase	additional	nuclear	fuel.

System	Energy	owns	and	operates	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,	regulatory	requirement changes,	including	changes	resulting	from	events	at	other	plants,	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.	 	Grand	Gulf's	operating	license	is	currently	due	to	expire	in	November	2024.	 	In	October	2011,	System	Energy	filed	an application	with	the	NRC	for	an	extension	of	Grand	Gulf's	operating	license	to	2044,	which	application	is	pending.

The	nuclear	industry	continues	to	address	susceptibility	to	stress	corrosion	cracking	of	certain	materials	within	the	reactor	coolant	system. The	issue	is	applicable	to	Grand	Gulf	and	is	managed	in	accordance	with	industry	standard	practices	and	guidelines	which	include	in-service examinations,	replacements,	and	mitigation	strategies.		Developments	in	the	industry	or	identification	of	issues	at	the	nuclear	units	could	require unanticipated	remediation	efforts	that	cannot	be	quantified	in	advance.

On	June	8,	2012,	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit	vacated	the	NRC's	2010	update	to	its	Waste	Confidence	Decision,	which had	found	generically	that	a	permanent	geologic	repository	to	store	spent	nuclear	fuel	would	be	available	when	necessary	and	that	spent	nuclear fuel	could	be	stored	at	nuclear	reactor	sites	in	the	interim	without	significant	environmental	effects,	and	remanded	the	case	for	further	proceedings. The	court	concluded	that	the	NRC	had	not	satisfied	the	requirements	of	the	National	Environmental	Policy	Act	(NEPA)	when	it	considered environmental	effects	in	reaching	these	conclusions.	The	Waste	Confidence	Decision	has	been	relied	upon	by	NRC	license	renewal	applicants	to address	some	of	the	issues	that	NEPA	requires	the	NRC	to	address	before	it	issues	a	renewed	license.	Certain	nuclear	opponents	filed	requests with	the	NRC	asking	it	to	address	the	issues	raised	by	the	court's	decision	in	the	license	renewal	proceedings	for	a	number	of	nuclear	plants including	Grand	Gulf.	On	August	7,	2012	 the	NRC	 issued	an	order	stating	 that	 it	will	not	 issue	final	 licenses	dependent	upon	 the	Waste Confidence	Decision	until	the	D.C.	Circuit's	remand	is	addressed,	but	also	stating	that	licensing	reviews	and	proceedings	should	continue	to	move forward.	On	September	6,	2012	the	NRC	directed	its	staff	to	develop	a	revised	Waste	Confidence	Decision	within	24	months.	On	September	13, 2013	the	NRC	published	a	draft	of	the	revised	Waste	Confidence	rule	and	supporting	draft	environmental	impact	statement	for	public	comment. The	NRC's	current	schedule	calls	for	publication	of	a	final	rule	and	environmental	impact	statement	no	later	than	October	2014	with	the	effective date	30	days	after	publication.

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	that could	produce	estimates	that	would	have	a	material	impact	on	the	presentation	of	System	Energy's	financial	position	or	results	of	operations.

In	the	fourth	quarter	2013,	System	Energy	recorded	a	revision	to	its	estimated	decommissioning	cost	liability	for	Grand	Gulf	as	a	result	of a	revised	decommissioning	cost	study.		The	revised	estimate	resulted	in	a	$102.3	million	increase	in	its	decommissioning	liability,	along	with	a corresponding	increase	in	the	related	asset	retirement	cost	asset.

| actuarial	assumptions	(dollars	in	thousands). |  |  |  |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Change\tin\nAssumption | Impact\ton\t2013\nQualified\tPension\tCost | Impact\ton\t2013\nProjected\tQualified\tBenefit\nObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $1,022 | $9,432 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $505 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $408 | $1,587 |

Total	qualified	pension	cost	for	System	Energy	in	2013	was	$13.7	million,	including	a	$2	million	special	termination	charge	related	to workforce	downsizing.		System	Energy	anticipates	2014	qualified	pension	cost	to	be	$12.2	million.		System	Energy	contributed	$8.3	million	to	its pension	plans	in	2013	and	estimates	2014	pension	contributions	to	be	approximately	$12.2	million;	although	the	required	pension	contributions will	not	be	known	with	more	certainty	until	the	January	1,	2014	valuations	are	completed	by	April	1,	2014.	The	expected	increase	in	pension contributions	is	primarily	due	to	the	phase	out	of	pension	funding	relief	under	MAP-21.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	System	Energy	in	2013	were	$5.7	million,	including	a	$760	thousand curtailment	charge	related	to	workforce	downsizing.	System	Energy	expects	2014	postretirement	health	care	and	life	insurance	benefit	costs	to approximate	$561	thousand.	System	Energy	contributed	$5.4	million	to	its	other	postretirement	plans	in	2013	and	expects	to	contribute	$864 thousand	in	2014.

We	have	audited	the	accompanying	balance	sheets	of	System	Energy	Resources,	Inc.	(the	"Company")	as	of	December	31,	2013	and	2012,	and the	related	income	statements,	statements	of	cash	flows,	and	statements	of	changes	in	common	equity	(pages	424	through	428	and	applicable	items in	pages	57	through	217)	for	each	of	the	three	years	in	the	period	ended	December	31,	2013.	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,	2013	and	2012,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $735,089 | $622,118 | $563,411 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand |  |  |  |
| gas\tpurchased\tfor\tresale | 103,358 | 62,918 | 76,353 |
| Nuclear\trefueling\toutage\texpenses | 29,551 | 21,824 | 16,314 |
| Other\toperation\tand\tmaintenance | 174,772 | 149,346 | 136,495 |
| Decommissioning | 35,472 | 33,019 | 31,460 |
| Taxes\tother\tthan\tincome\ttaxes | 25,537 | 19,468 | 21,425 |
| Depreciation\tand\tamortization | 176,387 | 154,561 | 142,543 |
| Other\tregulatory\tcredits\t-\tnet | (13,068) | (10,429) | (11,781) |
| TOTAL | 532,009 | 430,707 | 412,809 |
| OPERATING\tINCOME | 203,080 | 191,411 | 150,602 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 7,784 | 26,102 | 22,359 |
| Interest\tand\tinvestment\tincome | 9,844 | 10,134 | 8,294 |
| Miscellaneous\t-\tnet | (804) | (617) | (699) |
| TOTAL | 16,824 | 35,619 | 29,954 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 38,173 | 45,214 | 48,117 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (786) | (7,165) | (6,711) |
| TOTAL | 37,387 | 38,049 | 41,406 |
| INCOME\tBEFORE\tINCOME\tTAXES | 182,517 | 188,981 | 139,150 |
| Income\ttaxes | 68,853 | 77,115 | 74,953 |
| NET\tINCOME | $113,664 | $111,866 | $64,197 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2013 | 2012 | 2011 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $113,664 | $111,866 | $64,197 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\nactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 293,537 | 235,881 | 229,715 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 29,996 | 43,651 | 14,923 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (29,226) | (12,557) | (5,512) |
| Accounts\tpayable | 6,685 | (10,511) | 17,275 |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (170,356) | 89,022 | 160,494 |
| Interest\taccrued | (3,794) | (2,157) | (38,305) |
| Other\tworking\tcapital\taccounts | 24,863 | (22,917) | 11,260 |
| Other\tregulatory\tassets | 79,345 | (44,004) | 10,874 |
| Pension\tand\tother\tpostretirement\tliabilities | (63,206) | 2,898 | 34,474 |
| Other\tassets\tand\tliabilities | (1,870) | 20,828 | (68,714) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 279,638 | 412,000 | 430,681 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (51,584) | (450,236) | (234,753) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 7,784 | 26,102 | 22,359 |
| Nuclear\tfuel\tpurchases | (65,691) | (194,314) | (59,755) |
| Proceeds\tfrom\tsale\tof\tnuclear\tfuel | 26,522 | 52,708 | 12,420 |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 215,467 | 349,427 | 203,444 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (247,042) | (379,833) | (232,636) |
| Change\tin\tmoney\tpool\treceivable\t-\tnet |  |  |  |
|  | 17,692 | 93,509 | (22,476) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (96,852) | (502,637) | (311,397) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 85,000 | 297,908 | — |
| Retirement\tof\tlong-term\tdebt | (111,479) | (262,867) | (78,161) |
| Changes\tin\tcredit\tborrowings\t-\tnet | (39,986) | 39,986 | (38,264) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (70,286) | (79,700) | (76,000) |
| Other | (2,515) | (6,225) | (5,474) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | (139,266) | (10,898) | (197,899) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 43,520 | (101,535) | (78,615) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 83,622 | 185,157 | 263,772 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $127,142 | $83,622 | $185,157 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $32,178 | $34,012 | $40,719 |
| Income\ttaxes | $211,210 | ($56,808) | ($100,889) |

| Cash | $62,561 | $100 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 64,581 | 83,522 |
| Total\tcash\tand\tcash\tequivalents | 127,142 | 83,622 |
| Accounts\treceivable: |  |  |
| Associated\tcompanies | 104,419 | 93,381 |
| Other | 6,400 | 5,904 |
| Total\taccounts\treceivable | 110,819 | 99,285 |
| Accumulated\tdeferred\tincome\ttaxes | — | 74,331 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 85,118 | 82,443 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 7,853 | 35,155 |
| Prepayments\tand\tother | 1,727 | 2,080 |
| TOTAL | 332,659 | 376,916 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 603,896 | 490,572 |
| TOTAL | 603,896 | 490,572 |
| UTILITY\tPLANT |  |  |
| Electric | 4,124,647 | 3,987,672 |
| Property\tunder\tcapital\tlease | 570,872 | 569,355 |
| Construction\twork\tin\tprogress | 29,061 | 40,392 |
| Nuclear\tfuel | 188,824 | 252,682 |
| TOTAL\tUTILITY\tPLANT | 4,913,404 | 4,850,101 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 2,699,263 | 2,568,862 |
| UTILITY\tPLANT\t-\tNET | 2,214,141 | 2,281,239 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets:\nRegulatory\tasset\tfor\tincome\ttaxes\t-\tnet |  |  |
|  | 115,492 | 126,503 |
| Other\tregulatory\tassets | 261,740 | 330,074 |
| Other | 15,996 | 18,212 |
| TOTAL | 393,228 | 474,789 |
| TOTAL\tASSETS | $3,543,924 | $3,623,516 |

| Currently	maturing	long-term	debt | $48,653 | $111,854 |
| :--- | :--- | :--- |
| Short-term\tborrowings | — | 39,986 |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 12,778 | 5,564 |
| Other | 31,862 | 44,433 |
| Taxes\taccrued | 11,121 | 181,477 |
| Accumulated\tdeferred\tincome\ttaxes | 2,310 | 1,789 |
| Interest\taccrued | 11,825 | 15,619 |
| Other | 2,312 | 2,429 |
| TOTAL | 120,861 | 403,151 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 737,973 | 782,469 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 54,786 | 56,188 |
| Other\tregulatory\tliabilities | 349,846 | 256,024 |
| Decommissioning | 616,157 | 478,371 |
| Pension\tand\tother\tpostretirement\tliabilities | 79,411 | 142,617 |
| Long-term\tdebt | 708,783 | 671,945 |
| Other | — | 22 |
| TOTAL | 2,546,956 | 2,387,636 |
| Commitments\tand\tContingencies |  |  |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t1,000,000\tshares; |  |  |
| issued\tand\toutstanding\t789,350\tshares\tin\t2013\tand\t2012 | 789,350 | 789,350 |
| Retained\tearnings | 86,757 | 43,379 |
| TOTAL | 876,107 | 832,729 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $3,543,924 | $3,623,516 |

| SYSTEM	ENERGY	RESOURCES,	INC. |  |  |  |
| :--- | :--- | :--- | :--- |
| STATEMENTS\tOF\tCHANGES\tIN\tCOMMON\tEQUITY | STATEMENTS\tOF\tCHANGES\tIN\tCOMMON\tEQUITY |  |  |
| For\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 | For\tthe\tYears\tEnded\tDecember\t31,\t2013,\t2012,\tand\t2011 |  |  |
|  | Common\tEquity | Common\tEquity |  |
|  | Common\tStock | Retained\nEarnings | Total |
|  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2010 | $789,350 | $23,016 | $812,366 |
| Net\tincome | — | 64,197 | 64,197 |
| Common\tstock\tdividends | — | (76,000) | (76,000) |
| Balance\tat\tDecember\t31,\t2011 | $789,350 | $11,213 | $800,563 |
| Net\tincome | — | 111,866 | 111,866 |
| Common\tstock\tdividends | — | (79,700) | (79,700) |
| Balance\tat\tDecember\t31,\t2012 | $789,350 | $43,379 | $832,729 |
| Net\tincome | — | 113,664 | 113,664 |
| Common\tstock\tdividends | — | (70,286) | (70,286) |
| Balance\tat\tDecember\t31,\t2013 | $789,350 | $86,757 | $876,107 |

|  | 2013 | 2012 | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tThousands) |  |  |
| Operating\trevenues | $735,089 | $622,118 | $563,411 | $558,584 | $554,007 |
| Net\tincome | $113,664 | $111,866 | $64,197 | $82,624 | $48,908 |
| Total\tassets | $3,543,924 | $3,623,516 | $3,245,365 | $3,224,070 | $3,135,651 |
| Long-term\tobligations\t(a) | $708,783 | $671,945 | $636,885 | $796,728 | $728,253 |
| Electric\tenergy\tsales\t(GWh) | 9,794 | 6,602 | 9,293 | 8,692 | 9,898 |

# Item	2.			Properties

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

# Other	Generation	Resources"	and	"Entergy	Wholesale	Commodities	-	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	2012	are	discussed	in	Part	I.	Item	1.	-	Business	under	the	sections	titled	"Retail	 Rate Regulation",	"Environmental	Regulation",	and		"Litigation"	and	"Impairment	of	Long-Lived	Assets"	in	Note	1	to	the	financial	statements	in this	report.

# Item	4.			Mine	Safety	Disclosures

Not	applicable.

# EXECUTIVE	OFFICERS	OF	ENTERGY	CORPORATION

# Executive	Officers

(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.

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

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

The	high	and	low	prices	of	Entergy	Corporation's	common	stock	for	each	quarterly	period	in	2013	and	2012	were	as	follows:

|  | 2013 |  | 2012 | 2012 |
| :--- | :--- | :--- | :--- | :--- |
|  | High | Low | High | Low |
|  |  | (In\tDollars) |  |  |
| First | 65.39 | 61.09 | 73.66 | 66.23 |
| Second | 72.10 | 63.12 | 68.20 | 62.97 |
| Third | 72.60 | 61.66 | 74.50 | 67.07 |
| Fourth | 68.63 | 60.22 | 72.98 | 61.55 |

Consecutive	quarterly	cash	dividends	on	common	stock	were	paid	to	stockholders	of	Entergy	Corporation	in	2013	and	2012.		Quarterly dividends	of	$0.83	per	share	were	paid	in	2013	and	2012.

As	of	January	31,	2014,	there	were	32,163	stockholders	of	record	of	Entergy	Corporation.

# Unregistered	Sales	of	Equity	Securities	and	Use	of	Proceeds

# Issuer	Purchases	of	Equity	Securities	(1)

| Period | Period | Total	Number	of<br>Shares	Purchased | Average	Price<br>Paid	per	Share | Total	Number	of<br>Shares	Purchased<br>as	Part	of	a<br>Publicly<br>Announced	Plan | Maximum	$<br>Amount<br>of	Shares	that	May<br>Yet	be	Purchased<br>Under	a	Plan	(2) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 10/01/2013 | -10/31/2013 | — | $— | — | $350,052,918 |
| 11/01/2013 | -11/30/2013 | — | $— | — | $350,052,918 |
| 12/01/2013 | -12/31/2013 | — | $— | — | $350,052,918 |
| Total |  | — | $— | — |  |

In	 accordance	 with	 Entergy's	 stock-based	 compensation	 plans,	 Entergy	 periodically	 grants	 stock	 options	 to	 key	 employees,	 which	 may	 be exercised	to	obtain	shares	of	Entergy's	common	stock.		According	to	the	plans,	these	shares	can	be	newly	issued	shares,	treasury	stock,	or	shares purchased	on	the	open	market.		Entergy's	management	has	been	authorized	by	the	Board	to	repurchase	on	the	open	market	shares	up	to	an	amount sufficient	to	fund	the	exercise	of	grants	under	the	plans.		The	amount	of	share	repurchases	under	these	programs	may	vary	as	a	result	of	material changes	in	business	results	or	capital	spending	or	new	investment	opportunities.		In	addition,	in	the	first	quarter	2013,	Entergy	withheld	62,841 shares	of	its	common	stock	at	$64.45	per	share	to	pay	taxes	due	upon	vesting	of	restricted	stock	granted	as	part	of	its	long-term	incentive	program.

(1) See	Note	12	to	the	financial	statements	for	additional	discussion	of	the	stock-based	compensation	plans.

(2) Maximum	amount	of	shares	that	may	yet	be	repurchased	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.

There	is	no	market	for	the	common	stock	of	Entergy	Corporation's	wholly	owned	subsidiaries.		Cash	dividends	on	common	stock	paid	by the	Registrant	Subsidiaries	during	2013	and	2012,	were	as	follows:

|  | 2013 | 2012 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| Entergy\tArkansas | $15.0 | $10.0 |
| Entergy\tGulf\tStates\tLouisiana | $119.9 | $114.2 |
| Entergy\tLouisiana | $356.3 | $15.6 |
| Entergy\tMississippi | $7.4 | $— |
| Entergy\tNew\tOrleans | $— | $1.7 |
| Entergy\tTexas | $25.0 | $87.2 |
| System\tEnergy | $70.3 | $79.7 |

Information	with	respect	to	restrictions	that	limit	the	ability	of	the	Registrant	Subsidiaries	to	pay	dividends	is	presented	in	Note	7	to	the financial	statements.

# Item	6.				Selected	Financial	Data

Refer to	"SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON	OF	ENTERGY	CORPORATION	AND	SUBSIDIARIES,	ENTERGY ARKANSAS,	INC.	AND	SUBSIDIARIES,	ENTERGY	GULF	STATES	LOUISIANA,	L.L.C., 	ENTERGY	LOUISIANA,	LLC,	ENTERGY	MISSISSIPPI,

INC.,	ENTERGY	NEW	ORLEANS,	INC.,	ENTERGY	TEXAS,

INC.	AND	SUBSIDIARIES,	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.	AND	SUBSIDIARIES,	ENTERGY	GULF	STATES,	LOUISIANA, 	L.L.C.,	ENTERGY	LOUISIANA,	LLC,	ENTERGY	MISSISSIPPI, INC.,	ENTERGY	NEW	ORLEANS,	INC.,	ENTERGY	TEXAS,	INC.	AND	SUBSIDIARIES,	and	SYSTEM	ENERGY	RESOURCES,	INC."

# Item	7A.			Quantitative	and	Qualitative	Disclosures	About	Market	Risk

Refer	to	"MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS	OF	ENTERGY	CORPORATION	AND	SUBSIDIARIES 	-	Market	and Credit	Risk	Sensitive	Instruments."

# Item	8.		Financial	Statements	and	Supplementary	Data

Refer	to	"TABLE	OF	CONTENTS	-	Entergy	Corporation,	Entergy	Arkansas,	Inc.,	Entergy	Gulf	States	Louisiana,	L.L.C.,	Entergy	Louisiana,	LLC, Entergy	Mississippi,	Inc.,	Entergy	New	Orleans,	Inc.,	Entergy	Texas,	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	Corporation,	Entergy	Arkansas,	Entergy Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	or	System	Energy.

# Item	9A.		Controls	and	Procedures

# Disclosure	Controls	and	Procedures

As	of	December	31,	2013,	evaluations	were	performed	under	the	supervision	and	with	the	participation	of	Entergy	Corporation,	Entergy Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy (individually	"Registrant"	and	collectively	the	"Registrants")	management,	including	their	respective	Principal	Executive	Officers	(PEO)	and Principal	Financial	Officers	(PFO).		The	evaluations	assessed	the	effectiveness	of	the	Registrants'	disclosure	controls	and	procedures.		Based	on the	evaluations,	each	PEO	and	PFO	has	concluded	that,	as	to	the	Registrant	or	Registrants	for	which	they	serve	as	PEO	or	PFO,	the	Registrant's	or 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;	and	 that	 the	Registrant's	or	Registrants'	disclosure	controls	and	procedures	are	also effective	 in	 reasonably	 assuring	 that	 such	 information	 is	 accumulated	 and	 communicated	 to	 the	 Registrant's	 or	 Registrants'	 management, including	their	respective	PEOs	and	PFOs,	as	appropriate	to	allow	timely	decisions	regarding	required	disclosure.

# Internal	Control	over	Financial	Reporting

The	managements	of	Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi, Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	(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, 2013.		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.	The	 original	 1992	 COSO	 Framework	 was	 utilized	 for	 management's assessment.

Based	on	each	management's	assessment	and	the	criteria	set	forth	by	the	original	1992	COSO	Framework,	each	Registrant's	management believes	that	each	Registrant	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2013.

The	Registrants'	registered	public	accounting	firm	has	issued	an	attestation	report	on	each	Registrant's	internal	control	over	financial

# reporting.

# Changes	in	Internal	Controls	over	Financial	Reporting

Under	the	supervision	and	with	the	participation	of	each	Registrant's	management,	including	its	respective	PEO	and	PFO,	each	Registrant evaluated	changes	in	internal	control	over	financial	reporting	that	occurred	during	the	quarter	ended	December	31,	2013	and	found	no	change	that has	materially	affected,	or	is	reasonably	likely	to	materially	affect,	internal	control	over	financial	reporting.

# Attestation	Report	of	Registered	Public	Accounting	Firm

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Corporation	and	Subsidiaries	(the	"Corporation")	as	of	December	31, 2013,	based	on	criteria	established	in	Internal	Control	-Integrated	Framework	(1992)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the Treadway	Commission.	The	Corporation'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,	 included	 in	 the	 accompanying	 Internal	 Control	 over	 Financial Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	Corporation'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,	assessing	the	risk that	a	material	weakness	exists,	testing	and	evaluating	the	design	and	operating	effectiveness	of	internal	control	based	on	the	assessed	risk,	and performing	such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We	believe	that	our	audit	provides	a	reasonable	basis	for	our opinion.

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	generally	accepted	accounting	principles.	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,	the	Corporation	maintained,	in	all	material	respects,	effective	internal	control	over	financial	reporting	as	of	December	31,	2013, based	on	the	criteria	established	in	Internal	Control	-Integrated	Framework	(1992)	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,	2013	of	the	Corporation	and	our	report	dated	February	27,	2014	expressed	an unqualified	opinion	on	those	consolidated	financial	statements.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Arkansas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31, 2013,	based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	included	in	the	accompanying	Internal	Control	over	Financial Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

In	our	opinion,	the	Company	maintained,	in	all	material	respects,	effective	internal	control	over	financial	reporting	as	of	December	31,	2013, based	on	the	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	2013	of	the	Company	and	our	report	dated	February	27,	2014	expressed	an unqualified	opinion	on	those	consolidated	financial	statements.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Gulf	States	Louisiana,	L.L.C.	(the	"Company")	as	of	December	31,	2013, based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	 included	 in	 the	 accompanying	 Internal	 Control	 over	 Financial Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

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,	2013	of	the	Company	and	our	report	dated	February	27,	2014	expressed	an	unqualified opinion	on	those	financial	statements.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Louisiana,	LLC	and	Subsidiaries	(the	"Company")	as	of	December	31, 2013,	based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	included	in	the	accompanying	Internal	Control	over	Financial Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Mississippi,	Inc.	(the	"Company")	as	of	December	31,	2013,	based	on criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting.	Our responsibility	is	to	express	an	opinion	on	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,	assessing	the	risk that	a	material	weakness	exists,	testing	and	evaluating	the	design	and	operating	effectiveness	of	internal	control	based	on	assessed	risk,	and performing	such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We	believe	that	our	audit	provides	a	reasonable	basis	for	our opinion.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	New	Orleans,	Inc.	(the	"Company")	as	of	December	31,	2013,	based	on criteria	 established	 in	Internal	Control-Integrated	Framework	(1992)	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,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting.	Our responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Texas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31,	2013, based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	 included	 in	 the	 accompanying	 Internal	 Control	 over	 Financial Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

We	have	audited	the	internal	control	over	financial	reporting	of	System	Energy	Resources,	Inc.	(the	"Company")	as	of	December	31,	2013,	based on	criteria	established	in	Internal	Control	-	Integrated	Framework	(1992)	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,	included	in	the	accompanying	Internal	Control	over	Financial	Reporting.	Our responsibility	is	to	express	an	opinion	on	the	Company's	internal	control	over	financial	reporting	based	on	our	audit.

# PART	III

# Item	 10.		Directors	and	Executive	Officers	of	the	Registrants	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,

# Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas)

Information	required	by	 this	 item	concerning	directors	of	Entergy	Corporation	 is	set	forth	under	 the	heading	"Item	1	–	Election	of Directors"	contained	in	the	Proxy	Statement	of	Entergy	Corporation,	to	be	filed	in	connection	with	its	Annual	Meeting	of	Stockholders	to	be	held May	2,	2014,	and	is	incorporated	herein	by	reference.

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.

# Directors

# Officers

Each	director	and	officer	of	the	applicable	Entergy	company	is	elected	yearly	to	serve	by	the	unanimous	consent	of	the	sole	stockholder with	the	exception	of	the	directors	and	officers	of	Entergy	Gulf	States	Louisiana,	L.L.C.	and	Entergy	Louisiana,	LLC,	who	are	elected	yearly	to serve	 by	 the	 unanimous	 consent	 of	 the	 sole	 common	 membership	 owners,	 EGS	 Holdings,	 Inc.	 and	 Entergy	 Louisiana	 Holdings, respectively.		Entergy	Corporation's	directors	are	elected	annually	at	the	annual	meeting	of	shareholders.		Entergy	Corporation's	officers	are elected	at	the	annual	organizational	meeting	of	the	Board	of	Directors.

# 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)

Maureen	S.	Bateman

# Stuart	L.	Levenick

# Blanche	L.	Lincoln

All	Audit	Committee	members	are	independent.		In	addition	to	the	general	independence	requirements,	all	Audit	Committee	members	must	meet the	heightened	independence	standards	imposed	by	the	SEC	and	NYSE.		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	does	not	have	any	single	method	for	identifying	director	candidates	but	will	consider	candidates suggested	by	a	wide	range	of	sources	including	director	candidates	recommended	by	Entergy	Corporation's	shareholders.	Shareholders	wishing	to recommend	 a	 candidate	 to	 the	 Corporate	 Governance	 Committee	 should	 do	 so	 by	 submitting	 the	 recommendation	 in	 writing	 to	 Entergy Corporation's	Secretary	at	639	Loyola	Avenue,	P.O.	Box	61000,	New	Orleans,	LA	70161,	and	it	will	be	forwarded	to	the	Corporate	Governance Committee	members	for	their	consideration.	Any	recommendation	should	include:

•the	number	of	shares	of	Entergy	Corporation	held	by	the	shareholder;

•the	name	and	address	of	the	candidate;

•a	brief	biographical	description	of	the	candidate,	including	his	or	her	occupation	for	at	least	the	last	five	years,	and	a	statement	of	the qualifications	of	the	candidate,	taking	into	account	the	qualification	requirements	set	forth	above;	and

•the	candidate's	signed	consent	to	serve	as	a	director	if	elected	and	to	be	named	in	the	Proxy	Statement.

Once	the	Corporate	Governance	Committee	receives	the	recommendation,	it	may	request	additional	information	from	the	candidate	about the	candidate's	independence,	qualifications,	and	other	information	that	would	assist	the	Corporate	Governance	Committee	in	evaluating	the candidate,	 as	 well	 as	 certain	 information	 that	 must	 be	 disclosed	 about	 the	 candidate	 in	 the	 Proxy	 Statement,	 if	 nominated.	The	 Corporate Governance	Committee	will	apply	the	same	standards	in	considering	director	candidates	recommended	by	shareholders	as	it	applies	to	other candidates.

# 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	2,	2014,	under	the	heading	"Section 16(a)	Beneficial	Ownership	Reporting	Compliance",	which	information	is	incorporated	herein	by	reference.

# Item	11.		Executive	Compensation

Information	 concerning	 the	 directors	 and	 officers	 of	 Entergy	 Corporation	 is	 set	 forth	 in	 the	 Proxy	 Statement	 under	 the	 headings "Compensation	 Discussion	 and	Analysis,"	 "Executive	 Compensation	 Tables,"	 "Nominees	 for	 the	 Board	 of	 Directors,"	 and	 "Non-Employee Director	Compensation,"	all	of	which	information	is	incorporated	herein	by	reference.

# ENTERGY	ARKANSAS,	ENTERGY	GULF	STATES	LOUISIANA,	ENTERGY	LOUISIANA,	ENTERGY	MISSISSIPPI,	ENTERGY NEW	ORLEANS,	AND	ENTERGY	TEXAS

# COMPENSATION	DISCUSSION	AND	ANALYSIS

In	this	section,	the	compensation	earned	by	the	following	Named	Executive	Officers	in	2013	is	discussed.	Each	officer's	title	is	provided as	of	December	31,	2013.

Mr.	 Denault,	 Mr.	 Forbes,	 Mr.	 Marsh,	 Mr.	 Mohl	 and	 Mr.	 West	 serve	 as	 executive	 officers	 of	 Entergy	 Corporation.	 No	 additional compensation	was	paid	in	2013	to	Mr.	Denault,	Mr.	Marsh,	Mr.	Mohl	or	Mr.	West	for	their	service	as	Named	Executive	Officers	of	Entergy Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans	and	Entergy	Texas	(the	"Subsidiaries").

1		Mr.	Mohl	is	included	in	the	Executive	Compensation	section	of	this	Form	10-K	because	he	served	as	President,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana for	a	portion	of	2013.

# CD&A	Highlights

# Pay	for	Performance	Philosophy

Entergy	Corporation's	executive	compensation	programs	are	based	on	a	philosophy	of	pay-for-performance	that	is	embodied	in	the	design of	the	annual	and	long-term	incentive	plans.	In	keeping	with	this	philosophy,	approximately	80%	of	the	annual	target	compensation	of	Entergy Corporation's	Chief	Executive	Officer	(excluding	non-qualified	supplemental	retirement	income)	is	"at	risk,"	with	the	substantial	majority	of	this "at	 risk"	 compensation	 consisting	 of	 awards	 under	 the	 Executive	 Annual	 Incentive	 Plan	 (or	 Annual	 Incentive	 Plan)	 and	 the	 Long-Term Performance	Unit	Program,	and	the	balance	consisting	of	stock	option	and	restricted	stock	awards.

•The	Annual	Incentive	Plan	incentivizes	and	rewards	the	achievement	of	operational	financial	metrics	that	are	deemed	by	the	Personnel Committee	to	be	consistent	with	the	overall	goals	and	strategic	direction	that	the	Board	has	set	for	Entergy	Corporation. •The	equity-based	long-term	incentive	programs,	including	the	Long-Term	Performance	Unit	Program,	further	align	the	interests	of	the executives	and	Entergy	Corporation's	shareholders	by	directly	tying	the	value	of	the	equity	awards	granted	to	executives	under	these programs	to	the	performance	of	Entergy	Corporation's	stock	price	and	total	shareholder	return.

# 2013	Incentive	Pay	Outcomes

Pay	outcomes	for	the	Named	Executive	Officers	during	2013	demonstrated	the	application	of	this	pay-	for-performance	philosophy.

# Annual	Incentive	Plan	Awards

Awards	under	the	Annual	Incentive	Plan	are	tied	to	operational	financial	performance	through	the	Entergy	Achievement	Multiplier,	which is	the	performance	metric	used	to	determine	the	funding	of	awards	under	the	plan.	For	2013,	the	Entergy	Achievement	Multiplier	was	determined based	in	equal	part	on	the	success	in	achieving	earnings	per	share	and	operating	cash	flow	goals.	These	goals	were	set	at	the	beginning	of	the	year based	on	Entergy	Corporation's	financial	plan	and	the	Board's	overall	goals	for	Entergy	Corporation	and	were	consistent	with	its	published earnings	guidance.

For	2013,	the	Personnel	Committee,	based	on	the	recommendation	of	the	Finance	Committee,	determined	that	management	exceeded	its earnings	per	share	goal	of	$5.00	per	share	by	$0.36	per	share	and	met	its	operating	cash	flow	goal	of	$3.25	billion,	in	each	case	based	on operational	earnings	and	operating	cash	flow,	which	excluded	from	as-reported	results	special	items	relating	to	Entergy	Corporation's	decision	to close	the	Vermont	Yankee	Nuclear	Power	Station	and	a	related	settlement	reached	with	the	State	of	Vermont	in	2013,	the	implementation	of	the human	capital	management	strategic	initiative,	and	Entergy	Corporation's	proposed	spin-merge	transaction	with	ITC	Holdings	Corp.	(the	"ITC Transaction").	The	Personnel	Committee	evaluated	each	of	these	adjustments	to	as-reported	results	and	concluded	that	they	were	appropriate	in light	of	management's	performance	with	respect	to	these	matters	and	the	Committee's	view	that,	in	general,	management's	performance	for purposes	of	determining	Annual	Incentive	Plan	awards	should	be	measured	against	operational	financial	results,	since	operational	results	form	the basis	for	Entergy	Corporation's	financial	plan	and	guidance	to	investors	and	are	the	primary	basis	on	which	its	financial	performance	is	evaluated by	investors.

