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,	2017

# 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:

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.

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.		[ü]

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

Entergy	Mississippi,	Inc.

Entergy	New	Orleans,	LLC

Entergy	Texas,	Inc. ü

System	Energy	Resources,	Inc. ü

If	an	emerging	growth	company,	indicate	by	check	mark	if	the	registrants	have	elected	not	to	use	the	extended	transition	period	for	complying with	any	new	or	revised	financial	accounting	standards	provided	pursuant	to	Section	13(a)	of	the	Exchange	Act.	o

Indicate	by	check	mark	whether	the	registrants	are	shell	companies	(as	defined	in	Rule	12b-2	of	the	Exchange	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 2017	was	$13.8	billion	based	on	the	reported	last	sale	price	of	$76.77	per	share	for	such	stock	on	the	New	York	Stock	Exchange	on	June	30, 2017.		Entergy	Corporation	is	the	sole	holder	of	the	common	stock	of	Entergy	Arkansas,	Inc.,	Entergy	Mississippi,	Inc.,	Entergy	Texas,	Inc.,	and System	Energy	Resources,	Inc.		Entergy	Corporation	is	the	direct	and	indirect	holder	of	the	common	membership	interests	of	Entergy	Utility Holding	Company,	LLC,	which	is	the	sole	holder	of	the	common	membership	interests	of	Entergy	Louisiana,	LLC	and	Entergy	New	Orleans, LLC.

# 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	4, 2018,	are	incorporated	by	reference	into	Part	III	hereof.

(Page	left	blank	intentionally)

| Forward-looking	information |  | iv |
| :--- | :--- | :--- |
| Definitions |  | vii |
| Entergy\tCorporation\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 1 |
| Report\tof\tManagement |  | 45 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 46 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 47 |
| Consolidated\tStatements\tof\tOperations\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 48 |
| Consolidated\tStatements\tof\tComprehensive\tIncome\t(Loss)\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\n2016,\tand\t2015 | Part\tII.\tItem\t8. | 49 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 50 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 52 |
| Consolidated\tStatements\tof\tChanges\tin\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 54 |
| Notes\tto\tFinancial\tStatements |  |  |
| Note\t1.\tSummary\tof\tSignificant\tAccounting\tPolicies | Part\tII.\tItem\t8. | 55 |
| Note\t2.\tRate\tand\tRegulatory\tMatters | Part\tII.\tItem\t8. | 67 |
| Note\t3.\tIncome\tTaxes | Part\tII.\tItem\t8. | 108 |
|  | Part\tII.\tItem\t8. | 122 |
| Note\t5.\tLong-term\tDebt | Part\tII.\tItem\t8. | 126 |
| Note\t6.\tPreferred\tEquity | Part\tII.\tItem\t8. | 135 |
| Note\t7.\tCommon\tEquity | Part\tII.\tItem\t8. | 137 |
| Note\t8.\tCommitments\tand\tContingencies | Part\tII.\tItem\t8. | 141 |
| Note\t9.\tAsset\tRetirement\tObligations | Part\tII.\tItem\t8. | 150 |
| Note\t10.\tLeases | Part\tII.\tItem\t8. | 156 |
| Note\t11.\tRetirement,\tOther\tPostretirement\tBenefits,\tand\tDefined\tContribution\tPlans | Part\tII.\tItem\t8. | 159 |
| Note\t12.\tStock-based\tCompensation | Part\tII.\tItem\t8. | 187 |
| Note\t13.\tBusiness\tSegment\tInformation | Part\tII.\tItem\t8. | 191 |
| Note\t14.\tAcquisitions,\tDispositions,\tand\tImpairment\tof\tLong-lived\tAssets | Part\tII.\tItem\t8. | 195 |
| Note\t15.\tRisk\tManagement\tand\tFair\tValues | Part\tII.\tItem\t8. | 201 |
| Note\t16.\tDecommissioning\tTrust\tFunds | Part\tII.\tItem\t8. | 218 |
| Note\t17.\tVariable\tInterest\tEntities | Part\tII.\tItem\t8. | 224 |
| Note\t18.\tTransactions\twith\tAffiliates | Part\tII.\tItem\t8. | 226 |
| Note\t19.\tQuarterly\tFinancial\tData | Part\tII.\tItem\t8. | 228 |
| Entergy's\tBusiness |  |  |
| Utility | Part\tI.\tItem\t1. | 231 |
| Entergy\tWholesale\tCommodities | Part\tI.\tItem\t1. | 252 |
| Regulation\tof\tEntergy's\tBusiness | Part\tI.\tItem\t1. | 257 |
| Litigation |  | 273 |
| Employees |  | 274 |
| Availability\tof\tSEC\tfilings\tand\tother\tinformation\ton\tEntergy's\twebsite |  | 274 |
| Risk\tFactors | Part\tI.\tItem\t1A. | 275 |

# Entergy	Arkansas,	Inc.	and	Subsidiaries

| Management's	Financial	Discussion	and	Analysis | Part	II.	Item	7. | 300 |
| :--- | :--- | :--- |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 318 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 319 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 321 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 322 |
| Consolidated\tStatements\tof\tChanges\tin\tCommon\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\nand\t2015 | Part\tII.\tItem\t8. | 324 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 325 |
| Entergy\tLouisiana,\tLLC\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 326 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 348 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 349 |
| Consolidated\tStatements\tof\tComprehensive\tIncome\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\n2015 | Part\tII.\tItem\t8. | 350 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 351 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 352 |
| Consolidated\tStatements\tof\tChanges\tin\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | 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,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 370 |
| Statements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 371 |
| Balance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 372 |
| Statements\tof\tChanges\tin\tCommon\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 374 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 375 |
| Entergy\tNew\tOrleans,\tLLC\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 376 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 391 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 392 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 393 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 394 |
| Consolidated\tStatements\tof\tChanges\tin\tMember's\tEquity\tfor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\nand\t2015 | Part\tII.\tItem\t8. | 396 |
| Selected\tFinancial\tData\t-\tFive-Year\tComparison | Part\tII.\tItem\t6. | 397 |
| Entergy\tTexas,\tInc.\tand\tSubsidiaries |  |  |
| Management's\tFinancial\tDiscussion\tand\tAnalysis | Part\tII.\tItem\t7. | 398 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  | 413 |
| Consolidated\tIncome\tStatements\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 414 |
| Consolidated\tStatements\tof\tCash\tFlows\tFor\tthe\tYears\tEnded\tDecember\t31,\t2017,\t2016,\tand\t2015 | Part\tII.\tItem\t8. | 415 |
| Consolidated\tBalance\tSheets,\tDecember\t31,\t2017\tand\t2016 | Part\tII.\tItem\t8. | 416 |

# This	combined	Form	10-K	is	separately	filed	by	Entergy	Corporation	and	its	six	"Registrant	Subsidiaries:"	Entergy	Arkansas,

Inc.,	Entergy	Louisiana,	LLC,	Entergy	Mississippi,	Inc.,	Entergy	New	Orleans,	LLC,	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,	formula	rate	proceedings	and	related	negotiations,	including	various	performance-based	rate discussions,	Entergy's	utility	supply	plan,	and	recovery	of	fuel	and	purchased	power	costs;

•long-term	risks	and	uncertainties	associated	with	the	termination	of	the	System	Agreement	in	2016,	including	the	potential	absence	of federal	authority	to	resolve	certain	issues	among	the	Utility	operating	companies	and	their	retail	regulators;

•regulatory	and	operating	challenges	and	uncertainties	and	economic	risks	associated	with	the	Utility	operating	companies'	participation in	MISO,	including	the	benefits	of	continued	MISO	participation,	the	effect	of	current	or	projected	MISO	market	rules	and	market	and system	conditions	in	the	MISO	markets,	the	allocation	of	MISO	system	transmission	upgrade	costs,	and	the	effect	of	planning	decisions that	MISO	makes	with	respect	to	future	transmission	investments	by	the	Utility	operating	companies;

•changes	in	utility	regulation,	including	with	respect	to	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	or	the	U.S.	Department	of	Justice;

•changes	in	the	regulation	or	regulatory	oversight	of	Entergy's	nuclear	generating	facilities	and	nuclear	materials	and	fuel,	including	with respect	 to	 the	 planned,	 potential,	 or	 actual	 shutdown	 of	 nuclear	 generating	 facilities	 owned	 or	 operated	 by	 Entergy	 Wholesale Commodities,	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	or other	authorizations	required	of	nuclear	generating	facilities	and	the	effect	of	public	and	political	opposition	on	these	applications, regulatory	proceedings,	and	litigation;

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

•increases	in	costs	and	capital	expenditures	that	could	result	from	the	commitment	of	substantial	human	and	capital	resources	required for	the	operation	and	maintenance	of	Entergy's	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,	especially	in	light	of	the	planned	shutdown	or	sale	of	each	of	these	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,	emissions	allowances,	and	other	energy-related	commodities,	and the	effect	of	those	changes	on	Entergy	and	its	customers;

# FORWARD-LOOKING	INFORMATION	(Continued)

•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;

•changes	in	environmental	laws	and	regulations,	agency	positions	or	associated	litigation,	including	requirements	for	reduced	emissions of	sulfur	dioxide,	nitrogen	oxide,	greenhouse	gases,	mercury,	particulate	matter,	heat,	and	other	regulated	air	and	water	emissions,

requirements	for	waste	management	and	disposal	and	for	the	remediation	of	contaminated	sites,	wetlands	protection	and	permitting,	and changes	in	costs	of	compliance	with	these	environmental	laws	and	regulations;

•changes	in	laws	and	regulations,	agency	positions,	or	associated	litigation	related	to	protected	species	and	associated	critical	habitat designations;

•the	effects	of	changes	in	federal,	state	or	local	laws	and	regulations,	and	other	governmental	actions	or	policies,	including	changes	in monetary,	fiscal,	tax,	environmental,	or	energy	policies;

•uncertainty	regarding	the	establishment	of	interim	or	permanent	sites	for	spent	nuclear	fuel	and	nuclear	waste	storage	and	disposal	and the	level	of	spent	fuel	and	nuclear	waste	disposal	fees	charged	by	the	U.S.	government	or	other	providers	related	to	such	sites;

•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,	including	the	potential	for	increases	in	sea	levels	or	coastal	land	and	wetland	loss;

•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 and	circumstances	that	could	influence	economic	conditions	in	those	areas,	including	power	prices,	and	the	risk	that	anticipated	load growth	may	not	materialize;

•federal	income	tax	reform,	including	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	and	its	intended	and	unintended	consequences	on financial	results	and	future	cash	flows,	including	the	potential	impact	to	credit	ratings,	which	may	affect	Entergy's	ability	to	borrow funds	or	increase	the	cost	of	borrowing	in	the	future;

•the	effects	of	Entergy's	strategies	to	reduce	tax	payments,	especially	in	light	of	federal	income	tax	reform;

•changes	in	the	financial	markets	and	regulatory	requirements	for	the	issuance	of	securities,	particularly	as	they	affect	access	to	capital and	Entergy's	ability	to	refinance	existing	securities,	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	such	as	distributed	energy	and energy	storage,	energy	efficiency,	demand	side	management	and	other	measures	that	reduce	load;

•the	effects,	including	increased	security	costs,	of	threatened	or	actual	terrorism,	cyber-attacks	or	data	security	breaches,	natural	or	man- made	electromagnetic	pulses	that	affect	transmission	or	generation	infrastructure,	accidents,	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,	directors,	and	employees	with	specialized	skills;

•changes	in	accounting	standards	and	corporate	governance;

•declines	in	the	market	prices	of	marketable	securities	and	resulting	funding	requirements	and	the	effects	on	benefits	costs	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,	requirements	for,	or	cost	to	decommission	Entergy's nuclear	plant	sites	and	the	implementation	of	decommissioning	of	such	sites	following	shutdown;

# FORWARD-LOOKING	INFORMATION	(Concluded)

•the	decision	to	cease	merchant	power	generation	at	all	Entergy	Wholesale	Commodities	nuclear	power	plants	by	mid-2022,	including the	implementation	of	the	planned	shutdowns	of	Pilgrim,	Indian	Point	2,	Indian	Point	3,	and	Palisades;

•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	 strategic	 transactions	 Entergy	 may	 undertake,	 including	 mergers,	 acquisitions,	 divestitures,	 or restructurings,	regulatory	or	other	limitations	imposed	as	a	result	of	any	such	strategic	transaction,	and	the	success	of	the	business following	any	such	strategic	transaction.

# 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	operation	of	a	small	natural	gas	distribution	business. •The	Entergy	Wholesale	Commodities	business	segment	includes	the	ownership,	operation,	and	decommissioning	of	nuclear	power plants	located	in	the	northern	United	States	and	the	sale	of	the	electric	power	produced	by	its	operating	plants	to	wholesale	customers. Entergy	Wholesale	Commodities	also	provides	services	to	other	nuclear	power	plant	owners	and	owns	interests	in	non-nuclear	power plants	that	sell	the	electric	power	produced	by	those	plants	to	wholesale	customers.	See	"Entergy	Wholesale	Commodities	Exit	from the	Merchant	Power	Business"	below	for	discussion	of	the	operation	and	planned	shutdown	or	sale	of	each	of	the	Entergy	Wholesale Commodities	nuclear	power	plants.

Following	are	the	percentages	of	Entergy's	consolidated	revenues	generated	by	its	operating	segments	and	the	percentage	of	total	assets held	by	them.	Net	income	or	loss	generated	by	the	operating	segments	is	discussed	in	the	sections	that	follow.

|  |  | %	of	Revenue |  | %	of	Total	Assets | %	of	Total	Assets |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Segment | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 |
| Utility | 85 | 83 | 82 | 92 | 89 | 86 |
| Entergy\tWholesale\tCommodities | 15 | 17 | 18 | 12 | 15 | 18 |
| Parent\t&\tOther | — | — | — | (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	2017	to 2016	showing	how	much	the	line	item	increased	or	(decreased)	in	comparison	to	the	prior	period.

|  | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;	Other<br>(a) | Entergy |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| 2016\tConsolidated\tNet\tIncome\t(Loss) | $1,151,133 | ($1,493,124) | ($222,512) | ($564,503) |
| Net\trevenue\t(operating\trevenue\tless\tfuel\texpense,\tpurchased\npower,\tand\tother\tregulatory\tcharges/credits) | 138,617 | (73,433) | (16) | 65,168 |
| Other\toperation\tand\tmaintenance | 108,187 | 13,922 | 4,869 | 126,978 |
| Asset\twrite-offs,\timpairments,\tand\trelated\tcharges | — | (2,297,265) | — | (2,297,265) |
| Taxes\tother\tthan\tincome\ttaxes | 38,897 | (14,657) | 814 | 25,054 |
| Depreciation\tand\tamortization | 49,491 | (6,731) | 31 | 42,791 |
| Gain\ton\tsale\tof\tasset | — | 16,270 | — | 16,270 |
| Other\tincome | 64,815 | 132,734 | 1,962 | 199,511 |
| Interest\texpense | (10,245) | 856 | 5,362 | (4,027) |
| Other\texpenses | 24,859 | 12,874 | — | 37,733 |
| Income\ttaxes | 370,228 | 1,045,783 | (56,182) | 1,359,829 |
| 2017\tConsolidated\tNet\tIncome\t(Loss) | $773,148 | ($172,335) | ($175,460) | $425,353 |

(a) Parent	&	Other	includes	eliminations,	which	are	primarily	intersegment	activity.

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.

Results	of	operations	for	2017	include:	1)	$538	million	($350	million	net-of-tax)	of	impairment	charges	due	to	costs	being	charged	to expense	 as	 incurred	 as	 a	 result	 of	 the	 impaired	 value	 of	 the	 Entergy	Wholesale	 Commodities	 nuclear	 plants'	 long-lived	 assets	 due	 to	 the significantly	reduced	remaining	estimated	operating	lives	associated	with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale Commodities'	merchant	fleet;	2)	a	reduction	in	net	income	of	$181	million,	including	a	$34	million	net-of-tax	reduction	of	regulatory	liabilities,	at Utility	and	$397	million	at	Entergy	Wholesale	Commodities	and	an	increase	in	net	income	of	$52	million	at	Parent	and	Other	as	a	result	of Entergy's	re-measurement	of	its	deferred	tax	assets	and	liabilities	not	subject	to	the	ratemaking	process	due	to	the	enactment	of	the	Tax	Cuts	and Jobs	Act,	in	December	2017,	which	lowered	the	federal	corporate	income	tax	rate	from	35%	to	21%;	and	3)	a	reduction	in	income	tax	expense,	net of	unrecognized	tax	benefits,	of	$373	million	as	a	result	of	a	change	in	the	tax	classification	of	legal	entities	that	own	Entergy	Wholesale Commodities	 nuclear	 power	 plants.	See "MANAGEMENT'S	 FINANCIAL	 DISCUSSION	 AND	 ANALYSIS -	Entergy	 Wholesale Commodities	Exit	from	the	Merchant	Power	Business"	below	for	a	discussion	of	management's	strategy	to	reduce	the	size	of	the	Entergy Wholesale	Commodities'	merchant	fleet	and	see	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges. See	Note	3	to	the	financial	statements	for	further	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act	and	the	change	in	the	tax	classification.

Results	of	operations	for	2016	include:	1)	$2,836	million	($1,829	million	net-of-tax)	of	impairment	and	related	charges	primarily	to	write down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	Palisades,	Indian	Point	2,	and	Indian	Point	3	plants	and	related	assets	to	their fair	values;	2)	a	reduction	of	income	tax	expense,	net	of	unrecognized	tax	benefits,	of	$238	million	as	a	result	of	a	change	in	the	tax	classification of	a	legal	entity	that	owned	one	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants;	income	tax	benefits	as	a	result	of	the	settlement	of the	2010-2011	IRS	audit,	including	a	$75	million	tax	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment	of	the	Vidalia	purchased power	agreement	and	a	$54	million	net	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment	of	proceeds	received	in	2010	for	the financing	of	Hurricane	Gustav	and	Hurricane	Ike	storm	costs	pursuant	to	Louisiana	Act	55;	and	3)	a	reduction	in	expenses	of	$100	million	($64 million	net-of-tax)	due	to	the	effects	of	recording	in	2016	the	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel storage	costs.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges,	see	Note	3	to	the	financial statements	for	additional	discussion	of	the	income	tax	items,	and	see	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel litigation.

# Net	Revenue

# Utility

Following	is	an	analysis	of	the	change	in	net	revenue	comparing	2017	to	2016.

| 2016	net	revenue | $6,179 |
| :--- | :--- |
| Retail\telectric\tprice | 91 |
| Regulatory\tcredit\tresulting\tfrom\treduction\tof\tthe\n\t\tfederal\tcorporate\tincome\ttax\trate | 56 |
| Grand\tGulf\trecovery | 27 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | 17 |
| Volume/weather | (61) |
| Other | 9 |
| 2017\tnet\trevenue | $6,318 |

The	retail	electric	price	variance	is	primarily	due	to:

•the	implementation	of	formula	rate	plan	rates	effective	with	the	first	billing	cycle	of	January	2017	at	Entergy	Arkansas	and	an	increase	in base	rates	effective	February	24,	2016,	each	as	approved	by	the	APSC.	A	significant	portion	of	the	base	rate	increase	was	related	to	the purchase	of	Power	Block	2	of	the	Union	Power	Station	in	March	2016;

•a	provision	recorded	in	2016	related	to	the	settlement	of	the	Waterford	3	replacement	steam	generator	prudence	review	proceeding; •the	implementation	of	the	transmission	cost	recovery	factor	rider	at	Entergy	Texas,	effective	September	2016,	and	an	increase	in	the transmission	cost	recovery	factor	rider	rate,	effective	March	2017,	as	approved	by	the	PUCT;	and

•an	increase	in	rates	at	Entergy	Mississippi,	as	approved	by	the	MPSC,	effective	with	the	first	billing	cycle	of	July	2016.

See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate	proceedings	and	the	Waterford	3	replacement	steam	generator	prudence review	proceeding.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase.

The	regulatory	credit	resulting	from	reduction	of	the	federal	corporate	income	tax	rate	variance	is	due	to	the	reduction	of	the	Vidalia purchased	power	agreement	regulatory	liability	by	$30.5	million	and	the	reduction	of	the	Louisiana	Act	55	financing	savings	obligation	regulatory liabilities	by	$25	million	as	a	result	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	which	lowered	the	federal	corporate	income tax	rate	from	35%	to	21%.	The	effects	of	the	Tax	Cuts	and	Jobs	Act	are	discussed	further	in	Note	3	to	the	financial	statements.

The	Grand	Gulf	recovery	variance	is	primarily	due	to	increased	recovery	of	higher	operating	costs.

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	in	2016	for	tax	savings	to	be	shared	with customers	per	an	agreement	approved	by	the	LPSC.	The	tax	savings	resulted	from	the	2010-2011	IRS	audit	settlement	on	the	treatment	of	the Louisiana	Act	55	financing	of	storm	costs	for	Hurricane	Gustav	and	Hurricane	Ike.	See	Note	3	to	the	financial	statements	for	additional	discussion of	the	settlement	and	benefit	sharing.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales,	partially	offset by	an	increase	in	industrial	usage.	The	increase	in	industrial	usage	is	primarily	due	to	new	customers	in	the	primary	metals	industry	and	expansion projects	and	an	increase	in	demand	for	existing	customers	in	the	chlor-alkali	industry.

# Entergy	Wholesale	Commodities

| 2016	net	revenue | $1,542 |
| :--- | :--- |
| FitzPatrick\tsale | (158) |
| Nuclear\tvolume | (89) |
| FitzPatrick\treimbursement\tagreement | 57 |
| Nuclear\tfuel\texpenses | 108 |
| Other | 9 |
| 2017\tnet\trevenue | $1,469 |

As	shown	in	the	table	above,	net	revenue	for	Entergy	Wholesale	Commodities	decreased	by	approximately	$73	million	in	 2017	primarily due	to	the	absence	of	net	revenue	from	the	FitzPatrick	plant	after	it	was	sold	to	Exelon	in	March	2017	and	lower	volume	in	the	Entergy	Wholesale Commodities	nuclear	fleet	resulting	from	more	outage	days	in	2017	as	compared	to	2016.	The	decrease	was	partially	offset	by	an	increase resulting	 from	 the	 reimbursement	 agreement	 with	 Exelon	 pursuant	 to	 which	 Exelon	 reimbursed	 Entergy	 for	 specified	 out-of-pocket	 costs associated	with	preparing	for	the	refueling	and	operation	of	FitzPatrick	that	otherwise	would	have	been	avoided	had	Entergy	shut	down	FitzPatrick in	January	2017	and	a	decrease	in	nuclear	fuel	expenses	primarily	related	to	the	impairments	of	the	Indian	Point	2,	Indian	Point	3,	and	Palisades plants	 and	 related	 assets.	Revenues	 received	 from	 Exelon	 in	 2017	 under	 the	 reimbursement	 agreement	 are	 offset	 by	 other	 operation	 and maintenance	expenses	and	taxes	other	than	income	taxes	and	had	no	effect	on	net	income.	See	Note	14	to	the	financial	statements	for	discussion of	the	sale	of	FitzPatrick,	the	reimbursement	agreement	with	Exelon,	and	the	impairments	and	related	charges.

Following	are	key	performance	measures	for	Entergy	Wholesale	Commodities	for	2017	and	2016.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Owned\tcapacity\t(MW)\t(a) | 3,962 | 4,800 |
| GWh\tbilled | 30,501 | 35,881 |
| Entergy\tWholesale\tCommodities\tNuclear\tFleet |  |  |
| Capacity\tfactor | 83% | 87% |
| GWh\tbilled | 28,178 | 33,551 |
| Average\tenergy\tand\tcapacity\trevenue\tper\tMWh | $50.04 | $47.31 |
| Refueling\tOutage\tDays: |  |  |
| FitzPatrick | 42 | — |
| Indian\tPoint\t2 | — | 102 |
| Indian\tPoint\t3 | 66 | — |
| Pilgrim | 43 | — |
| Palisades | 27 | — |

(a) The	reduction	in	owned	capacity	is	due	to	Entergy's	sale	of	the	838	MW	FitzPatrick	plant	to	Exelon	in	March	2017.	See	Note	14	to	the financial	statements	for	discussion	of	the	sale	of	FitzPatrick.

# Other	Income	Statement	Items

Other	operation	and	maintenance	expenses	increased	from	$2,360	million	for	2016	to	$2,468	million	for	2017	primarily	due	to:

•an	increase	of	$46	million	in	nuclear	generation	expenses	primarily	due	to	higher	nuclear	labor	costs,	including	contract	labor,	to	position the	nuclear	fleet	to	meet	its	operational	goals,	including	additional	training	and	initiatives	to	support	management's	operational	goals	at Grand	Gulf,	partially	offset	by	a	decrease	in	regulatory	compliance	costs.	The	decrease	in	regulatory	compliance	costs	is	primarily	related to	additional	NRC	inspection	activities	in	2016	as	a	result	of	the	NRC's	March	2015	decision	to	move	ANO	into	the	"multiple/repetitive degraded	 cornerstone	 column"	 of	 the	 NRC's	 reactor	 oversight	 process	 action	 matrix.	See	 Note	 8	 to	 the	 financial	 statements	 for	 a discussion	of	the	ANO	stator	incident	and	subsequent	NRC	reviews;

•an	increase	of	$24	million	in	compensation	and	benefits	costs	primarily	due	to	higher	incentive-based	compensation	accruals	in	2017	as compared	to	the	prior	year;

•an	increase	of	$20	million	in	transmission	and	distribution	expenses	due	to	higher	vegetation	maintenance	costs;

•the	effects	of	recording	in	2016	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs.	The damages	awarded	included	the	reimbursement	of	approximately	$19	million	of	spent	nuclear	fuel	storage	costs	previously	recorded	as other	operation	and	maintenance	expense.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation;	and •the	deferral	in	the	first	quarter	2016	of	$7.7	million	of	previously-incurred	costs	related	to	ANO	post-Fukushima	compliance	and	$9.9 million	of	previously-incurred	costs	related	to	ANO	flood	barrier	compliance,	as	approved	by	the	APSC	in	February	2016	as	part	of	the Entergy	Arkansas	2015	rate	case	settlement.	These	costs	are	being	amortized	over	a	ten-year	period	beginning	March	2016.	See	Note	2	to the	financial	statements	for	further	discussion	of	the	rate	case	settlement.

The	increase	was	partially	offset	by	a	decrease	of	$23	million	in	fossil-fueled	generation	expenses	primarily	due	to	lower	long-term	service agreement	costs.

Taxes	other	than	income	taxes	increased	primarily	due	to	increases	in	ad	valorem	taxes,	local	franchise	taxes,	state	franchise	taxes,	and employment	taxes.	Ad	valorem	taxes	increased	primarily	due	to	higher	assessments,	including	the	assessment	of	ad	valorem	taxes	on	the	Union Power	Station	beginning	in	2017.	Local	franchise	taxes	increased	primarily	due	to	higher	revenues	in	2017	as	compared	to	the	prior	year.	State franchise	taxes	increased	primarily	due	to	a	change	in	the	Louisiana	franchise	tax	law	which	became	effective	for	2017.

Depreciation	and	amortization	expenses	 increased	primarily	due	 to	additions	 to	plant	 in	service,	 including the	Union	Power	Station purchased	in	March	2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase.

Other	income	increased	primarily	due	to	higher	realized	gains	in	2017	as	compared	to	the	prior	year	on	the	decommissioning	trust	fund investments,	including	portfolio	rebalancing	in	2017,	and	an	increase	in	the	allowance	for	equity	funds	used	during	construction	due	to	higher construction	work	in	progress	in	2017,	including	the	St.	Charles	Power	Station	project.

Other	expenses	increased	primarily	due	to	increases	in	deferred	refueling	outage	amortization	costs	primarily	associated	with	the	most recent	ANO	plant	outages	compared	to	previous	outages.

Other	operation	and	maintenance	expenses	increased	from	$915	million	for	2016	to	$929	million	for	2017	primarily	due	to:

•FitzPatrick's	nuclear	refueling	outage	expenses	and	expenditures	for	capital	assets	being	classified	as	other	operation	and	maintenance expenses	as	a	result	of	the	sale	and	reimbursement	agreements	Entergy	entered	into	with	Exelon.	These	costs	would	have	not	been incurred	absent	the	sale	agreement	with	Exelon	because	Entergy	planned	to	shut	the	plant	down	in	January	2017.	The	expenses	are	offset by	revenue	realized	pursuant	to	the	reimbursement	agreement	and	had	no	effect	on	net	income.	See	Note	14	to	the	financial	statements	for discussion	of	the	sale	and	reimbursement	agreements;

•the	effect	of	recording	in	2016	final	court	decisions	in	litigation	against	the	DOE	for	the	reimbursement	of	spent	nuclear	fuel	storage	costs, which	reduced	other	operation	and	maintenance	expenses	in	2016	by	$60	million.	See	Note	8	to	the	financial	statements	for	discussion	of the	spent	nuclear	fuel	litigation;	and

•an	increase	of	$37	million	in	severance	and	retention	costs	in	2017	as	compared	to	the	prior	year	due	to	management's	strategy	to	reduce the	 size	 of	 the	 Entergy	 Wholesale	 Commodities'	 merchant	 fleet.	See "MANAGEMENT'S	 FINANCIAL	 DISCUSSION	 AND ANALYSIS	-	Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power	Business "	below	for	a	discussion	of	management's strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet.

The	increase	was	partially	offset	by	a	decrease	due	to	the	absence	of	other	operation	and	maintenance	expenses	from	the	FitzPatrick	plant	after	it was	sold	to	Exelon	in	March	2017.	See	Note	14	to	the	financial	statements	for	discussion	of	the	sale	of	FitzPatrick.

The	asset	write-offs,	impairments,	and	related	charges	variance	is	primarily	due	to	$538	million	($350	million	net-of-tax)	of	impairment charges	in	2017	compared	to	$2,836	million	($1,829	million	net-of-tax)	of	impairment	and	related	charges	in	2016.	The	impairment	charges	in 2017	are	due	to	nuclear	fuel	spending,	nuclear	refueling	outage	spending,	and	expenditures	for	capital	assets	being	charged	to	expense	as	incurred as	a	result	of	 the	 impaired	value	of	 the	Entergy	Wholesale	Commodities	nuclear	plants'	 long-lived	assets	due	 to	 the	significantly	reduced remaining	estimated	operating	lives	associated	with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant fleet.	See	"MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS 	-	Entergy	Wholesale	Commodities	Exit	from	the	Merchant Power	Business"	below	for	a	discussion	of	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet.	The impairment	and	related	charges	in	2016	were	primarily	to	write	down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	Palisades, Indian	Point	2,

and	Indian	Point	3	plants	and	related	assets	to	their	fair	values.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairments and	related	charges.

Taxes	other	than	income	taxes	decreased	primarily	due	to	the	absence	of	ad	valorem	taxes	from	the	FitzPatrick	plant	after	it	was	sold	to Exelon	in	March	2017.	See	Note	14	to	the	financial	statements	for	discussion	of	the	sale	of	FitzPatrick.

The	gain	on	sale	of	assets	resulted	from	the	sale	in	March	2017	of	the	838	MW	FitzPatrick	plant	to	Exelon.	Entergy	sold	the	FitzPatrick plant	for	approximately	$110	million,	which	includes	a	$10	million	non-refundable	signing	fee	paid	in	August	2016,	in	addition	to	the	assumption by	Exelon	of	certain	liabilities	related	to	the	FitzPatrick	plant,	resulting	in	a	pre-tax	gain	of	$16	million	on	the	sale.	See	Note	14	to	the	financial statements	for	a	discussion	of	the	sale	of	FitzPatrick.

Other	income	increased	primarily	due	to	higher	realized	gains	in	2017	as	compared	to	the	prior	year	on	the	decommissioning	trust	fund investments,	 including	 the	 result	 of	 portfolio	 rebalancing	 in	 2017,	 and	 the	 increase	 in	 value	 realized	 upon	 the	 receipt	 from	 NYPA	 of	 the decommissioning	trust	funds	for	the	Indian	Point	3	and	FitzPatrick	plants	in	January	2017.	See	Note	9	to	the	financial	statements	for	discussion	of the	trust	transfer	agreement	with	NYPA.

Other	expenses	increased	primarily	due	to	increases	in	decommissioning	expenses	primarily	as	a	result	of	a	trust	transfer	agreement Entergy	entered	into	with	NYPA	in	August	2016,	which	closed	in	January	2017,	to	transfer	the	decommissioning	trusts	and	decommissioning liabilities	for	the	Indian	Point	3	and	FitzPatrick	plants	to	Entergy	and	revisions	to	the	estimated	decommissioning	cost	liabilities	for	the	Entergy Wholesale	Commodities'	Indian	Point	2	and	Palisades	plants	as	a	result	of	revised	decommissioning	cost	studies	in	the	fourth	quarter	2016.	The increase	was	partially	offset	by	a	reduction	in	deferred	refueling	outage	amortization	costs	related	to	the	impairments	of	the	Indian	Point	2,	Indian Point	3,	and	Palisades	plants	and	related	assets.	See	Note	9	to	the	financial	statements	for	discussion	of	the	trust	transfer	agreement	with	NYPA and	the	revised	decommissioning	cost	studies.	See	Note	14	to	the	financial	statements	for	discussion	of	the	impairments	and	related	charges.

# 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	2017	was	56.1%.	The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for	2017 was	primarily	due	to	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	signed	by	President	Trump	in	December	2017,	which	changed	the	federal corporate	income	tax	rate	from	35%	to	21%	effective	in	2018,	partially	offset	by	a	change	in	the	tax	classification	of	legal	entities	that	own Entergy	Wholesale	 Commodities	 nuclear	 power	 plants,	 which	 resulted	 in	 both	 permanent	 and	 temporary	 differences	 under	 the	 income	 tax accounting	standards.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act	and	the	change	in	tax classification.

The	effective	income	tax	rate	for	2016	was	59.1%.		The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for 2016	was	primarily	due	to	a	change	in	the	tax	classification	of	a	legal	entity	that	owned	one	of	the	Entergy	Wholesale	Commodities	nuclear	power plants	and	the	reversal	of	a	portion	of	the	provision	for	uncertain	tax	positions	as	a	result	of	the	settlement	of	the	2010-2011	IRS	audit,	partially offset	by	state	income	taxes	and	certain	book	and	tax	differences	related	to	utility	plant	items.	See	Note	3	to	the	financial	statements	for	additional discussion	of	the	change	in	the	tax	classification	and	the	tax	settlement.

|  | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;	Other | Entergy |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| 2015\tConsolidated\tNet\tIncome\t(Loss) | $1,114,516 | ($1,065,657) | ($205,593) | ($156,734) |
| Net\trevenue\t(operating\trevenue\tless\tfuel\texpense,\tpurchased\npower,\tand\tother\tregulatory\tcharges/credits) | 350,528 | (123,791) | (33) | 226,704 |
| Other\toperation\tand\tmaintenance | (83,265) | 15,269 | 9,726 | (58,270) |
| Asset\twrite-offs,\timpairments,\tand\trelated\tcharges | (68,672) | 799,403 | — | 730,731 |
| Taxes\tother\tthan\tincome\ttaxes | (10,229) | (16,259) | (432) | (26,920) |
| Depreciation\tand\tamortization | 49,600 | (39,180) | (509) | 9,911 |
| Gain\ton\tsale\tof\tasset | — | (154,037) | — | (154,037) |
| Other\tincome | 15,153 | 8,666 | 4,281 | 28,100 |
| Interest\texpense | 14,414 | (3,930) | 12,417 | 22,901 |
| Other\texpenses | 19,589 | (15,074) | — | 4,515 |
| Income\ttaxes | 407,627 | (581,924) | (35) | (174,332) |
| 2016\tConsolidated\tNet\tIncome\t(Loss) | $1,151,133 | ($1,493,124) | ($222,512) | ($564,503) |

Results	of	operations	for	2016	include	$2,836	million	($1,829	million	net-of-tax)	of	impairment	and	related	charges	primarily	to	write down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	Palisades,	Indian	Point	2,	and	Indian	Point	3	plants	and	related	assets	to	their fair	values.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges.	Results	of	operations	for	2016 also	include	a	reduction	of	income	tax	expense,	net	of	unrecognized	tax	benefits,	of	$238	million	as	a	result	of	a	change	in	the	tax	classification	of a	legal	entity	that	owned	one	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants;	income	tax	benefits	as	a	result	of	the	settlement	of	the 2010-2011	IRS	audit,	including	a	$75	million	tax	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment	of	the	Vidalia	purchased	power agreement	and	a	$54	million	net	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment	of	proceeds	received	in	2010	for	the	financing	of Hurricane	Gustav	and	Hurricane	Ike	storm	costs	pursuant	to	Louisiana	Act	55;	and	a	reduction	in	expenses	of	$100	million	($64	million	net-of- tax)	due	to	the	effects	of	recording	in	2016	the	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs. See	Note	3	to	the	financial	statements	for	additional	discussion	of	the	income	tax	items.	See	Note	8	to	the	financial	statements	for	discussion	of	the spent	nuclear	fuel	litigation.

Results	of	operations	for	2015	include	$2,036	million	($1,317	million	net-of-tax)	of	impairment	and	related	charges	primarily	to	write down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	FitzPatrick,	Pilgrim,	and	Palisades	plants	and	related	assets	to	their	fair	values. See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges.	As	a	result	of	the	Entergy	Louisiana	and Entergy	Gulf	States	Louisiana	business	combination,	results	of	operations	for	2015	also	include	two	items	that	occurred	in	October	2015:	1)	a deferred	tax	asset	and	resulting	net	increase	in	tax	basis	of	approximately	$334	million	and	2)	a	regulatory	liability	of	$107	million

Entergy	Corporation	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

($66	million	net-of-tax)	as	a	result	of	customer	credits	to	be	realized	by	electric	customers	of	Entergy	Louisiana,	consistent	with	the	terms	of	the stipulated	 settlement	 in	 the	 business	 combination	 proceeding.	See	 Note	 2	 to	 the	 financial	 statements	 for	 further	 discussion	 of	 the	 business combination	and	customer	credits.	Results	of	operations	for	2015	also	include	the	sale	in	December	2015	of	the	583	MW	Rhode	Island	State Energy	Center	for	a	realized	gain	of	$154	million	($100	million	net-of-tax)	on	the	sale	and	the	$77	million	($47	million	net-of-tax)	write-off	and regulatory	charges	to	recognize	that	a	portion	of	the	assets	associated	with	the	Waterford	3	replacement	steam	generator	project	is	no	longer probable	of	recovery.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Rhode	Island	State	Energy	Center	sale.	See	Note	2	to the	financial	statements	for	further	discussion	of	the	Waterford	3	replacement	steam	generator	prudence	review	proceeding.

| 2015	net	revenue | $5,829 |
| :--- | :--- |
| Retail\telectric\tprice | 289 |
| Louisiana\tbusiness\tcombination\tcustomer\tcredits | 107 |
| Volume/weather | 14 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | (17) |
| Other | (43) |
| 2016\tnet\trevenue | $6,179 |

•an	increase	in	base	rates	at	Entergy	Arkansas,	as	approved	by	the	APSC.	The	new	rates	were	effective	February	24,	2016	and	began billing	with	the	first	billing	cycle	of	April	2016.	The	increase	included	an	interim	base	rate	adjustment	surcharge,	effective	with	the	first billing	cycle	of	April	2016,	to	recover	the	incremental	revenue	requirement	for	the	period	February	24,	2016	through	March	31,	2016.	A significant	portion	of	the	increase	was	related	to	the	purchase	of	Power	Block	2	of	the	Union	Power	Station;

•an	increase	in	the	purchased	power	and	capacity	acquisition	cost	recovery	rider	for	Entergy	New	Orleans,	as	approved	by	the	City Council,	effective	with	the	first	billing	cycle	of	March	2016,	primarily	related	to	the	purchase	of	Power	Block	1	of	the	Union	Power Station;

•an	increase	in	formula	rate	plan	revenues	for	Entergy	Louisiana,	implemented	with	the	first	billing	cycle	of	March	2016,	to	collect	the estimated	first-year	revenue	requirement	related	to	the	purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station;	and •an	increase	in	revenues	at	Entergy	Mississippi,	as	approved	by	the	MPSC,	effective	with	the	first	billing	cycle	of	July	2016,	and	an increase	in	revenues	collected	through	the	storm	damage	rider.

See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate	proceedings.	See	Note	14	to	the	financial	statements	for	discussion	of	the Union	Power	Station	purchase.

The	Louisiana	business	combination	customer	credits	variance	is	due	to	a	regulatory	liability	of	$107	million	recorded	by	Entergy	in October	2015	as	a	result	of	the	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	business	combination.	Consistent	with	the	terms	of	the stipulated	settlement	in	the	business	combination	proceeding,	electric	customers	of	Entergy	Louisiana	will	realize	customer	credits	associated	with the	business	combination;	accordingly,	in	October	2015,	Entergy	recorded	a	regulatory	liability	of	$107	million	($66	million	net-of-tax).	These costs	are	being

amortized	 over	 a	 nine-year	 period	 beginning	 December	 2015.	See	Note	2 to the	financial	statements	for	further	discussion	of the	business combination	and	customer	credits.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	more	favorable	weather	during	the	unbilled	period	and	an	increase	in industrial	usage,	partially	offset	by	the	effect	of	less	favorable	weather	on	residential	sales.	The	increase	in	industrial	usage	is	primarily	due	to expansion	projects,	primarily	in	the	chemicals	industry,	and	increased	demand	from	new	customers,	primarily	in	the	industrial	gases	industry.

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	for	tax	savings	to	be	shared	with	customers per	an	agreement	approved	by	the	LPSC.	The	tax	savings	resulted	from	the	2010-2011	IRS	audit	settlement	on	the	treatment	of	the	Louisiana	Act 55	financing	of	storm	costs	for	Hurricane	Gustav	and	Hurricane	Ike.	See	Note	3	to	the	financial	statements	for	additional	discussion	of	the settlement	and	benefit	sharing.

Included	in	Other	is	a	provision	of	$23	million	recorded	in	2016	related	to	the	settlement	of	the	Waterford	3	replacement	steam	generator prudence	review	proceeding,	offset	by	a	provision	of	$32	million	recorded	in	2015	related	to	the	uncertainty	at	that	time	associated	with	the resolution	of	the	Waterford	3	replacement	steam	generator	prudence	review	proceeding.		See	Note	2	to	the	financial	statements	for	a	discussion	of the	Waterford	3	replacement	steam	generator	prudence	review	proceeding.

| 2015	net	revenue | $1,666 |
| :--- | :--- |
| Nuclear\trealized\tprice\tchanges | (149) |
| Rhode\tIsland\tState\tEnergy\tCenter | (44) |
| Nuclear\tvolume | (36) |
| FitzPatrick\treimbursement\tagreement | 41 |
| Nuclear\tfuel\texpenses | 68 |
| Other | (4) |
| 2016\tnet\trevenue | $1,542 |

As	shown	in	the	table	above,	net	revenue	for	Entergy	Wholesale	Commodities	decreased	by	approximately	$124	million	in	2016	primarily due	to:

•lower	realized	wholesale	energy	prices	and	lower	capacity	prices,	the	amortization	of	the	Palisades	below-market	PPA,	and	Vermont Yankee	capacity	revenue.	The	effect	of	the	amortization	of	the	Palisades	below-market	PPA	and	Vermont	Yankee	capacity	revenue	on	the net	revenue	variance	from	2015	to	2016	is	minimal;

•the	sale	of	the	Rhode	Island	State	Energy	Center	in	December	2015.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the Rhode	Island	State	Energy	Center	sale;	and

•lower	volume	in	the	Entergy	Wholesale	Commodities	nuclear	fleet	resulting	from	more	refueling	outage	days	in	2016	as	compared	to 2015	and	larger	exercise	of	resupply	options	in	2016	as	compared	to	2015.	See	"Nuclear	Matters	-	Indian	Point"	below	for	discussion	of the	extended	Indian	Point	2	outage	in	the	second	quarter	2016.

# The	decrease	was	partially	offset	by:

•an	increase	resulting	from	the	reimbursement	agreement	with	Exelon	pursuant	to	which	Exelon	reimbursed	Entergy	for	specified	out-of- pocket	costs	associated	with	preparing	for	the	refueling	and	operation	of	FitzPatrick	that	otherwise	would	have	been	avoided	had	Entergy shut	down	FitzPatrick	in	January	2017.	Revenues	received	from	Exelon	under	the	reimbursement	agreement	are	offset	in	nuclear	fuel expenses	 and	 other	 operation	 and	 maintenance	 expenses	 and	 have	 no	 material	 effect	 on	 net	 income.	See "Entergy	 Wholesale Commodities	Exit	from	the	Merchant	Power	Business -	Sale	of	FitzPatrick"	below	for	further	discussion	of the	reimbursement agreement;	and

•a	decrease	in	nuclear	fuel	expenses	primarily	related	to	the	impairments	of	the	FitzPatrick,	Pilgrim,	and	Palisades	plants	and	related	assets. See	Note	14	to	the	financial	statements	for	discussion	of	the	impairments.

|  | 2016 | 2015 |
| :--- | :--- | :--- |
| Owned\tcapacity\t(MW)\t(a) | 4,800 | 4,880 |
| GWh\tbilled | 35,881 | 39,745 |
| Entergy\tWholesale\tCommodities\tNuclear\tFleet |  |  |
| Capacity\tfactor | 87% | 91% |
| GWh\tbilled | 33,551 | 35,859 |
| Average\tenergy\tand\tcapacity\trevenue\tper\tMWh | $47.31 | $50.29 |
| Refueling\tOutage\tDays: |  |  |
| Indian\tPoint\t2 | 102 | — |
| Indian\tPoint\t3 | — | 23 |
| Palisades | — | 32 |
| Pilgrim | — | 34 |

(a) The	reduction	in	owned	capacity	is	due	to	Entergy's	sale	of	its	50%	membership	interest	in	Top	Deer	Wind	Ventures,	LLC	in	November 2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	sale.

Other	operation	and	maintenance	expenses	decreased	from	$2,443	million	for	2015	to	$2,360	million	for	2016	primarily	due	to:

•a	decrease	of	$78	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	net	periodic	pension	and	other	postretirement benefits	costs	as	a	result	of	an	increase	in	the	discount	rate	used	to	value	the	benefit	liabilities	and	a	refinement	in	the	approach	used	to estimate	the	service	cost	and	interest	cost	components	of	pension	and	other	postretirement	costs.	See	"Critical	Accounting	Estimates" below	and	Note	11	to	the	financial	statements	for	further	discussion	of	pension	and	other	postretirement	benefit	costs;

•the	effects	of	recording	in	2016	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs.	The damages	awarded	include	the	reimbursement	of	approximately	$19	million	of	spent	nuclear	fuel	storage	costs	previously	recorded	as	other operation	and	maintenance	expense.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation; •the	 deferral	 in	 2016	 of	 $7.7	 million	 of	 previously-incurred	 costs	 related	 to	ANO	 post-Fukushima	 compliance	 and	 $9.9	 million	 of previously-incurred	costs	related	to	ANO	flood	barrier	compliance,	as	approved	by	the	APSC	in	February	2016	as	part	of	the	Entergy Arkansas	2015	rate	case	settlement.	These	costs	are	being

amortized	over	a	ten-year	period	beginning	March	2016.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate	case settlement;	and

•a	decrease	of	$13	million	in	energy	efficiency	costs,	including	the	effects	of	true-ups	to	energy	efficiency	filings	for	fixed	costs	to	be collected	from	customers	and	incentives	recognized	as	a	result	of	participation	in	energy	efficiency	programs.

The	decrease	was	partially	offset	by	an	increase	of	$61	million	in	nuclear	generation	expenses	primarily	due	to	higher	nuclear	labor	costs, including	contract	labor,	and	an	overall	higher	scope	of	work	done	during	plant	outages	in	2016	as	compared	to	prior	year.

The	asset	write-offs,	impairments,	and	related	charges	variance	is	due	to	the	following	activity:

•the	$45	million	($28	million	net-of-tax)	write-off	in	2015	 to	recognize that	a	portion	of the	assets	associated	with the	Waterford	3 replacement	steam	generator	project	was	no	longer	probable	of	recovery;	and

•the	$23.5	million	($15.3	million	net-of-tax)	write-off	in	2015	of	the	regulatory	asset	associated	with	the	Spindletop	gas	storage	facility	as	a result	of	the	approval	of	the	System	Agreement	termination	settlement	agreement.

See	Note	2	to	the	financial	statements	for	further	discussion	of	the	asset	write-offs.

Depreciation	and	amortization	expenses	 increased	primarily	due	 to	additions	 to	plant	 in	service,	 including	 the	Union	Power	Station purchased	in	March	2016,	partially	offset	by	the	effects	of	recording	the	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent nuclear	fuel	storage	costs.	The	damages	awarded	include	the	reimbursement	of	approximately	$11	million	in	2016	of	spent	nuclear	fuel	storage costs	previously	recorded	as	depreciation.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation.

Other	expenses	increased	primarily	due	to	an	increase	in	nuclear	refueling	outage	expenses	as	a	result	of	amortization	of	higher	costs associated	with	refueling	outages	and	increases	in	decommissioning	expenses	in	2016	primarily	due	to	revised	decommissioning	cost	studies	in 2015	for	Grand	Gulf	and	Waterford	3.

•an	increase	of	$60	million	in	severance	and	retention	costs	related	to	the	planned	shutdown	or	sale	of	the	Pilgrim	and	FitzPatrick	plants. See	"Entergy	Wholesale	Commodities	Exit	From	the	Merchant	Power	Business "	below	for	a	discussion	of	management's	strategy	to reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet;

•$41	million	associated	with	preparing	to	refuel	FitzPatrick	in	January	2017.	Exelon	reimbursed	Entergy	for	these	costs	in	accordance	with the	reimbursement	agreement	discussed	in	"Entergy	Wholesale	Commodities	Exit	From	the	Merchant	Power	Business -	Sale	 of FitzPatrick"	below;	and

•an	increase	of	$26	million	in	costs	related	to	Pilgrim's	response	to	a	planned	NRC	enhanced	inspection	as	a	result	of	the	NRC	placing Pilgrim	in	its	"multiple/repetitive	degraded	cornerstone	column"	(Column	4)	of	its	Reactor	Oversight	Process	Action	Matrix	in	September 2015.	See	Note	8	to	the	financial	statements	for	further	discussion	of	the	NRC's	decision	and	Pilgrim's	response.

# The	increase	was	partially	offset	by:

•the	effects	of	recording	the	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs.	The damages	awarded	include	the	reimbursement	of	approximately	$60	million	in	2016	compared	to	the	reimbursement	of	approximately	$2 million	in	2015	of	spent	nuclear	fuel	storage	costs

previously	recorded	as	other	operation	and	maintenance	expenses.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent nuclear	fuel	litigation;

•a	decrease	of	$32	million	as	a	result	of	the	sale	of	the	Rhode	Island	State	Energy	Center	in	December	2015.	See	Note	14	to	the	financial statements	for	further	discussion	of	the	Rhode	Island	State	Energy	Center	sale;	and

The	asset	write-offs,	impairments,	and	related	charges	variance	is	due	to	$2,836	million	($1,829	million	net-of-tax)	in	2016	of	impairment and	related	charges	primarily	to	write	down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	Palisades,	Indian	Point	2,	and	Indian Point	3	plants	and	related	assets	to	their	fair	values,	partially	offset	by	$2,036	million	($1,317	million	net-of-tax)	in	2015	of	impairment	and related	charges	primarily	to	write	down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	FitzPatrick,	Pilgrim,	and	Palisades	plants	and related	assets	to	their	fair	values.	See	Note	14	to	the	financial	statements	for	further	discussion	of	these	charges.

Depreciation	and	amortization	expenses	decreased	primarily	due	to:

•decreases	in	depreciable	asset	balances	as	a	result	of	the	impairments	of	the	FitzPatrick,	Pilgrim,	and	Palisades	plants.	See	Note	14	to	the financial	statements	for	further	discussion	of	the	impairments;

•the	effects	of	recording	the	final	court	decisions	in	several	lawsuits	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs.	The damages	awarded	include	the	reimbursement	of	approximately	$15	million	in	2016	compared	to	the	reimbursement	of	approximately	$4 million	 in	 2015	 of	 spent	 nuclear	 fuel	 storage	 costs	 previously	 recorded	 as	 depreciation.	See	 Note	 8	 to	 the	 financial	 statements	 for discussion	of	the	spent	nuclear	fuel	litigation;	and

•a	decrease	in	depreciable	asset	balances	as	a	result	of	the	sale	of	the	Rhode	Island	State	Energy	Center	in	December	2015.	See	Note	14	to the	financial	statements	for	further	discussion	of	the	Rhode	Island	State	Energy	Center	sale.

The	gain	on	sale	of	asset	resulted	from	the	sale	in	December	2015	of	the	583	MW	Rhode	Island	State	Energy	Center	in	Johnston,	Rhode Island,	a	business	wholly-owned	by	Entergy	in	the	Entergy	Wholesale	Commodities	segment.	Entergy	sold	the	Rhode	Island	State	Energy	Center for	approximately	$490	million	and	realized	a	pre-tax	gain	of	$154	million	on	the	sale.	See	Note	14	to	the	financial	statements	for	further discussion	of	the	Rhode	Island	State	Energy	Center	sale.

Other	expenses	decreased	primarily	due	to	the	reduction	in	deferred	refueling	outage	amortization	costs	related	to	the	impairments	of	the FitzPatrick,	Pilgrim,	and	Palisades	plants	and	related	assets,	partially	offset	by	increases	in	decommissioning	expenses	primarily	as	a	result	of	a trust	transfer	agreement	Entergy	entered	into	with	NYPA	in	August	2016	to	transfer	the	decommissioning	trusts	and	decommissioning	liabilities for	the	Indian	Point	3	and	FitzPatrick	plants	to	Entergy	and	a	revision	to	the	estimated	decommissioning	cost	liability	for	the	Entergy	Wholesale Commodities'	Pilgrim	plant	as	a	result	of	a	revised	decommissioning	cost	study	in	2015.	See	Note	14	to	the	financial	statements	for	further discussion	of	the	impairments	and	related	charges	and	Note	9	to	the	financial	statements	for	further	discussion	of	nuclear	decommissioning	costs.

The	effective	income	tax	rate	for	2015	was	80.4%.		The	difference	in	the	effective	income	tax	rate	versus	the	statutory	rate	of	35%	for 2015	was	primarily	due	to	the	tax	effects	of	the	Louisiana	business	combination.	See	Note	3	to	the	financial	statements	for	further	discussion	of the	tax	effects	of	the	Louisiana	business	combination.

# Income	Tax	Legislation

On	December	22,	2017,	President	Trump	signed	into	law	H.R.	1,	also	known	as	the	Tax	Cuts	and	Jobs	Act	(the	Act).	 As	a	result	of	the Act,	Entergy	and	the	Registrant	Subsidiaries	re-measured	their	deferred	tax	assets	and	liabilities	in	December	2017	to	reflect	the	reduction	in	the federal	corporate	income	tax	rate	from	35%	to	21%	that	is	effective	January	1,	2018.	Note	3	to	the	financial	statements	contains	additional discussion	of	the	effect	of	the	Act	on	2017	results	of	operations	and	financial	position,	the	provisions	of	the	Act,	and	the	uncertainties	associated with	accounting	for	the	Act,	and	Note	2	to	the	financial	statements	discusses	proceedings	commenced	or	other	responses	by	Entergy's	regulators to	the	Act.

On	a	going	forward	basis,	after	going	through	the	appropriate	regulatory	processes	Entergy	expects	the	Act	to	reduce	its	operating	cash flows	because	the	lower	federal	corporate	income	tax	rate	will	result	in	lower	income	tax	expense	collected	in	revenues	and	as	excess	deferred income	taxes	are	returned	to	customers.	In	general,	rate	base	is	expected	to	increase	over	time	as	a	consequence	of	the	Act	as	the	excess	deferred income	taxes	are	returned	to	customers.	Entergy	expects	to	finance	its	incremental	cash	requirements	as	a	consequence	of	these	changes	through	a combination	of	Registrant	Subsidiary	debt	and	Entergy	Corporation	debt	and	equity.	Entergy	Corporation	expects	the	equity	portion	of	this financing	to	be	approximately	$1	billion,	and	currently	expects	to	issue	all	of	this	equity	before	the	end	of	2019.	It	is	expected	that	certain	credit metrics	that	incorporate	operating	cash	flows	or	debt	outstanding	will	be	adversely	affected	by	the	effects	of	the	Act.

The	amount	and	timing	of	the	earnings	and	cash	effects	of	the	Act	and	the	financing	of	the	incremental	cash	requirements	will	depend upon	regulatory	treatment	of	the	effects	of	the	Act.	The	Registrant	Subsidiaries	will	work	directly	with	their	respective	regulators	to	determine	the appropriate	path	forward	in	each	jurisdiction.	Potential	regulatory	options	that	may	be	considered	include:

•determining	the	period	over	which	certain	income	tax	benefits	are	provided	to	customers;

•accelerating	depreciation	or	amortization	for	certain	assets	or	asset	classes;	and •increasing	or	modifying	capital	investments.

# Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power	Business

Entergy	management	has	undertaken	a	strategy	to	manage	and	reduce	the	risk	of	the	Entergy	Wholesale	Commodities	business,	which includes	taking	actions	to	reduce	the	size	of	the	merchant	fleet.	Management	evaluated	the	challenges	for	each	of	the	plants	based	on	a	variety	of factors	such	as	their	market	for	both	energy	and	capacity,	their	size,	their	contracted	positions,	and	the	amount	of	investment	required	to	continue to	operate	and	maintain	the	safety	and	integrity	of	the	plants,	including	the	estimated	asset	retirement	costs.	Management	continues	to	look	for ways	to	mitigate	the	operational	and	decommissioning	risks	associated	with	the	merchant	power	business.	Assumptions	regarding	the	operating life	of	the	plants	and	the	decommissioning	timeline	and	process	continue	to	be	evaluated.		Changes	to	current	assumptions	could	result	in	revisions to	the	asset	retirement	obligations	and	affect	compliance	with	certain	NRC	minimum	financial	assurance	requirements	for	meeting	obligations	to decommission	the	plants.	Increases	in	the	asset	retirement	obligations	could	result	in	an	increase	in	operating	expense	in	the	period	of	a	revision.

Assumptions	regarding	the	possibility	that	a	plant	may	have	an	operating	life	shorter	than	previously	assumed	will	likely	result	in	the	need	for additional	contributions	to	decommissioning	trust	funds,	or	the	posting	of	parent	guarantees,	letters	of	credit,	or	other	surety	mechanisms.

Entergy	Wholesale	Commodities	includes	the	ownership	of	the	following	nuclear	reactors:

As	discussed	below,	Entergy	sold	the	FitzPatrick	nuclear	power	plant	to	Exelon	in	March	2017.	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 addition,	Entergy	Wholesale	Commodities	provides	operations	and	management	services,	including	decommissioning	services,	to	nuclear	power plants	owned	by	other	utilities	in	the	United	States.	A	relatively	minor	portion	of	the	Entergy	Wholesale	Commodities	business	is	the	ownership of	interests	in	non-nuclear	power	plants	that	sell	the	electric	power	produced	by	those	plants	to	wholesale	customers.

# Shutdown	and	Planned	Sale	of	Vermont	Yankee

On	December	29,	2014,	the	Vermont	Yankee	plant	ceased	power	production	and	entered	its	decommissioning	phase. 	In	November	2016, Entergy	entered	 into	an	agreement	 to	sell	100%	of	 the	membership	 interests	 in	Entergy	Nuclear	Vermont	Yankee,	LLC	 to	a	subsidiary	of NorthStar.	Entergy	Nuclear	Vermont	Yankee	is	the	owner	of	the	Vermont	Yankee	plant	and	is	in	the	Entergy	Wholesale	Commodities	segment. The	sale	of	Entergy	Nuclear	Vermont	Yankee	to	NorthStar	will	include	the	transfer	of	the	nuclear	decommissioning	trust	fund	and	the	asset retirement	obligation	for	the	spent	fuel	management	and	decommissioning	of	the	plant.

Entergy	Nuclear	Vermont	Yankee	has	an	outstanding	credit	facility	with	borrowing	capacity	of	$145	million	to	pay	for	dry	fuel	storage costs.	This	credit	facility	is	guaranteed	by	Entergy	Corporation.	At	or	before	closing,	a	subsidiary	of	Entergy	will	assume	the	obligations	under	the existing	credit	facility	or	enter	into	a	new	credit	facility,	and	Entergy	will	guarantee	the	credit	facility.	At	the	closing	of	the	sale	transaction, NorthStar	will	pay	$1,000	for	the	membership	interests	in	Entergy	Nuclear	Vermont	Yankee,	and	NorthStar	will	cause	Entergy	Nuclear	Vermont Yankee	to	issue	a	promissory	note	to	an	Entergy	affiliate.	The	amount	of	the	promissory	note	issued	will	be	equal	to	the	amount	drawn	under	the credit	facility	or	the	amount	drawn	under	the	new	credit	facility,	plus	borrowing	fees	and	costs	incurred	by	Entergy	in	connection	with	such facility.	The	principal	amount	drawn	under	the	outstanding	credit	facility	was	$104	million	as	of	December	31,	2017,	and	the	net	book	value	of Entergy	Nuclear	Vermont	Yankee,	including	unrealized	gains	on	the	decommissioning	trust	fund,	as	of	December	31,	2017,	was	approximately $123	million.

Entergy	plans	to	transfer	all	spent	nuclear	fuel	to	dry	cask	storage	by	the	end	of	2018	in	advance	of	the	planned	transaction	close.	Under the	sale	agreement	and	related	agreements	to	be	entered	into	at	the	closing,	NorthStar	will	commit	to	initiate	decommissioning	and	site	restoration by	2021	and	complete	those	activities	by	2030.	The	original	planned	completion	date,	as	outlined	in	Entergy's	Post	Shutdown	Decommissioning Activities	Report	filed	with	the	NRC,	was	2075.	Entergy	Nuclear	Vermont	Yankee,	under	NorthStar	ownership,	will	be	required	to	repay	the promissory	note	issued	to	Entergy	with	certain	of	the	proceeds	from	the	recovery	of	damages	under	its	claims	against	the	DOE	related	to	spent nuclear	fuel	disposal,	with	any	balance	remaining	due	at	partial	site	release,	subject	to	extension	not	to	exceed	two	years	from	partial	site	release.

The	transaction	is	subject	to	certain	closing	conditions,	including	approval	by	the	NRC;	approval	by	the	State	of	Vermont	Public	Utility Commission,	including	approval	of	site	restoration	standards	that	have	been	proposed	as	part	of	the	transaction;	the	transfer	of	all	spent	nuclear fuel	to	dry	fuel	storage	on	the	independent	spent	fuel	storage	installation;	and	that	the	market	value	of	the	fund	assets	held	in	the	decommissioning trust	fund	for	the	Vermont	Yankee	Nuclear	Power	Station,	less	the	hypothetical	income	tax	on	the	aggregate	unrealized	net	gain	of	such	fund assets	at	closing,	is	equal	to	or	exceeds	$451.95	million,	subject	to	adjustments.	Entergy	has	the	option	to	contribute	to	the	decommissioning	trust fund	if	the	value	is	less	than	$451.95	million,	subject	to	adjustments.	The	transaction	is	planned	to	close	by	the	end	of	2018.