Based	 on	 this	 performance	 and	 the	 recommendation	 of	 the	 Finance	 Committee,	 the	 Personnel	 Committee	 certified	 an	 Entergy Achievement	Multiplier	of	136%	for	2013,	consistent	with	the	strong	financial	results	achieved	by	Entergy	Corporation	despite	the	significant challenges	posed	in	2013,	including	continued	low	wholesale	power	prices	and	financial	and	regulatory	challenges	and	uncertainty	related	to Entergy	Corporation's	wholesale	nuclear	plants.	In	reaching	this	decision,	the	Committee	also	took	into	account	management's	performance	in relation	to	a	number	of	strategic	initiatives	and	decisions	undertaken	in	2013,	including	the	successful	integration	of	the	transmission	systems owned	by	Entergy	Corporation's	utility	operating	companies	into	MISO,	the	decision	to	close	the	Vermont

Yankee	Nuclear	Power	Station	and	related	settlement	agreement	with	the	State	of	Vermont,	the	development	and	implementation	of	the	human capital	management	initiative,	and	management's	unsuccessful	effort	to	complete	the	ITC	Transaction.	This	resulted	in	payouts	to	the	executive officers,	including	Entergy	Corporation's	Chief	Executive	Officer,	under	the	Annual	Incentive	Plan	at	136%	of	target,	which	the	Personnel Committee	considered	to	be	appropriate	in	light	of	Entergy	Corporation's	financial	performance	for	the	year	and	management's	performance	on the	matters	discussed	above.

# Long-Term	Performance	Unit	Program	Payouts

Under	the	Long-Term	Performance	Unit	Program,	a	substantial	portion	of	targeted	executive	officer	pay	is	tied	directly	to	Entergy's relative	total	shareholder	return.	Under	this	program,	performance	is	measured	over	a	three-year	period	by	assessing	Entergy	Corporation's	total shareholder	return	in	relation	to	the	total	shareholder	return	of	the	companies	included	in	the	Philadelphia	Utility	Index,	with	payouts	based	solely on	relative	performance.	Performance	is	measured	based	on	relative	total	shareholder	return	because	it	encourages	the	executives	to	deliver superior	shareholder	value	in	relation	to	Entergy	Corporation's	peers	and	rewards	not	just	stock	price	appreciation,	but	also	the	ability	to	deliver significant	dividends	to	shareholders.

Although	Entergy	Corporation's	total	shareholder	return	improved	in	2013	both	on	an	absolute	basis	and	in	relation	to	its	peers,	Entergy Corporation's	total	shareholder	return	for	the	2011	through	2013	performance	period	was	in	the	bottom	quartile	of	the	Philadelphia	Utility	Index, which	resulted	in	a	zero	payout	for	the	performance	units	granted	in	2011	for	all	of	the	Named	Executive	Officers.	This	compares	with	a	grant date	 target	opportunity	of	$1,111,023	for	Entergy	Corporation's	Chief	Executive	Officer	and	grant	date	payout	opportunities	ranging	from $243,224	to	$544,393	for	the	other	Named	Executive	Officers	for	this	performance	period.

# Establishing	Executive	Compensation

Entergy	Corporation's	executive	compensation	programs	are	based	on	a	philosophy	of	pay-for-performance	that	is	embodied	in	the	design of	the	annual	and	long-term	incentive	plans.	The	annual	incentive	plan	incentivizes	and	rewards	the	achievement	of	operational	financial	metrics that	are	deemed	by	the	Personnel	Committee	to	be	consistent	with	the	overall	goals	and	strategic	direction	that	the	Board	has	set.	The	long-term incentive	programs	further	align	the	interests	of	executives	and	Entergy	Corporation's	shareholders	by	directly	tying	the	value	of	the	equity awards	granted	to	executives	under	these	programs	to	the	performance	of	Entergy	Corporation's	stock	price	and	total	shareholder	return.	Entergy Corporation	believes	the	executive	pay	programs	described	in	this	section	and	in	the	accompanying	tables	have	played	a	material	role	in	the	ability to	drive	strong	financial	and	operational	results	and	to	attract	and	retain	a	highly	experienced	and	successful	management	team.

# The	Starting	Point

To	develop	a	competitive	compensation	program,	the	Personnel	Committee	annually	reviews	compensation	data	from	two	sources:

# Survey	Data

The	Committee	uses	published	and	private	compensation	survey	data	 to	develop	marketplace	compensation	 levels	for	 the	executive officers.	The	data,	which	is	compiled	by	the	Committee's	independent	compensation	consultant,	compares	the	current	compensation	opportunities provided	to	each	of	the	executive	officers	against	the	compensation	opportunities	provided	to	executives	holding	similar	positions	at	companies with	corporate	revenues	similar	to	Entergy	Corporation's.	For	non-industry	specific	positions	such	as	a	chief	financial	officer,	the	Committee reviews	general	industry	data	for	total	cash	compensation	(base	salary	and	annual	incentive).	For	management	positions	that	are	industry-specific such	as	Group	President,	Utility	Operations,	the	Committee	reviews	data	from	utility	companies	for	total	cash	compensation.	However,	for	long- term	incentives,	all	positions	are	reviewed	relative	to	utility	market	data.	The	survey

data	reviewed	by	the	Committee	covers	hundreds	of	companies	across	a	broad	range	of	industries	and	over	60	investor-owned	utility	companies	in the	utility	sector.	In	evaluating	compensation	levels	against	the	survey	data,	the	Committee	considers	only	the	aggregated	survey	data.	The identities	of	the	companies	participating	in	compensation	survey	data	are	not	disclosed	to,	or	considered	by,	the	Committee	in	its	decision-making process	and,	thus,	are	not	considered	material	by	the	Committee.

The	Committee	uses	this	survey	data	to	develop	compensation	opportunities	that	are	designed	to	deliver	total	target	compensation	at approximately	the	50th	percentile	of	the	surveyed	companies.	The	survey	data	are	the	primary	data	used	for	purposes	of	determining	target compensation.	 As	 a	 result,	 Mr.	 Denault,	 Entergy	 Corporation's	 Chief	 Executive	 Officer,	 is	 compensated	 at	 a	 higher	 level	 than	 Entergy Corporation's	 other	 Named	 Executive	 Officers,	 reflecting	 market	 practices	 that	 compensate	 chief	 executive	 officers	 at	 greater	 potential compensation	levels	with	more	"pay	at	risk"	than	other	named	executive	officers,	due	to	the	greater	responsibilities	and	accountability	required	of a	Chief	Executive	Officer.	In	most	cases,	the	Committee	considers	its	objectives	to	have	been	met	if	Entergy	Corporation's	Chief	Executive Officer	and	the	eight	(8)	other	executive	officers	(including	all	of	the	Named	Executive	Officers)	who	constitute	what	is	referred	to	as	the	Office of	the	Chief	Executive	each	have	a	target	compensation	opportunity	that	falls	within	the	range	of	85%	-	115%	of	the	50th	percentile	of	the	survey data.	Promoted	officers	or	officers	who	are	new	to	their	roles	may	be	transitioned	into	the	targeted	market	range	over	time.	Actual	compensation received	by	an	individual	officer	may	be	above	or	below	the	targeted	range	based	on	an	individual	officer's	skills,	performance,	experience	and responsibilities,	corporate	performance	and	internal	pay	equity.	For	2013,	the	total	target	compensation	of	each	of	the	Named	Executive	Officers fell	within	the	targeted	range	except	for	three	officers	whose	total	target	compensation	fell	below	the	targeted	range	and	another	officer	whose total	targeted	compensation	was	set	above	the	targeted	range,	based	on	the	Committee's	assessment	of	his	skills,	performance,	experience	and responsibilities	and	internal	pay	equity.

# Proxy	Analysis

Although	the	survey	data	described	above	is	the	primary	data	used	in	determining	compensation,	the	Committee	reviews	data	derived from	the	proxy	statements	of	companies	included	in	the	Philadelphia	Utility	Index	as	an	additional	point	of	comparison.	The	proxy	data	are	used to	compare	the	compensation	levels	of	the	Named	Executive	Officers	with	the	compensation	levels	of	the	corresponding	top	five	highest	paid executive	officers	of	the	companies	included	in	the	Philadelphia	Utility	Index,	as	reported	in	their	proxy	statements,	based	on	pay	rank	and without	regard	to	roles	and	responsibilities	except	with	respect	to	the	Chief	Executive	Officer	and	Chief	Financial	Officer,	for	whom	comparable roles	 are	 used.	 The	 Personnel	 Committee	 uses	 this	 analysis	 to	 evaluate	 the	 overall	 reasonableness	 of	 Entergy	 Corporation's	 compensation programs.	The	following	companies	were	included	in	the	Philadelphia	Utility	Index	at	the	time	the	proxy	data	was	compiled:

# Executive	Compensation	Elements

The	following	table	lists	the	elements	of	target	direct	compensation	for	the	2013	executive	compensation	program.	The	program	uses	a mix	of	fixed	and	variable	compensation	elements	and	provides	alignment	with	both

short-	and	long-term	business	goals	through	annual	and	long-term	incentives.	Incentives	are	designed	to	drive	overall	corporate	performance, specific	business	unit	strategies,	and	individual	performance	using	performance	and	operational	measures	the	Committee	believes	correlate	to shareholder	value	and	align	with	Entergy	Corporation's	strategic	vision	and	operating	priorities.	The	Committee	establishes	the	performance measures	and	ranges	of	performance	for	the	variable	compensation	elements.	An	individual's	award	is	based	primarily	on	corporate	performance, market-based	compensation	levels,	and	individual	performance.

# Short-Term	Compensation

The	Personnel	Committee	determines	the	base	salaries	for	all	of	the	Named	Executive	Officers	who	are	members	of	the	Office	of	the Chief	Executive	based	on	competitive	compensation	data,	performance	considerations,	and	advice	provided	by	the	Committee's	independent compensation	consultant.	For	the	other	Named	Executive	Officers,	their	salaries	are	established	by	their	supervisors	using	the	same	criteria.	The Committee	also	uses	internal	pay	equity;	however,	the	Committee	has	not	established	any	predetermined	formula	against	which	the	base	salary	of one	Named	Executive	Officer	is	measured	against	another	officer	or	employee.

In	2013,	all	of	the	Named	Executive	Officers	received	merit	increases	in	their	base	salaries	in	the	range	of	2.0	to	5.8	percent,	exc ept	for Messrs.	Denault,	Marsh,	Forbes,	May	and	Mohl.	These	increases	in	base	salary	were	made	in	light	of	current	economic	conditions	and	the projected	growth	in	executive	salaries	in	2013	based	on	general	industry	surveys	obtained	from	human	resources	consulting	firms,	as	well	as,	an internal	 pay	 equity	 comparison.	The	 salary	 increases	 shown	 for	 Messrs.	 Denault,	 Forbes,	 Marsh,	 May	 and	 Mohl	 from	 2012	 to	 2013	 were determined	in	conjunction	with	their	promotion	to	new	positions	assumed	in	2013.	The	Committee	determined	the	compensation	levels	for	each	of these	officers	using	competitive	compensation	data	provided	by	its	independent	compensation	consultant.	The	Committee	also	considered	their previous	compensation	levels	and	the	compensation	paid	to	their	predecessors.	In	determining	the	2013	base	salaries,	the	Committee	sought	to position	the	compensation	for	each	officer,	other	than	Mr.	Mohl	and	Mr.	May,	at	below	market	levels	with	the	intent	of	transitioning	them	to market-competitive	levels	over	time.	Mr.	Mohl's	salary	was	established,	in	consultation	with	the	independent	compensation	consultant,	to	reflect his	unique	responsibilities	and	accountability	as	President	of	the	wholesale	commodities	business.

The	following	table	sets	forth	the	2012	and	2013	base	salaries	for	the	Named	Executive	Officers.	Changes	in	base	salaries	were	effective either	upon	the	date	of	the	officers'	promotion	or	in	April	of	the	years	shown,	for	those	who	received	merit	increases.

| Named	Executive	Officer | 2012	Base	Salary | 2013	Base	Salary |
| :--- | :--- | :--- |
| Leo\tP.\tDenault | $674,856 | $1,085,000 |
| Jeffry\tS.\tForbes | $450,000 | $550,000 |
| Andrew\tS.\tMarsh | $301,378 | $500,000 |
| Roderick\tK.\tWest | $589,160 | $612,726 |
| Haley\tR.\tFisackerly | $288,950 | $296,174 |
| Phillip\tR.\tMay,\tJr. | $259,450 | $330,000 |
| Hugh\tT.\tMcDonald | $336,800 | $345,220 |
| William\tM.\tMohl | $342,250 | $560,000 |
| Alyson\tM.\tMount | $280,000 | $286,700 |
| Sallie\tT.\tRainer | $275,000 | $291,000 |
| Charles\tL.\tRice,\tJr. | $252,100 | $257,144 |

# Annual	Incentive	Plan

Performance-based	 incentives	 are	 included	 in	 the	 Named	 Executive	 Officers'	 compensation	 packages	 because	 Entergy	 Corporation believes	 performance-based	 incentives	 encourage	 the	 Named	 Executive	 Officers	 to	 pursue	 objectives	 consistent	 with	 the	 overall	 goals	 and strategic	direction	that	the	Board	has	set	for	Entergy	Corporation.	Annual	incentive	plans	are	commonly	used	by	companies	in	a	variety	of industry	sectors	to	compensate	their	executive	officers	for	achieving	financial	and	operational	goals.

Under	the	Annual	Incentive	Plan,	a	performance	metric	known	as	the	Entergy	Achievement	Multiplier	is	used	to	determine	the	percentage of	target	annual	plan	opportunities	that	will	be	paid	each	year	to	each	Named	Executive	Officer,	subject	to	adjustment	based	on	individual performance.

Each	 year	 the	 Personnel	 Committee	 reviews	 the	 performance	 measures	 used	 to	 determine	 the	 Entergy	Achievement	 Multiplier.	 In December	 2012,	 the	 Personnel	 Committee	 decided	 to	 retain	 for	 2013	 the	 performance	 measures	 used	 for	 determining	 the	 2012	 Entergy Achievement	Multiplier.	These	measures	were	consolidated	earnings	per	share	and	operating	cash	flow,	with	each	measure	weighted	equally.	The Committee	selected	these	performance	measures	because:

•earnings	per	share	and	operating	cash	flow	have	both	a	correlative	and	causal	relationship	with	shareholder	value	over	the	long-term; •earnings	per	share	and	operating	cash	flow	targets	are	aligned	with	externally-communicated	goals;	and •earnings	per	share	and	operating	cash	flow	results	are	readily	available	in	earning	releases	and	SEC	filings.

In	addition,	these	measures	are	used	by	a	number	of	other	companies,	including	the	companies	in	the	Philadelphia	Utility	Index,	as components	of	their	incentive	programs.

The	 Committee	 sets	 minimum,	 target	 and	 maximum	 achievement	 levels	 under	 the	Annual	 Incentive	 Plan.	 There	 is	 no	 payout	 for performance	at	or	below	the	minimum	achievement	level,	the	payout	for	performance	at	target	is	100%	of	the	target	payout,	and	the	payout	for performance	at	or	above	the	maximum	achievement	level	is	200%	of	target.	Payouts	for	performance	between	minimum	and	target	achievement levels	and	between	target	and	maximum	levels	are	calculated	using	straight-line	interpolation.	In	general,	the	Committee	seeks	to	establish	target achievement	levels	such	that	the	relative	difficulty	of	achieving	the	target	level	is	consistent	from	year	to	year.

In	January	2013,	the	Committee	determined	the	Annual	Incentive	Plan	targets	to	be	used	for	purposes	of	determining	annual	bonuses	for 2013.	 The	 Committee's	 determination	 of	 the	 target	 levels	 was	 made	 after	 a	 full	 review	 by	 Entergy	 Corporation's	 Board	 of	 Directors	 of management's	2013	financial	plan	for	Entergy	Corporation	and	upon	the	recommendation	of	the	Finance	Committee.	In	setting	the	target	levels, the	Committee	confirmed	that	the	established	targets	aligned	with	Entergy	Corporation's	anticipated	2013	financial	performance	as	reflected	in	the financial	plan	and	Entergy	Corporation's	published	earnings	guidance.	In	keeping	with	its	past	practice,	the	Committee	also	determined	that	for purposes	of	measuring	performance	against	such	targets,	the	Committee	would	exclude	the	effect	on	as-reported	results	of	activities	associated with	Entergy	Corporation's	planned	ITC	Transaction,	since	that	was	a	known	special	item	that	would	be	excluded	in	determining	operational results,	and	the	effect	of	any	major	storms	that	may	occur	during	the	year.	The	Committee	therefore	established	the	following	targets	for	purposes of	measuring	management	performance,	in	each	case	excluding	the	effect	of	activities	associated	with	the	ITC	Transaction.

|  | Minimum | Target | Maximum |
| :--- | :--- | :--- | :--- |
| Earnings\tPer\tShare\t($) | $4.50 | $5.00 | $5.50 |
| Operating\tCash\tFlow\t($\tbillion) | $2.840 | $3.250 | $3.660 |
| Payout\tLevel | 0% | 100% | 200% |

In	2013	in	connection	with	their	promotions,	the	Personnel	Committee	increased	the	2013	target	awards	for	incentives	to	be	paid	for	2013 under	the	Annual	Incentive	Plan	for	Messrs.	Denault,	Forbes,	Marsh,	May,	and	Mohl	as	follows:	Mr.	Denault's	increased	from	70%	to	120%	of his	base	salary,	Mr.	Marsh's	increased	from	40%	to	70%,	Mr.	Mohl's	and	Mr.	Forbes'	increased	from	60%	to	70%	of	their	base	salaries	and	Mr. May's	increased	from	40%	to	60%	of	his	base	salary.	The	target	awards	established	for	these	officers	were	comparable	to	the	target	awards historically	set	for	these	positions	and	levels	of	responsibility.

In	December	2012,	the	target	awards	for	incentives	to	be	paid	for	2013	under	the	Annual	Incentive	Plan	for	the	other	Named	Executive Officers	were	set	as	follows:	Haley	Fisackerly	(40%);	Hugh	T.	McDonald	(50%);	Alyson	M.	Mount,	(60%);	Sallie	T.	Rainer	(40%);	Charles	L. Rice,	Jr.	(40%);	and	Roderick	K.	West	(70%).

The	 target	 awards	 for	 the	 Named	 Executive	 Officers	 (other	 than	 Entergy	 Corporation	 named	 executive	 officers)	 were	 set	 by their respective	supervisors	(subject	to	ultimate	approval	of	Entergy's	Corporation's	Chief	Executive

Officer)	who	allocated	a	potential	incentive	pool	established	by	the	Personnel	Committee	among	various	of	their	direct	and	indirect	reports.

Target	awards	are	set	based	on	an	executive	officer's	position	and	executive	management	level	within	the	Entergy	organization.	Executive management	levels	at	Entergy	range	from	Level	1	through	Level	4.	At	December	31,	2013,	Mr.	Denault	held	a	Level	1	position,	Messrs.	Forbes, Marsh,	Mohl	and	West	held	positions	in	Level	2,	Ms.	Mount	and	Mr.	May	held	Level	3	positions,	and	the	remaining	Named	Executive	Officers held	positions	in	Level	4.	Accordingly,	their	respective	incentive	targets	differ	one	from	another	based	on	the	external	market	data	developed	by the	Committee's	independent	compensation	consultant	and	the	other	factors	noted	above.

In	 January	 2014,	 the	 Finance	 and	 Personnel	 Committees	 reviewed	 Entergy	 Corporation's	 financial	 results	 against	 the	 performance objectives	reflected	in	the	table	above.	Based	on	the	Finance	Committee's	recommendation,	the	Personnel	Committee	determined	that	for	2013, management	exceeded	its	earnings	per	share	goal	of	$5.00	per	share	by	$0.36	per	share	and	met	its	operating	cash	flow	goal	of	$3.25	billion,	in each	case	based	on	operational	earnings	and	operating	cash	flow,	which	excluded	from	as-reported	results	special	items	recorded	for	(i)	an impairment	and	other	expenses	associated	with	the	planned	closure	of	the	Vermont	Yankee	Nuclear	Power	Station	and	the	related	settlement agreement	reached	with	the	State	of	Vermont	in	2013,	(ii)	expenses	for	the	implementation	of	the	human	capital	management	strategic	initiative	in 2013,	and	(iii)	costs	associated	with	Entergy	Corporation's	proposed	spin-merge	transaction	with	the	ITC	Transaction,	offset	by	a	related	tax benefit.	The	adjustment	to	as-reported	results	for	costs	associated	with	the	ITC	Transaction	had	been	identified	as	a	special	item	at	the	time	the goals	were	set,	but	the	other	special	items	had	arisen	during	the	year.	The	Committee	evaluated	each	of	these	adjustments	to	as-reported	results and	 concluded	 that	 they	 were	 appropriate	 in	 light	 of	 the	 Committee's	 view	 that,	 in	 general,	 management's	 performance	 for	 purposes	 of determining	Annual	Incentive	Plan	awards	should	be	measured	against	operational	financial	results,	since	operational	results	form	the	basis	for Entergy	Corporation's	financial	plan	and	guidance	to	investors	and	are	the	primary	basis	on	which	Entergy	Corporation's	financial	performance	is evaluated	by	investors.

Based	 on	 this	 performance,	 and	 the	 recommendation	 of	 the	 Finance	 Committee,	 the	 Personnel	 Committee	 certified	 an	 Entergy Achievement	Multiplier	of	136%	for	2013,	consistent	with	the	strong	financial	results	achieved	by	Entergy	Corporation,	despite	the	significant challenges	 posed	 in	 2013,	 including	 continued	 low	 wholesale	 power	 prices	 and	 regulatory	 challenges	 and	 uncertainty	 related	 to	 Entergy Corporation's	wholesale	nuclear	plants.	In	reaching	this	decision,	the	Committee	also	took	into	account	management's	performance	in	relation	to	a number	of	strategic	initiatives	and	decisions	undertaken	in	2013,	including	the	successful	integration	of	the	transmission	systems	owned	by Entergy	Corporation's	utility	operating	companies	into	MISO,	the	decision	to	close	the	Vermont	Yankee	Nuclear	Power	Station	and	related settlement	 agreement	 with	 the	 State	 of	 Vermont,	 the	 development	 and	 implementation	 of	 the	 human	 capital	 management	 initiative,	 and management's	unsuccessful	effort	 to	complete	 the	ITC	Transaction.	This	compares	with	an	Entergy	Achievement	Multiplier	of	104%	and	a payout	to	members	of	the	Office	of	Chief	Executive	of	95%	of	target	for	2012,	when	Entergy	Corporation	exceeded	its	earnings	per	share	target by	a	smaller	margin	and	fell	short	of	its	operating	cash	flow	goal	and	the	Personnel	Committee	reduced	the	awards	paid	to	reflect	management's failure	to	meet	the	Committee's	expectations	with	respect	to	employee	safety.

After	 the	 Entergy	 Achievement	 Multiplier	 was	 established	 to	 determine	 overall	 funding	 for	 the	 Annual	 Incentive	 Plan,	 Entergy Corporation's	Chief	Executive	Officer	allocated	incentive	award	funding	to	the	business	units	based	on	their	business	unit	results	(referred	to	as the	 "line	 of	 business	 multiplier").	Individual	awards	were	determined	based	on	 the	 line	of	business	multiplier	as	well	as	 individual	officer performance.

The	following	table	shows	the	Annual	Incentive	Plan	payments	as	a	percentage	of	base	salary	for	2013,	as	well	as	the	incentive	awards paid	to	each	Named	Executive	Officer	for	2013.

|  |  | Target	as	Percentage	of | Payout	as	Percentage	of | 2013	Annual |
| :--- | :--- | :--- | :--- | :--- |
| Named\tExecutive\tOfficer | Base\tSalary | Base\tSalary | Base\tSalary | Incentive\tAward |
| Leo\tP.\tDenault | $1,085,000 | 120% | 163% | $1,770,720 |
| Jeffrey\tD.\tForbes | $550,000 | 70% | 95% | $523,600 |
| Andrew\tS.\tMarsh | $500,000 | 70% | 95% | $476,000 |
| Roderick\tK.\tWest | $612,726 | 70% | 95% | $583,315 |
| Haley\tR.\tFisackerly | $296,174 | 40% | 48% | $142,368 |
| Phillip\tR.\tMay,\tJr. | $330,000 | 60% | 72% | $238,223 |
| Hugh\tT.\tMcDonald | $345,220 | 50% | 56% | $191,562 |
| William\tM.\tMohl | $560,000 | 70% | 95% | $533,120 |
| Alyson\tM.\tMount | $286,700 | 60% | 86% | $245,000 |
| Sallie\tT.\tRainer | $291,000 | 40% | 48% | $140,184 |
| Charles\tL.\tRice,\tJr. | $257,144 | 40% | 44% | $112,446 |

# Nuclear	Retention	Plan

Mr.	Forbes	participates	in	the	Entergy	Nuclear	Retention	Plan,	a	special	retention	plan	for	officers	and	other	leaders	with	special	expertise	in the	nuclear	industry.	The	Committee	authorized	this	plan	to	attract	and	retain	key	management	and	employee	talent	in	the	nuclear	power	field,	a field	that	requires	unique	technical	and	other	expertise	that	is	in	great	demand	in	the	utility	industry.	The	plan	provides	for	bonuses	to	be	paid annually	over	a	 three-year	employment	period	with	 the	bonus	opportunity	dependent	on	 the	participant's	management	 level	and	continued employment.	Each	annual	payment	is	equal	to	an	amount	ranging	from	15%	to	30%	of	the	employee's	base	salary	as	of	their	date	of	enrollment	in the	Plan.	In	the	case	of	Mr.	Forbes,	the	annual	cash	bonus	was	fixed	at	30%	of	his	base	salary	as	of	January	1,	2011	for	the	2011	through	2013 plan	 cycle.	Under	the	plan,	Mr.	Forbes	therefore	received,	in	January	2013,	a	cash	bonus	equal	to	30%	of	his	January	1,	2011	base	salary	of $358,750.	Mr.	Forbes	received	his	final	payout	for	the	2011	through	2013	plan	cycle	in	January	2014.

Mr.	Forbes'	participation	in	the	plan	was	renewed	in	January	2014	for	a	three-year	period	beginning	on	January	1,	2014,	in	recognition	of	the value	Entergy	Corporation	places	on	Mr.	Forbes	as	a	member	of	Entergy	Corporation's	senior	management	team	and	his	extensive	experience	in the	nuclear	industry,	and	to	keep	his	pay	competitive.	In	accordance	with	the	terms	and	conditions	of	the	Nuclear	Retention	Plan,	in	January	2015, 2016	and	2017,	Mr.	Forbes	will	receive	a	cash	bonus	equal	to	30%	of	his	base	salary	as	of	January	1,	2014.	The	three	year	period	covered	and percentage	of	base	salary	paid	to	Mr.	Forbes	under	the	plan	are	consistent	with	the	terms	of	participation	of	other	senior	executive	officers	who participate	in	this	plan.

# Long-Term	Incentive	Compensation

The	goal	for	the	long-term	incentive	compensation	is	to	focus	the	executive	officers	on	building	shareholder	value	and	to	increase	the executive	officers'	ownership	of	Entergy	Corporation	common	stock.	In	the	long-term	incentive	compensation	programs,	Entergy	Corporation uses	a	mix	of	performance	units,	restricted	stock	and	stock	options.	Performance	units	reward	the	Named	Executive	Officers	on	the	basis	of	total shareholder	return,	which	is	a	measure	of	stock	price	appreciation	and	dividend	payments,	in	relation	to	the	companies	in	the	Philadelphia	Utility Index.	Restricted	stock	 ties	 the	executive	officers'	 long-term	financial	 interest	 to	 the	 long-term	financial	 interests	of	Entergy	Corporation's shareholders.	 Stock	 options	 provide	 a	 direct	 incentive	 to	 increase	 the	 price	 of	 Entergy	 Corporation's	 common	 stock.	In	 general,	 Entergy Corporation	seeks	to	allocate	the	total	value	of	long-term	incentive	compensation	60%	to	performance	units	and	40%	to	a	combination	of	stock options	and	restricted	stock,	equally	divided	in	value,

all	based	on	their	grant	date	fair	values.	Allocations	for	individual	Named	Executive	Officers	may	vary	from	this	target	as	a	result	of	individual performance,	promotions	and	internal	pay	equity.

All	of	the	performance	units,	shares	of	restricted	stock	and	stock	options	granted	to	the	Named	Executive	Officers	in	2013	were	awarded under	the	2011	Equity	Ownership	Plan.	All	equity	awards	granted	under	the	equity	ownership	plans	require	both	a	change	in	control	and	an involuntary	job	loss	or	substantial	diminution	of	duties	(a	"double	trigger")	for	the	acceleration	of	these	awards	upon	a	change	in	control.

# Performance	Unit	Program

Performance	unit	awards	are	issued	to	the	Named	Executive	Officers	under	the	Long-Term	Performance	Unit	Program.	Each	performance unit	represents	the	value	of	one	share	of	Entergy	Corporation	common	stock	at	the	end	of	the	three-year	performance	period,	plus	dividends accrued	during	the	performance	period.	The	Personnel	Committee	sets	payout	opportunities	for	the	program	at	the	outset	of	each	performance period,	and	the	program	is	structured	to	reward	Named	Executive	Officers	only	if	performance	goals	set	by	the	Personnel	Committee	are	met.	The Personnel	Committee	has	no	discretion	to	make	awards	if	minimum	performance	goals	are	not	achieved.

Beginning	with	the	2012-2014	performance	period,	upon	vesting,	the	performance	units	granted	under	the	Long-Term	Performance	Unit Program	will	be	settled	in	shares	of	Entergy	Corporation	common	stock	rather	than	cash.	Accrued	dividends	on	any	shares	earned	during	the performance	period	will	also	be	will	be	paid	in	shares	of	Entergy	Corporation	common	stock	at	the	end	of	the	performance	period	if	earned.	All shares	paid	out	under	the	Long-Term	Performance	Unit	Program	will	be	required	to	be	retained	by	the	officers	until	applicable	executive	stock ownership	requirements	are	met.	The	form	of	payment	was	modified	from	a	cash-settled	award	to	a	stock-settled	award	to	align	the	method	of payment	with	market	practice	and	to	encourage	the	executives	to	own	shares	of	Entergy	Corporation	common	stock.

The	Long-Term	Performance	Unit	Program	specifies	a	minimum,	target	and	maximum	achievement	level.	Performance	is	measured	by assessing	Entergy's	 total	shareholder	return	relative	 to	 the	 total	shareholder	return	of	 the	companies	 in	 the	Philadelphia	Utility	Index.	The Personnel	Committee	identified	the	Philadelphia	Utility	Index	as	the	industry	peer	group	for	total	shareholder	return	performance	because	the companies	included	in	this	index,	in	the	aggregate,	approximate	Entergy	Corporation	in	terms	of	business	and	scale.	The	Personnel	Committee chose	relative	total	shareholder	return	as	a	measure	of	performance	because	it	reflects	Entergy	Corporation's	creation	of	shareholder	value	relative to	other	electric	utilities	over	the	performance	period.	It	also	takes	into	account	dividends	paid	by	the	companies	in	this	index	and	normalizes certain	events	that	affect	the	industry	as	a	whole.	Minimum,	target	and	maximum	performance	levels	are	determined	by	reference	to	the	percentile ranking	of	Entergy's	total	shareholder	return	against	the	total	shareholder	return	of	the	companies	in	the	Philadelphia	Utility	Index.	At	any	given time,	a	participant	in	the	Long-Term	Performance	Unit	Program	may	be	participating	in	up	to	three	performance	periods.	Currently,	participants are	participating	in	the	2012-2014,	the	2013-2015	and	the	2014-2016	performance	periods.

2013-2015	Performance	Unit	Program	Grants.	Subject	to	achievement	of	performance	levels,	the	Personnel	Committee	established	the following	target	performance	unit	payout	opportunities	for	the	2013-2015	performance	period:

•37,156	performance	units	for	Mr.	Denault;

•7,472	performance	units	for	Mr.	Forbes	and	Mr.	Mohl;

•7,442	performance	units	for	Mr.	Marsh;

•7,600	performance	units	for	Mr.	West;

•3,000	performance	units	for	Ms.	Mount;

•1.900	performance	units	for	Mr.	Fisackerly,	Mr.	McDonald,	Ms.	Rainer	and	Mr.	Rice.

The	range	of	potential	payouts	under	the	program	is	shown	below.	Each	Named	Executive	Officer	received	a	larger	number	of	performance	units than	were	granted	to	officers	at	their	respective	levels	in	2012	to	reflect	the	lower	stock

price	at	the	time	of	the	award	as	compared	to	2012	and	an	increase	in	targeted	long-term	value	required	to	result	in	awards	approximating	the	50 th percentile	of	the	corporate	market	data.	The	target	awards	for	Messrs.	Denault,	Forbes,	Marsh,	May,	and	Mohl	include	target	awards	established	in January	2013,	plus,	pursuant	to	the	terms	of	the	program,	prorated	awards	received	in	connection	with	their	promotions	in	2013.

| Performance	Level | Minimum | Target | Maximum |
| :--- | :--- | :--- | :--- |
| Total\tShareholder\tReturn | 25th\tpercentile | 50th\tpercentile | 75th\tpercentile |
| Payouts | 25%\tof\ttarget | 100%\tof\ttarget | 200%\tof\tTarget |

There	 is	no	payout	for	performance	below the	25th	percentile.	Payouts	between	minimum	and target	and target	and	maximum	are calculated	using	straight-line	interpolation.