# Sale	of	Rhode	Island	State	Energy	Center

In	December	2015,	Entergy	sold	the	Rhode	Island	State	Energy	Center,	a	583	MW	natural	gas-fired	combined-cycle	generating	plant owned	by	Entergy	in	the	Entergy	Wholesale	Commodities	segment.	Entergy	sold	the	Rhode	Island	State	Energy	Center	for	approximately	$490 million	and	realized	a	pre-tax	gain	of	$154	million	on	the	sale.

# Sale	of	Top	Deer	Investment

In	November	2016,	Entergy	sold	its	50%	membership	interest	in	Top	Deer	Wind	Ventures,	LLC,	a	wind-powered	electric	generation	joint venture	owned	by	Entergy	in	the	Entergy	Wholesale	Commodities	segment	and	accounted	for	as	an	equity	method	investment.	Entergy	sold	its 50%	membership	interest	in	Top	Deer	for	approximately	$0.5	million	and	realized	a	pre-tax	loss	of	$0.2	million	on	the	sale.

# Sale	of	FitzPatrick

In	October	2015,	Entergy	determined	that	it	would	close	the	FitzPatrick	plant.	The	original	expectation	was	to	shut	down	the	FitzPatrick plant	at	the	end	of	its	fuel	cycle	in	January	2017.	See	Note	14	to	the	financial	statements	for	discussion	of	the	impairment	charges	associated	with the	decision	to	cease	operations	earlier	than	expected.

In	 August	 2016,	 Entergy	 entered	 into	 a	 trust	 transfer	 agreement	 with	 NYPA	 to	 transfer	 the	 decommissioning	 trust	 funds	 and decommissioning	liabilities	for	the	Indian	Point	3	and	FitzPatrick	plants	to	Entergy.	When	Entergy	purchased	Indian	Point	3	and	FitzPatrick	in 2000	 from	 NYPA,	 NYPA	 retained	 the	 decommissioning	 trust	 funds	 and	 the	 decommissioning	 liabilities.	 	 NYPA	 and	 Entergy	 subsidiaries executed	 decommissioning	 agreements,	 which	 specified	 their	 decommissioning	 obligations.	 	 NYPA	 had	 the	 right	 to	 require	 the	 Entergy subsidiaries	to	assume	each	of	the	decommissioning	liabilities	provided	that	it	assigned	the	corresponding	decommissioning	trust,	up	to	a	specified level,	 to	 the	 Entergy	 subsidiaries.	 	 Under	 the	 original	 agreements,	 if	 the	 decommissioning	 liabilities	 were	 retained	 by	 NYPA,	 the	 Entergy subsidiaries	 would	 perform	 the	 decommissioning	 of	 the	 plants	 at	 a	 price	 equal	 to	 the	 lesser	 of	 a	 pre-specified	 level	 or	 the	 amount	 in	 the decommissioning	trust	funds.		At	the	time	of	the	acquisition	of	the	plants	Entergy	recorded	a	contract	asset	that	represented	an	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	was	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	was	recorded	as	interest	income.	As	a result	of	the	agreement	with	NYPA,	in	the	third	quarter	2016,	Entergy	removed	the	contract	asset	from	its	balance	sheet,	and	recorded	receivables for	the	beneficial	interests	in	the	decommissioning	trust	funds	and	asset	retirement	obligations	for	the	decommissioning	liabilities.	The	 asset retirement	obligations	are	accreted	monthly	through	a	charge	to	decommissioning	expense.	The	decommissioning	trust	funds	for	the	Indian	Point 3	and	FitzPatrick	plants	were	transferred	to	Entergy	by	NYPA	in	January	2017.	See	Note	9	to	the	financial	statements	for	further	discussion	of Indian	Point	3	and	FitzPatrick's	decommissioning	liabilities	and	see	Note	16	to	the	financial	statements	for	further	discussion	of	the	receivables	for the	beneficial	interests	in	Indian	Point	3	and	FitzPatrick's	decommissioning	trust	funds	as	of	December	31,	2016.

In	August	2016,	Entergy	entered	into	an	agreement	to	sell	the	FitzPatrick	plant	to	Exelon.	NRC	approval	of	the	sale	was	received	in March	2017.	The	transaction	closed	in	March	2017	for	a	purchase	price	of	$110	million,	which

included	a	$10	million	non-refundable	signing	fee	paid	in	August	2016,	in	addition	to	the	assumption	by	Exelon	of	certain	liabilities	related	to	the FitzPatrick	plant,	resulting	in	a	pre-tax	gain	on	the	sale	of	$16	million.	At	the	transaction	close,	Exelon	paid	an	additional	$8	million	for	the proration	of	certain	expenses	prepaid	by	Entergy.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	sale	of	FitzPatrick.	As discussed	in	Note	3	to	the	financial	statements,	as	a	result	of	the	sale	of	FitzPatrick,	Entergy	re-determined	the	plant's	tax	basis,	resulting	in	a	$44 million	income	tax	benefit	in	the	first	quarter	2017.

# Planned	Shutdown	of	Pilgrim

In	October	2015,	Entergy	determined	that	it	would	close	the	Pilgrim	plant.	The	decision	came	after	management's	extensive	analysis	of the	economics	and	operating	life	of	the	plant	following	the	NRC's	decision	in	September	2015	to	place	the	plant	in	its	"multiple/repetitive degraded	cornerstone	column"	(Column	4)	of	its	Reactor	Oversight	Process	Action	Matrix.	The	Pilgrim	plant	is	expected	to	cease	operations	on May	31,	2019,	at	the	end	of	its	current	fuel	cycle.	See	Note	14	to	the	financial	statements	for	discussion	of	the	impairment	charges	associated	with the	decision	to	cease	operations	earlier	than	expected	and	see	Note	8	for	further	discussion	on	the	placement	of	Pilgrim	in	Column	4.

# Planned	Shutdown	of	Indian	Point	2	and	Indian	Point	3

Indian	Point	2	and	Indian	Point	3	have	been	involved,	and	have	faced	opposition,	in	extensive	licensing	proceedings.	In	January	2017, Entergy	announced	that	it	reached	a	settlement	with	New	York	State	to	shut	down	Indian	Point	2	by	April	30,	2020	and	Indian	Point	3	by	April	30, 2021.	See	further	discussion	of	the	licensing	proceedings	and	the	settlement	reached	with	New	York	State	in	"Entergy	Wholesale	Commodities Authorizations	to	Operate	Indian	Point"	below.

As	discussed	above,	in	August	2016,	Entergy	entered	into	a	trust	transfer	agreement	with	NYPA	to	transfer	the	decommissioning	trust fund	and	decommissioning	liability	for	the	Indian	Point	3	plant	to	Entergy.	The	decommissioning	trust	fund	for	the	Indian	Point	3	plant	was transferred	to	Entergy	by	NYPA	in	January	2017.

See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	charges	associated	with	management's	evaluation	of alternatives	to	the	continued	operation	of	the	Indian	Point	plants.

# Planned	Shutdown	of	Palisades

Most	of	the	Palisades	output	is	sold	under	a	power	purchase	agreement	(PPA)	with	Consumers	Energy,	entered	into	when	the	plant	was acquired	in	2007,	that	is	scheduled	to	expire	in	2022.	The	PPA	prices	currently	exceed	market	prices	and	escalate	each	year,	up	to	$61.50/MWh	in 2022.	In	December	2016,	Entergy	reached	an	agreement	with	Consumers	Energy	to	amend	the	existing	PPA	to	terminate	early,	on	May	31,	2018. Pursuant	to	the	agreement	to	amend	the	PPA,	Consumers	Energy	would	pay	Entergy	$172	million	for	the	early	termination	of	the	PPA.	 The	PPA amendment	agreement	was	subject	to	regulatory	approvals,	including	approval	by	the	Michigan	Public	Service	Commission.	Separately,	Entergy intended	to	shut	down	the	Palisades	nuclear	power	plant	permanently	on	October	1,	2018,	after	refueling	in	the	spring	of	2017	and	operating through	the	end	of	that	fuel	cycle.

In	September	2017	the	Michigan	Public	Service	Commission	issued	an	order	conditionally	approving	the	PPA	amendment	transaction, but	only	granting	Consumers	Energy	recovery	of	$136.6	million	of	the	$172	million	requested	early	termination	payment.	As	a	result,	Entergy	and Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement.	Entergy	will	continue	to	operate	Palisades	under	the	current	PPA	with Consumers	Energy,	instead	of	shutting	down	in	the	fall	of	2018	as	previously	planned.	Entergy	intends	to	shut	down	the	Palisades	nuclear	power plant	 permanently	 on	 May	 31,	 2022.	As	 a	 result	 of	 the	 change	 in	 expected	 operating	 life	 of	 the	 plant,	 the	 expected	 probability-weighted undiscounted	net	cash	flows	as	of	September	30,	2017	exceeded	the	carrying	value	of	the	plant	and	related	assets.	Accordingly,	nuclear	fuel spending,	nuclear	refueling	outage	spending,	and	expenditures	for	capital	assets	incurred	at	Palisades	after	September	30,	2017	are	no	longer charged	to	expense	as	incurred,	but	recorded	as

assets	and	depreciated	or	amortized,	subject	to	the	typical	periodic	impairment	reviews	prescribed	in	the	accounting	rules.	See	Note	9	to	the financial	statements	for	discussion	of	the	associated	asset	retirement	obligation	revision.	See	Note	14	to	the	financial	statements	for	discussion	of the	updated	calculation	of	the	liability	amortization	associated	with	the	PPA	and	discussion	of	the	impairment	charges	associated	with	the	decision to	cease	operations	earlier	than	expected.

# Costs	Associated	with	Entergy	Wholesale	Commodities	Strategic	Transactions

Entergy	incurred	approximately	$113	million	in	costs	in	2017	and	$95	million	in	costs	in	2016	associated	with	management's	strategy	to reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet,	primarily	employee	retention	and	severance	expenses	and	other	benefits- related	 costs,	 and	 contracted	 economic	 development	 contributions.	Entergy	 expects	 to	 incur	 employee	 retention	 and	 severance	 expenses	 of approximately	$165	million	in	2018,	and	approximately	$205	million	from	2019	through	mid-2022	associated	with	these	strategic	transactions. See	Note	13	to	the	financial	statements	for	further	discussion	of	these	costs.

In	 2017,	 Entergy	 Wholesale	 Commodities	 incurred	 impairment	 charges	 related	 to	 nuclear	 fuel	 spending,	 nuclear	 refueling	 outage spending,	and	expenditures	for	capital	assets	of	$0.5	billion.	These	costs	were	charged	to	expense	as	incurred	as	a	result	of	the	impaired	value	of the	 Entergy	Wholesale	 Commodities	 nuclear	 plants'	 long-lived	 assets	 due	 to	 the	 significantly	 reduced	 remaining	 estimated	 operating	 lives associated	with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet.	Entergy	expects	to	continue	to incur	costs	associated	with	nuclear	fuel-related	spending	and	expenditures	for	capital	assets	and,	except	for	Palisades,	expects	to	continue	to charge	these	costs	to	expense	as	incurred	because	Entergy	expects	the	value	of	the	plants	to	continue	to	be	impaired.	In	2016,	Entergy	Wholesale Commodities	incurred	impairment	charges	of	$2.8	billion	primarily	to	write	down	the	carrying	values	of	the	Entergy	Wholesale	Commodities' Palisades,	Indian	Point	2,	and	Indian	Point	3	plants	and	related	assets	to	their	fair	values.	See	Note	14	to	the	financial	statements	for	further discussion	of	these	impairment	charges.

# Entergy	Wholesale	Commodities	Authorizations	to	Operate	Indian	Point

In	April	2007,	Entergy	submitted	to	the	NRC	a	joint	application	to	renew	the	operating	licenses	for	Indian	Point	2	and	Indian	Point	3	for	an additional	20	years.	The	original	expiration	dates	of	the	NRC	operating	licenses	for	Indian	Point	2	and	Indian	Point	3	were	in	September	2013	and December	2015,	respectively.	While	the	NRC	staff	reviews	the	license	renewal	applications,	Indian	Point	2	and	Indian	Point	3's	initial	license terms	have	expired	and	the	plants	are	operating	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.

In	January	2017,	Entergy	reached	a	settlement	with	New	York	State,	several	State	agencies,	and	Riverkeeper,	Inc.,	under	which	Indian Point	2	and	Indian	Point	3	will	cease	commercial	operation	by	April	30,	2020	and	April	30,	2021,	respectively,	subject	to	certain	conditions, including	 New	 York	 State's	 withdrawal	 of	 opposition	 to	 Indian	 Point's	 license	 renewals	 and	 issuance	 of	 contested	 permits	 and	 similar authorizations.	See	Note	14	to	the	financial	statements	for	a	discussion	of	the	impairment	and	related	charges	associated	with	the	settlement	with New	York	State.

The	Indian	Point	settlement	required	New	York	State	agencies	to	issue	environmental	certifications	needed	for	license	renewal	and	a renewed	water	discharge	permit	based	on	current	plant	configuration.	It	also	required	the	New	York	State	Attorney	General	and	Riverkeeper	to withdraw	their	contentions	pending	before	the	Atomic	Safety	and	Licensing	Board	(ASLB).	In	exchange,	Entergy	commits	to	cease	commercial operation	of	Indian	Point	2	by	April	30,	2020	and	Indian	Point	3	by	April	30,	2021.	These	actions	have	been	completed,	all	New	York	State approvals	required	for	the	NRC	to	issue	renewed	licenses	have	been	granted,	and	the	ASLB	has	terminated	proceedings	before	it	following	the withdrawal	of	pending	contentions.	The	NRC	is	not	expected	to	issue	renewed	licenses	earlier	than	third	quarter	2018,	as	its	staff	must	complete updates	 to	 the	 record	 on	 environmental	 and	 safety	 matters	 (a	 supplement	 to	 the	 final	 supplemental	 environmental	 impact	 statement	 and	 a supplement	to	the	final	safety	evaluation	report).

Operations	may	be	extended	up	to	four	additional	years	for	each	unit	by	mutual	agreement	of	Entergy	and	New	York	State	based	on	an exigent	reliability	need	for	Indian	Point	generation.	In	accordance	with	the	FERC-approved	tariff	of	the	New	York	Independent	System	Operator (NYISO),	Entergy	submitted	to	the	NYISO	a	notice	of	generator	deactivation	based	on	the	dates	in	the	settlement	(no	later	than	April	30,	2020	for Indian	Point	Unit	2	and	April	30,	2021	for	Indian	Point	Unit	3).	In	December	2017,	NYISO	issued	a	report	stating	there	will	not	be	a	system reliability	 need	 following	 the	 deactivation	 of	 Indian	 Point.	The	 NYISO	 also	 has	 advised	 that	 it	 will	 perform	 an	 analysis	 of	 the	 potential competitive	impacts	of	the	proposed	retirement	under	provisions	of	its	tariff.	The	deadline	for	the	NYISO	to	make	a	withholding	determination	is in	dispute	and	is	pending	before	the	FERC.

In	addition	to	contractually	agreeing	to	cease	commercial	operations	early,	in	February	2017	Entergy	filed	with	the	NRC	an	amendment	to its	license	renewal	application	changing	the	term	of	the	requested	licenses	to	coincide	with	the	latest	possible	extension	by	mutual	agreement based	on	exigent	reliability	needs:	April	30,	2024	for	Indian	Point	2	and	April	30,	2025	for	Indian	Point	3.	If	Entergy	reasonably	determines	that the	NRC	will	treat	the	amendment	other	than	as	a	routine	amendment,	Entergy	may	withdraw	the	amendment.

Other	provisions	of	the	settlement	include	termination	of	all	then-existing	investigations	of	Indian	Point	by	the	agencies	signing	the agreement,	which	include	the	New	York	State	Department	of	Environmental	Conservation,	the	New	York	State	Department	of	State,	the	New York	State	Department	of	Public	Service,	the	New	York	State	Department	of	Health,	and	the	New	York	State	Attorney	General.	 The	settlement recognizes	the	right	of	New	York	State	agencies	to	pursue	new	investigations	and	enforcement	actions	with	respect	to	new	circumstances	or existing	conditions	that	become	materially	exacerbated.

Another	provision	of	the	settlement	obligates	Entergy	to	establish	a	$15	million	fund	for	environmental	projects	and	community	support. Apportionment	and	allocation	of	funds	to	beneficiaries	are	to	be	determined	by	mutual	agreement	of	New	York	State	and	Entergy.	The	settlement recognizes	New	York	State's	right	to	perform	an	annual	inspection	of	Indian	Point,	with	scope	and	timing	to	be	determined	by	mutual	agreement.

In	May	2017	a	plaintiff	filed	two	parallel	state	court	appeals	challenging	New	York	State's	actions	in	signing	and	implementing	the	Indian Point	settlement	with	Entergy	on	the	basis	that	the	State	failed	to	perform	sufficient	environmental	analysis	of	its	actions.	All	signatories	to	the settlement	 agreement,	 including	 the	 Entergy	 affiliates	 that	 hold	 NRC	 licenses	 for	 Indian	 Point,	 were	 named.	The	 appeals	 were	 voluntarily dismissed	in	November	2017.

# Liquidity	and	Capital	Resources

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

# Capital	Structure

Entergy's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.	The	increase	in	the	debt	to	capital	ratio	for Entergy	as	of	December	31,	2017	is	primarily	due	to	an	increase	in	commercial	paper	outstanding	in	2017	as	compared	to	2016.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 67.1% | 64.8% |
| Effect\tof\texcluding\tsecuritization\tbonds | (0.8%) | (1.0%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 66.3% | 63.8% |
| Effect\tof\tsubtracting\tcash | (1.1%) | (2.0%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 65.2% | 61.8% |

(a) Calculation	excludes	the	Arkansas,	Louisiana,	New	Orleans,	and	Texas	securitization	bonds,	which	are	non-recourse	to	Entergy	Arkansas, Entergy	Louisiana,	Entergy	New	Orleans,	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,	2017.	To	estimate	future	interest	payments	for	variable rate	debt,	Entergy	used	the	rate	as	of	December	31,	2017.	The	amounts	below	include	payments	on	System	Energy's	Grand	Gulf	sale-leaseback transaction,	which	are	included	in	long-term	debt	on	the	balance	sheet.

| interest	payments | 2018 | 2019 | 2020 | 2021-2022 | after	2022 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Utility | $1,427 | $1,430 | $927 | $2,234 | $15,102 |
| Entergy\tWholesale\tCommodities | 3 | 3 | 106 | — | — |
| Parent\tand\tOther | 76 | 76 | 520 | 953 | 832 |
| Total | $1,506 | $1,509 | $1,553 | $3,187 | $15,934 |

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	August	2022.	The	facility permits	the	issuance	of	letters	of	credit	against	$20	million	of	the	total	borrowing	capacity	of	the	credit	facility.	The	commitment	fee	is	currently 0.225%	of	the	undrawn	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,	2017	was	2.55%	on	the drawn	portion	of	the	facility.

As	of	December	31,	2017,	amounts	outstanding	and	capacity	available	under	the	$3.5	billion	credit	facility	are:

| Capacity | Borrowings | Letters	of	Credit | Capacity	Available |
| :--- | :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |  |
| $3,500 | $210 | $6 | $3,284 |

A	covenant	in	Entergy	Corporation's	credit	facility	requires	Entergy	to	maintain	a	consolidated	debt	ratio,	as	defined,	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.	One	such	difference	is	that	it	excludes	the	effects,	among	other	things,	of	certain	impairments	related	to	the	Entergy	Wholesale Commodities	nuclear	generation	assets.	Entergy	is	currently	in	compliance	with	the	covenant	and	expects	to	remain	in	compliance	with	this 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.

Entergy	Corporation	has	a	commercial	paper	program	with	a	Board-approved	program	limit	of	up	to 	$2	billion.		As	of	December	31, 2017,	 Entergy	 Corporation	 had	$1.467	 billion	 of	 commercial	 paper	 outstanding.	 	 The	 weighted-average	 interest	 rate	 for	 the	 year	 ended December	31,	2017	was	1.49%.

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

|  | 2018 | 2019 | 2020 | 2021-2022 | after	2022 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Capital\tlease\tpayments | $3 | $3 | $3 | $6 | $19 |

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

Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	each	had	credit	facilities	available	as of	December	31,	2017	as	follows:

| Company | Expiration	Date | Amount	of	Facility | Interest<br>Rate	(a) | Amount	Drawn<br>	as	of	December	31,<br>2017 | Letters	of	Credit<br>Outstanding	as	of<br>December	31,	2017 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Entergy\tArkansas | April\t2018 | $20\tmillion\t(b) | 2.82% | — | — |
| Entergy\tArkansas | August\t2022 | $150\tmillion\t(c) | 2.82% | — | — |
| Entergy\tLouisiana | August\t2022 | $350\tmillion\t(c) | 2.82% | — | $9.1\tmillion |
| Entergy\tMississippi | May\t2018 | $10\tmillion\t(d) | 3.07% | — | — |
| Entergy\tMississippi | May\t2018 | $20\tmillion\t(d) | 3.07% | — | — |
| Entergy\tMississippi | May\t2018 | $35\tmillion\t(d) | 3.07% | — | — |
| Entergy\tMississippi | May\t2018 | $37.5\tmillion\t(d) | 3.07% | — | — |
| Entergy\tNew\tOrleans | November\t2018 | $25\tmillion\t(c) | 3.04% | — | $0.8\tmillion |
| Entergy\tTexas | August\t2022 | $150\tmillion\t(c) | 3.07% | — | $25.6\tmillion |

(a) The	interest	rate	is	the	estimated	interest	rate	as	of	December	31,	2017	that	would	have	been	applied	to	outstanding	borrowings	under	the facility.

(b) Borrowings	 under this	 Entergy	Arkansas	 credit	 facility	 may	 be	 secured	 by	 a	 security interest in its	 accounts	 receivable	 at	 Entergy Arkansas's	option.

(c) The	credit	facility	permits	the	issuance	of	letters	of	credit	against	a	portion	of	the	borrowing	capacity	of	the	facility	as	follows:	$5	million for	Entergy	Arkansas;	$15	million	for	Entergy	Louisiana;	$10	million	for	Entergy	New	Orleans;	and	$30	million	for	Entergy	Texas.

(d) Borrowings	under	the	Entergy	Mississippi	credit	facilities	may	be	secured	by	a	security	interest	in	its	accounts	receivable	at	Entergy Mississippi's	option.

Each	of	the	credit	facilities	requires	the	Registrant	Subsidiary	borrower	to	maintain	a	debt	ratio,	as	defined,	of	65%	or	less	of	its	total capitalization.	Each	Registrant	Subsidiary	is	in	compliance	with	this	covenant.

In	addition,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas	each	entered	into	one	or more	uncommitted	standby	letter	of	credit	facilities	as	a	means	to	post	collateral	to	support	its	obligations	to	MISO.	Following	is	a	summary	of	the uncommitted	standby	letter	of	credit	facilities	as	of	December	31,	2017:

| Company | Amount	of<br>Uncommitted	Facility | Letter	of	Credit	Fee | Letters	of	Credit	Issued	as	of<br>December	31,	2017	(a) |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | $25\tmillion | 0.70% | $1.0\tmillion |
| Entergy\tLouisiana | $125\tmillion | 0.70% | $29.7\tmillion |
| Entergy\tMississippi | $40\tmillion | 0.70% | $15.3\tmillion |
| Entergy\tNew\tOrleans | $15\tmillion | 1.00% | $1.4\tmillion |
| Entergy\tTexas | $50\tmillion | 0.70% | $22.8\tmillion |

(a) As	of	December	31,	2017,	letters	of	credit	posted	with	MISO	covered	financial	transmission	right	exposure	of	$0.2	million	for	Entergy Arkansas,	$0.1	 million	 for	 Entergy	 Mississippi,	 and	$0.05	 million	 for	 Entergy	 Texas.	See	 Note	 15	 to	 the	 financial	 statements	 for discussion	of	financial	transmission	rights.

Entergy	Nuclear	Vermont	Yankee	has	a	credit	facility	guaranteed	by	Entergy	Corporation	with	a	borrowing	capacity	of	 $145	million	that expires	in	November	2020.	As	of	December	31,	2017,	$104	million	in	cash	borrowings	were	outstanding	under	the	credit	facility.		The	weighted average	interest	rate	for	the	year	ended	December	31,	2017	was	2.64%	on	the	drawn	portion	of	the	facility.		Entergy	Nuclear	Vermont	Yankee also	had	an	uncommitted	credit	facility	guaranteed	by	Entergy	Corporation	with	a	borrowing	capacity	of	$85	million	that	expired	in	January	2018. As	 of	December	31,	2017,	 there	 were	 no	 cash	 borrowings	 outstanding	 under	 the	 credit	 facility.	See	Note	4	 to	 the	financial	statements	for additional	discussion	of	the	Vermont	Yankee	credit	facilities.

# 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,	2017	on	non-cancelable	operating	leases	with	a	term	over	one year:

Operating	leases	are	discussed	in	Note	10	to	the	financial	statements.

Summary	of	Contractual	Obligations	of	Consolidated	Entities

| Contractual	Obligations | 2018 | 2019-2020 | 2021-2022 | after	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $1,506 | $3,062 | $3,187 | $15,934 | $23,689 |
| Capital\tlease\tpayments\t(b) | $3 | $6 | $6 | $19 | $34 |
| Operating\tleases\t(b)\t(c) | $80 | $150 | $102 | $97 | $429 |
| Purchase\tobligations\t(d) | $1,394 | $2,485 | $1,992 | $4,728 | $10,599 |

(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) Does	not	include	power	purchase	agreements	that	are	accounted	for	as	leases	that	are	included	in	purchase	obligations.

(d) 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	stated	above,	Entergy	currently	expects	to	contribute	approximately	$352.1	million	to	its	pension	plans and	approximately	$52.3	million	to	other	postretirement	plans	in	2018,	although	the	2018	required	pension	contributions	will	be	known	with	more certainty	 when	 the	 January	 1,	 2018	 valuations	 are	 completed,	 which	 is	 expected	 by	April	 1,	 2018.	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	$916	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	2018	through	2020.

| Planned	construction	and	capital	investments | 2018 | 2019 | 2020 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Utility: |  |  |  |
| Generation | $1,590 | $1,410 | $1,245 |
| Transmission | 990 | 865 | 735 |
| Distribution | 860 | 1,030 | 945 |
| Utility\tSupport | 480 | 335 | 375 |
| Total | 3,920 | 3,640 | 3,300 |
| Entergy\tWholesale\tCommodities | 245 | 75 | 35 |
| Total | $4,165 | $3,715 | $3,335 |

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	types	of	construction	and	capital	investments:

•Investments,	including	the	St.	Charles	Power	Station,	Lake	Charles	Power	Station,	New	Orleans	Power	Station,	and	Montgomery	County Power	Station,	each	discussed	below,	and	potential	construction	of	additional	generation. •Entergy	 Wholesale	 Commodities	 investments	 associated	 with	 specific	 investments such	 as	 component replacements, software	 and security,	and	dry	cask	storage.

•Investments	in	Entergy's	nuclear	fleet.

•Transmission	spending	to	enhance	reliability,	reduce	congestion,	and	enable	economic	growth.

•Distribution	spending	to	enhance	reliability	and	improve	service	to	customers,	including	investment	to	support	advanced	metering.

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	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.

# St.	Charles	Power	Station

In	August	2015,	Entergy	Louisiana	filed	with	the	LPSC	an	application	seeking	certification	that	the	public	necessity	and	convenience would	be	served	by	the	construction	of	the	St.	Charles	Power	Station,	a	nominal	980	megawatt	combined-cycle	generating	unit,	on	land	adjacent to	 the	 existing	 Little	 Gypsy	 plant	 in	 St.	 Charles	 Parish,	 Louisiana.	It	 is	 currently	 estimated	 to	 cost	 $869	 million	 to	 construct,	 including transmission	interconnection	and	other	related	costs.	The	LPSC	issued	an	order	approving	certification	of	St.	Charles	Power	Station	in	December 2016.	Construction	is	in	progress	and	commercial	operation	is	estimated	to	occur	by	mid-2019.

# Lake	Charles	Power	Station

In	November	2016,	Entergy	Louisiana	filed	an	application	with	the	LPSC	seeking	certification	that	the	public	convenience	and	necessity would	be	served	by	the	construction	of	the	Lake	Charles	Power	Station,	a	nominal	994	megawatt	combined-cycle	generating	unit	in	Westlake, Louisiana,	on	land	adjacent	to	the	existing	Nelson	plant	in	Calcasieu	Parish.	The	current	estimated	cost	of	the	Lake	Charles	Power	Station	is	$872 million,	including	estimated	costs	of	transmission	interconnection	and	other	related	costs.	In	May	2017	the	parties	to	the	proceeding	agreed	to	an uncontested	stipulation	finding	that	construction	of	the	Lake	Charles	Power	Station	is	in	the	public	interest	and	authorizing	an	in-service	rate recovery	plan.	In	July	2017	the	LPSC	issued	an	order	unanimously	approving	the	stipulation	and	approved	certification	of	the	unit.	Construction	is in	progress	and	commercial	operation	is	expected	to	occur	by	mid-2020.

# New	Orleans	Power	Station

In	June	2016,	Entergy	New	Orleans	filed	an	application	with	the	City	Council	seeking	a	public	interest	determination	and	authorization	to construct	the	New	Orleans	Power	Station,	a	226	MW	advanced	combustion	turbine	in	New	Orleans,	Louisiana,	at	the	site	of	the	existing	Michoud generating	facility,	which	was	retired	effective	May	31,	2016.	In	January	2017	several	intervenors	filed	testimony	opposing	the	construction	of	the New	Orleans	Power	Station	on	various	grounds.	In	July	2017,	Entergy	New	Orleans	submitted	a	supplemental	and	amending	application	to	the City	Council	seeking	approval	to	construct	either	the	originally	proposed	226	MW	advanced	combustion	turbine,	or	alternatively,	a	128	MW	unit composed	of	natural	gas-fired	reciprocating	engines	and	a	related	cost	recovery	plan.	The	application	included	an	updated	cost	estimate	of	$232 million	for	 the	226	MW	advanced	combustion	 turbine.	The	cost	estimate	for	 the	alternative	128	MW	unit	 is	$210	million.	In	addition,	the application	renewed	the	commitment	to	pursue	up	to	100	MW	of	renewable	resources	to	serve	New	Orleans.	In	testimony	filed	subsequent	to Entergy	New	Orleans's	supplemental	and	amending	application,	several	intervenors	oppose	City	Council	approval	of	either	alternative,	while	the City	Council	advisors	and	one	intervenor	support	the	smaller	alternative.	A	contested	hearing	was	held	in	December	2017	and	post-hearing	briefs were	filed	in	January	2018.	In	February	2018	the	City	Council	Utility	Committee	adopted	a	resolution	approving	construction	of	the	128	MW unit.	The	full	City	Council	is	expected

to	vote	on	the	resolution	in	March	2018.	The	commercial	operation	date	is	dependent	on	the	alternative	selected	by	the	City	Council	and	the receipt	of	other	permits	and	approvals.

# Montgomery	County	Power	Station

In	October	2016,	Entergy	Texas	filed	an	application	with	the	PUCT	seeking	certification	that	the	public	convenience	and	necessity	would be	served	by	the	construction	of	the	Montgomery	County	Power	Station,	a	nominal	993	MW	combined-cycle	generating	unit	in	Montgomery County,	Texas	on	land	adjacent	to	the	existing	Lewis	Creek	plant.	The	current	estimated	cost	of	the	Montgomery	County	Power	Station	is	$937 million,	including	approximately	$111	million	of	transmission	interconnection	and	network	upgrades	and	other	related	costs.	The	independent monitor,	who	oversaw	the	request	for	proposal	process,	filed	testimony	and	a	report	affirming	that	the	Montgomery	County	Power	Station	was selected	through	an	objective	and	fair	request	for	proposal	process	that	showed	no	undue	preference	to	any	proposal.	In	June	2017	parties	to	the proceeding	filed	an	unopposed	stipulation	and	settlement	agreement.	The	stipulation	contemplates	that	Entergy	Texas's	level	of	cost-recovery	for generation	construction	costs	for	Montgomery	County	Power	Station	 is	capped	at	$831	million,	subject	 to	certain	exclusions	such	as	force majeure	events.	Transmission	interconnection	and	network	upgrades	and	other	related	costs	are	not	subject	to	the	$831	million	cap.	In	July	2017 the	PUCT	approved	the	stipulation.	Subject	to	the	timely	receipt	of	other	permits	and	approvals,	commercial	operation	is	estimated	to	occur	by mid-2021.

# Washington	Parish	Energy	Center

In	April	2017,	Entergy	Louisiana	signed	a	purchase	and	sale	agreement	with	a	subsidiary	of	Calpine	Corporation	for	the	acquisition	of	a peaking	plant.	Calpine	will	construct	the	plant,	which	will	consist	of	two	natural	gas-fired	combustion	turbine	units	with	a	total	nominal	capacity of	approximately	361	MW.	The	plant,	named	the	Washington	Parish	Energy	Center,	will	be	located	in	Bogalusa,	Louisiana	and,	subject	to	permits and	approvals,	is	expected	to	be	completed	in	2021.	Subject	to	regulatory	approvals,	Entergy	Louisiana	will	purchase	the	plant	once	it	is	complete for	an	estimated	total	investment	of	approximately	$261	million,	including	transmission	and	other	related	costs.	In	May	2017,	Entergy	Louisiana filed	an	application	with	the	LPSC	seeking	certification	of	the	plant.	A	procedural	schedule	has	been	established,	with	the	deadlines	recently extended	and	the	hearing	continued	from	March	2018	until	June	2018	in	order	to	allow	the	parties	an	opportunity	to	reach	settlement.

# Advanced	Metering	Infrastructure	(AMI)

See	Note	2	to	the	financial	statements	for	discussion	of	filings	made	by	the	Utility	operating	companies	regarding	the	deployment	of	AMI. The	filings	included	estimates	of	implementation	costs	for	AMI	of	$208	million	for	Entergy	Arkansas,	$330	million	for	Entergy	Louisiana,	$132 million	for	Entergy	Mississippi,	$75	million	for	Entergy	New	Orleans,	and	$132	million	for	Entergy	Texas.

# 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	earnings	per	share	from	the	Utility	operating	segment	and	the	Parent	and	Other	portion of	the	business,	financial	strength,	and	future	investment	opportunities.	At	its	January	2018	meeting,	the	Board	declared	a	dividend	of	$0.89	per share.	Entergy	paid	$629	million	in	2017,	$612	million	in	2016,	and	$599	million	in	2015	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	stock	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, 2017,	$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	relating	to	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.	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,	which	is	subject	to	the	jurisdiction	of	the	APSC.	The	City	Council	has	concurrent jurisdiction	over	Entergy	New	Orleans's	securities	issuances	with	maturities	longer	than	one	year.	No	regulatory	approvals	are	necessary	for Entergy	Corporation	to	issue	securities.	The	current	FERC-authorized	short-term	borrowing	limits	are	effective	through	October	2019.	Entergy Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	have	obtained	long-term	financing	authorizations	from the	FERC	that	extend	 through	October	2019.	Entergy	Arkansas	has	obtained	long-term	financing	authorization	from	the	APSC	that	extends through	December	2018.	Entergy	New	Orleans	also	has	obtained	long-term	financing	authorization	from	the	City	Council	that	extends	through June	2018.	Entergy	Arkansas,	Entergy	Louisiana,	and	System	Energy	each	have	obtained	long-term	financing	authorizations	from	the	FERC	that extend	 through	 October	 2019	 for	 issuances	 by	 its	 respective	 nuclear	 fuel	 company	 variable	 interest	 entity.	In	 addition	 to	 borrowings	 from commercial	 banks,	 the	 Registrant	 Subsidiaries	 may	 also	 borrow	 from	 the	 Entergy	 System	 money	 pool	 and	 from	 other	 internal	 short-term borrowing	arrangements.	The	money	pool	and	the	other	internal	borrowing	arrangements	are	inter-company	borrowing	arrangements	designed	to reduce	 Entergy's	 subsidiaries'	 dependence	 on	 external	 short-term	 borrowings.	Borrowings	from	 internal	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.

# Cash	Flow	Activity

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $1,188 | $1,351 | $1,422 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 2,624 | 2,999 | 3,291 |
| Investing\tactivities | (3,841) | (3,850) | (2,609) |
| Financing\tactivities | 810 | 688 | (753) |
| Net\tdecrease\tin\tcash\tand\tcash\tequivalents | (407) | (163) | (71) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $781 | $1,188 | $1,351 |

Net	cash	flow	provided	by	operating	activities	decreased	by	$375	million	in	2017	primarily	due	to:

•lower	 Entergy	Wholesale	 Commodities	 net	 revenue,	 excluding	 the	 effect	 of	 revenues	 resulting	 from	 the	 FitzPatrick	 reimbursement agreement	with	Exelon,	in	2017	as	compared	to	prior	year,	as	discussed	above.	See	Note	14	to	the	financial	statements	for	discussion	of the	reimbursement	agreement;

•an	increase	of	$141	million	in	spending	on	nuclear	refueling	outages	in	2017	as	compared	to	the	prior	year;

•an	 increase	 of	 $94	 million	 in	 severance	 and	 retention	 payments	 in	 2017	 as	 compared	 to	 the	 prior	 year.	See	 "MANAGEMENT'S FINANCIAL	DISCUSSION	AND	ANALYSIS	-	Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power	Business "	above for	a	discussion	of	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet;

•a	refund	to	customers	in	January	2017	of	approximately	$71	million	as	a	result	of	the	settlement	approved	by	the	LPSC	related	to	the Waterford	3	replacement	steam	generator	project.	See	Note	2	to	the	financial	statements	for	discussion	of	the	settlement	and	refund; •proceeds	of	$23	million	received	in	2017	compared	to	proceeds	of	$102	million	received	in	2016	from	the	DOE	resulting	from	litigation regarding	spent	nuclear	fuel	storage	costs	that	were	previously	expensed.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent nuclear	fuel	litigation;	and

•an	increase	of	$20	million	in	pension	contributions	in	2017.	See	"MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS	- Critical	 Accounting	 Estimates" below	 and	 Note 11 to	 the	 financial	 statements	 for	 discussion	 of	 qualified	 pension	 and	 other postretirement	benefits	funding.

•income	tax	refunds	of	$13	million	in	2017	compared	to	income	tax	payments	of	$95	million	in	2016.	Entergy	received	income	tax	refunds in	2017	resulting	from	the	carryback	of	net	operating	losses.	Entergy	made	income	tax	payments	in	2016	related	to	the	effect	of	the	2006- 2007	IRS	audit	and	for	jurisdictions	that	do	not	have	net	operating	loss	carryovers	or	jurisdictions	in	which	the	utilization	of	net	operating loss	carryovers	are	limited.	See	Note	3	to	the	financial	statements	for	a	discussion	of	the	income	tax	audit;

•a	decrease	of	$68	million	in	interest	paid	in	2017	as	compared	to	the	prior	year	primarily	due	to	an	interest	payment	of	$60	million	made in	March	2016	related	to	the	purchase	of	a	beneficial	interest	in	the	Waterford

3	leased	assets.	See	Note	10	to	the	financial	statements	for	a	discussion	of	Entergy	Louisiana's	purchase	of	a	beneficial	interest	in	the Waterford	3	leased	assets;	and

•an	increase	due	to	the	timing	of	recovery	of	fuel	and	purchased	power	costs	in	2017	as	compared	to	the	prior	year.	See	Note	2	to	the financial	statements	for	a	discussion	of	fuel	and	purchased	power	cost	recovery.

•a	decrease	due	to	the	timing	of	recovery	of	fuel	and	purchased	power	costs	in	2016	as	compared	to	2015.	See	Note	2	to	the	financial statements	for	a	discussion	of	fuel	and	purchased	power	cost	recovery;

•lower	Entergy	Wholesale	Commodities	net	revenue	in	2016	as	compared	to	2015,	as	discussed	previously;	and •an	increase	of	$83	million	in	interest	paid	in	2016	as	compared	to	2015	primarily	due	to	an	interest	payment	of	$60	million	made	in	March 2016	related	to	the	purchase	of	a	beneficial	interest	in	the	Waterford	3	leased	assets	and	an	increase	in	interest	expense	primarily	due	to 2016	net	debt	issuances	by	various	Utility	operating	companies,	partially	offset	by	a	decrease	in	interest	paid	in	2016	on	the	Grand	Gulf sale-leaseback	obligation.	See	Note	10	to	the	financial	statements	for	a	discussion	of	Entergy	Louisiana's	purchase	of	a	beneficial	interest in	the	Waterford	3	leased	assets	and	for	details	of	the	Grand	Gulf	lease	obligation.	See	Note	5	to	the	financial	statements	for	a	discussion of	long-term	debt.

•higher	Utility	net	revenues	in	2016	as	compared	to	2015,	as	discussed	above;

•proceeds	of	$102	million	received	in	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel	storage	costs	that	were previously	expensed.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation;

•a	decrease	of	$46	million	in	spending	on	nuclear	refueling	outages	in	2016	as	compared	to	2015;	and

•a	decrease	of	$19	million	in	spending	related	to	the	shutdown	of	Vermont	Yankee,	which	ceased	power	production	in	December	2014.

# Investing	Activities

Net	cash	flow	used	in	investing	activities	decreased	by	$9	million	in	2017	primarily	due	to	the	purchase	of	the	Union	Power	Station	for approximately	$949	million	in	March	2016	and	proceeds	of	$100	million	from	the	sale	in	March	2017	of	the	FitzPatrick	plant	to	Exelon.	See	Note 14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase	and	the	sale	of	FitzPatrick.	The	decrease	was	partially	offset	by:

•an	increase	of	$827	million	in	construction	expenditures,	primarily	in	the	Utility	business.	The	increase	in	construction	expenditures	in	the Utility	business	is	primarily	due	to	an	increase	of	$452	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to higher	spending	in	2017	on	the	St.	Charles	Power	Station	project	and	the	Lake	Charles	Power	Station	project	and	a	higher	scope	of	work performed	 on	 various	 other	 fossil	 projects	 in	 2017	 as	 compared	 to	 2016;	 an	 increase	 of	 $133	 million	 in	 distribution	 construction expenditures	primarily	due	 to	a	higher	scope	of	non-storm	related	work	performed	 in	2017	as	compared	 to	2016	and	higher	storm restoration	spending	in	2017;	an	increase	of	$102	million	in	nuclear	construction	expenditures	primarily	due	to	increased	spending	on various	nuclear	projects	in	2017	as	compared	to	2016;	an	increase	of	$101	million	in	transmission	construction	expenditures	primarily	due to	a	higher	scope	of	work	performed	on	transmission	projects	in	2017	as	compared	to	2016;	and	an	increase	of	$51	million	due	to increased	spending	on	advanced	metering	infrastructure	in	2017;

•a	decrease	of	$144	million	in	proceeds	received	from	the	DOE	in	2017	as	compared	to	the	prior	year	resulting	from	litigation	regarding spent	nuclear	fuel	storage	costs	that	were	previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear fuel	litigation;	and

•a	 decrease	 of	 $63	 million	 in	 nuclear	 fuel	 purchases	 due	 to	 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.

Net	cash	flow	used	in	investing	activities	increased	by	$1,241	million	in	2016	primarily	due	to:

•the	purchase	of	the	Union	Power	Station	for	approximately	$949	million	in	March	2016.	See	Note	14	to	the	financial	statements	for discussion	of	the	Union	Power	Station	purchase;

•proceeds	of	approximately	$490	million	from	the	sale	in	December	2015	of	Rhode	Island	State	Energy	Center.	See	Note	14	to	the financial	statements	for	further	discussion	of	the	sale;	and

•an	increase	of	$279	million	in	construction	expenditures,	primarily	in	the	Utility	business.	The	increase	in	construction	expenditures	in	the Utility	business	is	primarily	due	to	an	increase	of	$114	million	in	transmission	construction	expenditures	primarily	due	to	an	overall higher	 scope	 of	 work	 performed	 on	 transmission	 projects	 in	 2016	 as	 compared	 to	 2015,	 an	 increase	 of	 $106	 million	 in	 nuclear construction	expenditures	primarily	due	to	a	higher	scope	of	work	on	various	nuclear	projects	in	2016	as	compared	to	2015,	an	increase	of $95	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	spending	on	the	St.	Charles	Power	Station	project	in 2016,	an	increase	of	$79	million	in	distribution	construction	expenditures	primarily	due	to	a	higher	scope	of	non-storm	related	work performed	in	2016	as	compared	to	the	same	period	in	2015	and	higher	storm	restoration	spending	in	2016,	and	an	increase	of	$65	million in	information	technology	construction	expenditures	due	to	various	information	technology	projects	and	upgrades	in	2016.	The	increase was	partially	offset	by	a	decrease	of	$148	million	in	spending	related	to	compliance	with	NRC	post-Fukushima	requirements	in	the	Utility and	Entergy	Wholesale	Commodities	businesses.

•an	increase	of	$151	million	in	proceeds	received	from	the	DOE	in	2016	as	compared	to	the	prior	year	resulting	from	litigation	regarding spent	nuclear	fuel	storage	costs	that	were	previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear fuel	litigation;

•a	$71	million	NYPA	value	sharing	payment	in	2015.	See	Note	14	to	the	financial	statements	for	further	discussion	of	Entergy's	NYPA value	sharing	agreements;	and

•the	deposit	of	$64	million	into	Entergy	New	Orleans's	storm	reserve	escrow	accounts	in	2015.

# Financing	Activities

Net	cash	flow	provided	by	financing	activities	increased	by	$122	million	in	2017	primarily	due	to:

•Entergy's	net	issuances	of	$1,123	million	of	commercial	paper	in	2017	compared	to	net	repayments	of	$78	million	of	commercial	paper	in 2016;

•an	increase	of	$95	million	resulting	from	lower	redemptions	of	preferred	stock.	In	2017,	Entergy	New	Orleans	redeemed	its	$7.8	million of	4.75%	Series	preferred	stock,	its	$6	million	of	5.56%	Series	preferred	stock,	and	its	$6	million	of	4.36%	Series	preferred	stock.	In	2016, Entergy	Arkansas	redeemed	its	$75	million	of	6.45%

Series	preferred	stock	and	its	$10	million	of	6.08%	Series	preferred	stock	and	Entergy	Mississippi	redeemed	its	$30	million	of	6.25% Series	preferred	stock;

•an	 increase	of	$48	million	 in	 treasury	stock	 issuances	 in	2017	primarily	due to	a larger	amount	of	previously	repurchased	Entergy Corporation	common	stock	issued	in	2017	to	satisfy	stock	option	exercises;	and

•net	borrowings	of	$41	million	by	the	nuclear	fuel	company	variable	interest	entities	in	2017	compared	to	net	repayments	of	$1	million	in 2016.

The	 increase	was	partially	offset	by	 long-term	debt	activity	providing	approximately	$224	million	of	cash	 in	2017	compared	 to	providing approximately	$1,489	million	of	cash	in	2016.	Included	in	the	long-term	debt	activity	is	$490	million	in	2017	and	$135	million	in	2016	for	the repayment	of	borrowings	on	the	Entergy	Corporation	long-term	credit	facility.

Entergy's	financing	activities	provided	$688	million	of	cash	for	2016	compared	to	using	$753	million	of	cash	for	2015	primarily	due	to the	following	activity:

•long-term	 debt	 activity	 providing	 approximately	 $1,489	 million	 of	 cash	 in	 2016	 compared	 to	 providing	 $41	 million	 of	 cash	 in 2015.		Included	in	the	long-term	debt	activity	is	net	repayments	of	borrowings	of	$135	million	in	2016	compared	to	net	borrowings	of $140	million	in	2015	on	the	Entergy	Corporation	long-term	credit	facility;

•the	issuance	of	$110	million	of	preferred	stock	in	2015.	See	Note	6	to	the	financial	statements	for	further	discussion;

•$100	million	of	common	stock	repurchased	in	2015,	as	discussed	above;

•a	net	increase	of	$41	million	in	2016	in	short-term	borrowings	by	the	nuclear	fuel	company	variable	interest	entities;	and •a	 decrease	 of	 $21	 million	 resulting	 from	 higher	 repurchase/redemptions	 of	 preferred	 stock.	In	 September	 2015,	 Entergy	 Louisiana redeemed	its	$100	million	6.95%	Series	preferred	membership	interests,	of	which	$16	million	was	owned	by	Entergy	Louisiana	Holdings, an	Entergy	subsidiary,	and	Entergy	Gulf	States	Louisiana	repurchased	its	$10	million	Series	A	8.25%	preferred	membership	interests	as part	of	a	multi-step	process	to	effectuate	the	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	business	combination.		See	Note	2	to the	 financial	 statements	 for	 a	 discussion	 of	 the	 combination.	In	2016,	Entergy	Arkansas	redeemed	 its	$75	million	of	6.45%	Series preferred	stock	and	its	$10	million	of	6.08%	Series	preferred	stock	and	Entergy	Mississippi	redeemed	its	$30	million	of	6.25%	Series preferred	stock.

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.

# 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	LPSC,	the	MPSC,	the	City	Council,	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:

| Company | Authorized	Return	on	Common	Equity |
| :--- | :--- |
| Entergy\tArkansas | 9.25%\t-\t10.25% |
| Entergy\tLouisiana | 9.15%\t-\t10.75%\tElectric;\t9.45%\t-\t10.45%\tGas |
| Entergy\tMississippi | 9.47%\t-\t11.49% |
| Entergy\tNew\tOrleans | 10.7%\t-\t11.5%\tElectric;\t10.25%\t-\t11.25%\tGas |
| Entergy\tTexas | 9.8% |

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.

# Federal	Regulation

The	FERC	regulates	wholesale	sales	of	electricity	rates	and	interstate	transmission	of	electricity,	including	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	current	return	on	equity	under	the	Unit	Power	Sales	Agreement	is	10.94%.	Prior	to	each	operating	company's termination	of	participation	in	the	System	Agreement	(Entergy	Arkansas	in	December	2013,	Entergy	Mississippi	in	November	2015,	and	Entergy Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas	each	in	August	2016),	the	Utility	operating	companies	engaged	in	the	coordinated	planning, construction,	and	operation	of	generating	and	bulk	transmission	facilities	under	the	terms	of	the	System	Agreement,	which	was	a	rate	schedule approved	by	the	FERC.	Certain	of	the	Utility	operating	companies'	retail	regulators	are	pursuing	litigation	involving	the	System	Agreement	at	the FERC	and	in	federal	courts.	See	Note	2	to	the	financial	statements	for	discussion	of	the	System	Agreement	proceedings,	a	complaint	filed	with	the FERC	challenging	System	Energy's	return	on	equity,	and	System	Energy's	proposed	amendments	to	the	Unit	Power	Sales	Agreement.

# 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	16	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	outstanding	indebtedness.		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	use	commodity	and	financial	instruments	to	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	also	exposed	to	credit	risk.		Credit	risk	is	the	risk	of	loss	from	nonperformance	by suppliers,	customers,	or	financial	counterparties	to	a	contract	or	agreement.		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'	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.		Entergy Wholesale	Commodities	enters	 into	forward	contracts	with	 its	customers	and	also	sells	energy	 in	 the	day	ahead	or	spot	markets.	 	Entergy Wholesale	Commodities	also	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'	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,	and	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	sensitivities	are	provided	in	the	table	below	to	show potential	variations.		The	sensitivities	may	not	reflect	the	total	maximum	upside	potential	from	higher	market	prices.		The	information	contained	in the	following	table	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'	current	forward	capacity	and	generation contracts	as	well	as	total	revenue	projections	based	on	market	prices	as	of	December	31,	2017.

# Entergy	Wholesale	Commodities	Nuclear	Portfolio

|  | 2018 | 2019 | 2020 | 2021 | 2022 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Energy |  |  |  |  |  |
| Percent\tof\tplanned\tgeneration\tunder\tcontract\t(a): |  |  |  |  |  |
| Unit-contingent\t(b) | 98% | 91% | 51% | 74% | 67% |
| Firm\tLD\t(c) | 9% | —% | —% | —% | —% |
| Offsetting\tpositions\t(d) | (9%) | —% | —% | —% | —% |
| Total | 98% | 91% | 51% | 74% | 67% |
| Planned\tgeneration\t(TWh)\t(e)\t(f) | 27.9 | 25.5 | 17.9 | 9.7 | 2.8 |
| Average\trevenue\tper\tMWh\ton\tcontracted\tvolumes: |  |  |  |  |  |
| Expected\tbased\ton\tmarket\tprices\tas\tof\tDecember\t31,\n2017 | $39.1 | $40.6 | $50.5 | $59.2 | $58.8 |
| Capacity |  |  |  |  |  |
| Percent\tof\tcapacity\tsold\tforward\t(g): |  |  |  |  |  |
| Bundled\tcapacity\tand\tenergy\tcontracts\t(h) | 22% | 25% | 36% | 69% | 99% |
| Capacity\tcontracts\t(i) | 36% | 13% | —% | —% | —% |
| Total | 58% | 38% | 36% | 69% | 99% |
| Planned\tnet\tMW\tin\toperation\t(average)\t(f) | 3,568 | 3,167 | 2,195 | 1,158 | 338 |
| Average\trevenue\tunder\tcontract\tper\tkW\tper\tmonth\t(applies\nto\tcapacity\tcontracts\tonly) | $7.1 | $9.1 | $— | $— | $— |
| Total\tEnergy\tand\tCapacity\tRevenues\t(j) |  |  |  |  |  |
| Expected\tsold\tand\tmarket\ttotal\trevenue\tper\tMWh | $47.0 | $46.9 | $48.9 | $56.1 | $47.8 |
| Sensitivity:\t-/+\t$10\tper\tMWh\tmarket\tprice\tchange | $46.9\t- | $46.0\t- | $44.3\t- | $53.5\t- | $44.5\t- |
|  | $47.2 | $47.8 | $53.5 | $58.7 | $51.1 |

(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.	Positions	that	are	not classified	as	hedges	are	netted	in	the	planned	generation	under	contract.

(b) Transaction	under	which	power	is	supplied	from	a	specific	generation	asset;	if	the	asset	is	not	operating,	the	seller	is	generally	not	liable	to buyer	for	any	damages.	Certain	unit-contingent	sales	include	a	guarantee	of	availability.	Availability	guarantees	provide	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.

(c) 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.	This	also	includes	option transactions	that	may	expire	without	being	exercised.

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

(e) 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.

(f) Assumes	the	planned	shutdown	of	Pilgrim	on	May	31,	2019,	planned	shutdown	of	Indian	Point	2	on	April	30,	2020,	planned	shutdown	of Indian	Point	3	on	April	30,	2021,	and	planned	shutdown	of	Palisades	on	May	31,

2022.	Assumes	NRC	license	renewals	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	while	its	application	is	pending)	and	Indian	Point	3	(December	2015	and now	operating	under	its	period	of	extended	operations	while	its	application	is	pending).	For	a	discussion	regarding	the	planned	shutdown	of the	Pilgrim,	Indian	Point	2,	Indian	Point	3,	and	Palisades	plants,	see	"Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power Business" above.	For	 a	 discussion	 regarding	 the	 license	 renewals	 for	 Indian	 Point	 2	 and	 Indian	 Point	 3,	 see	 "Entergy	 Wholesale Commodities	Authorizations	to	Operate	Indian	Point"	above.

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

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

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

(j) Includes	assumptions	on	converting	a	portion	of	the	portfolio	to	contracted	with	fixed	price	cost	or	discount	and	excludes	non-cash	revenue from	the	amortization	of	the	Palisades	below-market	purchased	power	agreement,	mark-to-market	activity,	and	service	revenues.

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	$3	million	in	2018	and	would	have	had	a	corresponding	effect	on	pre-tax income	of	$37	million	in	2017.	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	($3)	million	in 2018	and	would	have	had	a	corresponding	effect	on	pre-tax	income	of	($31)	million	in	2017.

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	made	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	paid	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	was	due	by	January	15	of	the	following	year,	and	the	final	payment	to	NYPA	was	made	in January	2015.		Entergy	recorded	the	liability	for	payments	to	NYPA	as	power	was	generated	and	sold	by	Indian	Point	3	and	FitzPatrick.		An amount	equal	to	the	liability	was	recorded	to	the	plant	asset	account	as	contingent	purchase	price	consideration	for	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	credit	support	to	secure	its	obligations	under	the	agreements.		The	Entergy	subsidiary	is	required	to	provide	credit support	based	upon	 the	difference	between	 the	current	market	prices	and	contracted	power	prices	 in	 the	regions	where	Entergy	Wholesale Commodities	sells	power.		The	primary	form	of	credit	support	to	satisfy	these	requirements	is	an	Entergy	Corporation	guaranty.		Cash	and	letters of	credit	are	also	acceptable	forms	of	credit	support.		At	December	31,	2017,	based	on	power	prices	at	that	time,	Entergy	had	liquidity	exposure	of $167	million	under	the	guarantees	in	place	supporting	Entergy	Wholesale	Commodities	transactions	and	 $8	million	of	posted	cash	collateral.		In the	event	of	a	decrease	in	Entergy	Corporation's	credit	rating	to	below	investment	grade,	based	on	power	prices	as	of	December	31,	2017,	Entergy would	have	been	required	 to	provide	approximately	$98	million	of	additional	cash	or	letters	of	credit	under	some	of	the	agreements.	As	 of December	 31,	 2017,	 the	 liquidity	 exposure	 associated	 with	 Entergy	 Wholesale	 Commodities	 assurance	 requirements,	 including	 return	 of previously	posted	collateral	from	counterparties,	would	increase	by	$372	million	for	a	$1	per	MMBtu	increase	in	gas	prices	in	both	the	short-	and long-term	markets.

As	of	December	31,	2017,	substantially	all	of	the	credit	exposure	associated	with	the	planned	energy	output	under	contract	for	Entergy Wholesale	Commodities	nuclear	plants	through	2022	is	with	counterparties	or	their	guarantors	that	have	public	investment	grade	credit	ratings.

# Nuclear	Matters

Entergy's	Utility	and	Entergy	Wholesale	Commodities	businesses	include	the	ownership	and	operation	of	nuclear	generating	plants	and are,	therefore,	subject	to	the	risks	related	to	such	ownership	and	operation.	These	include	risks	related	to:	the	use,	storage,	and	handling	and disposal	of	high-level	and	low-level	radioactive	materials;	the	substantial	financial	requirements,	both	for	capital	investments	and	operational needs,	to	position	Entergy's	nuclear	fleet	to	meet	its	operational	goals,	including	the	financial	requirements	to	address	emerging	issues	like	stress corrosion	 cracking	 of	 certain	 materials	 within	 the	 plant	 systems	 and	 the	 Fukushima	 event;	 the	 implementation	 of	 plans	 to	 cease	 merchant generation	at	all	Entergy	Wholesale	Commodities	nuclear	plants	by	2022	and	the	post-shutdown	decommissioning	of	these	plants;	regulatory requirements	and	potential	future	regulatory	changes,	including	changes	affecting	the	regulations	governing	nuclear	plant	ownership,	operations, license	renewal	and	amendments,	and	decommissioning;	the	performance	and	capacity	factors	of	these	nuclear	plants;	the	availability	of	interim	or permanent	sites	for	the	disposal	of	spent	nuclear	fuel	and	nuclear	waste,	including	the	fees	charged	for	such	disposal;	the	sufficiency	of	nuclear decommissioning	trust	fund	assets	and	earnings	to	complete	decommissioning	of	each	site	when	required;	and	limitations	on	the	amounts	and types	of	 insurance	commercially	available	for	 losses	 in	connection	with	nuclear	plant	operations	and	catastrophic	events	such	as	a	nuclear accident.

See	Note	8	to	the	financial	statements	for	discussion	of	the	NRC's	decision	in	March	2015	to	move	ANO	into	the	"multiple/repetitive degraded	cornerstone	column,"	or	Column	4,	of	the	NRC's	Reactor	Oversight	Process	Action	Matrix,	and	the	resulting	significant	additional	NRC inspection	activities	at	the	ANO	site.

# Pilgrim

See	Note	8	to	the	financial	statements	for	discussion	of	the	NRC's	decision	in	September	2015	to	place	Pilgrim	in	Column	4	of	its	Reactor Oversight	Process	Action	Matrix	due	to	its	finding	of	continuing	weaknesses	in	Pilgrim's	corrective	action	program	that	contributed	to	repeated unscheduled	shutdowns	and	equipment	failures.

# Indian	Point

During	the	scheduled	refueling	and	maintenance	outage	at	Indian	Point	2	in	the	first	quarter	2016,	comprehensive	inspections	were	done as	part	of	the	aging	management	program	that	calls	for	an	in-depth	inspection	of	the	reactor	vessel.		Inspections	of	more	than	2,000	bolts	in	the reactor's	 removable	 insert	 liner	 identified	 issues	 with	 roughly	11%	 of	 the	 bolts	 that	 required	 further	 analysis.	 	 Entergy	 replaced	 bolts	 as appropriate,	and	the	unit	returned	to	service	in	June	2016.	In	2016,	Entergy	evaluated	the	scope	and	duration	of	Indian	Point	3's	scheduled refueling	outage	planned	for	2017,	which	began	in	March	2017.	Based	on	the	results	of	the	2016	evaluation	and	analysis,	Entergy	extended	Indian Point	3's	planned	2017	outage	duration.	Entergy	performed	the	same	in-depth	inspection	of	the	reactor	vessel	at	Indian	Point	3	during	Indian	Point 3's	spring	2017	refueling	and	maintenance	outage	that	it	performed	for	Indian	Point	2.	Based	on	inspection	data,	Entergy	replaced	approximately the	same	number	of	bolts	at	Indian	Point	3	that	it	replaced	at	Indian	Point	2	before	returning	the	plant	to	service	in	May	2017.

# Grand	Gulf

Grand	Gulf	began	a	maintenance	outage	on	September	8,	2016	to	replace	a	residual	heat	removal	pump.	Although	the	pump	had	been replaced,	 on	 September	 27,	 2016	 management	 decided	 to	 keep	 the	 plant	 in	 an	 outage	 for	 additional	 training	 and	 other	 steps	 to	 support management's	operational	goals.	Grand	Gulf	returned	to	service	on	January	31,	2017.