Payout	 for the	 2011-2013	 Performance	 Period.	 For the	 2011-2013	 performance	 period, the	 approved target	 performance	 unit	 payout opportunities	were:

•12,041	performance	units	for	Mr.	Denault;

•1,319	performance	units	for	Ms.	Mount;

•1,200	performance	units	for	Mr.	Fisackerly	and	Mr.	McDonald;

•633	performance	units	for	Ms.	Rainer;	and

•1,200	performance	units	for	Mr.	Rice.

The	target	awards	for	Messrs.	Denault,	Forbes,	Marsh,	May,	and	Mohl	include	target	awards	established	in	January	2011	plus,	pursuant	to	the terms	of	the	program,	pro-rated	awards	received	in	connection	with	their	promotions	in	2013.

| Performance	Level | Minimum | Target | Maximum |
| :--- | :--- | :--- | :--- |
| Total\tShareholder\tReturn | 25th\tpercentile | 50th\tpercentile | 75th\tpercentile |
| Payouts | 10%\tof\ttarget | 100%\tof\ttarget | 250%\tof\tTarget |

In	January	2014,	the	Committee	assessed	Entergy	Corporation's	total	shareholder	return	for	the	2011-2013	performance	period	in	order	to determine	the	actual	number	of	performance	units	to	be	paid	to	Long	Term	Performance	Unit	Program	participants	for	the	2011-2013	performance period.	The	 Committee	 compared	 Entergy	 Corporation's	 total	 shareholder	 return	 against	 the	 total	 shareholder	 return	 of	 the	 companies	 that comprise	 the	 Philadelphia	 Utility	 Index.	 Based	 on	 this	 comparison,	 as	 recommended	 by	 the	 Finance	 Committee,	 the	 Personnel	 Committee concluded	that	Entergy	Corporation's	performance	for	the	2011-2013	performance	period	ranked	in	the	bottom	quartile,	resulting	in	a	zero	payout for	the	2011-2013	performance	period.

# Stock	Options	and	Restricted	Stock

Stock	options	and	restricted	stock	are	granted	as	part	of	the	long-term	incentive	awards	to	the	executive	officers.

As	previously	discussed,	the	Personnel	Committee	considers	several	factors	in	determining	the	number	of	stock	options	and	shares	of restricted	stock	it	will	grant	to	the	Named	Executive	Officers,	including	individual	performance,	prevailing	market	practice,	targeted	long-term valued	created	by	the	use	of	stock	options	and	restricted	stock,	and	the	potential	dilutive	effect	of	stock	option	and	restricted	stock	grants.	The Committee's	assessment	of	individual	performance	of	each	Named	Executive	Officer	is	the	most	important	factor	in	determining	the	number	of

shares	of	restricted	stock	and	stock	options	awarded	except	with	respect	to	Entergy	Corporation's	Chief	Executive	Officer,	for	whom	comparative market	data	is	the	most	important	factor.	The	Committee,	in	consultation	with	Entergy	Corporation's	Chief	Executive	Officer,	reviews	each	other Named	Executive	Officer's	performance,	role	and	responsibilities,	strengths	and	developmental	opportunities.	Stock	option	and	restricted	stock awards	 for	 Entergy	 Corporation's	 Chief	 Executive	 Officer	 are	 determined	 solely	 by	 the	 Personnel	 Committee	 on	 the	 basis	 of	 the	 same considerations.	For	all	equity	awards,	the	Committee	also	considers	Entergy	Corporation's	significant	achievements	of	the	prior	year.

The	following	table	sets	forth	the	number	of	stock	options	and	shares	of	restricted	stock	granted	to	each	Named	Executive	Officer	in	2013. The	exercise	price	for	each	option	was	$64.60,	which	was	the	closing	price	of	Entergy's	common	stock	on	the	date	of	grant.

| Named	Executive	Officer | Stock	Options | Shares	of	Restricted	Stock |
| :--- | :--- | :--- |
| Leo\tP.\tDenault | 50,000 | 6,000 |
| Jeffrey\tS.\tForbes | 22,500 | 2,800 |
| Andrew\tS.\tMarsh | 32,000 | 4,000 |
| Roderick\tK.\tWest | 40,000 | 5,000 |
| Haley\tR.\tFisackerly | 6,000 | 1,400 |
| Phillip\tR.\tMay,\tJr. | 6,000 | 1,400 |
| Hugh\tT.\tMcDonald | 6,000 | 1,400 |
| William\tM.\tMohl | 32,000 | 4,000 |
| Alyson\tM.\tMount | 8,900 | 1,800 |
| Sallie\tT.\tRainer | 5,800 | 1,400 |
| Charles\tL.\tRice,\tJr. | 5,000 | 1,200 |

Stock	 Options.	 Under	 the	 equity	 plans,	 all	 stock	 options	 must	 have	 an	 exercise	 price	 equal	 to	 the	 fair	 market	 value	 of	 Entergy Corporation's	common	stock	on	the	date	of	grant.	The	equity	ownership	plans	prohibit	the	repricing	of	"underwater"	stock	options	without shareholder	approval.

A	formal	policy	has	not	been	adopted	regarding	the	granting	of	options	at	times	when	Entergy	Corporation	is	in	possession	of	material non-public	information.	However,	Entergy	Corporation	generally	grants	options	to	Named	Executive	Officers	only	during	the	month	of	January	in connection	with	annual	executive	compensation	decisions.

Restricted	Stock.	Upon	vesting,	shares	of	Entergy	Corporation	common	stock	will	be	distributed	along	with	the	dividends	that	have accrued	 on	 the	 vested	 shares.	 Entergy	 Corporation	 believes	 the	 use	 of	 restricted	 stock	 enhances	 retention,	 mitigates	 the	 burn	 rate	 and,	 in conjunction	with	stock	ownership	requirements,	assists	in	building	executive	ownership	of	Entergy	Corporation	common	stock.

For	additional	 information	regarding	stock	options	and	shares	of	restricted	stock	awarded in	2013 to	each	of the	Named	Executive Officers,	see	the	2013	Grants	of	Plan-Based	Awards	table.

# Restricted	Units

Restricted	units	granted	under	the	2011	Equity	Ownership	Plan	represent	phantom	shares	of	Entergy	Corporation	common	stock	(i.e.,	non- stock	interests	that	have	an	economic	value	equivalent	to	a	share	of	Entergy	Corporation's	common	stock).	Restricted	units	are	occasionally granted	for	retention	purposes,	to	offset	forfeited	compensation	from	a	previous	employer	or	for	other	limited	purposes.	If	all	conditions	of	the grant	are	satisfied,	restrictions	on	the	restricted	units	lift	at	the	end	of	the	restricted	period,	and	a	cash	equivalent	value	of	the	restricted	units	is paid.	The	settlement	price	is	equal	to	the	number	of	restricted	units	multiplied	by	the	closing	price	of	Entergy	Corporation	common	stock	on	the date	restrictions	lift.	Restricted	units	are	not	entitled	to	dividends	or	voting	rights.	Restricted	units	are	generally

time-based	awards	for	which	restrictions	lift,	subject	to	continued	employment,	generally	over	a	two-	to	five-year	period.

In	January	2013,	the	Committee	granted	Mr.	Forbes	8,000	restricted	units	and	in	May	2013,	the	Committee	granted	Mr.	West	21,000 restricted	units.	The	Committee	granted	the	restricted	units	to	Mr.	Forbes	to	encourage	the	retention	of	his	leadership	in	light	of	the	numerous strategic	challenges	facing	Entergy	Corporation's	nuclear	fleet.	Mr.	West's	award	was	made	in	recognition	of	Mr.	West's	senior	leadership	role with	Entergy	Corporation	and	to	ensure	a	successful	transition	in	light	of	the	leadership	changes	made	in	2013.	In	determining	the	size	of	the	grant, the	Committee	consulted	its	independent	consultant	to	confirm	that	the	grant	was	consistent	with	market	practices.	The	Committee	also	noted, based	on	the	advice	of	its	independent	consultant,	that	such	grants	are	a	commonly	used	technique	for	retention	purposes.

Mr.	Forbes'	restricted	units	will	vest	in	one	installment	on	January	2,	2016	and	Mr.	West's	restricted	units	will	vest	in	one	installment	on May	1,	2018.	On	the	respective	vesting	dates,	Entergy	Corporation	will	pay	to	Mr.	Forbes	and	Mr.	West,	subject	to	payment	of	withholding	taxes, a	cash	amount	equal	to	the	closing	price	of	a	share	of	Entergy	Corporation	common	stock	on	that	date	multiplied	by	the	number	of	units	subject	to their	awards.	Upon	a	termination	of	employment	without	cause	or	upon	termination	of	employment	by	Mr.	Forbes	or	Mr.	West	with	good	reason within	24	months	following	a	change	in	control,	Mr.	Forbes'	and	Mr.	West's	restricted	units	may	vest	on	an	earlier	date.

# Benefits,	Perquisites,	Agreements	and	Post-Termination	Plans

# Pension	Plan,	Pension	Equalization	Plan	and	System	Executive	Retirement	Plan

# Retirement	Plans

The	Named	Executive	Officers	participate	in	an	Entergy	Corporation-sponsored	tax	qualified	final	average	pay	defined	benefit	pension plan	that	covers	a	broad	group	of	employees.	In	addition,	each	Named	Executive	Officer	participates	in	the	Pension	Equalization	Plan,	a	non- qualified	restoration	plan,	and	the	System	Executive	Retirement	Plan,	a	non-qualified	supplemental	retirement	plan.	Both	plans	are	sponsored	by Entergy	Corporation.	Under	the	terms	of	the	Pension	Equalization	Plan	and	System	Executive	Retirement	Plan,	an	employee	participating	in	both plans	is	eligible	to	receive	only	the	greater	of	the	two	benefits	computed	in	accordance	with	the	terms	of,	and	conditions	of	each	plan.

The	Committee	believes	that	these	plans	have	been	an	important	part	of	the	executive	compensation	programs	because	they	have	assisted in	the	recruitment	of	top	talent	in	the	competitive	market,	as	these	types	of	supplemental	plans	have	typically	been	found	historically	in	companies of	similar	size	to	Entergy	Corporation	and	in	its	industry.	These	plans	serve	a	critically	important	role	in	the	retention	of	senior	executives,	as benefits	from	these	plans	generally	increase	for	each	year	that	these	executives	remain	employed	by	us.	The	plans	thereby	have	encouraged	the most	senior	executives	to	remain	employed	by	us	and	continue	their	work	on	behalf	of	Entergy	Corporation's	shareholders.	See	the	2013	Pension Benefits	Table	for	additional	information	regarding	the	operation	of	the	plans	described	under	this	caption.

# Savings	Plan

The	Named	Executive	Officers	are	eligible	to	participate	in	an	Entergy	Corporation-sponsored	Savings	Plan	that	covers	a	broad	group	of employees.	The	Savings	Plan	is	a	tax-qualified	retirement	savings	plan,	wherein	total	combined	before-tax	and	after-tax	contributions	may	not exceed	30%	of	a	participant's	base	salary	up	to	certain	contribution	limits	defined	by	law.	In	addition,	under	the	Savings	Plan,	the	participant's employer	matches	an	amount	equal	to	seventy	cents	for	each	dollar	contributed	by	participating	employees,	including	the	Named	Executive Officers,	with	respect	to	the	first	six	percent	of	their	eligible	earnings	under	the	plan	for	that	pay	period.	For	employees	hired	or	rehired	on	or	after July	1,	2014	who	are	not	eligible	to	participate	in	the	final	average	pay	defined	benefit	pension,	but	instead	will	participate	in	a	new	cash	balance defined	benefit	pension	plan,	the	Entergy	System	employer	matching	contribution	will	be	one	dollar	for	each	dollar	contributed	by	the	employee with	respect	to	the	first	six	percent	of	the

eligible	earnings	for	each	pay	period.	The	Savings	Plan	is	maintained	for	employees,	including	the	Named	Executive	Officers	to	encourage employees	to	save	some	percentage	of	their	cash	compensation	for	their	eventual	retirement.	The	Savings	Plan	permits	employees	to	make	such savings	in	a	manner	that	is	relatively	tax	efficient.	Entergy	Corporation	believes	this	type	of	savings	plan	is	also	a	critical	element	in	attracting	and retaining	talent	in	a	competitive	market.

# Retirement	Plan	Changes

During	2013,	after	reviewing	comparative	market	data,	the	Personnel	Committee	approved	certain	changes	to	Entergy	Corporation's retirement	plans	and	policies	to	better	align	them	with	emerging	market	practice.	As	a	result	of	these	changes,	employees	who	are	hired	or	rehired on	or	after	July	1,	2014	will	no	longer	be	eligible	to	participate	in	Entergy	Corporation's	tax	qualified	final	average	pay	defined	benefit	pension plan	and	instead	will	participate	in	a	new	cash	balance	pension	plan	and	will	receive	an	enhanced	employer	matching	contribution	under	Entergy Corporation's	 Savings	 Plan,	 as	 described	 above.	In	 addition,	 in	 January	 2014,	 the	 Committee	 authorized	 management	 to	 (i)	 amend	 the Supplemental	Executive	Retirement	Plan	to	provide	that	as	of	July	1,	2014,	the	plan	will	be	closed	to	new	participants,	including	employees	hired or	promoted	to	an	officer-level	position	on	or	after	July	1,	2014,	(ii)	amend	the	Pension	Equalization	Plan	to	provide	that	participants	in	the	new cash	balance	pension	plan	will	not	be	eligible	to	participate	 in	such	plan	and	 instead	may	be	eligible	 to	participate	 in	a	new	cash	balance restoration	plan,	and	(iii)	amend	the	Pension	Equalization	Plan	and,	as	necessary,	all	other	non-qualified	plans	sponsored	by	Entergy	Corporation to	provide	that	supplemental	credited	service	will	no	longer	be	granted	under	any	such	plans	to	new	executive	officers.

# Executive	Deferred	Compensation	Plan

The	Named	Executive	Officers	are	eligible	 to	defer	up	 to	100%	of	 their	Annual	Incentive	Plan	awards	 into	either	or	both	Entergy Corporation-sponsored	Executive	Deferred	Compensation	Plan	and	the	equity	plan.	In	addition,	they	are	eligible	to	defer	up	to	100%	of	their	base salary	into	the	Executive	Deferred	Compensation	Plan.	Entergy	Corporation	believes	that	providing	this	benefit	is	important	as	a	retention	and recruitment	tool	because	many,	if	not	all,	of	the	companies	with	which	Entergy	Corporation	competes	for	executive	talent	provide	a	similar arrangement	to	their	senior	executive	officers.	See	the	2013	Non-qualified	Deferred	Compensation	discussion	for	additional	information	regarding the	operation	of	the	Executive	Deferred	Compensation	Plan.

# Health	&	Welfare	Benefits

The	Named	Executive	Officers	are	eligible	to	participate	in	various	health	and	welfare	benefits	available	to	a	broad	group	of	employees. These	benefits	include	medical,	dental	and	vision	coverage,	life	and	accidental	death	and	dismemberment	insurance,	business	travel	accident insurance,	and	long-term	disability	insurance.	Eligibility,	coverage	levels,	potential	employee	contributions,	and	other	plan	design	features	are	the same	for	the	Named	Executive	Officers	as	for	the	broad	employee	population.

# Executive	Disability	Plan

All	of	the	executive	officers,	including	the	Named	Executive	Officers,	are	eligible	to	participate	in	the	Executive	Disability	Plan	of Entergy	Corporation	and	Subsidiaries.	Individuals	who	elect	to	participate	in	this	plan	and	become	disabled	under	the	terms	of	the	plan	are	eligible for	65%	of	the	difference	between	their	base	salary	and	$276,923	(i.e.	the	base	salary	that	produces	the	maximum	$15,000	monthly	disability payment	under	Entergy	Corporation's	general	long-term	disability	plan).

# Perquisites

Named	Executive	Officers	are	provided	with	a	limited	number	of	perquisites	and	other	personal	benefits	as	part	of	providing	a	competitive executive	compensation	program	and	for	employee	retention.	The	Personnel	Committee	reviews	all	perquisites,	including	the	personal	use	of corporate	aircraft,	on	an	annual	basis.	In	2013,	the	Named	Executive	Officers	were	offered:	corporate	aircraft	usage,	relocation	assistance,	annual physical	exams,	and	event	tickets.	Certain

of	the	Named	Executive	Officers,	who	are	not	members	of	the	Office	of	the	Chief	Executive,	were	provided	in	2013	with	club	dues	and	tax	gross up	payments	on	some	perquisites.	For	security	and	business	convenience	reasons,	Entergy	Corporation's	Chief	Executive	Officer	is	permitted	to use	its	corporate	aircraft	at	the	expense	of	Entergy	Corporation	for	personal	use.	The	other	Named	Executive	Officers	may	use	corporate	aircraft for	personal	travel	subject	to	the	approval	of	Entergy	Corporation's	Chief	Executive	Officer.	From	time	to	time,	tickets	to	cultural	and	sporting events	are	made	available	to	employees,	including	the	Named	Executive	Officers,	for	business	purposes.	If	not	utilized	for	business	purposes,	the tickets	are	made	available	to	employees,	including	the	Named	Executive	Officers,	for	personal	use.	Relocation	benefits	provided	to	the	executive officers,	including	tax	gross-up	payments	on	this	benefit,	are	similar	in	nature	and	amount	to	those	provided	to	all	eligible	employees.	For additional	information	regarding	perquisites,	see	the	"All	Other	Compensation"	column	in	the	Summary	Compensation	Table.

# Retention	Agreements	and	other	Compensation	Arrangements

The	Committee	believes	that	retention	and	transitional	compensation	arrangements	are	an	important	part	of	overall	compensation.	The Committee	 believes	 that	 these	 arrangements	 help	 to	 secure	 the	 continued	 employment	 and	 dedication	 of	 the	 Named	 Executive	 Officers, notwithstanding	any	concern	that	they	might	have	at	the	time	of	a	change	in	control	regarding	their	own	continued	employment.	In	addition,	the Committee	believes	that	these	arrangements	are	important	as	recruitment	and	retention	devices,	as	all	or	nearly	all	of	the	companies	with	which Entergy	Corporation	competes	for	executive	talent	have	similar	arrangements	in	place	for	their	senior	employees.

To	achieve	these	objectives,	Entergy	Corporation	has	established	a	System	Executive	Continuity	Plan	under	which	each	of	the	Named Executive	Officers	is	entitled	to	receive	"change	in	control"	payments	and	benefits	if	such	officer's	employment	is	involuntarily	terminated	in connection	with	a	change	in	control.	Severance	payments	under	the	System	Executive	Continuity	Plan	are	based	on	a	multiple	of	the	sum	of	an executive	officer's	annual	base	salary	plus	his	or	her	average	Annual	Incentive	Plan	award	at	target	for	the	two	fiscal	years	immediately	preceding the	fiscal	year	in	which	the	termination	of	employment	occurs.	Under	no	circumstances	can	this	multiple	exceed	2.99	times	the	sum	of	(a)	the executive	officer's	annual	base	salary	as	in	effect	at	any	time	within	one	year	prior	to	the	commencement	of	a	change	in	control	period	or	if	higher, immediately	prior	to	a	circumstance	constituting	good	reason	plus	(b)	his	or	her	annual	incentive,	calculated	using	the	average	annual	target opportunity	derived	under	the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	officer's termination	occurs,	or	if	higher	the	annual	incentive	award	actually	received	under	the	Annual	Incentive	Plan	for	the	fiscal	year	immediately preceding	the	fiscal	year	in	which	the	termination	of	employment	occurs.	Entergy	Corporation	has	strived	to	ensure	that	the	benefits	and	payment levels	under	the	System	Executive	Continuity	Plan	are	consistent	with	market	practices.	The	executive	officers	will	not	receive	any	tax	gross-up payments	on	any	severance	benefits	received	under	this	plan.

In	certain	cases,	the	Committee	may	approve	the	execution	of	a	retention	agreement	with	an	individual	executive	officer.	These	decisions are	made	on	a	case	by	case	basis	to	reflect	specific	retention	needs	or	other	factors,	including	market	practice.	If	a	retention	agreement	is	entered into	with	an	individual	officer,	the	Committee	considers	the	economic	value	associated	with	that	agreement	in	making	overall	compensation decisions	for	that	officer.	Entergy	Corporation	has	voluntarily	adopted	a	policy	that	any	severance	arrangements	providing	benefits	in	excess	of 2.99	times	an	officer's	annual	base	salary	and	annual	incentive	award	must	be	approved	by	Entergy	Corporation's	shareholders.

During	 2013,	 Entergy	 Corporation	 had	 retention	 agreements	 with	 Mr.	 Denault	 and	 Mr.	 Mohl.	 In	 general,	 Mr.	 Denault's	 retention agreement	provides	for	severance	payments	and	other	benefits	in	the	event	of	termination	of	employment	other	than	for	cause	or	on	account	of death	or	disability	in	lieu	of	those	provided	under	Entergy	Corporation's	System	Executive	Continuity	Plan.	As	with	any	severance	benefits	paid under	the	System	Executive	Continuity	Plan,	Mr.	Denault	will	not	receive	tax	gross-up	payments	on	any	severance	benefits	he	may	receive	under his	agreement.	Mr.	Denault's	retention	agreement	was	entered	into	when	he	was	Entergy	Corporation's	Chief	Financial	Officer	and	was	designed to	reflect	the	competition	for	chief	financial	officer	talent	in	the	marketplace	at	that	time	and	the	Committee's	assessment	of	the	critical	role	this position	plays	in	executing	Entergy	Corporation's	long-term	financial	and	other	strategic	objectives.	Based	on	the	market	data	provided	by	its former	independent	compensation	consultant,	the	Committee	believes	the	benefits	and	payment	levels	under	Mr.	Denault's	retention	agreement are	consistent	with	market	practices.

Entergy	Corporation	entered	into	an	agreement	with	Mr.	Mohl	when	he	became	President,	Entergy	Wholesale	Commodities	that	provides for	severance	payments	if	his	employment	is	terminated	upon	the	occurrence	of	certain	events	related	to	the	Entergy	Wholesale	Commodities business	(an	"EWC	Event")	and	subsequent	to	such	event,	he	does	not	continue	employment	with	the	wholesale	commodities	business	and	is	not offered	a	comparable	position	with	an	Entergy	System	company.	Upon	termination,	Mr.	Mohl	would	receive	a	payment	equal	to	two	times	his base	salary	plus	his	target	annual	incentive	bonus	for	the	year	of	termination	or	if	termination	occurs	in	2014,	his	2013	target	annual	bonus	if	it	is higher	than	the	2014	target	annual	bonus.	If	such	termination	occurs	prior	to	September	18,	2014,	he	will	be	eligible	to	receive,	in	addition	to	the severance	payment	described	above,	a	payment	equal	to	$2,200,000	plus	a	payment	equal	to	the	benefits	he	would	have	been	eligible	for	under	the System	Executive	Retirement	Plan	as	if	he	were	retirement	eligible,	reduced	by	any	benefits	payable	under	any	of	Entergy	Corporation's	qualified or	non-qualified	plans	provided	he	executes	a	release	agreement	in	favor	of	Entergy	Corporation.	If	the	EWC	Event	is	considered	a	change	in control	under	Entergy	Corporation's	System	Continuity	Plan,	he	will	only	receive	the	benefits	he	is	eligible	for	under	that	plan.	This	agreement was	entered	into	in	light	of	the	unique	challenges	facing	the	Entergy	Wholesale	Commodities	business	at	the	time	Mr.	Mohl	assumed	his	position. In	 determining	 the	 type	 and	 size	 of	 the	 amount	 of	 payment	 under	 this	 agreement,	 Entergy	 Corporation	 consulted	 with	 the	 independent compensation	consultant	to	confirm	that	the	economic	value	of	this	arrangement	was	consistent	with	market	practice.

For	additional	information	regarding	the	System	Executive	Continuity	Plan	and	Mr.	Denault's	and	Mr.	Mohl's	retention	agreements described	above,	see	"2013	Potential	Payments	Upon	Termination	or	Change."

# Other	Compensation	Policies	and	Practices

Entergy	Corporation	strives	to	ensure	that	its	compensation	philosophy	and	practices	are	in	line	with	the	best	practices	of	companies	in	its industry	as	well	as	Fortune	500	companies.	Some	of	these	practices	include	the	following:

# Clawback	Provisions

Entergy	Corporation	has	adopted	the	Entergy	Corporation	Policy	Regarding	Recoupment	of	Certain	Compensation.	This	policy	covers individuals	subject	to	Section	16	of	the	Exchange	Act.	Under	the	policy,	the	Committee	will	require	reimbursement	of	incentives	paid	to	these executive	officers	where:

•(i)	the	payment	was	predicated	upon	the	achievement	of	certain	financial	results	with	respect	to	the	applicable	performance	period	that were	subsequently	the	subject	of	a	material	restatement	other	than	a	restatement	due	to	changes	in	accounting	policy;	or	(ii)	a	material miscalculation	of	a	performance	award	occurs,	whether	or	not	the	financial	statements	were	restated	and,	in	either	such	case,	a	lower payment	would	have	been	made	to	the	executive	officer	based	upon	the	restated	financial	results	or	correct	calculation;	or •in	the	Board	of	Directors'	view,	the	executive	officer	engaged	in	fraud	that	caused	or	partially	caused	the	need	for	a	restatement	or	caused a	material	miscalculation	of	a	performance	award	whether	or	not	the	financial	statements	were	restated.

The	amount	the	Committee	requires	to	be	reimbursed	is	equal	to	the	excess	of	the	gross	incentive	payment	made	over	the	gross	payment	that would	have	been	made	 if	 the	original	payment	had	been	determined	based	on	 the	restated	financial	results	or	correct	calculation.	Further, following	a	material	restatement	of	Entergy	Corporation's	financial	statements,	Entergy	Corporation	will	seek	 to	recover	any	compensation received	by	Entergy	Corporation's	Chief	Executive	Officer	and	Chief	Financial	Officer	that	is	required	to	be	reimbursed	under	Section	304	of	the Sarbanes-Oxley	Act	of	2002.

# Stock	Ownership	Guidelines	and	Share	Retention	Requirements

For	many	years,	Entergy	Corporation	has	had	stock	ownership	guidelines	for	executives,	including	the	Named	Executive	Officers.	These guidelines	are	designed	to	align	the	executives'	long-term	financial	interests	with	those	of	shareholders.	Annually,	the	Personnel	Committee monitors	the	executive	officers'	compliance	with	these	guidelines.

To	more	closely	align	the	stock	ownership	guidelines	with	market	practice,	effective	January	1,	2014,	Entergy	Corporation	adjusted	the	stock ownership	guidelines	to	increase	the	salary	multiple	for	Entergy	Corporation's	Chief	Executive	Officer	to	six	times	his	base	salary	and	reduced	the base	salary	multiple	for	the	other	executive	officers.

The	new	ownership	guidelines	are	as	follows:

Further,	to	ensure	compliance	with	the	guidelines,	until	an	executive	officer	satisfies	the	stock	ownership	guidelines,	the	officer	must

# retain:

•all	net	after-tax	shares	paid	out	under	the	Long-Term	Performance	Unit	Program,	which	will	pay	out	entirely	in	Entergy	Corporation	stock commencing	with	the	2012-2014	performance	period;

•all	net	after-tax	shares	of	Entergy	Corporation's	restricted	stock	received	upon	vesting;	and

•at	least	75%	of	the	after-tax	net	shares	received	upon	the	exercise	of	Entergy	Corporation	stock	options,	except	for	stock	options	granted before	 January	 1,	 2014,	 as	 to	 which	 the	 executive	 officer	 must	 retain	 at	 least	 75%	 of	 the	 after-tax	 net	 shares	 until	 the	 earlier	 of achievement	of	the	stock	ownership	guidelines	or	five	years	from	the	date	of	exercise.

# Trading	Controls	and	Anti-Pledging	and	Anti-Hedging	Policies

Executive	officers,	including	the	Named	Executive	Officers,	are	required	to	receive	the	permission	of	Entergy	Corporation's	General Counsel	prior	to	entering	into	any	transaction	involving	company	securities,	including	gifts,	other	than	the	exercise	of	employee	stock	options. Trading	is	generally	permitted	only	during	open	trading	windows	occurring	immediately	following	the	release	of	earnings.	Employees,	who	are subject	to	trading	restrictions,	including	the	Named	Executive	Officers,	may	enter	into	trading	plans	under	Rule	10b5-1	of	the	Exchange	Act,	but these	 trading	 plans	 may	 be	 entered	 into	 only	 during	 an	 open	 trading	 window	 and	 must	 be	 approved	 by	 Entergy	 Corporation.	The	 Named Executive	Officer	bears	full	responsibility	if	he	or	she	violates	this	policy	by	permitting	shares	to	be	bought	or	sold	without	pre-approval	or	when trading	is	restricted.

Entergy	Corporation	also	prohibits	directors	and	executive	officers,	including	the	Named	Executive	Officers,	from	pledging	any	Entergy Corporation	securities	or	entering	into	margin	accounts	involving	Entergy	Corporation	securities.	Entergy	Corporation	prohibits	these	transactions because	of	the	potential	that	sales	of	Entergy	Corporation	securities	could	occur	outside	trading	periods	and	without	the	required	approval	of	the General	Counsel.

Entergy	Corporation	also	has	adopted	an	anti-hedging	policy	that	prohibits	officers,	directors	and	employees	from	entering	into	hedging	or monetization	transactions	involving	Entergy	Corporation's	common	stock.	Prohibited	transactions	include,	without	limitation,	zero-cost	collars, forward	sale	contracts,	purchase	or	sale	of	options,	puts,	calls,	straddles	or	equity	swaps	or	other	derivatives	that	are	directly	linked	to	Entergy Corporation's	stock	or	transactions	involving	"short-sales"	of	Entergy	Corporation's	stock.	The	Board	adopted	this	policy	to	require	officers, directors	and	employees	to	continue	to	own	Entergy	Corporation	stock	with	the	full	risks	and	rewards	of	ownership,	thereby	ensuring	continued alignment	of	their	objectives	with	those	of	Entergy	Corporation's	other	shareholders.

# Compensation	Consultant	Independence	Policy

To	maintain	the	independence	of	the	Personnel	Committee's	compensation	consultant,	the	Board	has	adopted	a	policy	that	any	consultant (including	its	affiliates)	retained	by	the	Board	of	Directors	or	any	Committee	of	the	Board	of	Directors	to	provide	advice	or	recommendations	on the	amount	or	form	of	executive	and	director	compensation

should	not	be	retained	by	Entergy	Corporation	or	any	of	its	affiliates	to	provide	other	services	in	an	aggregate	amount	that	exceeds	$120,000	in any	year.	In	2013,	the	Personnel	Committee's	independent	compensation	consultant,	Pay	Governance	LLC,	did	not	provide	any	services	to Entergy	Corporation	other	than	its	services	to	the	Personnel	Committee.	Annually,	the	Committee	reviews	the	relationship	with	its	compensation consultant	including	services	provided,	quality	of	those	services,	and	fees	associated	with	services	in	its	evaluation	of	the	executive	compensation consultant's	independence.

# Roles	and	Responsibilities

# Role	of	Personnel	Committee

The	Personnel	Committee	has	overall	responsibility	for	approving	the	compensation	program	for	the	Named	Executive	Officers	and makes	all	final	compensation	decisions	regarding	the	Named	Executive	Officers.	The	Committee	works	with	executive	management	to	ensure	that the	compensation	policies	and	practices	are	consistent	with	Entergy	Corporation's	values	and	support	the	successful	recruitment,	development, and	retention	of	executive	talent	so	business	objectives	can	be	achieved	and	optimize	Entergy	Corporation's	long-term	financial	returns.	The Committee	evaluates	executive	pay	each	year	to	ensure	that	the	compensation	policies	and	practices	are	consistent	with	Entergy	Corporation's philosophy.	The	Personnel	Committee	is	responsible	for,	among	its	other	duties,	the	following	actions	related	to	the	Named	Executive	Officers:

•developing	and	implementing	compensation	policies	and	programs	for	hiring,	evaluating,	and	setting	compensation	for	the	executive officers,	including	any	employment	agreement	with	an	executive	officer;

•evaluating	the	performance	of	Entergy	Corporation's	Chairman	and	Chief	Executive	Officer;	and

•reporting,	at	least	annually,	to	the	Board	on	succession	planning,	including	succession	planning	for	Entergy	Corporation's	Chief	Executive Officer.

# Role	of	Chief	Executive	Officer

The	Personnel	Committee	solicits	recommendations	from	Entergy	Corporation's	Chief	Executive	Officer,	with	respect	to	compensation decisions	for	the	other	Named	Executive	Officers.	Compensation	decisions	made	by	the	Personnel	Committee	in	early	2013	were	based	on	the recommendations	of	Mr.	Leonard,	Entergy	Corporation's	former	Chief	Executive	Officer.

At	the	Committee's	request,	Entergy	Corporation's	Chief	Executive	Officer	provides	the	Personnel	Committee	with	an	assessment	of	the performance	of	each	of	the	other	Named	Executive	Officers	and	recommends	compensation	levels	to	be	awarded	to	each	of	them.	In	addition,	the Committee	may	request	that	Entergy	Corporation's	Chief	Executive	Officer	provide	management	feedback	and	recommendations	on	changes	in the	design	of	compensation	programs,	such	as	special	retention	plans	or	changes	in	the	structure	of	bonus	programs	Mr.	Denault	does	not	play	any role	with	respect	to	any	matter	affecting	his	own	compensation,	nor	does	he	have	any	role	determining	or	recommending	the	amount,	or	form	of, director	compensation.	The	Personnel	Committee	also	relies	on	the	recommendations	of	the	senior	human	resources	executives	with	respect	to compensation	decisions,	policies	and	practices.

Mr.	Denault	may	attend	meetings	of	the	Personnel	Committee	only	at	the	invitation	of	the	chair	of	the	Personnel	Committee	and	cannot call	a	meeting	of	the	Committee.	However,	he	is	not	in	attendance	at	the	portion	of	any	meeting	when	the	Committee	approves	the	compensation to	be	paid	to	the	Named	Executive	Officers.	Since	he	is	not	a	member	of	the	Committee,	he	has	no	vote	on	matters	submitted	to	the	Committee. During	2013,	Mr.	Denault	attended	6	meetings	of	the	Personnel	Committee.

# Role	of	the	Compensation	Consultant

The	Personnel	Committee	has	the	sole	authority	from	the	Board	of	Directors	for	the	appointment,	compensation,	and	oversight	of	its outside	compensation	consultant.	In	2013,	Entergy	Corporation's	Personnel	Committee	retained

Pay	Governance	LLC	as	its	independent	compensation	consultant	to	assist	it	in,	among	other	things,	evaluating	different	compensation	programs and	developing	market	data	to	assess	the	compensation	programs.

During	2013,	Pay	Governance	assisted	the	Committee	with	its	responsibilities	related	to	Entergy	Corporation's	compensation	programs	for its	executives.	Specifically,	the	Committee	directed	Pay	Governance	to:	(i)	regularly	attend	meetings	of	the	Committee;	(ii)	conduct	studies	of competitive	compensation	practices;	(iii)	identify	market	surveys	and	proxy	peer	groups;	(iv)	review	base	salary,	annual	incentives,	and	long-term incentive	compensation	opportunities	relative	to	competitive	practices;	and	(v)	develop	conclusions	and	recommendations	related	to	the	executive compensation	plan	for	consideration	by	the	Committee.	A	senior	consultant	from	Pay	Governance	attended	all	Personnel	Committee	meetings	to which	he	was	invited	in	2013.	Pay	Governance	did	not	provide	any	other	services	to	Entergy	Corporation	in	2013.

# Tax	and	Accounting	Considerations

Section	162(m)	of	the	Code	limits	the	tax	deductibility	by	a	publicly	held	corporation	of	compensation	in	excess	of	$1	million	paid	to Entergy	Corporation's	Chief	Executive	Officer	or	any	of	its	other	Named	Executive	Officers	who	may	be	a	Section	162(m)	covered	employee, unless	that	compensation	is	"performance-based	compensation"	within	 the	meaning	of	Section	162(m).	The	Personnel	Committee	considers deductibility	under	Section	162(m)	as	it	structures	the	compensation	packages	that	are	provided	to	its	Named	Executive	Officers.	Likewise,	the Personnel	Committee	considers	financial	accounting	consequences	as	it	structures	the	compensation	packages	that	are	provided	to	the	Named Executive	Officers.	However,	the	Personnel	Committee	and	the	Board	believe	that	it	is	in	Entergy	Corporation's	best	interest	that	the	Personnel Committee	retains	the	flexibility	and	discretion	to	make	compensation	awards,	whether	or	not	deductible.	This	flexibility	is	necessary	to	foster achievement	of	performance	goals	established	by	the	Personnel	Committee,	as	well	as	other	corporate	goals	that	the	Committee	deems	important to	Entergy	Corporation's	success,	such	as	encouraging	employee	retention	and	rewarding	achievement	of	key	Entergy	Corporation's	goals.

# PERSONNEL	COMMITTEE	REPORT

The	Personnel	Committee	Report	included	in	the	Entergy	Corporation	Proxy	Statement	is	incorporated	by	reference,	but	will	not	be deemed	to	be	"filed"	in	this	Annual	Report	on	Form	10-K.	None	of	the	Subsidiaries	has	a	compensation	committee	or	other	board	committee performing	equivalent	functions.	The	board	of	directors	of	each	of	the	Subsidiaries	is	comprised	of	individuals	who	are	officers	or	employees	of Entergy	Corporation	or	one	of	the	Subsidiaries.	These	boards	do	not	make	determinations	regarding	the	compensation	paid	to	executive	officers	of the	Subsidiaries.

# EXECUTIVE	COMPENSATION	TABLES

# 2013	Summary	Compensation	Table

The	following	table	summarizes	the	total	compensation	paid	or	earned	by	each	of	the	Named	Executive	Officers	for	the	fiscal	years	ended December	31,	2013,	2012,	and	2011.		For	information	on	the	principal	positions	held	by	each	of	the	Named	Executive	Officers,	see	Item	10, "Directors	and	Executive	Officers	of	the	Registrants."		The	compensation	set	forth	in	the	table	represents	the	aggregate	compensation	paid	by	all Entergy	System	companies.	 	None	of	the	Entergy	System	companies	has	entered	into	any	employment	agreements	with	any	of	the	Named Executive	 Officers	 (other	 than	 the	 retention	 agreements	 described	 in	 "Potential	 Payments	 upon	 Termination	 or	 Change	 in	 Control").	 	 For additional	information	regarding	the	material	terms	of	the	awards	reported	in	the	following	tables,	including	a	general	description	of	the	formula	or criteria	to	be	applied	in	determining	the	amounts	payable,	see	"Compensation	Discussion	and	Analysis."

| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | Change\tin |  |  |
|  |  |  |  |  |  |  | Pension |  |  |
|  |  |  |  |  |  |  | Value\tand |  |  |
|  |  |  |  |  |  | Non-Equity | Non-qualified |  |  |
|  |  |  |  |  |  | Incentive | Deferred |  |  |
|  |  |  |  | Stock | Option | Plan | Compensation | All |  |
| Name\tand | Year | Salary | Bonus | Awards | Awards | Compensation | Earnings | Other | Total |
| Principal\tPosition |  | (1) | (2) | \t(3) | \t(4) | (5) | \t(6) | Compensation\t(7) |  |
| Leo\tP.\tDenault | 2013 | $1,039,253 | $— | $3,780,189 | $400,000 | $1,770,720 | $630,800 | $44,690 | $7,665,652 |
| Chairman\tof\tthe | 2012 | $669,564 | $— | $647,594 | $282,600 | $448,779 | $972,400 | $22,657 | $3,043,594 |
| Board\tand\tCEO\t- | 2011 | $648,512 | $— | $891,941 | $287,000 | $587,059 | $980,400 | $16,756 | $3,411,668 |
| Entergy\tCorp. |  |  |  |  |  |  |  |  |  |
| Haley\tR.\tFisackerly | 2013 | $294,090 | $10,000 | $214,624 | $48,000 | $142,368 | $— | $28,058 | $737,140 |
| CEO\t-\tEntergy | 2012 | $287,296 | $30,000 | $186,225 | $43,332 | $139,000 | $284,900 | $26,781 | $997,534 |
| Mississippi | 2011 | $280,885 | $— | $172,899 | $33,292 | $150,000 | $295,700 | $16,603 | $949,379 |
| Jeffrey\tS.\tForbes | 2013 | $547,548 | $107,625 | $1,323,048 | $180,000 | $523,600 | $264,100 | $26,186 | $2,972,107 |
| Executive\tVice |  |  |  |  |  |  |  |  |  |
| President\tand\tChief |  |  |  |  |  |  |  |  |  |
| Nuclear\tOfficer\t- |  |  |  |  |  |  |  |  |  |
| Entergy\tCorp. |  |  |  |  |  |  |  |  |  |
| Andrew\tS.\tMarsh | 2013 | $477,846 | $— | $921,927 | $256,000 | $476,000 | $157,700 | $213,663 | $2,503,136 |
| Executive\tVice |  |  |  |  |  |  |  |  |  |
| President\tand\tCFO\t- |  |  |  |  |  |  |  |  |  |
| Entergy\tCorp. |  |  |  |  |  |  |  |  |  |
| Phillip\tR.\tMay,\tJr. | 2013 | $321,860 | $5,000 | $325,813 | $48,000 | $238,223 | $— | $16,547 | $955,443 |
| CEO\t-\tEntergy\tGulf |  |  |  |  |  |  |  |  |  |
| States\tLouisiana\tand |  |  |  |  |  |  |  |  |  |
| Entergy\tLouisiana |  |  |  |  |  |  |  |  |  |
| Hugh\tT.\tMcDonald | 2013 | $342,791 | $10,000 | $214,624 | $48,000 | $191,562 | $— | $48,326 | $855,303 |
| CEO\t-\tEntergy | 2012 | $334,891 | $30,000 | $193,355 | $43,332 | $202,000 | $452,900 | $38,819 | $1,295,297 |
| Arkansas | 2011 | $327,892 | $— | $172,899 | $33,292 | $210,000 | $485,000 | $28,320 | $1,257,403 |
| William\tM.\tMohl | 2013 | $535,712 | $— | $882,568 | $256,000 | $533,120 | $367,600 | $200,784 | $2,775,784 |
| Former\tCEO\t- | 2012 | $340,447 | $30,000 | $268,014 | $69,708 | $300,000 | $448,600 | $17,169 | $1,473,938 |
| Entergy\tGulf\tStates | 2011 | $332,751 | $— | $303,794 | $70,028 | $265,000 | $388,900 | $26,668 | $1,387,141 |

| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | Change\tin |  |  |
|  |  |  |  |  |  |  | Pension |  |  |
|  |  |  |  |  |  |  | Value\tand |  |  |
|  |  |  |  |  |  | Non-Equity | Non-qualified |  |  |
|  |  |  |  |  |  | Incentive | Deferred |  |  |
|  |  |  |  | Stock | Option | Plan | Compensation | All |  |
| Name\tand | Year | Salary | Bonus | Awards | Awards | Compensation | Earnings | Other | Total |
| Principal\tPosition |  | (1) | (2) | \t(3) | \t(4) | (5) | \t(6) | Compensation\t(7) |  |
| Alyson\tM.\tMount | 2013 | $284,896 | $— | $312,360 | $71,200 | $245,000 | $69,200 | $14,553 | $997,209 |
| Acting\tprincipal | 2012 | $252,389 | $— | $320,401 | $— | $210,000 | $384,700 | $11,556 | $1,179,046 |
| financial\tofficer\t- |  |  |  |  |  |  |  |  |  |
| Entergy\tArkansas, |  |  |  |  |  |  |  |  |  |
| Entergy\tGulf\tStates |  |  |  |  |  |  |  |  |  |
| Louisiana,\tEntergy |  |  |  |  |  |  |  |  |  |
| Louisiana,\tEntergy |  |  |  |  |  |  |  |  |  |
| Mississippi,\tEntergy |  |  |  |  |  |  |  |  |  |
| New\tOrleans, |  |  |  |  |  |  |  |  |  |
| Entergy\tTexas |  |  |  |  |  |  |  |  |  |
| Sallie\tT.\tRainer | 2013 | $286,692 | $10,000 | $214,624 | $46,400 | $140,184 | $57,800 | $22,779 | $778,479 |
| CEO\t-\tEntergy | 2012 | $251,907 | $30,000 | $215,262 | $— | $128,000 | $581,300 | $13,714 | $1,220,183 |
| Texas |  |  |  |  |  |  |  |  |  |
| Charles\tL.\tRice,\tJr. | 2013 | $255,786 | $10,000 | $201,704 | $40,000 | $112,446 | $67,900 | $24,078 | $711,914 |
| CEO\t-\tEntergy\tNew | 2012 | $250,781 | $30,000 | $175,530 | $43,332 | $115,000 | $96,900 | $24,422 | $735,965 |
| Orleans | 2011 | $245,312 | $— | $154,702 | $33,292 | $130,000 | $78,400 | $20,594 | $662,300 |
| Roderick\tK.\tWest | 2013 | $606,381 | $— | $2,318,926 | $320,000 | $583,315 | $147,800 | $27,045 | $4,003,467 |
| Executive\tVice | 2012 | $584,540 | $— | $647,594 | $282,600 | $391,791 | $991,000 | $46,097 | $2,943,622 |
| President\tand\tChief | 2011 | $566,162 | $— | $746,361 | $195,160 | $512,512 | $664,800 | $20,261 | $2,705,256 |

# Officer	-	Entergy

# Corp.

(1) The	amounts	in	column	(c)	represent	the	actual	base	salary	paid	to	the	Named	Executive	Officer.		The	2013	changes	in	base	salaries	noted in	the	Compensation	Discussion	and	Analysis	for	Messrs.	Denault,	Forbes,	Marsh,	May,	and	Mohl	were	effective	upon	their	promotions and	for	the	other	Named	Executive	Officers	in	April	2013.

(2) The	amounts	in	column	(d)	in	2013	and	2012	for	Mr.	Fisackerly,	Mr.	McDonald,	Ms.	Rainer,	and	Mr.	Rice,	in	2012	for	Mr.	Mohl,	and	in 2013	for	Mr.	May	represent	a	cash	bonus	paid	in	recognition	of	their	work	supporting	the	move	to	MISO.	The	amount	for	Mr.	Forbes represents	the	cash	bonus	paid	to	him	pursuant	to	the	Nuclear	Retention	Plan.	See	"Nuclear	Retention	Plan"	in	Compensation	Discussion and	Analysis.

(3) The	amounts	in	column	(e)	represent	the	aggregate	grant	date	fair	value	of	restricted	stock,	restricted	units,	and	performance	units	granted under	the	2011	Equity	Ownership	Plan	calculated	in	accordance	with	FASB	ASC	Topic	718,	without	taking	into	account	estimated forfeitures.		The	grant	date	fair	value	of	the	restricted	stock	and	the	restricted	units	is	based	on	the	closing	price	of	Entergy	Corporation common	stock	on	the	date	of	grant.		The	grant	date	fair	value	of	performance	units	is	based	on	the	probable	outcome	of	the	applicable performance	conditions,	measured	using	a	Monte	Carlo	simulation	valuation	model.		The	simulation	model	applies	a	risk-free	interest	rate and	an	expected	volatility	assumption.	 	The	risk-free	rate	 is	assumed	 to	equal	 the	yield	on	a	 three-year	 treasury	bond	on	 the	grant date.		Volatility	is	based	on	historical	volatility	for	the	36-month	period	preceding	the	grant	date.		If	the	highest	achievement	level	is attained,	the	maximum	amounts	that	will	be	received	with	respect	to	the	performance	units	granted	in	2013	are	as	follows:		Mr.	Denault, $7,378,205;	Mr.	Fisackerly,	$245,480;	Mr.	Forbes,	$1,348,185;	Mr.	Marsh,	$1,470,889;	Mr.	May,	$509,644;	Mr.	McDonald,	$245,480; Mr.	Mohl,	$1,348,716;	Ms.	Mount,	$387,600;	Ms.	Rainer,	$245,480;	Mr.	Rice,	$245,480;	and	Mr.	West,	$981,920.

(4) The	amounts	in	column	(f)	represent	the	aggregate	grant	date	fair	value	of	stock	options	granted	under	the	2011	Equity	Ownership	Plan calculated	in	accordance	with	FASB	ASC	Topic	718.		For	a	discussion	of	the	relevant	assumptions	used	in	valuing	these	awards,	see	Note 12	to	the	financial	statements.

(5) The	amounts	in	column	(g)	represent	cash	payments	made	under	the	Annual	Incentive	Plan.

(6) The	amounts	in	column	(h)	include	the	annual	actuarial	increase	in	the	present	value	of	the	Named	Executive	Officers'	benefits	under	all pension	plans	established	by	Entergy	Corporation	using	interest	rate	and	mortality	rate	assumptions	consistent	with	those	used	in	Entergy Corporation's	financial	statements	and	include	amounts	which	the	Named	Executive	Officers	may	not	currently	be	entitled	to	receive because	such	amounts	are	not	vested	(see	"2013	Pension	Benefits").		None	of	the	increase	is	attributable	to	above-market	or	preferential earnings	on	non-qualified	deferred	compensation	(see	"2013	Non-qualified	Deferred	Compensation").		For	2013,	the	aggregate	change	in the	actuarial	present	value	of	Messrs.	Fisackerly's,	May's,	and	McDonald's	pension	benefits	was	a	decrease	of	$103,400,	$80,100,	and $116,500,	respectively.

(7) The	amounts	in	column	(i)	for	2013	include	(a)	matching	contributions	by	Entergy	Corporation	under	the	Savings	Plan	to	each	of	the Named	Executive	Officers;	(b)	dividends	paid	on	restricted	stock	when	vested;	(c)	life	insurance	premiums;	(d)	tax	gross	up	payments	on club	dues	and	relocation	expenses;	and	(e)	perquisites	and	other	compensation.		The	amounts	are	listed	in	the	following	table:

| Named	Executive<br>Officer | Company<br>Contribution	–<br>Savings	Plan | Dividends	Paid<br>on	Restricted<br>Stock | Life<br>Insurance<br>Premium | Tax	Gross<br>Up<br>Payments | Perquisites	and<br>Other<br>Compensation | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Leo\tP.\tDenault | $10,710 | $15,524 | $4,002 | $— | $14,454 | $44,690 |
| Haley\tR.\tFisackerly | $10,500 | $3,324 | $971 | $3,837 | $9,426 | $28,058 |
| Jeffrey\tS.\tForbes | $10,710 | $6,316 | $7,482 | $— | $1,678 | $26,186 |
| Andrew\tS.\tMarsh | $10,710 | $3,762 | $3,040 | $9,236 | $186,915 | $213,663 |
| Phillip\tR.\tMay,\tJr. | $10,790 | $2,991 | $2,546 | $— | $220 | $16,547 |
| Hugh\tT.\tMcDonald | $10,710 | $3,433 | $6,696 | $8,537 | $18,950 | $48,326 |
| William\tM.\tMohl | $10,710 | $4,102 | $3,893 | $32,729 | $149,350 | $200,784 |
| Alyson\tM.\tMount | $11,062 | $3,209 | $282 | $— | $— | $14,553 |
| Sallie\tT.\tRainer | $11,074 | $2,547 | $3,030 | $— | $6,128 | $22,779 |
| Charles\tL.\tRice,\tJr. | $11,084 | $2,605 | $3,185 | $2,169 | $5,035 | $24,078 |
| Roderick\tK.\tWest | $10,710 | $11,079 | $2,598 | $— | $2,658 | $27,045 |

# Perquisites	and	Other	Compensation

The	amounts	set	forth	in	column	(i)	include	perquisites	and	other	personal	benefits	that	Entergy	Corporation	provides	to	the	Named Executive	Officers	as	part	of	providing	a	competitive	executive	compensation	program	and	for	employee	retention.	In	2013,	the	Named	Executive Officers	were	offered:	corporate	aircraft	usage,	relocation	assistance,	annual	physical	exams	and	event	tickets.	Certain	of	the	Named	Executive Officers,	who	are	not	members	of	the	Office	of	the	Chief	Executive,	were	provided	with	club	dues	and	tax	gross	up	payments	on	some	perquisites. The	following	perquisites	and	other	compensation	were	provided	by	Entergy	Corporation	in	2013:

For	security	and	business	reasons,	Entergy	Corporation	permits	its	Chief	Executive	Officer	to	use	its	corporate	aircraft	for	personal	use	at the	expense	of	Entergy	Corporation.	 	The	other	Named	Executive	Officers	may	use	the	corporate	aircraft	for	personal	travel	subject	to	the approval	of	Entergy	Corporation's	Chief	Executive	Officer.		The	amounts	included	in	column	(i)	for	the	personal	use	of	corporate	aircraft,	reflect the	incremental	cost	to	Entergy	Corporation	for	use	of	the	corporate	aircraft,	determined	on	the	basis	of	the	variable	operational	costs	of	each flight,	including	fuel,	maintenance,	flight	crew	travel	expense,	catering,	communications,	and	fees,	including	flight	planning,	ground	handling,	and landing	permits.

Tickets	to	cultural	and	sporting	events	are	purchased	for	business	purposes,	and	if	not	utilized	for	business	purposes,	the	tickets	are	made available	to	the	employees,	including	the	Named	Executive	Officers,	for	personal	use.

Entergy	Corporation	also	provides	relocation	benefits	to	a	broad	base	of	employees	which	include	assistance	with	moving	expenses, purchase	 and	 sale	 of	 homes,	 and	 transportation	 of	 household	 goods.	In	 connection	 with	 their	 promotion,	 and	 in	 accordance	 with	 Entergy Corporation's	 relocation	 policies,	 Entergy	 Corporation	 paid	 $186,915	 and	 $145,279	 in	 relocation	 expenses	 for	 Mr.	 Marsh	 and	 Mr.	 Mohl, respectively,	 in	 2013.	The	relocation	assistance	amounts	reported	above	represent	the	amounts	paid	to	our	relocation	service	provider	or	the executive	officer.	None	of	the	other	perquisites	referenced	above	exceeded	$25,000	for	any	of	the	other	Named	Executive	Officers.

# 2013	Grants	of	Plan-Based	Awards

The	following	table	summarizes	award	grants	during	2013	to	the	Named	Executive	Officers.

|  |  |  | Payouts	Under	Non-Equity<br>Incentive	Plan	Awards(1) | Payouts	Under	Non-Equity<br>Incentive	Plan	Awards(1) | Incentive	Plan	Awards(2) | Payouts	under	Equity |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) |
|  |  |  |  |  |  |  |  |  | All\tOther |  |  |
|  |  |  |  |  |  |  |  | All\tOther | Option |  |  |
|  |  |  |  |  |  |  |  | Stock | Awards: | Exercise | Grant |
|  |  |  |  |  |  |  |  | Awards: | Number\tof | or\tBase | Date\tFair |
|  |  |  |  |  |  |  |  | Number | Securities | Price\tof | Value\tof |
|  |  |  |  |  |  |  |  | of\tShares | Under- | Option | Stock\tand |
| Name | Grant\nDate | Thresh-\nold | Target | Maximum | Thresh-\nold | Target | Maximum | of\tStock\nor\tUnits | lying\nOptions | Awards | Option\nAwards |
|  |  | ($) | ($) | ($) | (#) | (#) | (#) | (#) | (#) | ($/Sh) | ($) |
|  |  |  |  |  |  |  |  | (3) | (4) |  | (5) |
| Leo\tP. | 1/31/13 | — | $1,302,000 | $2,604,000 |  |  |  |  |  |  |  |
| Denault(6) | 1/31/13 |  |  |  | 9,289 | 37,156 | 74,312 |  |  |  | $2,428,516 |
|  | 2/1/13 |  |  |  | 3,434 | 13,736 | 27,472 |  |  |  | $921,823 |
|  | 2/1/13 |  |  |  | 1,535 | 6,141 | 12,282 |  |  |  | $42,250 |
|  | 1/31/13 |  |  |  |  |  |  | 6,000 |  |  | $387,600 |
|  | 1/31/13 |  |  |  |  |  |  |  | 50,000 | $64.60 | $400,000 |
| Haley\tR. | 1/31/13 | — | $118,470 | $236,940 |  |  |  |  |  |  |  |
| Fisackerly | 1/31/13 |  |  |  | 475 | 1,900 | 3,800 |  |  |  | $124,184 |
|  | 1/31/13 |  |  |  |  |  |  | 1,400 |  |  | $90,440 |
|  | 1/31/13 |  |  |  |  |  |  |  | 6,000 | $64.60 | $48,000 |
| Jeffrey\tS. | 1/31/13 | — | $385,000 | $770,000 |  |  |  |  |  |  |  |
| Forbes(6) | 1/31/13 |  |  |  | 1,868 | 7,472 | 14,944 |  |  |  | $488,370 |
|  | 1/2/13 |  |  |  | 479 | 1,917 | 3,834 |  |  |  | $128,650 |
|  | 1/2/13 |  |  |  | 260 | 1,039 | 2,078 |  |  |  | $7,148 |
|  | 1/31/13 |  |  |  |  |  |  | 2,800 |  |  | $180,880 |
|  | 1/2/13 |  |  |  |  |  |  | 8,000(7) |  |  | $518,000 |
|  | 1/31/13 |  |  |  |  |  |  |  | 22,500 | $64.60 | $180,000 |
| Andrew\tS. | 1/31/13 | — | $350,000 | $700,000 |  |  |  |  |  |  |  |
| Marsh(6) | 1/31/13 |  |  |  | 1,861 | 7,442 | 14,884 |  |  |  | $486,409 |
|  | 2/1/13 |  |  |  | 623 | 2,492 | 4,984 |  |  |  | $167,238 |
|  | 2/1/13 |  |  |  | 359 | 1,436 | 2,872 |  |  |  | $9,880 |
|  | 1/31/13 |  |  |  |  |  |  | 4,000 |  |  | $258,400 |
|  | 1/31/13 |  |  |  |  |  |  |  | 32,000 | $64.60 | $256,000 |
| Phillip\tR. | 1/31/13 | — | $132,000 | $264,000 |  |  |  |  |  |  |  |
| May,\tJr.(6) | 1/31/13 |  |  |  | 742 | 2,969 | 5,938 |  |  |  | $194,054 |
|  | 2/1/13 |  |  |  | 144 | 575 | 1,150 |  |  |  | $38,588 |
|  | 2/1/13 |  |  |  | 99 | 397 | 794 |  |  |  | $2,731 |
|  | 1/31/13 |  |  |  |  |  |  | 1,400 |  |  | $90,440 |
|  | 1/31/13 |  |  |  |  |  |  |  | 6,000 | $64.60 | $48,000 |

|  |  |  | Payouts	Under	Non-Equity<br>Incentive	Plan	Awards(1) | Payouts	Under	Non-Equity<br>Incentive	Plan	Awards(1) | Incentive	Plan	Awards(2) | Payouts	under	Equity |  |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) |
|  |  |  |  |  |  |  |  |  | All\tOther |  |  |
|  |  |  |  |  |  |  |  | All\tOther | Option |  |  |
|  |  |  |  |  |  |  |  | Stock | Awards: | Exercise | Grant |
|  |  |  |  |  |  |  |  | Awards: | Number\tof | or\tBase | Date\tFair |
|  |  |  |  |  |  |  |  | Number | Securities | Price\tof | Value\tof |
|  |  |  |  |  |  |  |  | of\tShares | Under- | Option | Stock\tand |
| Name | Grant\nDate | Thresh-\nold | Target | Maximum | Thresh-\nold | Target | Maximum | of\tStock\nor\tUnits | lying\nOptions | Awards | Option\nAwards |
|  |  | ($) | ($) | ($) | (#) | (#) | (#) | (#) | (#) | ($/Sh) | ($) |
|  |  |  |  |  |  |  |  | (3) | (4) |  | (5) |
| Hugh\tT. | 1/31/13 | — | $172,610 | $345,220 |  |  |  |  |  |  |  |
| McDonald | 1/31/13 |  |  |  | 475 | 1,900 | 3,800 |  |  |  | $124,184 |
|  | 1/31/13 |  |  |  |  |  |  | 1,400 |  |  | $90,440 |
|  | 1/31/13 |  |  |  |  |  |  |  | 6,000 | $64.60 | $48,000 |
| William\tM. | 1/31/13 | — | $392,000 | $784,000 |  |  |  |  |  |  |  |
| Mohl(6) | 1/31/13 |  |  |  | 1,868 | 7,472 | 14,944 |  |  |  | $488,370 |
|  | 2/1/13 |  |  |  | 479 | 1,917 | 3,834 |  |  |  | $128,650 |
|  | 2/1/13 |  |  |  | 260 | 1,039 | 2,078 |  |  |  | $7,148 |
|  | 1/31/13 |  |  |  |  |  |  | 4,000 |  |  | $258,400 |
|  | 1/31/13 |  |  |  |  |  |  |  | 32,000 | $64.60 | $256,000 |
| Alyson\tM. | 1/31/13 | — | $172,020 | $344,040 |  |  |  |  |  |  |  |
| Mount | 1/31/13 |  |  |  | 750 | 3,000 | 6,000 |  |  |  | $196,080 |
|  | 1/31/13 |  |  |  |  |  |  | 1,800 |  |  | $116,280 |
|  | 1/31/13 |  |  |  |  |  |  |  | 8,900 | $64.60 | $71,200 |
| Sallie\tT. | 1/31/13 | — | $116,400 | $232,800 |  |  |  |  |  |  |  |
| Rainer | 1/31/13 |  |  |  | 475 | 1,900 | 3,800 |  |  |  | $124,184 |
|  | 1/31/13 |  |  |  |  |  |  | 1,400 |  |  | $90,440 |
|  | 1/31/13 |  |  |  |  |  |  |  | 5,800 | $64.60 | $46,400 |
| Charles\tL. | 1/31/13 | — | $102,857 | $205,714 |  |  |  |  |  |  |  |
| Rice,\tJr. | 1/31/13 |  |  |  | 475 | 1,900 | 3,800 |  |  |  | $124,184 |
|  | 1/31/13 |  |  |  |  |  |  | 1,200 |  |  | $77,520 |
|  | 1/31/13 |  |  |  |  |  |  |  | 5,000 | $64.60 | $40,000 |
| Roderick\tK. | 1/31/13 | — | $428,908 | $857,816 |  |  |  |  |  |  |  |
| West | 1/31/13 |  |  |  | 1,900 | 7,600 | 15,200 |  |  |  | $496,736 |
|  | 1/31/13 |  |  |  |  |  |  | 5,000 |  |  | $323,000 |
|  | 5/1/13 |  |  |  |  |  |  | 21,000(8) |  |  | $1,499,190 |
|  | 1/31/13 |  |  |  |  |  |  |  | 40,000 | $64.60 | $320,000 |

(1) The	amounts	in	columns	(c),	(d),	and	(e)	represent	minimum,	target,	and	maximum	payment	levels	under	the	Annual	Incentive	Plan.		The actual	amounts	awarded	are	reported	in	column	(g)	of	the	Summary	Compensation	Table.

(2) Except	as	otherwise	noted	in	footnote	6,	the	amounts	in	columns	(f),	(g),	and	(h)	represent	the	minimum,	target,	and	maximum	payment levels	under	the	Long-Term	Performance	Unit	Program.		Performance	under	the	program	is	measured	by	Entergy	Corporation's	total shareholder	return	relative	 to	 the	 total	shareholder	returns	of	 the	companies	 included	 in	 the	Philadelphia	Utility	Index.	 	If	Entergy Corporation's	total	shareholder	return	is	not	at	least	25%	of	that	for	the	Philadelphia

Utility	Index,	there	is	no	payout.		Subject	to	achievement	of	performance	targets,	each	unit	will	be	converted	into	one	share	of	Entergy Corporation's	common	stock	on	the	last	day	of	the	performance	period	(December	31,	2015.)		Accrued	dividends	on	the	shares	earned will	also	be	paid	in	Entergy	Corporation	common	stock.

(3) Except	as	otherwise	noted	in	footnotes	7	and	8,	the	amounts	in	column	(i)	represent	shares	of	restricted	stock	granted	under	the	2011 Equity	Ownership	Plan.		Shares	of	restricted	stock	vest	over	a	three-year	period,	have	voting	rights	and	accrue	dividends	during	the vesting	period.

(4) The	amounts	in	column	(j)	represent	options	to	purchase	shares	of	Entergy	Corporation's	common	stock.		The	options	vest	one-third	on each	of	the	first	through	third	anniversaries	of	the	grant	date	and	have	a	ten-year	term	from	the	date	of	grant.		The	options	were	granted under	the	2011	Equity	Ownership	Plan.

(5) The	amounts	in	column	(l)	are	valued	based	on	the	aggregate	grant	date	fair	value	of	the	award	calculated	in	accordance	with	FASB	ASC Topic	718	and,	in	the	case	of	the	performance	units,	are	based	on	the	probable	outcome	of	the	applicable	performance	conditions.		See Notes	3	and	4	to	the	Summary	Compensation	Table	for	a	discussion	of	the	relevant	assumptions	used	in	calculating	the	grant	date	fair value.

(6) With	their	promotions,	Messrs.	Denault,	Forbes,	Marsh,	May	and	Mohl	received	pro-rated	performance	unit	awards	under	the	2011	– 2013	Long-Term	Performance	Unit	Program	and	2012	–	2014	Long-Term	Performance	Unit	Program.			For	the	2011	-	2013	Long-Term Performance	Program,	subject	to	achievement	of	performance	targets,	each	unit	will	be	converted	into	the	cash	equivalent	of	one	share	of Entergy	Corporation's	common	stock	on	the	last	day	of	the	performance	period	(December	31,	2013).	For	the	2012	-	2014	Long-Term Performance	Program,	subject	to	achievement	of	performance	targets,	each	unit	will	be	converted	into	one	share	of	Entergy	Corporation's common	stock	on	the	last	day	of	the	performance	period	(December	31,	2014).

(7) In	January	2013,	Mr.	Forbes	was	awarded	8,000	restricted	units	under	the	2011	Equity	Ownership	Plan.		The	restricted	units	will	vest	on January	2,	2016.