Based	on	the	plant's	performance	indicators,	in	November	2016	the	NRC	placed	Grand	Gulf	in	the	"regulatory	response	column,"	or Column	 2,	 of	 its	 Reactor	 Oversight	 Process	Action	 Matrix.	Entergy	 is	 implementing	a	plan	 to	restore	Grand	Gulf	 to	Column	1,	 including addressing	the	issues	related	to	the	three	very	low	safety	significance	non-

cited	violations	identified	in	the	NRC's	report	on	the	results	of	its	October	2016	special	inspection.	Depending	on	the	success	of	implementing that	plan	and	the	plant's	performance	indicators,	there	is	risk	that	the	NRC	could	move	Grand	Gulf	into	the	"degraded	cornerstone	column,"	or Column	3,	of	the	NRC's	Reactor	Oversight	Process	Action	Matrix.

# 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	for	those	plants	that	do	not	have	an	announced	shutdown	date.	The	estimate	may	include assumptions	regarding	the	possibility	that	the	plant	may	have	an	operating	life	shorter	than	the	operating	license	expiration,	as	well	as assumptions	regarding	the	probability	that	the	plant's	license	will	be	renewed	for	those	plants	that	have	not	yet	received	operating	license renewal.	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	obligation. •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%	 annually.	A	50-basis	point	change	in	this	assumption	could change	the	estimated	present	value	of	the	decommissioning	liabilities	by	approximately	3%	to	18%.	The	timing	assumption	influences	the significance	of	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	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	damage	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.	These	estimates	could	change	in	the	future,	however, based	on	the	expected	timing	of	when	the	DOE	begins	to	fulfill	its	obligation	to	receive	and	store	spent	nuclear	fuel.	See	Note	8	to	the financial	statements	for	further	discussion	of	Entergy's	spent	nuclear	fuel	litigation.

•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	the	current	credit-adjusted	risk-free	rate.	Decreases	in	estimated	cash	flows	are	discounted	using	the	credit-adjusted	risk-free	rate used	previously	in	estimating	the	decommissioning	liability	that	is	being	revised.	Therefore,	to	the	extent	that	a	revised	cost	study	results in	an	increase	in	estimated	cash	flows,	a	change	in	interest	rates	from	the	time	of	the	previous	cost	estimate	will	affect	the	calculation	of the	present	value	of	the	revised	decommissioning	liability.

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	for	which	the	plant's	value	is	impaired,	these	reductions	will	immediately	reduce	operating expenses	in	the	period	of	the	revision	if	the	reduction	of	the	liability	exceeds	the	amount	of	the	undepreciated	plant	asset	at	the	date	of	the revision.	Revisions	of	estimated	decommissioning	costs	that	increase	the	liability	result	in	an	increase	in	the	asset	retirement	cost	asset,	which	is then	depreciated	over	the	asset's	remaining	economic	life.	For	a	plant	in	the	non-rate-regulated	portions	of	Entergy's	business	for	which	the plant's	value	is	impaired,	however,	including	a	plant	that	is	shutdown,	or	is	nearing	its	shutdown	date,	the	increase	in	the	liability	is	likely	to immediately	increase	operating	expense	in	the	period	of	the	revision	and	not	increase	the	asset	retirement	cost	asset.	See	Note	14	to	the	financial statements	for	further	discussion	of	impairment	of	long-lived	assets	and	Note	9	to	the	financial	statements	for	further	discussion	of	asset	retirement obligations.

# Utility	Regulatory	Accounting

Entergy's	Utility	operating	companies	and	System	Energy	are	subject	to	retail	regulation	by	their	respective	state	and	local	regulators	and to	wholesale	regulation	by	the	FERC.	Because	these	regulatory	agencies	set	the	rates	the	Utility	operating	companies	and	System	Energy	are allowed	to	charge	customers	based	on	allowable	costs,	including	a	reasonable	return	on	equity,	the	Utility	operating	companies	and	System Energy	 apply	 accounting	 standards	 that	 require	 the	 financial	 statements	 to	 reflect	 the	 effects	 of	 rate	 regulation,	 including	 the	 recording	 of regulatory	assets	and	liabilities.	Regulatory	assets	represent	incurred	costs	that	have	been	deferred	because	they	are	probable	of	future	recovery from	customers	through	regulated	rates.	Regulatory	liabilities	represent	the	excess	recovery	of	costs	that	have	been	deferred	because	it	is	probable such	amounts	will	be	returned	to	customers	through	future	regulated	rates.	See	Note	2	to	the	financial	statements	for	a	discussion	of	rate	and regulatory	matters,	including	details	of	Entergy's	and	the	Registrant	Subsidiaries'	regulatory	assets	and	regulatory	liabilities.

For	each	regulatory	jurisdiction	in	which	they	conduct	business,	the	Utility	operating	companies	and	System	Energy	assess	whether	the regulatory	assets	and	regulatory	liabilities	continue	to	meet	the	criteria	for	probable	future	recovery	or	settlement	at	each	balance	sheet	date	and when	regulatory	events	occur.	This	assessment	includes	consideration	of	recent	rate	orders,	historical	regulatory	treatment	for	similar	costs,	and factors	such	as	changes	in	applicable	regulatory	and	political	environments.	If	the	assessments	made	by	the	Utility	operating	companies	and System	Energy	are	ultimately	different	than	actual	regulatory	outcomes,	it	could	materially	affect	the	results	of	operations,	financial	position,	and cash	flows	of	Entergy	or	the	Registrant	Subsidiaries.

# 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	an	impairment	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	or	regulatory	conditions	arise,	particularly	if	it	leads	to	a	decision	or	an	expectation that	Entergy	will	operate	a	plant	for	a	shorter	period	than	previously	expected;	if	there	is	a	significant	adverse	change	in	the	physical	condition	of	a plant;	if	investment	in	a	plant	significantly	exceeds	previously-expected	amounts;	or,	for	Indian	Point	2	and	Indian	Point	3,	if	their	operating licenses	are	not	renewed.

If	an	asset	is	considered	held	for	use,	and	Entergy	concludes	that	events	and	circumstances	are	present	indicating	that	an	impairment analysis	should	be	performed	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	the	expected undiscounted	future	cash	flows	are	less	than	the	carrying	value	and	the	carrying	value	exceeds	the	fair	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.

The	expected	future	cash	flows	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	affected	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	and	the	life	of	the	asset	-	Entergy	assumes	an	expected	life	of	the	asset.		A	change	in	the	timing	assumption,	whether	due	to management	decisions	regarding	operation	of	the	plant,	the	regulatory	process,	or	operational	or	other	factors,	could	have	a	significant effect	on	the	expected	future	cash	flows	and	result	in	a	significant	effect	on	operations.

See	Note	14	to	the	financial	statements	for	a	discussion	of	the	impairments	of	the	Palisades,	Indian	Point,	FitzPatrick,	and	Pilgrim	plants.

Entergy	evaluates	investment	securities	in	the	Entergy	Wholesale	Commodities'	nuclear	decommissioning	trust	funds	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).		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.		Effective	January	1,	2018	with	the	adoption	of	ASU	2016-01,	unrealized	losses	and	gains	on	investments	in equity	securities	held	by	the	Entergy	Wholesale	Commodities'	nuclear	decommissioning	trust	funds	will	be	recorded	in	earnings	as	they	occur. See	Note	16	to	the	financial	statements	for	details	on	the	decommissioning	trust	funds.

# Taxation	and	Uncertain	Tax	Positions

Management	 exercises	 significant	 judgment	 in	 evaluating	 the	 potential	 tax	 effects	 of	 Entergy's	 operations,	 transactions,	 and	 other events.		Entergy	accounts	for	uncertain	income	tax	positions	using	a	recognition	model	under	a	two-step	approach	with	a	more	likely-than-not recognition	threshold	and	a	measurement	approach	based	on	the	largest	amount	of	tax	benefit	that	is	greater	than	50%	likely	of	being	realized upon	settlement.		Management	evaluates	each	tax	position	based	on	the	technical	merits	and	facts	and	circumstances	of	the	position,	assuming	the position	will	be	examined	by	a	taxing	authority	having	full	knowledge	of	all	relevant	information.	Significant	judgment	is	required	to	determine whether	available	information	supports	the	assertion	that	the	recognition	threshold	has	been	met.	Additionally,	measurement	of	unrecognized	tax benefits	to	be	recorded	in	the	consolidated	financial	statements	is	based	on	the	probability	of	different	potential	outcomes.	Income	tax	expense	and tax	positions	recorded	could	be	significantly	affected	by	events	such	as	additional	transactions	contemplated	or	consummated	by	Entergy	as	well as	audits	by	 taxing	authorities	of	 the	 tax	positions	 taken	 in	 transactions.	Management	believes	that	the	financial	statement	tax	balances	are accounted	for	and	adjusted	appropriately	each	quarter	as	necessary	in	accordance	with	applicable	authoritative	guidance;	however,	the	ultimate outcome	of	tax	matters	could	result	in	favorable	or	unfavorable	effects	on	the	consolidated	financial	statements.	Entergy's	income	taxes,	including unrecognized	tax	benefits,	open	audits,	and	other	significant	tax	matters	are	discussed	in	Note	3	to	the	financial	statements.

See	"MANAGEMENT'S	FINANCIAL	DISCUSSION	AND	ANALYSIS	-	Income	Tax	Legislation"	above	and	Note	3	to	the	financial statements	for	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act,	the	federal	income	tax	legislation	enacted	in	December	2017.

# Qualified	Pension	and	Other	Postretirement	Benefits

Entergy	sponsors	qualified,	defined	benefit	pension	plans	that	cover	substantially	all	employees,	including	cash	balance	plans	and	final average	pay	plans.		Additionally,	Entergy	currently	provides	other	postretirement	health	care	and	life	insurance	benefits	for	substantially	all	full- time	employees	whose	most	recent	date	of	hire	or	rehire	 is	before	July	1,	2014	and	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	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	qualified	pension	and	other	postretirement	health	care	and	life	insurance	costs	include discount	rates,	projected	healthcare	cost	rates,	expected	long-term	rate	of	return	on	plan	assets,	rate	of	increase	in	future	compensation	levels, retirement	rates	and	mortality	rates.

Annually,	Entergy	reviews	and,	when	necessary,	adjusts	the	assumptions	for	the	pension	and	other	postretirement	plans.		Every	three-to- five	 years,	 a	 formal	 actuarial	 assumption	 experience	 study	 that	 compares	 assumptions	 to	 the	 actual	 experience	 of	 the	 pension	 and	 other postretirement	health	care	and	life	insurance	plans	is	conducted.		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.

# Discount	rates

In	selecting	an	assumed	discount	rate	to	calculate	benefit	obligations,	Entergy	uses	a	yield	curve	based	on	high-quality	corporate	debt. Before	2016	the	discount	rates	used	to	estimate	the	service	cost	and	interest	cost	components	of	benefit	costs	were	the	same	as	the	weighted- average	discount	rate	used	to	measure	the	benefit	obligation	at	the	beginning	of	the	year.	In	2016,	Entergy	refined	its	approach	to	estimating	the service	cost	and	interest	cost	components.	Under	the	refined	approach,	instead	of	using	the	weighted-average	benefit	obligation	discount	rate	at the	beginning	of	the	year,	the	2016	service	and	interest	costs'	expected	cash	flows	were	discounted	by	the	applicable	spot	rates.	The	refinement had	the	effect	of	lowering	2016	qualified	pension	costs	by	$61	million	and	2016	other	postretirement	health	care	and	life	insurance	benefit	costs by	$15	million.

# Projected	health	care	cost	trend	rates

Entergy's	health	care	cost	trend	is	affected	by	both	medical	cost	inflation,	and	with	respect	to	capped	costs	under	the	plan,	the	effects	of general	inflation.	Entergy	reviews	actual	recent	cost	trends	and	projected	future	trends	in	establishing	its	health	care	cost	trend	rates.

# Expected	long-term	rate	of	return	on	plan	assets

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	some	of	its	investment managers.	Entergy	conducts	periodic	asset/liability	studies	in	order	to	set	its	target	asset	allocations.

Since	2003,	Entergy	has	targeted	an	asset	allocation	for	its	qualified	pension	plan	assets	of	roughly	65%	equity	securities	and	35%	fixed- income	securities.		In	2017,	Entergy	confirmed	the	2011	liability-driven	investment	strategy	for	its	pension	assets,	which	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.	In 2017,	Entergy	adopted	a	new	ultimate	allocation	for	pension	assets	of	35%	equity	securities	and	65%	fixed	income	securities.		The	ultimate	asset allocation	is	expected	to	be	attained	when	the	plan	is	105%	funded.

In	2016,	the	target	allocations	for	both	Entergy's	non-taxable	other	postretirement	assets	and	its	taxable	other	postretirement	assets	were 65%	equity	securities	and	35%	fixed-income	securities.	During	the	first	quarter	of	2017,	Entergy	implemented	a	new	asset	allocation	strategy, based	on	the	funded	status	of	each	sub-account	within	each	trust,	which	resulted	in	an	overall	shift	to	more	fixed	income	in	the	non-taxable	trusts and	no	material	changes	in	asset	allocation	to	the	taxable	trust.	The	new	strategy	no	longer	focuses	on	targeting	an	overall	asset	allocation	for	each trust,	but	rather	a	target	asset	allocation	for	each	sub-account	within	each	trust.	See	Note	11	to	the	financial	statements	for	discussion	of	the current	asset	allocations	for	Entergy's	other	postretirement	assets.

# Retirement	and	mortality	rates

In	 October	 2017	 the	 Internal	 Revenue	 Service	 issued	 updated	 mortality	 regulations	 for	 single	 employer	 plans	 for	 determining	 cash contribution	requirements.	The	regulations,	based	on	the	Society	of	Actuaries'	2014	mortality	table,	are	effective	for	plan	years	beginning	on	or after	January	1,	2018.

# Costs	and	Sensitivities

The	estimated	2018	and	actual	2017	qualified	pension	and	other	postretirement	costs	and	related	underlying	assumptions	and	sensitivities are	shown	below:

| Assumptions | 2018 | 2017 |
| :--- | :--- | :--- |
| Discount\trates |  |  |
| Qualified\tpension |  |  |
| Service\tcost | 3.89% | 4.75% |
| Interest\tcost | 3.44% | 3.73% |
| Other\tpostretirement |  |  |
| Service\tcost | 3.88% | 4.60% |
| Interest\tcost | 3.33% | 3.61% |
| Expected\tlong-term\trates\tof\treturn |  |  |
| Qualified\tpension\tassets | 7.50% | 7.50% |
| Other\tpostretirement\t-\tnon-taxable\tassets | 6.50%\t-\t7.50% | 6.50%\t-\t6.90% |
| Other\tpostretirement\t-\ttaxable\tassets\t-\tafter\ttax\trate | 5.50% | 5.75% |
| Weighted-average\trate\tof\tfuture\tcompensation | 3.98% | 3.98% |
| Assumed\thealth\tcare\tcost\ttrend\trates |  |  |
| Pre-65\tretirees | 6.95% | 6.55% |
| Post-65\tretirees | 7.25% | 7.25% |
| Ultimate\trate | 4.75% | 4.75% |
| Year\tultimate\trate\tis\treached\tand\tbeyond | 2027 | 2026 |

Actual	asset	returns	have	an	effect	on	Entergy's	qualified	pension	and	other	postretirement	costs.	In	2017,	Entergy's	actual	average	annual	return on	qualified	pension	assets	was	approximately	16%	and	for	other	postretirement	assets	was	approximately	14%,	as	compared	with	the	2017 expected	long-term	rates	of	return	discussed	above.

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

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

| Discount	rate | (0.25%) | $3 | $50 |
| :--- | :--- | :--- | :--- |
| Health\tcare\tcost\ttrend | 0.25% | $5 | $39 |

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

# Accounting	Mechanisms

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.	Additionally,	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. Prior	service	costs/credits	are	then	amortized	into	expense	over	the	average	future	working	life	of	active	employees.	Certain	decisions,	including workforce	reductions,	plan	amendments,	and	plant	shutdowns	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	gains	or	losses.	Similarly,	payments	made	to	settle benefit	obligations	can	also	result	in	recognition	in	the	form	of	settlement	losses	or	gains.

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.

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

# Funding

	Entergy's	pension	funding	in	2017	was	$410	million.		Entergy	estimates	pension	contributions	will	be	approximately	$352.1	million	in 2018;	although	the	2018	required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed, which	is	expected	by	April	1,	2018.

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	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.

Moving	Ahead	for	Progress	in	the	21st	Century	Act	(MAP-21)	became	federal	law	in	July	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.		These	pension	funding	stabilization	provisions	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	did	not	reduce	contribution	requirements	over	the	long	term.	The	interest	rate	stabilization	periods	of	MAP-21 were	extended	by	the	Highway	and	Transportation	Funding	Act	in	2014	and	the	Bipartisan	Budget	Act	in	2015.

Entergy	contributed	$44.3	million	to	its	postretirement	plans	in	2017	and	plans	to	contribute	$52.3	million	in	2018.

# Federal	Healthcare	Legislation

In	2010	the	Patient	Protection	and	Affordable	Care	Act	(PPACA),	as	amended,	imposed	a	40%	excise	tax	on	per	capita	medical	benefit costs	that	exceed	certain	thresholds.	In	January	2018	the	effective	date	of	the	excise	tax	was	delayed	and	is	currently	expected	to	take	effect	in 2022.		Entergy	will	continue	to	monitor	developments	to	determine	the	possible	effect	on	Entergy.

# 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	federal,	state,	or	local	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.

# New	Accounting	Pronouncements

See	Note	1	to	the	financial	statements	for	discussion	of	new	accounting	pronouncements.

# 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	2013	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's	independent	registered	public	accounting	firm,	Deloitte	&	Touche	LLP,	has	issued	an	attestation	report	on	the effectiveness	of	Entergy	Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2017.

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	2013	COSO	criteria,	management	believes	that	Entergy	and	each	of	the Registrant	Subsidiaries	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2017.		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.

# SELECTED	FINANCIAL	DATA	-	FIVE-YEAR	COMPARISON

| Operating	revenues | $11,074,481 | $10,845,645 | $11,513,251 | $12,494,921 | $11,390,947 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Net\tincome\t(loss) | $425,353 | ($564,503) | ($156,734) | $960,257 | $730,572 |
| Earnings\t(loss)\tper\tshare: |  |  |  |  |  |
| Basic | $2.29 | ($3.26) | ($0.99) | $5.24 | $3.99 |
| Diluted | $2.28 | ($3.26) | ($0.99) | $5.22 | $3.99 |
| Dividends\tdeclared\tper\tshare | $3.50 | $3.42 | $3.34 | $3.32 | $3.32 |
| Return\ton\tcommon\tequity | 5.12% | (6.73%) | (1.83)% | 9.58% | 7.56% |
| Book\tvalue\tper\tshare,\tyear-end | $44.28 | $45.12 | $51.89 | $55.83 | $54.00 |
| Total\tassets | $46,707,149 | $45,904,434 | $44,647,681 | $46,414,455 | $43,290,290 |
| Long-term\tobligations\t(a) | $14,535,077 | $14,695,422 | $13,456,742 | $12,627,180 | $12,265,971 |

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

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Utility\telectric\toperating\nrevenues: |  |  |  |  |  |
| Residential | $3,355 | $3,288 | $3,518 | $3,555 | $3,396 |
| Commercial | 2,480 | 2,362 | 2,516 | 2,553 | 2,415 |
| Industrial | 2,584 | 2,327 | 2,462 | 2,623 | 2,405 |
| Governmental | 231 | 217 | 223 | 227 | 218 |
| Total\tretail | 8,650 | 8,194 | 8,719 | 8,958 | 8,434 |
| Sales\tfor\tresale | 253 | 236 | 249 | 330 | 210 |
| Other | 376 | 437 | 341 | 304 | 298 |
| Total | $9,279 | $8,867 | $9,309 | $9,592 | $8,942 |
| Utility\tbilled\telectric\tenergy\tsales\n(GWh): |  |  |  |  |  |
| Residential | 33,834 | 35,112 | 36,068 | 35,932 | 35,169 |
| Commercial | 28,745 | 29,197 | 29,348 | 28,827 | 28,547 |
| Industrial | 47,769 | 45,739 | 44,382 | 43,723 | 41,653 |
| Governmental | 2,511 | 2,547 | 2,514 | 2,428 | 2,412 |
| Total\tretail | 112,859 | 112,595 | 112,312 | 110,910 | 107,781 |
| Sales\tfor\tresale | 11,550 | 11,054 | 9,274 | 9,462 | 3,020 |
| Total | 124,409 | 123,649 | 121,586 | 120,372 | 110,801 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |
| Operating\trevenues | $1,657 | $1,850 | $2,062 | $2,719 | $2,313 |
| Billed\telectric\tenergy\tsales |  |  |  |  |  |
| (GWh) | 30,501 | 35,881 | 39,745 | 44,424 | 45,127 |

# REPORT	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

# To	the	shareholders	and	Board	of	Directors	of

# Opinion	on	the	Financial	Statements

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Corporation	and	Subsidiaries	(the	"Corporation")	as	of	December	31, 2017	and	2016,	the	related	consolidated	statements	of	operations,	comprehensive	income	(loss),	cash	flows,	and	changes	in	equity,	for	each	of	the three	years	in	the	period	ended	December	31,	2017,	and	the	related	notes	(collectively	referred	to	as	the	"financial	statements").	In	our	opinion,	the financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Corporation	as	of	December	31,	2017	and	2016,	and	the results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	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)	(PCAOB),	the Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2017,	based	on	criteria	established	in	Internal	Control	-	Integrated Framework	(2013)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	and	our	report	dated	February	26,	2018, expressed	an	unqualified	opinion	on	the	Corporation's	internal	control	over	financial	reporting.

# Basis	for	Opinion

These	 financial	 statements	 are	 the	 responsibility	 of	 the	 Corporation's	 management.	 Our	 responsibility	 is	 to	 express	 an	 opinion	 on	 the Corporation's	financial	statements	based	on	our	audits.	We	are	a	public	accounting	firm	registered	with	the	PCAOB	and	are	required	to	be independent	with	respect	to	the	Corporation	in	accordance	with	the	U.S.	federal	securities	laws	and	the	applicable	rules	and	regulations	of	the Securities	and	Exchange	Commission	and	the	PCAOB.

We	conducted	our	audits	in	accordance	with	the	standards	of	the	PCAOB.	Those	standards	require	that	we	plan	and	perform	the	audit	to	obtain reasonable	assurance	about	whether	the	financial	statements	are	free	of	material	misstatement,	whether	due	to	error	or	fraud.	Our	audits	included performing	procedures	to	assess	the	risks	of	material	misstatement	of	the	financial	statements,	whether	due	to	error	or	fraud,	and	performing procedures	that	respond	to	those	risks.	Such	procedures	included	examining,	on	a	test	basis,	evidence	regarding	the	amounts	and	disclosures	in	the financial	statements.	Our	audits	also	included	evaluating	the	accounting	principles	used	and	significant	estimates	made	by	management,	as	well	as evaluating	the	overall	presentation	of	the	financial	statements.	We	believe	that	our	audits	provide	a	reasonable	basis	for	our	opinion.

/s/	DELOITTE	&	TOUCHE	LLP

New	Orleans,	Louisiana February	26,	2018

We	have	served	as	the	Corporation's	auditor	since	2001.

# CONSOLIDATED	STATEMENTS	OF	OPERATIONS

| Electric | $9,278,895 | $8,866,659 | $9,308,678 |
| :--- | :--- | :--- | :--- |
| Natural\tgas | 138,856 | 129,348 | 142,746 |
| Competitive\tbusinesses | 1,656,730 | 1,849,638 | 2,061,827 |
| TOTAL | 11,074,481 | 10,845,645 | 11,513,251 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 1,991,589 | 1,809,200 | 2,452,171 |
| Purchased\tpower | 1,427,950 | 1,220,527 | 1,390,805 |
| Nuclear\trefueling\toutage\texpenses | 168,151 | 208,678 | 251,316 |
| Other\toperation\tand\tmaintenance | 3,423,689 | 3,296,711 | 3,354,981 |
| Asset\twrite-offs,\timpairments,\tand\trelated\tcharges | 538,372 | 2,835,637 | 2,104,906 |
| Decommissioning | 405,685 | 327,425 | 280,272 |
| Taxes\tother\tthan\tincome\ttaxes | 617,556 | 592,502 | 619,422 |
| Depreciation\tand\tamortization | 1,389,978 | 1,347,187 | 1,337,276 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (131,901) | 94,243 | 175,304 |
| TOTAL | 9,831,069 | 11,732,110 | 11,966,453 |
| Gain\ton\tsale\tof\tasset | 16,270 | — | 154,037 |
| OPERATING\tINCOME\t(LOSS) | 1,259,682 | (886,465) | (299,165) |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 95,088 | 67,563 | 51,908 |
| Interest\tand\tinvestment\tincome | 288,197 | 145,127 | 187,062 |
| Miscellaneous\t-\tnet | (12,701) | (41,617) | (95,997) |
| TOTAL | 370,584 | 171,073 | 142,973 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 707,212 | 700,545 | 670,096 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (44,869) | (34,175) | (26,627) |
| TOTAL | 662,343 | 666,370 | 643,469 |
| INCOME\t(LOSS)\tBEFORE\tINCOME\tTAXES | 967,923 | (1,381,762) | (799,661) |
| Income\ttaxes | 542,570 | (817,259) | (642,927) |
| CONSOLIDATED\tNET\tINCOME\t(LOSS) | 425,353 | (564,503) | (156,734) |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 13,741 | 19,115 | 19,828 |
| NET\tINCOME\t(LOSS)\tATTRIBUTABLE\tTO\tENTERGY\tCORPORATION | $411,612 | ($583,618) | ($176,562) |
| Earnings\t(loss)\tper\taverage\tcommon\tshare: |  |  |  |
| Basic | $2.29 | ($3.26) | ($0.99) |
| Diluted | $2.28 | ($3.26) | ($0.99) |
| Basic\taverage\tnumber\tof\tcommon\tshares\toutstanding | 179,671,797 | 178,885,660 | 179,176,356 |
| Diluted\taverage\tnumber\tof\tcommon\tshares\toutstanding | 180,535,893 | 178,885,660 | 179,176,356 |

See	Notes	to	Financial	Statements.

# CONSOLIDATED	STATEMENTS	OF	COMPREHENSIVE	INCOME	(LOSS)

|  |  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| Net\tIncome\t(Loss) | $425,353 | ($564,503) | ($156,734) |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Cash\tflow\thedges\tnet\tunrealized\tgain\t(loss) |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t($22,570),\t($55,298),\tand\t$3,752) | (41,470) | (101,977) | 7,852 |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t($4,057),\t($3,952),\tand\t$61,576) | (61,653) | (2,842) | 103,185 |
| Net\tunrealized\tinvestment\tgains\t(losses) |  |  |  |
| (net\tof\ttax\texpense\t(benefit)\tof\t$80,069,\t$57,277,\tand\t($45,904)) | 115,311 | 62,177 | (59,138) |
| Foreign\tcurrency\ttranslation |  |  |  |
| (net\tof\ttax\tbenefit\tof\t$403,\t$689,\tand\t$345) | (748) | (1,280) | (641) |
| Other\tcomprehensive\tincome\t(loss) | 11,440 | (43,922) | 51,258 |
| Comprehensive\tIncome\t(Loss) | 436,793 | (608,425) | (105,476) |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 13,741 | 19,115 | 19,828 |
| Comprehensive\tIncome\t(Loss)\tAttributable\tto\tEntergy\tCorporation | $423,052 | ($627,540) | ($125,304) |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Consolidated\tnet\tincome\t(loss) | $425,353 | ($564,503) | ($156,734) |
| Adjustments\tto\treconcile\tconsolidated\tnet\tincome\t(loss)\tto\tnet\tcash\tflow\tprovided\tby\noperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 2,078,578 | 2,123,291 | 2,117,236 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 529,053 | (836,257) | (820,350) |
| Asset\twrite-offs,\timpairments,\tand\trelated\tcharges | 357,251 | 2,835,637 | 2,104,906 |
| Gain\ton\tsale\tof\tasset | (16,270) | — | (154,037) |
| Changes\tin\tworking\tcapital: |  |  |  |
| Receivables | (97,637) | (96,975) | 38,152 |
| Fuel\tinventory | (3,043) | 38,210 | (12,376) |
| Accounts\tpayable | 101,802 | 174,421 | (135,211) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 33,853 | (28,963) | 81,969 |
| Interest\taccrued | 742 | (7,335) | (11,445) |
| Deferred\tfuel\tcosts | 56,290 | (241,896) | 298,725 |
| Other\tworking\tcapital\taccounts | (4,331) | 31,197 | (113,701) |
| Changes\tin\tprovisions\tfor\testimated\tlosses | (3,279) | 20,905 | 42,566 |
| Changes\tin\tother\tregulatory\tassets | 595,504 | (48,469) | 262,317 |
| Changes\tin\tother\tregulatory\tliabilities | 2,915,795 | 158,031 | 61,241 |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability\t/\tasset | (3,665,498) | — | — |
| Changes\tin\tpensions\tand\tother\tpostretirement\tliabilities | (130,686) | (136,919) | (446,418) |
| Other | (549,977) | (421,676) | 134,344 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 2,623,500 | 2,998,699 | 3,291,184 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction/capital\texpenditures | (3,607,532) | (2,780,222) | (2,500,860) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 96,000 | 68,345 | 53,635 |
| Nuclear\tfuel\tpurchases | (377,324) | (314,706) | (493,604) |
| Payment\tfor\tpurchase\tof\tplant\tor\tassets |  |  |  |
|  | (16,762) | (949,329) | — |
| Proceeds\tfrom\tsale\tof\tassets | 100,000 | — | 487,406 |
| Insurance\tproceeds\treceived\tfor\tproperty\tdamages | 26,157 | 20,968 | 24,399 |
| Changes\tin\tsecuritization\taccount | 1,323 | 4,007 | (5,806) |
| NYPA\tvalue\tsharing\tpayment | — | — | (70,790) |
| Payments\tto\tstorm\treserve\tescrow\taccount | (2,878) | (1,544) | (69,163) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 11,323 | — | 5,916 |
| Decrease\tin\tother\tinvestments | 1,078 | 9,055 | 571 |
| Litigation\tproceeds\tfor\treimbursement\tof\tspent\tnuclear\tfuel\tstorage\tcosts | 25,493 | 169,085 | 18,296 |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 3,162,747 | 2,408,920 | 2,492,176 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (3,260,674) | (2,484,627) | (2,550,958) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (3,841,049) | (3,850,048) | (2,608,782) |

| Long-term	debt | 1,809,390 | 6,800,558 | 3,502,189 |
| :--- | :--- | :--- | :--- |
| Preferred\tstock\tof\tsubsidiary | 14,399 | — | 107,426 |
| Treasury\tstock | 80,729 | 33,114 | 24,366 |
| Retirement\tof\tlong-term\tdebt | (1,585,681) | (5,311,324) | (3,461,518) |
| Repurchase\tof\tcommon\tstock | — | — | (99,807) |
| Repurchase\t/\tredemptions\tof\tpreferred\tstock | (20,599) | (115,283) | (94,285) |
| Changes\tin\tcredit\tborrowings\tand\tcommercial\tpaper\t-\tnet | 1,163,296 | (79,337) | (104,047) |
| Other | (7,731) | (6,872) | (9,136) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (628,885) | (611,835) | (598,897) |
| Preferred\tstock | (13,940) | (20,789) | (19,758) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | 810,978 | 688,232 | (753,467) |
| Net\tdecrease\tin\tcash\tand\tcash\tequivalents | (406,571) | (163,117) | (71,065) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 1,187,844 | 1,350,961 | 1,422,026 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $781,273 | $1,187,844 | $1,350,961 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $678,371 | $746,779 | $663,630 |
| Income\ttaxes | ($13,375) | $95,317 | $103,589 |

# CONSOLIDATED	BALANCE	SHEETS

# ASSETS

| Cash | $56,629 | $129,579 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 724,644 | 1,058,265 |
| Total\tcash\tand\tcash\tequivalents | 781,273 | 1,187,844 |
| Accounts\treceivable: |  |  |
| Customer | 673,347 | 654,995 |
| Allowance\tfor\tdoubtful\taccounts | (13,587) | (11,924) |
| Other | 169,377 | 158,419 |
| Accrued\tunbilled\trevenues | 383,813 | 368,677 |
| Total\taccounts\treceivable | 1,212,950 | 1,170,167 |
| Deferred\tfuel\tcosts | 95,746 | 108,465 |
| Fuel\tinventory\t-\tat\taverage\tcost | 182,643 | 179,600 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 723,222 | 698,523 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 133,164 | 146,221 |
| Prepayments\tand\tother | 156,333 | 193,448 |
| TOTAL | 3,285,331 | 3,684,268 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliates\t-\tat\tequity | 198 | 198 |
| Decommissioning\ttrust\tfunds | 7,211,993 | 5,723,897 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 260,980 | 233,641 |
| Other | 441,862 | 469,664 |
| TOTAL | 7,915,033 | 6,427,400 |
| PROPERTY,\tPLANT,\tAND\tEQUIPMENT |  |  |
| Electric | 47,287,370 | 45,191,216 |
| Property\tunder\tcapital\tlease | 620,544 | 619,527 |
| Natural\tgas | 453,162 | 413,224 |
| Construction\twork\tin\tprogress | 1,980,508 | 1,378,180 |
| Nuclear\tfuel | 923,200 | 1,037,899 |
| TOTAL\tPROPERTY,\tPLANT\tAND\tEQUIPMENT | 51,264,784 | 48,640,046 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 21,600,424 | 20,718,639 |
| PROPERTY,\tPLANT\tAND\tEQUIPMENT\t-\tNET | 29,664,360 | 27,921,407 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 761,280 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof\t$485,031\tas\tof\tDecember\t31,\t2017\tand\t$600,996\tas\tof\nDecember\t31,\t2016) | 4,935,689 | 4,769,913 |
| Deferred\tfuel\tcosts | 239,298 | 239,100 |
| Goodwill | 377,172 | 377,172 |
| Accumulated\tdeferred\tincome\ttaxes | 178,204 | 117,885 |
| Other | 112,062 | 1,606,009 |
| TOTAL | 5,842,425 | 7,871,359 |
| TOTAL\tASSETS | $46,707,149 | $45,904,434 |

# LIABILITIES	AND	EQUITY

| Currently	maturing	long-term	debt | $760,007 | $364,900 |
| :--- | :--- | :--- |
| Notes\tpayable\tand\tcommercial\tpaper | 1,578,308 | 415,011 |
| Accounts\tpayable | 1,452,216 | 1,285,577 |
| Customer\tdeposits | 401,330 | 403,311 |
| Taxes\taccrued | 214,967 | 181,114 |
| Interest\taccrued | 187,972 | 187,229 |
| Deferred\tfuel\tcosts | 146,522 | 102,753 |
| Obligations\tunder\tcapital\tleases | 1,502 | 2,423 |
| Pension\tand\tother\tpostretirement\tliabilities | 71,612 | 76,942 |
| Other | 221,771 | 180,836 |
| TOTAL | 5,036,207 | 3,200,096 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 4,466,503 | 7,495,290 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 219,634 | 227,147 |
| Obligations\tunder\tcapital\tleases | 22,015 | 24,582 |
| Regulatory\tliability\tfor\tincome\ttaxes-net | 2,900,204 | — |
| Other\tregulatory\tliabilities | 1,588,520 | 1,572,929 |
| Decommissioning\tand\tasset\tretirement\tcost\tliabilities | 6,185,814 | 5,992,476 |
| Accumulated\tprovisions | 478,273 | 481,636 |
| Pension\tand\tother\tpostretirement\tliabilities | 2,910,654 | 3,036,010 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$544,921\tas\tof\tDecember\t31,\t2017\tand\t$661,175\tas\tof\tDecember\t31,\n2016) | 14,315,259 | 14,467,655 |
| Other | 393,748 | 1,121,619 |
| TOTAL | 33,480,624 | 34,419,344 |
| Commitments\tand\tContingencies |  |  |
| Subsidiaries'\tpreferred\tstock\twithout\tsinking\tfund | 197,803 | 203,185 |
| \tCOMMON\tEQUITY |  |  |
|  | 2,548 | 2,548 |
| Paid-in\tcapital | 5,433,433 | 5,417,245 |
| Retained\tearnings | 7,977,702 | 8,195,571 |
| Accumulated\tother\tcomprehensive\tloss | (23,531) | (34,971) |
| Less\t-\ttreasury\tstock,\tat\tcost\t(74,235,135\tshares\tin\t2017\tand\t75,623,363\tshares\tin\t2016) | 5,397,637 | 5,498,584 |
| TOTAL | 7,992,515 | 8,081,809 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $46,707,149 | $45,904,434 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	EQUITY

|  | Subsidiaries'<br>Preferred	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,\t2014 | $94,000 | $2,548 | ($5,497,526) | $5,375,353 | $10,169,657 | ($42,307) | $10,101,725 |
| Consolidated\tnet\tincome\t(loss)\t(a) | 19,828 | — | — | — | (176,562) | — | (156,734) |
| Other\tcomprehensive\tincome | — | — | — | — | — | 51,258 | 51,258 |
| Common\tstock\trepurchases | — | — | (99,807) | — | — | — | (99,807) |
| Preferred\tstock\trepurchases\t/\nredemptions | (94,000) | — | — | — | (285) | — | (94,285) |
| Common\tstock\tissuances\trelated\tto\tstock\nplans | — | — | 44,954 | 28,405 | — | — | 73,359 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (598,897) | — | (598,897) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (19,828) | — | — | — | — | — | (19,828) |
| Balance\tat\tDecember\t31,\t2015 | $— | $2,548 | ($5,552,379) | $5,403,758 | $9,393,913 | $8,951 | $9,256,791 |
| Consolidated\tnet\tincome\t(loss)\t(a) | 19,115 | — | — | — | (583,618) | — | (564,503) |
| Other\tcomprehensive\tloss | — | — | — | — | — | (43,922) | (43,922) |
| Common\tstock\tissuances\trelated\tto\tstock\nplans | — | — | 53,795 | 13,487 | — | — | 67,282 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (611,835) | — | (611,835) |
| Subsidiaries'\tcapital\tstock\tredemptions | — | — | — | — | (2,889) | — | (2,889) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (19,115) | — | — | — | — | — | (19,115) |
| Balance\tat\tDecember\t31,\t2016 | $— | $2,548 | ($5,498,584) | $5,417,245 | $8,195,571 | ($34,971) | $8,081,809 |
| Consolidated\tnet\tincome\t(a) | 13,741 | — | — | — | 411,612 | — | 425,353 |
| Other\tcomprehensive\tincome | — | — | — | — | — | 11,440 | 11,440 |
| Common\tstock\tissuances\trelated\tto\tstock\nplans | — | — | 100,947 | 16,188 | — | — | 117,135 |
| Common\tstock\tdividends\tdeclared | — | — | — | — | (628,885) | — | (628,885) |
| Subsidiaries'\tcapital\tstock\tredemptions | — | — | — | — | (596) | — | (596) |
| Preferred\tdividend\trequirements\tof\nsubsidiaries\t(a) | (13,741) | — | — | — | — | — | (13,741) |
| Balance\tat\tDecember\t31,\t2017 | $— | $2,548 | ($5,397,637) | $5,433,433 | $7,977,702 | ($23,531) | $7,992,515 |

(a)	Consolidated	net	income	and	preferred	dividend	requirements	of	subsidiaries	include	$13.7	million	for	2017,	$19.1	million	for	2016,	and	$14.9	million	for	2015	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	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	 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	also	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	Louisiana,	Entergy	Mississippi,	and	Entergy	Texas	generate,	transmit,	and	distribute	electric	power	primarily to	retail	customers	in	Arkansas,	Louisiana,	Mississippi,	and	Texas,	respectively.		Entergy	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,	 including	Algiers.	Prior	to	October	1,	2015,	Entergy	Louisiana	was	the	electric	power	supplier	for	Algiers.	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.

For	sales	under	rates	implemented	subject	to	refund,	Entergy	reduces	revenue	by	accruing	estimated	amounts	for	probable	refunds	when Entergy	believes	it	is	probable	that	revenues	will	be	refunded	to	customers	based	upon	the	status	of	the	rate	proceeding.

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

Entergy	is	a	member	of	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	nets	purchases	and	sales	within	the	MISO	market	on	an	hourly	basis	and	reports	in	operating	revenues when	in	a	net	selling	position	for	an	hour	period	and	in	operating	expenses	when	in	a	net	purchasing	position	for	an	hour	period.

# Property,	Plant,	and	Equipment

Property,	plant,	and	equipment	is	stated	at	original	cost	less	regulatory	disallowances	and	impairments.		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	were	sold	and	leased	back	in	prior	periods.		For	financial	reporting purposes,	these	sale	and	leaseback	arrangements	are	reflected	as	financing	transactions.	In	March	2016,	Entergy	Louisiana	completed	the	first	step in	a	two-step	transaction	to	purchase	the	undivided	interests	in	Waterford	3	that	were	previously	being	leased	by	acquiring	a	beneficial	interest	in the	Waterford	3	leased	assets.	In	February	2017	the	leases	were	terminated	and	the	leased	assets	transferred	to	Entergy	Louisiana.	See	Note	10	to the	financial	statements	for	further	discussion	of	Entergy	Louisiana's	purchase	of	the	Waterford	3	leased	assets.

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,	2017	and	2016,	is	shown	below:

| 2017 | Entergy | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;	Other |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |
| Nuclear | $6,946 | $6,694 | $252 | $— |
| Other | 4,215 | 4,118 | 97 | — |
| Transmission | 5,844 | 5,842 | 2 | — |
| Distribution | 8,000 | 8,000 | — | — |
| Other | 1,755 | 1,748 | 3 | 4 |
| Construction\twork\tin\tprogress | 1,981 | 1,951 | 30 | — |
| Nuclear\tfuel | 923 | 822 | 101 | — |
| Property,\tplant,\tand\tequipment\t-\tnet | $29,664 | $29,175 | $485 | $4 |

| 2016 | Entergy | Utility | Entergy<br>Wholesale<br>Commodities | Parent	&amp;	Other |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Production |  |  |  |  |
| Nuclear | $6,948 | $6,524 | $424 | $— |
| Other | 4,047 | 4,000 | 47 | — |
| Transmission | 5,226 | 5,223 | 3 | — |
| Distribution | 7,648 | 7,648 | — | — |
| Other | 1,636 | 1,521 | 111 | 4 |
| Construction\twork\tin\tprogress | 1,378 | 1,334 | 44 | — |
| Nuclear\tfuel | 1,038 | 817 | 221 | — |
| Property,\tplant,\tand\tequipment\t-\tnet | $27,921 | $27,067 | $850 | $4 |

Depreciation	rates	on	average	depreciable	property	for	Entergy	approximated	3.0%	in	2017,	2.8%	in	2016,	and	2.9%	in	2015.		Included	in these	rates	are	the	depreciation	rates	on	average	depreciable	Utility	property	of	2.6%	in	2017,	2.6%	in	2016,	and	2.7%	2015,	and	the	depreciation rates	 on	 average	 depreciable	 Entergy	 Wholesale	 Commodities	 property	 of	22.3%	 in	2017,	 5.2%	 in	2016,	 and	5.4%	 in	2015.	 The	 higher depreciation	rate	in	2017	for	Entergy	Wholesale	Commodities	reflects	the	significantly	reduced	remaining	estimated	operating	lives	associated with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet.

Entergy	amortizes	nuclear	fuel	using	a	units-of-production	method.		Nuclear	fuel	amortization	is	included	in	fuel	expense	in	the	income statements.	Because	the	value	of	their	long-lived	assets	are	impaired,	and	their	remaining	estimated	operating	lives	significantly	reduced,	the Entergy	Wholesale	Commodities	nuclear	plants,	except	for	Palisades,	charge	nuclear	fuel	costs	directly	to	expense	when	incurred	because	their undiscounted	cash	flows	are	insufficient	to	recover	the	carrying	amount	of	these	capital	additions.

"Non-utility	property	-	at	cost	(less	accumulated	depreciation)"	for	Entergy	is	reported	net	of	accumulated	depreciation	of	$167	million and	$169	million	as	of	December	31,	2017	and	2016,	respectively.

Construction	expenditures	included	in	accounts	payable	is	$368	million	and	$253	million	at	December	31,	2017	and	2016,	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,	2017	and	2016,	is	shown	below:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>	New	Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Production |  |  |  |  |  |  |
| Nuclear | $1,368 | $3,664 | $— | $— | $— | $1,660 |
| Other | 806 | 2,016 | 560 | 207 | 531 | — |
| Transmission | 1,650 | 2,148 | 900 | 81 | 1,021 | 42 |
| Distribution | 2,226 | 2,748 | 1,316 | 440 | 1,270 | — |
| Other | 247 | 592 | 203 | 204 | 168 | 39 |
| Construction\twork\tin\nprogress | 281 | 1,281 | 149 | 47 | 102 | 70 |
| Nuclear\tfuel | 277 | 337 | — | — | — | 208 |
| Property,\tplant,\tand\nequipment\t-\tnet | $6,855 | $12,786 | $3,128 | $979 | $3,092 | $2,019 |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Production |  |  |  |  |  |  |
| Nuclear | $1,201 | $3,540 | $— | $— | $— | $1,783 |
| Other | 801 | 1,966 | 537 | 213 | 483 | — |
| Transmission | 1,491 | 1,925 | 740 | 79 | 943 | 45 |
| Distribution | 2,144 | 2,632 | 1,242 | 414 | 1,216 | — |
| Other | 216 | 517 | 201 | 188 | 106 | 25 |
| Construction\twork\tin\nprogress | 304 | 670 | 118 | 25 | 111 | 44 |
| Nuclear\tfuel | 307 | 250 | — | — | — | 260 |
| Property,\tplant,\tand\nequipment\t-\tnet | $6,464 | $11,500 | $2,838 | $919 | $2,859 | $2,157 |

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

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2017 | 2.5% | 2.3% | 3.1% | 3.5% | 2.6% | 2.8% |
| 2016 | 2.5% | 2.3% | 3.1% | 3.4% | 2.5% | 2.8% |
| 2015 | 2.6% | 2.3% | 3.2% | 3.0% | 2.6% | 2.8% |

Non-utility	property	-	at	cost	(less	accumulated	depreciation)	for	Entergy	Louisiana	is	reported	net	of	accumulated	depreciation	of	 $152.3 million	 and	$154.4	million	as	of	December	31,	2017	 and	2016,	 respectively.	Non-utility	property	-	at	cost	(less	accumulated	depreciation)	for Entergy	 Mississippi	 is	 reported	 net	 of	 accumulated	 depreciation	 of	$0.5	 million	 and	$0.5	 million	 as	 of	December	 31,	 2017	 and	2016, respectively.		Non-utility	property	-	at	cost	(less	accumulated	depreciation)	for	Entergy	Texas	is	reported	net	of	accumulated	depreciation	of	$4.9 million	and	$4.9	million	as	of	December	31,	2017	and	2016,	respectively.

As	of	December	31,	2017,	construction	expenditures	included	in	accounts	payable	are	$58.8	million	for	Entergy	Arkansas,	$160.4	million for	Entergy	Louisiana,	$17.1	million	for	Entergy	Mississippi,	$2.5	million	for	Entergy	New	Orleans,	$32.8	million	for	Entergy	Texas,	and	$33.9 million	for	System	Energy.		As	of	December	31,	2016,	construction	expenditures	included	in	accounts	payable	are	$40.9	million	for	Entergy Arkansas,	$114.8	million	for	Entergy	Louisiana,	$11.5	million	for	Entergy	Mississippi,	$2.3	million	for	Entergy	New	Orleans,	$9.3	million	for Entergy	Texas,	and	$6.2	million	for	System	Energy.

# Jointly-Owned	Generating	Stations

Certain	Entergy	subsidiaries	jointly	own	electric	generating	facilities	with	affiliates	or	third	parties.	All	parties	are	required	to	provide their	own	financing.		The	investments,	fuel	expenses,	and	other	operation	and	maintenance	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,	2017,	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 | Unit\t1 | Coal | 836 | 31.50% | $140 | $103 |
| \t\tIndependence | Common\tFacilities | Coal |  | 15.75% | $34 | $27 |
| \t\tWhite\tBluff | Units\t1\tand\t2 | Coal | 1,636 | 57.00% | $531 | $364 |
| \t\tOuachita\t(b) | Common\tFacilities | Gas |  | 66.67% | $172 | $150 |
| Units\t1\tand\t2\tCommon | Units\t1\tand\t2\tCommon |  |  |  |  |  |
| \t\tUnion\t(c) | Facilities | Gas |  | 50.00% | $1 | $— |
| \t\tUnion\t(c) | Common\tFacilities | Gas |  | 25.00% | $28 | $3 |
| Entergy\tLouisiana\t- |  |  |  |  |  |  |
| \t\tRoy\tS.\tNelson | Unit\t6 | Coal | 550 | 40.25% | $280 | $194 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon\tFacilities | Coal |  | 25.79% | $15 | $6 |
| \t\tBig\tCajun\t2 | Unit\t3 | Coal | 574 | 24.15% | $150 | $117 |
| \t\tBig\tCajun\t2 | Unit\t3\tCommon\tFacilities | Coal |  | 8.05% | $5 | $2 |
| \t\tOuachita\t(b) | Common\tFacilities | Gas |  | 33.33% | $90 | $75 |
| \t\tAcadia | Common\tFacilities | Gas |  | 50.00% | $20 | $— |
| \t\tUnion\t(c) | Common\tFacilities | Gas |  | 50.00% | $55 | $3 |
| Entergy\tMississippi\t- |  |  |  |  |  |  |
| Units\t1\tand\t2\tand\tCommon | Units\t1\tand\t2\tand\tCommon |  |  |  |  |  |
| \t\tIndependence\nEntergy\tNew\tOrleans\t- | Facilities | Coal | 1,678 | 25.00% | $266 | $156 |
| Units\t1\tand\t2\tCommon | Units\t1\tand\t2\tCommon |  |  |  |  |  |
| \t\tUnion\t(c) | Facilities | Gas |  | 50.00% | $1 | $— |
| \t\tUnion\t(c) | Common\tFacilities | Gas |  | 25.00% | $28 | $3 |
| Entergy\tTexas\t- |  |  |  |  |  |  |
| \t\tRoy\tS.\tNelson | Unit\t6 | Coal | 550 | 29.75% | $200 | $114 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon\tFacilities | Coal |  | 14.16% | $6 | $3 |
| \t\tBig\tCajun\t2 | Unit\t3 | Coal | 574 | 17.85% | $113 | $76 |
| \t\tBig\tCajun\t2 | Unit\t3\tCommon\tFacilities | Coal |  | 5.95% | $3 | $1 |
| System\tEnergy\t- |  |  |  |  |  |  |
| \t\tGrand\tGulf\t(d) | Unit\t1 | Nuclear | 1,414 | 90.00% | $4,916 | $3,175 |
| Entergy\tWholesale\nCommodities: |  |  |  |  |  |  |
| \t\tIndependence | Unit\t2 | Coal | 842 | 14.37% | $73 | $50 |
| \t\tIndependence | Common\tFacilities | Coal |  | 7.18% | $17 | $12 |
| \t\tRoy\tS.\tNelson | Unit\t6 | Coal | 550 | 10.90% | $113 | $62 |
| \t\tRoy\tS.\tNelson | Unit\t6\tCommon\tFacilities | Coal |  | 5.19% | $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	Louisiana.		The	investment and	accumulated	depreciation	numbers	above	are	only	for	the	common	facilities	and	not	for	the	generating	units.

(c) Union	Unit	1	is	owned	100%	by	Entergy	New	Orleans,	Union	Unit	2	is	owned	100%	by	Entergy	Arkansas,	Union	Units	3	and	4	are	owned 100%	by	Entergy	Louisiana.		The	investment	and	accumulated	depreciation	numbers	above	are	only	for	the	specified	common	facilities and	not	for	the	generating	units.

(d) 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.	Because	the value	 of	 their	 long-lived	 assets	 are	 impaired,	 and	 their	 remaining	 estimated	 operating	 lives	 significantly	 reduced,	 the	 Entergy	 Wholesale Commodities	 nuclear	 plants,	 except	 for	 Palisades,	 charge	 nuclear	 refueling	 outage	 costs	 directly	 to	 expense	 when	 incurred	 because	 their undiscounted	cash	flows	are	insufficient	to	recover	the	carrying	amount	of	these	costs.

# 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.		Entergy	Louisiana, LLC	and	Entergy	New	Orleans,	LLC	are	not	members	of	the	Entergy	Corporation	consolidated	federal	income	tax	filing	group	but,	rather,	are included	in	the	Entergy	Utility	Holding	Company,	LLC	consolidated	federal	income	tax	filing	group.		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	agreements.		Deferred	income	taxes	are	recorded	for	temporary	differences	between	the	book	and	tax	basis	of assets	and	liabilities,	and	for	certain	losses	and	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.	See	the	"Other	Tax	Matters	-	Tax	Cuts	and	Jobs	Act"	section	in	Note	3	to	the	financial	statements for	discussion	of	the	effects	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017.

The	benefits	of	investment	tax	credits	are	deferred	and	amortized	over	the	average	useful	life	of	the	related	property,	as	a	reduction	of income	tax	expense,	for	such	credits	associated	with	rate-regulated	operations	in	accordance	with	ratemaking	treatment.

# Earnings	(Loss)	per	Share

The	 following table	 presents	 Entergy's	 basic	 and	 diluted	 earnings	 per	 share	 calculation included	 on the	 consolidated	 statements	 of operations:

|  | 2017 | 2017 | 2016 | 2016 | 2015 | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | $/share | (In\tMillions,\tExcept\tPer\tShare\tData) | $/share |  | $/share |
| Net\tincome\t(loss)\tattributable\tto\tEntergy\nCorporation | $411.6 |  | ($583.6) |  | ($176.6) |  |
| Basic\tearnings\t(loss)\tper\taverage\ncommon\tshare | 179.7 | $2.29 | 178.9 | ($3.26) | 179.2 | ($0.99) |
| Average\tdilutive\teffect\tof: |  |  |  |  |  |  |
| Stock\toptions | 0.2 | — | — | — | — | — |
| Other\tequity\tplans | 0.6 | (0.01) | — | — | — | — |
| Diluted\tearnings\t(loss)\tper\taverage\ncommon\tshares | 180.5 | $2.28 | 178.9 | ($3.26) | 179.2 | ($0.99) |

The	calculation	of	diluted	earnings	(loss)	per	share	excluded	2,927,512	options	outstanding	at	December	31,	2017,	7,137,210	options outstanding	at	December	31,	2016,	and	7,399,820	options	outstanding	at	December	31,	2015	because	they	were	antidilutive.

# Stock-based	Compensation	Plans

Entergy	grants	stock	options,	restricted	stock,	performance	units,	and	restricted	stock	unit	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	three	years.

Effective	 January	 1,	 2017,	 Entergy	 adopted	 ASU	 2016-09,	 "Compensation	 -	 Stock	 Compensation	 (Topic	 718):	 Improvements	 to Employee	 Share-Based	 Payment	Accounting."	The	ASU	permits	 the	election	of	an	accounting	policy	change	 to	 the	method	of	recognizing forfeitures	of	stock-based	compensation.	Previously,	Entergy	recorded	an	estimate	of	the	number	of	forfeitures	expected	to	occur	each	period. Entergy	elected	to	change	this	policy	to	account	for	forfeitures	when	they	occur.	This	accounting	change	was	applied	retrospectively,	but	did	not result	in	an	adjustment	to	retained	earnings	as	of	January	1,	2017.	As	a	result	of	adoption	of	the	ASU,	Entergy	now	prospectively	recognizes	all income	tax	effects	related	to	share-based	payments	through	the	income	statement.	In	the	first	quarter	2017,	stock	option	expirations,	along	with other	stock	compensation	activity,	resulted	in	the	write-off	of	$11.5	million	of	deferred	tax	assets.

# 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,	which	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	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,	unless	specific	cost	recovery	is	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	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	or	Liability	for	Income	Taxes

Accounting	 standards	 for	 income	 taxes	 provide	 that	 a	 regulatory	 asset	 or	 liability	 be	 recorded	 if	 it	 is	 probable	 that	 the	 currently determinable	future	increase	or	decrease	in	regulatory	income	tax	expense	will	be	recovered	from	or	returned	to	customers	through	future	rates. There	are	two	main	sources	of	Entergy's	regulatory	asset	or	liability	for	income	taxes.	There	is	a	regulatory	asset	related	to	the	ratemaking treatment	of	the	tax	effects	of	book	depreciation	for	the	equity	component	of	AFUDC	that	has	been	capitalized	to	property,	plant,	and	equipment but	for	which	there	is	no	corresponding	tax	basis.	Equity-AFUDC	is	a	component	of	property,	plant,	and	equipment	that	is	included	in	rate	base when	the	plant	is	placed	in	service.	There	is	a	regulatory	liability	related	to	the	adjustment	of	Entergy's	net	deferred	income	taxes	that	was required	by	the	enactment	in	December	2017	of	a	change	in	the	federal	corporate	income	tax	rate,	which	is	discussed	in	Note	3	to	the	financial statements.

# Cash	and	Cash	Equivalents

Entergy	considers	all	unrestricted	highly	liquid	debt	instruments	with	an	original	maturity	of	three	months	or	less	at	date	of	purchase	to	be cash	equivalents.

# Securitization	Recovery	Trust	Accounts

The	funds	that	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas	hold	in	their	securitization	recovery	trust accounts	are	not	classified	as	cash	and	cash	equivalents	or	restricted	cash	and	cash	equivalents	because	of	their	nature,	uses,	and	restrictions.	These funds	are	classified	as	part	of	other	current	assets	and	other	investments,	depending	on	the	timeframe	within	which	the	Registrant	Subsidiary expects	to	use	the	funds.

# 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

Entergy	Corporation	and	Subsidiaries Notes	to	Financial	Statements

for	decommissioning	trust	funds,	for	unrealized	gains/(losses)	on	investment	securities	the	Registrant	Subsidiaries	record	an	offsetting	amount	in other	regulatory	liabilities/assets.		For	the	30%	interest	in	River	Bend	formerly	owned	by	Cajun,	Entergy	Louisiana	records	an	offsetting	amount in	other	deferred	credits	for	the	excess	trust	earnings	not	currently	expected	to	be	needed	to	decommission	the	plant.		Decommissioning	trust funds	for	Pilgrim,	Indian	Point	1,	Indian	Point	2,	Indian	Point	3,	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.		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.	 	 Effective	 January	 1,	 2018	 with	 the	 adoption	 of	ASU	 2016-01,	 unrealized	 gains	 and	 losses	 on investments	in	equity	securities	held	by	the	nuclear	decommissioning	trust	funds	will	be	recorded	in	earnings	as	they	occur	rather	than	in	other comprehensive	 income.	In	 accordance	 with	 the	 regulatory	 treatment	 of	 the	 decommissioning	 trust	 funds	 of	 the	 Registrant	 Subsidiaries,	 an offsetting	amount	of	unrealized	gains/losses	will	continue	to	be	recorded	in	other	regulatory	liabilities/assets.	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	16	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	the	investee's	comprehensive	earnings	and losses	in	income	and	as	an	increase	or	decrease	to	the	investment	account.	Any	cash	distributions	are	charged	against	the	investment	account. 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.

# 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	sale	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.	Due	to	regulatory	treatment,	an	offsetting	regulatory	asset or	liability	is	recorded	for	changes	in	fair	value	of	recognized	derivatives	for	the	Registrant	Subsidiaries.

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.	Changes	in	the	fair	value	of	derivative	instruments	that	are not	designated	as	cash	flow	hedges	are	recorded	in	current-period	earnings	on	a	mark-to-market	basis.

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.	See	Note	15	to	the	financial	statements	for	further	details	on	Entergy's	derivative	instruments	and	hedging	activities.

# Fair	Values

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 held	by	regulated	businesses	may	be	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.		See	Note	15	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	expected	operating	life	of	the	assets,	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.	Because	the	values	of	their	long-lived	assets	are	impaired,	and	their	remaining	estimated operating	 lives	 significantly	 reduced,	 the	 Entergy	 Wholesale	 Commodities	 nuclear	 plants,	 except	 for	 Palisades,	 are	 charging	 additional expenditures	for	capital	assets	directly	to	expense	when	incurred	because	their	undiscounted	cash	flows	are	insufficient	to	recover	the	carrying amount	of	these	capital	additions.		See	Note	14	to	the	financial	statements	for	further	discussions	of	the	impairments	of	the	Entergy	Wholesale Commodities	nuclear	plants.

# 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	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	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,	prior	to	December	1,	2017,	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.		In	November	2017,	Entergy	New	Orleans redeemed	its	outstanding	preferred	securities	as	part	of	a	multi-step	process	to	undertake	an	internal	restructuring.	See	Note	2	to	the	financial statements	for	a	discussion	of	Entergy	New	Orleans's	internal	restructuring.

The	outstanding	preferred	securities	of	Entergy	Arkansas,	Entergy	Mississippi,	and	Entergy	New	Orleans,	and	Entergy	Utility	Holding Company	(a	Utility	subsidiary)	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.		The	preferred	dividends	or distributions	paid	by	all	subsidiaries	are	reflected	for	all	periods	presented	outside	of	consolidated	net	income.

In	May	2014	the	FASB	issued	ASU	No.	2014-09,	"Revenue	from	Contracts	with	Customers	(Topic	606)."	The	ASU's	core	principle	is that	 "an	 entity	 should	 recognize	 revenue	 to	 depict	 the	 transfer	 of	 promised	 goods	 or	 services	 to	 customers	 in	 an	 amount	 that	 reflects	 the consideration	to	which	the	entity	expects	to	be	entitled	in	exchange	for	those	goods	or	services."	The	ASU	details	a	five-step	model	that	should	be followed	 to	 achieve	 the	 core	 principle.	With	FASB	 issuance	of	ASU	No.	2015-14,	"Revenue	from	Contracts	with	Customers	(Topic	606): Deferral	of	the	Effective	Date,"	ASU	2014-09	is	effective	for	Entergy	for	the	first	quarter	2018.	Entergy	has	selected	the	modified	retrospective transition	 method.	Entergy's	 evaluation	 of	ASU	 2014-09	 has	 not	 identified	 any	 effects	 that	 it	 expects	 will	 affect	 materially	 its	 results	 of operations,	financial	position,	or	cash	flows,	other	than	changes	in	required	financial	statement	disclosures.	The	adoption	of	the	ASU	did	not	result in	an	adjustment	to	retained	earnings	as	of	January	1,	2018.