# 2013	Outstanding	Equity	Awards	at	Fiscal	Year-End

The	following	table	summarizes,	for	each	Named	Executive	Officer,	unexercised	options,	restricted	stock	that	has	not	vested,	and	equity	incentive plan	awards	outstanding	as	of	the	end	of	2013.

| Name | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive<br>Plan<br>Awards:<br>Number<br>of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number<br>of	Shares<br>or	Units<br>of	Stock<br>That	Have<br>Not<br>Vested | Market<br>Value	of<br>Shares	or<br>Units	of<br>Stock<br>That	Have<br>Not	Vested | Incentive<br>Plan<br>Awards:<br>Number	of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>	Rights<br>That	Have<br>Not	Vested | Plan	Awards:<br>Market	or<br>Payout	Value<br>of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>Rights<br>That	Have<br>Not	Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Leo\tP. | — | 50,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Denault | 10,000 | 20,000(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 16,666 | 8,334(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 50,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 45,000 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 50,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 60,000 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 50,000 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 35,000 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  |  |  |  |  |  |  |  | 9,289(4) | $587,715 |
|  |  |  |  |  |  |  |  | 4,784(5) | $302,684 |
|  |  |  |  |  |  | 6,000(6) | $379,620 |  |  |
|  |  |  |  |  |  | 2,667(7) | $168,741 |  |  |
|  |  |  |  |  |  | 1,667(8) | $105,471 |  |  |
| Haley\tR. | — | 6,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Fisackerly | 1,533 | 3,067(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 1,933 | 967(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 9,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 3,800 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 5,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 2,500 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 1,000 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  |  |  |  |  |  |  |  | 475(4) | $30,053 |
|  |  |  |  |  |  |  |  | 375(5) | $23,726 |
|  |  |  |  |  |  | 1,400(6) | $88,578 |  |  |
|  |  |  |  |  |  | 800(7) | $50,616 |  |  |
|  |  |  |  |  |  | 300(8) | $18,981 |  |  |

| Name | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive<br>Plan<br>Awards:<br>Number<br>of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number<br>of	Shares<br>or	Units<br>of	Stock<br>That	Have<br>Not<br>Vested | Market<br>Value	of<br>Shares	or<br>Units	of<br>Stock<br>That	Have<br>Not	Vested | Incentive<br>Plan<br>Awards:<br>Number	of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>	Rights<br>That	Have<br>Not	Vested | Plan	Awards:<br>Market	or<br>Payout	Value<br>of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>Rights<br>That	Have<br>Not	Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Jeffrey\tS. | — | 22,500(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Forbes | 4,166 | 8,334(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 6,666 | 3,334(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 15,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 11,000 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 12,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 14,800 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 9,500 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 10,000 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,868(4) | $118,188 |
|  |  |  |  |  |  |  |  | 1,079(5) | $68,268 |
|  |  |  |  |  |  | 2,800(6) | $177,156 |  |  |
|  |  |  |  |  |  | 1,400(7) | $88,578 |  |  |
|  |  |  |  |  |  | 600(8) | $37,962 |  |  |
|  |  |  |  |  |  | 8,000(9) | $506,160 |  |  |
| Andrew\tS. | — | 32,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Marsh | 3,333 | 6,667(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 2,666 | 1,334(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 9,100 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 8,000 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 10,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 5,000 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 5,500 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 4,000 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  | 3,000 | — |  | $58.60 | 3/2/2014 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,861(4) | $117,745 |
|  |  |  |  |  |  |  |  | 998(5) | $63,143 |
|  |  |  |  |  |  | 4,000(6) | $253,080 |  |  |
|  |  |  |  |  |  | 934(7) | $59,094 |  |  |
|  |  |  |  |  |  | 334(8) | $21,132 |  |  |

| Name | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive<br>Plan<br>Awards:<br>Number<br>of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number<br>of	Shares<br>or	Units<br>of	Stock<br>That	Have<br>Not<br>Vested | Market<br>Value	of<br>Shares	or<br>Units	of<br>Stock<br>That	Have<br>Not	Vested | Incentive<br>Plan<br>Awards:<br>Number	of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>	Rights<br>That	Have<br>Not	Vested | Plan	Awards:<br>Market	or<br>Payout	Value<br>of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>Rights<br>That	Have<br>Not	Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Phillip\tR. | — | 6,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| May,\tJr. | 1,533 | 3,067(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 1,933 | 967(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 6,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 4,700 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 6,500 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  | 1,400(6) | $88,578 |  |  |
|  |  |  |  |  |  | 800(7) | $50,616 |  |  |
|  |  |  |  |  |  | 250(8) | $15,818 |  |  |
| Hugh\tT. | — | 6,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| McDonald | 1,533 | 3,067(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 1,933 | 967(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 4,600 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 4,500 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 7,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 12,000 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 7,500 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 10,000 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  |  |  |  |  |  |  |  | 475(4) | $30,053 |
|  |  |  |  |  |  |  |  | 375(5) | $23,726 |
|  |  |  |  |  |  | 1,400(6) | $88,578 |  |  |
|  |  |  |  |  |  | 867(7) | $54,855 |  |  |
|  |  |  |  |  |  | 300(8) | $18,981 |  |  |

| Name | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive<br>Plan<br>Awards:<br>Number<br>of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number<br>of	Shares<br>or	Units<br>of	Stock<br>That	Have<br>Not<br>Vested | Market<br>Value	of<br>Shares	or<br>Units	of<br>Stock<br>That	Have<br>Not	Vested | Incentive<br>Plan<br>Awards:<br>Number	of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>	Rights<br>That	Have<br>Not	Vested | Plan	Awards:<br>Market	or<br>Payout	Value<br>of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>Rights<br>That	Have<br>Not	Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| William | — | 32,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| M.\tMohl | 2,466 | 4,934(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 4,066 | 2,034(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 9,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 7,500 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 9,300 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 3,500 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 5,000 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 3,000 | — |  | $69.47 | 1/27/2015 |  |  | 1,868(4) | $118,188 |
|  |  |  |  |  |  |  |  | 1,079(5) | $68,268 |
|  |  |  |  |  |  | 4,000(6) | $253,080 |  |  |
|  |  |  |  |  |  | 1,000(7) | $63,270 |  |  |
|  |  |  |  |  |  | 367(8) | $23,220 |  |  |
| Alyson\tM. | — | 8,900(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Mount | 6,500 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 4,500 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 4,500 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 5,400 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 5,000 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 4,000 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  | 1,500 | — |  | $58.60 | 3/2/2014 |  |  |  |  |
|  |  |  |  |  |  |  |  | 750(4) | $47,453 |
|  |  |  |  |  |  |  |  | 517(5) | $32,711 |
|  |  |  |  |  |  | 1,800(6) | $113,886 |  |  |
|  |  |  |  |  |  | 1,000(7) | $63,270 |  |  |
|  |  |  |  |  |  | 234(8) | $14,805 |  |  |

| Name | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number<br>	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive<br>Plan<br>Awards:<br>Number<br>of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number<br>of	Shares<br>or	Units<br>of	Stock<br>That	Have<br>Not<br>Vested | Market<br>Value	of<br>Shares	or<br>Units	of<br>Stock<br>That	Have<br>Not	Vested | Incentive<br>Plan<br>Awards:<br>Number	of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>	Rights<br>That	Have<br>Not	Vested | Plan	Awards:<br>Market	or<br>Payout	Value<br>of<br>Unearned<br>Shares,<br>Units	or<br>Other<br>Rights<br>That	Have<br>Not	Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Sallie\tT. | — | 5,800(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Rainer | 2,500 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 1,200 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 2,300 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 2,000 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 2,500 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 2,500 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  |  |  |  |  |  |  |  | 475(4) | $30,053 |
|  |  |  |  |  |  |  |  | 323(5) | $20,436 |
|  |  |  |  |  |  | 1,400(6) | $88,578 |  |  |
|  |  |  |  |  |  | 867(7) | $54,855 |  |  |
|  |  |  |  |  |  | 167(8) | $10,566 |  |  |
| Charles\nL. | — | 5,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| Rice,\tJr. | 1,533 | 3,067(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 1,933 | 967(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  |  |  |  |  |  |  |  | 475(4) | $30,053 |
|  |  |  |  |  |  |  |  | 375(5) | $23,726 |
|  |  |  |  |  |  | 1,200(6) | $75,924 |  |  |
|  |  |  |  |  |  | 700(7) | $44,289 |  |  |
|  |  |  |  |  |  | 217(8) | $13,730 |  |  |
| Roderick | — | 40,000(1) |  | $64.60 | 1/31/2023 |  |  |  |  |
| K.\tWest | 10,000 | 20,000(2) |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 11,333 | 5,667(3) |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 7,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 5,000 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 8,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  | 12,000 | — |  | $91.82 | 1/25/2017 |  |  |  |  |
|  | 1,334 | — |  | $68.89 | 1/26/2016 |  |  |  |  |
|  | 667 | — |  | $69.47 | 1/27/2015 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,900(4) | $120,213 |
|  |  |  |  |  |  |  |  | 1,350(5) | $85,415 |
|  |  |  |  |  |  | 5,000(6) | $316,350 |  |  |
|  |  |  |  |  |  | 2,667(7) | $168,741 |  |  |
|  |  |  |  |  |  | 1,000(8) | $63,270 |  |  |
|  |  |  |  |  |  | 21,000(10) | $1,328,670 |  |  |

(3) The	remaining	unexercisable	options	vested	on	1/27/2014.

(4) Consists	of	performance	units	that	will	vest	on	December	31,	2015	based	on	Entergy	Corporation's	total	shareholder	return	performance over	the	2013-2015	performance	period,	as	described	under	"Executive	Compensation	Elements	-	Long-Term	Incentive	Compensation	- Performance	Unit	Program"	in	Compensation	Discussion	and	Analysis.

(5) Consists	of	performance	units	that	will	vest	on	December	31,	2014	based	on	Entergy	Corporation's	total	shareholder	return	performance over	the	2012	–	2014	performance	period.

(7) Consists	of	shares	of	restricted	stock	that	vested	or	will	vest	as	follows:		1/2	of	the	shares	of	restricted	stock	granted	vest	on	each	of 1/26/2014	and	1/26/2015.

(8) Consists	of	shares	of	restricted	stock	that	vested	on	1/27/2014.

(9) Consists	of	restricted	units	granted	under	the	2011	Equity	Ownership	Plan	which	will	vest	on	January	2,	2016.

(10) Consists	of	restricted	units	granted	under	the	2011	Equity	Ownership	Plan	which	will	vest	on	May	1,	2018.

# 2013	Option	Exercises	and	Stock	Vested

The	following	table	provides	information	concerning	each	exercise	of	stock	options	and	each	vesting	of	stock	during	2013	for	the	Named Executive	Officers.

|  | Options	Awards |  | Stock	Awards | Stock	Awards |
| :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) |
| Name | Number\tof\nShares\nAcquired\non\tExercise | Value\nRealized\non\tExercise | Number\tof\nShares\nAcquired\non\tVesting | Value\nRealized\non\tVesting |
|  | (#) | ($) | (#) | ($) |
| Leo\tP.\tDenault | 34,995 | $117,552 | 11,241(1) | $725,593 |
| Haley\tR.\tFisackerly | — | $— | 752 | $48,439 |
| Jeffrey\tS.\tForbes | — | $— | 1,398 | $90,101 |
| Andrew\tS.\tMarsh | — | $— | 2,525(2) | $171,484 |
| Phillip\tR.\tMay,\tJr. | 7,000 | $138,454 | 696 | $44,883 |
| Hugh\tT.\tMcDonald | — | $— | 786 | $50,675 |
| William\tM.\tMohl | — | $— | 931 | $59,980 |
| Alyson\tM.\tMount | — | $— | 783 | $50,451 |
| Sallie\tT.\tRainer | 1,900 | $25,460 | 640 | $41,217 |
| Charles\tL.\tRice,\tJr. | — | $— | 607 | $39,149 |
| Roderick\tK.\tWest | — | $— | 17,505(3) | $1,229,890 |

(1) Includes	the	January	25,	2013	cash	settlement	of	8,000	restricted	units	granted	under	the	2007	Equity	Ownership	Plan.

(2) Includes	the	June	30,	2013	cash	settlement	of	1,668	restricted	units	granted	under	the	2007	Equity	Ownership	Plan.

(3) Includes	the	April	30,	2013	cash	settlement	of	15,000	restricted	units	granted	under	the	2007	Equity	Ownership	Plan.

# 2013	Pension	Benefits

The	following	table	shows	the	present	value	as	of	December	31,	2013,	of	accumulated	benefits	payable	to	each	of	the	Named	Executive	Officers, including	the	number	of	years	of	service	credited	to	each	Named	Executive	Officer,	under	the	retirement	plans	sponsored	by	Entergy	Corporation, determined	using	 interest	rate	and	mortality	rate	assumptions	set	forth	 in	Note	11	 to	 the	financial	statements.	 	Information	regarding	 these retirement	plans	is	included	in	Compensation	Discussion	&	Analysis	under	the	heading,	"Benefits,	Perquisites,	Agreements,	and	Post-Retirement Plans	-	Pension	Plan,	Pension	Equalization	Plan,	and	System	Executive	Retirement	Plan."		In	addition,	this	section	includes	information	regarding early	retirement	options	under	the	plans.

| Name | Plan<br>Name | Number<br>of	Years<br>Credited<br>Service | Present<br>Value	of<br>Accumulated<br>Benefit | Payments<br>During<br>	2013 |
| :--- | :--- | :--- | :--- | :--- |
| Leo\tP.\tDenault\t(1) | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 29.83 | $6,116,800 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 14.83 | $390,600 | $— |
| Haley\tR.\tFisackerly | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 18.08 | $727,200 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 18.08 | $373,700 | $— |
|  | Non-qualified\tSystem |  |  |  |
| Jeffrey\tS.\tForbes | \t\t\tExecutive\tRetirement\tPlan | 10.41 | $1,797,900 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 10.41 | $323,200 | $— |
|  | Non-qualified\tSystem |  |  |  |
| Andrew\tS.\tMarsh | \t\t\tExecutive\tRetirement\tPlan | 15.37 | $994,700 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 15.37 | $230,700 | $— |
| Phillip\tR.\tMay,\tJr. | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 27.56 | $1,048,100 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 27.56 | $640,600 | $— |
| Hugh\tT.\tMcDonald\t(2) | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 31.93 | $1,503,300 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 30.44 | $853,200 | $— |
| William\tM.\tMohl | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 11.44 | $1,485,300 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 11.44 | $303,500 | $— |
| Alyson\tM.\tMount | Non-qualified\tSystem |  |  |  |
|  | \t\t\tExecutive\tRetirement\tPlan | 11.35 | $438,700 | $— |
|  | Qualified\tdefined |  |  |  |
|  | \t\t\tbenefit\tplan | 11.35 | $182,600 | $— |

| Plan<br>Name | Number<br>of	Years<br>Credited<br>Service | Present<br>Value	of<br>Accumulated<br>Benefit | Payments<br>During<br>	2013 |
| :--- | :--- | :--- | :--- |
| Non-qualified\tSystem\n\t\t\tExecutive\tRetirement\tPlan | 29.38 | $601,500 | $— |
| Qualified\tdefined\n\t\t\tbenefit\tplan | 27.52 | $694,400 | $— |
| Non-qualified\tSystem\n\t\t\tExecutive\tRetirement\tPlan | 4.47 | $186,700 | $— |
| Qualified\tdefined\n\t\t\tbenefit\tplan | 4.47 | $91,200 | $— |
| Non-qualified\tSystem\n\t\t\tExecutive\tRetirement\tPlan | 14.75 | $2,177,400 | $— |
| Qualified\tdefined\n\t\t\tbenefit\tplan | 14.75 | $258,400 | $— |

(1) During	2006,	Mr.	Denault	entered	into	an	agreement	granting	an	additional	15	years	of	service	under	the	non-qualified	System	Executive Retirement	Plan	if	he	continues	to	work	for	an	Entergy	System	company	employer	until	age	55.		The	additional	15	years	of	service increases	the	present	value	of	his	benefit	by	$1,595,600.

(2) Service	under	the	non-qualified	System	Executive	Retirement	Plan	is	granted	from	date	of	hire.		Qualified	plan	benefit	service	is	granted from	the	later	of	date	of	hire	or	plan	participation	date.

# Qualified	Retirement	Benefits

The	qualified	retirement	plan	is	a	funded,	tax-qualified,	noncontributory	defined	benefit	pension	plan	that	provides	benefits	to	most	of	the non-bargaining	unit	employees	of	Entergy	System	Companies.		All	Named	Executive	Officers	are	participants	in	this	plan.		Benefits	under	the tax-qualified	pension	plan	are	calculated	as	an	annuity	payable	at	age	65	and	generally	equal	to	1.5%	of	a	participant's	Final	Average	Monthly Earnings	(FAME)	multiplied	by	years	of	service	(not	to	exceed	40).		"Eligible	Earnings"	for	purposes	of	calculating	FAME	generally	includes	the employee's	base	salary	and	eligible	annual	incentive	award	and	excludes	all	other	bonuses.	FAME	is	calculated	using	the	employee's	average monthly	Earnings	for	 the	60	consecutive	months	 in	which	 the	employee's	earnings	were	highest	during	 the	120	month	period	 immediately preceding	the	employee's	retirement	and	includes	up	to	5	annual	bonuses	paid	during	the	60	month	period.		Benefits	under	the	tax-qualified	plan are	payable	monthly	after	attainment	of	at	least	age	55	and	after	separation	from	an	Entergy	System	company.		The	amount	of	annual	earnings	that may	be	considered	in	calculating	benefits	under	the	tax-qualified	pension	plan	is	limited	by	federal	law.		Participants	are	100%	vested	in	their benefit	upon	completing	5	years	of	vesting	service	or	upon	attainment	of	age	65	while	an	active	employee	participant	in	the	plan.		Contributions	to the	pension	plan	are	made	entirely	by	Entergy	Corporation	and	are	paid	into	a	trust	fund	from	which	the	benefits	of	participants	will	be	paid.

Normal	retirement	under	the	plan	is	age	65.		Employees	who	terminate	employment	prior	to	age	55	may	receive	a	reduced	deferred	vested retirement	benefit	commencing	as	early	as	age	55	that	is	based	on	the	normal	retirement	benefit	(reduced	by	7%	per	year	for	the	first	5	years commencement	precedes	age	65,	and	reduced	by	6%	for	each	additional	year	commencement	precedes	age	65).	Employees	who	are	at	least	age 55	with	10	years	of	vesting	service	upon	termination	of	employment	are	entitled	to	a	subsidized	early	retirement	benefit	beginning	as	early	as	age 55.		The	subsidized	early	retirement	benefit	is	equal	to	the	normal	retirement	benefit	reduced	by	2%	per	year	for	each	year	that	early	retirement precedes	age	65.

Mr.	Forbes	and	Mr.	McDonald	are	eligible	for	subsidized	early	retirement	benefits.

# Non-qualified	Retirement	Benefits

The	Named	Executive	Officers	are	eligible	to	participate	in	certain	non-qualified	retirement	benefit	plans	that	provide	retirement	income, including	the	Pension	Equalization	Plan	and	the	System	Executive	Retirement	Plan.		Each	of	these	plans	is	an	unfunded	non-qualified	defined benefit	pension	plan	that	provides	benefits	to	key	management	employees.		In	these	plans,	as	described	below,	an	executive	is	typically	enrolled	in one	or	more	plans	but	only	paid	the	amount	due	under	the	plan	that	provides	the	highest	benefit.		In	general,	upon	disability,	participants	in	the Pension	Equalization	Plan	and	the	System	Executive	Retirement	Plan	remain	eligible	for	continued	service	credits	until	the	earlier	of	recovery	or retirement	 eligibility.	 	 Generally,	 spouses	 of	 participants	 who	 die	 before	 commencement	 of	 benefits	 may	 be	 eligible	 for	 a	 portion	 of	 the participant's	accrued	benefit.

All	of	the	Named	Executive	Officers	participate	in	both	the	Pension	Equalization	Plan	and	the	System	Executive	Retirement	Plan.

# The	Pension	Equalization	Plan

The	Pension	Equalization	Plan	is	a	non-qualified	unfunded	restoration	retirement	plan	that	provides	for	the	payment	to	participants	from Entergy's	general	assets	a	single	lump	sum	cash	distribution	upon	separation	from	service	generally	equal	to	the	actuarial	present	value	of	the difference	between	the	amount	that	would	have	been	payable	as	an	annuity	under	the	tax-qualified	pension	plan,	but	for	Internal	Revenue	Code limitations	on	pension	benefits	and	earnings	that	may	be	considered	in	calculating	tax-qualified	pension	benefits,	and	the	amount	actually	payable as	an	annuity	under	the	tax-qualified	pension	plan.	The	Pension	Equalization	Plan	also	takes	into	account	as	"Eligible	Earnings"	any	incentive awards	paid	under	the	Annual	Incentive	Plan	and	includes	supplemental	credited	service	granted	to	a	Participant	in	calculating	his	or	her	benefit. Participants	receive	their	Pension	Equalization	Plan	benefit	in	the	form	of	a	single	sum	cash	distribution.	The	benefits	under	this	plan	are	offset	by benefits	 payable	 from	 the	 qualified	 retirement	 plan	 and	 may	 be	 offset	 by	 prior	 employer	 benefits.	 The	 Pension	 Equalization	 Plan	 benefit attributable	to	supplemental	credited	service	is	not	vested	until	age	65.	Effective	July	1,	2014,	new	participants	in	the	Pension	Equalization	Plan will	not	be	provided	with	supplemental	credited	service.	Subject	to	the	prior	written	consent	of	the	Entergy	System	Company	employer	(which consent	is	deemed	given	if	the	participant's	employment	is	terminated	within	twenty-four	months	following	a	change	in	control	by	the	employer without	"Cause"	or	by	the	participant	for	"Good	Reason"	as	defined	in	the	plan),	an	employee	who	terminates	employment	prior	to	age	65	may	be vested	in	his	or	her	benefit,	with	payment	of	the	lump	sum	benefit	generally	at	separation	from	service	unless	delayed	six	months	under	Internal Revenue	Code	Section	409A.	Benefits	payable	prior	to	age	65	are	subject	to	the	same	reductions	as	qualified	plan	benefits.

# The	System	Executive	Retirement	Plan

The	System	Executive	Retirement	Plan	is	a	non-qualified	supplemental	retirement	plan	that	provides	for	a	single	sum	payment	at	age	65. 	Like	the	Pension	Equalization	Plan,	the	System	Executive	Retirement	Plan	is	designed	to	provide	for	the	payment	to	participants	from	Entergy's general	assets	of	a	single-sum	cash	distribution	upon	separation	from	service.		The	single-sum	benefit	is	generally	equal	to	the	actuarial	present value	 of	 a	 specified	 percentage	 of	 the	 participant's	 "Final	Average	 Monthly	 Compensation"	 (which	 is	 generally	 1/36th	 of	 the	 sum	 of	 the participant's	annual	rate	of	base	salary	and	Annual	Incentive	Plan	award	for	the	3	highest	years	during	the	last	10	years	preceding	termination	of employment),	after	first	being	reduced	by	the	value	of	the	participant's	tax-qualified	Pension	Plan	benefit	and	typically	any	prior	employer	pension benefit	available	to	the	participant.

While	the	System	Executive	Retirement	Plan	has	a	replacement	ratio	schedule	from	one	year	of	service	to	the	maximum	of	30	years	of service,	the	table	below	offers	a	sample	ratio	at	20	and	30	years	of	service.

| Years	of<br>Service | Executives	at<br>Management<br>Level	1 | Executives	at	Management	Levels	2<br>and	3	–	includes	the	remaining	4<br>Named	Executive	Officers | Executives	at<br>Management<br>Level	4 |
| :--- | :--- | :--- | :--- |
| 20\tYears | 55.0% | 50.0% | 45.0% |
| 30\tyears | 65.0% | 60.0% | 55.0% |

The	System	Executive	Retirement	Plan	benefit	is	not	vested	until	age	65.	Subject	to	the	prior	written	consent	of	the	Entergy	System company	employer,	an	employee	who	terminates	his	or	her	employment	prior	to	age	65	may	be	vested	in	the	System	Executive	Retirement	Plan benefit,	with	payment	of	the	lump	sum	benefit	generally	at	separation	from	service	unless	delayed	six	months	under	Code	Section	409A.	Benefits payable	prior	to	age	65	are	subject	to	the	same	reductions	as	qualified	plan	benefits.	Further,	in	the	event	of	a	change	in	control,	participants whose	employment	is	terminated	without	"Cause"	or	by	the	employee	for	"Good	Reason,"	as	defined	in	the	Plan	are	also	eligible	for	a	subsidized lump	sum	benefit	payment,	even	if	they	do	not	currently	meet	the	age	or	service	requirements	for	early	retirement	under	that	plan	or	have company	permission	to	separate	from	employment.	Such	lump	sum	benefit	is	payable	generally	at	separation	from	service	unless	delayed	6 months	under	Code	Section	409A.

# 2013	Non-qualified	Deferred	Compensation

The	Executive	Deferred	Compensation	Plan,	the	2007	Equity	Ownership	Plan	and	the	2011	Equity	Ownership	Plan	allow	for	the	deferral of	compensation	for	the	Named	Executive	Officers.	Entergy	Corporation	does	not	"match"	amounts	that	are	deferred	by	employees	pursuant	to the	Executive	Deferred	Compensation	Plan	or	the	equity	plans.		With	the	exception	of	allowing	for	the	deferral	of	federal	and	state	taxes,	Entergy Corporation	provides	no	additional	benefit	to	the	Named	Executive	Officer	for	deferring	any	of	the	compensation	received	under	these	plans.		Any increase	in	value	of	the	deferred	amounts	results	solely	from	the	increase	in	value	of	the	deemed	investment	options	selected	by	the	Named Executive	Officer	(phantom	stock	of	Entergy	Corporation	or	mutual	funds	available	under	the	Savings	Plan).		As	of	December	31,	2013,	none	of the	Named	Executive	Officers	had	deferred	compensation	balances	under	the	equity	ownership	plans	or	the	Executive	Deferred	Compensation Plan.

As	of	December	31,	2013,	Mr.	Forbes	and	Mr.	May	had	deferred	account	balances	under	a	frozen	Defined	Contribution	Restoration Plan.		These	amounts	are	deemed	invested,	as	chosen	by	the	participant,	in	certain	T.	Rowe	Price	investment	funds	that	are	also	available	to participants	under	the	Savings	Plan.		The	Defined	Contribution	Restoration	Plan,	until	it	was	frozen	in	2005,	credited	eligible	employees'	deferral accounts	with	employer	contributions	to	the	extent	contributions	under	the	qualified	savings	plan	in	which	the	employee	participated	were	subject to	limitations	imposed	by	the	Internal	Revenue	Code.

All	deferrals	are	credited	to	the	applicable	Entergy	System	company	employer's	non-funded	liability	account.		Depending	on	the	plan under	which	the	deferral	is	made,	the	Named	Executive	Officers	may	elect	investment	in	either	phantom	Entergy	Corporation	common	stock	or one	or	more	of	several	investment	options	available	under	the	Savings	Plan.		Within	limitations	of	the	program,	participating	Named	Executive Officers	may	move	funds	from	one	deemed	investment	option	to	another.		The	participating	Named	Executive	Officers	do	not	have	the	ability	to withdraw	funds	from	 the	deemed	 investment	accounts	except	within	 the	 terms	provided	 in	 their	deferral	elections.	 	Within	 the	 limitations prescribed	by	law	as	well	as	the	plan,	participating	Named	Executive	Officers	with	deferrals	under	the	Executive	Deferred	Compensation	Plan and/or	the	equity	plans	have	the	option	to	make	a	successive	deferral	of	these	funds.			Assuming	a	Named	Executive	Officer	does	not	elect	a successive	deferral,	the	Entergy	System	company	employer	of	the	participant	is	obligated	to	pay	the	amount	credited	to	the	participant's	account at	the	earlier	of	deferral	receipt	date	or	separation	from	service.		These	payments	are	paid	out	of	the	general	assets	of	the	employer	and	are	payable in	a	lump	sum.

# Defined	Contribution	Restoration	Plan

| Name<br>(a) | Executive<br>Contributions	in<br>	2013<br>(b) | Registrant<br>Contributions	in<br>2013<br>(c) | Aggregate<br>Earnings	in<br>2013	(1)<br>(d) | Aggregate<br>Withdrawals/<br>Distributions<br>(e) | Aggregate<br>Balance	at<br>December	31,<br>2013<br>(f) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Jeffrey\tS.\tForbes | $— | $— | $160 | $— | $3,716 |
| Phillip\tR.\tMay,\tJr. | $— | $— | $215 | $— | $1,362 |

(1) Amounts	in	this	column	are	not	included	in	the	Summary	Compensation	Table.

# 2013	Potential	Payments	upon	Termination	or	Change	in	Control

Entergy	Corporation	has	plans	and	other	arrangements	that	provide	compensation	to	a	Named	Executive	Officer	if	his	or	her	employment is	terminated	under	specified	conditions,	including	following	a	change	in	control	of	Entergy	Corporation.		In	addition,	Entergy	Corporation	has entered	into	individual	retention	agreements	with	Mr.	Denault	and	Mr.	Mohl.

The	tables	below	reflect	the	amount	of	compensation	each	of	the	Named	Executive	Officers	would	have	received	if	his	or	her	employment with	an	Entergy	System	company	had	been	terminated	under	various	scenarios	as	of	December	31,	2013.		For	purposes	of	these	tables,	the assumed	stock	price	was	$63.27,	the	closing	market	price	on	that	date.

# Leo	P.	Denault

# Chairman	and	Chief	Executive	Officer

The	following	 table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	 the	Chairman	and	Chief Executive	Officer	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of	December	31, 2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon | Voluntary | For | Reason\tor\tNot |  |  |  | Change\tin | Change\tin |
| Termination(1) | Resignation | Cause | for\tCause | Retirement(8) | Disability | Death | Control | Control |
| Severance\tPayment(2) | — | — | $5,515,055 | — | — | — | — | $5,515,055 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | $1,417,248 | — | $1,417,248 | $1,417,248 | — | $1,417,248 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | $1,417,248 | — | $1,417,248 | $1,417,248 | — | $1,417,248 |
| Unvested\tStock\tOptions(4) | — | — | $— | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | $707,921 | — | $707,921 | $707,921 | — | $707,921 |
| COBRA\tBenefits(6) | — | — | $25,614 | — | — | — | — | — |
| Medical\tand\tDental\tBenefits(7) | — | — | — | — | — | — | — | $25,614 |
| 280G\tTax\tGross-up(9) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	Mr.	Denault	also	would	have	been	entitled	to	receive	his	vested	pension	benefits.	If Mr.	Denault's	employment	were	terminated	under	certain	conditions	relating	to	a	change	in	control,	he	would	also	be	eligible	for	early retirement	benefits.	For	a	description	of	these	benefits,	see	"2013	Pension	Benefits."	In	addition,	Mr.	Denault	is	subject	to	the	following provisions:

Retention	Agreement.		Mr.	Denault's	retention	agreement	provides	that,	unless	his	employment	is	terminated	for	cause,	he	will	be granted	an	additional	15	years	of	service	under	the	System	Executive	Retirement	Plan	if	he	continues	to	work	for	an	Entergy	System company	employer	until	age	55.	Because	Mr.	Denault	had	not	reached	age	55	as	of	December	31,	2013,	he	is	only	entitled	to	this supplemental	credited	service	and	System	Executive	Retirement	Plan	supplemental	benefits	in	the	event	of	his	death	or	disability.

System	Executive	Retirement	Plan.		If	Mr.	Denault's	employment	were	terminated	for	cause,	he	would	forfeit	his	benefit	under	the System	Executive	Retirement	Plan.	In	the	event	of	a	termination	related	to	a	change	in	control,	pursuant	to	the	terms	of	the	System Executive	Retirement	Plan,	Mr.	Denault	would	be	eligible	for	subsidized	retirement	(but	not	the	additional	15	years	of	service)	upon his	separation	of	service	even	if	he	does	not	then	meet	the	age	or	service	requirements	for	early	retirement	under	the	System Executive	Retirement	Plan	or	have	company	permission	to	separate	from	employment.

(2) In	the	event	of	a	termination	(not	due	to	death	or	disability)	by	Mr.	Denault	for	good	reason	or	by	Entergy	Corporation	not	for	cause (regardless	of	whether	there	is	a	change	in	control),	Mr.	Denault	would	be	entitled	to	receive,	pursuant	to	his

retention	agreement,	a	lump	sum	severance	payment	equal	to	the	product	of	2.99	times	the	sum	of	(a)	his	annual	base	salary	as	in	effect	at any	 time	 within	 one	 year	 prior	 to	 the	 effective	 date	 of	 the	 retention	 agreement	 or,	 if	 higher,	 immediately	 prior	 to	 a	 circumstance constituting	good	reason	plus	(b)	the	greater	of	(i)	his	actual	annual	incentive	award	under	the	Annual	Incentive	Plan	for	the	calendar	year immediately	preceding	the	calendar	year	in	which	Mr.	Denault's	termination	date	occurs	or	(ii)	Mr.	Denault's	Annual	Incentive	Plan target	award	for	the	calendar	year	in	which	the	effective	date	of	the	retention	agreement	occurred.	For	purposes	of	this	table,	we	have calculated	the	award	using	a	base	salary	of	$1,085,000	and	target	award	of	70%.

(3) In	the	event	of	a	termination	due	to	death	or	disability,	by	Mr.	Denault	for	good	reason,	or	by	Entergy	Corporation	not	for	cause	(in	all cases,	regardless	of	whether	there	is	a	change	in	control),	Mr.	Denault	would	have	forfeited	his	performance	units	for	all	open	performance periods	and	would	have	been	entitled	to	receive	a	single-lump	sum	severance	payment	pursuant	to	his	retention	agreement	that	would	not be	based	on	any	outstanding	performance	periods.	The	payment	would	be	calculated	using	the	average	annual	number	of	performance units	he	would	have	been	entitled	to	receive	under	the	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	Denault's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009- 2011	Performance	Unit	Program	(22,500	units)	and	the	2010-2012	Performance	Unit	Program	(22,300	units).	This	average	number	of units	(22,400	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of $1,417,248	for	the	forfeited	performance	units.

(4) In	the	event	of	his	death,	disability,	termination	by	Mr.	Denault	for	good	reason	or	by	Entergy	Corporation	not	for	cause	(regardless	of whether	there	is	a	change	in	control),	all	of	Mr.	Denault's	unvested	stock	options	would	immediately	vest.	In	addition,	he	would	be entitled	to	exercise	any	unexercised	options	during	a	ten-year	term	extending	from	the	grant	date	of	the	options.	For	purposes	of	this	table, we	assumed	that	Mr.	Denault	exercised	his	options	immediately	upon	vesting	and	received	proceeds	equal	to	the	difference	between	the closing	price	of	common	stock	on	December	31,	2013,	and	the	exercise	price	of	each	option	share.	As	of	December	31,	2013,	the	closing stock	price	for	Mr.	Denault's	unvested	options	fell	below	 the	exercise	prices	and	accordingly	are	considered	"underwater"	and	are excluded	from	the	table.

(5) In	the	event	of	his	death,	disability,	termination	by	Mr.	Denault	for	good	reason	or	by	Entergy	Corporation	not	for	cause	(regardless	of whether	there	is	a	change	in	control),	all	of	Mr.	Denault's	unvested	restricted	stock	would	immediately	vest.

(6) Pursuant	to	his	retention	agreement,	in	the	event	of	a	termination	by	Mr.	Denault	for	good	reason	or	by	Entergy	Corporation	not	for	cause, Mr.	Denault	would	be	eligible	to	receive	company-subsidized	COBRA	benefits	for	18	months.

(7) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Denault	would	be eligible	to	receive	company-subsidized	medical	and	dental	benefits	for	18	months.

(8) As	of	December	31,	2013,	Mr.	Denault	is	not	eligible	for	retirement.

(9) In	December	of	2010,	Mr.	Denault	voluntarily	agreed	to	amend	his	retention	agreement	to	eliminate	excise	tax	gross-up	payments.

Under	the	terms	of	Mr.	Denault's	retention	agreement,	Entergy	Corporation	may	terminate	his	employment	for	cause	upon	Mr.	Denault's:

•continuing	failure	to	substantially	perform	his	duties	(other	than	because	of	physical	or	mental	illness	or	after	he	has	given	notice	of termination	for	good	reason)	that	remains	uncured	for	30	days	after	receiving	a	written	notice	from	the	Personnel	Committee;

•willfully	engaging	in	conduct	that	is	demonstrably	and	materially	injurious	to	Entergy;

•conviction	of	or	entrance	of	a	plea	of	guilty	or	nolo	contendere	to	a	felony	or	other	crime	that	has	or	may	have	a	material	adverse	effect	on his	ability	to	carry	out	his	duties	or	upon	Entergy's	reputation;

•material	violation	of	any	agreement	that	he	has	entered	into	with	Entergy;	or

•unauthorized	disclosure	of	Entergy's	confidential	information.

Mr.	Denault	may	terminate	his	employment	for	good	reason	upon:

•the	substantial	reduction	in	the	nature	or	status	of	his	duties	or	responsibilities;

•a	reduction	of	5%	or	more	in	his	base	salary	as	in	effect	on	the	date	of	the	retention	agreement;

•the	relocation	of	his	principal	place	of	employment	to	a	location	other	than	the	corporate	headquarters;

•the	failure	to	continue	to	allow	him	to	participate	in	programs	or	plans	providing	opportunities	for	equity	awards,	stock	options,	restricted stock,	stock	appreciation	rights,	incentive	compensation,	bonus	and	other	plans	on	a	basis	not	materially	less	favorable	than	enjoyed	at	the time	of	the	retention	agreement	(other	than	changes	similarly	affecting	all	senior	executives);

•the	failure	to	continue	to	allow	him	to	participate	in	programs	or	plans	with	opportunities	for	benefits	not	materially	less	favorable	than those	enjoyed	by	him	under	any	of	the	pension,	savings,	life	insurance,	medical,	health	and	accident,	disability	or	vacation	plans	at	the time	of	the	retention	agreement	(other	than	changes	similarly	affecting	all	senior	executives);	or

•any	purported	termination	of	his	employment	not	taken	in	accordance	with	his	retention	agreement.

Mr.	Denault	may	terminate	his	employment	for	good	reason	in	the	event	of	a	change	in	control	upon:

•the	substantial	reduction	or	alteration	in	the	nature	or	status	of	his	duties	or	responsibilities;

•a	reduction	in	his	annual	base	salary;

•the	relocation	of	his	principal	place	of	employment	to	a	location	more	than	20	miles	from	his	current	place	of	employment;

•the	failure	to	pay	any	portion	of	his	compensation	within	seven	days	of	its	due	date;

•the	failure	to	continue	in	effect	any	compensation	plan	in	which	he	participates	and	which	is	material	to	his	total	compensation,	unless other	equitable	arrangements	are	made;

•the	failure	to	continue	to	provide	benefits	substantially	similar	to	those	that	he	currently	enjoys	under	any	of	the	pension,	savings,	life insurance,	medical,	health	and	accident	or	disability	plans,	or	Entergy	taking	of	any	other	action	which	materially	reduces	any	of	those benefits	or	deprives	him	of	any	material	fringe	benefits	that	he	currently	enjoys;

•the	failure	to	provide	him	with	the	number	of	paid	vacation	days	to	which	he	is	entitled	in	accordance	with	the	normal	vacation	policy; or

# Haley	R.	Fisackerly

# President	&	CEO,	Entergy	Mississippi

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President	and	CEO, Entergy	Mississippi	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of	December	31, 2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $414,643 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $63,270 | $63,270 | — | $60,107 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $40,050 | $40,050 | — | $60,107 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $74,848 | $74,848 | — | $171,284 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $17,076 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Fisackerly's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	Fisackerly	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for early	retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	Fisackerly's	employment	were terminated	for	cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Fisackerly	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan,	a	lump	sum	severance	payment	equal	to	the	product	of	one	time	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	40%	target	opportunity	and	a	base	salary	of	$296,174	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Fisackerly	would	have	forfeited	his	performance	units	for	the 2012-2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a single-sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance period	and	the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance units	he	would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance periods	preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes of	the	table,	the	value	of	Mr.	Fisackerly's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the 2009-2011	Performance	Unit	Program	(900	units)	and	the	2010-2012	Performance	Unit	Program	(1,000	units).	This	average	number	of units	(950	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of $60,107	for	the	forfeited	performance	units.

In	 the	event	of	Mr.	Fisackerly's	death	or	disability	not	related	 to	a	change	 in	control,	Mr.	Fisackerly	would	not	have	forfeited	his performance	units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his number	of	months	of	participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	the	award	is	based	on	actual performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	Fisackerly's	awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	Fisackerly's	unvested	stock	options would	immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from the	grant	date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	Fisackerly	exercised	his	options	immediately	upon	vesting and	received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable exercise	price	of	each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	Fisackerly's	unvested	options	fell	below	the exercise	prices	and	accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	Fisackerly	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that was	otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as dividends	declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the number	of	days	between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In the	event	of	his	qualifying	termination	related	to	a	change	in	control,	Mr.	Fisackerly	would	immediately	vest	in	all	unvested	restricted stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Fisackerly	would	be eligible	to	receive	company-subsidized	COBRA	benefits	for	12	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available to	Mr.	Fisackerly	under this	scenario	are	substantially the	same	as available	with	a	voluntary	resignation.

(8) In	December	2010,	the	System	Executive	Continuity	Plan	was	amended	to	eliminate	excise	tax	gross-up	payments.

# Jeffrey	S.	Forbes

# Executive	Vice	President,	Nuclear	Operations	and	Chief	Nuclear	Officer

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	Executive	Vice	President, Nuclear	Operations	and	Chief	Nuclear	Officer	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various scenarios	as	of	December	31,	2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(9) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $2,631,200 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | $182,091 | $182,091 | $182,091 | — | $319,514 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | $157,606 | $157,606 | $157,606 | — | $319,514 |
| Unvested\tStock\tOptions(4) | — | — | — | $— | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $142,981 | $142,981 | — | $328,264 |
| Nuclear\tRetention\tPlan(6) | — | — | — | — | — | — | — | — |
| Unvested\tRestricted\tUnits(7) | — | — | $506,160 | — | — | — | — | $506,160 |
| Medical\tand\tDental\tBenefits(8) | — | — | — | — | — | — | — | — |
| 280G\tTax\tGross-up(10) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	Mr.	Forbes	would	have	been	eligible	to	retire	and	entitled	to	receive	his	vested pension	benefits.	For	a	description	of	the	pension	benefits	available	see	"2013	Pension	Benefits."	In	the	event	of	a	termination	related	to	a change	in	control,	pursuant	to	the	terms	of	the	System	Executive	Retirement	Plan,	Mr.	Forbes	would	be	eligible	for	subsidized	early retirement	even	if	he	does	not	have	company	permission	to	separate	from	employment.	If	Mr.	Forbes'	employment	were	terminated	for cause,	he	would	not	receive	a	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Forbes	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	2.99	times	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	 immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	60%	target	opportunity	and	a	base	salary	of	$550,000	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Forbes	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	Forbes'	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009-2011 Performance	Unit	Program	(4,800	units)	and	the	2010-2012	Performance	Unit	Program	(5,300	units).	This	average	number	of	units	(5,050 units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$319,514	for the	forfeited	performance	units.

In	the	event	of	Mr.	Forbes'	retirement,	death	or	disability	not	related	to	a	change	in	control,	Mr.	Forbes	would	not	have	forfeited	his performance	units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his number	of	months	of	participation	in	each	open	Performance	Unit	Program	performance

cycle.	The	amount	of	the	award	is	based	on	actual	performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period, and	payable	in	the	form	of	a	lump	sum	after	the	completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	Forbes' awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	Forbes's	unvested	stock	options would	immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from the	grant	date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	Forbes	exercised	his	options	immediately	upon	vesting	and received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise price	of	each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	Forbes's	unvested	options	fell	below	the	exercise prices	and	accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	Forbes	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	Forbes	would	immediately	vest	in	all	unvested	restricted	stock.

(6) As	Entergy	Corporation's	Chief	Nuclear	Officer,	Mr.	Forbes	participates	in	the	Nuclear	Retention	Program	which	does	not	allow	for accelerated	or	prorated	payout	upon	termination	of	any	kind.

(7) Mr.	Forbes'	8,000	restricted	units	vest	100%	in	2016.	Pursuant	to	his	restricted	unit	agreement,	any	unvested	restricted	units	will	vest immediately	in	the	event	of	a	termination	for	a	reason	other	than	cause,	total	disability	or	death.	The	units	will	vest	upon	termination within	24	months	of	a	change	in	control	without	cause	or	by	Mr.	Forbes	with	good	reason.	If	Mr.	Forbes	voluntarily	resigned	or	was terminated	for	cause,	he	would	forfeit	these	units.

(8) Upon	retirement,	Mr.	Forbes	would	be	eligible	for	retiree	medical	and	dental	benefits,	the	same	as	all	other	retirees.	Pursuant	to	the System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Forbes	would	not	be	eligible	to	receive company-subsidized	COBRA	benefits.

(9) As	of	December	31,	2013,	Mr.	Forbes	is	retirement	eligible	and	would	retire	rather	than	voluntarily	resign.	Given	that	scenario,	the compensation	and	benefits	available	to	Mr.	Forbes	under	retirement	are	substantially	the	same	as	available	with	a	voluntary	resignation.

(10) In	December	2010,	the	System	Executive	Continuity	Plan	was	amended	to	eliminate	excise	tax	gross-up	payments.

# Andrew	S.	Marsh

# Executive	Vice	President	and	Chief	Financial	Officer

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	Executive	Vice	President	and Chief	Financial	Officer	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of	December 31,	2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $2,093,000 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $168,361 | $168,361 | — | $319,514 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $156,973 | $156,973 | — | $319,514 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $133,876 | $133,876 | — | $355,972 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $25,614 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Marsh's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	Marsh	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	Marsh's	employment	were	terminated for	cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Marsh	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	2.99	times	the	sum	of	(a)	his	annual	base	salary	as	in effect	at	any	time	within	one	year	prior	to	the	commencement	of	a	of	a	change	in	control	period	or,	if	higher,	immediately	prior	to	a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	40%	target	opportunity	and	a	base	salary	of	$500,000	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Marsh	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plans,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	Marsh's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009- 2011	Performance	Unit	Program	(4,800	units)	and	the	2010-2012	Performance	Unit	Program	(5,300	units).	This	average	number	of	units (5,050	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of $319,514	for	the	forfeited	performance	units.

In	the	event	of	Mr.	Marsh's	death	or	disability	not	related	to	a	change	in	control,	Mr.	Marsh	would	not	have	forfeited	his	performance units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	number	of months	 of	 participation	 in	 each	 open	 Performance	 Unit	 Program	 performance	 cycle.	 The	 amount	 of	 the	 award	 is	 based	 on	 actual performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	Marsh's	awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	Marsh's	unvested	stock	options would	immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from the	grant	date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	Marsh	exercised	his	options	immediately	upon	vesting	and received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise price	of	each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	Marsh's	unvested	options	fell	below	the	exercise prices	and	accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	Marsh	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	Marsh	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Marsh	would	be	eligible to	receive	company-subsidized	COBRA	benefits	for	18	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available	to	Mr.	Marsh	under	this	scenario	are	substantially	the	same	as	available with	a	voluntary	resignation.

# Phillip	R.	May,	Jr.

# President	&	CEO,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President	&	CEO, Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under various	scenarios	as	of	December	31,	2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $924,000 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $87,502 | $87,502 | — | $132,867 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $62,637 | $62,637 | — | $132,867 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $71,432 | $71,432 | — | $167,610 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $25,614 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	May's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	May	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	May's	employment	were	terminated	for cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	May	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	two	times	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	of	 a	 change	 in	 control	 period	 or,	 if	 higher,	 immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	40%	target	opportunity	and	a	base	salary	of	$330,000	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	May	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	May's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009-2011 Performance	Unit	Program	(2,000	units)	and	the	2010-2012	Performance	Unit	Program	(2,200	units).	This	average	number	of	units	(2,100 units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$132,867	for the	forfeited	performance	units.

In	the	event	of	Mr.	May's	death	or	disability	not	related	to	a	change	in	control,	Mr.	May	would	not	have	forfeited	his	performance	units	for all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	number	of	months	of participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	 the	award	 is	based	on	actual	performance achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the	completion	of	the performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	May's	awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	May's	unvested	stock	options	would immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from	the	grant date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	May	exercised	his	options	immediately	upon	vesting	and	received proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise	price	of each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	May's	unvested	options	fell	below	the	exercise	prices	and accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	May	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	May	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	May	would	be	eligible to	receive	company-subsidized	COBRA	benefits	for	18	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available	to	Mr.	May	under	this	scenario	are	substantially	the	same	as	available	with a	voluntary	resignation.

# Hugh	T.	McDonald

# President	&	CEO,	Entergy	Arkansas

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President	&	CEO, Entergy	Arkansas	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of	December	31, 2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $517,830 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | $63,270 | $63,270 | $63,270 | — | $60,107 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | $40,050 | $40,050 | $40,050 | — | $60,107 |
| Unvested\tStock\tOptions(4) | — | — | — | $— | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $77,063 | $77,063 | — | $175,975 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | — |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — |  | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	McDonald	would	have	been	eligible	to	retire	and	entitled	to	receive	his	vested pension	benefits.	For	a	description	of	the	pension	benefits	available	see	"2013	Pension	Benefits."	In	the	event	of	a	termination	related	to	a change	in	control,	pursuant	to	the	terms	of	the	System	Executive	Retirement	Plan,	Mr.	McDonald	would	be	eligible	for	subsidized	early retirement	even	if	he	does	not	have	company	permission	to	separate	from	employment.	If	Mr.	McDonald's	employment	were	terminated for	cause,	he	would	not	receive	a	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	McDonald	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan,	a	lump	sum	severance	payment	equal	to	the	product	of	one	time	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	 immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	50%	target	opportunity	and	a	base	salary	of	$345,220	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	McDonald	would	have	forfeited	his	performance	units	for	the 2012-2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a single-sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance period	and	the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance units	he	would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance periods	preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes of	the	table,	the	value	of	Mr.	McDonald's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the 2009-2011	Performance	Unit	Program	(900	units)	and	the	2010-2012	Performance	Unit	Program	(1,000	units).	This	average	number	of units	(950	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$ $60,107	for	the	forfeited	performance	units.

In	the	event	of	Mr.	McDonald's	retirement,	death,	or	disability	not	related	to	a	change	in	control,	Mr.	McDonald	would	not	have	forfeited his	performance	units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his number	of	months	of	participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	the	award	is	based	on	actual performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the

performance	period,	and	payable	in	the	form	of	a	lumpsum	after	the	completion	of	the	performance	period.	For	purposes	of	the	table,	the value	of	Mr.	McDonald's	awards	were	calculated	as	follows:

(4) In	the	event	of	his	retirement,	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	McDonald's	unvested stock	options	would	immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year extending	 from	 the	 grant	 date	 of	 the	 options.	For	 purposes	 of	 this	 table,	 it	 is	 assumed	 that	 Mr.	 McDonald	 exercised	 his	 options immediately	upon	vesting	and	received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31, 2013,	and	the	applicable	exercise	price	of	each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	McDonald's unvested	options	fell	below	the	exercise	prices	and	accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	McDonald	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that was	otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as dividends	declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the number	of	days	between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In the	event	of	his	qualifying	termination	related	to	a	change	in	control,	Mr.	McDonald	would	immediately	vest	in	all	unvested	restricted stock.

(6) Upon	retirement,	Mr.	McDonald	would	be	eligible	for	retiree	medical	and	dental	benefits,	the	same	as	all	other	retirees.	Pursuant	to	the System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	McDonald	would	not	be	eligible	to receive	company-subsidized	COBRA	benefits.

(7) As	of	December	31,	2013,	Mr.	McDonald	is	retirement	eligible	and	would	rather	retire	than	voluntary	resign.	Given	that	scenario,	the compensation	 and	 benefits	 available	 to	 Mr.	 McDonald	 under	 retirement	 are	 substantially	 the	 same	 as	 available	 with	 a	 voluntary resignation.

# William	M.	Mohl

# President,	Entergy	Wholesale	Commodities

# Former	President	&	CEO,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President,	Entergy Wholesale	Commodities	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of December	31,	2013:

| Benefits	and	Payments	Upon<br>Termination(1) | Voluntary<br>Resignation | For<br>Cause | Termination<br>for	Good<br>Reason	or	Not<br>for	Cause | Retirement(8) | Disability | Death | Change	in<br>Control | Termination<br>Related	to	a<br>Change	in<br>Control |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| \tSeverance\tPayment(2) | — | — | — | — | — | — | — | $2,679,040 |
| \tPerformance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $182,091 | $182,091 | — | $319,514 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $157,606 | $157,606 | — | $319,514 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $138,369 | $138,369 | — | $363,145 |
| Special\tSeverance\tAgreement(6) | — | — | $7,538,650 | — | — | — | — | — |
| Medical\tand\tDental\tBenefits(7) | — | — | — | — | — | — | — | $19,063 |
| 280G\tTax\tGross-up(9) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Mohl's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	Mohl	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	Mohl's	employment	were	terminated	for cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Mohl	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	2.99	times	the	sum	of	(a)	his	annual	base	salary	as	is effect	at	any	time	within	one	year	prior	to	the	commencement	of	a	of	a	change	in	control	period	or,	if	higher,	immediately	prior	to	a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	60%	target	opportunity	and	a	base	salary	of	$560,000	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Mohl	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	Mohl's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009-2011 Performance	Unit	Program	(4,800	units)	and	the	2010-2012	Performance	Unit	Program	(5,300	units).	This	average	number	of	units	(5,050 units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$319,514	for the	forfeited	performance	units.

In	the	event	of	Mr.	Mohl's	death	or	disability	not	related	to	a	change	in	control,	Mr.	Mohl	would	not	have	forfeited	his	performance	units for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	number	of	months	of participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	 the	award	 is	based	on	actual	performance achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and

payable	in	the	form	of	a	lump	sum	after	the	completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	Mohl's awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	Mohl's	unvested	stock	options	would immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from	the	grant date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	Mohl	exercised	his	options	immediately	upon	vesting	and	received proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise	price	of each	option	share.	As	of	December	31,	2013,	the	closing	stock	prices	of	Mr.	Mohl's	unvested	options	fell	below	the	exercise	prices	and accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	Mohl	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	Mohl	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	provisions	of	Mr.	Mohl's	retention	agreement,	if	Mr.	Mohl	is	terminated	without	cause	prior	to	September	18,	2014,	the date	Mr.	Mohl	becomes	retirement	eligible,	Mr.	Mohl	would	receive	a	severance	payment	of	$7,538,650,	upon	satisfaction	of	certain	terms and	 conditions.	This	amount	includes,	in	addition	to	a	severance	payment	calculated	on	the	basis	of	his	base	salary	and	target	annual bonus,	a	payment	of	$2,200,000	plus	the	benefits	he	would	be	eligible	for	under	the	System	Executive	Retirement	Plan	as	if	he	were retirement	eligible	reduced	by	any	benefits	payable	under	any	of	Entergy	Corporation's	qualified	or	non-qualified	retirement	plans.	See "Executive	Compensation	-	Compensation	Discussion	And	Analysis	-Retention	Agreements	and	Other	Compensation	Arrangements."

(7) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Mohl	would	be	eligible to	receive	company-subsidized	COBRA	benefits	for	18	months.

(8) As	of	December	31,	2013,	compensation	and	benefits	available	to	Mr.	Mohl	under	this	scenario	are	substantially	the	same	as	available with	a	voluntary	resignation.

# Alyson	M.	Mount

# Senior	Vice	President,	Chief	Accounting	Officer

The	 following	 table	 shows	 certain	 payments	 and	 benefits,	 excluding	 vested	 or	 earned	 awards	 and	 benefits,	 which	 the	 Senior	Vice President,	Chief	Accounting	Officer	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	her	employment	under	various	scenarios	as of	December	31,	2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $845,765 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $87,186 | $87,186 | — | $132,867 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $63,270 | $63,270 | — | $132,867 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $85,035 | $85,035 | — | $207,074 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $8,518 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Ms.	Mount's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Ms.	Mount	also	would	have	been	entitled	to	receive	her	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Ms.	Mount's	employment	were	terminated for	cause,	she	would	forfeit	her	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Ms.	Mount	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	2.00	times	the	sum	of	(a)	her	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	her	annual	incentive,	calculated	using	the	average	annual	target	opportunity	under	the Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination	occurs. For	purposes	of	this	table,	a	48%	target	opportunity	and	a	base	salary	of	$286,700	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Ms.	Mount	would	have	forfeited	her	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	she would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	her	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Ms.	Mount's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009- 2011	Performance	Unit	Program	(2,000	units)	and	the	2010-2012	Performance	Unit	Program	(2,200	units).	This	average	number	of	units (2,100	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of $132,867	for	the	forfeited	performance	units.

In	the	event	of	Ms.	Mount's	death	or	disability	not	related	to	a	change	in	control,	Ms.	Mount	would	not	have	forfeited	her	performance units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	her	number	of months	 of	 participation	 in	 each	 open	 Performance	 Unit	 Program	 performance	 cycle.	The	 amount	 of	 the	 award	 is	 based	 on	 actual performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Ms.	Mount's	awards	were	calculated	as	follows:

(4) In	the	event	of	her	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Ms.	Mount's	unvested	stock	options would	immediately	vest.	In	addition,	she	would	be	entitled	to	exercise	her	stock	options	for	the	remainder	of	the	ten-year	extending	from the	grant	date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Ms.	Mount	exercised	her	options	immediately	upon	vesting	and received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise price	of	each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Ms.	Mount's	unvested	options	fell	below	the	exercise prices	and	accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	her	death	or	disability,	Ms.	Mount	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	her	death	or	disability.	In	the	event	of her	qualifying	termination	related	to	a	change	in	control,	Ms.	Mount	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Ms.	Mount	would	be eligible	to	receive	company-subsidized	COBRA	benefits	for	18	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available	to	Ms.	Mount	under	this	scenario	are	substantially	the	same	as	available with	a	voluntary	resignation.

# Sallie	T.	Rainer

# President	&	CEO,	Entergy	Texas

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President	&	CEO, Entergy	Texas	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	her	employment	under	various	scenarios	as	of	December	31, 2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $392,850 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $54,475 | $54,475 | — | $60,107 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $40,050 | $40,050 | — | $60,107 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $68,015 | $68,015 | — | $166,202 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $17,076 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Ms.	Rainer's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Ms.	Rainer	also	would	have	been	entitled	to	receive	her	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Ms.	Rainer's	employment	were	terminated for	cause,	she	would	forfeit	her	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Ms.	Rainer	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	1.00	times	the	sum	of	(a)	her	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	her	annual	incentive,	calculated	using	the	average	annual	target	opportunity	under	the Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination	occurs. For	purposes	of	this	table,	a	40%	target	opportunity	and	a	base	salary	of	$291,000	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Ms.	Rainer	would	have	forfeited	her	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	she would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	her	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Ms.	Rainer's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009- 2011	Performance	Unit	Program	(900	units)	and	the	2010-2012	Performance	Unit	Program	(1,000	units).	This	average	number	of	units (950	units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$60,107 for	the	forfeited	performance	units.

In	the	event	of	Ms.	Rainer's	death	or	disability	not	related	to	a	change	in	control,	Ms.	Rainer	would	not	have	forfeited	his	performance units	for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	her	number	of months	 of	 participation	 in	 each	 open	 Performance	 Unit	 Program	 performance	 cycle.	 The	 amount	 of	 the	 award	 is	 based	 on	 actual performance	achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Ms.	Rainer's	awards	were	calculated	as	follows:

(4) In	the	event	of	her	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Ms.	Rainer's	unvested	stock	would immediately	vest.	In	addition,	she	would	be	entitled	to	exercise	any	unexercised	options	during	a	ten-year	term	extending	from	the	grant date	of	the	options.	For	purposes	of	this	table,	we	assumed	that	Ms.	Rainer	exercised	her	options	immediately	upon	vesting	and	received proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	exercise	price	of	each	option share.	As	of	December	31,	2013,	the	closing	stock	price	of	Ms.	Rainer's	unvested	options	fell	below	the	exercise	prices	and	accordingly are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	her	death	or	disability,	Ms.	Rainer	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	her	death	or	disability.	In	the	event	of her	qualifying	termination	related	to	a	change	in	control,	Ms.	Rainer	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Ms.	Rainer	would	be eligible	to	receive	company-subsidized	COBRA	benefits	for	12	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available	to	Ms.	Rainer	under	this	scenario	are	substantially	the	same	as	available with	a	voluntary	resignation.

# Charles	L.	Rice,	Jr.

# President	&	CEO,	Entergy	New	Orleans

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	President	and	CEO, Entergy	New	Orleans	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	his	employment	under	various	scenarios	as	of	December 31,	2013:

|  |  |  | Termination |  |  |  |  | Termination |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | for\tGood |  |  |  |  | Related\tto\ta |
| Benefits\tand\tPayments\tUpon\nTermination(1) | Voluntary\nResignation | For\nCause | Reason\tor\tNot\nfor\tCause | Retirement(7) | Disability | Death | Change\tin\nControl | Change\tin\nControl |
| Severance\tPayment(2) | — | — | — | — | — | — | — | $360,001 |
| Performance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\tPerformance\tUnit\nProgram | — | — | — | — | $63,270 | $63,270 | — | $60,107 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $40,050 | $40,050 | — | $60,107 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $61,878 | $61,878 | — | $144,865 |
| Medical\tand\tDental\tBenefits(6) | — | — | — | — | — | — | — | $900 |
| 280G\tTax\tGross-up(8) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Rice's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	Rice	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	Rice's	employment	were	terminated	for cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Rice	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan,	a	lump	sum	severance	payment	equal	to	the	product	of	one	time	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	 immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under the	Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination occurs.	For	purposes	of	this	table,	a	40%	target	opportunity	and	a	base	salary	of	$257,144	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	Rice	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	to	receive	under	each	Performance	Unit	Program	with	respect	to	the	two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	Rice's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009-2011 Performance	Unit	Program	(900	units)	and	the	2010-2012	Performance	Unit	Program	(1,000	units).	This	average	number	of	units	(950 units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$60,107	for the	forfeited	performance	units.

In	the	event	of	Mr.	Rice's	death	or	disability	not	related	to	a	change	in	control,	Mr.	Rice	would	not	have	forfeited	his	performance	units	for all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	number	of	months	of participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	 the	award	 is	based	on	actual	performance achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and	payable	in	the	form	of	a	lump	sum	after	the	completion	of	the performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	Rice's	awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	Rice's	unvested	stock	options	would immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	his	stock	options	for	the	remainder	of	the	ten-year	extending	from	the	grant date	of	the	options.	For	purposes	of	this	table,	it	is	assumed	that	Mr.	Rice	exercised	his	options	immediately	upon	vesting	and	received proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	applicable	exercise	price	of each	option	share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	Rice's	unvested	options	fell	below	the	exercise	prices	and accordingly	are	considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	Rice	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	Rice	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Rice	would	be	eligible to	receive	company-subsidized	COBRA	benefits	for	12	months.

(7) As	of	December	31,	2013,	compensation	and	benefits	available	to	Mr.	Rice	under	this	scenario	are	substantially	the	same	as	available	with a	voluntary	resignation.

# Roderick	K.	West

# Executive	Vice	President	&	Chief	Administrative	Officer

The	following	table	shows	certain	payments	and	benefits,	excluding	vested	or	earned	awards	and	benefits,	which	the	Executive	Vice President	&	Chief	Administrative	Officer	would	have	been	entitled	to	receive	as	a	result	of	a	termination	of	her	employment	under	various scenarios	as	of	December	31,	2013:

| Benefits	and	Payments	Upon<br>Termination(1) | Voluntary<br>Resignation | For<br>Cause | Termination<br>for	Good<br>Reason	or	Not<br>for	Cause | Retirement(8) | Disability | Death | Change	in<br>Control | Termination<br>Related	to	a<br>Change	in<br>Control |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| \tSeverance\tPayment(2) | — | — | — | — | — | — | — | $3,114,488 |
| \tPerformance\tUnits:(3) |  |  |  |  |  |  |  |  |
| 2012-2014\t\tPerformance\tUnit\nProgram | — | — | — | — | $227,772 | $227,772 | — | $319,514 |
| 2013-2015\tPerformance\tUnit\nProgram | — | — | — | — | $160,263 | $160,263 | — | $319,514 |
| Unvested\tStock\tOptions(4) | — | — | — | — | $— | $— | — | $— |
| Unvested\tRestricted\tStock(5) | — | — | — | — | $255,854 | $255,854 | — | $592,560 |
| Unvested\tRestricted\tUnits(6) | — | — | $1,328,670 | — | $— | $— | — | $1,328,670 |
| Medical\tand\tDental\tBenefits(7) | — | — | — | — | $— | $— | — | $25,614 |
| 280G\tTax\tGross-up(9) | — | — | — | — | — | — | — | — |

(1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	West's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	Mr.	West	also	would	have	been	entitled	to	receive	his	vested	pension	benefits	and	would	have	been	eligible	for	early retirement	benefits.	For	a	description	of	the	pension	benefits,	see	"2013	Pension	Benefits."	If	Mr.	West's	employment	were	terminated	for cause,	he	would	forfeit	his	benefit	under	the	System	Executive	Retirement	Plan.

(2) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	West	would	be	entitled	to	receive	pursuant	to	the	System Executive	Continuity	Plan	a	lump	sum	severance	payment	equal	to	the	product	of	2.99	times	the	sum	of	(a)	his	annual	base	salary	as	in effect	 at	 any	 time	 within	 one	 year	 prior	 to	 the	 commencement	 of	 a	 change	 in	 control	 period	 or,	 if	 higher,	 immediately	 prior	 to	 a circumstance	constituting	good	reason	plus	(b)	his	annual	incentive,	calculated	using	the	average	annual	target	opportunity	under	the Annual	Incentive	Plan	for	the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	participant's	termination	occurs. For	purposes	of	this	table,	a	70%	target	opportunity	and	a	base	salary	of	$612,726	was	assumed.

(3) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	Mr.	West	would	have	forfeited	his	performance	units	for	the	2012- 2014	and	2013-2015	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2011	Equity	Ownership	Plan,	a	single- sum	severance	payment	that	would	not	be	based	on	any	outstanding	performance	periods.	For	both	the	2012-2014	performance	period	and the	2013-2015	performance	period,	the	payment	would	have	been	calculated	using	the	average	annual	number	of	performance	units	he would	have	been	entitled	 to	receive	under	 the	Performance	Unit	Program	with	respect	 to	 the	 two	most	recent	performance	periods preceding	the	calendar	year	in	which	his	termination	occurs,	assuming	all	performance	goals	were	achieved	at	target.	For	purposes	of	the table,	the	value	of	Mr.	West's	severance	payment	was	calculated	by	taking	an	average	of	the	target	performance	units	from	the	2009-2011 Performance	Unit	Program	(4,800	units)	and	the	2010-2012	Performance	Unit	Program	(5,300	units).	This	average	number	of	units	(5,050 units)	multiplied	by	the	closing	price	of	Entergy	stock	on	December	31,	2013	($63.27)	would	equal	a	severance	payment	of	$319,514	for the	forfeited	performance	units.