In	 January	 2016	 the	 FASB	 issued	ASU	 No.	 2016-01	 "Financial	 Instruments	 (Subtopic	 825-10):	 Recognition	 and	 Measurement	 of Financial	Assets	and	Financial	Liabilities."	The	ASU	requires	investments	in	equity	securities,	excluding	those	accounted	for	under	the	equity method	or	resulting	in	consolidation	of	the	investee,	to	be	measured	at	fair	value	with	changes	recognized	in	net	income.	The	ASU	requires	a qualitative	assessment	to	identify	impairments	of	investments	in	equity	securities	that	do	not	have	a	readily	determinable	fair	value.	ASU	2016-01 is	effective	for	Entergy	for	the	first	quarter	2018.	Entergy	expects	that	ASU	2016-01	will	affect	its	results	of	operations	by	requiring	unrealized gains	and	losses	on	investments	in	equity	securities	held	by	the	nuclear	decommissioning	trust	funds	to	be	recorded	in	earnings	rather	than	in other	 comprehensive	 income.	In	accordance	with	the	regulatory	treatment	of	the	decommissioning	trust	funds	of	Entergy	Arkansas,	Entergy Louisiana,	and	System	Energy,	an	offsetting	amount	of	unrealized	gains/losses	will	continue	to	be	recorded	in	other	regulatory	liabilities/assets. Entergy	recorded	an	adjustment	to	retained	earnings	of	$633	million	as	of	January	1,	2018	for	the	cumulative	effect	of	the	unrealized	gains	and losses

on	investments	in	equity	securities	held	by	the	decommissioning	trust	funds	that	do	not	meet	the	criteria	for	regulatory	accounting	treatment.

In	February	2016	the	FASB	issued	ASU	No.	2016-02,	"Leases	(Topic	842)."		The	ASU's	core	principle	is	that	"a	lessee	should	recognize the	assets	and	liabilities	that	arise	from	leases."	The	ASU	considers	that	"all	leases	create	an	asset	and	a	liability,"	and	accordingly	requires recording	the	assets	and	liabilities	related	to	all	leases	with	a	term	greater	than	12	months.		In	January	2018	the	FASB	issued	ASU	No.	2018-01, "Leases	(Topic	842):	Land	Easement	Practical	Expedient	for	Transition	to	Topic	842,"	providing	entities	the	option	to	elect	not	to	evaluate existing	land	easements	that	are	not	currently	accounted	for	under	the	previous	lease	standard.	ASU	2016-02	is	effective	for	Entergy	for	the	first quarter	2019,	and	Entergy	does	not	expect	to	early	adopt	the	standard.		Entergy	expects	that	ASU	2016-02	will	affect	its	financial	position	by increasing	the	assets	and	liabilities	recorded	relating	to	its	operating	leases.		Entergy	is	evaluating	ASU	2016-02	for	other	effects	on	its	results	of operations,	 financial	 position,	 cash	 flows,	 and	 financial	 statement	 disclosures,	 as	 well	 as	 the	 potential	 to	 elect	 various	 practical	 expedients permitted	by	the	standards.

In	June	2016	the	FASB	issued	ASU	No.	2016-13,	"Financial	Instruments	-	Credit	Losses	(Topic	326):	Measurement	of	Credit	Losses	on Financial	 Instruments."	The	ASU	 requires	 entities	 to	 record	 a	 valuation	 allowance	 on	 financial	 instruments	 recorded	 at	 amortized	 cost	 or classified	as	available-for-sale	debt	securities	for	the	total	credit	losses	expected	over	the	life	of	the	instrument.	Increases	and	decreases	in	the valuation	allowance	will	be	recognized	immediately	in	earnings.	ASU	2016-13	is	effective	for	Entergy	for	the	first	quarter	2020.	Entergy	 is evaluating	ASU	2016-13	for	the	expected	effects	on	its	results	of	operations,	financial	position,	and	cash	flows.

In	October	2016	the	FASB	issued	ASU	No.	2016-16,	"Income	Taxes	(Topic	740):	Intra-Entity	Transfers	of	Assets	Other	Than	Inventory." The	ASU	requires	entities	to	recognize	the	income	tax	consequences	of	intra-entity	asset	transfers,	other	than	inventory,	at	the	time	the	transfer occurs.	ASU	2016-16	is	effective	for	Entergy	for	the	first	quarter	2018	and	will	affect	its	statement	of	financial	position	by	requiring	recognition of	deferred	tax	assets	or	liabilities	arising	from	intra-entity	asset	transfers.	Entergy	recorded	an	adjustment	to	retained	earnings	of	$56	million	as of	January	1,	2018	for	the	cumulative-effect	of	the	recognition	of	the	deferred	tax	assets	arising	from	intra-entity	asset	transfers.

In	March	2017	the	FASB	issued	ASU	No.	2017-07,	"Compensation	-	Retirement	Benefits	(Topic	715):	Improving	the	Presentation	of	Net Periodic	Pension	Cost	and	Net	Periodic	Postretirement	Benefit	Cost."	The	ASU	requires	entities	to	report	the	service	cost	component	of	defined benefit	pension	cost	and	postretirement	benefit	cost	(net	benefit	cost)	in	the	same	line	item	as	other	compensation	costs	arising	from	services rendered	during	the	period.		The	other	components	of	net	benefit	cost	are	required	to	be	presented	in	the	income	statement	separately	from	the service	cost	component	and	outside	a	subtotal	of	income	from	operations.		In	addition,	the	ASU	allows	only	the	service	cost	component	of	net benefit	cost	to	be	eligible	for	capitalization.		ASU	2017-07	is	effective	for	Entergy	for	the	first	quarter	2018.		Entergy	does	not	expect	ASU	2017- 07	to	affect	materially	its	results	of	operations,	financial	position,	or	cash	flows.

In	August	2017	the	FASB	issued	ASU	No.	2017-12,	"Derivatives	and	Hedging	(Topic	815):	Targeted	Improvements	to	Accounting	for Hedging	 Activities."	 	 The	 ASU	 makes	 a	 number	 of	 amendments	 to	 hedge	 accounting,	 most	 significantly	 changing	 the	 recognition	 and presentation	of	highly	effective	hedges.	 	Upon	adoption	of	 the	standard	 there	will	no	 longer	be	separate	recognition	or	presentation	of	 the ineffective	portion	of	highly	effective	hedges.		In	addition,	the	ASU	allows	entities	to	designate	a	contractually-specified	component	as	the	hedged risk,	simplifies	the	process	for	assessing	the	effectiveness	of	hedges,	and	adds	additional	disclosure	requirements	for	hedges.		ASU	2017-12	is effective	for	Entergy	for	the	first	quarter	2019.	Entergy	does	not	expect	to	early	adopt	the	standard.		Entergy	expects	that	ASU	2017-12	will	affect its	net	income	by	eliminating	volatility	in	earnings	related	to	the	ineffective	portion	of	designated	hedges	on	nuclear	power	sales.		Entergy	is evaluating	ASU	2017-12	for	other	effects	on	its	results	of	operations,	financial	position,	or	cash	flows.

In	 February	 2018	 the	 FASB	 issued	 ASU	 No.	 2018-02,	 "Income	 Statement-	 Reporting	 Comprehensive Income (Topic 220): Reclassification	of	Certain	Tax	Effects	from	Accumulated	Other	Comprehensive	Income."		The	ASU

allows	reclassification	from	accumulated	other	comprehensive	income	to	retained	earnings	for	certain	tax	effects	resulting	from	the	Tax	Cuts	and Jobs	Act	that	would	otherwise	be	stranded	in	accumulated	other	comprehensive	income	.		ASU	2018-02	is	effective	for	Entergy	for	the	first quarter	2019,	but	may	be	early	adopted.	Entergy	plans	to	adopt	the	ASU	in	the	first	quarter	2018.		Entergy	expects	that	upon	the	adoption	of	ASU 2018-02	it	will	record	to	the	statement	of	financial	position	a	net	reclassification	reducing	retained	earnings	and	increasing	accumulated	other comprehensive	income	by	approximately	$15	million.		Entergy	does	not	expect	that	ASU	2018-02	will	have	any	other	material	effect	on	its results	of	operations,	financial	position,	or	cash	flows.

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

# Regulatory	Assets	and	Regulatory	Liabilities

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.	Regulatory	liabilities	represent	probable	future	reductions	in	revenues associated	with	amounts	that	Entergy	expects	to	benefit	customers	through	the	regulatory	ratemaking	process	under	which	the	Utility	business operates.	In	addition	to	the	regulatory	assets	and	liabilities	that	are	specifically	disclosed	on	the	face	of	the	balance	sheets,	the	tables	below provide	detail	of	"Other	regulatory	assets"	and	"Other	regulatory	liabilities"	that	are	included	on	Entergy's	and	the	Registrant	Subsidiaries' balance	sheets	as	of	December	31,	2017	and	2016:

# Other	Regulatory	Assets

| and	Non-Qualified	Pension	Plans)	(a) | and	Non-Qualified	Pension	Plans)	(a) |  |  | $2,642.3 | $2,635.5 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\tof\tnuclear\tunits\tor\ndismantlement\tof\tnon-nuclear\tpower\tplants\t(Note\t9)\t(a) | Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\tof\tnuclear\tunits\tor\ndismantlement\tof\tnon-nuclear\tpower\tplants\t(Note\t9)\t(a) | Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\tof\tnuclear\tunits\tor\ndismantlement\tof\tnon-nuclear\tpower\tplants\t(Note\t9)\t(a) | Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\tof\tnuclear\tunits\tor\ndismantlement\tof\tnon-nuclear\tpower\tplants\t(Note\t9)\t(a) | 746.0 | 677.2 |
| Storm\tdamage\tcosts,\tincluding\thurricane\tcosts\t-\trecovered\tthrough\tsecuritization\tand\tretail\trates\t(Note |  |  |  |  |  |
| 2\t–\tStorm\tCost\tRecovery\tFilings\twith\tRetail\tRegulators)\t(Note\t5) | 2\t–\tStorm\tCost\tRecovery\tFilings\twith\tRetail\tRegulators)\t(Note\t5) | 2\t–\tStorm\tCost\tRecovery\tFilings\twith\tRetail\tRegulators)\t(Note\t5) |  | 558.9 | 637.0 |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(a) | Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(a) | Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(a) |  | 436.5 | 353.9 |
| Opportunity\tSales\t-\trecovery\twill\tbe\tdetermined\tafter\tfinal\torder\tin\tproceeding\t(Note\t2\t-\tEntergy |  |  |  |  |  |
| Arkansas\tOpportunity\tSales\tProceeding) | Arkansas\tOpportunity\tSales\tProceeding) | Arkansas\tOpportunity\tSales\tProceeding) |  | 109.8 | — |
| Retail\trate\tdeferrals\t-\trecovered\tthrough\trate\triders\tas\trates\tare\tredetermined\tby\tretail\tregulators | Retail\trate\tdeferrals\t-\trecovered\tthrough\trate\triders\tas\trates\tare\tredetermined\tby\tretail\tregulators | Retail\trate\tdeferrals\t-\trecovered\tthrough\trate\triders\tas\trates\tare\tredetermined\tby\tretail\tregulators | Retail\trate\tdeferrals\t-\trecovered\tthrough\trate\triders\tas\trates\tare\tredetermined\tby\tretail\tregulators | 86.4 | 22.1 |
| Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 82.9 | 91.4 |
| Little\t Gypsy\t costs\t –\nBonds\t-\tLittle\tGypsy) | recovered | through\t securitization | (Note\t 5\t –\tEntergy\t Louisiana\t Securitization | 73.7 | 100.0 |
| Transition\tto\tcompetition\tcosts\t-\trecovered\tover\ta\t15-year\tperiod\tthrough\tFebruary\t2021 | Transition\tto\tcompetition\tcosts\t-\trecovered\tover\ta\t15-year\tperiod\tthrough\tFebruary\t2021 | Transition\tto\tcompetition\tcosts\t-\trecovered\tover\ta\t15-year\tperiod\tthrough\tFebruary\t2021 | Transition\tto\tcompetition\tcosts\t-\trecovered\tover\ta\t15-year\tperiod\tthrough\tFebruary\t2021 | 37.7 | 47.9 |
| New\tnuclear\tgeneration\tdevelopment\tcosts\t(Note\t2\t-\tNew\tNuclear\tGeneration\tDevelopment\tCosts) |  |  |  |  |  |
| (b) | (b) | (b) | (b) | 36.4 | 43.7 |
| Other | Other | Other | Other | 125.1 | 161.2 |
| Entergy\tTotal |  |  |  | $4,935.7 | $4,769.9 |

# Entergy	Arkansas

| and	Non-Qualified	Pension	Plans)	(a) | $757.0 | $786.6 |
| :--- | :--- | :--- |
| Asset\tretirement\tobligation\t-\trecovery\tdependent\tupon\ttiming\tof\tdecommissioning\tof\tnuclear\tunits\tor\ndismantlement\tof\tnon-nuclear\tpower\tplants\t(Note\t9)\t(a) | 345.2 | 322.9 |
| Removal\tcosts\t-\trecovered\tthrough\tdepreciation\trates\t(Note\t9)\t(a) | 176.9 | 128.5 |
| Opportunity\nsales\t-\t recovery\t will\t be\t determined\t after\t final\t order\nin\t proceeding\t (Note\t 2\t -\tEntergy |  |  |
| Arkansas\tOpportunity\tSales\tProceeding) | 109.8 | — |
| Storm\tdamage\tcosts\t-\trecovered\teither\tthrough\tsecuritization\tor\tretail\trates\t(Note\t5\t-\t Entergy\tArkansas |  |  |
| Securitization\tBonds) | 76.2 | 88.9 |
| Retail\trate\tdeferrals\t-\trecovered\tthrough\trate\triders\tas\trates\tare\tredetermined\tannually | 28.2 | 10.1 |
| Unamortized\tloss\ton\treacquired\tdebt\t-\trecovered\tover\tterm\tof\tdebt | 24.3 | 27.6 |
| ANO\tFukushima\tand\tFlood\tBarrier\tcosts\t-\trecovered\tthrough\tretail\trates\tthrough\tFebruary\t2026\t(Note | 14.4 | 16.1 |
| 2\t-\tRetail\tRate\tProceedings)\t(b) |  |  |
| Lake\tCatherine\t4\treliability\tand\tsustainability\tcost\tdeferral\t-\trecovery\tthrough\tretail\trates\t(b) | 8.9 | 9.8 |
| Incremental\tice\tstorm\tcosts\t-\trecovered\tthrough\t2032 | 7.4 | 7.9 |
| MISO\tcosts\t-\trecovery\tthrough\tretail\trates\tthrough\t2018\t(Note\t2\t-\t Retail\tRate\tProceedings)\t(b) | 5.5 | 11.1 |
| Human\tcapital\tmanagement\tcosts\t-\trecovery\tthrough\tretail\trates\tthrough\tAugust\t2019\t(Note\t2\t-\t Retail |  |  |
| Rate\tProceedings)\t(b) | 4.4 | 7.0 |
| Other | 9.2 | 11.5 |
| Entergy\tArkansas\tTotal | $1,567.4 | $1,428.0 |

# Entergy	Louisiana

# Entergy	New	Orleans

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

(b) Does	not	earn	a	return	on	investment.

# Other	Regulatory	Liabilities

|  |  |  |  |  |  |  | (In	Millions) | (In	Millions) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | Unrealized\tgains\ton\tnuclear\tdecommissioning\ttrust\tfunds\t(Note\t16)\t(a) | $989.3 | $735.5 |
| Vidalia\tpurchased\tpower\tagreement\t(Note\t8)\t(b) | Vidalia\tpurchased\tpower\tagreement\t(Note\t8)\t(b) | Vidalia\tpurchased\tpower\tagreement\t(Note\t8)\t(b) |  |  |  |  | 151.6 | 202.4 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | Louisiana\tAct\t55\tfinancing\tsavings\tobligation\t(Note\t2\t-\tStorm\tCost\tRecovery\tFilings\twith\tRetail\nRegulators)\t(b) | 124.8 | 165.5 |
| Grand\tGulf\tsale-leaseback\t-\t(Note\t10\t-\tSale\tand\tLeaseback\tTransactions) | Grand\tGulf\tsale-leaseback\t-\t(Note\t10\t-\tSale\tand\tLeaseback\tTransactions) | Grand\tGulf\tsale-leaseback\t-\t(Note\t10\t-\tSale\tand\tLeaseback\tTransactions) | Grand\tGulf\tsale-leaseback\t-\t(Note\t10\t-\tSale\tand\tLeaseback\tTransactions) |  |  |  | 67.9 | 67.9 |
| Business\tcombination\tguaranteed\tcustomer\tbenefits\t-\treturned\tto\tcustomers\tthrough\tretail\trates\tand |  |  |  |  |  |  |  |  |
| fuel | rates\t beginning\t December\t 2015 | through\t November\t 2024\t(Note | 2 | -\tEntergy\t Louisiana\t and | -\tEntergy\t Louisiana\t and | -\tEntergy\t Louisiana\t and |  |  |
| Entergy\tGulf\tStates\tLouisiana\tBusiness\tCombination) | Entergy\tGulf\tStates\tLouisiana\tBusiness\tCombination) | Entergy\tGulf\tStates\tLouisiana\tBusiness\tCombination) |  |  |  |  | 65.8 | 83.5 |
| Entergy\t Arkansas's | accumulated | accelerated\t Grand\t Gulf | amortization\t-\t will | be | returned | to |  |  |
| customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | customers\twhen\tapproved\tby\tthe\tAPSC\tand\tthe\tFERC | 44.4 | 44.4 |
| Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | Asset\tretirement\tobligation\t-\treturn\tto\tcustomers\tdependent\tupon\ttiming\tof\tdecommissioning\t(Note\t9)\n(a) | 36.7 | 32.7 |
|  |  |  |  |  |  |  | 32.4 | 53.9 |
| Removal\tcosts\t-\treturned\tto\tcustomers\tthrough\tdepreciation\trates\t(Note\t9)\t(a) |  |  |  |  |  |  |  |  |
| Entergy\tMississippi's\taccumulated\taccelerated\tGrand\tGulf\tamortization\t-\tamortized\tand\tcredited |  |  |  |  |  |  |  |  |
| through\tthe\tUnit\tPower\tSales\tAgreement | through\tthe\tUnit\tPower\tSales\tAgreement |  |  |  |  |  | 32.1 | 39.3 |
| Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | Waterford\t3\treplacement\tsteam\tgenerator\tprovision\t(Note\t2\t-\tRetail\tRate\tProceedings) | — | 68.0 |
| Other | Other | Other | Other | Other | Other | Other | 43.5 | 79.8 |
| Entergy\tTotal |  |  |  |  |  |  | $1,588.5 | $1,572.9 |

(a) Offset	by	related	asset.

(b) As	a	result	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	and	the	lowering	of	the	federal	corporate	income	tax	rate from	35%	to	21%	effective	January	2018,	the	Vidalia	purchased	power	agreement	regulatory	liability	was	reduced	by	 $30.5	million	and the	Louisiana	Act	55	financing	savings	obligation	regulatory	liabilities	were	reduced	by	$25.0	million,	with	corresponding	increases	to Other	regulatory	credits	on	the	income	statement.	The	effects	of	the	Tax	Cuts	and	Jobs	Act	are	discussed	further	in	Note	3	to	the	financial statements.

# Regulatory	activity	regarding	the	Tax	Cuts	and	Jobs	Act

See	the	"Other	Tax	Matters	-	Tax	Cuts	and	Jobs	Act"	section	in	Note	3	to	the	financial	statements	for	discussion	of	the	effects	of	the enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	including	its	effects	on	Entergy's	and	the	Registrant	Subsidiaries'	regulatory asset/liability	for	income	taxes.

After	enactment	of	the	Tax	Cuts	and	Jobs	Act	the	APSC	issued	an	order	that	applies	to	investor-owned	utilities	in	Arkansas,	including Entergy	 Arkansas.	The	order	requests	information	regarding	certain	effects	of	the	Tax	Cuts	and	Jobs	Act	and	requires	the	utilities	to	begin, effective	January	1,	2018,	to	record	regulatory	liabilities	to	record	the	effects	of	the	Act,	subject	to	review	by	the	APSC,	although	the	order acknowledges	that	the	exact	amount	of	tax	savings	and	rate	reductions	cannot	be	determined	at	this	time.	Entergy	Arkansas	requested	clarification or,	in	the	alternative,	rehearing	regarding	the	requirement	to	record	a	regulatory	liability,	and	also	responded	to	the	request	for	information.	In	its request	for	clarification	Entergy	Arkansas	sought	clarification	that	the	amount	of	any	regulatory	liability	would	be	determined	only	after	the utilities	are	heard	and	present	evidence	on	 the	 issue,	as	 this	otherwise	would	be	arbitrary	and	could	 implicate	single-issue	and	retroactive ratemaking.	The	APSC	has	not	responded	to	the	request	for	clarification.	In	its	response	to	the	APSC's	request	for	information	Entergy	Arkansas states	 that	 its	formula	rate	plan	rider	already	provides	 the	means	for	customers	 to	realize	 the	benefits	of	 the	Act,	except	for	 the	return	of unprotected	excess	accumulated	deferred	income	taxes.	Entergy	Arkansas's	next	formula	rate	plan	filing	is	scheduled	for	July	2018.	Entergy Arkansas	intends	to	return	unprotected	excess	accumulated	deferred	income	taxes	as	expeditiously	as	possible,	subject	to	a	subsequent	request	to be	made	by	Entergy	Arkansas	and	approval	by	the	APSC.

After	enactment	of	the	Tax	Cuts	and	Jobs	Act	the	LPSC	passed	an	agenda	item	requiring	utilities,	including	Entergy	Louisiana,	to	file reports	regarding	certain	effects	of	the	Act.	Entergy	Louisiana	responded	to	the	directive	and	stated	in	its	response	that	it	is	working	with	the LPSC	staff	and	other	interested	parties	to	extend	its	formula	rate	plan	such	that	its	next	base	rate	change	will	occur	effective	September	2018,	or it	would	file	a	base	rate	case.	Entergy	Louisiana	went	on	to	state	that	if	the	formula	rate	plan	is	extended	Entergy	Louisiana's	next	adjustment	of rates	will	reflect	the	new	21%	federal	corporate	income	tax	rate.	Entergy	Louisiana	stated	that	it	is	working	with	the	LPSC	staff	and	interested parties	to	determine	when	the	tax	rate	reduction	will	be	reflected	in	rates,	along	with	when	and	how	the	excess	accumulated	deferred	income taxes	will	be	reflected	in	rates,	and	how	certain	tax	sharing	agreement	customer	credits	will	be	adjusted.	On	February	21,	2018,	the	LPSC	issued a	special	order	requiring	that	all	LPSC-jurisdictional	utilities,	beginning	as	of	January	1,	2018,	record	as	a	regulatory	liability	(deferred	liability) the	amount	required	to	reflect	the	reduction	in	the	federal	corporate	income	tax	rate	from	35%	to	21%	and	the	associated	savings	in	excess accumulated	deferred	income	taxes	until	such	time	as	its	rates	are	changed	by	the	LPSC	to	reflect	these	federal	tax	savings.	In	the	same	special order,	the	LPSC	also	initiated	a	new	rulemaking	docket	to	consider	these	issues	and	the	appropriate	manner	in	which	to	flow	through	the	benefits to	Louisiana	customers	and	to	provide	an	opportunity	for	discovery	and	comments	of	jurisdictional	utilities	and	other	interested	stakeholders.	The rulemaking	further	requires	the	LPSC	staff	to	report	back	to	the	LPSC	as	soon	as	practicable	and	preferably	by	the	March	21,	2018,	LPSC Business	and	Executive	Session	with	recommendations	as	to	how	the	federal	tax-related	benefits	will	be	flowed	through	to	Louisiana	customers.

After	enactment	of	the	Tax	Cuts	and	Jobs	Act	the	MPSC	ordered	utilities,	including	Entergy	Mississippi,	that	operate	under	a	formula	rate plan	to	file	a	description	by	February	26,	2018,	of	how	the	Act	will	be	reflected	in	the	formula	rate	plan	under	which	the	utility	operates.	In addition	to	the	description	that	is	due	February	26,	2018,	Entergy	Mississippi's	formula	rate	plan	2018	test	year	filing	is	scheduled	to	be	filed	by March	15,	2018.

After	enactment	of	the	Tax	Cuts	and	Jobs	Act	the	City	Council	passed	a	resolution	ordering	Entergy	New	Orleans	to,	effective	January	1, 2018,	record	deferred	regulatory	liabilities	to	account	for	the	Act's	effect	on	Entergy	New	Orleans's	revenue	requirement	and	to	make	a	filing	by mid-March	2018	regarding	the	Act's	effects	on	Entergy	New	Orleans's	operating	income	and	rate	base	and	potential	mechanisms	for	customers	to receive	benefits	of	the	Act.	The	resolution	also	directed	Entergy	New	Orleans	to	request	that	Entergy	Services	file	with	the	FERC	for	revisions	of the	Unit	Power	Sales	Agreement	and	MSS-4	replacement	tariffs	to	address	the	return	of	excess	accumulated	deferred	income	taxes.	Entergy	plans to	make	such	filings	with	the	FERC	by	the	end	of	March	2018.

After	enactment	of	the	Tax	Cuts	and	Jobs	Act	the	PUCT	issued	an	order	requiring	most	utilities,	including	Entergy	Texas,	beginning January	25,	2018,	to	record	a	regulatory	liability	for	the	difference	between	revenues	collected	under	existing	rates	and	revenues	that	would	have been	collected	had	existing	rates	been	set	using	the	new	federal	income	tax	rates	and	also	for	the	balance	of	excess	accumulated	deferred	income taxes.	The	order	also	directs	the	PUCT	staff	to	investigate	each	investor-owned	utility	on	a	case-by-case	basis	to	determine	the	appropriate mechanism	to	adjust	its	rates	to	reflect	the	changes	under	the	Act.	In	both	a	memorandum	issued	prior	to	the	open	meeting	when	the	order	was discussed	and	during	the	discussions	at	the	open	meeting	discussing	the	order,	the	PUCT	indicated	that	it	would	consider	utility	earnings	in determining	the	treatment	of	the	liability	and	the	effects	of	the	Act.	Entergy	Texas	had	previously	provided	information	to	the	PUCT	Staff	in	the docket	and	stated	that	it	expects	the	PUCT	to	address	the	lower	tax	expense	as	part	of	Entergy	Texas's	rate	case	expected	to	be	filed	in	May	2018. Entergy	Texas	also	stated	that	it	would	be	inappropriate	for	the	PUCT	to	require	a	refund	of	the	reduction	in	income	tax	expense	in	2018	resulting from	the	Act	on	a	retroactive	basis	and	without	a	comprehensive	review	of	Entergy	Texas's	cost	of	service	and	earned	return	on	equity.	 In	a subsequent	order	issued	following	the	February	2018	open	meeting,	the	PUCT	clarified	that	carrying	costs	need	not	be	recorded	as	part	of	the regulatory	liability.

The	Registrant	Subsidiaries	will	continue	to	work	with	their	respective	regulators	to	determine	the	appropriate	path	forward	in	each jurisdiction	regarding	the	effects	of	the	Act.

# Fuel	and	purchased	power	cost	recovery

Entergy	Arkansas,	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,	2017	 and	2016	that	Entergy expects	to	recover	(or	return	to	customers)	through	fuel	mechanisms,	subject	to	subsequent	regulatory	review.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| Entergy\tArkansas\t(a) | $130.4 | $163.6 |
| Entergy\tLouisiana\t(b) | $96.7 | $119.9 |
| Entergy\tMississippi | $32.4 | $7.0 |
| Entergy\tNew\tOrleans\t(b) | ($3.7) | $8.9 |
| Entergy\tTexas | ($67.3) | ($54.5) |

(a) Includes	$67.1	million	in	2017	and	$66.9	million	in	2016	of	fuel	and	purchased	power	costs,	which	do	not	currently	earn	a	return	on investment	and	whose	recovery	periods	are	indeterminate	but	are	expected	to	be	recovered	over	a	period	greater	than	twelve	months.

(b) Includes	$168.1	million	in	each	year	for	Entergy	Louisiana	and	$4.1	million	in	each	year	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	recovered	over	a	period	greater	than	twelve	months.

# 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	the	costs	from	customers	over twelve	months.

In	 May	 2014,	 Entergy	Arkansas	 filed	 its	 annual	 redetermination	 of	 the	 production	 cost	 allocation	 rider	 to	 recover	 the	 $3	 million unrecovered	retail	balance	as	of	December	31,	2013	and	the	$67.8	million	System	Agreement	bandwidth	remedy	payment	made	in	May	2014	as	a result	of	the	compliance	filing	pursuant	to	the	FERC's	February	2014	orders	related	to	the	bandwidth	payments/receipts	for	the	June	-	December 2005	period.	In	January	2015	the	APSC	issued	an	order	approving	Entergy	Arkansas's	request	for	recovery	of	the	$3	million	under-recovered amount	based	on	the	true-up	of	the	production	cost	allocation	rider	and	the	$67.8	million	May	2014	System	Agreement	bandwidth	remedy payment	subject	to	refund	with	interest,	with	recovery	of	these	payments	concluding	with	the	last	billing	cycle	in	December	2015.	The	APSC	also found	that	Entergy	Arkansas	is	entitled	to	carrying	charges	pursuant	to	the	current	terms	of	the	production	cost	allocation	rider.	Entergy	Arkansas made	its	compliance	filing	pursuant	to	the	order	in	January	2015	and	the	APSC	issued	its	approval	order,	also	in	January	2015.	The	redetermined rate	went	into	effect	with	the	first	billing	cycle	of	February	2015.

In	May	2015,	Entergy	Arkansas	filed	its	annual	redetermination	of	the	production	cost	allocation	rider,	which	included	a $38	million payment	made	by	Entergy	Arkansas	as	a	result	of	the	FERC's	February	2014	order	related	to	the	comprehensive	bandwidth	recalculation	for calendar	year	2006,	2007,	and	2008	production	costs.	The	redetermined	rate	for	the	2015	production	cost	allocation	rider	update	was	added	to	the redetermined	rate	from	the	2014	production	cost	allocation	rider	update	and	the	combined	rate	was	effective	with	the	first	billing	cycle	of	July 2015.	This	combined	rate	was	effective	through	December	2015.	The	collection	of	the	remainder	of	the	redetermined	rate	for	the	2015	production cost	allocation	rider	update	continued	through	June	2016.

In	May	2016,	Entergy	Arkansas	filed	its	annual	redetermination	pursuant	to	the	production	cost	allocation	rider,	which	reflected	recovery of	 the	 production	 cost	 allocation	 rider	 true-up	 adjustment	 of	 the	 2014	 and	 2015	 unrecovered	 retail	 balance	 in	 the	 amount	 of	$1.9	 million. Additionally,	the	redetermined	rates	reflected	the	recovery	of	a	$1.9	million	System	Agreement	bandwidth	remedy	payment	resulting	from	a compliance	filing	pursuant	to	the	FERC's	December	2015	order	related	to	test	year	2009	production	costs.	The	rates	for	the	2016	production	cost allocation	rider	update	became	effective	with	the	first	billing	cycle	of	July	2016,	and	the	rates	were	effective	through	June	2017.

In	May	2017,	Entergy	Arkansas	filed	its	annual	redetermination	pursuant	to	the	production	cost	allocation	rider,	which	reflected	a	credit amount	 of	$0.3	million	resulting	from	a	compliance	filing	pursuant	to	the	FERC's	September	2016	order.	Additionally,	the	redetermined	rate reflected	recovery	of	the	production	cost	allocation	rider	true-up	adjustment	of	the	2016	unrecovered	retail	balance	in	the	amount	of	$0.3	million. Because	of	the	small	effect	of	the	2017	production	cost	allocation	rider	update,	Entergy	Arkansas	proposed	to	reduce	the	effective	period	of	the update	to	one	month,	July	2017.	After	the	one	month	collection	period,	rates	were	set	to	zero	for	all	rate	classes	for	the	period	August	2017 through	June	2018.

# 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	 January	 2014,	 Entergy	Arkansas	 filed	 a	 motion	 with	 the	APSC	 relating	 to	 its	 redetermination	 of	 its	 energy	 cost	 rate	 that	 was subsequently	filed	in	March	2014.	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	redetermination	of	its	2014	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.	In	July 2017,	Entergy	Arkansas	filed	for	a	change	 in	rates	pursuant	 to	 its	formula	rate	plan	rider.	In	that	docket,	the	APSC	approved	a	settlement agreement	agreed	upon	by	the	parties,	including	a	provision	that	requires	Entergy	Arkansas	to	initiate	a	docket	for	the	purpose	of	recovering	funds currently	withheld	from	rates	and	related	to	the	stator	incident,	including	the	$65.9	million	of	deferred	fuel	and	purchased	energy	costs	previously noted,	subject	to	certain	timelines	and	conditions	set	forth	in	the	settlement	agreement.	See	the	"ANO	Damage,	Outage,	and	NRC	Reviews" section	in	Note	8	to	the	financial	statements	for	further	discussion	of	the	ANO	stator	incident.

In	March	2017,	Entergy	Arkansas	filed	its	annual	redetermination	of	its	energy	cost	rate	pursuant	to	the	energy	cost	recovery	rider,	which reflected	an	increase	in	the	rate	from	$0.01164	per	kWh	to	$0.01547	per	kWh.	The	APSC	staff	filed	testimony	in	March	2017	recommending	that the	 redetermined	 rate	 be	 implemented	 with	 the	 first	 billing	 cycle	 of	April	 2017	 under	 the	 normal	 operation	 of	 the	 tariff.	Accordingly,	 the redetermined	rate	went	into	effect	on	March	31,	2017	pursuant	to	the	tariff.	In	July	2017	the	Arkansas	Attorney	General	requested	additional information	to	support	certain	of	the	costs	included	in	Entergy	Arkansas's	2017	energy	cost	rate	redetermination.

Entergy	Louisiana	recovers	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	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	April	2010	the	LPSC	authorized	its	staff	to	initiate	an	audit	of	Entergy	Louisiana's	fuel	adjustment	clause	filings.		The	audit	included	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	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.	In	October	2016	the	LPSC	staff	filed	testimony	affirming	the	recommendation	in	its	audit	report	on	the	lone	remaining	issue	that nuclear	dry	fuel	storage	costs	should	be	realigned	to	base	rates.	The	parties	agreed	to	remove	that	remaining	issue	to	a	separate	docket	because	the same	issue	was	outstanding	in	the	Entergy	Gulf	States	Louisiana	audit	for	the	same	time	period.	In	November	2016	the	LPSC	approved	the resolution	of	this	audit	and	the	creation	of	a	new	docket	for	the	resolution	of	the	proper	method	of	recovery	for	nuclear	dry	fuel	storage	costs.	In December	2016	the	LPSC	opened	a	new	docket	in	order	to	resolve	the	issue	regarding	the	proper	methodology	for	the	recovery	of	nuclear	dry	fuel storage	costs.	In	October	2017	the	LPSC	approved	the	continued	recovery	of	the	nuclear	dry	fuel	storage	costs	through	the	fuel	adjustment	clause, resolving	the	open	issue	in	the	audit.

In	December	2011	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	2005	through	2009.		In	March	2016	the	LPSC	staff	consultant	issued	its	audit	report.	In	its	report,	the	LPSC	staff consultant	 recommended	 that	 Entergy	 Louisiana	 refund	 approximately	$8.6	 million,	 plus	 interest,	 to	 customers	 and	 realign	 the	 recovery	 of approximately	$12.7	million	from	Entergy	Gulf	States	Louisiana's	fuel	adjustment	clause	to	base	rates.	In	September	2016	the	LPSC	staff	filed testimony	 stating	 that	 it	 was	 no	 longer	 recommending	 a	 disallowance	 of	$3.4	 million	 of	 the	$8.6	 million	 discussed	 above,	 but	 otherwise maintained	positions	from	its	report.	Subsequently,	the	parties	entered	into	a	settlement,	which	was	approved	by	the	LPSC	in	November	2016. The	settlement	recognized	the	dry	cask	storage	recovery	method	issue,	which	was	addressed	in	the	separate	proceeding	approved	by	the	LPSC	in October	2017,	provided	for	a	refund	of	$5	million,	which	was	made	to	legacy	Entergy	Gulf	States	Louisiana	customers	in	December	2016,	and resolved	all	other	issues	raised	in	the	audit.

In	July	2014	the	LPSC	authorized	its	staff	to	initiate	an	audit	of	Entergy	Gulf	States	Louisiana's	fuel	adjustment	clause	filings.	The	audit includes	a	review	of	the	reasonableness	of	charges	flowed	by	Entergy	Gulf	States	Louisiana	through	its	fuel	adjustment	clause	for	the	period	from 2010	through	2013.	Discovery	commenced	in	July	2015.	No	report	of	audit	has	been	issued.

In	July	2014	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	by	Entergy	Louisiana	through	its	fuel	adjustment	clause	for	the	period	from	2010	through	2013. Discovery	commenced	in	July	2015.	No	report	of	audit	has	been	issued.

In	June	2016	the	LPSC	staff	provided	notice	of	audits	of	Entergy	Louisiana's	fuel	adjustment	clause	filings	and	purchased	gas	adjustment clause	filings.	In	recognition	of	the	business	combination	that	occurred	in	2015,	the	audit	notice	was	issued	to	Entergy	Louisiana	and	will	also include	a	review	of	charges	to	legacy	Entergy	Gulf	States	Louisiana	customers	prior	to	the	business	combination.	The	audit	includes	a	review	of the	reasonableness	of	charges	flowed	through	Entergy	Louisiana's	fuel	adjustment	clause	for	the	period	from	2014	through	2015	and	charges flowed	through	Entergy	Louisiana's	purchased	gas	adjustment	clause	for	the	period	from	2012	through	2015.	Discovery	commenced	in	March 2017.	No	report	of	audit	has	been	issued.

Due	to	higher	fuel	costs	for	the	operating	month	of	January	2018	resulting	in	part	from	recent	cold	weather,	higher	Henry	Hub	prices,	and an	increase	in	total	fuel	and	purchased	power	costs,	Entergy	Louisiana	plans	to	cap	the	average	fuel	adjustment	charge	to	be	billed	in	March	2018 at	$0.03060	per	kWh	and	to	defer	billing	of	all	fuel	costs	in	excess	of	the	capped	amounts	by	including	such	costs	in	the	over-	or	under-recovery account.

# Entergy	Mississippi

Entergy	Mississippi's	rate	schedules	include	an	energy	cost	recovery	rider	that	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.

Entergy	Mississippi	had	a	deferred	fuel	over-recovery	balance	of	$58.3	million	as	of	May	31,	2015,	along	with	an	under-recovery	balance of	$12.3	million	under	the	power	management	rider.	Pursuant	to	those	tariffs,	in	July	2015,	Entergy	Mississippi	filed	for	interim	adjustments	under both	the	energy	cost	recovery	rider	and	the	power	management	rider	to	flow	through	to	customers	the	approximately	$46	million	net	over- recovery	over	a	six-month	period.	In	August	2015,	the	MPSC	approved	the	interim	adjustments	effective	with	September	2015	bills.	In	November 2015,	Entergy	Mississippi	filed	its	annual	redetermination	of	the	annual	factor	to	be	applied	under	the	energy	cost	recovery	rider.	The	calculation of	the	annual	factor	included	a	projected	over-recovery	balance	of	$48	million	projected	through	January	31,	2016.	In	January	2016	the	MPSC approved	the	redetermined	annual	factor	effective	February	1,	2016.	The	MPSC	further	ordered,	however,	that	due	to	the	significant	change	in natural	gas	price	forecasts	since	Entergy	Mississippi's	filing	in	November	2015	Entergy	Mississippi	should	file	a	revised	fuel	factor	with	the MPSC	no	later	than	February	1,	2016.	Pursuant	to	that	order,	Entergy	Mississippi	submitted	a	revised	fuel	factor.	Additionally,	because	Entergy Mississippi's	projected	over-recovery	balance	for	the	period	ending	January	31,	2016	was	$68	million,	in	February	2016,	Entergy	Mississippi filed	for	another	interim	adjustment	to	the	energy	cost	factor	effective	April	2016	to	flow	through	to	customers	the	projected	over-recovery balance	over	a	six-month	period.	That	interim	adjustment	was	approved	by	the	MPSC	in	February	2016	effective	for	April	2016	bills.

In	November	2016,	Entergy	Mississippi	filed	its	annual	redetermination	of	the	annual	factor	to	be	applied	under	the	energy	cost	recovery rider.	The	calculation	of	the	annual	factor	included	an	over-recovery	of	less	than	$2	million	as	of	September	30,	2016.	In	January	2017	the	MPSC approved	the	annual	factor	effective	with	February	2017	bills.	Also	in	January	2017	the	MPSC	certified	to	the	Mississippi	Legislature	the	audit reports	of	its	independent	auditors	for	the	fuel	year	ending	September	30,	2016.	In	its	order,	the	MPSC	expressly	reserved	the	right	to	review	and determine	the	recoverability	of	any	and	all	purchased	power	expenditures	made	during	fiscal	year	2016.	The	MPSC	hired	independent	auditors	to conduct	an	annual	operations	audit	and	a	financial	audit.	The	independent	auditors

issued	their	audit	reports	in	December	2017.	The	audit	reports	included	several	recommendations	for	action	by	Entergy	Mississippi	but	did	not recommend	any	cost	disallowances.	In	January	2018	the	MPSC	certified	the	audit	reports	to	the	Mississippi	Legislature.	In	November	2017	the Public	Utilities	Staff	separately	engaged	a	consultant	to	review	the	outage	at	the	Grand	Gulf	Nuclear	Station	that	began	in	2016.	The	review	is currently	in	progress.

In	November	2017,	Entergy	Mississippi	filed	its	annual	redetermination	of	the	annual	factor	to	be	applied	under	the	energy	cost	recovery rider.	The	 calculation	 of	 the	 annual	 factor	 included	 an	 under-recovery	 of	 approximately	$61.5	 million	 as	 of	 September	 30,	 2017.	Entergy Mississippi	proposed	a	two-tiered	energy	cost	factor	designed	to	promote	overall	rate	stability	throughout	2018	particularly	during	the	summer months.	In	January	2018	the	MPSC	approved	the	proposed	energy	cost	factors	effective	for	February	2018	bills.

# 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.

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	considered	"mass	actions"	under	the	Class	Action	Fairness	Act,	so	as	to	establish	federal	subject	matter	jurisdiction. One	day	later	the	Attorney	General	renewed	his	motion	to	remand	the	Entergy	case	back	to	state	court,	citing	the	U.S.	Supreme	Court's	decision. The	defendant	Entergy	companies	responded	to	that	motion	reiterating	the	additional	grounds	asserted	for	federal	question	jurisdiction,	and	the District	Court	held	oral	argument	on	the	renewed	motion	to	remand	in	February	2014.	In	April	2015	the	District	Court	entered	an	order	denying the	renewed	motion	to	remand,	holding	that	the	District	Court	has	federal	question	subject	matter	jurisdiction.	The	Attorney	General	appealed	to the	U.S.	Fifth	Circuit	Court	of	Appeals	the	denial	of	the	motion	to	remand.	In	July	2015	the	Fifth	Circuit	issued	an	order	denying	the	appeal,	and the	Attorney	General	subsequently	filed	a	petition	for	rehearing	of	the	request	for	interlocutory	appeal,	which	was	also	denied.	In	December	2015 the	District	Court	ordered	that	the	parties	submit	to	the	court	undisputed	and	disputed	facts	that	are	material	to	the	Entergy	defendants'	motion	for judgment	on	the	pleadings,	as	well	as	supplemental	briefs	regarding	the	same.	Those	filings	were	made	in	January	2016.

In	September	2016	the	Attorney	General	filed	a	mandamus	petition	with	the	U.S.	Fifth	Circuit	Court	of	Appeals	in	which	the	Attorney General	asked	the	Fifth	Circuit	to	order	the	chief	judge	to	reassign	this	case	to	another	judge.	In	September	2016	the	District	Court	denied	the Entergy	companies'	motion	for	judgment	on	the	pleadings.	The	Entergy	companies	filed	a	motion	seeking	to	amend	the	District	Court's	order denying	the	Entergy	companies'	motion	for	judgment	on	the	pleadings	and	allowing	an	interlocutory	appeal.	In	October	2016	the	Fifth	Circuit granted	the	Attorney	General's	motion	for	writ	of	mandamus	and	directed	the	chief	judge	to	assign	the	case	to	a	new	judge.	The	case	was reassigned	in	October	2016.	In	January	2017	the	District	Court	denied	the	Entergy	companies'	motion	to	amend	the	order	denying	the	motion	for judgment	on	the	pleadings.	In	June	2017	the	District	Court	issued	a	case	management	order	setting	a	trial	date	in	November	2018.	Discovery	is currently	in	progress.

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.

Due	to	higher	fuel	costs	associated	in	part	with	the	extended	Grand	Gulf	outage	and	the	partially	simultaneous	Union	Power	Block	1 planned	outage,	for	the	December	2016,	January	2017,	and	February	2017	billing	months,	the	City	Council	authorized	Entergy	New	Orleans	to cap	the	fuel	adjustment	charge	billed	to	customers	at	$0.035	per	kWh	and	to	defer	billing	of	all	fuel	costs	in	excess	of	the	capped	amount	by including	such	costs	in	the	over-	or	under-recovery	account.

Due	to	higher	fuel	costs	for	the	operating	month	of	January	2018	resulting	in	part	from	recent	cold	weather,	higher	Henry	Hub	prices,	and an	increase	in	total	fuel	and	purchased	power	costs	associated	in	part	with	certain	plant	outages,	Entergy	New	Orleans	has	proposed	to	cap	the	fuel adjustment	charge	to	be	billed	in	March	2018	to	non-transmission	Entergy	New	Orleans	legacy	customers	and	Entergy	New	Orleans	Algiers customers	at	$0.035323	per	kWh	and	$0.025446	per	kWh,	respectively.	Entergy	New	Orleans	has	also	proposed	to	cap	the	fuel	adjustment	charge to	be	billed	in	March	2018	for	Entergy	New	Orleans	legacy	transmission	customers	at	$0.034609	per	kWh	and	to	defer	billing	of	all	fuel	costs	in excess	of	the	capped	amount	by	including	such	costs	in	the	over-	or	under-recovery	account.

# 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	August	2014,	Entergy	Texas	filed	an	application	seeking	PUCT	approval	to	implement	an	interim	fuel	refund	of	approximately $24.6 million	for	over-collected	fuel	costs	incurred	during	the	months	of	November	2012	through	April	2014.	This	refund	resulted	from	(i)	applying $48.6	million	in	bandwidth	remedy	payments	that	Entergy	Texas	received	in	May	2014	related	to	the	June	-	December	2005	period	to	Entergy Texas's	$8.7	million	under-recovered	fuel	balance	as	of	April	30,	2014	and	(ii)	netting	that	fuel	balance	against	the	 $15.3	million	bandwidth remedy	payment	that	Entergy	Texas	made	related	to	calendar	year	2013	production	costs.	Also	in	August	2014,	Entergy	Texas	filed	an	unopposed motion	for	interim	rates	to	implement	these	refunds	for	most	customers	over	a	two-month	period	commencing	with	September	2014.	The	PUCT issued	its	order	approving	the	interim	relief	in	August	2014	and	Entergy	Texas	completed	the	refunds	in	October	2014. 	Parties	intervened	in	this matter,	and	all	parties	agreed	that	the	proceeding	should	be	bifurcated	such	that	the	proposed	interim	refund	would	become	final	in	a	separate proceeding,	which	refund	was	approved	by	the	PUCT	in	March	2015.			In	July	2015	certain	parties	filed	briefs	in	the	open	proceeding	asserting that	Entergy	Texas	should	refund	to	retail	customers	an	additional	$10.9	million	in	bandwidth	remedy	payments	Entergy	Texas	received	related	to calendar	year	2006	production	costs.		In	October	2015	an	ALJ	issued	a	proposal	for	decision	recommending	that	the	additional	$10.9	million	in bandwidth	remedy	payments	be	refunded	to	retail	customers.	In	January	2016	the	PUCT	issued	its	order	affirming	the	ALJ's	recommendation,	and Entergy	Texas	filed	a	motion	for	rehearing	of	the	PUCT's	decision,	which	the	PUCT	denied.	In	March	2016,	Entergy	Texas	filed	a	complaint	in Federal	District	Court	for	the	Western	District	of	Texas	and	a	petition	in	the	Travis	County	(State)	District	Court	appealing	the	PUCT's	decision. The	pending	appeals	did	not	stay	the	PUCT's	decision.	In	April	2016,	Entergy	Texas	filed	with	the	PUCT	an	application	to	refund	to	customers approximately	$56.2	million.	The	refund	resulted	from	(i)	$41.8	million	of	fuel	cost	recovery	over-collections	through	February	2016,	(ii)	the $10.9	million	in	bandwidth	remedy	payments,

discussed	above,	that	Entergy	Texas	received	related	to	calendar	year	2006	production	costs,	and	(iii)	 $3.5	million	in	bandwidth	remedy	payments that	Entergy	Texas	received	related	to	2006-2008	production	costs.	In	June	2016,	Entergy	Texas	filed	an	unopposed	settlement	agreement	that added	additional	over-recovered	fuel	costs	for	the	months	of	March	and	April	2016.	The	settlement	resulted	in	a	$68	million	 refund.	The	ALJ approved	the	refund	on	an	interim	basis	to	be	made	to	most	customers	over	a	four-month	period	beginning	with	the	first	billing	cycle	of	July	2016. In	July	2016	the	PUCT	issued	an	order	approving	the	interim	refund.	The	federal	appeal	of	the	PUCT's	January	2016	decision	was	heard	in December	2016,	and	the	Federal	District	Court	granted	Entergy	Texas's	requested	relief.	In	January	2017	the	PUCT	and	an	intervenor	filed petitions	for	appeal	to	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	of	the	Federal	District	Court	ruling.	Oral	argument	was	held	before	the	U.S. Court	of	Appeals	for	the	Fifth	Circuit	in	February	2018,	and	a	decision	is	pending.	The	State	District	Court	appeal	of	the	PUCT's	January	2016 decision	also	remains	pending.

In	July	2016,	Entergy	Texas	filed	an	application	to	reconcile	its	fuel	and	purchased	power	costs	for	the	period	April	1,	2013	through March	31,	2016.	Under	a	recent	PUCT	rule	change,	a	fuel	reconciliation	is	required	to	be	filed	at	least	once	every	three	years	and	outside	of	a	base rate	case	filing.	During	the	reconciliation	period,	Entergy	Texas	incurred	approximately	$1.77	billion	in	Texas	jurisdictional	eligible	fuel	and purchased	power	expenses,	net	of	certain	revenues	credited	to	such	expenses	and	other	adjustments.	Entergy	Texas	estimated	an	over-recovery balance	of	approximately	$19.3	million,	including	interest,	which	Entergy	Texas	requested	authority	to	carry	over	as	the	beginning	balance	for	the subsequent	reconciliation	period	beginning	Apri1	2016.	Entergy	Texas	also	noted,	however,	that	the	estimated	$19.3	million	over	collection	was being	refunded	to	customers	as	a	portion	of	the	interim	fuel	refund	beginning	with	the	first	billing	cycle	of	July	2016,	discussed	above.	Entergy Texas	also	requested	a	prudence	finding	for	each	of	the	fuel-related	contracts	and	arrangements	entered	into	or	modified	during	the	reconciliation period	that	have	not	been	reviewed	by	the	PUCT	in	a	prior	proceeding.	In	December	2016,	Entergy	Texas	entered	into	a	stipulation	and	settlement agreement	resulting	in	a	$6	million	disallowance	not	associated	with	any	particular	issue	raised	and	a	refund	of	the	over-recovery	balance	of	 $21 million	as	of	November	30,	2016,	to	most	customers	beginning	April	2017	through	June	2017.	This	settlement	was	developed	concurrently	with the	stipulation	and	settlement	agreement	in	the	2016	transmission	cost	recovery	factor	rider	amendment	discussed	below,	and	the	terms	and conditions	in	both	settlements	are	interdependent.	The	fuel	reconciliation	settlement	was	approved	by	the	PUCT	in	March	2017	and	the	refunds were	made.

In	June	2017,	Entergy	Texas	filed	an	application	for	a	fuel	refund	of	approximately	 $30.7	million	for	the	months	of	December	2016 through	April	2017.	For	most	customers,	the	refunds	flowed	through	bills	for	the	months	of	July	2017	through	September	2017.	The	fuel	refund was	approved	by	the	PUCT	in	August	2017.

In	December	2017,	Entergy	Texas	filed	an	application	for	a	fuel	refund	of	approximately	 $30.5	million	for	the	months	of	May	2017 through	October	2017.	Also	in	December	2017,	the	PUCT's	ALJ	approved	the	refund	on	an	interim	basis.	For	most	customers,	the	refunds	flowed through	bills	beginning	January	2018	and	will	continue	through	March	2018.	A	final	decision	in	this	matter	remains	pending.

# Retail	Rate	Proceedings

# Filings	with	the	APSC	(Entergy	Arkansas)

2015	Base	Rate	Filing

In	April	2015,	Entergy	Arkansas	filed	with	the	APSC	for	a	general	change	in	rates,	charges,	and	tariffs.	 The	filing	notified	the	APSC	of Entergy	Arkansas's	intent	to	implement	a	forward	test	year	formula	rate	plan	pursuant	to	Arkansas	legislation	passed	in	2015,	and	requested	a retail	rate	increase	of	$268.4	million,	with	a	net	increase	in	revenue	of	$167	million.	The	filing	requested	a	10.2%	return	on	common	equity.	In September	2015	the	APSC	staff	and	intervenors	filed	direct	testimony,	with	the	APSC	staff	recommending	a	revenue	requirement	of	$217.9 million	and	a	9.65%	return	on	common	equity.	In	December	2015,	Entergy	Arkansas,	the	APSC	staff,	and	certain	of	the	intervenors

in	the	rate	case	filed	with	the	APSC	a	joint	motion	for	approval	of	a	settlement	of	the	case	that	proposed	a	retail	rate	increase	of	approximately $225	million	with	a	net	increase	in	revenue	of	approximately	$133	million;	an	authorized	return	on	common	equity	of	9.75%;	and	a	formula	rate plan	tariff	that	provides	a	+/-	50	basis	point	band	around	the	9.75%	allowed	return	on	common	equity.	A	significant	portion	of	the	rate	increase	is related	to	Entergy	Arkansas's	acquisition	in	March	2016	of	Union	Power	Station	Power	Block	2	for	a	base	purchase	price	of	$237	million.	The settlement	agreement	also	provided	for	amortization	over	a	10-year	period	of	$7.7	million	of	previously-incurred	costs	related	to	ANO	post- Fukushima	compliance	and	$9.9	million	of	previously-incurred	costs	related	to	ANO	flood	barrier	compliance.	A	settlement	hearing	was	held	in January	 2016.	In	February	2016	the	APSC	approved	the	settlement	with	one	exception	that	reduced	the	retail	rate	increase	proposed	in	the settlement	 by	$5	million.	The	settling	parties	agreed	to	the	APSC	modifications	in	February	2016.	The	new	rates	were	effective	February	24, 2016	and	began	billing	with	the	first	billing	cycle	of	April	2016.	In	March	2016,	Entergy	Arkansas	made	a	compliance	filing	regarding	the	new rates	that	included	an	interim	base	rate	adjustment	surcharge,	effective	with	the	first	billing	cycle	of	April	2016,	to	recover	the	incremental	revenue requirement	for	the	period	February	24,	2016	through	March	31,	2016.	The	interim	base	rate	adjustment	surcharge	was	designed	to	recover	a	total of	$21.1	million	over	the	nine-month	period	from	April	2016	through	December	2016.

# 2016	Formula	Rate	Plan	Filing

In	July	2016,	Entergy	Arkansas	filed	with	the	APSC	its	2016	formula	rate	plan	filing	showing	Entergy	Arkansas's	projected	earned	return on	common	equity	for	the	twelve	months	ended	December	31,	2017	test	period	to	be	below	the	formula	rate	plan	bandwidth.	The	filing	requested a	$67.7	million	revenue	requirement	increase	to	achieve	Entergy	Arkansas's	target	earned	return	on	common	equity	of	 9.75%.	In	October	2016, Entergy	Arkansas	filed	with	the	APSC	revised	formula	rate	plan	attachments	with	an	updated	request	for	a	$54.4	million	revenue	requirement increase	based	on	acceptance	of	certain	adjustments	and	recommendations	made	by	 the	APSC	staff	and	other	 intervenors,	as	well	as	 three additional	adjustments	identified	as	appropriate	by	Entergy	Arkansas.	In	November	2016	a	hearing	was	held	and	the	APSC	issued	an	order directing	 the	parties	 to	brief	certain	 issues.	In	December	2016	 the	APSC	approved	 the	settlement	agreement	and	 the	$54.4	 million	 revenue requirement	increase	with	approximately	$25	million	of	the	$54.4	million	revenue	requirement	subject	to	possible	future	adjustment	and	refund	to customers	 with	 interest.	The	APSC	requested	supplemental	 information	for	some	of	Entergy	Arkansas's	requested	nuclear	expenditures.	In December	2016	the	APSC	approved	Entergy	Arkansas's	formula	rate	plan	compliance	tariff,	and	the	rates	became	effective	with	the	first	billing cycle	of	January	2017.	In	April	2017,	Entergy	Arkansas	filed	a	motion	consented	to	by	all	parties	requesting	that	it	be	permitted	to	submit	the supplemental	information	requested	by	the	APSC	in	conjunction	with	its	2017	formula	rate	plan	filing,	which	was	subsequently	made	in	July	2017 and	is	discussed	below.	In	May	2017	the	APSC	approved	the	joint	motion	and	proposal	to	review	Entergy	Arkansas's	supplemental	information on	a	concurrent	schedule	with	the	2017	formula	rate	plan	filing.	In	October	2017,	Entergy	Arkansas	and	the	parties	to	the	proceeding	filed	a	joint motion	to	approve	a	unanimous	settlement	agreement	resolving	all	issues	in	the	docket	and	providing	for	recovery	of	the	2017	and	2018	nuclear costs.	In	December	2017	the	APSC	approved	the	settlement	agreement	and	recovery	of	the	2017	and	2018	nuclear	costs.

In	July	2017,	Entergy	Arkansas	filed	with	the	APSC	its	2017	formula	rate	plan	filing	showing	Entergy	Arkansas's	projected	earned	return on	common	equity	for	the	twelve	months	ended	December	31,	2018	test	period	to	be	below	the	formula	rate	plan	bandwidth.		The	filing	projected a	$129.7	 million	 revenue	 requirement	 increase	 to	 achieve	 Entergy	Arkansas's	 target	 earned	 return	 on	 common	 equity	 of	 9.75%.	 	 Entergy Arkansas's	 formula	 rate	 plan	 is	 subject	 to	 a	four	percent	annual	revenue	constraint	and	 the	projected	annual	revenue	requirement	 increase exceeded	the	four	percent,	resulting	in	a	proposed	increase	for	the	2017	formula	rate	plan	of	$70.9	million.	In	October	2017,	Entergy	Arkansas filed	with	the	APSC	revised	formula	rate	plan	attachments	that	projected	a	$126.2	million	revenue	requirement	increase	based	on	acceptance	of certain	adjustments	and	recommendations	made	by	the	APSC	staff	and	other	intervenors.	The	revised	formula	rate	plan	filing	included	a	proposed $71.1	million	revenue	requirement	increase	based	on	a	revision	to	the	four	percent	constraint	calculation.	In	October	2017,	Entergy	Arkansas	and the	parties	to	the	proceeding	filed	a	joint	motion	to	approve	a	unanimous	settlement	agreement	resolving	all	issues	in	the	docket	and

providing	for	recovery	of	the	2017	and	2018	nuclear	costs.	In	December	2017	the	APSC	approved	the	settlement	agreement	and	the	$71.1	million revenue	requirement	increase,	as	well	as	Entergy	Arkansas's	formula	rate	plan	compliance	tariff,	and	the	rates	became	effective	with	the	first billing	cycle	of	January	2018.

# Internal	Restructuring

In	November	2017,	Entergy	Arkansas	filed	an	application	with	the	APSC	seeking	authorization	to	undertake	a	restructuring	that	would result	in	the	transfer	of	substantially	all	of	the	assets	and	operations	of	Entergy	Arkansas	to	a	new	entity,	which	would	ultimately	be	owned	by	an existing	Entergy	subsidiary	holding	company.	The	restructuring	is	subject	to	regulatory	review	and	approval	by	the	APSC,	the	FERC,	and	the NRC.	Entergy	Arkansas	also	filed	a	notice	with	the	Missouri	Public	Service	Commission	in	December	2017	out	of	an	abundance	of	caution, although	Entergy	Arkansas	does	not	serve	any	retail	customers	in	Missouri.	If	the	APSC	approves	the	restructuring	by	September	1,	2018,	and	the restructuring	closes	on	or	before	December	1,	2018,	Entergy	Arkansas	proposed	in	its	application	to	credit	retail	customers	$66	million	over	six years,	beginning	 in	2019.	In	February	2018,	Entergy	Arkansas	filed	supplemental	testimony	reducing	the	proposed	retail	customer	credits	to $39.6	million	over	six	years.	If	the	APSC,	the	FERC,	and	the	NRC	approvals	are	obtained,	Entergy	Arkansas	expects	the	restructuring	will	be consummated	on	or	before	December	1,	2018.

It	is	currently	contemplated	that	Entergy	Arkansas	would	undertake	a	multi-step	restructuring,	which	would	include	the	following:

•Entergy	Arkansas	would	redeem	its	outstanding	preferred	stock	at	the	aggregate	redemption	price	of	approximately	 $32.7	million,	which includes	call	premiums,	plus	accumulated	and	unpaid	dividends,	if	any.

•Entergy	Arkansas	would	convert	from	an	Arkansas	corporation	to	a	Texas	corporation.

•Under	the	Texas	Business	Organizations	Code	(TXBOC),	Entergy	Arkansas	will	allocate	substantially	all	of	its	assets	to	a	new	subsidiary,

Entergy	Arkansas	Power,	LLC,	a	Texas	limited	liability	company	(Entergy	Arkansas	Power),	and	Entergy	Arkansas	Power	will	assume substantially	all	of	the	liabilities	of	Entergy	Arkansas,	in	a	transaction	regarded	as	a	merger	under	the	TXBOC.	Entergy	Arkansas	will remain	in	existence	and	hold	the	membership	interests	in	Entergy	Arkansas	Power.

•Entergy	Arkansas	will	contribute	the	membership	interests	in	Entergy	Arkansas	Power	to	an	affiliate	(Entergy	Utility	Holding	Company, LLC,	a	Texas	limited	liability	company	and	subsidiary	of	Entergy	Corporation).	As	a	result	of	the	contribution,	Entergy	Arkansas	Power will	be	a	wholly-owned	subsidiary	of	Entergy	Utility	Holding	Company,	LLC.

•Entergy	Arkansas	will	change	its	name	to	Entergy	Utility	Property,	Inc.,	and	Entergy	Arkansas	Power	will	then	change	its	name	to Entergy	Arkansas,	LLC.

Upon	 the	 completion	 of	 the	 restructuring,	 Entergy	Arkansas,	 LLC	 will	 hold	 substantially	 all	 of	 the	 assets,	 and	 will	 have	 assumed substantially	all	of	 the	 liabilities,	of	Entergy	Arkansas.	Entergy	Arkansas	may	modify	or	supplement	the	steps	to	be	taken	to	effectuate	the restructuring.