In	the	event	of	Mr.	West's	death	or	disability	not	related	to	a	change	in	control,	Mr.	West	would	not	have	forfeited	his	performance	units for	all	open	performance	periods,	but	rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	number	of	months	of participation	in	each	open	Performance	Unit	Program	performance	cycle.	The	amount	of	 the	award	 is	based	on	actual	performance achieved,	with	a	stock	price	set	as	of	the	end	of	the	performance	period,	and

payable	in	the	form	of	a	lump	sum	after	the	completion	of	the	performance	period.	For	purposes	of	the	table,	the	value	of	Mr.	West's awards	were	calculated	as	follows:

(4) In	the	event	of	his	death,	disability	or	qualifying	termination	related	to	a	change	in	control,	all	of	Mr.	West's	unvested	stock	options	would immediately	vest.	In	addition,	he	would	be	entitled	to	exercise	any	unexercised	options	during	a	ten-year	term	extending	from	the	grant date	of	the	options.	For	purposes	of	this	table,	we	assumed	that	Mr.	West	exercised	his	options	immediately	upon	vesting	and	received proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	31,	2013,	and	the	exercise	price	of	each	option share.	As	of	December	31,	2013,	the	closing	stock	price	of	Mr.	West's	unvested	options	fell	below	the	exercise	prices	and	accordingly	are considered	"underwater"	and	are	excluded	from	the	table.

(5) In	the	event	of	his	death	or	disability,	Mr.	West	would	immediately	vest	in	a	pro-rated	portion	of	the	unvested	restricted	stock	that	was otherwise	scheduled	to	become	vested	on	the	immediately	following	twelve	(12)-month	grant	date	anniversary	date	(as	well	as	dividends declared	on	the	pro-rated	portion	of	such	restricted	stock).	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days between	the	most	recent	preceding	twelve	(12)-month	grant	date	anniversary	date	and	the	date	of	his	death	or	disability.	In	the	event	of	his qualifying	termination	related	to	a	change	in	control,	Mr.	West	would	immediately	vest	in	all	unvested	restricted	stock.

(6) Mr.	West's	21,000	restricted	units	vest	100%	in	2018.	 Pursuant	to	his	restricted	unit	agreement,	any	unvested	restricted	units	will	vest immediately	in	the	event	of	a	termination	for	a	reason	other	than	cause,	total	disability	or	death.	The	units	will	vest	upon	termination within	24	months	of	a	change	in	control	without	cause	or	by	Mr.	West	with	good	reason.	If	Mr.	West	voluntarily	resigned	or	was terminated	for	cause,	he	would	forfeit	these	units.

(7) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	West	would	be	eligible to	receive	company-subsidized	COBRA	benefits	for	18	months.

(8) As	of	December	31,	2013,	compensation	and	benefits	available	to	Mr.	West	under	this	scenario	are	substantially	the	same	as	available with	a	voluntary	resignation.

In	the	following	sections,	additional	information	is	provided	regarding	certain	of	the	scenarios	described	in	the	tables	above:

# Termination	Related	to	a	Change	in	Control

Under	the	System	Executive	Continuity	Plan,	the	Named	Executive	Officers	will	be	entitled	to	the	benefits	described	in	the	tables	above in	the	event	of	a	termination	related	to	a	change	in	control	if	their	employment	is	terminated	other	than	for	cause	or	if	they	terminate	their employment	for	good	reason,	in	each	case	within	a	period	ending	24	months	following	the	effective	date	of	a	change	in	control.

A	change	in	control	includes	the	following	events:

•The	purchase	of	30%	or	more	of	either	the	common	stock	or	the	combined	voting	power	of	the	voting	securities	of	Entergy	Corporation; •the	merger	or	consolidation	of	Entergy	Corporation	(unless	Entergy	Corporation's	board	members	constitute	at	least	a	majority	of	the board	members	of	the	surviving	entity);

•the	liquidation,	dissolution	or	sale	of	all	or	substantially	all	of	Entergy	Corporation's	assets;	or

•a	change	in	the	composition	of	Entergy	Corporation's	board	such	that,	during	any	two-year	period,	the	individuals	serving	at	the	beginning of	the	period	no	longer	constitute	a	majority	of	Entergy	Corporation's	board	at	the	end	of	the	period.

Entergy	Corporation	may	terminate	a	Named	Executive	Officer's	employment	for	cause	under	the	System	Executive	Continuity	Plan	if	he or	she:

•willfully	and	continuously	fails	to	substantially	perform	his	or	her	duties	after	receiving	a	30-day	written	demand	for	performance	from the	Board;

•engages	in	conduct	that	is	injurious	to	Entergy	Corporation	or	any	of	its	subsidiaries;

•is	convicted	or	pleads	guilty	or	nolo	contendere	to	a	felony	or	other	crime	that	materially	and	adversely	affects	his	or	her	ability	to	perform his	or	her	duties	or	Entergy	Corporation's	reputation;

•materially	violates	any	agreement	with	Entergy	Corporation	or	any	of	its	subsidiaries;	or •discloses	any	of	Entergy	Corporation's	confidential	information	without	authorization.

A	 Named	 Executive	 Officer	 may terminate	 employment	 with	 Entergy	 Corporation for	 good reason	 under the	 System	 Executive Continuity	Plan	if,	without	his	or	her	consent:

•the	nature	or	status	of	his	or	her	duties	and	responsibilities	is	substantially	altered	or	reduced	compared	to	the	period	prior	to	the	change	in control;

•his	or	her	salary	is	reduced	by	5%	or	more;

•he	or	she	is	required	to	be	based	outside	of	the	continental	United	States	at	somewhere	other	than	the	primary	work	location	prior	to	the change	in	control;

•any	of	his	or	her	compensation	plans	are	discontinued	without	an	equitable	replacement;

•his	or	her	benefits	or	number	of	vacation	days	are	substantially	reduced;	or

•his	or	her	employment	is	purported	to	be	terminated	other	than	in	accordance	with	the	System	Executive	Continuity	Plan.

In	addition	to	participation	in	the	System	Executive	Continuity	Plan,	upon	the	completion	of	a	transaction	resulting	in	a	change	in	control of	Entergy	Corporation,	benefits	already	accrued	under	the	System	Executive	Retirement	Plan,	Pension	Equalization	Plan,	and	Supplemental Retirement	Plan,	if	any,	will	become	fully	vested	if	the	executive	is	involuntarily	terminated	without	"Cause"	or	terminates	employment	for "Good	Reason."	Any	awards	granted	under	the	equity	ownership	plans	will	become	fully	vested	upon	a	change	in	control	and	the	executive	is involuntarily	 terminated	 without	 cause	 or	 terminates	 employment	 for	 good	 reason.	 	 In	 2010,	 Entergy	 Corporation	 eliminated	 tax	 gross	 up payments	for	any	severance	benefits	paid	under	the	System	Executive	Continuity	Plan.

Under	 certain	 circumstances,	 the	 payments	 and	 benefits	 received	 by	 a	 Named	 Executive	 Officer	 pursuant	 to	 the	 System	 Executive Continuity	 Plan	 may	 be	 forfeited	 and,	 in	 certain	 cases,	 subject	 to	 repayment.	 Benefits	 are	 no	 longer	 payable	 under	 the	 System	 Executive Continuity	Plan,	and	unvested	performance	units	under	the	Performance	Unit	Program	are	subject	to	forfeiture,	if	the	executive:

•accepts	employment	with	Entergy	Corporation	or	any	of	its	subsidiaries;

•elects	to	receive	the	benefits	of	another	severance	or	separation	program;

•removes,	copies	or	fails	to	return	any	property	belonging	to	Entergy	Corporation	or	any	of	its	subsidiaries;

•discloses	non-public	data	or	information	concerning	Entergy	Corporation	or	any	of	its	subsidiaries;	or

•violates	their	non-competition	provision,	which	generally	runs	for	two	years	but	extends	to	three	years	if	permissible	under	applicable	law.

Furthermore,	 if	 the	executive	discloses	non-public	data	or	 information	concerning	Entergy	Corporation	or	any	of	 its	subsidiaries	or violates	 their	 non-competition	 provision,	 he	 or	 she	 will	 be	 required	 to	 repay	 any	 benefits	 previously	 received	 under	 the	 System	 Executive Continuity	Plan.

# Termination	for	Cause

If	a	Named	Executive	Officer's	employment	is	terminated	for	"cause"	(as	defined	in	the	System	Executive	Continuity	Plans	and	described above	under	"Termination	Related	to	a	Change	in	Control"),	he	or	she	is	generally	entitled	to	the	same	compensation	and	separation	benefits described	below	under	"Voluntary	Resignation"	except	that	all	options	may	no	longer	be	exercisable.

# Voluntary	Resignation

If	a	Named	Executive	Officer	voluntarily	resigns	from	an	Entergy	System	company	employer,	he	or	she	is	entitled	to	all	accrued	benefits and	compensation	as	of	the	separation	date,	including	qualified	pension	benefits	(if	any)	and	other	post-employment	benefits	on	terms	consistent with	those	generally	available	to	other	salaried	employees.		In	the	case	of	voluntary	resignation,	the	officer	would	forfeit	all	unvested	stock options,	shares	of	restricted	stock	and	restricted	units	as	well	as	any	perquisites	to	which	he	or	she	is	entitled	as	an	officer.		In	addition,	the	officer would	forfeit,	except	as	described	below,	his	or	her	right	to	receive	incentive	payments	under	any	outstanding	performance	periods	under	the	Long Term	 Performance	 Unit	 Program	 or	 the	Annual	 Incentive	 Plan.	 If	 the	 officer	 resigns	 after	 the	 completion	 of	 an	Annual	 Incentive	 Plan	 or Performance	Unit	Program	performance	period,	he	could	receive	a	payout	under	the	Performance	Unit	Program	based	on	the	outcome	of	the performance	cycle	and	could,	at	entergy	Corporation's	discretion,	receive	an	annual	incentive	payment	under	the	Annual	Incentive	Plan.	Any vested	stock	options	held	by	the	officer	as	of	the	separation	date	will	expire	the	earlier	of	ten	years	from	date	of	grant	or	90	days	from	the	last	day of	active	employment.

# Retirement

Under	Entergy	Corporation's	retirement	plans,	a	Named	Executive	Officer's	eligibility	for	retirement	benefits	is	based	on	a	combination	of age	and	years	of	service.		Normal	retirement	is	defined	as	age	65.		Early	retirement	is	defined	under	the	qualified	retirement	plan	as	minimum	age 55	with	10	years	of	service	and	in	the	case	of	the	System	Executive	Retirement	Plan	and	the	supplemental	credited	service	under	the	Pension Equalization	Plan,	the	consent	of	Entergy	System	company	employer.

Upon	a	Named	Executive	Officer's	retirement,	he	or	she	is	generally	entitled	to	all	accrued	benefits	and	compensation	as	of	the	separation date,	including	qualified	pension	benefits	and	other	post-employment	benefits	consistent	with	those	generally	available	to	salaried	employees.	The annual	incentive	payment	under	the	Annual	Incentive	Plan	is	pro-rated	based	on	the	actual	number	of	days	employed	during	the	performance	year in	which	the	retirement	date	occurs.	Similarly,	payments	under	the	Performance	Unit	Program	for	those	retiring	with	a	minimum	12	months	of participation	are	pro-rated	based	on	the	actual	full	months	of	participation,	in	each	outstanding	performance	cycle,	in	which	the	retirement	date occurs.	In	each	case,	payments	are	delivered	at	the	conclusion	of	each	annual	or	performance	cycle,	consistent	with	the	timing	of	payments	to active	participants	in	the	Annual	Incentive	Plan	and	the	Performance	Unit	Program,	respectively.	Unvested	stock	options	issued	under	our	equity ownership	plans	vest	on	the	retirement	date	and	expire	ten	years	from	the	grant	date	of	the	options.	Any	restricted	units	held	(other	than	those issued	under	the	Performance	Unit	Program)	by	the	executive	upon	his	or	her	retirement	are	forfeited,	and	perquisites	are	not	available	following the	separation	date.

# Disability

If	 a	 Named	 Executive	 Officer's	 employment	 is	 terminated	 due	 to	 disability,	 he	 or	 she	 generally	 is	 entitled	 to	 the	 same	 compensation	 and separation	benefits	described	above	under	"Retirement,"	except	that	restricted	units	may	be	subject	to	specific	disability	benefits	(as	noted,	where applicable,	in	the	tables	above).

# Death

If	a	Named	Executive	Officer	dies	while	actively	employed	by	an	Entergy	System	company	employer,	he	or	she	generally	is	entitled	to the	same	compensation	and	separation	benefits	described	above	under	"Retirement,"	including:

•all	unvested	stock	options	will	vest	immediately;

•vested	stock	options	will	expire	ten	years	from	the	grant	date;	and

•restricted	units	may	be	subject	to	specific	death	benefits	depending	on	the	restricted	unit	agreement	(as	noted,	where	applicable,	in	the tables	above).

# 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.	 	The	Boards	of	Directors	of	Entergy	Arkansas,	Entergy	Gulf	States Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	are	comprised	solely	of	employee	directors	who receive	no	compensation	for	service	as	directors.

# 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	Louisiana, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans	and	Entergy	Texas.		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.

The	following	table	sets	forth	the	beneficial	ownership	of	Common	Stock	of	Entergy	Corporation	and	stock-based	units	as	of	January	31, 2014	for	all	directors	and	Named	Executive	Officers.		Unless	otherwise	noted,	each	person	had	sole	voting	and	investment	power	over	the	number of	shares	of	Common	Stock	and	stock-based	units	of	Entergy	Corporation	set	forth	across	from	his	or	her	name.

| Name | Shares	(1) | Options	Exercisable<br>Within	60	Days | Stock	Units	(2) |
| :--- | :--- | :--- | :--- |
| Entergy\tCorporation |  |  |  |
| Maureen\tS.\tBateman* | 5,649 | — | 10,471 |
| Leo\tP.\tDenault*** | 43,873 | 351,666 | — |
| Kirkland\tH.\tDonald* | 331 | — | — |
| Gary\tW.\tEdwards* | 1,713 | — | 9,451 |
| Jeffrey\tS.\tForbes** | 10,442 | 98,133 | 59 |
| Alexis\tHerman* | 6,501 | — | 8,071 |
| Donald\tC.\tHintz* | 3,492 | 20,000 | 9,070 |
| J.\tWayne\tLeonard** | 484,141 | 1,444,200 | — |
| Stuart\tL.\tLevenick* | 5,149 | — | 6,302 |
| Blanche\tL.\tLincoln* | 1,912 | — | 1,871 |
| Andrew\tS.\tMarsh** | 11,330 | 65,932 | — |
| William\tM.\tMohl** | 11,691 | 58,999 | — |
| Stewart\tC.\tMyers* | 2,931 | — | 3,054 |
| W.\tJ.\tTauzin* | 5,049 | — | 6,164 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| Steven\tV.\tWilkinson* | 6,204 | — | 7,698 |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(21\tpersons) | 676,740 | 2,526,561 | 62,503 |

# Options	Exercisable

# Within	60	Days

# Stock	Units	(2)

| Name | Shares	(1) | Options	Exercisable<br>Within	60	Days | Stock	Units	(2) |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Jeffrey\tS.\tForbes** | 10,442 | 98,133 | 59 |
| Andrew\tS.\tMarsh* | 11,330 | 65,932 | — |
| Hugh\tT.\tMcDonald*** | 14,566 | 53,566 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(10\tpersons) | 156,543 | 1,056,928 | 351 |
| Entergy\tGulf\tStates\tLouisiana |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Jeffrey\tS.\tForbes** | 10,442 | 98,133 | 59 |
| Andrew\tS.\tMarsh* | 11,330 | 65,932 | — |
| Phillip\tR.\tMay,\tJr.*** | 10,758 | 41,666 | 10 |
| William\tM.\tMohl** | 11,691 | 58,999 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(11\tpersons) | 164,426 | 1,104,027 | 361 |
| Entergy\tLouisiana |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Jeffrey\tS.\tForbes** | 10,442 | 98,133 | 59 |
| Andrew\tS.\tMarsh* | 11,330 | 65,932 | — |
| Phillip\tR.\tMay,\tJr.*** | 10,758 | 41,666 | 10 |
| William\tM.\tMohl** | 11,691 | 58,999 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(11\tpersons) | 164,426 | 1,104,027 | 361 |

# Name Shares	(1) Within	60	Days Stock	Units	(2)

| Name | Shares	(1) | Options	Exercisable<br>Within	60	Days | Stock	Units	(2) |
| :--- | :--- | :--- | :--- |
| Entergy\tMississippi |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Haley\tR.\tFisackerly*** | 5,845 | 29,266 | — |
| Andrew\tS.\tMarsh*** | 11,330 | 65,932 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(9\tpersons) | 137,380 | 934,495 | 292 |
| Entergy\tNew\tOrleans |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Andrew\tS.\tMarsh*** | 11,330 | 65,932 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Charles\tL.\tRice,\tJr.*** | 4,542 | 7,632 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(9\tpersons) | 136,077 | 912,861 | 292 |
| Entergy\tTexas |  |  |  |
| Theodore\tH.\tBunting,\tJr.* | 13,627 | 88,833 | — |
| Leo\tP.\tDenault** | 43,873 | 351,666 | — |
| Andrew\tS.\tMarsh*** | 11,330 | 65,932 | — |
| Alyson\tM.\tMount** | 7,159 | 34,366 | — |
| Sallie\tT.\tRainer*** | 6,919 | 14,933 | — |
| Mark\tT.\tSavoff* | 15,510 | 209,333 | 292 |
| Roderick\tK.\tWest** | 19,086 | 84,334 | — |
| All\tdirectors\tand\texecutive |  |  |  |
| officers\tas\ta\tgroup\t(9\tpersons) | 138,454 | 920,162 | 292 |

** Named	Executive	Officer	of	the	respective	Company

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

(1) The	number	of	shares	of	Entergy	Corporation	common	stock	owned	by	each	individual	and	by	all	directors	and	executive	officers	as	a	group does	not	exceed	one	percent	of	the	outstanding	Entergy	Corporation	common	stock.

(2) Represents	the	balances	of	phantom	units	each	executive	holds	under	the	defined	contribution	restoration	plan	and	the	deferral	provisions	of the	Equity	Ownership	Plan.		These	units	will	be	paid	out	in	either	Entergy	Corporation	Common	Stock	or	cash	equivalent	to	the	value	of	one share	of	Entergy	Corporation	common	stock	per	unit	on	the	date	of	payout,	including	accrued	dividends.		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	phantom	units	are	issued under	the	Service	Recognition	Program	for	Outside	Directors.		All	non-employee	directors	are	credited	with	units	for	each	year	of	service	on the	Board.		In	addition,	Messrs.	Edwards	and	Hintz	have	deferred	receipt

of	some	of	their	quarterly	stock	grants.		The	deferred	shares	will	be	settled	in	cash	in	an	amount	equal	to	the	market	value	of	Entergy Corporation	common	stock	at	the	end	of	the	deferral	period.

# Equity	Compensation	Plan	Information

The	following	table	summarizes	the	equity	compensation	plan	information	as	of	December	31,	2013.	Information	is	included	for	equity compensation	plans	approved	by	the	stockholders	and	equity	compensation	plans	not	approved	by	the	stockholders.

| Plan | Number	of	Securities	to<br>be	Issued	Upon	Exercise<br>of	Outstanding	Options<br>(a) | Weighted<br>Average<br>Exercise<br>Price<br>(b) | Number	of	Securities<br>Remaining	Available	for<br>Future	Issuance	(excluding<br>securities	reflected	in<br>column	(a))<br>(c) |
| :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans\n\t\tapproved\tby\tsecurity\tholders\t(1) | 9,639,849 | $80.06 | 4,859,094 |
| Equity\tcompensation\tplans\tnot\n\t\tapproved\tby\tsecurity\tholders(2) | — | — | — |
| Total | 9,639,849 | $80.06 | 4,859,094 |

(1) Includes	the	Equity	Ownership	Plan,	which	was	approved	by	the	shareholders	on	May	15,	1998,	the	2007	Equity	Ownership	Plan	and	the 2011	Equity	Ownership	Plan.		The	2007	Equity	Ownership	Plan	was	approved	by	Entergy	Corporation	shareholders	on	May	12,	2006,	and 7,000,000	shares	of	Entergy	Corporation	common	stock	can	be	 issued,	with	no	more	 than	2,000,000	shares	available	for	non-option grants.		The	2011	Equity	Ownership	Plan	was	approved	by	Entergy	Corporation	shareholders	on	May	6,	2011,	and	5,500,000	shares	of Entergy	Corporation	common	stock	can	be	issued	from	the	2011	Equity	Ownership	Plan,	with	no	more	than	2,000,000	shares	available	for incentive	stock	option	grants.		The	Equity	Ownership	Plan,	the	2007	Equity	Ownership	Plan	and	the	2011	Equity	Ownership	Plan	(the "Plans")	are	administered	by	the	Personnel	Committee	of	the	Board	of	Directors	(other	than	with	respect	to	awards	granted	to	non-employee directors,	which	awards	are	administered	by	the	entire	Board	of	Directors).		Eligibility	under	the	Plans	is	limited	to	the	non-employee directors	and	to	the	officers	and	employees	of	an	Entergy	System	employer	and	any	corporation	80%	or	more	of	whose	stock	(based	on voting	power)	or	value	is	owned,	directly	or	indirectly,	by	Entergy	Corporation.		The	Plans	provide	for	the	issuance	of	stock	options, restricted	shares,	equity	awards	(units	whose	value	is	related	to	the	value	of	shares	of	the	Common	Stock	but	do	not	represent	actual	shares of	Common	Stock),	performance	awards	(performance	shares	or	units	valued	by	reference	to	shares	of	Common	Stock	or	performance	units valued	by	reference	to	financial	measures	or	property	other	than	Common	Stock)	and	other	stock-based	awards.

(2) Entergy	has	a	Board-approved	stock-based	compensation	plan.	However,	effective	May	9,	2003,	the	Board	has	directed	that	no	further awards	be	issued	under	that	plan.	As	of	December	31,	2013,	all	options	outstanding	under	the	plan	were	either	exercised	or	expired.

# Item	13.		Certain	Relationships	and	Related	Transactions	and	Director	Independence

For	information	regarding	certain	relationships,	related	transactions	and	director	independence	of	Entergy	Corporation,	see	the	Proxy	Statement	under	the headings	"Corporate	Governance	-	Director	Independence"	and	"Transactions	with	Related	Persons,"	which	information	is	incorporated	herein	by	reference.

Since	December	31,	2011,	none	of	the	Subsidiaries	or	any	of	their	affiliates	has	participated	in	any	transaction	involving	an	amount	in	excess	of	$120,000	in which	any	director	or	executive	officer	of	any	of	the	Subsidiaries,	any	nominee	for	director,	or	any	immediate	family	member	of	the	foregoing	had	a	material	interest	as contemplated	by	Item	404(a)	of	Regulation	S-K	("Related	Party	Transactions").

Entergy	 Corporation's	 Board	 of	 Directors	 has	 adopted	 written	 policies	 and procedures for the review, approval or ratification of	 Related Party Transactions.		Under	these	policies	and	procedures,	the	Corporate	Governance	Committee,	or	a

subcommittee	of	the	Board	of	Directors	of	Entergy	Corporation	composed	of	independent	directors,	reviews	the	transaction	and	either	approves	or	rejects	the	transaction after	taking	into	account	the	following	factors:

•Whether	the	proposed	transaction	is	on	terms	at	least	as	favorable	to	Entergy	Corporation	or	the	subsidiary	as	those	achievable	with	an	unaffiliated	third party;

•Size	of	transaction	and	amount	of	consideration;

•Nature	of	the	interest;

•Whether	the	transaction	involves	a	conflict	of	interest;

•Whether	the	transaction	involves	services	available	from	unaffiliated	third	parties;

•Any	other	factors	that	the	Corporate	Governance	Committee	or	subcommittee	deems

relevant.

The	policy	does	not	apply	to	(a)	compensation	and	Related	Party	Transactions	involving	a	director	or	an	executive	officer	solely	resulting	from	that	person's service	as	a	director	or	employment	with	the	Company	so	long	as	the	compensation	is	approved	by	Entergy's	Board	of	Directors,	(b)	transactions	involving	the	rendering of	services	as	a	public	utility	at	rates	or	charges	fixed	in	conformity	with	law	or	governmental	authority	or	(c)	any	other	categories	of	transactions	currently	or	in	the future	excluded	from	the	reporting	requirements	of	Item	404(a)	of	Regulation	SK.

None	of	the	Subsidiaries	are	listed	issuers.		As	previously	noted,	the	Boards	of	Directors	of	the	Subsidiaries	are	composed	solely	of	employee	directors.		None of	the	Boards	of	Directors	of	any	of	the	Subsidiaries	has	any	committees.

# Item	14.		Principal	Accountant	Fees	and	Services	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy

# Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Aggregate	 fees	 billed	 to	 Entergy	 Corporation	 (consolidated),	 Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy	 Louisiana, Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	for	the	years	ended	December	31,	2013	and	2012	by	Deloitte	& Touche	LLP	were	as	follows:

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| Entergy\tCorporation\t(consolidated) |  |  |
| Audit\tFees | $9,832,698 | $11,162,397 |
| Audit-Related\tFees\t(a) | 545,000 | 540,000 |
| Total\taudit\tand\taudit-related\tfees | 10,377,698 | 11,702,397 |
| Tax\tFees\t(b) | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $10,377,698 | $11,702,397 |
| Entergy\tArkansas |  |  |
| Audit\tFees | $985,484 | $992,666 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 985,484 | 992,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $985,484 | $992,666 |
| Entergy\tGulf\tStates\tLouisiana |  |  |
| Audit\tFees | $840,484 | $905,666 |
| Audit-Related\tFees\t(a) | 100,000 | 80,000 |
| Total\taudit\tand\taudit-related\tfees | 940,484 | 985,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $940,484 | $985,666 |
| Entergy\tLouisiana |  |  |
| Audit\tFees | $985,484 | $1,032,666 |
| Audit-Related\tFees\t(a) | 100,000 | 80,000 |
| Total\taudit\tand\taudit-related\tfees | 1,085,484 | 1,112,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $1,085,484 | $1,112,666 |

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| Entergy\tMississippi |  |  |
| Audit\tFees | $840,484 | $945,666 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 840,484 | 945,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $840,484 | $945,666 |
| Entergy\tNew\tOrleans |  |  |
| Audit\tFees | $885,484 | $945,666 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 885,484 | 945,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $885,484 | $945,666 |
| Entergy\tTexas |  |  |
| Audit\tFees | $1,886,280 | $998,666 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 1,886,280 | 998,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $1,886,280 | $998,666 |
| System\tEnergy |  |  |
| Audit\tFees | $840,484 | $945,666 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 840,484 | 945,666 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(c) | $840,484 | $945,666 |

(a) Includes	fees	for	employee	benefit	plan	audits,	consultation	on	financial	accounting	and	reporting,	and	other	attestation	services.

(b) Includes	fees	for	tax	advisory	services.

(c) 100%	of	fees	paid	in	2013	and	2012	were	pre-approved	by	the	Entergy	Corporation	Audit	Committee.

# Entergy	Audit	Committee	Guidelines	for	Pre-approval	of	Independent	Auditor	Services

The	Audit	Committee	has	adopted	the	following	guidelines	regarding	the	engagement	of	Entergy's	independent	auditor	to	perform	services	for	Entergy:

1. The	independent	auditor	will	provide	the	Audit	Committee,	for	approval,	an	annual	engagement	letter	outlining	the	scope	of	services	proposed	to	be performed	during	the	fiscal	year,	including	audit	services	and	other	permissible	non-audit	services	(e.g.	audit-related	services,	tax	services,	and	all	other services).

2. For	other	permissible	services	not	included	in	the	engagement	letter,	Entergy	management	will	submit	a	description	of	the	proposed	service,	including	a budget	estimate,	to	the	Audit	Committee	for	pre-approval.		Management	and	the	independent	auditor	must	agree	that	the	requested	service	is	consistent with	the	SEC's	rules	on	auditor	independence	prior	to	submission	to	the	Audit	Committee.		The	Audit	Committee,	at	its	discretion,	will	pre-approve permissible	services	and	has	established	the	following	additional	guidelines	for	permissible	non-audit	services	provided	by	the	independent	auditor:

•Aggregate	non-audit	service	fees	are	targeted	at	fifty	percent	or	less	of	the	approved	audit	service

•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	 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	and	Financial	Statement	Schedules

(a)1. Financial	 Statements	 and	 Independent	Auditors'	 Reports	 for	 Entergy,	 Entergy	Arkansas,	 Entergy	 Gulf	 States	 Louisiana,	 Entergy Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	are	listed	in	the	Table	of	Contents.

# (a)2. Financial	Statement	Schedules

Report	of	Independent	Registered	Public	Accounting	Firm	(see	page	531)

Financial	Statement	Schedules	are	listed	in	the	Index	to	Financial	Statement	Schedules	(see	page	S-1)

Exhibits	for	Entergy,	Entergy	Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans, Entergy	Texas,	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.

By		/s/	Alyson	M.	Mount

Senior	Vice	President	and	Chief	Accounting	Officer

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

Leo	P.	Denault	(Chairman	of	the	Board,	Chief	Executive	Officer	and	Director;	Principal	Executive	Officer);	Andrew	S.	Marsh	(Executive Vice	President	and	Chief	Financial	Officer;	Principal	Financial	Officer);	Maureen	S.	Bateman,	Kirkland	H.	Donald,	Gary	W.	Edwards,	Alexis	M. Herman,	Donald	C.	Hintz,	Stuart	L.	Levenick,	Blanche	L.	Lincoln,	Stewart	C.	Myers,	W.	J.	Tauzin,	and	Steven	V.	Wilkinson	(Directors).

(Alyson	M.	Mount,	Attorney-in-fact)

# ENTERGY	ARKANSAS,	INC.

Bunting,	Jr.,	Andrew	S.	Marsh,	and	Mark	T.	Savoff	(Directors).

# ENTERGY	LOUISIANA,	LLC

# ENTERGY	TEXAS,	INC.

Jeffrey	S.	Forbes	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Wanda	C.	Curry (Vice	President,	Chief	Financial	Officer	-	Nuclear	Operations;	Principal	Financial	Officer);	Andrew	S.	Marsh	and	Steven	C.	McNeal	(Directors).

# CONSENTS	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-02	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	consolidated	financial	statements	and	financial	statement	schedule	of	Entergy	Arkansas,	Inc.	and	Subsidiaries,	and	the	effectiveness of	Entergy	Arkansas,	Inc.	and	Subsidiaries'	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy Arkansas,	Inc.	for	the	year	ended	December	31,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-01	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	financial	statements	and	financial	statement	schedule	of	Entergy	Gulf	States	Louisiana,	L.L.C.,	and	the	effectiveness	of	Entergy Gulf	States	Louisiana,	L.L.C.'s	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Gulf	States Louisiana,	L.L.C.	for	the	year	ended	December	31,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-07	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	 to	 the	 consolidated	 financial	 statements	 and	 financial	 statement	 schedule	 of	 Entergy	 Louisiana,	 LLC	 and	 Subsidiaries,	 and	 the effectiveness	of	Entergy	Louisiana,	LLC	and	Subsidiaries'	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form 10-K	of	Entergy	Louisiana,	LLC	for	the	year	ended	December	31,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-06	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	financial	statements	and	financial	statement	schedule	of	Entergy	Mississippi,	Inc.,	and	the	effectiveness	of	Entergy	Mississippi, Inc.'s	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Mississippi,	Inc.	for	the	year	ended December	31,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-05	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	financial	statements	and	financial	statement	schedule	of	Entergy	New	Orleans,	Inc.,	and	the	effectiveness	of	Entergy	New	Orleans, Inc.'s	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,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-04	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	consolidated	financial	statements	and	financial	statement	schedule	of	Entergy	Texas,	Inc.	and	Subsidiaries,	and	the	effectiveness	of Entergy	Texas,	Inc.	and	Subsidiaries'	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Texas, Inc.	for	the	year	ended	December	31,	2013.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-190911-03	on	Form	S-3	of	our	reports	dated	February	27,	2014, relating	to	the	financial	statements	of	System	Energy	Resources,	Inc.,	and	the	effectiveness	of	System	Energy	Resources,	Inc.'s	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,	2013.

Entergy	Mississippi,	Inc. Entergy	New	Orleans,	Inc.

We	have	audited	the	consolidated	financial	statements	of	Entergy	Corporation	and	Subsidiaries,	Entergy	Arkansas,	Inc.	and	Subsidiaries,	Entergy Louisiana,	LLC	and	Subsidiaries,	and	Entergy	Texas,	Inc.	and	Subsidiaries,	and	we	have	also	audited	the	financial	statements	of	Entergy	Gulf States	Louisiana,	L.L.C.,	Entergy	Mississippi,	Inc.,	and	Entergy	New	Orleans,	Inc.	(collectively	the	"Companies")	as	of	December	31,	2013	and 2012,	and	for	each	of	the	three	years	in	the	period	ended	December	31,	2013,	and	the	respective	Companies'	internal	control	over	financial reporting	as	of	December	31,	2013,	and	have	issued	our	reports	thereon	dated	February	27,	2014;	such	financial	statements	and	reports	are included	elsewhere	in	this	Form	10-K.	Our	audits	also	included	the	financial	statement	schedules	of	the	respective	Companies	listed	in	Item	15. These	financial	statement	schedules	are	the	responsibility	of	the	respective	Companies'	managements.	Our	responsibility	is	to	express	an	opinion based	on	our	audits.	In	our	opinion,	such	financial	statement	schedules,	when	considered	in	relation	to	the	basic	financial	statements	taken	as	a whole,	present	fairly,	in	all	material	respects,	the	information	set	forth	therein.

# 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	II	-	VALUATION	AND	QUALIFYING	ACCOUNTS

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\tof\nPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\n\tof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $31,956 | $2,355 | $— | $34,311 |
| 2012 | $31,159 | $2,448 | $1,651 | $31,956 |
| 2011 | $31,777 | $512 | $1,130 | $31,159 |

are	reduced	by	recoveries	of	amounts	previously	written	off.