# Filings	with	the	LPSC	(Entergy	Louisiana)

# Retail	Rates	-	Electric

In	 connection	 with	 the	 approval	 of	 the	 business	 combination	 of	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana,	 the	 LPSC authorized	the	filing	of	a	single,	joint,	formula	rate	plan	evaluation	report	for	Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	2014 calendar	year	operations.	The	joint	evaluation	report	was	filed	in	September	2015	and	reflected	an	earned	return	on	common	equity	of	9.09%.	As such,	no	adjustment	 to	base	formula	rate	plan	revenue	was	required.	The	following	adjustments	were	required	under	the	formula	rate	plan, however:	a	 decrease	 in	 the	 additional	 capacity	 mechanism	 for	 Entergy	 Louisiana	 of	$17.8	 million;	 an	 increase	 in	 the	 additional	 capacity mechanism	for	Entergy	Gulf	States	Louisiana	of	$4.3	million;	and	a	reduction	of	$5.5	million	to	the	MISO	cost	recovery

mechanism	to	collect	approximately	$35.7	million	on	a	combined-company	basis.	Under	the	order	approving	the	business	combination,	following completion	 of	 the	 prescribed	 review	 period,	 rates	 were	 implemented	 with	 the	 first	 billing	 cycle	 of	 December	 2015,	 subject	 to	 refund.	 See "Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	Business	Combination"	below	for	further	discussion	of	the	business	combination.	In June	2017	the	LPSC	staff	and	Entergy	Louisiana	filed	an	unopposed	joint	report	of	proceedings,	which	was	accepted	by	the	LPSC	in	June	2017, finalizing	the	results	of	this	proceeding	with	no	changes	to	rates	already	implemented.

In	May	2016,	Entergy	Louisiana	filed	its	formula	rate	plan	evaluation	report	for	its	2015	calendar	year	operations.	The	evaluation	report reflected	an	earned	return	on	common	equity	of	9.07%.	As	such,	no	adjustment	to	base	formula	rate	plan	revenue	was	required.	The	following other	 adjustments,	 however,	 were	 required	 under	 the	 formula	 rate	 plan:	 an	 increase	 in	 the	 legacy	 Entergy	 Louisiana	 additional	 capacity mechanism	 of	$14.2	million;	a	separate	 increase	 in	 legacy	Entergy	Louisiana	revenue	of	$10	million	primarily	 to	reflect	 the	effects	of	 the termination	of	the	System	Agreement;	an	increase	in	the	legacy	Entergy	Gulf	States	Louisiana	additional	capacity	mechanism	of	$0.5	million;	a decrease	 in	 legacy	Entergy	Gulf	States	Louisiana	revenue	of	$58.7	million	primarily	to	reflect	the	effects	of	the	termination	of	the	System Agreement;	 and	 an	 increase	 of	$11	million	 to	 the	 MISO	 cost	 recovery	 mechanism.	Rates	were	 implemented	with	 the	first	billing	cycle	of September	2016,	subject	 to	refund.	Following	implementation	of	the	as-filed	rates	in	September	2016,	there	were	several	interim	updates	to Entergy	 Louisiana's	 formula	 rate	 plan,	 including	 the	 one	 submitted	 in	 December	 2016,	 reflecting	 implementation	 of	 the	 settlement	 of	 the Waterford	3	replacement	steam	generator	project	prudence	review	described	below.	In	June	2017	the	LPSC	staff	and	Entergy	Louisiana	filed	a joint	report	of	proceedings,	which	was	accepted	by	the	LPSC	in	June	2017,	finalizing	the	results	of	the	May	2016	evaluation	report,	interim updates,	and	corresponding	proceedings	with	no	changes	to	rates	already	implemented.

# Extension	of	MISO	Cost	Recovery	Mechanism	Rider

In	November	2016,	Entergy	Louisiana	filed	with	the	LPSC	a	request	to	extend	the	MISO	cost	recovery	mechanism	rider	provision	of	its formula	 rate	 plan.	In	March	2017	the	LPSC	staff	submitted	direct	testimony	generally	supportive	of	a	one-year	extension	of	the	MISO	cost recovery	mechanism	and	the	intervenor	in	the	proceeding	did	not	oppose	an	extension	for	this	period	of	time.	In	July	2017	an	uncontested	joint stipulation	authorizing	a	one-year	extension	of	the	MISO	cost	recovery	mechanism	rider	was	approved.

In	May	2017,	Entergy	Louisiana	filed	its	formula	rate	plan	evaluation	report	for	its	2016	calendar	year	operations.	The	evaluation	report reflected	an	earned	return	on	common	equity	of	9.84%.	As	such,	no	adjustment	to	base	formula	rate	plan	revenue	was	required.	Adjustments, however,	were	required	under	the	formula	rate	plan;	the	2016	formula	rate	plan	evaluation	report	showed	a	decrease	in	formula	rate	plan	revenue of	approximately	$16.9	million,	comprised	of	a	decrease	in	legacy	Entergy	Louisiana	formula	rate	plan	revenue	of	$3.5	million,	a	decrease	in legacy	Entergy	Gulf	States	Louisiana	formula	rate	plan	revenue	of	$9.7	million,	and	a	decrease	in	incremental	formula	rate	plan	revenue	of	 $3.7 million.	 Additionally,	 the	 formula	 rate	 plan	 evaluation	 report	 called	 for	 a	 decrease	 of	$40.5	 million	 in	 the	 MISO	 cost	 recovery	 revenue requirement	from	the	present	level	of	$46.8	million	 to	$6.3	million.	Rates	reflecting	these	adjustments	were	implemented	with	the	first	billing cycle	of	September	2017,	subject	to	refund.	In	September	2017	the	LPSC	issued	its	report	indicating	that	no	changes	to	Entergy	Louisiana's original	formula	rate	plan	evaluation	report	were	required	but	reserved	for	several	issues,	including	Entergy	Louisiana's	September	2017	update to	its	formula	rate	plan	evaluation	report.

# Formula	Rate	Plan	Extension	Request

In	August	2017,	Entergy	Louisiana	filed	a	request	with	the	LPSC	seeking	to	extend	its	formula	rate	plan	for	three	years	(2017-2019)	with limited	modifications	to	its	terms.		Those	modifications	include:	a	one-time	resetting	of

base	rates	to	the	midpoint	of	the	band	at	Entergy	Louisiana's	authorized	return	on	equity	of	9.95%	for	the	2017	test	year;	narrowing	of	the formula	rate	plan	bandwidth	from	a	total	of	160	basis	points	to	80	basis	points;	and	a	forward-looking	mechanism	that	would	allow	Entergy Louisiana	to	recover	certain	transmission-related	costs	contemporaneously	with	when	those	projects	begin	delivering	benefits	to	customers. Entergy	Louisiana	requested	that	the	LPSC	consider	its	request	on	an	expedited	basis,	in	an	effort	to	maintain	Entergy	Louisiana's	current	cycle for	 implementing	 rate	 adjustments,	 i.e.,	 September	 2018,	 without	 the	 need	 for	 filing	 a	 full	 base	 rate	 case	 proceeding.	Several	 parties	 have intervened	in	the	proceeding	and	all	parties	have	been	participating	in	settlement	discussions.

# Waterford	3	Replacement	Steam	Generator	Project

Following	the	completion	of	the	Waterford	3	replacement	steam	generator	project,	the	LPSC	undertook	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.	In	July	2014	the	LPSC	staff	filed	 testimony	recommending	potential	project	and	replacement	power	cost	disallowances	of	up	 to	$71 million,	 citing	 a	 need	 for	 further	 explanation	 or	 documentation	 from	 Entergy	 Louisiana.	 	 An	 intervenor	 filed	 testimony	 recommending disallowance	of	$141	million	of	incremental	project	costs,	claiming	the	steam	generator	fabricator	was	imprudent.		Entergy	Louisiana	provided further	documentation	and	explanation	requested	by	the	LPSC	staff.	An	evidentiary	hearing	was	held	in	December	2014.	At	the	hearing	the parties	maintained	the	positions	reflected	in	pre-filed	testimony.	Entergy	Louisiana	believed	that	the	replacement	steam	generator	costs	were prudently	incurred	and	applicable	legal	principles	supported	their	recovery	in	rates.		Nevertheless,	Entergy	Louisiana	recorded	a	write-off	of	$16 million	of	Waterford	3's	plant	balance	in	December	2014	because	of	the	uncertainty	at	the	time	associated	with	the	resolution	of	the	prudence review.	In	December	2015	the	ALJ	issued	a	proposed	recommendation,	which	was	subsequently	finalized,	concluding	that	Entergy	Louisiana prudently	managed	the	Waterford	3	replacement	steam	generator	project,	including	the	selection,	use,	and	oversight	of	contractors,	and	could	not reasonably	have	anticipated	the	damage	to	the	steam	generators.	Nevertheless,	the	ALJ	concluded	that	Entergy	Louisiana	was	liable	for	the conduct	of	its	contractor	and	subcontractor	and,	therefore,	recommended	a	disallowance	of	$67	million	in	capital	costs.	Additionally,	the	ALJ concluded	that	Entergy	Louisiana	did	not	sufficiently	justify	the	incurrence	of	$2	million	in	replacement	power	costs	during	the	replacement outage.	Although	the	ALJ's	recommendation	had	not	yet	been	considered	by	the	LPSC,	after	considering	the	progress	of	the	proceeding	in	light	of the	ALJ	recommendation,	Entergy	Louisiana	recorded	in	the	fourth	quarter	2015	approximately	$77	million	in	charges,	including	a	 $45	million asset	write-off	and	a	$32	million	regulatory	charge,	to	reflect	that	a	portion	of	the	assets	associated	with	the	Waterford	3	replacement	steam generator	project	was	no	longer	probable	of	recovery.	Entergy	Louisiana	maintained	that	the	ALJ's	recommendation	contained	significant	factual and	legal	errors.

In	October	2016	the	parties	reached	a	settlement	in	this	matter.	The	settlement	was	approved	by	 the	LPSC	 in	December	2016.	The settlement	effectively	provided	for	an	agreed-upon	disallowance	of	$67	million	of	plant,	which	had	been	previously	written	off	by	Entergy Louisiana,	as	discussed	above.	The	refund	to	customers	of	approximately	$71	million	as	a	result	of	the	settlement	approved	by	the	LPSC	was made	to	customers	in	January	2017.	Of	the	$71	million	of	refunds,	$68	million	was	credited	to	customers	through	Entergy	Louisiana's	formula rate	plan,	outside	of	sharing,	and	$3	million	through	its	fuel	adjustment	clause.	Entergy	Louisiana	had	previously	recorded	a	provision	of	$48 million	for	this	refund.	The	previously-recorded	provision	included	the	cumulative	revenues	recorded	through	December	2016	related	to	the	$67 million	 of	 disallowed	 plant.	An	additional	regulatory	charge	of	$23	million	was	recorded	in	fourth	quarter	2016	to	reflect	the	effects	of	the settlement.	The	settlement	also	provided	that	Entergy	Louisiana	could	retain	the	value	associated	with	potential	service	credits	agreed	to	by	the project	contractor,	to	the	extent	they	are	realized	in	the	future.	Following	a	review	by	the	parties,	an	unopposed	joint	report	of	proceedings	was filed	by	the	LPSC	staff	and	Entergy	Louisiana	in	May	2017	and	the	LPSC	accepted	the	joint	report	of	proceedings	resolving	the	matter.

# Ninemile	6

In	July	2014,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	filed	an	unopposed	stipulation	with	the	LPSC,	which	was	subsequently approved,	that	estimated	a	first	year	revenue	requirement	associated	with	Ninemile	6	and	provided	a	mechanism	to	update	the	revenue	requirement as	the	in-service	date	approached.	In	late-December	2014,	roughly	contemporaneous	with	the	unit's	placement	in	service,	a	final	updated	estimated revenue	requirement	of	$26.8	million	for	Entergy	Gulf	States	Louisiana	and	$51.1	million	for	Entergy	Louisiana	was	filed.	The	December	2014 estimate	formed	the	basis	of	rates	implemented	effective	with	the	first	billing	cycle	of	January	2015.	In	July	2015,	Entergy	Louisiana	submitted	to the	LPSC	a	compliance	filing	including	an	estimate	at	completion,	inclusive	of	interconnection	costs	and	transmission	upgrades,	of	approximately $648	million,	or	$76	million	less	than	originally	estimated,	along	with	other	project	details	and	supporting	evidence,	to	enable	the	LPSC	to	review the	prudence	of	Entergy	Louisiana's	management	of	the	project.	Testimony	filed	by	the	LPSC	staff	generally	supported	the	prudence	of	the management	of	the	project	and	recovery	of	the	costs	incurred	to	complete	the	project.	The	LPSC	staff	had	questioned	the	warranty	coverage	for one	element	of	the	project.	In	October	2016	all	parties	agreed	to	a	stipulation	providing	that	100%	of	Ninemile	6	construction	costs	was	prudently incurred	and	is	eligible	for	recovery	from	customers,	but	reserving	the	LPSC's	rights	to	review	the	prudence	of	Entergy	Louisiana's	actions regarding	one	element	of	the	project.	This	stipulation	was	approved	by	the	LPSC	in	January	2017.

# Union	Power	Station	and	Deactivation	or	Retirement	Decisions	for	Entergy	Louisiana	Plants

In	January	2015,	Entergy	Gulf	States	Louisiana	filed	its	application	with	the	LPSC	for	approval	of	the	acquisition	and	cost	recovery	of	 two power	 blocks	 of	 the	 Union	 Power	 Station	 for	 an	 expected	 base	 purchase	 price	 of	 approximately	$237	 million	 per	 power	 block,	 subject	 to adjustments.	In	September	2015,	Entergy	Gulf	States	Louisiana	agreed	to	settlement	terms	with	all	parties	for	Entergy	Gulf	States	Louisiana's purchase	of	the	two	power	blocks.	In	October	2015	the	LPSC	voted	unanimously	to	approve	the	uncontested	settlement	which	finds,	among	other things,	that	acquisition	of	Power	Blocks	3	and	4	is	in	the	public	interest	and,	therefore,	prudent.	The	business	combination	of	Entergy	Gulf	States Louisiana	and	Entergy	Louisiana	received	regulatory	approval	and	closed	in	October	2015	making	Entergy	Louisiana	the	named	purchaser	of Power	Blocks	3	and	4	of	the	Union	Power	Station.	In	March	2016,	Entergy	Louisiana	acquired	Power	Blocks	3	and	4	of	Union	Power	Station	for an	aggregate	purchase	price	of	approximately	$474	million	and	implemented	rates	to	collect	the	estimated	first-year	revenue	requirement	with	the first	billing	cycle	of	March	2016.

As	a	term	of	the	LPSC-approved	settlement	authorizing	the	purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station,	Entergy Louisiana	agreed	to	make	a	filing	with	the	LPSC	to	review	its	decisions	to	deactivate	Ninemile	3	and	Willow	Glen	2	and	4	and	its	decision	to retire	Little	Gypsy	1.	 	In	January	2016,	Entergy	Louisiana	made	 its	compliance	filing	with	 the	LPSC.	Entergy	Louisiana,	LPSC	staff,	and intervenors	participated	in	a	technical	conference	in	March	2016	where	Entergy	Louisiana	presented	information	on	its	deactivation/retirement decisions	for	these	four	units	in	addition	to	information	on	the	current	deactivation	decisions	for	the	ten-year	planning	horizon.	Parties	 have requested	further	proceedings	on	the	prudence	of	the	decision	to	deactivate	Willow	Glen	2	and	4.		No	party	contests	the	prudence	of	the	decision to	deactivate	Willow	Glen	2	and	4	or	suggests	reactivation	of	these	units;	however,	issues	have	been	raised	related	to	Entergy	Louisiana's decision	to	give	up	its	transmission	service	rights	in	MISO	for	Willow	Glen	2	and	4	rather	than	placing	the	units	into	suspended	status	for	the three-year	term	permitted	by	MISO.	An	evidentiary	hearing	was	held	in	August	2017	and	post-hearing	briefs	were	submitted	in	October	2017.	A decision	is	expected	in	2018.

# Retail	Rates	-	Gas

In	accordance	with	the	settlement	of	Entergy	Gulf	States	Louisiana's	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2012,	in	August	2014,	Entergy	Gulf	States	Louisiana	submitted	for	consideration	a	proposal	for	implementation	of	an	infrastructure	rider	to recover	expenditures	associated	with	strategic	plant	investment	and	relocation	projects	mandated	by	local	governments.	After	review	by	the	LPSC staff	and	inclusion	of	certain	customer	safeguards	required	by	the	LPSC	staff,	in	December	2014,	Entergy	Gulf	States	Louisiana	and	the	LPSC staff	submitted

a	joint	settlement	for	implementation	of	an	accelerated	gas	pipe	replacement	program	providing	for	the	replacement	of	approximately	100	miles	of pipe	over	the	next	ten	years,	as	well	as	relocation	of	certain	existing	pipe	resulting	from	local	government-related	infrastructure	projects,	and	for	a rider	to	recover	the	investment	associated	with	these	projects.	The	rider	allows	for	recovery	of	approximately	$65	million	over	ten	years.	The	rider recovery	will	be	adjusted	on	a	quarterly	basis	to	include	actual	investment	incurred	for	the	prior	quarter	and	is	subject	to	the	following	conditions, among	others:	a	ten-year	term;	application	of	any	earnings	in	excess	of	10.45%	as	an	offset	to	the	revenue	requirement	of	the	infrastructure	rider; adherence	to	a	specified	spending	plan,	within	plus	or	minus	20%	annually;	annual	filings	comparing	actual	versus	planned	rider	spending	with actual	spending	and	explanation	of	variances	exceeding	10%;	and	an	annual	true-up.	The	joint	settlement	was	approved	by	the	LPSC	in	January 2015.	Implementation	of	the	infrastructure	rider	commenced	with	bills	rendered	on	and	after	the	first	billing	cycle	of	April	2015.

# 2014	Rate	Stabilization	Plan	Filing

In	January	2015,	Entergy	Gulf	States	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2014.		The	filing	showed	an	earned	return	on	common	equity	of	7.20%,	which	resulted	in	a	$706	thousand	rate	increase.		In	April	2015	the	LPSC issued	findings	recommending	two	adjustments	to	Entergy	Gulf	States	Louisiana's	as-filed	results,	and	an	additional	recommendation	that	did	not affect	the	results.	The	LPSC	staff's	recommended	adjustments	increase	the	earned	return	on	equity	for	the	test	year	to	7.24%.	Entergy	Gulf	States Louisiana	accepted	the	LPSC	staff's	recommendations	and	a	revenue	increase	of	$688	thousand	was	implemented	with	the	first	billing	cycle	of May	2015.

In	January	2016,	Entergy	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30,	2015.	The filing	showed	an	earned	return	on	common	equity	of	10.22%,	which	is	within	the	authorized	bandwidth,	therefore	requiring	no	change	in	rates.	In March	2016	the	LPSC	staff	issued	its	report	stating	that	the	2015	gas	rate	stabilization	plan	filing	was	in	compliance	with	the	exception	of	several issues	that	required	additional	information,	explanation,	or	clarification	for	which	the	LPSC	staff	had	reserved	the	right	to	further	review.	In	July 2016	the	parties	to	the	proceeding	filed	an	unopposed	joint	report	and	motion	for	entry	of	order	accepting	the	report	that	indicated	no	outstanding issues	remained	in	the	filing.

In	February	2016,	Entergy	Louisiana	filed	a	motion	requesting	to	extend	the	term	of	the	gas	rate	stabilization	plan	in	substantially	similar form	for	an	additional	 three-year	 term	and	 included	a	request	for	sharing	of	non-jurisdictional	compressed	natural	gas	revenues.	Following discovery	and	the	filing	of	testimony	by	the	LPSC	staff,	Entergy	Louisiana	and	the	LPSC	submitted	a	joint	motion	for	hearing	an	uncontested stipulated	settlement	resolving	the	proceeding.	A	hearing	on	the	stipulation	was	held	in	November	2016.	The	ALJ	issued	a	report	of	proceedings that	was	presented	with	the	parties'	stipulation	to	the	LPSC	for	consideration.	The	stipulation	approving	Entergy	Louisiana's	requested	extension of	the	rate	stabilization	plan	was	approved	by	the	LPSC	in	December	2016.

In	January	2017,	Entergy	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30,	2016.	The filing	of	the	evaluation	report	for	test	year	2016	reflected	an	earned	return	on	common	equity	of	6.37%.	As	part	of	the	original	filing,	pursuant	to the	 extraordinary	 cost	 provision	 of	 the	 rate	 stabilization	 plan,	 Entergy	 Louisiana	 sought	 to	 recover	 approximately	$1.5	 million	 in	 deferred operation	and	maintenance	expenses	incurred	to	restore	service	and	repair	damage	resulting	from	flooding	and	widespread	rainfall	in	southeast Louisiana	that	occurred	in	August	2016.	Entergy	Louisiana	requested	to	recover	the	prudently	incurred	August	2016	storm	restoration	costs	over ten	years,	outside	of	the	rate	stabilization	plan	sharing	provisions.	As	a	result,	Entergy	Louisiana's	filing	sought	an	annual	increase	in	revenue	of $1.4	million.	Following	review	of	the	filing,	except	for	the	proposed	extraordinary	cost	recovery,	the	LPSC	staff	confirmed	Entergy	Louisiana's filing	was	consistent	with	the	principles	and	requirements	of	the	rate	stabilization	plan.	The	extraordinary	cost	recovery	request	associated	with	the 2016	flood-related	deferred	operation	and	maintenance	expenses	incurred	for	gas	operations	was	removed	from	the	rate	stabilization

plan	pending	LPSC	consideration	in	a	separate	docket.	In	April	2017	the	LPSC	approved	a	joint	report	of	proceedings	and	Entergy	Louisiana submitted	a	revised	evaluation	report	reflecting	a	$1.2	million	annual	increase	in	revenue	with	rates	implemented	with	the	first	billing	cycle	of May	2017.

In	connection	with	the	joint	report	of	proceedings	accepted	by	the	LPSC,	in	May	2017,	Entergy	Louisiana	filed	an	application	to	initiate	a separate	proceeding	to	recover	through	the	extraordinary	cost	provision	of	the	gas	rate	stabilization	plan	the	deferred	operation	and	maintenance expenses	of	$1.4	million	incurred	to	restore	service	and	repair	damage	resulting	from	flooding	and	widespread	rainfall	in	southeast	Louisiana	that occurred	 in	August	 2016.	The	LPSC	staff	submitted	its	direct	testimony	in	the	proceeding	recommending	recovery	of	$0.9	million.	 Entergy Louisiana	filed	rebuttal	testimony	responding	to	the	LPSC	staff's	recommendation.	The	procedural	schedule	was	suspended	to	allow	the	parties	to engage	in	settlement	negotiations,	and	in	February	2018	the	LPSC	staff	and	Entergy	Louisiana	filed	an	unopposed	settlement.	If	approved	by	the LPSC,	the	settlement	would	provide	for	Entergy	Louisiana	to	recover,	over	ten	years,	the	approximately	$1.4	million	in	deferred	operation	and maintenance	expense	and	related	carrying	charges.	The	settlement	further	provides	for	recovery	to	commence	in	May	2018.

In	January	2018,	Entergy	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	test	year	ended	September	30,	2017.		The	filing of	the	evaluation	report	for	the	test	year	2017	reflected	an	earned	return	on	common	equity	of	9.06%.		This	earned	return	is	below	the	earnings sharing	band	of	the	rate	stabilization	plan	and	results	in	a	rate	increase	of	$0.1	million.		Due	to	the	enactment	in	late-December	2017	of	the	Tax Cuts	and	Jobs	Act,	Entergy	Louisiana	did	not	have	adequate	time	to	reflect	the	effects	of	this	tax	legislation	in	the	rate	stabilization	plan.		As	a result,	Entergy	Louisiana	will	file	a	supplement	to	the	January	2018	evaluation	report	to	reflect,	among	other	things,	a	21%	federal	corporate income	tax	rate.		Any	rate	change	resulting	from	the	revised	rate	stabilization	plan	will	become	effective	in	rates	in	May	2018.

# Filings	with	the	MPSC	(Entergy	Mississippi)

# Formula	Rate	Plan	Filings

In	March	2016,	Entergy	Mississippi	submitted	its	formula	rate	plan	2016	test	year	filing	showing	Entergy	Mississippi's	projected	earned return	for	the	2016	calendar	year	to	be	below	the	formula	rate	plan	bandwidth.	The	filing	showed	a	$32.6	million	rate	increase	was	necessary	to reset	 Entergy	 Mississippi's	 earned	 return	 on	 common	 equity	 to	 the	 specified	 point	 of	 adjustment	 of	9.96%,	 within	 the	 formula	 rate	 plan bandwidth.	In	 June	 2016	 the	 MPSC	 approved	 Entergy	 Mississippi's	 joint	 stipulation	 with	 the	 Mississippi	 Public	 Utilities	 Staff.	The	 joint stipulation	provided	for	a	total	revenue	increase	of	$23.7	million.	The	revenue	increase	includes	a	$19.4	million	increase	through	the	formula	rate plan,	resulting	in	a	return	on	common	equity	point	of	adjustment	of	10.07%.	The	revenue	increase	also	includes	$4.3	million	in	incremental	ad valorem	tax	expenses	to	be	collected	through	an	updated	ad	valorem	tax	adjustment	rider.	The	revenue	increase	and	ad	valorem	tax	adjustment rider	were	effective	with	the	July	2016	bills.

In	March	2017,	Entergy	Mississippi	submitted	its	formula	rate	plan	2017	test	year	filing	and	2016	look-back	filing	showing	Entergy Mississippi's	earned	return	for	the	historical	2016	calendar	year	and	projected	earned	return	for	the	2017	calendar	year	to	be	within	the	formula rate	plan	bandwidth,	resulting	in	no	change	in	rates.	In	June	2017,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a stipulation	 that	confirmed	 that	Entergy	Mississippi's	earned	returns	for	both	 the	2016	 look-back	filing	and	2017	 test	year	were	within	 the respective	formula	rate	plan	bandwidths.	In	June	2017	the	MPSC	approved	the	stipulation,	which	resulted	in	no	change	in	rates.

# Filings	with	the	City	Council	(Entergy	New	Orleans)

# Retail	Rates

See	"Algiers	Asset	Transfer"	below	for	discussion	of	the	Algiers	asset	transfer.	As	a	provision	of	the	settlement	agreement	approved	by the	City	Council	in	May	2015	providing	for	the	Algiers	asset	transfer,	it	was	agreed	that,	with	limited	exceptions,	no	action	may	be	taken	with respect	to	Entergy	New	Orleans's	base	rates	until	rates	are	implemented	from	a	base	rate	case	that	must	be	filed	for	its	electric	and	gas	operations in	 2018.	This	 provision	 eliminated	 the	 formula	 rate	 plan	 applicable	 to	 Algiers	 operations.	The	 limited	 exceptions	 included	 continued implementation	of	the	then-remaining	two	years	of	the	four-year	phased-in	rate	increase	for	the	Algiers	area	and	certain	exceptional	cost	increases or	decreases	in	the	base	revenue	requirement.	An	additional	provision	of	the	settlement	agreement	allowed	for	continued	recovery	of	the	revenue requirement	associated	with	the	capacity	and	energy	from	Ninemile	6	received	by	Entergy	New	Orleans	under	a	power	purchase	agreement	with Entergy	Louisiana	(Algiers	PPA).	The	settlement	authorized	Entergy	New	Orleans	to	recover	the	remaining	revenue	requirement	related	to	the Algiers	PPA	through	base	rates	charged	to	Algiers	customers.	 The	settlement	also	provided	for	continued	implementation	of	the	Algiers	MISO recovery	rider.

In	addition	to	the	Algiers	PPA,	Entergy	New	Orleans	has	a	separate	power	purchase	agreement	with	Entergy	Louisiana	for	 20%	of	the capacity	and	energy	from	Ninemile	6	(Ninemile	PPA),	which	commenced	operation	in	December	2014.	Initially,	recovery	of	the	non-fuel	costs associated	with	the	Ninemile	PPA	was	authorized	through	a	special	Ninemile	6	rider	billed	only	to	Entergy	New	Orleans	customers	outside	of Algiers.

In	August	2015,	Entergy	New	Orleans	filed	an	application	with	the	City	Council	seeking	authorization	to	proceed	with	the	purchase	of Union	Power	Block	1,	with	an	expected	base	purchase	price	of	approximately	$237	million,	subject	to	adjustments,	and	seeking	approval	of	the recovery	of	the	associated	costs.	In	November	2015	the	City	Council	issued	written	resolutions	and	an	order	approving	an	agreement	in	principle between	Entergy	New	Orleans	and	City	Council	advisors	providing	that	the	purchase	of	Union	Power	Block	1	and	related	assets	by	Entergy	New Orleans	is	prudent	and	in	the	public	interest.	The	City	Council	authorized	expansion	of	the	terms	of	the	purchased	power	and	capacity	acquisition cost	recovery	rider	to	recover	the	non-fuel	purchased	power	expense	from	Ninemile	6,	the	revenue	requirement	associated	with	the	purchase	of Power	Block	1	of	the	Union	Power	Station,	and	a	credit	to	customers	of	$400	thousand	monthly	beginning	June	2016	in	recognition	of	the decrease	in	other	operation	and	maintenance	expenses	that	would	result	with	the	deactivation	of	Michoud	Units	2	and	3.	In	March	2016,	Entergy New	Orleans	purchased	Power	Block	1	of	the	Union	Power	Station	for	approximately	$237	million	and	initiated	recovery	of	these	costs	with March	2016	bills.	In	July	2016,	Entergy	New	Orleans	and	the	City	Council	Utility	Committee	agreed	to	a	temporary	increase	in	the	Michoud credit	to	customers	to	a	total	of	$1.4	million	monthly	for	August	2016	through	December	2016.

A	2008	rate	case	settlement	included	$3.1	million	per	year	in	electric	rates	to	fund	the	Energy	Smart	energy	efficiency	programs.		The	rate settlement	provided	an	incentive	for	Entergy	New	Orleans	to	meet	or	exceed	energy	savings	targets	set	by	the	City	Council	and	provided	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	January	2015	the	City	Council	approved	funding	for	the	Energy	Smart	program	from	April	2015	through	March	2017 using	 the	 remainder	 of	 the	 approximately	$12.8	million	of	2014	rough	production	cost	equalization	funds,	with	any	remaining	costs	being recovered	through	the	fuel	adjustment	clause.	This	funding	methodology	was	modified	in	November	2015	when	the	City	Council	directed	Entergy New	Orleans	to	use	a	combination	of	guaranteed	customer	savings	related	to	a	prior	agreement	with	the	City	Council	and	rough	production	cost equalization	funds	to	cover	program	costs	prior	to	recovering	any	costs	through	the	fuel	adjustment	clause.	In	April	2017	the	City	Council approved	an	implementation	plan	for	the	Energy	Smart	program	from	April	2017	through	December	2019.	The	City	Council	directed	that	the $11.8	million	balance	reported	for	Energy	Smart	funds	be	used	to	continue	funding	the	program	for	Entergy	New	Orleans's	legacy	customers	and that	the	Energy	Smart	Algiers	program	continue	to	be	funded	through	the	Algiers	fuel	adjustment	clause,	until	additional	customer	funding	is required	for	the	legacy	customers.	In	September	2017,	Entergy	New	Orleans	filed	a	supplemental	plan	and	proposed	several	options	for	an	interim cost	recovery	mechanism	necessary	to	recover	program

costs	during	the	period	between	when	existing	funds	directed	to	Energy	Smart	programs	are	depleted	(estimated	to	be	June	2018)	and	when	new rates	 from	 the	 anticipated	 2018	 combined	 rate	 case,	 which	 will	 include	 a	 cost	 recovery	 mechanism	 for	 Energy	 Smart	 funding,	 take	 effect (estimated	to	be	August	2019).	Entergy	New	Orleans	requested	that	the	City	Council	approve	a	cost	recovery	mechanism	prior	to	June	2018.	In December	2017	the	City	Council	approved	an	energy	efficiency	cost	recovery	rider	as	an	interim	funding	mechanism	for	Energy	Smart,	subject	to verification	that	no	additional	funding	sources	exist.

In	July	2016,	Entergy	New	Orleans	filed	an	application	with	the	City	Council	seeking	authorization	to	undertake	a	restructuring	that	would result	in	the	transfer	of	substantially	all	of	the	assets	and	operations	of	Entergy	New	Orleans,	Inc.	to	a	new	entity,	which	would	ultimately	be owned	by	an	existing	Entergy	subsidiary	holding	company.	The	restructuring	was	subject	to	regulatory	review	and	approval	by	the	City	Council and	the	FERC.	In	May	2017	the	City	Council	adopted	a	resolution	approving	the	proposed	internal	restructuring	pursuant	to	an	agreement	in principle	with	the	City	Council	advisors	and	certain	intervenors.	Pursuant	to	the	agreement	in	principle,	Entergy	New	Orleans	would	credit	retail customers	$10	million	in	2017,	$1.4	million	in	the	first	quarter	of	the	year	after	the	transaction	closes,	and	$117,500	each	month	in	the	second year	after	the	transaction	closes	until	such	time	as	new	base	rates	go	into	effect	as	a	result	of	the	anticipated	2018	base	rate	case.	Entergy	New Orleans	began	crediting	retail	customers	 in	June	2017.	In	June	2017	 the	FERC	approved	 the	 transaction	and,	pursuant	 to	 the	agreement	 in principle,	Entergy	New	Orleans	will	provide	additional	credits	to	retail	customers	of	$5	million	in	each	of	the	years	2018,	2019,	and	2020.

In	November	2017,	pursuant	to	the	agreement	in	principle,	Entergy	New	Orleans	undertook	a	multi-step	restructuring,	including	the following:

•Entergy	New	Orleans,	Inc.	redeemed	its	outstanding	preferred	stock	at	a	price	of	approximately	 $21	million,	which included	a	call premium	of	approximately	$819,000,	plus	any	accumulated	and	unpaid	dividends.

•Entergy	New	Orleans,	Inc.	converted	from	a	Louisiana	corporation	to	a	Texas	corporation.

•Under	the	Texas	Business	Organizations	Code	(TXBOC),	Entergy	New	Orleans,	Inc.	allocated	substantially	all	of	its	assets	to	a	new subsidiary,	Entergy	New	Orleans	Power,	LLC,	a	Texas	limited	liability	company	(Entergy	New	Orleans	Power),	and	Entergy	New	Orleans Power	assumed	substantially	all	of	the	liabilities	of	Entergy	New	Orleans,	Inc.,	in	a	transaction	regarded	as	a	merger	under	the	TXBOC. Entergy	New	Orleans,	Inc.	remained	in	existence	and	held	the	membership	interests	in	Entergy	New	Orleans	Power. •Entergy	New	Orleans,	Inc.	contributed	the	membership	interests	in	Entergy	New	Orleans	Power	to	an	affiliate	(Entergy	Utility	Holding Company,	LLC,	a	Texas	limited	liability	company	and	subsidiary	of	Entergy	Corporation).	As	a	result	of	the	contribution,	Entergy	New Orleans	Power	is	a	wholly-owned	subsidiary	of	Entergy	Utility	Holding	Company,	LLC.

In	December	2017,	Entergy	New	Orleans,	Inc.	changed	its	name	to	Entergy	Utility	Group,	Inc.,	and	Entergy	New	Orleans	Power	then	changed	its name	to	Entergy	New	Orleans,	LLC.	Entergy	New	Orleans,	LLC	holds	substantially	all	of	the	assets,	and	has	assumed	substantially	all	of	the liabilities,	of	Entergy	New	Orleans,	Inc.	The	restructuring	was	accounted	for	as	a	transaction	between	entities	under	common	control.

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

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	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	included	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	provided	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	the	PUCT	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	believed	that	it	was	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	also	filed	motions	for	rehearing	of	the	PUCT's	order.		The	PUCT	subsequently	denied	rehearing	of	substantive issues.		Several	parties,	including	Entergy	Texas,	appealed	various	aspects	of	the	PUCT's	order	to	the	Travis	County	District	Court.	A	hearing	was held	in	July	2014.	In	October	2014	the	Travis	County	District	Court	issued	an	order	upholding	the	PUCT's	decision	except	as	to	the	line-loss factor	issue	referenced	above,	which	was	found	in	favor	of	Entergy	Texas.	In	November	2014,	Entergy	Texas	and	other	parties,	including	the PUCT,	appealed	the	Travis	County	District	Court	decision	to	the	Third	Court	of	Appeals.	Oral	argument	before	the	court	panel	was	held	in September	2015.	In	April	2016	the	Third	Court	of	Appeals	issued	its	opinion	affirming	the	District	Court's	decision	on	all	points.	Entergy	Texas petitioned	the	Texas	Supreme	Court	to	hear	its	appeal	of	the	Third	Court's	ruling.	In	September	2017	the	Texas	Supreme	Court	denied	the petitions	for	review.	Entergy	Texas	filed	a	motion	for	rehearing	of	the	Texas	Supreme	Court's	denial	of	the	petition	for	review.	 In	January	2018 the	Texas	Supreme	Court	denied	Entergy	Texas's	motion	for	rehearing.

# Distribution	cost	recovery	factor	(DCRF)	rider

In	September	2015,	Entergy	Texas	filed	to	amend	its	DCRF	rider.	Entergy	Texas	requested	an	increase	in	recovery	under	the	rider	of	$6.5 million,	 for	 a	 total	 collection	 of	$10.1	million	 annually	 from	 retail	 customers.	In	October	2015	intervenors	and	PUCT	staff	filed	testimony opposing,	 in	part,	Entergy	Texas's	request.	In	November	2015,	Entergy	Texas	and	the	parties	filed	an	unopposed	settlement	agreement	and supporting	documents.	The	settlement	established	an	annual	revenue	requirement	of	$8.65	million	for	the	amended	DCRF	rider,	with	the	resulting rates	effective	for	usage	on	and	after	January	1,	2016.	The	PUCT	approved	the	settlement	agreement	in	February	2016.

In	June	2017,	Entergy	Texas	filed	an	application	to	amend	its	DCRF	rider	by	increasing	the	total	collection	from $8.65	 million to approximately	$19	million.	In	July	2017,	Entergy	Texas,	the	PUCT,	and	the	two	other	parties	in	the	proceeding	entered	into	an	unopposed stipulation	 and	 settlement	 agreement	 resulting	 in	 an	 amended	 DCRF	 annual	 revenue	 requirement	 of	$18.3	 million,	 with	 the	 resulting	 rates effective	for	usage	no	later	than	October	1,	2017.	In	September	2017	the	PUCT	issued	its	final	order	approving	the	unopposed	stipulation	and settlement	agreement.	The	amended	DCRF	rider	rates	became	effective	for	usage	on	and	after	September	1,	2017.

# Transmission	cost	recovery	factor	(TCRF)	rider

In	September	2015,	Entergy	Texas	filed	for	a	TCRF	rider	requesting	a	$13	million	increase,	incremental	to	base	rates.	Testimony	was	filed in	November	2015,	with	 the	PUCT	staff	and	other	parties	proposing	various	disallowances	 involving,	among	other	 things,	MISO	charges, vegetation	management	costs,	and	bad	debt	expenses

that	would	reduce	the	requested	increase	by	approximately	$2	million.	In	addition	to	those	recommended	disallowances,	a	number	of	parties recommended	that	Entergy	Texas's	request	be	reduced	by	an	additional	$3.4	million	to	account	for	load	growth	since	base	rates	were	last	set.	A hearing	on	the	merits	was	held	in	December	2015.	In	February	2016	a	State	Office	of	Administrative	Hearings	ALJ	issued	a	proposal	for	decision recommending	that	the	PUCT	disallow	approximately	$2	million	from	Entergy	Texas's	$13	million	request,	but	recommending	that	the	PUCT	not accept	the	load	growth	offset.	In	June	2016	the	PUCT	indicated	that	it	would	take	up	in	a	future	rulemaking	project	the	issue	of	whether	a	load growth	adjustment	should	apply	to	a	TCRF.	In	July	2016	the	PUCT	issued	an	order	generally	accepting	the	proposal	for	decision	but	declining	to adjust	the	TCRF	baseline	in	two	instances	as	recommended	by	the	ALJ,	which	resulted	in	a	total	annual	allowance	of	approximately	$10.5 million.	The	PUCT	also	ordered	its	staff	and	Entergy	Texas	to	track	all	spare	autotransformer	transfers	going	forward	so	that	it	could	address	the appropriate	accounting	treatment	and	prudence	of	such	transfers	in	Entergy	Texas's	next	base	rate	case.	Entergy	Texas	implemented	the	TCRF rider	beginning	with	September	2016	bills.

In	September	2016,	Entergy	Texas	filed	with	 the	PUCT	a	request	 to	amend	 its	TCRF	rider.	 The	proposed	amended	TCRF	rider	 is designed	to	collect	approximately	$29.5	million	annually	from	Entergy	Texas's	retail	customers.	This	amount	includes	the	approximately	$10.5 million	annually	that	Entergy	Texas	is	currently	authorized	to	collect	through	the	TCRF	rider,	as	discussed	above.	In	December	2016,	concurrent with	 the	2016	fuel	reconciliation	stipulation	and	settlement	agreement	discussed	above,	Entergy	Texas	and	 the	PUCT	reached	a	settlement agreeing	 to	 the	 amended	 TCRF	 annual	 revenue	 requirement	 of	$29.5	 million.	 As	 discussed	 above,	 the	 terms	 of	 the	 two	 settlements	 are interdependent.	The	PUCT	approved	the	settlement	and	issued	a	final	order	in	March	2017.	Entergy	Texas	implemented	the	amended	TCRF	rider beginning	with	bills	covering	usage	on	and	after	March	20,	2017.

# Advanced	Metering	Infrastructure	(AMI)	Filings

In	September	2016,	Entergy	Arkansas	filed	an	application	seeking	a	finding	from	the	APSC	that	Entergy	Arkansas's	deployment	of	AMI is	in	the	public	interest.	Entergy	Arkansas	proposed	to	replace	existing	meters	with	advanced	meters	that	enable	two-way	data	communication; design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement	support	systems.	AMI	is	intended	to	serve	as	the foundation	of	Entergy	Arkansas's	modernized	power	grid.	The	filing	included	an	estimate	of	implementation	costs	for	AMI	of	$208	million.	The filing	identified	a	number	of	quantified	and	unquantified	benefits,	and	Entergy	Arkansas	provided	a	cost	benefit	analysis	showing	that	its	AMI deployment	is	expected	to	produce	a	nominal	net	benefit	to	customers	of	$406	million.	Entergy	Arkansas	also	sought	to	continue	to	include	in	rate base	the	remaining	book	value	of	existing	meters,	which	was	approximately	$57	million	at	December	31,	2015,	that	will	be	retired	as	part	of	the AMI	deployment	and	also	to	depreciate	those	assets	using	current	depreciation	rates.	Entergy	Arkansas	proposed	a	15-year	depreciable	life	for	the new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019.	Deployment	of	the	communications	network	is	expected to	begin	in	2018.	Entergy	Arkansas	proposed	to	include	the	AMI	deployment	costs	and	the	quantified	benefits	in	future	formula	rate	plan	filings, and	the	2018	costs	were	approved	in	the	2017	formula	rate	plan	filing.	In	June	2017	the	APSC	staff	and	Arkansas	Attorney	General	filed	direct testimony.	The	APSC	staff	generally	supported	Entergy	Arkansas's	AMI	deployment	conditioned	on	various	recommendations.	 The	Arkansas Attorney	General's	consultant	primarily	recommended	denial	of	Entergy	Arkansas's	application	but	alternatively	suggested	recommendations	in the	event	the	APSC	approves	Entergy	Arkansas's	proposal.	Entergy	Arkansas	filed	rebuttal	testimony	in	June	2017,	substantially	accepting	the APSC	staff's	recommendations.	In	August	2017,	Entergy	Arkansas	and	the	parties	to	the	proceeding	filed	a	joint	motion	to	approve	a	unanimous settlement	agreement.	In	October	2017	the	APSC	issued	an	order	finding	that	Entergy	Arkansas's	AMI	deployment	is	in	the	public	interest	and approving	the	settlement	agreement	subject	to	a	minor	modification.	Entergy	Arkansas	expects	to	recover	the	undepreciated	balance	of	its	existing meters	through	a	regulatory	asset	to	be	amortized	over	15	years.	Entergy	Arkansas	has	begun	discussions	with	the	other	parties	to	implement	the items	in	the	settlement	agreement	including	pre-pay	and	time	of	use	programs.

In	November	2016,	Entergy	Louisiana	filed	an	application	seeking	a	finding	from	the	LPSC	that	Entergy	Louisiana's	deployment	of advanced	electric	and	gas	metering	infrastructure	is	in	the	public	interest.	Entergy	Louisiana	proposed	to	deploy	advanced	meters	that	enable	two- way	data	communication;	design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement	support	systems.	AMI is	intended	to	serve	as	the	foundation	of	Entergy	Louisiana's	modernized	power	grid.	The	filing	included	an	estimate	of	implementation	costs	for AMI	 of	$330	million.	The	filing	identified	a	number	of	quantified	and	unquantified	benefits,	and	Entergy	Louisiana	provided	a	cost/benefit analysis	showing	that	its	combined	electric	and	gas	AMI	deployment	is	expected	to	produce	a	nominal	net	benefit	to	customers	of	$607	million. Entergy	Louisiana	also	sought	to	continue	to	include	in	rate	base	the	remaining	book	value,	approximately	$92	million	at	December	31,	2015,	of the	existing	electric	meters	and	also	to	depreciate	those	assets	using	current	depreciation	rates.	Entergy	Louisiana	proposed	a	15-year	useful	life for	the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019.	The	communications	network	deployment	is expected	to	begin	by	late-2018,	after	the	necessary	information	technology	infrastructure	is	in	place.	Entergy	Louisiana	proposed	to	recover	the cost	of	AMI	through	the	implementation	of	a	customer	charge,	net	of	certain	benefits,	phased	in	over	the	period	2019	through	2022.	The	parties reached	an	uncontested	stipulation	permitting	implementation	of	Entergy	Louisiana's	proposed	AMI	system,	with	modifications	to	the	proposed customer	charge.	In	July	2017	the	LPSC	approved	the	stipulation.	Entergy	Louisiana	expects	to	recover	the	undepreciated	balance	of	its	existing meters	through	a	regulatory	asset	to	be	amortized	at	current	depreciation	rates.

In	November	2016,	Entergy	Mississippi	filed	an	application	seeking	an	order	from	the	MPSC	granting	a	certificate	of	public	convenience and	necessity	and	finding	that	Entergy	Mississippi's	deployment	of	AMI	is	in	the	public	interest.	Entergy	Mississippi	proposed	to	replace	existing meters	with	advanced	meters	 that	enable	 two-way	data	communication;	 to	design	and	build	a	secure	and	reliable	network	 to	support	such communications;	and	to	implement	support	systems.	AMI	is	intended	to	serve	as	the	foundation	of	Entergy	Mississippi's	modernized	power	grid. The	filing	included	an	estimate	of	implementation	costs	for	AMI	of	$132	million.	The	filing	identified	a	number	of	quantified	and	unquantified benefits,	and	Entergy	Mississippi	provided	a	cost	benefit	analysis	showing	that	its	AMI	deployment	is	expected	to	produce	a	nominal	benefit	to customers	of	$496	million	over	a	15-year	period,	which	when	netted	against	the	costs	of	AMI	results	in	 $183	million	of	net	customer	benefits. Entergy	Mississippi	also	sought	to	continue	to	include	in	rate	base	the	remaining	book	value,	approximately	$56	million	at	December	31,	2015,	of existing	meters	that	will	be	retired	as	part	of	the	AMI	deployment	and	also	to	depreciate	those	assets	using	current	depreciation	rates.	Entergy Mississippi	proposed	a	15-year	depreciable	life	for	the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019, subject	to	approval	by	the	MPSC,	with	deployment	of	the	communications	network	expected	to	begin	in	2018.	Entergy	Mississippi	proposed	to include	the	AMI	deployment	costs	and	the	quantified	benefits	in	existing	rate	mechanisms,	primarily	through	future	formula	rate	plan	filings and/or	future	energy	cost	recovery	rider	schedule	re-determinations,	as	applicable.	In	May	2017	the	Mississippi	Public	Utilities	Staff	and	Entergy Mississippi	entered	into	and	filed	a	joint	stipulation	supporting	Entergy	Mississippi's	filing,	and	the	MPSC	issued	an	order	approving	the	filing without	material	changes,	finding	that	Entergy	Mississippi's	deployment	of	AMI	is	in	the	public	interest	and	granting	a	certificate	of	public convenience	and	necessity.	The	MPSC	order	also	confirmed	that	Entergy	Mississippi	shall	continue	to	include	in	rate	base	the	remaining	book value	of	existing	meters	that	will	be	retired	as	part	of	the	AMI	deployment	and	also	to	depreciate	those	assets	using	current	depreciation	rates.

In	 October	 2016,	 Entergy	 New	 Orleans	 filed	 an	 application	 seeking	 a	 finding	 from	 the	 City	 Council	 that	 Entergy	 New	 Orleans's deployment	of	advanced	electric	and	gas	metering	infrastructure	is	in	the	public	interest.		Entergy	New	Orleans	proposed	to	deploy	advanced meters	that	enable	two-way	data	communication;	design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement support	systems.		AMI	is	intended	to	serve	as	the	foundation	of	Entergy	New	Orleans's	modernized	power	grid.		The	filing	included	an	estimate	of implementation	costs	for	AMI	of	$75	million.	The	filing	identified	a	number	of	quantified	and	unquantified	benefits,	and	Entergy	New

Orleans	provided	a	cost/benefit	analysis	showing	that	its	combined	electric	and	gas	AMI	deployment	is	expected	to	produce	a	nominal	net	benefit to	customers	of	$101	million.		Entergy	New	Orleans	also	sought	to	continue	to	include	in	rate	base	the	remaining	book	value,	approximately $21 million	at	December	31,	2015,	of	the	existing	electric	meters	and	also	to	depreciate	those	assets	using	current	depreciation	rates.		Entergy	New Orleans	proposed	a	15-year	depreciable	life	for	the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019. Deployment	of	the	information	technology	infrastructure	began	in	2017	and	deployment	of	the	communications	network	is	expected	to	begin	in 2018.		Entergy	New	Orleans	proposed	to	recover	the	cost	of	AMI	through	the	implementation	of	a	customer	charge,	net	of	certain	benefits,	phased in	over	the	period	2019	through	2022.		The	City	Council's	advisors	filed	testimony	in	May	2017	recommending	the	adoption	of	AMI	subject	to certain	modifications,	including	the	denial	of	Entergy	New	Orleans's	proposed	customer	charge	as	a	cost	recovery	mechanism.	In	January	2018	a settlement	 was	 reached	 between	 the	 City	 Council's	 advisors	 and	 Entergy	 New	 Orleans.	In	 February	 2018	 the	 City	 Council	 approved	 the settlement,	which	deferred	cost	recovery	to	the	2018	Entergy	New	Orleans	rate	case,	but	also	stated	that	an	adjustment	for	2018-2019	AMI	costs can	be	filed	in	the	rate	case	and	that,	for	all	subsequent	AMI	costs,	the	mechanism	to	be	approved	in	the	2018	rate	case	will	allow	for	the	timely recovery	of	such	costs.

In	April	2017	the	Texas	legislature	enacted	legislation	that	extends	statutory	support	for	AMI	deployment	to	Entergy	Texas	and	directs that	if	Entergy	Texas	elects	to	deploy	AMI,	it	shall	do	so	as	rapidly	as	practicable.	In	July	2017,	Entergy	Texas	filed	an	application	seeking	an order	from	the	PUCT	approving	Entergy	Texas's	deployment	of	AMI.	 Entergy	Texas	proposed	to	replace	existing	meters	with	advanced	meters that	enable	two-way	data	communication;	design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement	support systems.	AMI	is	intended	to	serve	as	the	foundation	of	Entergy	Texas's	modernized	power	grid.	The	filing	included	an	estimate	of	implementation costs	for	AMI	of	$132	million.	The	filing	identified	a	number	of	quantified	and	unquantified	benefits,	with	Entergy	Texas	showing	that	its	AMI deployment	is	expected	to	produce	nominal	net	operational	cost	savings	to	customers	of	$33	million.	Entergy	Texas	also	sought	to	continue	to include	in	rate	base	the	remaining	book	value,	approximately	$41	million	at	December	31,	2016,	of	existing	meters	that	will	be	retired	as	part	of the	AMI	deployment	and	also	to	depreciate	those	assets	using	current	depreciation	rates.	Entergy	Texas	proposed	a	seven-year	depreciable	life	for the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019.	Entergy	Texas	also	proposed	a	surcharge	tariff	to recover	the	reasonable	and	necessary	costs	it	has	and	will	incur	under	the	deployment	plan	for	the	full	deployment	of	advanced	meters.	Further, Entergy	Texas	sought	approval	of	fees	that	would	be	charged	to	customers	who	choose	to	opt	out	of	receiving	service	through	an	advanced	meter and	 instead	 receive	 electric	 service	 with	 a	 non-standard	 meter.	In	October	2017,	Entergy	Texas	and	other	parties	entered	 into	and	filed	an unopposed	stipulation	and	settlement	agreement,	permitting	deployment	of	AMI	with	limited	modifications.	The	PUCT	approved	the	stipulation and	settlement	agreement	in	December	2017.	Consistent	with	the	approval,	deployment	of	the	communications	network	is	expected	to	begin	in 2018.	Entergy	Texas	expects	to	recover	the	remaining	net	book	value	of	its	existing	meters	through	a	regulatory	asset	to	be	amortized	at	current depreciation	rates.

# Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	Business	Combination

Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	filed	an	application	with	the	LPSC	in	September	2014	seeking	authorization	to undertake	transactions	that	would	result	in	the	combination	of	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	into	a	single	public	utility.	An uncontested	stipulated	settlement	(stipulated	settlement)	was	filed	with	the	LPSC	in	July	2015.	Through	the	stipulated	settlement,	the	parties agreed	to	terms	upon	which	to	recommend	that	the	LPSC	find	that	the	business	combination	was	in	the	public	interest.	The	stipulated	settlement, which	was	either	joined,	or	unopposed,	by	all	parties	to	the	LPSC	proceeding,	represented	a	compromise	of	stakeholder	positions	and	was	the result	of	an	extensive	period	of	analysis,	discovery,	and	negotiation.	The	stipulated	settlement	provided	$107	million	in	guaranteed	customer benefits	 during	 the	 first	 nine	 years	 following	 the	 transaction's	 close.	Additionally,	 the	 combined	 company	 would	 honor	 the	 2013	 Entergy Louisiana	and	Entergy	Gulf	States	Louisiana	rate	case	settlements,	including	the	commitments	that	(1)	there	would	be	no	rate	increase	for	legacy Entergy	Gulf	States	Louisiana	customers	for	the	2014	test	year,	and	(2)	through	the	2016	test	year	formula	rate	plan,	Entergy	Louisiana	(as	a combined	entity)

would	not	raise	rates	by	more	than	$30	million,	net	of	the	$10	million	rate	increase	included	in	the	Entergy	Louisiana	legacy	formula	rate	plan. The	stipulated	settlement	also	provided	that	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana	would	be	permitted	to	defer	certain	external costs	that	were	incurred	to	achieve	the	business	combination's	customer	benefits.	In	2015	deferrals	of	$16	million	for	these	external	costs	were recorded,	and	they	are	being	amortized	over	a	10-year	period.	The	LPSC	approved	the	business	combination	in	August	2015.

On	October	1,	2015,	the	businesses	formerly	conducted	by	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	were	combined	into	a single	public	utility.	With	the	completion	of	the	business	combination,	Entergy	Louisiana	holds	substantially	all	of	the	assets,	and	has	assumed	the liabilities,	of	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana.	The	combination	was	accounted	for	as	a	transaction	between	entities	under common	control.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the	customer	credits	resulting	from	the	business	combination.

# Algiers	Asset	Transfer	(Entergy	Louisiana	and	Entergy	New	Orleans)

In	 October	 2014,	 Entergy	 Louisiana	 and	 Entergy	 New	 Orleans	 filed	 an	 application	 with	 the	 City	 Council	 seeking	 authorization	 to undertake	a	transaction	that	would	result	in	the	transfer	from	Entergy	Louisiana	to	Entergy	New	Orleans	of	certain	assets	that	supported	the provision	of	service	to	Entergy	Louisiana's	customers	in	Algiers.	In	April	2015	the	FERC	issued	an	order	approving	the	Algiers	assets	transfer.	In May	2015	the	parties	filed	a	settlement	agreement	authorizing	the	Algiers	assets	transfer	and	the	settlement	agreement	was	approved	by	a	City Council	resolution	in	May	2015.	On	September	1,	2015,	Entergy	Louisiana	transferred	its	Algiers	assets	to	Entergy	New	Orleans	for	a	purchase price	of	approximately	$85	million.	Entergy	New	Orleans	paid	Entergy	Louisiana	$59.6	million,	including	final	true-ups,	from	available	cash	and issued	a	note	payable	to	Entergy	Louisiana	in	the	amount	of	$25.5	million.

# System	Agreement	Cost	Equalization	Proceedings

Prior	to	its	final	termination	in	2016,	the	Utility	operating	companies	historically	engaged	in	the	coordinated	planning,	construction,	and operation	of	generating	and	bulk	transmission	facilities	under	the	terms	of	the	System	Agreement.		Entergy	Arkansas	terminated	its	participation in	the	System	Agreement	in	December	2013.	Entergy	Mississippi	terminated	its	participation	in	the	System	Agreement	in	November	2015.	The System	Agreement	terminated	with	respect	to	its	remaining	participants	in	August	2016.

Although	the	System	Agreement	has	terminated,	certain	of	the	Utility	operating	companies'	retail	regulators	continue	to	pursue	litigation involving	the	System	Agreement	at	the	FERC	and	in	federal	courts.		The	proceedings	include	challenges	to	the	allocation	of	costs	as	defined	by the	System	Agreement	and	other	matters.

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	decision	included,	among	other	things:

•The	FERC's	conclusion 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	the	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	reallocated	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.		This	was	accomplished	by	payments	from Utility	operating	companies	whose	production	costs	were	more	than	11%	below	Entergy	System	average	production	costs	to	Utility	operating companies	whose	production	costs	were	more	 than	 the	Entergy	System	average	production	cost,	with	payments	going	first	 to	 those	Utility operating	companies	whose	total	production	costs	were	farthest	above	the	Entergy	System	average.

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	those	two	issues.

In	October	2011	the	FERC	issued	an	order	addressing	the	D.C.	Circuit	remand	on	the	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	this	refund	ruling	will	be	held	in	abeyance	pending	the	outcome	of	the	rehearing requests	 in	 the	 interruptible	 load	 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	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.

In	March	2015,	in	light	of	a	December	2014	decision	by	the	D.C.	Circuit	in	the	interruptible	load	proceeding,	Entergy	filed	with	the	FERC a	motion	to	establish	a	briefing	schedule	on	refund	issues	and	an	initial	brief	addressing	refund	issues.	The	initial	brief	argued	that	the	FERC,	in response	to	the	D.C.	Circuit	decision,	should	clarify	its	policy	on	refunds	and	find	that	refunds	are	not	required	in	this	proceeding.	In	October	2015 the	FERC	issued	three	orders	related	to	the	commencement	of	the	remedy	on	June	1,	2005	and	the	inclusion	of	interest	for	the	period	June	1,	2005 through	December	31,	2005.	Specifically,	the	FERC	rejected	Entergy's	request	for	rehearing	of	its	decision	to	include	interest	for	the	seven-month period.	The	FERC	also	rejected	Entergy's	request	for	rehearing	of	the	order	rejecting	the	compliance	filing	with	regard	to	the	issue	of	interest. Finally,	the	FERC	set	for	hearing	and	settlement	procedures	the	2014	compliance	filing	that	included	the	bandwidth	calculation	for	the	seven months	June	1,	2005	through	December	31,	2005.	In	setting	the	compliance	filing	for	hearing,	the	FERC	rejected	the	APSC's	protest	that	Entergy Arkansas	should	not	be	subject	to	the	filing	because	Entergy	Arkansas	would	be	making	the	payments	during	a	period	following	its	exit	from	the System	Agreement.	In	January	2018	the	D.C.Circuit	affirmed	the	FERC	decision	that	Entergy	Arkansas	was	subject	to	the	filing.

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	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.	The	filing	shows	the	following	payments/receipts	among	the	Utility operating	companies:

|  | Payments<br>(Receipts) |
| :--- | :--- |
|  | (In\tMillions) |
| Entergy\tArkansas | $156 |
| Entergy\tLouisiana | ($75) |
| Entergy\tMississippi | ($33) |
| Entergy\tNew\tOrleans | ($5) |
| Entergy\tTexas | ($43) |

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	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	requested	rehearing	of	the	FERC's	October	2011	order.

In	February	2014	 the	FERC	 issued	a	rehearing	order	addressing	 its	October	2011	order.	The	FERC	denied	 the	LPSC's	request	for rehearing	on	the	issues	of	whether	the	bandwidth	remedy	should	be	made	effective	earlier	than	June	1,	2005,	and	whether	refunds	should	be ordered	for	the	20-month	refund	effective	period.	The	FERC	granted	the	LPSC's	rehearing	request	on	the	issue	of	interest	on	the	bandwidth payments/receipts	for	the	June	-	December	2005	period,	requiring	that	interest	be	accrued	from	June	1,	2006	until	the	date	those	bandwidth payments/receipts	are	made.	Also	in	February	2014	the	FERC	issued	an	order	rejecting	the	December	2011	compliance	filing	that	calculated	the bandwidth	 payments/receipts	 for	 the	 June	 -	 December	 2005	 period.	The	 FERC	 order	 required	 a	 new	 compliance	 filing	 that	 calculates	 the bandwidth	payments/receipts	for	the	June	-	December	2005	period	based	on	monthly	data	for	the	seven	individual	months	including	interest pursuant	to	the	February	2014	rehearing	order.	Entergy	sought	rehearing	of	the	February	2014	order	with	respect	to	the	FERC's	determinations regarding	interest.	In	April	2014	the	LPSC	filed	a	petition	for	review	of	the	FERC's	October	2011	and	February	2014	orders	with	the	U.S.	Court of	Appeals	for	the	D.C.	Circuit.	In	August	2017	the	D.C.	Circuit	issued	a	decision	addressing	the	LPSC's	appeal	of	the	FERC's	October	2011	and February	2014	orders.	On	the	issue	of	the	FERC's	implementation	of	the	prospective	remedy	as	of	June	2005	and	whether	the	bandwidth	remedy should	be	extended	for	an	additional	17	months	in	years	2004-2005,	the	D.C.	Circuit	affirmed	the	FERC's	implementation	of	the	remedy	and denied	the	LPSC's	appeal.	On	the	issue	of	whether	the	operating	companies	should	be	required	to	issue	refunds	for	the	20-month	period	from September	2001	to	May	2003,	the	D.C.	Circuit	granted	the	FERC's	request	for	agency	reconsideration	and	remanded	that	issue	back	to	the	FERC for	further	proceedings	as	requested	by	all	parties	to	the	appeal.