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\tof\nPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\nof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $28,343 | $1,770 | $— | $30,113 |
| 2012 | $26,155 | $2,188 | $— | $28,343 |
| 2011 | $24,402 | $1,753 | $— | $26,155 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\tof\nPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\nof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $711 | $198 | $— | $909 |
| 2012 | $843 | $123 | $255 | $711 |
| 2011 | $1,306 | ($235) | $228 | $843 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\tof\nPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\nof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $867 | $98 | $— | $965 |
| 2012 | $1,147 | $121 | $401 | $867 |
| 2011 | $1,961 | ($453) | $361 | $1,147 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\nof\tPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\n\tof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $910 | ($4) | $— | $906 |
| 2012 | $756 | $154 | $— | $910 |
| 2011 | $985 | ($229) | $— | $756 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\nof\tPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\nof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $446 | $528 | $— | $974 |
| 2012 | $465 | $12 | $31 | $446 |
| 2011 | $734 | ($241) | $28 | $465 |

| For	the	Years	Ended	December	31,	2013,	2012,	and	2011 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tThousands) |  |  |  |  |
| Column\tA | Column\tB | Column\tC | Column\tD | Column\tE |
|  |  |  | Other |  |
|  | Balance\tat | Additions | Changes | Balance |
| Description | Beginning\nof\tPeriod | Charged\tto\nIncome | Deductions\t(1) | at\tEnd\nof\tPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2013 | $680 | ($237) | $— | $443 |
| 2012 | $1,461 | ($21) | $760 | $680 |
| 2011 | $2,185 | ($212) | $512 | $1,461 |

# 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	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	15	of	Form	10-K.

Some	of	the	agreements	included	or	incorporated	by	reference	as	exhibits	to	this	Form	10-K	contain	representations	and	warranties	by each	of	the	parties	to	the	applicable	agreement.		These	representations	and	warranties	were	made	solely	for	the	benefit	of	the	other	parties	to	the applicable	agreement	and	(i)	were	not	intended	to	be	treated	as	categorical	statements	of	fact,	but	rather	as	a	way	of	allocating	the	risk	to	one	of	the parties	if	those	statements	prove	to	be	inaccurate;	(ii)	may	have	been	qualified	in	such	agreement	by	disclosures	that	were	made	to	the	other	party in	connection	with	the	negotiation	of	the	applicable	agreement;	(iii)	may	apply	contract	standards	of	"materiality"	that	are	different	from	the standard	of	"materiality"	under	the	applicable	securities	laws;	and	(iv)	were	made	only	as	of	the	date	of	the	applicable	agreement	or	such	other date	or	dates	as	may	be	specified	in	the	agreement.

Entergy	acknowledges	that,	notwithstanding	the	inclusion	of	the	foregoing	cautionary	statements,	it	is	responsible	for	considering	whether additional	specific	disclosures	of	material	information	regarding	material	contractual	provisions	are	required	to	make	the	statements	in	this	Form 10-K	not	misleading.

# (2)	Plan	of	Acquisition,	Reorganization,	Arrangement,	Liquidation	or	Succession

# (3)	Articles	of	Incorporation	and	By-laws

(b)	1	-- 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)(h)	below	for	 instruments	defining	 the	rights	of	holders	of	 long-term	debt	of	System	Energy,	Entergy Arkansas,	Entergy	Gulf	States	Louisiana,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas.

(a)	2	-- Credit	Agreement	($3,500,000,000),	dated	as	of	March	9,	2012,	among	Entergy	Corporation,	as	borrower,	the	Banks	named	therein (Citibank,	N.A.,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank of	Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	Union	Bank,	N.A.,	Barclays	Bank	PLC,	Goldman	Sachs	Bank	USA, KeyBank	National	Association,	Morgan	Stanley	Bank,	N.A.,	The	Royal	Bank	of	Scotland	plc,	BNP	Paribas,	Bank	of	the	West, The	Bank	of	New	York	Mellon,	CoBank,	ACB,	Deutsche	Bank	AG	New	York	Branch,	Regions	Bank,	Sumitomo	Mitsui	Banking Corporation,	U.S.	Bank	National	Association,	SunTrust	Bank,	National	Cooperative	Services	Corporation,	and	The	Northern	Trust Company),	Citibank,	N.A.,	as	Administrative	Agent	and	LC	Issuing	Bank,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank, National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of	Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	and Union	Bank,	N.A.,	as	LC	Issuing	Banks,	and	the	other	LC	Issuing	Banks	from	time	to	time	parties	thereto	(4.1	to	Form	8-K	filed March	14,	2012	in	1-11299).

(a)	3	-- Indenture	(For	Unsecured	Debt	Securities),	dated	as	of	September	1,	2010,	between	Entergy	Corporation	and	Wells	Fargo	Bank, National	Association	(4.01	to	Form	8-K	filed	September	16,	2010	in	1-11299).

*(a)	7	-- Officer's	Certificate	for	Entergy	Corporation	relating	to	4.50%	Senior	Note	due	December	16,	2028.

(c)	2	-- Credit	Agreement	($150,000,000),	dated	as	of	March	9,	2012,	among	Entergy	Arkansas,	Inc.,	as	borrower,	the	Banks	named	therein (Citibank,	N.A.,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	Union	Bank,	N.A.,	Barclays	Bank	PLC,	Goldman	Sachs	Bank	USA,	KeyBank National	Association,	Morgan	Stanley	Bank,	N.A.,	The	Royal	Bank	of	Scotland	plc,	BNP	Paribas,	The	Bank	of	New	York	Mellon, CoBank,	ACB,	Deutsche	Bank	AG	New	York	Branch,	Regions	Bank,	Sumitomo	Mitsui	Banking	Corporation,	U.S.	Bank	National Association,	SunTrust	Bank,	and	National	Cooperative	Services	Corporation),	Citibank,	N.A.,	as	Administrative	Agent	and	LC	Issuing Bank,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of	Nova	Scotia, The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	and	Union	Bank,	N.A.,	as	LC	Issuing	Banks,	and	the	other	LC	Issuing	Banks	from	time	to time	parties	thereto	(4.2	to	Form	8-K	filed	March	14,	2012	in	1-10764).

(c)	3	-- Credit	Agreement	($250,000,000),	dated	as	of	July	26,	2013,	among	Entergy	Arkansas,	Inc.,	as	borrower,	the	Banks	named	therein (Canadian	Imperial	Bank	of	Commerce,	New	York	Agency,	SunTrust	Bank,	and	Union	Bank,	N.A.),	and	Wells	Fargo	Bank,	National Association,	as	Administrative	Agent	(4.01	to	Form	8-K	filed	July	26,	2013	in	1-10764).

(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	-- Agreement	of	Resignation,	Appointment	and	Acceptance,	dated	as	of	October	3,	2007,	among	Entergy	Gulf	States,	Inc.,	JPMorgan Chase	Bank,	National	Association,	as	resigning	trustee,	and	The	Bank	of	New	York,	as	successor	trustee	(4(a)	to	Form	10-Q	for	the quarter	ended	September	30,	2007	in	1-27031).

(d)	5	-- Credit	Agreement	($150,000,000),	dated	as	of	March	9,	2012,	among	Entergy	Gulf	States	Louisiana,	L.L.C.,	as	borrower,	the	Banks named	therein	(Citibank,	N.A.,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd., The	Bank	of	Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	Union	Bank,	N.A.,	Barclays	Bank	PLC,	Goldman	Sachs	Bank USA,	KeyBank	National	Association,	Morgan	Stanley	Bank,	N.A.,	The	Royal	Bank	of	Scotland	plc,	BNP	Paribas,	The	Bank	of	New York	Mellon,	CoBank,	ACB,	Deutsche	Bank	AG	New	York	Branch,	Regions	Bank,	Sumitomo	Mitsui	Banking	Corporation,	U.S. Bank	National	Association,	SunTrust	Bank,	and	National	Cooperative	Services	Corporation),	Citibank,	N.A.,	as	Administrative	Agent and	LC	Issuing	Bank,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank of	Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	and	Union	Bank,	N.A.,	as	LC	Issuing	Banks,	and	the	other	LC	Issuing	Banks from	time	to	time	parties	thereto	(4.3	to	Form	8-K	filed	March	14,	2012	in	0-20371).

(e)	2	-- Facility	Lease	No.	1,	dated	as	of	September	1,	1989,	between	First	National	Bank	of	Commerce,	as	Owner	Trustee,	and	Entergy Louisiana	(4(c)-1	in	Registration	No.	33-30660),	as	supplemented	by	Lease	Supplement	No.	1	dated	as	of	July	1,	1997	(attached	to Refunding	Agreement	No.	1,	dated	as	of	June	27,	1997,	with	such	Refunding	Agreement	filed	as	Exhibit	2	to	Current	Report	on	Form 8-K,	dated	July	14,	1997	in	1-8474).

(e)	3	-- Facility	Lease	No.	2,	dated	as	of	September	1,	1989,	between	First	National	Bank	of	Commerce,	as	Owner	Trustee,	and	Entergy Louisiana	(4(c)-2	in	Registration	No.	33-30660),	as	supplemented	by	Lease	Supplemental	No.	1	dated	as	of	July	1,	1997	(attached	to Refunding	Agreement	No.	2,	dated	as	of	June	27,	1997,	with	such	Refunding	Agreement	filed	as	Exhibit	3	to	Current	Report	on	Form 8-K,	dated	July	14,	1997	in	1-8474).

(e)	5	-- Credit	Agreement	($200,000,000),	dated	as	of	March	9,	2012,	among	Entergy	Louisiana,	LLC,	as	borrower,	the	Banks	named	therein (Citibank,	N.A.,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	Union	Bank,	N.A.,	Barclays	Bank	PLC,	Goldman	Sachs	Bank	USA,	KeyBank National	Association,	Morgan	Stanley	Bank,	N.A.,	The	Royal	Bank	of	Scotland	plc,	BNP	Paribas,	The	Bank	of	New	York	Mellon, CoBank,	ACB,	Deutsche	Bank	AG	New	York	Branch,	Regions	Bank,	Sumitomo	Mitsui	Banking	Corporation,	U.S.	Bank	National Association,	SunTrust	Bank,	and	National	Cooperative	Services	Corporation),	Citibank,	N.A.,	as	Administrative	Agent	and	LC	Issuing Bank,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of	Nova	Scotia, The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	and	Union	Bank,	N.A.,	as	LC	Issuing	Banks,	and	the	other	LC	Issuing	Banks	from	time	to time	parties	thereto	(4.4	to	Form	8-K	filed	March	14,	2012	in	1-32718).

(h)	1	-- Credit	Agreement	($150,000,000),	dated	as	of	March	9,	2012,	among	Entergy	Texas,	Inc.,	as	borrower,	the	Banks	named	therein (Citibank,	N.A.,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of Nova	Scotia,	The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	Union	Bank,	N.A.,	Barclays	Bank	PLC,	Goldman	Sachs	Bank	USA,	KeyBank National	Association,	Morgan	Stanley	Bank,	N.A.,	The	Royal	Bank	of	Scotland	plc,	BNP	Paribas,	The	Bank	of	New	York	Mellon, CoBank,	ACB,	Deutsche	Bank	AG	New	York	Branch,	Regions	Bank,	Sumitomo	Mitsui	Banking	Corporation,	U.S.	Bank	National Association,	SunTrust	Bank,	and	National	Cooperative	Services	Corporation),	Citibank,	N.A.,	as	Administrative	Agent	and	LC	Issuing Bank,	JPMorgan	Chase	Bank,	N.A.,	Wells	Fargo	Bank,	National	Association,	Mizuho	Corporate	Bank,	Ltd.,	The	Bank	of	Nova	Scotia, The	Bank	of	Tokyo-Mitsubishi	UFJ,	Ltd.,	and	Union	Bank,	N.A.,	as	LC	Issuing	Banks,	and	the	other	LC	Issuing	Banks	from	time	to time	parties	thereto	(4.5	to	Form	8-K	filed	March	14,	2012	in	1-34360).

(h)	7	-- Officer's	Certificate	No.	5-B-4	dated	September	7,	2011,	supplemental	to	Indenture,	Deed	of	Trust	and	Security	Agreement	dated	as	of October	1,	2008,	between	Entergy	Texas,	Inc.	and	The	Bank	of	New	York	Mellon,	as	trustee	(4.40	to	Form	8-K	dated	September	13, 2011	in	1-34360).

# (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)	7	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services.

(a)	13	-- 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)	15	-- Thirty-seventh	Assignment	of	Availability	Agreement,	Consent	and	Agreement,	dated	as	of	September	1,	2012,	among	System Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	The	Bank	of	New	York	Mellon,	as successor	trustee	(10(a)15	to	Form	10-K	for	the	year	ended	December	31,	2012	in	1-11299).

(a)	19	-- Thirty-seventh	 Supplementary	 Capital	 Funds	 Agreement	 and	 Assignment,	 dated	 as	 of	 September	 1,	 2012,	 among	 Entergy Corporation,	System	Energy,	and	The	Bank	of	New	York	Mellon,	as	successor	trustee	(10(a)19	to	Form	10-K	for	the	year	ended December	31,	2012	in	1-11299).

(a)	20	-- 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)	21	-- 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)	22	-- 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)	31	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(a)	32	-- 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)	34	-- Middle	South	Utilities	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	April	28,	1988	(D- 1	to	Form	U5S	for	the	year	ended	December	31,	1987).

(a)	35	-- First	Amendment,	dated	January	1,	1990,	to	the	Middle	South	Utilities	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax Allocation	Agreement	(D-2	to	Form	U5S	for	the	year	ended	December	31,	1989).

(a)	36	-- Second	Amendment	dated	January	1,	1992,	to	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax Allocation	Agreement	(D-3	to	Form	U5S	for	the	year	ended	December	31,	1992).

(a)	37	-- Third	Amendment	dated	January	1,	1994	to	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement	(D-3(a)	to	Form	U5S	for	the	year	ended	December	31,	1993).

(a)	38	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement	(D-5	to	Form	U5S	for	the	year	ended	December	31,	1996).

+(a)	46	-- 2007	Equity	Ownership	and	Long	Term	Cash	Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries	(Effective	for	Grants	and Elections	On	or	After	January	1,	2007)	(Appendix	B	to	Entergy	Corporation's	Definitive	Proxy	Statement	filed	on	March	24,	2006 in	1-11299).

+(a)	50	-- Amended	and	Restated	1998	Equity	Ownership	Plan	of	Entergy	Corporation	and	Subsidiaries	(Effective	for	Grants	and	Elections After	February	13,	2003)	(10(a)	to	Form	10-Q	for	the	quarter	ended	March	31,	2003	in	1-11299).

+(a)	54	-- 2011	Equity	Ownership	and	Long	Term	Cash	Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries	(Annex	A to	Entergy Corporation's	Definitive	Proxy	Statement	filed	on	March	24,	2011	in	1-11299).

+(a)	58	-- Defined	Contribution	Restoration	Plan	of	Entergy	Corporation	and	Subsidiaries,	as	amended	and	restated	effective	January	1,	2009 (10(a)59	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	59	-- First	Amendment	of	the	Defined	Contribution	Restoration	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	December	30, 2010	(10(a)60	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	60	-- Second	Amendment	of	the	Defined	Contribution	Restoration	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	January	27, 2011	(10(a)60	to	Form	10-K	for	the	year	ended	December	31,	2011	in	1-11299).

+(a)	62	-- Executive	Deferred	Compensation	Plan	of	Entergy	Corporation	and	Subsidiaries,	as	amended	and	restated	effective	January	1, 2009	(10(a)62	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	63	-- First	Amendment	of	the	Executive	Deferred	Compensation	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	December	30, 2010	(10(a)63	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	64	-- Second	Amendment	of	the	Executive	Deferred	Compensation	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	January	27, 2011	(10(a)64	to	Form	10-K	for	the	year	ended	December	31,	2011	in	1-11299).

+(a)	66-- First	Amendment	of	the	System	Executive	Continuity	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	January	1,	2010 (10(a)78	to	Form	10-K	for	the	year	ended	December	31,	2009	in	1-11299).

+(a)	76	-- Service	Recognition	Program	for	Non-Employee	Outside	Directors	of	Entergy	Corporation	and	Subsidiaries,	as	amended	and restated	effective	June	1,	2012	(10(a)	to	Form	10-Q	for	the	quarter	ended	September	30,	2012	in	1-11299).

*+(a)	81-- Third	Amendment	of	the	System	Executive	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	January	26,	2012.

+(a)	98	-- Entergy	 Corporation	 Outside	 Director	 Stock	 Program	 Established	 under	 the	 2011	 Equity	 Ownership	 and	 Long	 Term	 Cash Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries	(10(b)	to	Form	10-Q	for	the	quarter	ended	June	30,	2011	in	1-11299).

+(a)	99	-- First	Amendment	to	Entergy	Corporation	Outside	Director	Stock	Program	Established	under	the	2011	Equity	Ownership	and	Long Term	Cash	Incentive	Plan	of	Entergy	Corporation	Subsidiaries	(10(b)	to	Form	10-Q	for	the	quarter	ended	September	30,	2012	in	1- 11299).

+(a)	101	-- Executive	Annual	Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries	as	amended	and	restated	effective	January	1,	2010 (Annex	A	to	Entergy	Corporation's	Definitive	Proxy	Statement	filed	on		March	17,	2010	in	1-11299).

*+(a)103- Form	of	Stock	Option	Grant	Letter.

*+(a)104- Form	of	Long	Term	Incentive	Program	Performance	Unit	Grant	Letter.

*+(a)105- Form	of	Restricted	Stock	Grant	Letter.

*+(a)109- Restricted	Unit	Agreement	between	Jeffrey	S.	Forbes	and	Entergy	Corporation.

(b)	27	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(b)	28	-- First	Amendment	to	the	Unit	Power	Sales	Agreement,	dated	as	of	June	28,	1984,	between	System	Energy	and	Entergy	Arkansas, Entergy	Louisiana,	Entergy	Mississippi	and	Entergy	New	Orleans	(19	to	Form	10-Q	for	the	quarter	ended	September	30,	1984	in 1-3517).

(b)	34	-- 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)	35	-- Middle	South	Utilities,	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	April	28,	1988	(D- 1	to	Form	U5S	for	the	year	ended	December	31,	1987).

(b)	36	-- 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)	37	-- Second	Amendment	dated	January	1,	1992,	to	the	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax Allocation	Agreement	(D-3	to	Form	U5S	for	the	year	ended	December	31,	1992).

(b)	38	-- Third	Amendment	dated	January	1,	1994	to	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement	(D-3(a)	to	Form	U5S	for	the	year	ended	December	31,	1993).

(b)	39	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement	(D-5	to	Form	U5S	for	the	year	ended	December	31,	1996).

*(b)	44	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services.

(b)	47	-- 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).

(c)	1	-- Agreement,	dated	April	23,	1982,	among	Entergy	Arkansas	and	certain	other	System	companies,	relating	to	System	Planning	and Development	and	Intra-System	Transactions	(10(a)	1	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

*(c)	5	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement,	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services,	Service	Agreement	for	Generation	Planning	and	Operational	Support Services,	and	Service	Agreement	for	Transmission	Planning	and	Reliability	Support	Services.

(c)	26	-- Contract,	dated	May	28,	1943,	Amendment	to	Contract,	dated	July	21,	1949,	and	Supplement	to	Amendment	to	Contract,	dated December	30,	1949,	between	Entergy	Arkansas	and	McKamie	Gas	Cleaning	Company;	Agreements,	dated	as	of	September	30, 1965,	between	Entergy	Arkansas	and	former	stockholders	of	McKamie	Gas	Cleaning	Company;	and	Letter	Agreement,	dated	June 22,	1966,	by	Humble	Oil	&	Refining	Company	accepted	by	Entergy	Arkansas	on	June	24,	1966	(5(k)7	in	2-41080).

(c)	28	-- 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)	29	-- 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)	32	-- 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)	33	-- 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)	35	-- 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)	39	-- 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)	40	-- 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)	41	-- 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)	44	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi,	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(c)	45	-- 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)	48	-- Middle	South	Utilities,	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	April	28,	1988	(D- 1	to	Form	U5S	for	the	year	ended	December	31,	1987).

(c)	49	-- 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)	50	-- 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)	51	-- 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)	52	-- 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)	59	-- Agreement	for	Purchase	and	Sale	of	Independence	Unit	2	between	Entergy	Arkansas	and	Entergy	Power,	dated	as	of	August	28, 1990	(B-3(c)	to	Rule	24	Certificate	dated	September	6,	1990	in	70-7684).

(c)	61	-- Ritchie	Steam	Electric	Station	Unit	No.	2	Operating	Agreement	between	Entergy	Arkansas	and	Entergy	Power,	dated	as	of August	28,	1990	(B-5(a)	to	Rule	24	Certificate	dated	September	6,	1990	in	70-7684).

(c)	62	-- Ritchie	Steam	Electric	Station	Unit	No.	2	Ownership	Agreement	between	Entergy	Arkansas	and	Entergy	Power,	dated	as	of August	28,	1990	(B-6(a)	to	Rule	24	Certificate	dated	September	6,	1990	in	70-7684).

(c)	63	-- Power	Coordination,	Interchange	and	Transmission	Service	Agreement	between	Entergy	Power	and	Entergy	Arkansas,	dated	as	of August	28,	1990	(10(c)71	to	Form	10-K	for	the	year	ended	December	31,	1990	in	1-10764).

(c)	64	-- Loan	Agreement,	dated	as	of	January	1,	2013,	between	Jefferson	County,	Arkansas	and	Entergy	Arkansas	relating	to	Revenue Bonds	(Entergy	Arkansas,	Inc.	Project)	Series	2013	(4(b)	to	Form	8-K	filed	January	9,	2013	in	1-10764).

(c)	65	-- Loan	Agreement,	dated	as	of	January	1,	2013,	between	Independence	County,	Arkansas	and	Entergy	Arkansas	relating	to	Revenue Bonds	(Entergy	Arkansas,	Inc.	Project)	Series	2013	(4(d)	to	Form	8-K	filed	January	9,	2013	in	1-10764).

(d)	1	-- Agreement	effective	February	1,	1964,	between	Sabine	River	Authority,	State	of	Louisiana,	and	Sabine	River	Authority	of	Texas, and	Entergy	Gulf	States,	Inc.,	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)	2	-- Joint	Ownership	Participation	and	Operating	Agreement	regarding	River	Bend	Unit	1	Nuclear	Plant,	dated	August	20,	1979, between	Entergy	Gulf	States,	Inc.,	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,	Inc.	and	Cajun;	and	Letter	Agreement	regarding	CEPCO buybacks,	dated	August	28,	1979,	between	Entergy	Gulf	States,	Inc.	and	Cajun	(2,	3,	and	4,	respectively,	to	Form	8-K	dated September	7,	1979	in	1-27031).

(d)	6	-- Agreements	between	Southern	Company	and	Entergy	Gulf	States,	Inc.,	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)	8	-- 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,	Inc.,	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)	10	-- Trust	Agreement	for	Deferred	Payments	to	be	made	by	Entergy	Gulf	States,	Inc.	pursuant	to	the	Executive	Income	Security	Plan, by	and	between	Entergy	Gulf	States,	Inc.	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)	11	-- Trust	Agreement	 for	 Deferred	 Installments	 under	 Entergy	 Gulf	 States,	 Inc.	 Management	 Incentive	 Compensation	 Plan	 and Administrative	Guidelines	by	and	between	Entergy	Gulf	States,	Inc.	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)	12	-- 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)	13	-- Trust	Agreement	for	Entergy	Gulf	States,	Inc.	Nonqualified	Directors	and	Designated	Key	Employees	by	and	between	Entergy Gulf	States,	Inc.	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)	15	-- Trust	and	Investment	Management	Agreement	between	Entergy	Gulf	States,	Inc.	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,	Inc.,	dated	March	15,	1989	(10-66	to	Form	10-K	for	the	year	ended	December	31,	1988	in	1-27031).

(d)	20	-- Partnership	Agreement	by	and	among	Conoco	Inc.,	and	Entergy	Gulf	States,	Inc.,	CITGO	Petroleum	Corporation	and	Vista Chemical	Company,	dated	April	28,	1988	(10-67	to	Form	10-K	for	the	year	ended	December	31,	1988	in	1-27031).

+(d)	22	-- Trust	Agreement	for	Entergy	Gulf	States,	Inc.	Executive	Continuity	Plan,	by	and	between	Entergy	Gulf	States,	Inc.	and	First	City Bank,	Texas-Beaumont,	N.A.	(now	Texas	Commerce	Bank),	effective	May	20,	1991	(10-5	to	Form	10-K	for	the	year	ended December	31,	1992	in	1-27031).

(d)	24	-- 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)	25	-- 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)	30	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services	and	Service	Agreement	for	Generation	Planning	and	Operational Support	Services).

(d)	32	-- Decommissioning	Trust	Agreement,	dated	as	of	December	22,	1997,	by	and	between	Cajun	Electric	Power	Cooperative,	Inc.	and Mellon	Bank,	N.A.	with	respect	to	decommissioning	funds	authorized	to	be	collected	by	Cajun	Electric	Power	Cooperative,	Inc. and	related	Settlement	Term	Sheet	(10(d)42	to	Form	10-K	for	the	year	ended	December	31,	2007	in	333-148557).

(d)	33	-- First	Amendment	to	Decommissioning	Trust	Agreement,	dated	as	of	December	23,	2003,	by	and	among	Cajun	Electric	Power Cooperative,	Inc.,	Mellon	Bank,	N.A.,	Entergy	Gulf	States,	Inc.,	and	the	Rural	Utilities	Services	of	the	United	States	Department of	Agriculture	(10(d)43	to	Form	10-K	for	the	year	ended	December	31,	2007	in	333-148557).

(d)	34	-- Second	Amendment	 to	 Decommissioning	Trust	Agreement,	 dated	 December	 31,	 2007,	 by	 and	 among	 Cajun	 Electric	 Power Cooperative,	Inc.,	Mellon	Bank,	N.A.,	Entergy	Gulf	States	Louisiana,	L.L.C.,	and	the	Rural	Utilities	Services	of	the	United	States Department	of	Agriculture	(10(d)44	to	Form	10-K	for	the	year	ended	December	31,	2007	in	333-148557).

(d)	35	-- Second	Amended	and	Restated	Limited	Liability	Company	Agreement	of	Entergy	Holdings	Company	LLC	dated	as	of	July	22, 2010	(10(a)	to	Form	10-Q	for	the	quarter	ended	June	30,	2010).

(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)	5	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services	and	Service	Agreement	for	Generation	Planning	and	Operational Support	Services).

(e)	17	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(e)	18	-- 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)	20	-- Contract	for	Disposal	of	Spent	Nuclear	Fuel	and/or	High-Level	Radioactive	Waste,	dated	February	2,	1984,	among	DOE,	System Fuels	and	Entergy	Louisiana	(10(d)33	to	Form	10-K	for	the	year	ended	December	31,	1984	in	1-8474).

(e)	23	-- Second	Amended	and	Restated	Limited	Liability	Company	Agreement	of	Entergy	Holdings	Company	LLC	dated	as	of	July	22, 2010	(10(a)	to	Form	10-Q	for	the	quarter	ended	June	30,	2010).

(e)	26	-- Loan	Agreement,	dated	as	of	October	1,	2010,	between	the	Louisiana	Public	Facilities	Authority	and	Entergy	Louisiana,	LLC relating	to	Revenue	Bonds	(Entergy	Louisiana,	LLC	Project)	Series	2010	(4(b)	to	Form	8-K	filed	October	12,	2010	in	1-32718).

(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)	5	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services	and	Service	Agreement	for	Generation	Planning	and	Operational Support	Services).

(f)	19	-- 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)	22	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi,	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(f)	23	-- 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)	27	-- 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)	28	-- Middle	South	Utilities,	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	April	28,	1988	(D- 1	to	Form	U5S	for	the	year	ended	December	31,	1987).

(f)	29	-- 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)	30	-- 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)	31	-- 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)	32	-- Fourth	Amendment	dated	April	1,	1997	to	Entergy	Corporation	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation Agreement	(D-5	to	Form	U5S	for	the	year	ended	December	31,	1996).

(f)	35	-- Purchase	and	Sale	Agreement	by	and	between	Central	Mississippi	Generating	Company,	LLC	and	Entergy	Mississippi,	Inc.,	dated as	of	March	16,	2005	(10(b)	to	Form	10-Q	for	the	quarter	ended	March	31,	2005	in	1-31508).

(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)	5	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services	and	Service	Agreement	for	Generation	Planning	and	Operational Support	Services).

(g)	15	-- Unit	Power	Sales	Agreement,	dated	as	of	June	10,	1982,	between	System	Energy	and	Entergy	Arkansas,	Entergy	Louisiana, Entergy	Mississippi	and	Entergy	New	Orleans	(10(a)39	to	Form	10-K	for	the	year	ended	December	31,	1982	in	1-3517).

(g)	16	-- 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)	19	-- Middle	South	Utilities,	Inc.	and	Subsidiary	Companies	Intercompany	Income	Tax	Allocation	Agreement,	dated	April	28,	1988	(D- 1	to	Form	U5S	for	the	year	ended	December	31,	1987).

(g)	20	-- 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)	21	-- 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)	22	-- 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)	23	-- 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).

(h)	1	-- Agreement	effective	February	1,	1964,	between	Sabine	River	Authority,	State	of	Louisiana,	and	Sabine	River	Authority	of	Texas, and	Entergy	Gulf	States,	Inc.,	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).

(h)	7	-- 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,	Inc.,	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).

+(h)	9	-- Trust	Agreement	for	Deferred	Payments	to	be	made	by	Entergy	Gulf	States,	Inc.	pursuant	to	the	Executive	Income	Security	Plan, by	and	between	Entergy	Gulf	States,	Inc.	and	Bankers	Trust	Company,	effective	November	1,	1986	(10-78	to	Form	10-K	for	the year	ended	December	31,	1986	in	1-27031).

+(h)	10	-- Trust	Agreement	 for	 Deferred	 Installments	 under	 Entergy	 Gulf	 States,	 Inc.	 Management	 Incentive	 Compensation	 Plan	 and Administrative	Guidelines	by	and	between	Entergy	Gulf	States,	Inc.	and	Bankers	Trust	Company,	effective	June	1,	1986	(10-79	to Form	10-K	for	the	year	ended	December	31,	1986	in	1-27031).

+(h)	11	-- 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).

+(h)	12	-- Trust	Agreement	for	Entergy	Gulf	States,	Inc.	Nonqualified	Directors	and	Designated	Key	Employees	by	and	between	Entergy Gulf	States,	Inc.	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).

+(h)	15	-- Trust	Agreement	for	Entergy	Gulf	States,	Inc.	Executive	Continuity	Plan,	by	and	between	Entergy	Gulf	States,	Inc.	and	First	City Bank,	Texas-Beaumont,	N.A.	(now	Texas	Commerce	Bank),	effective	May	20,	1991	(10-5	to	Form	10-K	for	the	year	ended December	31,	1992	in	1-27031).

(h)	17	-- 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).

(h)	18	-- 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).

*(h)	22	-- Amendment,	dated	December	19,	2013,	to	Service	Agreement	with	Entergy	Services	(includes	Amended	and	Restated	Service Agreement	for	Administrative	and	General	Support	Services	and	Service	Agreement	for	Generation	Planning	and	Operational Support	Services).

# (12)	Statement	Re	Computation	of	Ratios

*(a) Entergy	Arkansas's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Dividends,	as defined.

*(b) Entergy	Gulf	States	Louisiana's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred Distributions,	as	defined.

*(c) Entergy	Louisiana's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Distributions, 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's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Dividends, as	defined.

*(f) Entergy	Texas's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges,	as	defined.

*(g) 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	530.

*(e) Rule	13a-14(a)/15d-14(a)	Certification	for	Entergy	Gulf	States	Louisiana.

*(f) Rule	13a-14(a)/15d-14(a)	Certification	for	Entergy	Gulf	States	Louisiana.

*(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	Arkansas.

*(e) Section	1350	Certification	for	Entergy	Gulf	States	Louisiana.

*(f) Section	1350	Certification	for	Entergy	Gulf	States	Louisiana.

*(g) Section	1350	Certification	for	Entergy	Louisiana.

*(h) Section	1350	Certification	for	Entergy	Louisiana.

*(i) Section	1350	Certification	for	Entergy	Mississippi.

*(j) Section	1350	Certification	for	Entergy	Mississippi.

*(k) Section	1350	Certification	for	Entergy	New	Orleans.

*(l) Section	1350	Certification	for	Entergy	New	Orleans.

*(m) Section	1350	Certification	for	Entergy	Texas.

*(n) Section	1350	Certification	for	Entergy	Texas.

*(o) Section	1350	Certification	for	System	Energy.

*(p) Section	1350	Certification	for	System	Energy.

# *INS	- XBRL	Instance	Document.

*SCH	- XBRL	Taxonomy	Extension	Schema	Document.

*CAL	- XBRL	Taxonomy	Extension	Calculation	Linkbase	Document.

*DEF	- XBRL	Taxonomy	Extension	Definition	Linkbase	Document.

*LAB	- XBRL	Taxonomy	Extension	Label	Linkbase	Document.

*PRE	- XBRL	Taxonomy	Extension	Presentation	Linkbase	Document.

* Filed	herewith.

+	 Management	contracts	or	compensatory	plans	or	arrangements.



Question: what are the nuclear realized price changes as a percentage of the decrease in net revenue from 2011 to 2012?
Calculation: net_revenue_2011 = 2045
net_revenue_2012 = 1854
net_revenue_decrease = net_revenue_2011 - net_revenue_2012
nuclear_realized_price_change = 194 / net_revenue_decrease
answer = nuclear_realized_price_change * 100
Answer: 102%