In	April	and	May	2014,	Entergy	filed	with	the	FERC	an	updated	compliance	filing	that	provides	the	payments	and	receipts	among	the Utility	operating	companies	pursuant	to	the	FERC's	February	2014	orders.		The	filing	shows	the	following	net	payments	and	receipts,	including interest,	among	the	Utility	operating	companies:

|  | Payments<br>(Receipts) |
| :--- | :--- |
|  | (In\tMillions) |
| Entergy\tArkansas | $68 |
| Entergy\tLouisiana | ($10) |
| Entergy\tMississippi | ($11) |
| Entergy\tNew\tOrleans | $2 |
| Entergy\tTexas | ($49) |

These	payments	were	made	in	May	2014.	The	LPSC,	City	Council,	and	APSC	filed	protests.

The	hearing	on	the	bandwidth	calculation	for	the	seven	months	June	1,	2005	through	December	31,	2005	occurred	in	July	2016.	The presiding	 judge	 issued	 an	 initial	 decision	 in	 November	 2016.	In	 the	 initial	 decision,	 the	 presiding	 judge	 agreed	 with	 the	 Utility	 operating companies'	position	that:	(1)	interest	on	the	bandwidth	payments	for	the	2005	test	period	should	be	accrued	from	June	1,	2006	until	the	date	that the	bandwidth	payments	for	that	calculation	are	paid,	which	is	consistent	with	how	the	Utility	operating	companies	performed	the	calculation;	and (2)	a	portion	of	Entergy	Louisiana's	2001-vintage	Louisiana	state	net	operating	loss	accumulated	deferred	income	tax	that	results	from	the	Vidalia tax	deduction	should	be	excluded	from	the	2005	test	period	bandwidth	calculation.	Various	participants	filed	briefs	on	exceptions	and/or	briefs opposing	exceptions	related	to	the	initial	decision,	including	the	LPSC,	the	APSC,	the	FERC	trial	staff,	and	Entergy	Services.	The	initial	decision is	pending	before	the	FERC.

# Rough	Production	Cost	Equalization	Rates

Each	May	from	2007	through	2016	Entergy	filed	with	the	FERC	the	rates	to	implement	the	FERC's	orders	in	the	System	Agreement proceeding.	 	These	filings	showed	the	following	payments/receipts	among	the	Utility	operating	companies	were	necessary	to	achieve	rough production	cost	equalization	as	defined	by	the	FERC's	orders:

|  |  |  |  | Payments	(Receipts) | Payments	(Receipts) |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | 2013 | 2014 |
|  |  |  |  | (In\tMillions) | (In\tMillions) |  |  |  |
| Entergy\tArkansas | $252 | $252 | $390 | $41 | $77 | $41 | $— | $— |
| Entergy\tLouisiana | ($211) | ($160) | ($247) | ($22) | ($12) | ($41) | $— | $— |
| Entergy\tMississippi | ($41) | ($20) | ($24) | ($19) | ($40) | $— | $— | $— |
| Entergy\tNew\tOrleans | $— | ($7) | $— | $— | ($25) | $— | ($15) | ($15) |
| Entergy\tTexas | ($30) | ($65) | ($119) | $— | $— | $— | $15 | $15 |

The	Utility	operating	companies	recorded	accounts	payable	or	accounts	receivable	to	reflect	the	rough	production	cost	equalization	payments	and receipts	required	to	implement	the	FERC's	remedy.		When	accounts	payable	were	recorded,	a	corresponding	regulatory	asset	was	recorded	for	the right	to	collect	the	payments	from	customers.	When	accounts	receivable	were	recorded,	a	corresponding	regulatory	liability	was	recorded	for	the obligations	to	pass	the	receipts	on	to	customers.		No	payments	were	required	in	2016	or	2015	to	implement	the	FERC's	remedy	based	on	calendar year	2015	production	costs	and	2014	production	costs,	respectively.	The	System	Agreement	terminated	in	August	2016.

The	APSC	approved	a	production	cost	allocation	rider	for	recovery	from	customers	of	the	retail	portion	of	the	costs	allocated	to	Entergy Arkansas.		Entergy	Texas	recovered	its	2013	rough	production	cost	equalization	payment	over	three	years	beginning	April	2014.	Entergy	Texas included	its	2014	rough	production	cost	equalization	payment	as	a	component	of	an	interim	fuel	refund	made	in	2014.	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.

The	following	rough	production	cost	equalization	rate	proceedings	are	still	ongoing.

2010	Rate	Filing	Based	on	Calendar	Year	2009	Production	Costs

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.		After	an abeyance	of	the	proceeding	schedule,	a	hearing	was	held	in	March	2014	and	in	December	2015	the	FERC	issued	an	order.	Among	other	things, the	December	2015	order	directed	Entergy	to	submit	a	compliance	filing.	In	January	2016	the	LPSC,	the	APSC,	and	Entergy	filed	requests	for rehearing	of	the	FERC's	December	2015	order.	In	February	2016,	Entergy	submitted	the	compliance	filing	ordered	in	the	December	2015	order. The	result	of	the	true-up	payments	and	receipts	for	the	recalculation	of	production	costs	resulted	in	the	following	payments/receipts	among	the Utility	operating	companies:

# Payments

In	September	2016	the	FERC	accepted	the	February	2016	compliance	filing	subject	to	a	further	compliance	filing	made	in	November 2016.	The	further	compliance	filing	was	required	as	a	result	of	an	order	issued	in	September	2016	ruling	on	the	January	2016	rehearing	requests filed	by	the	LPSC,	the	APSC,	and	Entergy.	In	the	order	addressing	the	rehearing	requests,	the	FERC	granted	the	LPSC's	rehearing	request	and directed	that	interest	be	calculated	on	the	payment/receipt	amounts.	The	FERC	also	granted	the	APSC's	and	Entergy's	rehearing	request	and ordered	the	removal	of	both	securitized	asset	accumulated	deferred	income	taxes	and	contra-securitization	accumulated	deferred	income	taxes from	the	calculation.	In	November	2016,	Entergy	submitted	its	compliance	filing	in	response	to	the	FERC's	order	on	rehearing.	The	compliance filing	included	a	revised	refund	calculation	of	the	true-up	payments	and	receipts	based	on	2009	test	year	data	and	interest	calculations.	The	LPSC protested	the	interest	calculations.	In	November	2017	the	FERC	issued	an	order	rejecting	the	November	2016	compliance	filing.	The	 FERC determined	that	the	payments	detailed	in	the	November	2016	compliance	filing	did	not	include	adequate	interest	for	the	payments	from	Entergy Arkansas	to	Entergy	Louisiana	because	it	did	not	include	interest	on	the	principal	portion	of	the	payment	that	was	made	in	February	2016.	In December	2017,	Entergy	recalculated	the	interest	pursuant	to	the	November	2017	order.	As	a	result	of	the	recalculations,	Entergy	Arkansas	owed very	minor	payments	to	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans.

# 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.	After	an	abeyance	of	the	proceeding	schedule,	in December	2014	the	FERC	consolidated	the	2011	rate	filing	with	the	2012,	2013,	and	2014	rate	filings	for	settlement	and	hearing	procedures.	See discussion	below	regarding	the	consolidated	settlement	and	hearing	procedures	in	connection	with	this	proceeding.

# 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.	After	an	abeyance	of	the	proceeding	schedule,	in December	2014	the	FERC	consolidated	the	2012	rate	filing	with	the	2011,	2013,	and	2014	rate	filings	for	settlement	and	hearing	procedures.	See discussion	below	regarding	the	consolidated	settlement	and	hearing	procedures	in	connection	with	this	proceeding.

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.	After	an	abeyance	of	the	proceeding	schedule,	in	December 2014	the	FERC	consolidated	the	2013	rate	filing	with	the	2011,	2012,	and	2014	rate	filings	for	settlement	and	hearing	procedures.

# See	discussion	below	regarding	the	consolidated	settlement	and	hearing	procedures	in	connection	with	this	proceeding.

In	May	2014,	Entergy	filed	with	the	FERC	the	2014	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.	In	December	2014	the	FERC	issued	an	order	accepting	the	2014	rates,	effective	June	1,	2014,	subject	to	refund,	set	the	proceeding	for hearing	procedures,	and	consolidated	the	2014	rate	filing	with	the	2011,	2012,	and	2013	rate	filings	for	settlement	and	hearing	procedures.	See discussion	below	regarding	the	consolidated	settlement	and	hearing	procedures	in	connection	with	this	proceeding.

As	discussed	above,	in	December	2014	the	FERC	consolidated	the	2011,	2012,	2013,	and	2014	rate	filings	for	settlement	and	hearing procedures.	In	May	2015,	Entergy	filed	direct	testimony	in	the	consolidated	rate	filings	and	the	LPSC	filed	direct	testimony	concerning	its complaint	proceeding	that	is	consolidated	with	the	rate	filings,	challenging	certain	components	of	the	pending	bandwidth	calculations	for	prior years.	Hearings	occurred	in	November	2015,	and	the	ALJ	issued	an	initial	decision	in	July	2016.	In	the	initial	decision,	the	ALJ	generally	agreed with	Entergy's	bandwidth	calculations	with	one	exception	on	 the	accounting	related	 to	 the	Waterford	3	sale/leaseback.	Briefs	were	filed	 in September	2016	and	the	proceeding	is	pending.

# Utility	Operating	Company	Termination	of	System	Agreement	Participation

Entergy	Arkansas	and	Entergy	Mississippi	ceased	participating	in	the	System	Agreement	effective	December	18,	2013	and	November	7, 2015,	respectively.	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas	terminated	participation	in	the	System	Agreement	on	August	31, 2016,	which	resulted	in	the	termination	of	the	System	Agreement	in	its	entirety	pursuant	to	a	settlement	agreement	approved	by	the	FERC	in December	2015.

In	December	2013	the	FERC	set	one	issue	for	hearing	involving	whether	and	how	the	benefits	associated	with	settlement	with	Union Pacific	regarding	certain	coal	delivery	 issues	should	be	allocated	among	Entergy	Arkansas	and	 the	other	Utility	operating	companies	post- termination	of	the	System	Agreement.	In	December	2014	a	FERC	ALJ	issued	an	initial	decision	finding	that	Entergy	Arkansas	would	realize benefits	after	December	18,	2013	from	the	2008	settlement	agreement	between	Entergy	Services,	Entergy	Arkansas,	and	Union	Pacific,	related	to certain	 coal	 delivery	 issues.	The	ALJ	further	found	that	all	of	 the	Utility	operating	companies	should	share	 in	 those	benefits	pursuant	 to	a methodology	proposed	by	the	MPSC.	The	Utility	operating	companies	and	other	parties	to	the	proceeding	filed	briefs	on	exceptions	and/or	briefs opposing	exceptions	with	the	FERC	challenging	various	aspects	of	the	December	2014	initial	decision.	In	March	2016	the	FERC	issued	an opinion	affirming	the	December	2014	initial	decision	with	regard	to	the	determination	that	there	were	benefits	related	to	the	Union	Pacific settlement,	which	were	realized	post-Entergy	Arkansas's	December	2013	withdrawal	from	the	System	Agreement,	that	should	be	shared	with	the other	Utility	operating	companies	utilizing	the	methodology	proposed	by	the	MPSC	and	trued-up	to	actual	coal	volumes	purchased.	In	May	2016, Entergy	made	a	compliance	filing	that	provided	the	calculation	of	Union	Pacific	settlement	benefits	utilizing	the	methodology	adopted	by	the initial	decision,	trued-up	for	the	actual	volumes	of	coal	purchased.	The	payments	were	made	in	May	2016.	In	August	2016	the	FERC	issued	an order	accepting	Entergy's	compliance	filing.	Also	in	August	2016	the	APSC	filed	a	petition	for	review	of	the	FERC's	March	2016	and	August 2016	orders	with	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit.	Oral	argument	before	the	D.C.	Circuit	was	held	on	the	APSC's	petition	in January	2018	and	a	decision	is	pending.

In	 connection	 with	 the	 System	 Agreement	 termination	 settlement	 agreement,	 the	 purchase	 power	 agreements,	 referred	 to	 as	 the jurisdictional	separation	plan	PPAs,	between	Entergy	Texas	and	Entergy	Gulf	States	Louisiana	that	were	put	in	place	for	certain	legacy	gas	units at	the	time	of	Entergy	Gulf	States's	separation	into	Entergy	Texas	and	Entergy	Gulf	States	Louisiana	terminated	effective	with	the	System Agreement	 termination.	Similarly,	the	purchase	power	agreement	between	Entergy	Gulf	States	Louisiana	and	Entergy	Texas	for	the	Calcasieu unit	also	terminated.	In

March	2016,	Entergy	Services	filed	with	the	FERC	the	notices	of	termination.	The	jurisdictional	separation	plan	PPAs	were	the	means	by	which Entergy	Texas	received	payment	for	its	receivable	associated	with	Entergy	Louisiana's	Spindletop	gas	storage	facility	regulatory	asset.	As	a	result of	the	System	Agreement	termination	settlement	agreement,	effective	with	the	termination	date,	Entergy	Texas	no	longer	receives	payments	from Entergy	Louisiana	related	to	the	Spindletop	storage	facility,	which	resulted	in	a	write-off	recorded	in	2015	by	Entergy	Texas	of	$23.5	million ($15.3	million	 net-of-tax).	Upon	termination	of	the	System	Agreement,	other	purchase	power	agreements	entered	into	under	Service	Schedule MSS-4	of	the	System	Agreement	were	replaced	with	updated	agreements	under	a	FERC-jurisdictional	tariff	effective	September	1,	2016.

# 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	refunds	under	the	decision.		The	APSC	and	the Utility	operating	companies	appealed	the	FERC	decisions	to	the	D.C.	Circuit.

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,	the	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	July	2011	the	refunds	made	in	the	fourth	quarter	2009	described	above	were	reversed.	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	were	due.

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.		The	settlement	agreement	was	approved	by	the	FERC	in September	2016.

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.	Oral	argument	was	held	on	the	appeal	in	the	D.C.	Circuit	in	September	2014.	In	December	2014	the	D.C.	Circuit	issued an	 order	 on	 the	 LPSC's	 appeal	 and	 remanded	 the	 case	 back	 to	 the	 FERC.	The	D.C.	Circuit	rejected	 the	LPSC's	argument	 that	 there	 is	a presumption	in	favor	of	refunds,	but	it	held	that	the	FERC	had	not	adequately	explained	its	decision	to	deny	refunds	and	directed	the	FERC	"to consider	the	relevant	factors	and	weigh	them	against	one	another."	In	March	2015,	Entergy	filed	with	the	FERC	a	motion	to	establish	a	briefing schedule	on	remand	and	an	initial	brief	on	remand	to	address	the	December	2014	decision	by	the	D.C.	Circuit.	The	initial	brief	on	remand	argued that	 the	FERC,	 in	response	 to	 the	D.C.	Circuit	decision,	should	clarify	 its	policy	on	refunds	and	find	 that	refunds	are	not	required	 in	 the interruptible	load	proceeding.

In	April	2016	the	FERC	issued	an	order	on	remand	that	addressed	the	December	2014	decision	by	the	D.C.	Circuit	in	the	interruptible load	proceeding.	The	order	on	remand	affirmed	the	FERC's	denial	of	refunds	for	the	15-month	refund	effective	period.	The	FERC	explained	and clarified	its	policies	regarding	refunds	and	concluded	that	the	evidence	in	the	record	demonstrated	that	the	relevant	equitable	factors	favored	not requiring	refunds	in	this	case.	The	FERC	also	noted	that,	under	Section	206(c)	of	the	Federal	Power	Act,	in	a	Section	206	proceeding	involving two	or	more	electric	utility	companies	of	a	registered	holding	company	system,	the	FERC	may	order	refunds	only	if	it	determines	the	refunds would	not	cause	the	registered	holding	company	to	experience	any	reduction	in	revenues	resulting	from	an	inability	of	an	electric	utility	company in	the	system	to	recover	the	resulting	increase	in	costs.	The	FERC	stated	it	was	not	able	to	find	that	the	Entergy	system	would	not	experience	a reduction	in	revenues	if	refunds	were	awarded	in	this	proceeding,	which	further	supported	the	denial	of	refunds.	In	May	2016	the	LPSC	filed	a request	for	rehearing	of	the	FERC's	April	2016	order.	In	September	2016	the	FERC	issued	an	order	denying	the	LPSC's	request	for	rehearing	and reaffirming	its	denial	of	refunds	for	the	15-month	refund	effective	period.	The	LPSC	has	appealed	the	April	and	September	2016	orders	to	the U.S.	Court	of	Appeals	for	the	D.C.	Circuit.	Oral	argument	before	the	D.C.	Circuit	was	held	before	the	D.C.	Circuit	in	February	2018	and	a decision	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	 allocated	 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	prohibited	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	challenged	sales	made	beginning	in	2002	and	requested	refunds.		In	July	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	FERC	subsequently	ordered	a	hearing	in	the	proceeding.

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	requires	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.	A	hearing	was	held	 in	May	2013	 to	quantify	 the	effect	of	repricing	 the	opportunity	sales	 in accordance	with	the	FERC's	June	2012	decision.

In	August	 2013	 the	 presiding	 judge	 issued	 an	 initial	 decision	 in	 the	 calculation	 proceeding.	The	 initial	 decision	 concluded	 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	concluded	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	recognized	that	the	LPSC's	methodology	would	result	in	an inequitable	windfall	to	the	other	Utility	operating	companies	and,	therefore,	concluded	that	any	payments	by	Entergy	Arkansas	should	be	reduced by	20%.	The	LPSC,	the	APSC,	the	City	Council,	and	FERC	staff	filed	briefs	on	exceptions	and/or	briefs	opposing	exceptions.	Entergy	filed	a brief	on	exceptions	requesting	that	the	FERC	reverse	the	initial	decision	and	a	brief	opposing	certain	exceptions	taken	by	the	LPSC	and	FERC staff.

In	April	2016	the	FERC	issued	orders	addressing	requests	for	rehearing	filed	in	July	2012	and	the	ALJ's	August	2013	initial	decision.	 The first	order	denied	Entergy's	request	for	rehearing	and	affirmed	the	FERC's	earlier	rulings	that	Entergy's	original	methodology	for	allocating energy	 costs	 to	 the	 opportunity	 sales	 was	 incorrect	 and,	 as	 a	 result,	 Entergy	Arkansas	 must	 make	 payments	 to	 the	 other	 Utility	 operating companies	to	put	them	in	the	same	position	that	they	would	have	been	in	absent	the	incorrect	allocation.	The	FERC	clarified	that	interest	should be	included	with	the	payments.	The	second	order	affirmed	in	part,	and	reversed	in	part,	the	rulings	in	the	ALJ's	August	2013	initial	decision regarding	the	methodology	that	should	be	used	to	calculate	the	payments	Entergy	Arkansas	is	to	make	to	the	other	Utility	operating	companies. The	FERC	affirmed	the	ALJ's	ruling	that	a	full	re-run	of	intra-system	bills	should	be	performed,	but	required	that	methodology	be	modified	so that	the	sales	have	the	same	priority	for	purposes	of	energy	allocation	as	joint	account	sales.	The	FERC	reversed	the	ALJ's	decision	that	any payments	 by	 Entergy	Arkansas	 should	 be	 reduced	 by	20%.	 The	 FERC	 also	 reversed	 the	ALJ's	 decision	 that	 adjustments	 to	 other	 System Agreement	service

schedules	and	excess	bandwidth	payments	should	not	be	taken	into	account	when	calculating	the	payments	to	be	made	by	Entergy	Arkansas.	The FERC	held	that	such	adjustments	and	excess	bandwidth	payments	should	be	taken	into	account,	but	ordered	further	proceedings	before	an	ALJ	to address	whether	a	cap	on	any	reduction	due	to	bandwidth	payments	was	necessary	and	to	implement	the	other	adjustments	to	the	calculation methodology.

In	May	2016,	Entergy	Services	filed	a	request	for	rehearing	of	the	FERC's	April	2016	order	arguing	that	payments	made	by	Entergy Arkansas	should	be	reduced	as	a	result	of	the	timing	of	the	LPSC's	approval	of	certain	contracts.	Entergy	Services	also	filed	a	request	for clarification	and/or	rehearing	of	the	FERC's	April	2016	order	addressing	the	ALJ's	August	2013	initial	decision.	 The	APSC	and	the	LPSC	also filed	requests	for	rehearing	of	the	FERC's	April	2016	order.	In	September	2017	the	FERC	issued	an	order	denying	the	request	for	rehearing	on	the issue	of	whether	any	payments	by	Entergy	Arkansas	to	the	other	Utility	operating	companies	should	be	reduced	due	to	the	timing	of	the	LPSC's approval	of	Entergy	Arkansas's	wholesale	baseload	contract	with	Entergy	Louisiana.	In	November	2017	the	FERC	issued	an	order	denying	all	of the	remaining	requests	for	rehearing	of	the	April	2016	order.	In	November	2017,	Entergy	Services	filed	a	petition	for	review	in	the	D.C.	Circuit	of the	FERC's	orders	in	the	first	two	phases	of	the	opportunity	sales	case.	In	December	2017	the	D.C.	Circuit	granted	Entergy	Services's	request	to hold	the	appeal	in	abeyance	pending	final	resolution	of	the	related	proceeding	still	pending	with	the	FERC.	In	January	2018	the	APSC	and	the LPSC	filed	separate	petitions	for	review	in	the	D.C.	Circuit,	and	the	D.C.	Circuit	consolidated	the	appeals	with	Entergy	Services's	appeal	and	held all	of	the	appeals	in	abeyance.

Pursuant	to	the	procedural	schedule	established	in	the	case,	Entergy	Services	re-ran	intra-system	bills	for	the	ten-year	period	2000-2009	to quantify	the	effects	of	the	FERC's	ruling.	In	November	2016	the	LPSC	submitted	testimony	disputing	certain	aspects	of	the	calculations.	A hearing	was	held	in	May	2017.	In	July	2017,	the	ALJ	issued	an	initial	decision	concluding	that	Entergy	Arkansas	should	pay	$86	million	plus interest	to	the	other	Utility	operating	companies.	In	August	2017	the	Utility	operating	companies,	the	LPSC,	the	APSC,	and	FERC	staff	filed individual	briefs	on	exceptions	challenging	various	aspects	of	the	initial	decision.	In	September	2017	the	Utility	operating	companies,	the	LPSC, the	APSC,	the	MPSC,	the	City	Council,	and	FERC	staff	filed	separate	briefs	opposing	exceptions	taken	by	various	parties.	The	case	is	pending before	the	FERC.	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.

The	effect	of	the	FERC's	decisions	thus	far	in	the	case	would	be	that	Entergy	Arkansas	will	make	payments	to	some	or	all	of	the	other Utility	operating	companies.	Because	further	proceedings	will	still	occur	in	the	case,	the	amount	and	recipients	of	payments	by	Entergy	Arkansas are	unknown	at	this	time.	Based	on	testimony	previously	submitted	in	the	case	and	its	assessment	of	the	April	2016	FERC	orders,	in	the	first quarter	2016,	Entergy	Arkansas	recorded	a	liability	of	$87	million,	which	includes	interest,	for	its	estimated	increased	costs	and	payment	to	the other	Utility	operating	companies.	This	estimate	is	subject	to	change	depending	on	how	the	FERC	resolves	the	issues	that	are	still	outstanding	in the	case,	including	its	review	of	the	July	2017	initial	decision.	Entergy	Arkansas's	increased	costs	will	be	attributed	to	Entergy	Arkansas's	retail and	wholesale	businesses,	and	it	is	not	probable	that	Entergy	Arkansas	will	recover	the	wholesale	portion.	Entergy	Arkansas,	therefore,	recorded	a deferred	fuel	regulatory	asset	in	the	first	quarter	2016	of	approximately	$75	million,	which	represents	its	estimate	of	the	retail	portion	of	the	costs. Following	its	assessment	of	the	course	of	the	proceedings,	including	the	FERC's	denial	of	rehearing	in	November	2017	described	above,	in	the fourth	quarter	2017,	Entergy	Arkansas	recorded	an	additional	liability	of	$35	million	and	a	regulatory	asset	of	$31	million.	Because	management currently	expects	to	recover	the	retail	portion	of	the	costs	through	a	base	rate	proceeding	or	newly	proposed	rider,	the	regulatory	asset	is	reflected as	Other	regulatory	assets	as	of	December	31,	2017.

# Complaint	Against	System	Energy

In	January	2017	the	APSC	and	MPSC	filed	a	complaint	with	the	FERC	against	System	Energy.	The	complaint	seeks	a	reduction	in	the return	on	equity	component	of	the	Unit	Power	Sales	Agreement	pursuant	to	which	System	Energy	sells	its	Grand	Gulf	capacity	and	energy	to Entergy	Arkansas,	 Entergy	 Louisiana,	 Entergy	 Mississippi,	 and	 Entergy	 New	 Orleans.	Entergy	Arkansas	also	sells	some	of	 its	Grand	Gulf capacity	and	energy	to	Entergy	Louisiana,

Entergy	Mississippi,	and	Entergy	New	Orleans	under	separate	agreements.	The	current	return	on	equity	under	the	Unit	Power	Sales	Agreement	is 10.94%.	The	complaint	alleges	that	the	return	on	equity	is	unjust	and	unreasonable	because	current	capital	market	and	other	considerations indicate	that	it	is	excessive.	The	complaint	requests	the	FERC	to	institute	proceedings	to	investigate	the	return	on	equity	and	establish	a	lower return	on	equity,	and	also	requests	that	the	FERC	establish	January	23,	2017	as	a	refund	effective	date.	The	complaint	includes	return	on	equity analysis	that	purports	to	establish	that	the	range	of	reasonable	return	on	equity	for	System	Energy	is	between	8.37%	and	8.67%.	System	Energy answered	the	complaint	in	February	2017	and	disputes	that	a	return	on	equity	of	8.37%	to	8.67%	is	just	and	reasonable.	The	LPSC	and	the	City Council	 intervened	 in	 the	proceeding	expressing	support	for	 the	complaint.	System	Energy	is	recording	a	provision	against	revenue	for	 the potential	outcome	of	this	proceeding.	In	September	2017	the	FERC	established	a	refund	effective	date	of	January	23,	2017,	consolidated	the	return on	equity	complaint	with	 the	proceeding	described	 in	Unit	Power	Sales	Agreement	below,	and	directed	 the	parties	 to	engage	 in	settlement proceedings	before	an	ALJ.	If	the	parties	fail	to	come	to	an	agreement	during	settlement	proceedings,	a	prehearing	conference	will	be	held	to establish	a	procedural	schedule	for	hearing	proceedings.

# Unit	Power	Sales	Agreement

In	August	2017,	System	Energy	submitted	to	the	FERC	proposed	amendments	to	the	Unit	Power	Sales	Agreement	pursuant	to	which System	Energy	sells	its	Grand	Gulf	capacity	and	energy	to	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans. The	filing	proposes	limited	amendments	to	the	Unit	Power	Sales	Agreement	to	adopt	(1)	updated	rates	for	use	in	calculating	Grand	Gulf	plant depreciation	and	amortization	expenses	and	(2)	updated	nuclear	decommissioning	cost	annual	revenue	requirements,	both	of	which	are	recovered through	 the	 Unit	 Power	 Sales	 Agreement	 rate	 formula.	The	 proposed	 amendments	 would	 result	 in	 lower	 charges	 to	 the	 Utility	 operating companies	that	buy	capacity	and	energy	from	System	Energy	under	the	Unit	Power	Sales	Agreement.	The	proposed	changes	are	based	on	updated depreciation	and	nuclear	decommissioning	studies	 that	 take	 into	account	 the	renewal	of	Grand	Gulf's	operating	 license	for	a	 term	 through November	1,	2044.	System	Energy	requested	that	the	FERC	accept	the	amendments	effective	October	1,	2017.

In	 September	 2017	 the	 FERC	 accepted	 System	 Energy's	 proposed	 Unit	 Power	 Sales	 Agreement	 amendments,	 subject	 to	 further proceedings	to	consider	the	justness	and	reasonableness	of	the	amendments.	Because	the	amendments	propose	a	rate	decrease,	the	FERC	also initiated	an	investigation	under	Section	206	of	the	Federal	Power	Act	to	determine	if	the	rate	decrease	should	be	lower	than	proposed.	The	FERC accepted	the	proposed	amendments	effective	October	1,	2017,	subject	to	refund	pending	the	outcome	of	the	further	settlement	and/or	hearing proceedings,	and	established	a	refund	effective	date	of	October	11,	2017	with	respect	to	the	rate	decrease.	The	FERC	also	consolidated	the	Unit Power	Sales	Agreement	amendment	proceeding	with	the	proceeding	described	in	Complaint	Against	System	Energy	above,	and	directed	the parties	to	engage	in	settlement	proceedings	before	an	ALJ.	If	the	parties	fail	to	come	to	an	agreement	during	settlement	proceedings,	a	prehearing conference	will	be	held	to	establish	a	procedural	schedule	for	hearing	proceedings.

# Storm	Cost	Recovery	Filings	with	Retail	Regulators

# Hurricane	Isaac

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	June	2014	the	LPSC authorized	Entergy	Louisiana	to	utilize	Louisiana	Act	55	financing	for	Hurricane	Isaac	system	restoration	costs.		Entergy	Louisiana	committed	to pass	on	to	customers	a	minimum	of	$30.8	million	of	customer	benefits	through	annual	customer	credits	of	approximately	$6.2	million	for	five years.	Approvals	for	the	Act	55	financings	were	obtained	from	the	Louisiana	Utilities	Restoration	Corporation	(LURC)	and	the	Louisiana	State Bond	Commission.

In	August	 2014	 the	 Louisiana	 Local	 Government	 Environmental	 Facilities	 and	 Community	 Development	Authority	 (LCDA)	 issued $314.85	million	in	bonds	under	Louisiana	Act	55.		From	the	 $309	million	of	bond	proceeds	loaned	by	the	LCDA	to	the	LURC,	the	LURC deposited	$16	million	in	a	restricted	escrow	account	as	a	storm	damage	reserve	for	Entergy	Louisiana	and	transferred	 $293	million	directly	to Entergy	Louisiana.		Entergy	Louisiana	used	the	$293	million	received	from	the	LURC	to	acquire	2,935,152.69	Class	C	preferred,	non-voting, membership	interest	units	of	Entergy	Holdings	Company	LLC,	a	company	wholly-owned	and	consolidated	by	Entergy,	that	carry	a	7.5%	annual distribution	rate.	Distributions	are	payable	quarterly	commencing	on	September	15,	2014,	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	$1.75	billion.

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

# Hurricane	Gustav	and	Hurricane	Ike

In	 September	 2008,	 Hurricane	 Gustav	 and	 Hurricane	 Ike	 caused	 catastrophic	 damage	 to	 Entergy	 Louisiana's	 service	 territory.	 In December	2009,	Entergy	Louisiana	entered	into	a	stipulation	agreement	with	the	LPSC	staff	regarding	its	storm	costs.		In	March	and	April	2010, Entergy	Louisiana	and	other	parties	to	the	proceeding	filed	with	the	LPSC	an	uncontested	stipulated	settlement	that	included	Entergy	Louisiana's proposal	to	utilize	Act	55	financing,	which	included	a	commitment	to	pass	on	to	customers	a	minimum	of	$43.3	million	of	customer	benefits through	a	prospective	annual	rate	reduction	of	$8.7	million	for	five	years.		In	April	2010	the	LPSC	approved	the	settlement	and	subsequently issued	financing	orders	and	a	ratemaking	order	intended	to	facilitate	the	implementation	of	the	Act	55	financings.		In	June	2010	the	Louisiana State	Bond	Commission	approved	the	Act	55	financing.	The	settlement	agreement	allowed	for	an	adjustment	to	the	credits	if	there	was	a	change	in the	applicable	federal	or	state	income	tax	rate.	As	a	result	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	and	the	lowering	of the	federal	corporate	income	tax	rate	from	35%	to	21%,	the	Louisiana	Act	55	financing	savings	obligation	regulatory	liability	related	to	Hurricane Gustav	and	Hurricane	Ike	was	reduced	by	$2.7	million,	with	a	corresponding	increase	to	Other	regulatory	credits	on	the	income	statement.	The effects	of	the	Tax	Cuts	and	Jobs	Act	are	discussed	further	in	Note	3	to	the	financial	statements.

In	July	2010,	the	LCDA	issued	two	series	of	bonds	totaling	$713.0	million	under	Act	55.		From	the	$702.7	million	of	bond	proceeds loaned	by	the	LCDA	to	the	LURC,	the	LURC	deposited	$290	million	in	a	restricted	escrow	account	as	a	storm	damage	reserve	for	Entergy Louisiana	and	transferred	$412.7	million	directly	to	Entergy	Louisiana.		From	the	bond	proceeds	received	by	Entergy	Louisiana	from	the	LURC, Entergy	Louisiana	used	$412.7	million	to	acquire	4,126,940.15	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.

# Hurricane	Katrina	and	Hurricane	Rita

In	August	and	September	2005,	Hurricanes	Katrina	and	Rita	caused	catastrophic	damage	to	Entergy	Louisiana's	service	territory.	In March	2008,	Entergy	Louisiana	and	the	LURC	filed	at	the	LPSC	an	application	requesting	that	the	LPSC	grant	a	financing	order	authorizing	the financing	of	Entergy	Louisiana	storm	costs,	storm	reserves,	and	issuance	costs	pursuant	to	Louisiana	Act	55.		The	Louisiana	Act	55	financing	is expected	to	produce	additional	customer	benefits	as	compared	to	traditional	securitization.		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.		In	April	2008 the	Louisiana	Public	Facilities	Authority	(LPFA),	which	is	the	issuer	of	the	bonds	pursuant	to	the	Act	55	financing,	approved	requests	for	the	Act 55	financing.		Also	in	April	2008,	Entergy	Louisiana	and	the	LPSC	staff	filed	with	the	LPSC	an	uncontested	stipulated	settlement	that	included Entergy	Louisiana's	proposal	under	the	Act	55	financing,	which	included	a	commitment	to	pass	on	to	customers	a	minimum	of	$40	million	of customer	benefits	through	a	prospective	annual	rate	reduction	of	$8	million	for	five	years.		The	LPSC	subsequently	approved	the	settlement	and issued	two	financing	orders	and	one	ratemaking	order	intended	to	facilitate	implementation	of	the	Act	55	financing.		In	May	2008	the	Louisiana State	Bond	Commission	granted	final	approval	of	the	Act	55	financing.	The	settlement	agreement	allowed	for	an	adjustment	to	the	credits	if	there was	a	change	in	the	applicable	federal	or	state	income	tax	rate.	As	a	result	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	and the	lowering	of	the	federal	corporate	income	tax	rate	from	35%	 to	21%,	the	Louisiana	Act	55	financing	savings	obligation	regulatory	liability related	to	Hurricanes	Katrina	and	Rita	was	reduced	by	$22.3	million,	with	a	corresponding	increase	to	Other	regulatory	credits	on	the	income statement.	The	effects	of	the	Tax	Cuts	and	Jobs	Act	are	discussed	further	in	Note	3	to	the	financial	statements.

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.		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	Louisiana	and	transferred	 $187.7	million	directly	to	Entergy Louisiana.		From	the	bond	proceeds	received	by	Entergy	Louisiana	from	the	LURC,	Entergy	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	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	and	Entergy	Louisiana	do	not	report	the	bonds	issued	by	the	LPFA	on	their	balance	sheets	because	the	bonds	are	the	obligation	of the	LPFA,	and	there	is	no	recourse	against	Entergy	or	Entergy	Louisiana	in	the	event	of	a	bond	default.		To	service	the	bonds,	Entergy	Louisiana collects	a	system	restoration	charge	on	behalf	of	the	LURC,	and	remits	the	collections	to	the	bond	indenture	trustee.	 	Entergy	and	Entergy Louisiana	do	not	report	the	collections	as	revenue	because	Entergy	Louisiana	is	merely	acting	as	the	billing	and	collection	agent	for	the	state.

Entergy	 Mississippi	 has	 approval	 from	 the	 MPSC	 to	 collect	 a	 storm	 damage	 provision	 of	 $1.75	 million	 per	 month.	If	 Entergy Mississippi's	accumulated	storm	damage	provision	balance	exceeds	$15	million,	the	collection	of	the	storm	damage	provision	ceases	until	such time	that	the	accumulated	storm	damage	provision	becomes	less	than	$10	million.	As	of	April	30,	2016,	Entergy	Mississippi's	storm	damage provision	balance	was	less	than	$10	million,	therefore	Entergy	Mississippi	resumed	billing	the	monthly	storm	damage	provision	effective	with June	 2016	 bills.	As	 of	 September	 30,	 2016,	 however,	 Entergy	 Mississippi's	 storm	 damage	 provision	 balance	 again	 exceeded	$15	 million. Accordingly	the	storm	damage	provision	was	reset	to	zero	beginning	with	November	2016	bills.	As	of	July	31,	2017,	the	balance	in	Entergy Mississippi's	accumulated	storm	damage	provision	was	again	less	than	$10	million,	therefore	Entergy	Mississippi	resumed	billing	the	monthly storm	damage	provision	effective	with	September	2017	bills.

In	August	2012,	Hurricane	Isaac	caused	extensive	damage	to	Entergy	New	Orleans's	service	area.	In	January	2015	the	City	Council	issued a	resolution	approving	the	terms	of	a	joint	agreement	 in	principle	filed	by	Entergy	New	Orleans,	Entergy	Louisiana,	and	 the	City	Council Advisors	determining,	among	other	things,	that	Entergy	New	Orleans's	prudently-incurred	storm	recovery	costs	were	$49.3	million,	of	which $31.7	 million,	 net	 of	 reimbursements	 from	 the	 storm	 reserve	 escrow	 account,	 remained	 recoverable	 from	 Entergy	 New	 Orleans's	 electric customers.	The	resolution	also	directed	Entergy	New	Orleans	to	file	an	application	to	securitize	the	unrecovered	City	Council-approved	storm recovery	costs	of	$31.7	million	pursuant	to	the	Louisiana	Electric	Utility	Storm	Recovery	Securitization	Act	(Louisiana	Act	64).	In	addition,	the resolution	found	that	it	was	reasonable	for	Entergy	New	Orleans	to	include	in	the	principal	amount	of	its	potential	securitization	the	costs	to	fund and	replenish	Entergy	New	Orleans's	storm	reserve	in	an	amount	that	achieved	the	City	Council-approved	funding	level	of	$75	million.	 In January	2015,	in	compliance	with	that	directive,	Entergy	New	Orleans	filed	with	the	City	Council	an	application	requesting	that	the	City	Council grant	a	financing	order	authorizing	the	financing	of	Entergy	New	Orleans's	storm	costs,	storm	reserves,	and	issuance	costs	pursuant	to	Louisiana Act	64.	In	May	2015	the	parties	entered	into	an	agreement	in	principle	and	the	City	Council	issued	a	financing	order	authorizing	Entergy	New Orleans	to	issue	storm	recovery	bonds	in	the	aggregate	amount	of	$98.7	million,	including	$31.8	million	for	recovery	of	Entergy	New	Orleans's Hurricane	Isaac	storm	recovery	costs,	including	carrying	costs,	$63.9	million	to	fund	and	replenish	Entergy	New	Orleans's	storm	reserve,	and approximately	$3	million	for	estimated	up-front	financing	costs	associated	with	the	securitization.	See	Note	5	to	the	financial	statements	for discussion	of	the	issuance	of	the	securitization	bonds	in	July	2015.

# New	Nuclear	Generation	Development	Costs

Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	were	developing	a	project	option	for	new	nuclear	generation	at	River	Bend.		In March	2010,	Entergy	Louisiana	and	Entergy	Gulf	States	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.		At	its	June	2012	meeting	the	LPSC	voted	to	uphold	an	ALJ recommendation	that	the	request	of	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	be	declined	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.		The	LPSC	directed	that	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	be permitted	to	seek	recovery	of	these	costs	in	their	upcoming	rate	case	filings	that	were	subsequently	filed	in	February	2013.	In	the	resolution	of	the rate	case	proceeding	the	LPSC	provided	for	an	eight-year	amortization	of	costs	incurred	in	connection	with	the	potential	development	of	new nuclear	generation	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,	2017,	Entergy	Louisiana	has	a	regulatory	asset	of	$35.8	million	on	its	balance	sheet related	to	these	new	nuclear	generation	development	costs.

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

Income	taxes	for	2017,	2016,	and	2015	for	Entergy	Corporation	and	Subsidiaries	consist	of	the	following:

| Federal | $29,595 | $45,249 | $77,166 |
| :--- | :--- | :--- | :--- |
| Foreign | — | 68 | 97 |
| State | 15,478 | (14,960) | 157,829 |
| Total | 45,073 | 30,357 | 235,092 |
| Deferred\tand\tnon-current\t-\tnet | 505,010 | (840,465) | (864,799) |
| Investment\ttax\tcredit\tadjustments\t-\tnet | (7,513) | (7,151) | (13,220) |
| Income\ttaxes | $542,570 | ($817,259) | ($642,927) |

Income	taxes	for	2017,	2016,	and	2015	for	Entergy's	Registrant	Subsidiaries	consist	of	the	following:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Current: |  |  |  |  |  |  |
| Federal | $16,086 | ($84,250) | ($8,845) | ($30,635) | $6,034 | $47,674 |
| State | 9,191 | 1,480 | (924) | (728) | 310 | 5,314 |
| Total | 25,277 | (82,770) | (9,769) | (31,363) | 6,344 | 52,988 |
| Deferred\tand\tnon-current\t-\tnet | 69,753 | 572,988 | 83,501 | 62,946 | 43,102 | 19,243 |
| Investment\ttax\tcredit\tadjustments\t-\tnet | (1,226) | (4,920) | 187 | 1,695 | (965) | (2,262) |
| Income\ttaxes | $93,804 | $485,298 | $73,919 | $33,278 | $48,481 | $69,969 |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |
| Federal | ($14,748) | ($124,113) | $10,603 | ($91,067) | $19,656 | $29,628 |
| State | 2,805 | 10,757 | 2,257 | 566 | 1,374 | (25,825) |
| Total | (11,943) | (113,356) | 12,860 | (90,501) | 21,030 | 3,803 |
| Deferred\tand\tnon-current\t-\tnet | 120,942 | 208,157 | 46,984 | 119,345 | 42,982 | 71,051 |
| Investment\ttax\tcredit\tadjustments\t-\tnet | (1,226) | (5,067) | 4,010 | (139) | (915) | (3,793) |
| Income\ttaxes | $107,773 | $89,734 | $63,854 | $28,705 | $63,097 | $71,061 |

| 2015 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Current: |  |  |  |  |  |  |
| Federal | $66,966 | $101,382 | $25,628 | ($9,346) | $53,313 | ($63,302) |
| State | 6,265 | 35,406 | 6,832 | 1,784 | 2,450 | 26,755 |
| Total | 73,231 | 136,788 | 32,460 | (7,562) | 55,763 | (36,547) |
| Deferred\tand\tnon-current\t-\tnet | (31,463) | 47,220 | 31,149 | 32,890 | (17,599) | 93,491 |
| Investment\ttax\tcredit\tadjustments\t-\tnet | (1,227) | (5,337) | (1,737) | (138) | (914) | (3,867) |
| Income\ttaxes | $40,541 | $178,671 | $61,872 | $25,190 | $37,250 | $53,077 |

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	2017,	2016,	and	2015	are:

| Net	income	(loss)	attributable	to	Entergy	Corporation | $411,612 | ($583,618) | ($176,562) |
| :--- | :--- | :--- | :--- |
| Preferred\tdividend\trequirements\tof\tsubsidiaries | 13,741 | 19,115 | 19,828 |
| Consolidated\tnet\tincome\t(loss) | 425,353 | (564,503) | (156,734) |
| Income\ttaxes | 542,570 | (817,259) | (642,927) |
| Income\t(loss)\tbefore\tincome\ttaxes | $967,923 | ($1,381,762) | ($799,661) |
| Computed\tat\tstatutory\trate\t(35%) | $338,773 | ($483,617) | ($279,881) |
| Increases\t(reductions)\tin\ttax\tresulting\tfrom: |  |  |  |
| State\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffect | 44,179 | 40,581 | 29,944 |
| Regulatory\tdifferences\t-\tutility\tplant\titems | 39,825 | 33,581 | 32,089 |
| Equity\tcomponent\tof\tAFUDC | (33,282) | (23,647) | (18,191) |
| Amortization\tof\tinvestment\ttax\tcredits | (10,204) | (10,889) | (11,136) |
| Flow-through\t/\tpermanent\tdifferences | 8,727 | (19,307) | (7,872) |
| Tax\tlegislation\tenactment\t(a) | 560,410 | — | — |
| Louisiana\tbusiness\tcombination | — | — | (333,655) |
| Entergy\tWholesale\tCommodities\trestructuring\t(b) | (373,277) | (237,760) | — |
| Act\t55\tfinancing\tsettlement\t(d) | — | (63,477) | — |
| FitzPatrick\tdisposition | (44,344) | — | — |
| Provision\tfor\tuncertain\ttax\tpositions\t(c)\t(d) | 8,756 | (67,119) | (56,683) |
| Valuation\tallowance | — | 11,411 | — |
| Other\t-\tnet | 3,007 | 2,984 | 2,458 |
| Total\tincome\ttaxes\tas\treported | $542,570 | ($817,259) | ($642,927) |
| Effective\tIncome\tTax\tRate | 56.1% | 59.1% | 80.4% |

(a) See	"Other	Tax	Matters	-	Tax	Cuts	and	Jobs	Act"	below	for	discussion	of	the	tax	legislation	enactment.

(b) See	"Other	 Tax	 Matters -	Entergy	 Wholesale	 Commodities	 Restructuring"	 below for	 discussion	 of the	 Entergy	 Wholesale Commodities	restructuring.

(c) See	"Income	Tax	Audits	-	2008-2009	IRS	Audit"	below	for	discussion	of	the	most	significant	items	for	2015.

(d) See	"Income	Tax	Audits	-	2010-2011	IRS	Audit"	below	for	discussion	of	the	most	significant	items	for	2016.

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	2017,	2016,	and	2015	are:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $139,844 | $316,347 | $110,032 | $44,553 | $76,173 | $78,596 |
| Income\ttaxes | 93,804 | 485,298 | 73,919 | 33,278 | 48,481 | 69,969 |
| Pretax\tincome | $233,648 | $801,645 | $183,951 | $77,831 | $124,654 | $148,565 |
| Computed\tat\tstatutory\trate\t(35%) | $81,777 | $280,576 | $64,383 | $27,241 | $43,629 | $51,998 |
| Increases\t(reductions)\tin\ttax\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffect | 11,586 | 31,927 | 6,202 | 2,842 | 527 | 5,635 |
| Regulatory\tdifferences\t-\tutility\tplant\titems | 7,220 | 12,168 | 1,356 | 619 | 5,581 | 12,880 |
| Equity\tcomponent\tof\tAFUDC | (6,458) | (18,020) | (3,383) | (847) | (2,353) | (2,221) |
| Amortization\tof\tinvestment\ttax\tcredits | (1,201) | (4,871) | (160) | (124) | (951) | (2,896) |
| Flow-through\t/\tpermanent\tdifferences | 3,098 | 3,774 | 1,567 | (3,352) | 1,428 | (276) |
| Tax\tlegislation\tenactment\t(a) | (3,090) | 217,258 | 3,492 | 6,153 | 2,981 | (69) |
| Non-taxable\tdividend\tincome | — | (44,658) | — | — | — | — |
| Provision\tfor\tuncertain\ttax\tpositions | 200 | 5,700 | 228 | 600 | (2,617) | 4,800 |
| Other\t-\tnet | 672 | 1,444 | 234 | 146 | 256 | 118 |
| Total\tincome\ttaxes\tas\treported | $93,804 | $485,298 | $73,919 | $33,278 | $48,481 | $69,969 |
| Effective\tIncome\tTax\tRate | 40.1% | 60.5% | 40.2% | 42.8% | 38.9% | 47.1% |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $167,212 | $622,047 | $109,184 | $48,849 | $107,538 | $96,744 |
| Income\ttaxes | 107,773 | 89,734 | 63,854 | 28,705 | 63,097 | 71,061 |
| Pretax\tincome | $274,985 | $711,781 | $173,038 | $77,554 | $170,635 | $167,805 |
| Computed\tat\tstatutory\trate\t(35%) | $96,245 | $249,123 | $60,563 | $27,144 | $59,722 | $58,732 |
| Increases\t(reductions)\tin\ttax\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffect | 11,652 | 29,014 | 5,592 | 3,543 | 449 | 7,001 |
| Regulatory\tdifferences\t-\tutility\tplant\titems | 10,971 | 8,094 | (1,154) | 2,329 | 4,140 | 9,201 |
| Equity\tcomponent\tof\tAFUDC | (5,985) | (9,774) | (2,030) | (412) | (2,666) | (2,780) |
| Amortization\tof\tinvestment\ttax\tcredits | (1,201) | (5,019) | (160) | (132) | (900) | (3,476) |
| Flow-through\t/\tpermanent\tdifferences | (3,848) | (980) | 764 | (3,609) | 634 | (883) |
| Act\t55\tfinancing\tsettlement\t(b) | — | (61,620) | — | — | (454) | — |
| Non-taxable\tdividend\tincome | — | (44,658) | — | — | — | — |
| Provision\tfor\tuncertain\ttax\tpositions\t(b) | (717) | (75,871) | 50 | (300) | 1,926 | 3,151 |
| Other\t-\tnet | 656 | 1,425 | 229 | 142 | 246 | 115 |
| Total\tincome\ttaxes\tas\treported | $107,773 | $89,734 | $63,854 | $28,705 | $63,097 | $71,061 |
| Effective\tIncome\tTax\tRate | 39.2% | 12.6% | 36.9% | 37.0% | 37.0% | 42.3% |

| 2015 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Net\tincome | $74,272 | $446,639 | $92,708 | $44,925 | $69,625 | $111,318 |
| Income\ttaxes | 40,541 | 178,671 | 61,872 | 25,190 | 37,250 | 53,077 |
| Pretax\tincome | $114,813 | $625,310 | $154,580 | $70,115 | $106,875 | $164,395 |
| Computed\tat\tstatutory\trate\t(35%) | $40,185 | $218,859 | $54,103 | $24,540 | $37,406 | $57,538 |
| Increases\t(reductions)\tin\ttax\tresulting\tfrom: |  |  |  |  |  |  |
| State\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffect | 6,643 | 23,650 | 5,219 | 2,887 | 1,621 | 6,403 |
| Regulatory\tdifferences\t-\tutility\tplant\titems | 7,299 | 3,013 | 2,383 | 2,201 | 3,703 | 12,167 |
| Equity\tcomponent\tof\tAFUDC | (4,979) | (5,420) | (1,083) | (451) | (1,987) | (2,973) |
| Amortization\tof\tinvestment\ttax\tcredits | (1,201) | (5,252) | (160) | (111) | (900) | (3,476) |
| Flow-through\t/\tpermanent\tdifferences | (4,062) | 2,460 | 431 | (4,539) | 530 | 618 |
| Non-taxable\tdividend\tincome | — | (44,658) | — | — | — | — |
| Provision\tfor\tuncertain\ttax\tpositions\t(c) | (3,978) | (15,377) | 756 | 525 | (3,365) | (17,313) |
| Other\t-\tnet | 634 | 1,396 | 223 | 138 | 242 | 113 |
| Total\tincome\ttaxes\tas\treported | $40,541 | $178,671 | $61,872 | $25,190 | $37,250 | $53,077 |
| Effective\tIncome\tTax\tRate | 35.3% | 28.6% | 40.0% | 35.9% | 34.9% | 32.3% |

(b) See	"Income	Tax	Audits	-	2010-2011	IRS	Audit"	below	for	discussion	of	the	most	significant	items	for	Entergy	Louisiana.

(c) See	"Income	Tax	Audits	-	2008-2009	IRS	Audit"	below	for	discussion	of	the	most	significant	items	for	Entergy	Louisiana	and	System Energy.

Significant	 components	 of	 accumulated	 deferred income taxes	 and taxes	 accrued for	 Entergy	 Corporation	 and	 Subsidiaries	 as	 of December	31,	2017	and	2016	are	as	follows:

| Plant	basis	differences	-	net | ($3,963,798) | ($6,362,905) |
| :--- | :--- | :--- |
| Regulatory\tassets | — | (584,572) |
| Nuclear\tdecommissioning\ttrusts/receivables | (1,657,808) | (1,739,977) |
| Pension,\tnet\tfunding | (350,743) | (429,896) |
| Combined\tunitary\tstate\ttaxes | (24,645) | (33,063) |
| Power\tpurchase\tagreements | (19,621) | (993) |
| Other | (249,327) | (251,719) |
| Total | (6,265,942) | (9,403,125) |
| Deferred\ttax\tassets: |  |  |
| Nuclear\tdecommissioning\tliabilities | 964,945 | 1,399,468 |
| Regulatory\tliabilities | 841,370 | 255,272 |
| Pension\tand\tother\tpost-employment\tbenefits | 343,817 | 539,456 |
| Sale\tand\tleaseback | 122,397 | 135,866 |
| Compensation | 75,217 | 99,300 |
| Accumulated\tdeferred\tinvestment\ttax\tcredit | 59,285 | 92,375 |
| Provision\tfor\tallowances\tand\tcontingencies | 126,391 | 188,390 |
| Net\toperating\tloss\tcarryforwards | 467,255 | 334,025 |
| Capital\tlosses\tand\tmiscellaneous\ttax\tcredits | 16,738 | 18,470 |
| Valuation\tallowance | (137,283) | (104,277) |
| Other | 54,058 | 59,079 |
| Total | 2,934,190 | 3,017,424 |
| Non-current\taccrued\ttaxes\t(including\tunrecognized\ttax\tbenefits) | (956,547) | (991,704) |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | ($4,288,299) | ($7,377,405) |

Entergy's	estimated	tax	attributes	carryovers	and	their	expiration	dates	as	of	December	31,	2017	are	as	follows:

| Carryover	Description | Carryover	Amount | Year(s)	of	expiration |
| :--- | :--- | :--- |
| Federal\tnet\toperating\tlosses | $10.7\tbillion | 2023-2037 |
| State\tnet\toperating\tlosses | $9.6\tbillion | 2018-2037 |
| Miscellaneous\tfederal\tand\tstate\tcredits | $96.6\tmillion | 2018-2036 |

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	and	credit	carryovers	will	not	be utilized,	valuation	allowances	of	$106	million	as	of	December	31,	2017	and	$62	million	as	of	December	31,	2016	have	been	provided	on	the deferred	tax	assets	relating	to	these	state	net	operating	loss	and	credit	carryovers.	Additionally,	valuation	allowances	totaling	$31	million	as	of December	31,	2017	and	$42.3	million	as	of	December	31,	2016	have	been	provided	on	deferred	tax	assets	related	to	federal	and	state	jurisdictions in	which	Entergy	does	not	currently	expect	to	be	able	to	utilize	separate	company	tax	return	losses,	preventing	realization	of	such	deferred	tax assets.

Significant	components	of	accumulated	deferred	income	taxes	and	taxes	accrued	for	the	Registrant	Subsidiaries	as	of	 December	31,	2017 and	2016	are	as	follows:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Deferred\ttax\tliabilities: |  |  |  |  |  |  |
| Plant\tbasis\tdifferences\t-\tnet | ($1,289,827) | ($1,583,100) | ($571,682) | ($85,515) | ($526,596) | ($359,931) |
| Nuclear\tdecommissioning\ttrusts/receivables | (181,911) | (164,395) | — | — | — | (119,184) |
| Pension,\tnet\tfunding | (99,971) | (102,138) | (26,413) | (13,040) | (20,700) | (21,871) |
| Deferred\tfuel | (16,530) | (1,329) | (19,005) | (1,894) | — | (272) |
| Other | (23,079) | (98,307) | (11,306) | (23,610) | (8,236) | (5,955) |
| Total | (1,611,318) | (1,949,269) | (628,406) | (124,059) | (555,532) | (507,213) |
| Deferred\ttax\tassets: |  |  |  |  |  |  |
| Regulatory\tliabilities | 227,489 | 368,156 | 102,676 | 23,526 | 25,428 | 91,271 |
| Nuclear\tdecommissioning\tliabilities | 132,464 | 58,891 | — | — | — | 63,180 |
| Pension\tand\tother\tpost-employment\tbenefits | (16,252) | 98,596 | (4,865) | (9,618) | (12,044) | (516) |
| Sale\tand\tleaseback | — | 19,915 | — | — | — | 102,482 |
| Accumulated\tdeferred\tinvestment\ttax\tcredit | 8,913 | 35,323 | 2,212 | 488 | 2,516 | 9,832 |
| Provision\tfor\tallowances\tand\tcontingencies | 4,367 | 80,516 | 11,898 | 24,234 | 4,383 | — |
| Power\tpurchase\tagreements | — | (6,924) | 1,129 | — | — | — |
| Unbilled/deferred\trevenues | 6,195 | (18,263) | 4,847 | 1,811 | 7,736 | — |
| Compensation | 2,566 | 4,387 | 1,466 | 723 | 1,224 | 332 |
| Net\toperating\tloss\tcarryforwards | 16,172 | 44 | 10,255 | — | 1,690 | — |
| Capital\tlosses\tand\tmiscellaneous\ttax\tcredits | 2,678 | — | 5,736 | — | — | — |
| Other | 473 | 21,922 | 1,307 | 388 | 1,133 | — |
| Total | 385,065 | 662,563 | 136,661 | 41,552 | 32,066 | 266,581 |
| Non-current\taccrued\ttaxes\t(including\nunrecognized\ttax\tbenefits) | 35,584 | (763,665) | 2,939 | (200,795) | (21,176) | (535,788) |
| Accumulated\tdeferred\tincome\ttaxes\tand\ntaxes\taccrued | ($1,190,669) | ($2,050,371) | ($488,806) | ($283,302) | ($544,642) | ($776,420) |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Deferred\ttax\tliabilities: |  |  |  |  |  |  |
| Plant\tbasis\tdifferences\t-\tnet | ($1,857,554) | ($2,357,599) | ($820,971) | ($177,242) | ($835,671) | ($651,394) |
| Regulatory\tassets | (109,241) | (219,750) | (25,309) | (36,301) | (153,914) | (39,879) |
| Nuclear\tdecommissioning\ttrusts | (144,250) | (119,544) | — | — | — | (83,891) |
| Pension,\tnet\tfunding | (123,889) | (122,465) | (34,284) | (16,307) | (28,371) | (29,357) |
| Deferred\tfuel | (14,774) | (1,778) | (12,770) | (5,229) | (2,808) | (1,137) |
| Power\tpurchase\tagreements | — | — | — | — | — | — |
| Other | (47,785) | (22,136) | (12,474) | (18,536) | (8,812) | (2,051) |
| Total | (2,297,493) | (2,843,272) | (905,808) | (253,615) | (1,029,576) | (807,709) |
| Deferred\ttax\tassets: |  |  |  |  |  |  |
| Regulatory\tliabilities | 5,768 | 175,973 | 18,833 | 25,240 | 15,814 | 13,644 |
| Nuclear\tdecommissioning\tliabilities | 124,206 | 55,408 | — | — | — | 53,113 |
| Pension\tand\tother\tpost-employment\nbenefits | (24,467) | 145,401 | (8,042) | (12,070) | (19,096) | (1,182) |
| Sale\tand\tleaseback | — | 33,383 | — | — | — | 102,483 |
| Accumulated\tdeferred\tinvestment\ttax\ncredit | 13,848 | 54,509 | 3,315 | 239 | 4,527 | 15,936 |
| Provision\tfor\tallowances\tand\ncontingencies | (1,497) | 124,309 | 21,817 | 36,466 | 5,904 | — |
| Power\tpurchase\tagreements | (3,094) | 29,827 | 1,905 | — | 140 | — |
| Unbilled/deferred\trevenues | 6,799 | (35,006) | 5,085 | 3,751 | 11,902 | — |
| Compensation | 2,787 | 5,309 | 1,492 | 685 | 1,587 | 360 |
| Net\toperating\tloss\tcarryforwards | 69,524 | 17,125 | — | — | — | — |
| Capital\tlosses\tand\tmiscellaneous\ttax\ncredits | 2,074 | — | 4,487 | — | — | — |
| Other | 174 | 17,110 | 1,152 | 496 | 2,955 | — |
| Total | 196,122 | 623,348 | 50,044 | 54,807 | 23,733 | 184,354 |
| Non-current\taccrued\ttaxes\t(including\nunrecognized\ttax\tbenefits) | (85,252) | (471,194) | (5,567) | (136,145) | (21,804) | (489,510) |
| Accumulated\tdeferred\tincome\ttaxes\nand\ttaxes\taccrued | ($2,186,623) | ($2,691,118) | ($861,331) | ($334,953) | ($1,027,647) | ($1,112,865) |

The	Registrant	Subsidiaries'	estimated	tax	attributes	carryovers	and	their	expiration	dates	as	of	December	31,	2017	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:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Gross\tbalance\tat\tJanuary\t1 | $3,909,855 | $2,611,585 | $4,736,785 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\tcurrent\tyear | 1,120,687 | 1,532,782 | 1,850,705 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 283,683 | 368,404 | 59,815 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears\t(a) | (442,379) | (265,653) | (3,966,535) |
| Settlements | — | (337,263) | (68,227) |
| Lapse\tof\tstatute\tof\tlimitations | — | — | (958) |
| Gross\tbalance\tat\tDecember\t31 | 4,871,846 | 3,909,855 | 2,611,585 |
| Offsets\tto\tgross\tunrecognized\ttax\tbenefits: |  |  |  |
| Carryovers\tand\trefund\tclaims | (3,945,524) | (2,922,085) | (1,264,483) |
| Cash\tpaid\tto\ttaxing\tauthorities | (10,000) | (10,000) | — |
| Unrecognized\ttax\tbenefits\tnet\tof\tunused\ttax\tattributes,\trefund\tclaims\tand\tpayments\t(b) | $916,322 | $977,770 | $1,347,102 |

(a) The	primary	reduction	for	2015	is	related	to	the	nuclear	decommissioning	costs	treatment	discussed	in	" Income	Tax	Audits	-	2008-2009 IRS	Audit"	below.

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

The	balances	of	unrecognized	tax	benefits	include	$1,462	million,	$1,240	million,	and	$955	million	as	of	December	31,	2017,	2016,	and 2015,	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	$3,410	million,	$2,670	million,	and	$1,657	million	as	of	December	31,	2017,	2016,	and	2015, 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	accrues	interest	expense,	if	any,	related	to	unrecognized	tax	benefits	in	income	tax	expense.		Entergy's	December	31,	2017,	2016, and	2015	accrued	balance	for	the	possible	payment	of	interest	is	approximately	$38	million,	$30	million,	and	$27	million,	respectively.

A	reconciliation	of	the	Registrant	Subsidiaries'	beginning	and	ending	amount	of	unrecognized	tax	benefits	for	 2017,	2016,	and	2015	is	as follows:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\t1,\t2017 | $2,503 | $2,440,339 | $12,206 | $166,230 | $15,946 | $472,372 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\ncurrent\tyear\t(a) | 8,974 | 32,843 | 2,105 | 509,183 | 1,747 | 909 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 3,682 | 235,331 | 1,267 | 13,364 | 3,115 | 1,432 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (132,875) | (190,056) | (456) | (9,233) | (4,409) | (29,202) |
| Gross\tbalance\tat\tDecember\t31,\t2017 | (117,716) | 2,518,457 | 15,122 | 679,544 | 16,399 | 445,511 |
| Offsets\tto\tgross\tunrecognized\ttax\tbenefits: |  |  |  |  |  |  |
| Loss\tcarryovers | — | (1,591,907) | (15,122) | (441,374) | (638) | (12,536) |
| Unrecognized\ttax\tbenefits\tnet\tof\tunused\ttax\nattributes\tand\tpayments | ($117,716) | $926,550 | $— | $238,170 | $15,761 | $432,975 |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\t1,\t2016 | $25,445 | $1,690,661 | $19,482 | $53,897 | $13,462 | $478,318 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\ncurrent\tyear\t(a) | 16,868 | 931,720 | 2,662 | 33,912 | 2,002 | 5,318 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 2,463 | 157,586 | 336 | 129,784 | 2,888 | 601 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (41,957) | (144,068) | (10,219) | (29,821) | (1,849) | (10,266) |
| Settlements | (316) | (195,560) | (55) | (21,542) | (557) | (1,599) |
| Gross\tbalance\tat\tDecember\t31,\t2016 | 2,503 | 2,440,339 | 12,206 | 166,230 | 15,946 | 472,372 |
| Offsets\tto\tgross\tunrecognized\ttax\tbenefits: |  |  |  |  |  |  |
| Loss\tcarryovers | — | (1,783,093) | (2,373) | (27,320) | (376) | (90,028) |
| Unrecognized\ttax\tbenefits\tnet\tof\tunused\ttax\nattributes\tand\tpayments | $2,503 | $657,246 | $9,833 | $138,910 | $15,570 | $382,344 |

| 2015 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Gross\tbalance\tat\tJanuary\t1,\t2015 | $362,912 | $1,205,929 | $20,144 | $53,763 | $17,264 | $258,242 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\ncurrent\tyear\t(b) | 2,196 | 1,367,058 | 566 | 472 | 657 | 472,304 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 1,057 | 7,992 | 8,140 | 48 | 2,914 | 913 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (340,720) | (859,430) | — | (386) | (3,981) | (253,141) |
| Settlements | — | (30,888) | (9,368) | — | (3,392) | — |
| Gross\tbalance\tat\tDecember\t31,\t2015 | 25,445 | 1,690,661 | 19,482 | 53,897 | 13,462 | 478,318 |
| Offsets\tto\tgross\tunrecognized\ttax\tbenefits: |  |  |  |  |  |  |
| Loss\tcarryovers | (3,613) | (893,764) | (1,016) | (506) | (276) | (133,611) |
| Unrecognized\ttax\tbenefits\tnet\tof\tunused\ttax\nattributes\tand\tpayments | $21,832 | $796,897 | $18,466 | $53,391 | $13,186 | $344,707 |

(a) The	primary	additions	for	Entergy	Louisiana	in	2016	and	for	Entergy	New	Orleans	in	2017	are	related	to	the	mark-to-market	treatment discussed	in	"Other	Tax	Matters	-	Tax	Accounting	Methods"	below.

(b) The	primary	addition	for	Entergy	Louisiana	and	System	Energy	is	related	to	the	nuclear	decommissioning	costs	treatment	discussed	in "Other	Tax	Matters	-	Tax	Accounting	Methods"	below.

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

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Entergy\tArkansas | $2.6 | $3.6 | $4.5 |
| Entergy\tLouisiana | $575.8 | $473.3 | $692.7 |
| Entergy\tMississippi | $— | $— | $8.1 |
| Entergy\tNew\tOrleans | $31.7 | $33.6 | $50.7 |
| Entergy\tTexas | $4.4 | $7.0 | $5.2 |
| System\tEnergy | $— | $— | $0.7 |

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:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Entergy\tArkansas | $1.6 | $1.4 | $1.3 |
| Entergy\tLouisiana | $14.1 | $8.4 | $9.3 |
| Entergy\tMississippi | $1.0 | $0.8 | $0.4 |
| Entergy\tNew\tOrleans | $2.1 | $1.5 | $1.8 |
| Entergy\tTexas | $0.4 | $1.2 | $1.2 |
| System\tEnergy | $8.5 | $3.7 | $0.7 |

# Income	Tax	Audits

Entergy	and	its	subsidiaries	file	U.S.	federal	and	various	state	and	foreign	income	tax	returns.		IRS	examinations	are	complete	for	years before	2012.	All	state	taxing	authorities'	examinations	are	complete	for	years	before	2010.	Entergy	regularly	negotiates	with	the	IRS	to	achieve settlements.		The	resolution	of	audit	issues	could	result	in	significant	changes	to	the	amounts	of	unrecognized	tax	benefits	in	the	next	twelve months.

In	the	first	quarter	2015,	the	IRS	finalized	tax	and	interest	computations	from	the	2006-2007	audit	that	resulted	in	a	reversal	of	Entergy's provision	for	uncertain	tax	positions	related	to	accrued	interest	of	approximately	$20	million,	including	decreases	of	approximately	$4	million	for Entergy	Arkansas,	$11	million	for	Entergy	Louisiana,	and	$1	million	for	System	Energy.

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	Revenue	Agent	Report	(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	 disagreed	 with	 the	 IRS's disallowance	of	the	2009	CAM	and	filed	a	protest	with	the	IRS	Appeals	Division	in	October	2013.

In	August	2015,	Entergy	and	the	IRS	agreed	on	the	treatment	of	the	2009	position	regarding	nuclear	decommissioning	liabilities	from	the 2008-2009	audit.	The	agreement	provides	that	Entergy	is	entitled	to	deduct	approximately	$118	million	of	the	$9.3	billion	claimed	in	2009.	The agreement	effectively	settled	all	matters	pertaining	to	the	2009	tax	year	and	increased	Entergy's	2009	federal	income	tax	liability	by	$2.4	million.

The	IRS	completed	its	examination	of	the	2010	and	2011	tax	years	and	issued	its	2010-2011	RAR	in	June	2016.	Entergy	agreed	to	all proposed	 adjustments	 contained	 in	 the	 RAR.	As	a	result	of	 the	 issuance	of	 the	RAR,	Entergy	Louisiana	was	able	 to	recognize	previously unrecognized	tax	benefits	as	follows:

•Entergy	and	the	IRS	agreed	that	$148.6	million	of	the	proceeds	received	by	Entergy	Louisiana	in	2010	from	the	Louisiana	Utilities Restoration	Corporation	(LURC),	an	instrumentality	of	the	State	of	Louisiana,	for	the	financing	of	Hurricane	Gustav	and	Hurricane Ike	storm	costs	pursuant	to	Act	55	of	the	Louisiana	Regular	Session	of	2007	(Louisiana	Act	55)	were	not	taxable.	Because	 the treatment	of	the	financing	is	settled,	Entergy	recognized	previously	unrecognized	tax	benefits	totaling	$63.5	million,	of	which	Entergy Louisiana	recorded	$61.6	million.	Entergy	Louisiana	also	accrued	a	regulatory	liability	of	$16.1	million	($9.9	million	net-of-tax)	in accordance	 with	 the	 terms	 of	 Entergy	 Louisiana's	 previous	 settlement	 agreement	 approved	 by	 the	 LPSC	 regarding	 Entergy Louisiana's	obligation	to	pay	to	customers	savings	associated	with	the	Act	55	financing.

•Entergy	and	the	IRS	agreed	upon	the	tax	treatment	of	Entergy	Louisiana's	regulatory	liability	related	to	the	Vidalia	purchased	power agreement.	As	a	result,	Entergy	Louisiana	recognized	a	previously	unrecognized	tax	benefit	of	$74.5	million.

# Other	Tax	Matters

# Tax	Cuts	and	Jobs	Act

Deferred	tax	liabilities	and	assets	have	been	adjusted	for	the	effect	of	the	enactment	of	H.R.	1,	also	known	as	the	Tax	Cuts	and	Jobs	Act (the	Act),	signed	by	President	Trump	on	December	22,	2017.	The	most	significant	effect	of	the	Act	for	Entergy	and	the	Registrant	Subsidiaries	is the	change	in	the	federal	corporate	income	tax	rate	from	35%	to	21%,	effective	January	1,	2018.	Other	significant	provisions	and	their	effect	on Entergy	and	the	Registrant	Subsidiaries	are	summarized	below.

The	Act	limits	the	deduction	for	net	business	interest	expense	in	certain	circumstances.	The	new	limitation	does	not	apply	to	interest expense,	however,	that	is	properly	allocable	to	a	trade	or	business	that	furnishes	or	sells	electrical	energy,	gas,	or	steam	through	a	local	distribution system,	or	 transports	gas	or	steam	by	pipeline	 if	 the	rates	for	such	furnishing	or	sale	are	subject	 to	ratemaking	by	a	government	entity	or instrumentality	or	by	a	public	utility	commission.	Accordingly,	the	potential	interest	expense	disallowance	is	not	expected	to	have	a	material effect	on	Entergy's	or	the	Registrant	Subsidiaries'	interest	deductions.

The	Act	extends	and	modifies	the	additional	first-year	depreciation	deduction	(bonus	depreciation).	The	Act	excludes	from	bonus-eligible qualified	property,	however,	any	property	used	in	a	trade	or	business	that	furnishes	or	sells	electrical	energy,	gas,	or	steam	through	a	local distribution	 system,	 or	 transportation	 of	 gas	 or	 steam	 by	 pipeline	 if	 the	 rates	 for	 furnishing	 those	 services	 are	 subject	 to	 ratemaking	 by	 a government	entity	or	 instrumentality	or	by	a	public	utility	commission.	Accordingly,	the	extension	of	bonus	depreciation	and	modifications generally	do	not	apply	to	Entergy	or	the	Registrant	Subsidiaries.

The	Act	limits	the	net	operating	loss	(NOL)	deduction	for	a	given	year	to	 80%	of	taxable	income,	effective	with	respect	to	losses	arising	in tax	 years	 beginning	 after	 December	 31,	 2017.	Only	NOLs	generated	after	December	31,	2017	are	subject	 to	 the	80%	 limitation.	Prior	 law generally	provided	a	two-year	carryback	and	20-year	carryforward	for	NOLs.	The	Act	provides	for	the	indefinite	carryforward	of	NOLs	arising	in tax	years	ending	after	December	31,	2017,	as	opposed	to	the	current	20-year	carryforward.	Because	of	the	indefinite	carryforward,	the	new limitations	on	NOL	utilization	are	not	expected	to	have	a	material	effect	on	Entergy	or	the	Registrant	Subsidiaries.

The	Act	also	modified	Internal	Revenue	Code	section	162(m),	which	limits	the	deduction	for	compensation	with	respect	to	certain	covered employees	to	no	more	than	$1	million	per	year.		The	Act	includes	performance-based	compensation	in	the	annual	computation	of	the	section	162 limitation.		The	changes	are	expected	to	result	in	an	increase	in	disallowed	compensation	expense,	but	this	limitation	is	not	expected	to	have	a material	effect	on	Entergy	or	the	Registrant	Subsidiaries.

Other	provisions	that	are	not	expected	to	have	a	material	effect	on	Entergy	or	the	Registrant	Subsidiaries	include	the	following:

•repeal	of	the	corporate	alternative	minimum	tax	(AMT),

•modification	to	the	capital	contribution	rules	under	Internal	Revenue	Code	section	118,

•repeal	of	domestic	production	activities	deduction,	and

•fundamental	changes	to	the	taxation	of	multinational	entities.

With	respect	to	the	federal	corporate	income	tax	rate	change	from	35%	 to	21%,	Entergy	and	the	Registrant	Subsidiaries	believe	it	is probable	that	a	significant	portion	of	the	decrease	in	the	net	accumulated	deferred	income	tax	liability,	which	is	often	referred	to	as	"excess ADIT,"	will	be	returned	to	customers.	Accordingly,	it	is	appropriate	for	Entergy	and	the	Registrant	Subsidiaries	to	establish	a	regulatory	liability for	the	probable	reduction	in	future	revenue.	Entergy's	December	31,	2017	balance	sheet	reflects	a	regulatory	liability	of	$2.9	billion	due	to	a	re- measurement	of	deferred	tax	assets	and	liabilities	resulting	from	the	income	tax	rate	change.	Entergy's	regulatory	liability	for	income	taxes includes	a	gross-up	at	the	applicable	tax	rate	because	of	the	effect	that	excess	ADIT	has	on	the	ratemaking	formula.	The	regulatory	liability	for income	taxes	includes	the	effect	of	a)	the	reduction	of	the	net	deferred	tax	liability	resulting

in	excess	ADIT,	b)	the	tax	gross-up	of	excess	ADIT,	and	c)	the	effect	of	the	new	tax	rate	on	the	previous	net	regulatory	asset	for	income	taxes.	For the	same	reasons,	the	Registrant	Subsidiaries'	December	31,	2017	balance	sheets	reflect	net	regulatory	liabilities	for	income	taxes	as	follows: Entergy	 Arkansas,	$986	 million;	 Entergy	 Louisiana,	$725	 million;	 Entergy	 Mississippi,	$411	 million;	 Entergy	 New	 Orleans,	$119	 million; Entergy	Texas,	$413	million;	and	System	Energy,	$246	million.

Excess	ADIT	is	generally	classified	into	two	categories:	1)	the	portion	that	is	subject	to	the	normalization	requirements	of	the	Act,	i.e., "protected",	and	2)	 the	portion	 that	 is	not	subject	 to	such	normalization	provisions,	referred	 to	as	"unprotected".	The	Act	provides	 that	 the normalization	method	of	accounting	for	income	taxes	is	required	for	excess	ADIT	associated	with	public	utility	property.	The	Act	provides	for	the use	of	the	average	rate	assumption	method	(ARAM)	for	the	determination	of	the	timing	of	the	return	of	excess	ADIT	associated	with	such property.	Under	ARAM,	 the	 excess	ADIT	 is	 reduced	 over	 the	 remaining	 life	 of	 the	 asset.	Remaining	 asset	 lives	 vary	 for	 each	 Registrant Subsidiary,	but	the	average	life	of	public	utility	property	is	typically	30	years	or	longer.	Entergy	will	return	the	protected	portion	of	the	excess ADIT	in	conformity	with	the	normalization	requirements.	The	Registrant	Subsidiaries'	net	regulatory	liability	for	income	taxes	includes	protected excess	ADIT	as	follows:	Entergy	Arkansas,	$554	million;	 Entergy	 Louisiana,	$782	million;	 Entergy	 Mississippi,	$274	million;	Entergy	New Orleans,	$71	million;	Entergy	Texas,	$276	million;	and	System	Energy,	$217	million.

The	return	period	of	the	unprotected	excess	ADIT	is	subject	to	the	regulatory	process	in	each	jurisdiction	and	has	yet	to	be	determined. Further,	a	portion	of	the	unprotected	excess	ADIT	amount	is	associated	with	amounts	previously	securitized	and	may	be	treated	differently	than other	unprotected	excess	ADIT	consistent	with	applicable	agreements	and/or	not	be	subject	to	the	same	schedule	for	the	return	to	customers	as	the remaining	unprotected	excess	ADIT.	The	Registrant	Subsidiaries'	net	regulatory	liability	for	income	taxes	includes	unprotected	excess	ADIT	as follows:	Entergy	Arkansas,	$467	million;	Entergy	Louisiana,	$410	million;	Entergy	Mississippi,	$162	million;	Entergy	New	Orleans,	$37	million; Entergy	 Texas,	$198	million;	 and	 System	 Energy,	$76	million.	In	addition	to	the	protected	and	unprotected	excess	ADIT	amounts,	the	net regulatory	liability	for	income	taxes	includes	other	regulatory	assets	and	liabilities	for	income	taxes	associated	with	AFUDC,	which	is	described	in Note	1	to	the	financial	statements.

For	a	discussion	of the	proceedings	commenced	or	other	responses	by	Entergy's	regulators to the	Act,	see	Note	2 to the	financial statements.

Not	all	of	Entergy's	excess	ADIT	is	included	in	ratemaking.	Consequently,	Entergy	recorded	a	net	decrease	in	deferred	tax	assets	of	$560 million	for	which	there	is	a	corresponding	charge	to	income	tax	expense	for	the	year	ended	December	31,	2017.	The	corresponding	income	tax expense	(or	benefit)	recorded	by	the	Registrant	Subsidiaries	is	as	follows:	Entergy	Arkansas,	($3	million);	 Entergy	 Louisiana,	$217	 million; Entergy	Mississippi,	$3	million;	Entergy	New	Orleans,	$6	million;	Entergy	Texas,	$3	million;	and	System	Energy,	$0.

Included	in	the	effect	of	the	computation	of	the	changes	in	deferred	tax	assets	and	liabilities	is	the	recognition	threshold	and	measurement of	uncertain	tax	positions	resulting	in	unrecognized	tax	benefits.	The	final	economic	outcome	of	such	unrecognized	tax	benefits	is	generally	the result	of	a	negotiated	settlement	with	 the	IRS	 that	often	differs	from	 the	amount	 that	 is	recorded	as	realizable	under	GAAP.	The	 intrinsic uncertainty	with	respect	to	all	such	tax	positions	means	that	the	difference	between	current	estimates	of	such	amounts	likely	to	be	realized	and actual	amounts	realized	upon	settlement	may	have	an	effect	on	income	tax	expense	and	the	regulatory	liability	for	income	taxes	in	future	periods.

Entergy's	accounting	for	the	effects	of	the	Act	is	complete	using	the	best	estimates	and	information	available	to	it	at	this	time.	Entergy anticipates	 that	 the	Act,	 including	 the	 federal	 corporate	 income	 tax	 rate	 change,	 however,	 will	 continue	 to	 have	 ramifications	 that	 require adjustments	in	the	future	as	certain	events	occur.	These	events	include:	1)	the	evaluation	by	regulators	in	all	of	Entergy's	jurisdictions	regarding the	ratemaking	treatment	of	the	Act	and	excess	ADIT;	2)	the	filing	of	all	applicable	federal	and	state	income	tax	returns	that	include	any	tax elections	that	may	change	estimates	accrued	in	the	year-end	recording	process;	and	3)	additional	guidance,	interpretations,	or	rulings	by	the	U.S. Department	of	the	Treasury	or	the	IRS.	The	potential	exists	for	these	types	of	events	to	result	in	future	adjustments

because	of	the	difference	in	the	federal	corporate	income	tax	rate	between	past	and	future	periods	and	the	effect	of	the	tax	rate	change	on ratemaking.	In	turn,	these	items	also	will	potentially	affect	the	regulatory	liability	for	income	taxes.

# Louisiana	Business	Combination

In	October	2015	two	of	Entergy's	Louisiana	utilities,	Entergy	Gulf	States	Louisiana	and	Entergy	Louisiana,	combined	their	businesses into	 a	 legal	 entity	 which	 is	 identified	 as	 Entergy	 Louisiana	 herein.	The	 structure	 of	 the	 business	 combination	 generated	 both	 a	 permanent difference	and	a	temporary	difference	under	FASB	ASC	Topic	740.	 The	permanent	difference	resulted	from	recognition	of	the	Waterford	3	and River	Bend	decommissioning	liabilities	as	part	of	the	business	combination.	Recognition	of	such	decommissioning	liabilities	required	Entergy	to also	recognize	a	taxable	gain.	The	taxable	gain	resulted	in	a	temporary	difference	because	the	gain	provided	for	an	increase	in	tax	basis.	Entergy Louisiana	maintained	a	carryover	tax	basis	in	the	assets	received;	and,	to	the	extent	that	the	increase	in	tax	basis	will	provide	additional	tax depreciation,	Entergy	recorded	a	deferred	tax	asset.	Entergy	Louisiana	obtained	the	corresponding	deferred	tax	asset	in	the	business	combination. The	permanent	tax	benefit	net	of	ancillary	tax	charges	was	approximately	$334	million.	Consistent	with	the	terms	of	the	stipulated	settlement	in the	 business	 combination	 proceeding,	 electric	 customers	 of	 Entergy	 Louisiana	 will	 realize	 customer	 credits	 associated	 with	 the	 business combination.	Accordingly,	in	October	2015,	Entergy	recorded	a	regulatory	liability	of	$107	million	($66	million	net-of-tax)	which	partially	offsets the	effect	of	the	aforementioned	deferred	tax	asset.	The	deferred	tax	asset	and	the	regulatory	liability,	net-of-tax,	increased	Entergy	Louisiana's member's	equity	by	$268	million.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	business	combination.

# Entergy	Wholesale	Commodities	Restructuring

The	tax	classification	of	the	entity	that	owned	FitzPatrick	changed	in	the	second	quarter	2016.		The	change	in	tax	classification	required Entergy	to	recognize	the	plant's	nuclear	decommissioning	liability	for	income	tax	purposes	resulting	in	a	tax	accounting	permanent	difference	that reduced	income	tax	expense,	net	of	unrecognized	tax	benefits,	by	$238	million.	The	accrual	of	the	nuclear	decommissioning	liability	also	required Entergy	to	recognize	a	gain	for	income	tax	purposes,	a	significant	portion	of	which	resulted	in	an	increase	in	tax	basis	of	the	assets.	Recognition	of the	gain	and	the	increase	in	tax	basis	of	the	assets	represents	a	tax	accounting	temporary	difference.	Entergy	sold	FitzPatrick	on	March	31,	2017. The	removal	of	the	contingencies	regarding	the	sale	of	the	plant	and	the	receipt	of	NRC	approval	for	the	sale	allowed	Entergy	to	re-determine	the plant's	tax	basis.	The	re-determined	basis	resulted	in	a	$44	million	income	tax	benefit	in	the	first	quarter	2017.

In	the	second	quarter	2017,	Entergy	changed	the	tax	classification	of	legal	entities	that	own	Entergy	Wholesale	Commodities	nuclear power	 plants.	The	change	 in	 tax	classification	required	Entergy	 to	recognize	 the	plants'	nuclear	decommissioning	 liabilities	for	 income	 tax purposes	resulting	in	a	tax	accounting	permanent	difference	that	reduced	income	tax	expense,	net	of	unrecognized	tax	benefits,	by	$373	million. The	accrual	of	the	nuclear	decommissioning	liabilities	also	required	Entergy	to	recognize	a	gain	for	income	tax	purposes,	a	portion	of	which resulted	in	an	increase	in	tax	basis	of	the	assets.	Recognition	of	the	gain	and	the	increase	in	tax	basis	of	the	assets	represents	a	tax	accounting temporary	difference.

# Tax	Accounting	Methods

In	the	fourth	quarter	2015,	System	Energy	and	Entergy	Louisiana	adopted	a	new	method	of	accounting	for	income	tax	return	purposes	in which	the	companies'	nuclear	decommissioning	costs	will	be	treated	as	production	costs	of	electricity	includable	in	cost	of	goods	sold.	The	new method	results	in	a	reduction	of	taxable	income	of	$1.2	billion	for	System	Energy	and	$2.2	billion	for	Entergy	Louisiana.

In	 2016,	 Entergy	 Louisiana	 elected	 mark-to-market	 income	 tax	 treatment	 for	 various	 wholesale	 electric	 power	 purchase	 and	 sale agreements,	including	Entergy	Louisiana's	contract	to	purchase	electricity	from	the	Vidalia	hydroelectric	facility	and	from	System	Energy	under the	Unit	Power	Sales	Agreement.	The	election	resulted	in	a	$2.2

billion	deductible	temporary	difference.	In	2017,	Entergy	New	Orleans	also	elected	mark-to-market	income	tax	treatment	with	respect	to	the	Unit Power	Sales	Agreement	resulting	in	a	$1.1	billion	deductible	temporary	difference.

# Accounting	Pronouncements

In	the	first	quarter	2017,	Entergy	implemented	ASU	No.	2016-09,	"Compensation	-	Stock	Compensation	(Topic	718):	Improvements	to Employee	Share-Based	Payment	Accounting."	Entergy	will	now	prospectively	recognize	all	income	tax	effects	related	to	share-based	payments through	the	income	statement.	In	the	first	quarter	2017,	stock	option	expirations,	along	with	other	stock	compensation	activity,	resulted	in	the write-off	of	$11.5	million	of	deferred	tax	assets.	Entergy's	stock-based	compensation	plans	are	discussed	in	Note	12	to	the	financial	statements.

# NOTE	4.		REVOLVING	CREDIT	FACILITIES,	LINES	OF	CREDIT,	AND	SHORT-TERM	BORROWINGS	(Entergy	Corporation, Entergy	Arkansas,	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	August	2022.		The	facility permits	the	issuance	of	letters	of	credit	against	$20	million	of	the	total	borrowing	capacity	of	the	credit	facility.		The	commitment	fee	is	currently 0.225%	of	the	undrawn	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,	2017	was	2.55%	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,	2017.

| Capacity | Borrowings | Letters	of	Credit | Capacity	Available |
| :--- | :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |  |
| $3,500 | $210 | $6 | $3,284 |

Entergy	 Corporation's	 credit	 facility	 requires	 Entergy	 to	 maintain	 a	 consolidated	 debt	 ratio,	 as	 defined,	 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.

The	commitment	fees	on	the	credit	facilities	range	from	0.075%	 to	0.275%	of	the	undrawn	commitment	amount.	Each	of	the	credit	facilities requires	 the	 Registrant	 Subsidiary	 borrower	 to	 maintain	 a	 debt	 ratio,	 as	 defined,	 of	 65%	 or	 less	 of	 its	 total	 capitalization.	Each	 Registrant Subsidiary	is	in	compliance	with	this	covenant.

| Company | Amount	of	Uncommitted<br>Facility | Letter	of	Credit	Fee | Letters	of	Credit	Issued	as	of<br>December	31,	2017	(a) |
| :--- | :--- | :--- | :--- |
| Entergy\tArkansas | $25\tmillion | 0.70% | $1.0\tmillion |
| Entergy\tLouisiana | $125\tmillion | 0.70% | $29.7\tmillion |
| Entergy\tMississippi | $40\tmillion | 0.70% | $15.3\tmillion |
| Entergy\tNew\tOrleans | $15\tmillion | 1.00% | $1.4\tmillion |
| Entergy\tTexas | $50\tmillion | 0.70% | $22.8\tmillion |

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,	2019.	In	addition	to	borrowings	from	commercial

banks,	these	companies	may	also	borrow	from	the	Entergy	System	money	pool	and	from	other	internal	short-term	borrowing	arrangements.		The money	pool	and	the	other	internal	borrowing	arrangements	are	inter-company	borrowing	arrangements	designed	to	reduce	the	Utility	subsidiaries' dependence	on	external	short-term	borrowings.		Borrowings	from	internal	and	external	short	term	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,	2017	(aggregating	both	internal	and	external	short-term	borrowings)	for	the	Registrant	Subsidiaries:

|  | Authorized | Borrowings |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $250 | $166 |
| Entergy\tLouisiana | $450 | — |
| Entergy\tMississippi | $175 | — |
| Entergy\tNew\tOrleans | $150 | — |
| Entergy\tTexas | $200 | — |
| System\tEnergy | $200 | — |

# Entergy	Nuclear	Vermont	Yankee	Credit	Facilities

Entergy	Nuclear	Vermont	Yankee	has	a	credit	facility	guaranteed	by	Entergy	Corporation	with	a	borrowing	capacity	of	 $145	million	that expires	in	November	2020.	Entergy	Nuclear	Vermont	Yankee	does	not	have	the	ability	to	issue	letters	of	credit	against	the	credit	facility.	 This facility	 provides	 working	 capital	 to	 Entergy	 Nuclear	 Vermont	 Yankee	 for	 general	 business	 purposes	 including,	 without	 limitation,	 the decommissioning	of	Vermont	Yankee.	 The	commitment	fee	is	currently	0.20%	of	the	undrawn	commitment	amount.		As	of	December	31,	2017, $104	million	in	cash	borrowings	were	outstanding	under	the	credit	facility.		The	weighted	average	interest	rate	for	the	year	ended	 December	31, 2017	was	2.64%	on	the	drawn	portion	of	the	facility.

Entergy	Nuclear	Vermont	Yankee	also	had	an	uncommitted	credit	facility	guaranteed	by	Entergy	Corporation with	a	borrowing	capacity	of	$85	million	that	expired	in	January	2018.		As	of	 December	31,	2017,	there	were	no	cash	borrowings	outstanding under	the	credit	facility.	The	estimated	interest	rate	for	the	year	ended	December	31,	2017	would	have	been	3.07%	on	the	drawn	portion	of	the facility.

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

See	Note	17	 to	 the	financial	statements	for	a	discussion	of	 the	consolidation	of	 the	nuclear	fuel	company	variable	 interest	entities (VIE).		To	finance	the	acquisition	and	ownership	of	nuclear	fuel,	the	nuclear	fuel	company	VIEs	have	credit	facilities	and	three	of	the	four	VIEs also	issue	commercial	paper,	details	of	which	follow	as	of	December	31,	2017:

| Company | Expiration	Date | Amount	of<br>Facility | Weighted	Average<br>Interest	Rate	on<br>Borrowings	(a) | Amount	Outstanding	as	of<br>December	31,	2017 |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tin\tMillions) |  |
| Entergy\tArkansas\tVIE | May\t2019 | $80 | 2.87% | $74.9\t(b) |
| Entergy\tLouisiana\tRiver\tBend\tVIE | May\t2019 | $105 | 2.38% | $65.7 |
| Entergy\tLouisiana\tWaterford\tVIE | May\t2019 | $85 | 2.64% | $79.9\t(c) |
| System\tEnergy\tVIE | May\t2019 | $120 | 2.52% | $67.8\t(d) |

(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	Louisiana	River	Bend	does	not	issue	commercial	paper,	but	borrows	directly	on	its	bank credit	facility.

(b) Includes	borrowings	on	the	credit	facility	and	commercial	paper.	Commercial	paper	is	classified	as	a	current	liability	and	the	amount outstanding	for	Entergy	Arkansas	VIE	as	of	December	31,	2017	was	$50	million.

(c) Includes	borrowings	on	the	credit	facility	and	commercial	paper.	Commercial	paper	is	classified	as	a	current	liability	and	the	amount outstanding	for	Entergy	Louisiana	Waterford	VIE	as	of	December	31,	2017	was	$43.5	million.

(d) Includes	borrowings	on	the	credit	facility	and	commercial	paper.	Commercial	paper	is	classified	as	a	current	liability	and	the	amount outstanding	for	System	Energy	VIE	as	of	December	31,	2017	was	$17.8	million.

The	commitment	fees	on	the	credit	facilities	are	0.10%	of	the	undrawn	commitment	amount	for	the	Entergy	Arkansas,	Entergy	Louisiana, and	System	Energy	VIEs.	Each	credit	facility	requires	the	respective	lessee	of	nuclear	fuel	(Entergy	Arkansas,	Entergy	Louisiana,	or	Entergy Corporation	as	guarantor	for	System	Energy)	to	maintain	a	consolidated	debt	ratio,	as	defined,	of	70%	or	less	of	its	total	capitalization.

The	nuclear	fuel	company	variable	interest	entities	had	notes	payable	that	are	included	in	debt	on	the	respective	balance	sheets	as	of December	31,	2017	as	follows:

| Company | Description | Amount |
| :--- | :--- | :--- |
| Entergy\tArkansas\tVIE | \t 3.65%\tSeries\tL\tdue\tJuly\t2021 | $90\tmillion |
| Entergy\tArkansas\tVIE | \t 3.17%\tSeries\tM\tdue\tDecember\t2023 | $40\tmillion |
| Entergy\tLouisiana\tRiver\tBend\tVIE | \t 3.38%\tSeries\tR\tdue\tAugust\t2020 | $70\tmillion |
| Entergy\tLouisiana\tWaterford\tVIE | \t 3.92%\tSeries\tH\tdue\tFebruary\t2021 | $40\tmillion |
| Entergy\tLouisiana\tWaterford\tVIE | \t 3.22%\tSeries\tI\tdue\tDecember\t2023 | $20\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.

Entergy	Arkansas,	Entergy	Louisiana,	and	System	Energy	each	have	obtained	long-term	financing	authorizations	from	the	FERC	that extend	through	October	2019	for	issuances	by	its	nuclear	fuel	company	variable	interest	entities.

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

Long-term	debt	for	Entergy	Corporation	and	subsidiaries	as	of	December	31,	2017	and	2016	consisted	of:

|  | Weighted | Interest	Rate	Ranges	at	December	31, | Interest	Rate	Ranges	at	December	31, | Outstanding	at	December	31, | Outstanding	at	December	31, |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Type\tof\tDebt\tand\tMaturity | Average\nInterest\tRate\nDecember\t31,\n2017 | 2017 | 2016 | 2017 | 2016 |
|  |  |  |  | (In\tThousands) |  |
| Mortgage\tBonds |  |  |  |  |  |
| 2018-2022 | 4.39% | 2.55%-7.125% | 2.55%-7.125% | $2,550,000 | $2,550,000 |
| 2023-2027 | 3.72% | 2.40%-5.59% | 2.40%-5.59% | 4,735,000 | 3,765,000 |
| 2028-2031 | 3.06% | 2.85%-3.25% | 2.85%-3.25% | 1,125,000 | 1,125,000 |
| 2044-2066 | 5.00% | 4.70%-5.625% | 4.70%-5.625% | 2,960,000 | 2,960,000 |
| Governmental\tBonds\t(a) |  |  |  |  |  |
| 2017-2022 | 5.20% | 2.375%-5.875% | 1.55%-5.875% | 179,000 | 233,700 |
| 2028-2030 | 3.45% | 3.375%-3.50% | 3.375%-3.50% | 198,680 | 198,680 |
| Securitization\tBonds |  |  |  |  |  |
| 2018-2027 | 3.79% | 2.04%-5.93% | 2.04%-5.93% | 551,499 | 669,310 |
| Variable\tInterest\tEntities\tNotes\tPayable\n(Note\t4) |  |  |  |  |  |
| 2017-2023 | 3.48% | 3.17%-3.92% | 2.62%-4.02% | 345,000 | 555,000 |
| Entergy\tCorporation\tNotes |  |  |  |  |  |
| due\tSeptember\t2020 | n/a | 5.125% | 5.125% | 450,000 | 450,000 |
| due\tJuly\t2022 | n/a | 4.00% | 4.00% | 650,000 | 650,000 |
| due\tSeptember\t2026 | n/a | 2.95% | 2.95% | 750,000 | 750,000 |
| 5\tYear\tCredit\tFacility\t(Note\t4) | n/a | 2.55% | 2.23% | 210,000 | 700,000 |
| Vermont\tYankee\tCredit\tFacility\t(Note\t4) | n/a | 2.64% | 2.17% | 103,500 | 44,500 |
| Entergy\tArkansas\tVIE\tCredit\tFacility\t(Note |  |  |  |  |  |
| 4) | n/a | 2.87% | — | 24,900 | — |
| Entergy\t Louisiana\t River\t Bend\t VIE\t Credit\nFacility\t(Note\t4) | n/a | 2.38% | — | 65,650 | — |
| Entergy\nLouisiana\t Waterford\t VIE\t Credit\nFacility\t(Note\t4) | n/a | 2.64% | — | 36,360 | — |
| System\tEnergy\tVIE\tCredit\tFacility\t(Note\t4) | n/a | 2.52% | — | 50,000 | — |
| Long-term\tDOE\tObligation\t(b) | — | — | — | 183,435 | 181,853 |
| Waterford\t3\tLease\tObligation\t(c) | n/a | — | 8.09% | — | 57,492 |
| Waterford\tSeries\tCollateral\tTrust\tMortgage\nNotes\tdue\t2017\t(c) | n/a | — | (d) | — | 42,703 |
| Grand\tGulf\tLease\tObligation\t(c) | n/a | 5.13% | 5.13% | 34,356 | 34,359 |
| Unamortized\tPremium\tand\tDiscount\t-\tNet |  |  |  | (13,911) | (19,397) |
| Unamortized\tDebt\tIssuance\tCosts |  |  |  | (126,033) | (128,849) |
| Other |  |  |  | 12,830 | 13,204 |
| Total\tLong-Term\tDebt |  |  |  | 15,075,266 | 14,832,555 |
| Less\tAmount\tDue\tWithin\tOne\tYear |  |  |  | 760,007 | 364,900 |
| Long-Term\tDebt\tExcluding\tAmount\tDue |  |  |  |  |  |
| Within\tOne\tYear |  |  |  | $14,315,259 | $14,467,655 |
| Fair\tValue\tof\tLong-Term\tDebt\t(e) |  |  |  | $15,367,453 | $14,815,535 |

(a) Consists	of	pollution	control	revenue	bonds	and	environmental	revenue	bonds,	some	of	which	are	secured	by	collateral	mortgage	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) See	Note	10	to	the	financial	statements	for	further	discussion	of	the	Waterford	3	lease	obligation	and	Entergy	Louisiana's	acquisition	of the	equity	participant's	beneficial	interest	in	the	Waterford	3	leased	assets	and	for	further	discussion	of	the	Grand	Gulf	lease	obligation.

(d) This	note	did	not	have	a	stated	interest	rate,	but	had	an	implicit	interest	rate	of	 7.458%.

(e) The	fair	value	excludes	lease	obligations	of	$34	million	at	System	Energy	and	long-term	DOE	obligations	of	$183	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	15	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,	2017,	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.	As	part	of	the	purchase	agreement	with	NYPA,	Entergy	recorded	a	liability	representing	the	net	present	value	of	the	payments	Entergy would	be	liable	to	NYPA	for	each	year	that	the	FitzPatrick	and	Indian	Point	3	power	plants	would	run	beyond	their	respective	original	NRC license	expiration	date.	In	October	2015,	Entergy	announced	a	planned	shutdown	of	FitzPatrick	at	the	end	of	its	fuel	cycle.	As	a	result	of	the announcement,	Entergy	reduced	this	liability	by	$26.4	million	pursuant	to	the	terms	of	the	purchase	agreement.	In	August	2016,	Entergy	entered into	a	trust	transfer	agreement	with	NYPA	to	transfer	the	decommissioning	trust	funds	and	decommissioning	liabilities	for	the	Indian	Point	3	and FitzPatrick	plants	to	Entergy.	As	part	of	the	trust	transfer	agreement,	the	original	decommissioning	agreements	were	amended,	and	the	Entergy subsidiaries'	obligation	to	make	additional	license	extension	payments	to	NYPA	was	eliminated.	 In	the	third	quarter	2016,	Entergy	removed	the note	payable	of	$35.1	million	from	the	consolidated	balance	sheet.

Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	have	obtained	long-term	financing authorizations	from	the	FERC	that	extend	through	October	2019.		Entergy	Arkansas	has	obtained	long-term	financing	authorization	from	the APSC	that	extends	through	December	2018.	Entergy	New	Orleans	has	also	obtained	long-term	financing	authorization	from	the	City	Council	that extends	through	June	2018,	as	the	City	Council	has	concurrent	jurisdiction	with	the	FERC	over	such	issuances.

•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	 a	 supplement to the	 agreement	 assigning	 System Energy's	rights	in	the	agreement	as	security	for	the	specific	debt.

Long-term	debt	for	the	Registrant	Subsidiaries	as	of	December	31,	2017	and	2016	consisted	of:

| 3.75%	Series	due	February	2021 | $350,000 | $350,000 |
| :--- | :--- | :--- |
| 3.05%\tSeries\tdue\tJune\t2023 | 250,000 | 250,000 |
| 3.7%\tSeries\tdue\tJune\t2024 | 375,000 | 375,000 |
| 3.5%\tSeries\tdue\tApril\t2026 | 600,000 | 380,000 |
| 4.95%\tSeries\tdue\tDecember\t2044 | 250,000 | 250,000 |
| 4.90%\tSeries\tdue\tDecember\t2052 | 200,000 | 200,000 |
| 4.75%\tSeries\tdue\tJune\t2063 | 125,000 | 125,000 |
| 4.875%\tSeries\tdue\tSeptember\t2066 | 410,000 | 410,000 |
| Total\tmortgage\tbonds | 2,560,000 | 2,340,000 |
| Governmental\tBonds\t(a): |  |  |
| 1.55%\tSeries\tdue\t2017,\tJefferson\tCounty\t(d) | — | 54,700 |
| 2.375%\tSeries\tdue\t2021,\tIndependence\tCounty\t(d) | 45,000 | 45,000 |
| Total\tgovernmental\tbonds | 45,000 | 99,700 |
| Variable\tInterest\tEntity\tNotes\tPayable\tand\tCredit\tFacility\t(Note\t4): |  |  |
| 2.62%\tSeries\tK\tdue\tDecember\t2017 | — | 60,000 |
| 3.65%\tSeries\tL\tdue\tJuly\t2021 | 90,000 | 90,000 |
| 3.17%\tSeries\tM\tdue\tDecember\t2023 | 40,000 | 40,000 |
| Credit\tFacility\tdue\tMay\t2019,\tweighted\tavg\trate\t2.87% | 24,900 | — |
| Total\tvariable\tinterest\tentity\tnotes\tpayable\tand\tcredit\tfacility | 154,900 | 190,000 |
| Securitization\tBonds: |  |  |
| 2.30%\tSeries\tSenior\tSecured\tdue\tAugust\t2021 | 35,764 | 49,548 |
| Total\tsecuritization\tbonds | 35,764 | 49,548 |
| Other: |  |  |
| Long-term\tDOE\tObligation\t(b) | 183,435 | 181,853 |
| Unamortized\tPremium\tand\tDiscount\t–\tNet | 5,307 | 984 |
| Unamortized\tDebt\tIssuance\tCosts | (34,049) | (34,357) |
| Other | 2,042 | 2,057 |
| Total\tLong-Term\tDebt | 2,952,399 | 2,829,785 |
| Less\tAmount\tDue\tWithin\tOne\tYear | — | 114,700 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $2,952,399 | $2,715,085 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $2,865,844 | $2,623,910 |

| 6.0%	Series	due	May	2018 | $375,000 | $375,000 |
| :--- | :--- | :--- |
| 6.50%\tSeries\tdue\tSeptember\t2018 | 300,000 | 300,000 |
| 3.95%\tSeries\tdue\tOctober\t2020 | 250,000 | 250,000 |
| 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 | 325,000 |
| 5.59%\tSeries\tdue\tOctober\t2024 | 300,000 | 300,000 |
| 5.40%\tSeries\tdue\tNovember\t2024 | 400,000 | 400,000 |
| 3.78%\tSeries\tdue\tApril\t2025 | 110,000 | 110,000 |
| 3.78%\tSeries\tdue\tApril\t2025 | 190,000 | 190,000 |
| 4.44%\tSeries\tdue\tJanuary\t2026 | 250,000 | 250,000 |
| 2.40%\tSeries\tdue\tOctober\t2026 | 400,000 | 400,000 |
| 3.12%\tSeries\tdue\tSeptember\t2027 | 450,000 | — |
| 3.25%\tSeries\tdue\tApril\t2028 | 425,000 | 425,000 |
| 3.05%\tSeries\tdue\tJune\t2031 | 325,000 | 325,000 |
| 5.0%\tSeries\tdue\tJuly\t2044 | 170,000 | 170,000 |
| 4.95%\tSeries\tdue\tJanuary\t2045 | 450,000 | 450,000 |
| 5.25%\tSeries\tdue\tJuly\t2052 | 200,000 | 200,000 |
| 4.70%\tSeries\tdue\tJune\t2063 | 100,000 | 100,000 |
| 4.875%\tSeries\tdue\tSeptember\t2066 | 270,000 | 270,000 |
| Total\tmortgage\tbonds | 5,690,000 | 5,240,000 |
| Governmental\tBonds\t(a): |  |  |
| 3.375\t%\tSeries\tdue\t2028,\tLouisiana\tPublic\tFacilities\tAuthority\t(d) | 83,680 | 83,680 |
| 3.50%\tSeries\tdue\t2030,\tLouisiana\tPublic\tFacilities\tAuthority\t(d) | 115,000 | 115,000 |
| Total\tgovernmental\tbonds | 198,680 | 198,680 |
| Variable\tInterest\tEntity\tNotes\tPayable\tand\tCredit\tFacilities\t(Note\t4): |  |  |
| 3.25%\tSeries\tG\tdue\tJuly\t2017 | — | 25,000 |
| 3.25%\tSeries\tQ\tdue\tJuly\t2017 | — | 75,000 |
| 3.38%\tSeries\tR\tdue\tAugust\t2020 | 70,000 | 70,000 |
| 3.92%\tSeries\tH\tdue\tFebruary\t2021 | 40,000 | 40,000 |
| 3.22%\tSeries\tI\tdue\tDecember\t2023 | 20,000 | 20,000 |
| Credit\tFacility\tdue\tMay\t2019,\tweighted\tavg\trate\t2.38% | 65,650 | — |
| Credit\tFacility\tdue\tMay\t2019,\tweighted\tavg\trate\t2.64% | 36,360 | — |
| Total\tvariable\tinterest\tentity\tnotes\tpayable\tand\tcredit\tfacilities | 232,010 | 230,000 |
| Securitization\tBonds: |  |  |
| 2.04%\tSeries\tSenior\tSecured\tdue\tSeptember\t2023 | 79,228 | 100,972 |
| Total\tsecuritization\tbonds | 79,228 | 100,972 |
| Other: |  |  |
| Waterford\t3\tLease\tObligation\t(Note\t10)\t(e) | — | 57,492 |
| Waterford\tSeries\tCollateral\tTrust\tMortgage\tNotes\tdue\t2017\t(Note\t10)\t(f) | — | 42,703 |
| Unamortized\tPremium\tand\tDiscount\t-\tNet | (13,877) | (14,917) |
| Unamortized\tDebt\tIssuance\tCosts | (48,540) | (48,972) |
| Other | 6,570 | 6,833 |
| Total\tLong-Term\tDebt | 6,144,071 | 5,812,791 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 675,002 | 200,198 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $5,469,069 | $5,612,593 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $6,389,774 | $5,929,488 |

| 7.125%	Series	due	February	2019 | $500,000 | $500,000 |
| :--- | :--- | :--- |
| 2.55%\tSeries\tdue\tJune\t2021 | 125,000 | 125,000 |
| 4.1%\tSeries\tdue\tSeptember\t2021 | 75,000 | 75,000 |
| 3.45%\tSeries\tdue\tDecember\t2027 | 150,000 | — |
| 5.15%\tSeries\tdue\tJune\t2045 | 250,000 | 250,000 |
| 5.625%\tSeries\tdue\tJune\t2064 | 135,000 | 135,000 |
| Total\tmortgage\tbonds | 1,235,000 | 1,085,000 |
| Securitization\tBonds: |  |  |
| 5.79%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tOctober\t2018 | — | 23,584 |
| 3.65%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tAugust\t2019 | 30,769 | 74,899 |
| 5.93%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tJune\t2022 | 110,431 | 114,400 |
| 4.38%\tSeries\tSenior\tSecured,\tSeries\tA\tdue\tNovember\t2023 | 218,600 | 218,600 |
| Total\tsecuritization\tbonds | 359,800 | 431,483 |
| Other: |  |  |
| Unamortized\tPremium\tand\tDiscount\t-\tNet | (1,498) | (1,579) |
| Unamortized\tDebt\tIssuance\tCosts | (10,366) | (10,809) |
| Other | 4,214 | 4,312 |
| Total\tLong-Term\tDebt | 1,587,150 | 1,508,407 |
| Less\tAmount\tDue\tWithin\tOne\tYear | — | — |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $1,587,150 | $1,508,407 |
| Fair\tValue\tof\tLong-Term\tDebt\t(c) | $1,661,902 | $1,600,156 |

| 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. | 134,000 | 134,000 |
| Total\tgovernmental\tbonds | 134,000 | 134,000 |
| Variable\tInterest\tEntity\tNotes\tPayable\tand\tCredit\tFacility\t(Note\t4): |  |  |
| 4.02%\tSeries\tH\tdue\tFebruary\t2017 | — | 50,000 |
| 3.78%\tSeries\tI\tdue\tOctober\t2018 | 85,000 | 85,000 |
| Credit\tFacility\tdue\tMay\t2019,\tweighted\tavg\trate\t2.52% | 50,000 | — |
| Total\tvariable\tinterest\tentity\tnotes\tpayable\tand\tcredit\tfacility | 135,000 | 135,000 |
| Other: |  |  |
| Grand\tGulf\tLease\tObligation\t5.13%\t(Note\t10) | 34,356 | 34,359 |
| Unamortized\tPremium\tand\tDiscount\t–\tNet | (415) | (503) |
| Unamortized\tDebt\tIssuance\tCosts | (1,455) | (1,727) |
| Other | 2 | 3 |
| Total\tLong-Term\tDebt | 551,488 | 551,132 |
| Less\tAmount\tDue\tWithin\tOne\tYear | 85,004 | 50,003 |
| Long-Term\tDebt\tExcluding\tAmount\tDue\tWithin\tOne\tYear | $466,484 | $501,129 |
|  | $529,119 | $529,520 |

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

(c) The	fair	value	excludes	lease	obligations	of	$34	million	at	System	Energy	and	long-term	DOE	obligations	of	$183	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	15	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	mortgage	bonds.

(e) The	 interest	 rate	 as	 of	 December	 31,	 2016	 was	8.09%.	 See	 Note	 10	 to	 the	 financial	 statements	 for	 further	 discussion	 of	 Entergy Louisiana's	acquisition	of	the	equity	participant's	beneficial	interest	in	the	Waterford	3	leased	assets	in	March	2016.

(f) This	note	did	not	have	a	stated	interest	rate,	but	had	an	implicit	interest	rate	of	 7.458%.

# 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%.		Although	the	principal	amount	is	not	due	until	August	2021,	Entergy	Arkansas	Restoration Funding	expects	to	make	principal	payments	on	the	bonds	over	the	next	three	years	in	the	amount	of	$14.1	million	for	2018,	$14.4	million	for 2019,	and	$7.3	million	for	2020.	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.

# 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%.	 	Although	the	principal	amount	is	not	due	until	September	2023,	Entergy	Louisiana	Investment Recovery	Funding	expects	to	make	principal	payments	on	the	bonds	over	the	next	four	years	in	the	amounts	of	$22.3	million	 for	2018,	$22.7 million	 for	2019,	$23.2	million	 for	2020,	 and	$11	 million	 for	2021.	 	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	New	Orleans	Securitization	Bonds	-	Hurricane	Isaac

In	May	2015	the	City	Council	issued	a	financing	order	authorizing	the	issuance	of	securitization	bonds	to	recover	Entergy	New	Orleans's Hurricane	Isaac	storm	restoration	costs	of	$31.8	million,	including	carrying	costs,	the	costs	of	funding	and	replenishing	the	storm	recovery	reserve in	the	amount	of	$63.9	million,	and	approximately	$3	million	of	up-front	financing	costs	associated	with	the	securitization.	In	July	2015,	Entergy New	Orleans	Storm	Recovery	Funding	I,	L.L.C.,	a	company	wholly	owned	and	consolidated	by	Entergy	New	Orleans,	issued	$98.7	million	of storm	cost	recovery	bonds.	The	bonds	have	a	coupon	of	2.67%.	Although	the	principal	amount	is	not	due	until	June	2027,	Entergy	New	Orleans Storm	Recovery	Funding	expects	to	make	principal	payments	on	the	bonds	over	the	next	five	years	in	the	amounts	of	$11	million	for	2018,	$11.2 million	for	2019,	$11.6	million	for	2020,	$11.9	million	 for	2021,	 and	$12.2	million	 for	2022.	With	the	proceeds,	Entergy	New	Orleans	Storm Recovery	Funding	purchased	from	Entergy	New	Orleans	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	New	Orleans	balance	sheet.	The	creditors	of	Entergy	New	Orleans	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy New	Orleans	Storm	Recovery	Funding,	including	the	storm	recovery	property,	and	the	creditors	of	Entergy	New	Orleans	Storm	Recovery	Funding do	not	have	recourse	to	the

assets	or	revenues	of	Entergy	New	Orleans.	Entergy	New	Orleans	has	no	payment	obligations	to	Entergy	New	Orleans	Storm	Recovery	Funding except	to	remit	storm	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\t(a) | 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	four	years	in	the	amounts	of	$29.2	million	for	2018,	$30.9	million	for	2019,	$32.8	million	for 2020,	and	$17.5	million	for	2021.	All	of	the	scheduled	principal	payments	for	2018-2021	are	for	Tranche	A-3.	Tranche	A-1	and	Tranche	A-2 have	been	paid.

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\t(a) | 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	$45.8	million	for	2018,	$47.6	million	for	2019,	$49.8	million	for	2020, $52	million	 for	2021,	 and	$54.3	million	 for	2022.	Of	the	scheduled	principal	payments	for	2018,	$30.8	million	are	for	Tranche	A-2	and	 $15 million	are	for	Tranche	A-3.	All	of	the	scheduled	principle	payments	for	2019-2022	are	for	Tranche	A-3.	Tranche	A-1	has	been	paid.

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	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,	2017	 and	2016	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 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 |
| Entergy\tCorporation |  |  |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |
| Utility: |  |  |  |  |  |  |
| Preferred\tStock\tor\tPreferred\tMembership\nInterests\twithout\tsinking\tfund: |  |  |  |  |  |  |
| Entergy\tArkansas,\t4.32%-4.72%\tSeries | 313,500 | 313,500 | 313,500 | 313,500 | $31,350 | $31,350 |
| Entergy\tUtility\tHolding\tCompany,\tLLC,\n7.5%\tSeries\t(a) | 110,000 | 110,000 | 110,000 | 110,000 | 107,425 | 107,425 |
| Entergy\tUtility\tHolding\tCompany,\tLLC,\n6.25%\tSeries\t(b) | 15,000 | — | 15,000 | — | 14,398 | — |
| Entergy\tMississippi,\t4.36%-4.92%\tSeries | 203,807 | 203,807 | 203,807 | 203,807 | 20,381 | 20,381 |
| Entergy\tNew\tOrleans,\t4.36%-5.56%\tSeries | — | 197,798 | — | 197,798 | — | 19,780 |
| Total\tUtility\tPreferred\tStock\tor\tPreferred |  |  |  |  |  |  |
| Membership\tInterests\twithout\tsinking |  |  |  |  |  |  |
| fund | 642,307 | 825,105 | 642,307 | 825,105 | 173,554 | 178,936 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |  |
| Preferred\tStock\twithout\tsinking\tfund: |  |  |  |  |  |  |
| Entergy\tFinance\tHolding,\tInc.\t8.75%\t(c) | 250,000 | 250,000 | 250,000 | 250,000 | 24,249 | 24,249 |
| Total\tSubsidiaries'\tPreferred\tStock\twithout\nsinking\tfund | 892,307 | 1,075,105 | 892,307 | 1,075,105 | $197,803 | $203,185 |

(b) Dollar	amount	outstanding	is	net	of	$602	thousand	of	preferred	stock	issuance	costs.

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

In	 November	 2017,	 Entergy	 Utility	 Holding	 Company,	 LLC	 issued	15,000	 shares	 of	$1,000	 par	 value	6.25%	 Series	 B	 Preferred Membership	Interests,	all	of	which	are	outstanding	as	of	December	31,	2017.	The	distributions	are	cumulative	and	payable	quarterly.	These	units are	redeemable	on	or	after	February	28,	2038,	at	Entergy	Utility	Holding	Company,	LLC's	option,	at	the	fixed	redemption	price	of	$1,000	per share.

In	October	2015,	Entergy	Utility	Holding	Company,	LLC	issued	110,000	shares	of	$1,000	par	value	7.5%	Series	A	Preferred	Membership Interests,	 all	 of	 which	 are	 outstanding	 as	 of	 December	 31,	 2017.	The	 distributions	 are	 cumulative	 and	 payable	 quarterly.	These	 units	 are redeemable	on	or	after	January	1,	2036,	at	Entergy	Utility	Holding	Company,	LLC's	option,	at	the	fixed	redemption	price	of	$1,000	per	share.

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,	 2017.	The	 dividends	 are	 cumulative	 and	 payable	 quarterly.	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	for	Entergy	Arkansas,	Entergy	Mississippi, and	Entergy	New	Orleans	as	of	December	31,	2017	and	2016	are	presented	below.		All	series	of	the	Utility	operating	companies'	preferred	stock 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.

|  | Shares<br>Authorized<br>and	Outstanding | Shares<br>Authorized<br>and	Outstanding |  |  | Call	Price	per<br>Share	as	of<br>December	31, |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2017 | 2016 | 2017 |
| Entergy\tArkansas\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| 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 |
| Total\twithout\tsinking\tfund | 313,500 | 313,500 | $31,350 | $31,350 |  |

|  | Shares<br>Authorized<br>and	Outstanding | Shares<br>Authorized<br>and	Outstanding |  |  | Call	Price	per<br>Share	as	of<br>December	31, |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2017 | 2016 | 2017 |
| Entergy\tMississippi\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.36%\tSeries | 59,920 | 59,920 | $5,992 | $5,992 | $103.86 |
| 4.56%\tSeries | 43,887 | 43,887 | 4,389 | 4,389 | $107.00 |
| 4.92%\tSeries | 100,000 | 100,000 | 10,000 | 10,000 | $102.88 |
| Total\twithout\tsinking\tfund | 203,807 | 203,807 | $20,381 | $20,381 |  |

|  | Shares<br>Authorized<br>and	Outstanding | Shares<br>Authorized<br>and	Outstanding |  |  | Call	Price	per<br>Share	as	of<br>December	31, |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2017 | 2016 | 2017 |
| Entergy\tNew\tOrleans\tPreferred\tStock |  |  | (Dollars\tin\tThousands) | (Dollars\tin\tThousands) |  |
| Without\tsinking\tfund: |  |  |  |  |  |
| Cumulative,\t$100\tpar\tvalue: |  |  |  |  |  |
| 4.36%\tSeries\t(a) | — | 60,000 | $— | $6,000 | $— |
| 4.75%\tSeries\t(a) | — | 77,798 | — | 7,780 | $— |
| 5.56%\tSeries\t(a) | — | 60,000 | — | 6,000 | $— |
| Total\twithout\tsinking\tfund | — | 197,798 | $— | $19,780 |  |

(a) In	November	2017,	Entergy	New	Orleans	redeemed	its	$6	million	of	4.36%	Series,	$7.8	million	of	4.75%	Series,	and	$6	million	of	5.56% Series	of	preferred	membership	interests	as	part	of	a	multi-step	internal	restructuring.

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

# Common	Stock

Common	stock	and	treasury	stock	shares	activity	for	Entergy	for	2017,	2016,	and	2015	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 | 75,623,363 | 254,752,788 | 76,363,763 | 254,752,788 | 75,512,079 |
| Repurchases | — | — | — | — | — | 1,468,984 |
| Issuances: |  |  |  |  |  |  |
| Employee\tStock-Based\nCompensation\tPlans | — | (1,377,363) | — | (729,073) | — | (610,409) |
| Directors'\tPlan | — | (10,865) | — | (11,327) | — | (6,891) |
| Ending\tBalance,\tDecember |  |  |  |  |  |  |
| 31 | 254,752,788 | 74,235,135 | 254,752,788 | 75,623,363 | 254,752,788 | 76,363,763 |

Entergy	Corporation	reissues	treasury	shares	to	meet	the	requirements	of	the	Stock	Plan	for	Outside	Directors	(Directors'	Plan),	 three Equity	Ownership	Plans	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,	2017,	$350	million	of authority	remains	under	the	$500	million	share	repurchase	program.

System	Energy	paid	its	parent,	Entergy	Corporation,	distributions	out	of	its	common	stock	of	$21	million	in	2017	and	$40	million	in 2016.

# Retained	Earnings	and	Dividend	Restrictions

Provisions	within	the	articles	of	incorporation	relating	to	preferred	stock	of	each	of	Entergy	Arkansas	and	Entergy	Mississippi	could restrict	the	payment	of	cash	dividends	or	other	distributions	on	their	common	and	preferred	equity	if	such	payment	were	to	occur	when,	or	result in,	a	ratio	of	common	stock	equity	to	total	capitalization	of	25%	or	less.		Entergy	Corporation	received	dividend	payments	and	distributions	from subsidiaries	totaling	$201	million	in	2017,	$165	million	in	2016,	and	$615	million	in	2015.

# Comprehensive	Income

Accumulated	other	comprehensive	income	(loss)	is	included	in	the	equity	section	of	the	balance	sheets	of	Entergy	and	Entergy	Louisiana. The	following	table	presents	changes	in	accumulated	other	comprehensive	income	(loss)	for	Entergy	for	the	year	ended	December	31,	2017	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>gain	(loss) | Foreign<br>currency<br>translation | Total<br>Accumulated<br>Other<br>Comprehensive<br>Income	(Loss) |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Beginning\tbalance,\tJanuary\t1,\t2017 | $3,993 | ($469,446) | $429,734 | $748 | ($34,971) |
| Other\tcomprehensive\tincome\t(loss)\tbefore\nreclassifications | 28,602 | (104,029) | 171,099 | (748) | 94,924 |
| Amounts\treclassified\tfrom\taccumulated\tother\ncomprehensive\tincome\t(loss) | (70,072) | 42,376 | (55,788) | — | (83,484) |
| Net\tother\tcomprehensive\tincome\t(loss)\tfor\nthe\tperiod | (41,470) | (61,653) | 115,311 | (748) | 11,440 |
| Ending\tbalance,\tDecember\t31,\t2017 | ($37,477) | ($531,099) | $545,045 | $— | ($23,531) |

The	following	table	presents	changes	in	accumulated	other	comprehensive	income	(loss)	for	Entergy	for	the	year	ended	December	31, 2016	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>gain	(loss) | Foreign<br>currency<br>translation | Total<br>Accumulated<br>Other<br>Comprehensive<br>Income	(Loss) |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Beginning\tbalance,\tJanuary\t1,\t2016 | $105,970 | ($466,604) | $367,557 | $2,028 | $8,951 |
| Other\tcomprehensive\tincome\t(loss)\tbefore\nreclassifications | 87,740 | (26,997) | 68,465 | (1,280) | 127,928 |
| Amounts\treclassified\tfrom |  |  |  |  |  |
| accumulated\tother\tcomprehensive\tincome |  |  |  |  |  |
| (loss) | (189,717) | 24,155 | (6,288) | — | (171,850) |
| Net\tother\tcomprehensive\tincome\t(loss)\tfor\nthe\tperiod | (101,977) | (2,842) | 62,177 | (1,280) | (43,922) |
| Ending\tbalance,\tDecember\t31,\t2016 | $3,993 | ($469,446) | $429,734 | $748 | ($34,971) |

The	 following table	 presents	 changes in	 accumulated	 other	 comprehensive income	 (loss)	 for	 Entergy	 Louisiana	 for the	 year	 ended December	31,	2017:

Total	reclassifications	out	of	accumulated	other	comprehensive	income	(loss)	(AOCI)	for	Entergy	for	the	years	ended	 December	31,	2017 and	2016	are	as	follows:

| Power	contracts | $108,606 | $293,268 | revenues |
| :--- | :--- | :--- | :--- |
| Interest\trate\tswaps | (803) | (1,395) | \t Miscellaneous\t-\tnet |
| Total\trealized\tgain\t(loss)\ton\tcash\tflow\thedges | 107,803 | 291,873 |  |
|  | (37,731) | (102,156) | Income\ttaxes |
| Total\trealized\tgain\t(loss)\ton\tcash\tflow\thedges\t(net\tof\ttax) | $70,072 | $189,717 |  |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| Amortization\tof\tprior-service\tcosts | $26,251 | $29,414 | (a) |
| Acceleration\tof\tprior-service\tcost\tdue\tto\tcurtailment | — | (1,045) | (a) |
| Amortization\tof\tloss | (86,002) | (60,693) | (a) |
| Settlement\tloss | (7,544) | (2,007) | (a) |
| Total\tamortization | (67,295) | (34,331) |  |
|  | 24,919 | 10,176 | Income\ttaxes |
| Total\tamortization\t(net\tof\ttax) | ($42,376) | ($24,155) |  |
| Net\tunrealized\tinvestment\tgain\t(loss)\nRealized\tgain\t(loss) | $109,388 | $12,329 | Interest\tand\tinvestment\tincome |
|  | (53,600) | (6,041) | Income\ttaxes |
| Total\trealized\tinvestment\tgain\t(loss)\t(net\tof\ttax) | $55,788 | $6,288 |  |
| Total\treclassifications\tfor\tthe\tperiod\t(net\tof\ttax) | $83,484 | $171,850 |  |

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

Total	 reclassifications	 out	 of	 accumulated	 other	 comprehensive income (loss) (AOCI) for	 Entergy	 Louisiana for the	 years	 ended December	31,	2017	and	2016	are	as	follows:

| Amortization	of	prior-service	costs | $7,734 | $7,786 | (a) |
| :--- | :--- | :--- | :--- |
| Amortization\tof\tloss | (5,327) | (6,281) | (a) |
| Total\tamortization | 2,407 | 1,505 |  |
|  | (987) | (549) | Income\ttaxes |
| Total\tamortization\t(net\tof\ttax) | 1,420 | 956 |  |
| Total\treclassifications\tfor\tthe\tperiod\t(net\tof\ttax) | $1,420 | $956 |  |

# NOTE	 8. 	 COMMITMENTS	 AND	 CONTINGENCIES (Entergy	 Corporation,	 Entergy	 Arkansas,	 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	$122.9	million	in	2017,	$158.7	million	in	2016,	and $146	million	in	2015.		If	the	maximum	percentage	(94%)	of	the	energy	is	made	available	to	Entergy	Louisiana,	current	production	projections would	require	estimated	payments	of	approximately	$129	million	in	2018,	and	a	total	of	$1.68	billion	for	the	years	2019	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	October	2011	the	LPSC	approved	a	settlement	under	which Entergy	Louisiana	agreed	to	provide	credits	to	customers	by	crediting	billings	an	additional	$20.235	million	per	year	for	15	years	beginning January	2012.		Entergy	Louisiana	recorded	a	regulatory	charge	and	a	corresponding	regulatory	liability	to	reflect	this	obligation.		The	settlement agreement	allowed	for	an	adjustment	to	the	credits	if,	among	other	things,	there	was	a	change	in	the	applicable	federal	or	state	income	tax	rate.	As a	result	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	and	the	lowering	of	the	federal	corporate	income	tax	rate	from	35%	to 21%,	the	Vidalia	purchased	power	regulatory	liability	was	reduced	by	 $30.5	million,	with	a	corresponding	increase	to	Other	regulatory	credits	on the	income	statement.	The	effects	of	the	Tax	Cuts	and	Jobs	Act	are	discussed	further	in	Note	3	to	the	financial	statements.

# ANO	Damage,	Outage,	and	NRC	Reviews

In	March	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	total	cost	of	assessment,	restoration	of	off-site	power,	site restoration,	debris	removal,	and	replacement	of	damaged	property	and	equipment	was	approximately	$95	million.		Entergy	Arkansas	is	pursuing its	options	for	recovering	damages	that	resulted	from	the	stator	drop,	including	its	insurance	coverage	and	legal	action.	During	2014,	Entergy Arkansas	 collected	$50	million	from	Nuclear	Electric	Insurance	Limited	(NEIL),	a	mutual	insurance	company	that	provides	property	damage coverage	to	the	members'	nuclear	generating	plants.	Litigation	remains	pending.

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.		In	February	2014	the APSC	approved	Entergy	Arkansas's	request	to	exclude	from	the	calculation	of	its	revised	energy	cost	rate	$65.9	million	of	deferred	fuel	and purchased	energy	costs	incurred	in	2013	as	a	result	of	the	ANO	stator	incident.	The	APSC	authorized	Entergy	Arkansas	to	retain	the	$65.9	million in	its	deferred	fuel	balance	with	recovery	to	be	reviewed	in	a	later	period	after	more	information	regarding	various	claims	associated	with	the ANO	 stator	 incident	 is	 available.	In	July	2017,	Entergy	Arkansas	filed	for	a	change	in	rates	pursuant	to	its	formula	rate	plan	rider.	In	 that proceeding,	the	APSC	approved	a	settlement	agreement	agreed	upon	by	the	parties,	including	a	provision	that	requires	Entergy	Arkansas	to	initiate a	proceeding	for	the	purpose	of	recovering	funds	currently	withheld	from	rates	and	related	to	the	stator	incident,	including	the	$65.9	million	of deferred	fuel	and	purchased	energy	costs	previously	noted,	subject	to	certain	timelines	and	conditions	set	forth	in	the	settlement	agreement.

Shortly	after	the	stator	incident,	the	NRC	deployed	an	augmented	inspection	team	to	review	the	plant's	response.		In	July	2013	a	second team	of	NRC	 inspectors	visited	ANO	 to	evaluate	certain	 items	 that	were	 identified	as	requiring	follow-up	 inspection	 to	determine	whether performance	deficiencies	existed.	In	March	2014	the	NRC	issued	an	inspection	report	on	the	follow-up	inspection	that	discussed	two	preliminary findings,	one	that	was	preliminarily	determined	to	be	"red	with	high	safety	significance"	for	Unit	1	and	one	that	was	preliminarily	determined	to be	"yellow	with	substantial	safety	significance"	for	Unit	2,	with	the	NRC	indicating	further	that	these	preliminary	findings	may	warrant	additional regulatory	oversight.	This	report	also	noted	that	one	additional	item	related	to	flood	barrier	effectiveness	was	still	under	review.	In	June	2014	the NRC	classified	both	findings	as	"yellow	with	substantial	safety	significance."

In	March	2015,	after	several	NRC	inspections	and	regulatory	conferences,	the	NRC	issued	a	letter	notifying	Entergy	of	its	decision	to move	ANO	into	the	"multiple/repetitive	degraded	cornerstone	column,"	or	Column	4,	of	the	NRC's	Reactor	Oversight	Process	Action	Matrix. Placement	into	Column	4	requires	significant	additional	NRC	inspection	activities	at	the	ANO	site,	including	a	review	of	the	site's	root	cause evaluation	associated	with	flood	barrier	effectiveness	and	stator	issues,	an	assessment	of	the	effectiveness	of	the	site's	corrective	action	program, an	additional	design	basis	inspection,	a	safety	culture	assessment,	and	possibly	other	inspection	activities	consistent	with	the	NRC's	Inspection Procedure.	Entergy	Arkansas	incurred	incremental	costs	of	approximately	$53	million	in	2015	to	prepare	for	the	NRC	inspection	that	began	in early	 2016.	Excluding	remediation	and	response	costs	that	may	result	from	the	additional	NRC	inspection	activities,	Entergy	Arkansas	also incurred	 approximately	$44	 million	 in	 2016	 in	 support	 of	 NRC	 inspection	 activities	 and	 to	 implement	 Entergy	 Arkansas's	 performance improvement	initiatives	developed	in	2015.	A	lesser	amount	of	incremental	expense	is	expected	to	be	ongoing	annually	after	2016,	until	ANO transitions	out	of	Column	4.

The	 NRC	 completed	 the	 supplemental	 inspection	 required	 for	ANO's	 Column	 4	 designation	 in	 February	 2016,	 and	 published	 its inspection	 report	 in	 June	 2016.	In	 its	 inspection	 report,	 the	 NRC	 concluded	 that	 the	ANO	 site	 is	 being	 operated	 safely	 and	 that	 Entergy understands	the	depth	and	breadth	of	performance	concerns	associated	with	ANO's	performance	decline.	Also	in	June	2016,	the	NRC	issued	a confirmatory	action	letter	to	confirm	the	actions	Entergy	Arkansas	has	taken	and	will	continue	to	take	to	improve	performance	at	ANO.	The	NRC will	verify	the

completion	of	those	actions	through	quarterly	follow-up	inspections,	the	results	of	which	will	determine	when	ANO	should	transition	out	of Column	4.	There	have	been	no	significant	issues	arising	from	the	follow-up	inspections.

# Pilgrim	NRC	Oversight	and	Planned	Shutdown

In	 September	 2015	 the	 NRC	 placed	 Pilgrim	 in	 its	 "multiple/repetitive	 degraded	 cornerstone	 column,"	 or	 Column	 4,	 of	 its	 Reactor Oversight	Process	Action	Matrix	due	to	its	finding	of	continuing	weaknesses	in	Pilgrim's	corrective	action	program	that	contributed	to	repeated unscheduled	 shutdowns	 and	 equipment	 failures.	The	preliminary	estimate	of	direct	costs	of	Pilgrim's	response	to	a	planned	NRC	enhanced inspection	ranges	from	$45	million	to	$60	million,	of	which	$50	million	has	been	incurred	through	the	end	of	2017	in	operation	and	maintenance expense.	The	estimate	does	not	include	potential	capital	expenditures,	which	will	be	charged	directly	to	expense	when	incurred,	or	other	costs	to address	issues	that	may	arise	in	the	inspection.

Entergy	determined	in	October	2015	that	it	would	close	Pilgrim	no	later	than	June	1,	2019	because	of	poor	market	conditions	that	led	to reduced	revenues,	a	poor	market	design	 that	failed	 to	properly	compensate	nuclear	generators	for	 the	benefits	 they	provide,	and	 increased operational	costs.	The	decision	came	after	management's	extensive	analysis	of	the	economics	and	operating	life	of	the	plant	following	the	NRC's decision	to	place	the	plant	in	Column	4.	Entergy	determined	in	April	2016	that	it	intends	to	refuel	Pilgrim	in	2017	and	then	cease	operations	May 31,	2019.	Pilgrim	currently	has	approximately	677	MW	of	Capacity	Supply	Obligations	in	ISO	New	England	through	May	2019.

See	Note	14	to	the	financial	statements	for	discussion	of	the	impairment	of	the	Pilgrim	plant	and	related	long-lived	assets.

# Spent	Nuclear	Fuel	Litigation

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	have	been	charged	fees	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	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.		Following	the	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	per	net	kWh	generated	and	sold	after	April	7,	1983	fee.	In	November	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.	In	January	2014	the	DOE	submitted	the	proposal	to	Congress	under	protest,	and	also	filed	a	petition	for	rehearing with	the	D.C.	Circuit.	The	petition	for	rehearing	was	denied.	The	zero	spent	fuel	fee	went	into	effect	prospectively	in	May	2014.	Management cannot	predict	the	potential	timing	or	magnitude	of	future	spent	fuel	fee	revisions	that	may	occur.

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.	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.	Beginning	 in	 November	 2003	 these	 subsidiaries	 have	 pursued	 litigation	 to	 recover	 the	 damages	 caused	 by	 the	 DOE's	 delay	 in performance.	Following	are	details	of	final	judgments	recorded	by	Entergy	in	2016	related	to	Entergy's	nuclear	owner	licensee	subsidiaries' litigation	with	the	DOE.

In	December	2015	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	amount	of	$81	million	in	favor	of	Entergy	Nuclear	Indian Point	3	and	Entergy	Nuclear	FitzPatrick	in	the	first	round	Indian	Point	3/FitzPatrick	damages	case,	and	Entergy	received	the	payment	from	the U.S.	Treasury	 in	June	2016.	The	effect	of	recording	the	Indian	Point	3	proceeds	was	a	reduction	to	plant,	other	operation	and	maintenance expense,	and	depreciation	expense.	The	Indian	Point	3	damages	awarded	included	$45	million	related	to	costs	previously	capitalized	and	$2 million	related	to	costs	previously	recorded	as	other	operation	and	maintenance	expense.	Of	the	$45	million,	Entergy	recorded	$8	million	as	a reduction	to	previously-recorded	depreciation	expense.	Entergy	reduced	its	Indian	Point	3	plant	asset	balance	by	the	remaining	$37	million.	The effect	of	recording	the	FitzPatrick	proceeds	was	a	reduction	to	plant	and	other	operation	and	maintenance	expense.	The	FitzPatrick	damages awarded	included	$32	million	related	to	costs	previously	capitalized	and	$2	million	related	to	costs	previously	recorded	as	other	operation	and maintenance	expense.	Of	the	$32	million,	Entergy	recorded	$1	million	as	a	reduction	to	previously-recorded	depreciation	expense,	a	$10	million reduction	to	bring	its	remaining	FitzPatrick	plant	asset	balance	 to	zero,	and	the	excess	was	recorded	as	a	reduction	to	other	operations	and maintenance	expense.	See	Note	14	for	further	discussion	on	the	fair	value	analysis	performed	for	FitzPatrick	and	the	related	impairment	charge.

In	April	2016	the	U.S.	Court	of	Federal	Claims	issued	a	partial	judgment	in	the	amount	of	 $42	million	in	favor	of	Entergy	Louisiana	and against	the	DOE	in	the	first	round	River	Bend	damages	case.	Entergy	Louisiana	received	payment	from	the	U.S.	Treasury	in	August	2016.	The effects	of	recording	the	final	judgment	in	the	third	quarter	2016	were	reductions	to	plant,	nuclear	fuel	expense,	other	operation	and	maintenance expense,	and	depreciation	expense.	The	River	Bend	damages	awarded	included	$17	million	related	to	costs	previously	capitalized,	$23	million related	 to	 costs	 previously	 recorded	 as	 nuclear	 fuel	 expense,	 and	$2	 million	 related	 to	 costs	 previously	 recorded	 as	 other	 operation	 and maintenance	 expense.	Of	the	$17	million,	Entergy	Louisiana	recorded	$3	million	as	a	reduction	to	previously-recorded	depreciation	expense. Entergy	Louisiana	reduced	its	River	Bend	plant	asset	balance	by	the	remaining	$14	million.	In	September	2016	the	U.S.	Court	of	Federal	Claims issued	a	further	judgment	in	the	River	Bend	case	in	the	amount	of	$5	million.	Entergy	Louisiana	recorded	a	receivable	for	that	amount,	and subsequently	received	payment	from	the	U.S.	Treasury	in	January	2017.	The	River	Bend	damages	awarded	included	$2	million	related	to	costs previously	recorded	as	nuclear	fuel	expense	and	$3	million	related	to	costs	previously	recorded	as	other	operation	and	maintenance	expense.	In May	2017	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	first	round	River	Bend	damages	case	for	$0.6	million,	awarding	certain cask	loading	costs	that	had	not	previously	been	adjudicated	by	the	court.

In	May	2016,	Entergy	Nuclear	Vermont	Yankee	and	the	DOE	entered	into	a	stipulation	agreement	and	the	U.S.	Court	of	Federal	Claims issued	a	judgment	in	the	amount	of	$19	million	in	favor	of	Entergy	Nuclear	Vermont	Yankee	and	against	the	DOE	in	the	second	round	Vermont Yankee	damages	case.	Entergy	received	payment	from	the	U.S.	Treasury	in	June	2016.	The	effect	of	recording	the	proceeds	was	a	reduction	to other	 operation	 and	 maintenance	 expense	 and	 depreciation	 expense.	The	 damages	 awarded	 included	$15	million	 related	 to	 costs	 previously capitalized	and	$4	million	related	to	costs	previously	recorded	as	other	operation	and	maintenance	expense.	Of	the	$15	million,	Entergy	recorded $2	million	as	a	reduction	to	previously-recorded	depreciation	expense.	The	remaining	$13	million	would	have	been	recorded	as	a	reduction	to Vermont	Yankee's	plant	asset	balance,	but	was	recorded	as	a	reduction	to	other	operation	and	maintenance	expense	because	Vermont	Yankee's plant	asset	balance	is	fully	impaired.

In	June	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	amount	of	$49	million	in	favor	of	System	Energy	and	against the	DOE	in	the	second	round	Grand	Gulf	damages	case.	System	Energy	received	payment	from	the	U.S.	Treasury	in	August	2016.	The	effects	of recording	the	judgment	in	the	third	quarter	2016	were	reductions	to	plant,	nuclear	fuel	expense,	other	operation	and	maintenance	expense,	and depreciation	 expense.	The	amounts	of	Grand	Gulf	damages	awarded	related	to	System	Energy's	90%	ownership	of	Grand	Gulf	included	$16 million	related	to	costs	previously	capitalized,	$19	million	related	to	costs	previously	recorded	as	nuclear	fuel	expense,	and	$9	million	related	to costs	previously	recorded	as	other	operation	and	maintenance	expense.	Of	the	$16	million,	System	Energy	recorded	$5	million	as	a	reduction	to previously-recorded	depreciation	expense.	System	Energy	reduced	its	Grand	Gulf	plant	asset	balance	by	the	remaining	$11	million.

In	July	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	amount	of	$31	million	in	favor	of	Entergy	Arkansas	and against	the	DOE	in	the	second	round	ANO	damages	case.	Entergy	Arkansas	received	payment	from	the	U.S.	Treasury	in	October	2016.	The effects	of	recording	 the	 judgment	were	reductions	 to	plant,	nuclear	fuel	expense,	and	other	operation	and	maintenance	expense.	The	ANO damages	awarded	included	$6	million	related	to	costs	previously	capitalized,	$19	million	related	to	costs	previously	recorded	as	nuclear	fuel expense,	$5	million	related	to	costs	previously	recorded	as	other	operation	and	maintenance	expense,	and	 $1	million	related	to	costs	previously recorded	as	taxes	other	than	income	taxes.

In	August	2016	the	U.S.	Court	of	Federal	Claims	issued	a	partial	judgment	in	the	amount	of	$53	million	in	favor	of	Entergy	Louisiana	and against	the	DOE	in	the	first	round	Waterford	3	damages	case.	Entergy	Louisiana	received	payment	from	the	U.S.	Treasury	in	November	2016. The	effects	of	recording	the	judgment	were	reductions	to	plant,	nuclear	fuel	expense,	other	operation	and	maintenance	expense,	and	depreciation expense.	The	Waterford	3	damages	awarded	included	$41	million	related	to	costs	previously	capitalized,	$10	million	related	to	costs	previously recorded	as	nuclear	fuel	expense,	and	$2	million	related	to	costs	previously	recorded	as	other	operation	and	maintenance	expense.	Of	the	$41 million,	Entergy	Louisiana	recorded	$3	million	as	a	reduction	to	previously-recorded	depreciation	expense.

In	September	2016	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	Entergy	Nuclear	Palisades	case	in	the	amount	of	 $14 million.	Entergy	Nuclear	Palisades	recorded	a	receivable	for	that	amount,	and	subsequently	received	payment	from	the	U.S.	Treasury	in	January 2017.	The	effects	of	recording	the	judgment	were	reductions	to	plant	and	other	operation	and	maintenance	expenses.	The	Palisades	damages awarded	included	$11	million	related	to	costs	previously	capitalized	and	$3	million	related	to	costs	previously	recorded	as	other	operation	and maintenance	 expense.	Of	 the	 $11	 million,	 Entergy	 recorded	$1	million	 as	 a	 reduction	 to	 previously-recorded	 depreciation	 expense.	Entergy reduced	its	Palisades	plant	asset	balance	by	the	remaining	$10	million.	The	Court	previously	issued	a	partial	judgment	in	the	case	in	the	amount	of $21	million,	which	was	paid	by	the	U.S.	Treasury	in	October	2015.

In	October	2016	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	second	round	Entergy	Nuclear	Indian	Point	2	case	in	the amount	of	$34	million.	Entergy	Nuclear	Indian	Point	2	recorded	a	receivable	for	that	amount,	and	subsequently	received	payment	from	the	U.S. Treasury	in	January	2017.	The	effects	of	recording	the	judgment	were	reductions	to	plant	and	other	operation	and	maintenance	expenses.	The Indian	Point	2	damages	awarded	included	$14	million	related	to	costs	previously	capitalized,	$15	million	related	to	costs	previously	recorded	as other	operation	and	maintenance	expense,	$3	million	related	to	previously	recorded	decommissioning	expense,	and	$2	million	related	to	costs previously	recorded	as	taxes	other	than	income	taxes.	Of	the	$14	million,	Entergy	recorded	$3	million	as	a	reduction	to	previously-recorded depreciation	expense.	Entergy	reduced	its	Indian	Point	2	plant	asset	balance	by	the	remaining	$11	million.

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.

# 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 of	$450	million	for	each	operating	reactor	(prior	to	January	1,	2017,	the	primary	level	of	insurance	was	$375	million).		If	this	amount	is not	sufficient	to	cover	claims	arising	from	an	accident,

the	second	level,	Secondary	Financial	Protection,	applies.	In	2016	the	NRC	approved	Vermont	Yankee's	exemption	request	to	lower	their limits	from	$375	million	to	$100	million	effective	April	15,	2016.

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 approximately	$127.3	 million	 per	 reactor	 per	 incident	 (Entergy's	 maximum	 total	 contingent	 obligation	 per	 incident	 is	 $1.146 billion).		This	retrospective	premium	is	payable	at	a	rate	currently	set	at	approximately	 $19	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	approximately	$13	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.	Under	current	law,	the	Terrorism	Risk	Insurance	Act	extends	through	2020.

Currently,	102	nuclear	reactors	are	participating	in	the	Secondary	Financial	Protection	program.	 	Effective	April	15,	2016	the	NRC granted	Vermont	Yankee's	 exemption	 request	 and	 it	 was	 allowed	 to	 withdraw	 from	 participation	 in	 this	 layer	 of	 financial	 protection.	 The Secondary	Financial	Protection	program	provides	approximately	$13	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	and	Entergy	Louisiana	each	have	two	licensed	reactors.	System	Energy	has	one	licensed	reactor	(10%	of	Grand	Gulf	is owned	by	a	non-affiliated	company	(Cooperative	Energy)	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,	operation,	and	decommissioning of	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	 NEIL,	 a	 mutual	 insurance	 company	 that	 provides	 property	 damage coverage,	including	decontamination	and	premature	decommissioning	expense,	to	the	members'	nuclear	generating	plants.		The	property	damage insurance	 limits	 procured	 by	 Entergy	 for	 its	 Utility	 plants	 and	 Entergy	Wholesale	 Commodity	 plants	 are	 in	 compliance	 with	 the	 financial protection	requirements	of	the	NRC.

The	Utility	plants'	(ANO	1	and	2,	Grand	Gulf,	River	Bend,	and	Waterford	3)	property	damage	insurance	limits	are	 $1.5	billion	 per occurrence	at	each	plant	with	an	additional	$100	million	per	occurrence	that	is	shared	among	the	plants.	Property	damage	from	earthquake	and volcanic	eruption	is	excluded	from	the	first	$500	million	in	coverage	for	all	Utility	plants.	Property	damage	from	flood	is	excluded	from	the	first $500	million	in	coverage	at	ANO	1	and	2	and	Grand	Gulf.	Property	damage	from	flood	is	included	in	the	first	$500	million	for	Waterford	3	and River	Bend.	Property	damage	from	wind	for	all	of	the	Utility	nuclear	plants	includes	a	deductible	of	$10	million	plus	an	additional	10%	of	the amount	of	the	loss	in	excess	of	$10	million,	up	to	a	total	maximum	deductible	of	$50	million.

The	Entergy	Wholesale	Commodities'	plants	(Pilgrim,	Palisades,	Indian	Point,	Vermont	Yankee,	and	Big	Rock	Point)	have	property damage	insurance	limits	as	follows:	Vermont	Yankee	-	 $50	million	per	occurrence;	Big	Rock	Point	-	$500	million	per	occurrence;	Pilgrim	and Palisades	-	$1.115	billion	per	occurrence;	and	Indian	Point	-	$1.6	billion	per	occurrence.	For	losses	that	are	considered	non-nuclear	in	nature,	the property	damage	insurance	limit	at	Pilgrim,	Palisades,	and	Indian	Point	is	$500	million	and	at	Vermont	Yankee	is	 $50	million.	Property	damage from	wind	and	flood	at	Indian	Point	includes	a	deductible	of	$10	million	plus	an	additional	10%	of	the	amount	of	the	loss	in	excess	of	$10	million, up	to	a	maximum	deductible	of	$50	million,	but	property	damage	from	earthquake	and	volcanic	eruption	at	Indian	Point	is	excluded	from	the	first $500	million.	Property	damage	from	wind	at	Pilgrim	includes	a	deductible	of	$10	million	plus	an	additional	10%	of	the	amount	of	the	loss	in excess	of	$10	million,	up	to	a	maximum

deductible	of	$50	million,	but	property	damage	from	flood,	earthquake,	and	volcanic	eruption	at	Pilgrim	is	excluded	from	the	first	 $500	million. Property	damage	from	wind,	flood,	earthquake,	and	volcanic	eruption	at	Vermont	Yankee	and	Palisades	includes	a	deductible	of	 $10	million	plus an	additional	10%	of	the	amount	of	the	loss	in	excess	of	$10	million,	up	to	a	maximum	deductible	of	$50	million.

The	 value	 of	 the	 insured	 property	 at the time	 of	 an	 accident	 at	 Pilgrim,	 Palisades,	 and	Vermont	Yankee	 has	 been	 changed from replacement	cost	to	actual	cash	value.

In	addition,	Waterford	3	and	Grand	Gulf	are	also	covered	under	NEIL's	Accidental	Outage	Coverage	program.		Due	to	Entergy's	gradual exit	from	the	merchant/wholesale	power	business,	Entergy	no	longer	purchases	Accidental	Outage	Coverage	for	its	non-regulated,	non-generation assets.	Accidental	outage	coverage	provides	indemnification	for	the	actual	cost	incurred	in	the	event	of	an	unplanned	outage	resulting	from property	damage	covered	under	the	NEIL	Primary	Property	Insurance	policy,	subject	to	a	deductible	period.		The	indemnification	for	the	actual cost	incurred	is	based	on	market	power	prices	at	the	time	of	the	loss.	For	non-nuclear	events,	the	maximum	indemnity,	under	this	policy,	is	limited to	$327.6	million	per	occurrence.	After	the	deductible	period	has	passed,	weekly	indemnities	for	an	unplanned	outage,	covered	under	NEIL's Accidental	Outage	Coverage	program,	would	be	paid	according	to	the	amounts	listed	below:

•100%	of	the	weekly	indemnity	for	each	week	for	the	first	payment	period	of	52	weeks;	then •80%	of	the	weekly	indemnity	for	each	week	for	the	second	payment	period	of	52	weeks;	and	thereafter •80%	of	the	weekly	indemnity	for	an	additional	58	weeks	for	the	third	and	final	payment	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,	2017,	the	maximum	amounts	of	such	possible	assessments	per occurrence	were	as	follows:

|  | Assessments |
| :--- | :--- |
|  | (In\tMillions) |
| Utility: |  |
| Entergy\tArkansas | $40.3 |
| Entergy\tLouisiana | $49.4 |
| Entergy\tMississippi | $0.11 |
| Entergy\tNew\tOrleans | $0.11 |
| Entergy\tTexas | N/A |
| System\tEnergy | $22.3 |

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

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	not	exceeding	$3.24	billion	plus	the	additional	amounts	recovered	for	such	losses from	reinsurance,	indemnity,	and	any	other	sources	applicable	to	such	losses.

# Non-Nuclear	Property	Insurance

Entergy's	 non-nuclear	 property	 insurance	 program	 provides	 coverage	 on	 a	 system-wide	 basis	 for	 Entergy's	 non-nuclear	 assets.	The insurance	program	provides	coverage	up	to	$400	million	per	occurrence,	"each	and	every	loss"	basis	in	excess	of	a	 $20	million	self-insured retention	with	the	exception	of	the	following:	earthquake	shock,	flood,	and	named	windstorm,	including	associated	storm	surge.	For	earthquake shock	and	flood,	the	insurance	program	provides	coverage	up	to	$400	million	on	an	annual	aggregate	basis	in	excess	of	a	$40	million	self-insured retention.	For	named	windstorm	and	associated	storm	surge,	the	insurance	program	provides	coverage	up	to	$125	million	on	an	annual	aggregate basis	 in	 excess	 of	 a	$40	million	self-insured	retention.	 	The	coverage	provided	by	the	insurance	program	for	the	Entergy	New	Orleans	gas distribution	system	is	limited	to	$50	million	per	occurrence	and	is	subject	to	the	same	annual	aggregate	limits	and	retentions	listed	above	for earthquake	shock,	flood,	and	named	windstorm,	including	associated	storm	surge.

Covered	property	generally	includes	power	plants,	substations,	facilities,	inventories,	and	gas	distribution-related	properties.		Excluded property	generally	includes	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.	Under	current law,	the	Terrorism	Risk	Insurance	Act	extends	through	2020.

Prior	to	June	1,	2017,	Entergy	purchased	additional	coverage	for	some	of	its	non-regulated,	non-generation	assets	in	addition	to	the insurance	procured	via	the	conventional	property	insurance	program.	The	policy	served	to	buy-down	the	conventional	property	insurance	policy's $20	million	deductible	and	was	placed	on	a	scheduled	location	basis.		Due	to	Entergy's	gradual	exit	from	the	merchant/wholesale	power	business, effective	June	1,	2017,	Entergy	no	longer	purchases	this	additional	coverage	($20	million	per	occurrence)	for	some	of	its	non-regulated,	non- generation	assets.

# 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	Arkansas,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas)

Numerous	 lawsuits	 have	 been	 filed	 in	 federal	 and	 state	 courts,	 primarily	 by	 contractor	 employees	 who	 worked	 in	 the	 1940-1980s timeframe,	primarily	against	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 200	lawsuits	involving

approximately	500	 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.		In	December	2016	the	NRC	granted	the	extension	of	Grand	Gulf's	operating	license	to	2044.	Monthly	obligations	are based	on	actual	capacity	and	energy	costs.		The	average	monthly	payments	for	2017	under	the	agreement	are	approximately	$19.5	million	for Entergy	Arkansas,	$7.8	million	for	Entergy	Louisiana,	$17	million	for	Entergy	Mississippi,	and	$9.4	million	for	Entergy	New	Orleans.	See	Note	2 to	the	financial	statements	for	discussion	of	the	complaint	filed	with	the	FERC	against	System	Energy	seeking	a	reduction	in	the	return	on	equity component	of	the	Unit	Power	Sales	Agreement.

# 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.		The	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.

# NOTE	 9.	ASSET	RETIREMENT	OBLIGATIONS	(Entergy	Corporation,	Entergy	Arkansas,	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:

|  | (In	Millions) | (In	Millions) |
| :--- | :--- | :--- |
| Entergy\tArkansas | $176.9 | $128.5 |
| Entergy\tLouisiana | ($32.4) | ($53.9) |
| Entergy\tMississippi | $91.6 | $82.0 |
| Entergy\tNew\tOrleans | $44.8 | $40.1 |
| Entergy\tTexas | $55.2 | $33.5 |
| System\tEnergy | $67.9 | $69.7 |

The	cumulative	decommissioning	and	retirement	cost	liabilities	and	expenses	recorded	in	 2017	and	2016	by	Entergy	were	as	follows:

|  | Liabilities	as<br>of	December	31,<br>2016 |  | Accretion | Change	in<br>Cash	Flow<br>Estimate | Spending | Dispositions |  | Liabilities	as<br>of	December	31,<br>2017 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |  |
| Utility: |  |  |  |  |  |  |  |  |
| Entergy\tArkansas | $924.4 |  | $56.8 | $— | $— | $— |  | $981.2 |
| Entergy\tLouisiana | 1,082.7 |  | 57.8 | — | — | — |  | 1,140.5 |
| Entergy\tMississippi | 8.7 |  | 0.5 | — | — | — |  | 9.2 |
| Entergy\tNew\tOrleans | 2.9 |  | 0.2 | — | — | — |  | 3.1 |
| Entergy\tTexas | 6.5 |  | 0.3 | — | — | — |  | 6.8 |
| System\tEnergy | 854.2 |  | 43.4 | (35.9) | — | — |  | 861.7 |
| Total | 2,879.4 |  | 159.0 | (35.9) | — | — |  | 3,002.5 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |  |  |  |
| Big\tRock\tPoint | 37.9 |  | 3.1 | — | (2.1) | — |  | 38.9 |
| FitzPatrick | 714.3 | (a) | 13.9 | — | (0.9) | (727.3) | (b) | — |
| Indian\tPoint\t1 | 207.6 |  | 17.7 | — | (7.7) | — |  | 217.6 |
| Indian\tPoint\t2 | 653.1 |  | 55.8 | — | (0.2) | — |  | 708.7 |
| Indian\tPoint\t3 | 641.1 |  | 53.5 | — | (0.1) | — |  | 694.5 |
| Palisades | 500.3 |  | 41.3 | (68.7) | (2.5) | — |  | 470.4 |
| Pilgrim | 602.3 |  | 52.8 | — | (3.7) | — |  | 651.4 |
| Vermont\tYankee | 470.5 |  | 34.4 | — | (103.4) | — |  | 401.5 |
| Other\t(c) | 0.3 |  | — | — | — | — |  | 0.3 |
| Total | 3,827.4 |  | 272.5 | (68.7) | (120.6) | (727.3) |  | 3,183.3 |
| Entergy\tTotal | $6,706.8 |  | $431.5 | ($104.6) | ($120.6) | ($727.3) |  | $6,185.8 |

|  | Liabilities	as<br>of	December	31,<br>2015 |  | Liabilities<br>Incurred | Accretion | Change	in<br>Cash	Flow<br>Estimate | Spending | Liabilities	as<br>of	December	31,<br>2016 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tMillions) |  |  |  |
| Utility: |  |  |  |  |  |  |  |
| Entergy\tArkansas | $872.3 |  | $— | $53.6 | $— | ($1.5) | $924.4 |
| Entergy\tLouisiana | 1,027.9 |  | — | 54.8 | — | — | 1,082.7 |
| Entergy\tMississippi | 8.3 |  | — | 0.4 | — | — | 8.7 |
| Entergy\tNew\tOrleans | 2.7 |  | — | 0.2 | — | — | 2.9 |
| Entergy\tTexas | 6.1 |  | — | 0.4 | — | — | 6.5 |
| System\tEnergy | 803.4 |  | — | 50.8 | — | — | 854.2 |
| Total | 2,720.7 |  | — | 160.2 | — | (1.5) | 2,879.4 |
| Entergy\tWholesale\tCommodities: |  |  |  |  |  |  |  |
| Big\tRock\tPoint | 28.0 |  | — | 2.2 | 10.1 | (2.4) | 37.9 |
| FitzPatrick | — | (d) | 696.2 | 18.1 | — | — | 714.3 |
| Indian\tPoint\t1 | 197.9 |  | — | 17.1 | (0.3) | (7.1) | 207.6 |
| Indian\tPoint\t2 | 390.1 |  | — | 33.0 | 230.0 | — | 653.1 |
| Indian\tPoint\t3 | — | (d) | 466.3 | 12.1 | 162.7 | — | 641.1 |
| Palisades | 342.0 |  | — | 29.5 | 128.8 | — | 500.3 |
| Pilgrim | 551.2 |  | — | 48.4 | 3.2 | (0.5) | 602.3 |
| Vermont\tYankee | 560.0 |  | — | 39.3 | — | (128.8) | 470.5 |
| Other\t(c) | 0.3 |  | — | — | — | — | 0.3 |
| Total | 2,069.5 |  | 1,162.5 | 199.7 | 534.5 | (138.8) | 3,827.4 |
| Entergy\tTotal | $4,790.2 |  | $1,162.5 | $359.9 | $534.5 | ($140.3) | $6,706.8 |

(a) The	FitzPatrick	asset	retirement	obligation	was	classified	as	held	for	sale	within	other	non-current	liabilities	on	the	consolidated	balance sheet	as	of	December	31,	2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	sale	of	the	FitzPatrick	plant	to	Exelon	in March	2017.

(b) See	Note	14	to	the	financial	statements	for	discussion	of	the	sale	of	the	FitzPatrick	plant	to	Exelon	in	March	2017.

(c) See	"Coal	Combustion	Residuals"	below	for	additional	discussion	regarding	the	asset	retirement	obligations	related	to	coal	combustion residuals	management.

(d) See "Entergy	 Wholesale	 Commodities" in "Nuclear	 Plant	 Decommissioning" below for additional discussion regarding the decommissioning	agreements	with	NYPA	and	the	associated	asset	retirement	obligations.

# Nuclear	Plant	Decommissioning

Entergy	periodically	reviews	and	updates	estimated	decommissioning	costs.	 	The	actual	decommissioning	costs	may	vary	from	 the estimates	because	of	the	timing	of	plant	decommissioning,	regulatory	requirements,	changes	in	technology,	and	increased	costs	of	labor,	materials, and	equipment.		As	described	below,	during	2017	and	2016,	Entergy	updated	decommissioning	cost	estimates	for	certain	nuclear	power	plants.

In	the	second	quarter	2017,	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	$35.9	million

reduction	 in	 its	decommissioning	cost liability,	along	with	a	corresponding	reduction in the	related	asset	retirement	cost	asset that	will	be depreciated	over	the	remaining	life	of	the	unit.

In	August	2013	the	Board	approved	a	plan	to	close	and	decommission	Vermont	Yankee	at	the	end	of	2014.	 Vermont	Yankee	submitted notification	of	permanent	cessation	of	operations	and	permanent	removal	of	fuel	from	 the	reactor	 in	January	2015	after	final	shutdown	 in December	 2014.	Vermont	Yankee's	future	certifications	to	satisfy	the	NRC's	financial	assurance	requirements	will	now	be	based	on	the	site specific	 cost	 estimate,	 including	 the	 estimated	 cost	 of	 managing	 spent	 fuel,	 rather	 than	 the	 NRC	 minimum	 formula	 for	 estimating decommissioning	 costs.	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.

Entergy	expects	that	amounts	available	in	Vermont	Yankee's	decommissioning	trust	fund,	including	expected	earnings,	together	with borrowings	under	its	credit	facility	that	are	expected	to	be	repaid	with	recoveries	from	DOE	litigation	related	to	spent	fuel	storage,	and	the	site restoration	 trust,	 will	 be	 sufficient	 to	 cover	Vermont	Yankee's	 expected	 costs	 of	 decommissioning,	 spent	 fuel	 management	 costs,	 and	 site restoration.	See	Note	4	to	the	financial	statements	for	discussion	of	the	credit	facility	and	Note	16	to	the	financial	statements	for	discussion	of	the decommissioning	 trust	 fund.	 In	 June	 2015	 the	 NRC	 staff	 issued	 an	 exemption	 from	 its	 regulations	 to	 allow	 Vermont	Yankee	 to	 use	 its decommissioning	trust	fund	to	pay	for	approximately	$225	million	of	estimated	future	spent	fuel	management	costs	that	will	not	be	paid	for	using funds	from	its	credit	facility.		In	August	2015,	Vermont	and	two	Vermont	utilities	filed	a	petition	in	the	U.S.	Court	of	Appeals	for	the	D.C.	Circuit challenging	the	NRC's	issuance	of	that	exemption.		In	February	2016	the	court	dismissed	the	petition	as	premature	because	Vermont	and	the utilities	had	requested	the	NRC	to	reconsider	a	number	of	issues	related	to	Vermont	Yankee's	use	of	the	decommissioning	trust	fund	including	its use	to	pay	for	spent	fuel	management	expenses	pursuant	to	the	exemption	granted	in	June	2015.	In	October	2016	the	NRC	denied	Vermont's	and the	utilities'	request	for	a	hearing	and	other	relief	but	directed	the	NRC	staff	to	conduct	an	assessment	of	any	environmental	impacts	associated with	the	exemption.	In	December	2017	the	NRC	issued	its	final	environmental	assessment,	concluding	that	the	exemption	did	not,	and	will	not, have	a	significant	effect	on	the	environment.

In	 the	fourth	quarter	2016,	Entergy	Wholesale	Commodities	recorded	a	revision	 to	 its	estimated	decommissioning	cost	 liability	for Palisades	as	a	result	of	a	revised	decommissioning	cost	study.	The	revised	estimate	resulted	in	a	$129	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	on	October	1,	2018,	subject	to	regulatory	approval.	The	asset	retirement	cost	asset	was	included	in	the	Palisades	carrying	value	that	was written	down	to	fair	value	in	the	fourth	quarter	2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	impairment	of	the	value	and planned	shutdown	of	the	Palisades	plant.

In	 the	 third	 quarter	 2017,	 Entergy	 Wholesale	 Commodities	 recorded	 a	 revision	 to	 its	 estimated	 decommissioning	 cost	 liability	 for Palisades.	The	revised	estimate	resulted	in	a	$68.7	million	reduction	in	its	decommissioning	cost	liability,	along	with	a	corresponding	reduction	in the	plant	asset.	The	reduction	in	its	estimated	decommissioning	cost	liability	resulted	from	the	change	in	expectation	regarding	the	timing	of decommissioning	cash	flows	due	to	the	decision	to	continue	to	operate	the	plant	until	May	31,	2022.

For	the	Indian	Point	3	and	FitzPatrick	plants	purchased	in	2000	from	NYPA,	NYPA	retained	the	decommissioning	trust	funds	and	the decommissioning	liabilities.		NYPA	and	Entergy	subsidiaries	executed	decommissioning	agreements,	which	specified	their	decommissioning obligations.		NYPA	had	the	right	to	require	the	Entergy	subsidiaries	to	assume	each	of	the	decommissioning	liabilities	provided	that	it	assigned	the corresponding	decommissioning	trust,	up	to	a	specified	level,	to	the	Entergy	subsidiaries.		Under	the	original	agreements,	if	the	decommissioning liabilities	were	retained	by	NYPA,	the	Entergy	subsidiaries	would	perform	the	decommissioning	of

the	plants	at	a	price	equal	to	the	lesser	of	a	pre-specified	level	or	the	amount	in	the	decommissioning	trust	funds.	At	the	time	of	the	acquisition	of the	plants	Entergy	recorded	a	contract	asset	that	represented	an	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	was 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	was	recorded	as	interest	income.

In	the	third	quarter	2015,	Entergy	Wholesale	Commodities	recorded	a	revision	to	the	contract	asset	for	the	FitzPatrick	plant.	Due	to	a change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows,	the	result	was	a	write	down	of	the	contract	asset	from	$335	million	to $131	million,	for	a	charge	of	$204	million.

In	 August	 2016,	 Entergy	 entered	 into	 a	 trust	 transfer	 agreement	 with	 NYPA	 to	 transfer	 the	 decommissioning	 trust	 funds	 and decommissioning	liabilities	for	the	Indian	Point	3	and	FitzPatrick	plants	to	Entergy.	As	a	result	of	the	agreement	with	NYPA,	in	the	third	quarter 2016	Entergy	removed	the	contract	asset	from	its	balance	sheet,	and	recorded	receivables	for	the	beneficial	interests	in	the	decommissioning	trust funds	and	asset	retirement	obligations	for	the	decommissioning	liabilities.	The	transaction	was	contingent	upon	receiving	approval	from	the	NRC, which	was	received	in	January	2017.		The	decommissioning	trust	funds	for	the	Indian	Point	3	and	FitzPatrick	plants	were	transferred	to	Entergy by	 NYPA	 in	 January	 2017.	In	 March	 2017,	 Entergy	 sold	 the	 FitzPatrick	 plant	 to	 Exelon,	 and	 as	 part	 of	 the	 transaction,	 the	 FitzPatrick decommissioning	trust	fund,	along	with	the	decommissioning	obligation	for	that	plant,	was	transferred	to	Exelon.	See	Note	14	to	the	financial statements	for	discussion	of	the	sale	of	FitzPatrick.

In	the	fourth	quarter	2016,	Entergy	Wholesale	Commodities	recorded	a	revision	to	its	estimated	decommissioning	cost	liabilities	for Indian	Point	1,	Indian	Point	2,	and	Indian	Point	3	as	a	result	of	revised	decommissioning	cost	studies.	The	revised	estimates	resulted	in	a	$392 million	 increase	 in	 the	decommissioning	cost	 liabilities,	along	with	a	corresponding	 increase	 in	 the	related	asset	retirement	cost	assets.	The increase	in	the	estimated	decommissioning	cost	liabilities	resulted	from	the	change	in	expectation	regarding	the	timing	of	decommissioning	cash flows	due	to	the	decision	to	cease	operations	of	the	Indian	Point	2	plant	no	later	than	April	2020	and	the	Indian	Point	3	plant	no	later	than	April 2021.	The	asset	retirement	cost	assets	were	included	in	the	carrying	value	that	was	written	down	to	fair	value	in	the	fourth	quarter	2016.	See	Note 14	to	the	financial	statements	for	discussion	of	the	impairment	of	the	value	and	planned	shutdown	of	Indian	Point	Energy	Center.

As	 the	 Entergy	 Wholesale	 Commodities	 nuclear	 plants	 individually	 approach	 and	 begin	 decommissioning,	 the	 Entergy	 Wholesale Commodities	plant	owners	will	submit	filings	with	the	NRC	for	planned	shutdown	activities.	These	filings	with	the	NRC	will	determine	whether any	other	financial	assurance	may	be	required.	The	plants'	owners	are	required	to	provide	the	NRC	with	a	biennial	report	(annually	for	units	that have	shut	down	or	will	shut	down	within	five	years),	based	on	values	as	of	December	31,	addressing	the	owners'	ability	to	meet	the	NRC minimum	funding	levels.	Depending	on	the	value	of	the	trust	funds,	the	Entergy	Wholesale	Commodities	plant	owners	may	be	required	to	take steps,	such	as	providing	financial	guarantees	through	letters	of	credit	or	parent	company	guarantees	or	making	additional	contributions	to	the trusts,	which	could	be	significant,	to	ensure	that	the	trusts	are	adequately	funded	and	that	NRC	minimum	funding	requirements	are	met.

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,	2017	and	2016	are	as	follows:

|  | 2017 |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Decommissioning\nTrust\tFair\tValues | Regulatory\nAsset\t(Liability) | Decommissioning\nTrust\tFair\tValues | Regulatory\nAsset\t(Liability) |
|  | (In\tMillions) |  | (In\tMillions) |  |
| Utility: |  |  |  |  |
| ANO\t1\tand\tANO\t2 | $944.9 | $337.9 | $834.7 | $316.3 |
| River\tBend | $818.2 | ($30.6) | $712.8 | ($28.4) |
| Waterford\t3 | $493.9 | $188.9 | $427.9 | $172.8 |
| Grand\tGulf | $905.7 | $169.1 | $780.5 | $142.5 |
| Entergy\tWholesale\tCommodities | $4,049.3 | $— | $2,968.0 | $— |

As	a	result	of	the	agreement	with	NYPA	discussed	above,	in	the	third	quarter	2016,	Entergy	removed	the	contract	asset	from	its	balance sheet,	and	recorded	receivables	of	$1.5	billion	for	the	beneficial	interests	in	the	decommissioning	trust	funds	for	Indian	Point	3	and	FitzPatrick.	At December	31,	2016,	the	fair	values	of	the	decommissioning	trust	funds	held	by	NYPA	were	$719	million	for	the	Indian	Point	3	plant	and	$785 million	for	the	FitzPatrick	plant.	See	Note	16	to	the	financial	statements	for	further	discussion	of	the	transfer	of	the	decommissioning	trust	funds held	by	NYPA	to	Entergy.

# Coal	Combustion	Residuals

In	June	2010	the	EPA	issued	a	proposed	rule	on	coal	combustion	residuals	(CCRs)	that	contained	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	reused	in	certain	processes	would	remain	excluded from	hazardous	waste	regulation.	In	April	2015	the	EPA	published	the	final	CCR	rule	with	the	material	being	regulated	under	the	second	scenario presented	 above	 -	 as	 non-hazardous	 wastes	 regulated	 under	 RCRA	 Subtitle	 D.	The	 final	 regulations	 create	 new	 compliance	 requirements including	modified	storage,	new	notification	and	reporting	practices,	product	disposal	considerations,	and	CCR	unit	closure	criteria.		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. In	December	2016,	the	Water	Infrastructure	Improvements	for	the	Nation	Act	(WIIN	Act)	was	signed	into	law,	which	authorizes	states	to	regulate coal	 ash	 rather	 than	 leaving	 primary	 enforcement	 to	 citizen	 suit	 actions.	States	 may	 submit	 to	 the	 EPA	 proposals	 for	 permit	 programs.	In September	2017	the	EPA	agreed	to	reconsider	certain	provisions	of	the	CCR	rule	in	light	of	the	WIIN	Act.	 The	EPA	has	not	yet	initiated	a	new round	of	rulemaking	and	has	not	extended	the	existing	mid-October	2017	groundwater	monitoring	deadline.	Entergy	met	the	existing	monitoring deadline,	is	monitoring	state	agency	actions,	and	will	participate	in	the	regulatory	development	process.

# NOTE	10.			LEASES		(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy Texas,	and	System	Energy)

# General

As	 of	December	31,	2017,	Entergy	had	capital	leases	and	non-cancelable	operating	leases	for	equipment,	buildings,	vehicles,	and	fuel storage	facilities	with	minimum	lease	payments	as	follows	(excluding	power	purchase	agreement	operating	leases,	nuclear	fuel	leases,	and	the Grand	Gulf	sale	and	leaseback	transaction,	all	of	which	are	discussed	elsewhere):

| Year | Operating<br>Leases | Capital<br>Leases |
| :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |
| 2018 | $80,368 | $3,018 |
| 2019 | 82,516 | 2,887 |
| 2020 | 67,385 | 2,887 |
| 2021 | 58,507 | 2,887 |
| 2022 | 43,760 | 2,887 |
| Years\tthereafter | 96,550 | 19,004 |
| Minimum\tlease\tpayments | 429,086 | 33,570 |
| Less:\t\tAmount\trepresenting\tinterest | — | 10,051 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $429,086 | $23,519 |

Total	rental	expenses	for	all	leases	(excluding	power	purchase	agreement	operating	leases,	nuclear	fuel	leases,	and	the	Grand	Gulf	and Waterford	3	sale	and	leaseback	transactions)	amounted	to	$53.1	million	in	2017,	$44.4	million	in	2016,	and	$63.9	million	in	2015.

As	 of	December	31,	2017	the	Registrant	Subsidiaries	had	non-cancelable	operating	leases	for	equipment,	buildings,	vehicles,	and	fuel storage	facilities	with	minimum	lease	payments	as	follows	(excluding	power	purchase	agreement	operating	leases,	nuclear	fuel	leases,	and	the Grand	Gulf	lease	obligation,	all	of	which	are	discussed	elsewhere):

| Year | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2018 | $17,009 | $21,814 | $11,771 | $1,646 | $3,469 |
| 2019 | 17,665 | 22,875 | 10,611 | 1,579 | 2,893 |
| 2020 | 11,483 | 17,790 | 8,969 | 1,382 | 1,934 |
| 2021 | 9,363 | 13,762 | 7,059 | 1,033 | 1,299 |
| 2022 | 6,834 | 10,067 | 5,007 | 662 | 862 |
| Years\tthereafter | 23,598 | 19,443 | 5,817 | 1,797 | 2,173 |
| Minimum\tlease\tpayments | $85,952 | $105,751 | $49,234 | $8,099 | $12,630 |

| Year | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New	Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| 2017 | $7.5 | $23.0 | $5.6 | $2.5 | $3.4 | $2.2 |
| 2016 | $8.0 | $17.8 | $4.0 | $0.9 | $2.8 | $1.6 |
| 2015 | $13.6 | $21.8 | $5.4 | $1.6 | $4.0 | $2.9 |

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	$4.0	million	in	2017,	$3.4	million	in	2016,	and	$4.7	million	in	2015 for	Entergy	Arkansas	and	$0.3	million	in	2017,	$0.3	million	in	2016,	and	$1.1	million	in	2015	for	Entergy	Louisiana.		Oil	tank	facilities	lease payments	for	Entergy	Mississippi	were	$1.6	million	in	2017,	$1.6	million	in	2016,	and	$1.6	million	in	2015.

# Power	Purchase	Agreements

As	 of	December	 31,	 2017,	 Entergy	 Texas	 had	 a	 power	 purchase	 agreement	 that	 is	 accounted	 for	 as	 an	 operating	 lease	 under	 the accounting	standards.	The	lease	payments	are	recovered	in	fuel	expense	in	accordance	with	regulatory	treatment.	The	minimum	lease	payments under	the	power	purchase	agreement	are	as	follows:

| Year | (a) | Entergy |
| :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |
| 2018 | $30,458 | $30,458 |
| 2019 | 31,159 | 31,159 |
| 2020 | 31,876 | 31,876 |
| 2021 | 32,609 | 32,609 |
| 2022 | 10,180 | 10,180 |
| Years\tthereafter | — | — |
| Minimum\tlease\tpayments | $136,282 | $136,282 |

(a) Amounts	reflect	100%	of	minimum	payments.	Under	a	separate	contract,	which	expires	May	31,	2022,	Entergy	Louisiana	purchases	50% of	the	capacity	and	energy	from	the	power	purchase	agreement	from	Entergy	Texas.

Total	capacity	expense	under	the	power	purchase	agreement	accounted	for	as	an	operating	lease	at	Entergy	Texas	was $34.1	million	in	2017, $26.1	million	in	2016,	and	$29.9	million	in	2015.

# Sales	and	Leaseback	Transactions

# Waterford	3	Lease	Obligation

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	were	scheduled	to	expire	in	July	2017.		Entergy	Louisiana	was	required	to	report	the	sale- leaseback	as	a	financing	transaction	in	its	financial	statements.

In	December	2015,	Entergy	Louisiana	agreed	to	purchase	the	undivided	interests	in	Waterford	3	that	were	previously	being	leased.	The purchase	was	accomplished	in	a	two-step	transaction	in	which	Entergy	Louisiana	first

acquired	the	equity	participant's	beneficial	interest	in	the	leased	assets,	followed	by	a	termination	of	the	leases	and	transfer	of	the	leased	assets	to Entergy	Louisiana	when	the	outstanding	lessor	debt	is	paid.

In	March	2016,	Entergy	Louisiana	completed	the	first	step	in	the	two-step	transaction	by	acquiring	the	equity	participant's	beneficial interest	in	the	leased	assets.	Entergy	Louisiana	paid	$60	million	in	cash	and	$52	million	through	the	issuance	of	a	non-interest	bearing	collateral trust	mortgage	note,	payable	in	installments	through	July	2017.	Entergy	Louisiana	continued	to	make	payments	on	the	lessor	debt	that	remained outstanding	and	which	matured	in	January	2017.	The	combination	of	payments	on	the	$52	million	collateral	trust	mortgage	note	issued	and	the debt	service	on	the	lessor	debt	was	equal	in	timing	and	amount	to	the	remaining	lease	payments	due	from	the	closing	of	the	transaction	through the	end	of	the	lease	term	in	July	2017.

Throughout	the	term	of	the	lease,	Entergy	Louisiana	had	accrued	a	liability	for	the	amount	it	expected	to	pay	to	retain	the	use	of	the undivided	interests	in	Waterford	3	at	the	end	of	the	lease	term.	Since	the	sale-leaseback	transaction	was	accounted	for	as	a	financing	transaction, the	accrual	of	this	liability	was	accounted	for	as	additional	interest	expense.	As	of	December	2015,	the	balance	of	this	liability	was	$62.7	million. Upon	entering	into	the	agreement	to	purchase	the	equity	participant's	beneficial	interest	in	the	undivided	interests,	Entergy	Louisiana	reduced	the balance	of	the	liability	to	$60	million,	and	recorded	the	$2.7	million	difference	as	a	credit	to	interest	expense.	The	$60	million	remaining	liability was	eliminated	upon	payment	of	the	cash	portion	of	the	purchase	price	in	2016.

As	of	December	31,	2016,	Entergy	Louisiana,	in	connection	with	the	Waterford	3	lease	obligation,	had	a	future	minimum	lease	payment (reflecting	an	interest	rate	of	8.09%)	of	$57.5	million,	including	$2.3	million	in	interest,	due	January	2017	that	was	recorded	as	long-term	debt.

In	February	2017	the	leases	were	terminated	and	the	leased	assets	were	conveyed	to	Entergy	Louisiana.

# 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	expired	in	July	2015.		System	Energy	renewed	the	leases	for	fair market	value	with	renewal	terms	expiring	in	July	2036.	At	the	end	of	the	new	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	$55.6	million	as	of	December	31,	2017	and	2016.

As	of	December	31,	2017,	System	Energy,	in	connection	with	the	Grand	Gulf	sale	and	leaseback	transactions,	had	future	minimum	lease payments	(reflecting	an	implicit	rate	of	5.13%)	that	are	recorded	as	long-term	debt,	as	follows:

| 2018 | $17,188 |
| :--- | :--- |
| 2019 | 17,188 |
| 2020 | 17,188 |
| 2021 | 17,188 |
| 2022 | 17,188 |
| Years\tthereafter | 240,625 |
| Total | 326,565 |
| Less:\tAmount\trepresenting\tinterest | 292,209 |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $34,356 |

# NOTE 11. 	 RETIREMENT,	 OTHER	 POSTRETIREMENT	 BENEFITS,	 AND	 DEFINED	 CONTRIBUTION	 PLANS (Entergy Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

# Qualified	Pension	Plans

Entergy	 has	eight	 qualified	 pension	 plans	 covering	 substantially	 all	 employees.	The	 Entergy	 Corporation	 Retirement	 Plan	 for	 Non- Bargaining	Employees	(Non-Bargaining	Plan	I),	the	Entergy	Corporation	Retirement	Plan	for	Bargaining	Employees	(Bargaining	Plan	I),	the Entergy	Corporation	Retirement	Plan	II	for	Non-Bargaining	Employees	(Non-Bargaining	Plan	II),	the	Entergy	Corporation	Retirement	Plan	II	for Bargaining	 Employees,	 the	 Entergy	 Corporation	 Retirement	 Plan	 III,	 and	 the	 Entergy	 Corporation	 Retirement	 Plan	 IV	 for	 Bargaining Employees	 are	 non-contributory	 final	 average	 pay	 plans	 and	 provide	 pension	 benefits	 that	 are	 based	 on	 employees'	 credited	 service	 and compensation	during	employment.		Effective	as	of	the	close	of	business	on	December	31,	2016,	the	Entergy	Corporation	Retirement	Plan	IV	for Non-Bargaining	Employees	(Non-Bargaining	Plan	IV)	was	merged	with	and	into	Non-Bargaining	Plan	II.	At	the	close	of	business	on	December 31,	2016,	the	liabilities	for	the	accrued	benefits	and	the	assets	attributable	to	such	liabilities	of	all	participants	in	Non-Bargaining	Plan	IV	were assumed	by	and	transferred	to	Non-Bargaining	Plan	II.	There	was	no	loss	of	vesting	or	benefit	options	or	reduction	of	accrued	benefits	to	affected participants	as	a	result	of	this	plan	merger.	Non-bargaining	employees	whose	most	recent	date	of	hire	is	after	June	30,	2014	participate	in	the Entergy	Corporation	Cash	Balance	Plan	for	Non-Bargaining	Employees	(Non-Bargaining	Cash	Balance	Plan).	Certain	bargaining	employees hired	or	rehired	after	June	30,	2014,	or	such	later	date	provided	for	in	their	applicable	collective	bargaining	agreements,	participate	in	the	Entergy Corporation	Cash	Balance	Plan	for	Bargaining	Employees	(Bargaining	Cash	Balance	Plan).	The	Registrant	Subsidiaries	participate	in	these	four plans:	Non-Bargaining	Plan	I,	Bargaining	Plan	I,	Non-Bargaining	Cash	Balance	Plan,	and	Bargaining	Cash	Balance	Plan.

The	assets	of	the	six	final	average	pay	qualified	pension	plans	are	held	in	a	master	trust	established	by	Entergy,	and	the	assets	of	the	 two cash	balance	pension	plans	are	held	in	a	second	master	trust	established	by	Entergy.		Each	pension	plan	has	an	undivided	beneficial	interest	in each	of	the	investment	accounts	in	its	respective	master	trust	that	is	maintained	by	a	trustee.		Use	of	the	master	trusts	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	in	the	master	trusts	are	commingled,	the	trustee	maintains	supporting	records	for	the	purpose	of	allocating	the	trust	level	equity	in	net earnings	(loss)	and	the	administrative	expenses	of	the	investment	accounts	in	each	trust	to	the	various	participating	pension	plans	in	that	particular trust.		The	fair	value	of	the	trusts'	assets	is	determined	by	the	trustee	and	certain	investment	managers.		For	each	trust,	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	trusts	on	a pro	rata	basis.

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	net	income	and	contributions,	and	are decreased	for	benefit	payments.		A	plan's	investment	net	income/loss	(i.e.	interest	and	dividends,	realized	and	unrealized	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	plans	in	an	amount	not	less	than	the	minimum	required	contribution	under	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	2017,	2016,	and	2015	qualified	pension	costs	and	amounts	recognized	as	a	regulatory	asset and/or	other	comprehensive	income,	including	amounts	capitalized,	included	the	following	components:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Net\tperiodic\tpension\tcost: |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $133,641 | $143,244 | $175,046 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 260,824 | 261,613 | 302,777 |
| Expected\treturn\ton\tassets | (408,225) | (389,465) | (394,618) |
| Amortization\tof\tprior\tservice\tcost | 261 | 1,079 | 1,561 |
| Recognized\tnet\tloss | 227,720 | 195,298 | 235,922 |
| Curtailment\tloss | — | 3,084 | 374 |
| Special\ttermination\tbenefit | — | — | 76 |
| Net\tperiodic\tpension\tcosts | $214,221 | $214,853 | $321,138 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\tas\ta\tregulatory\nasset\tand/or\tAOCI\t(before\ttax) |  |  |  |
| Arising\tthis\tperiod: |  |  |  |
| Net\tloss | $368,067 | $203,229 | $50,762 |
| Amounts\treclassified\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\tperiodic\tpension\tcost\nin\tthe\tcurrent\tyear: |  |  |  |
| Amortization\tof\tprior\tservice\tcost | (261) | (1,079) | (1,561) |
| Acceleration\tof\tprior\tservice\tcost\tto\tcurtailment | — | (1,045) | (374) |
| Amortization\tof\tnet\tloss |  |  |  |
|  | (227,720) | (195,298) | (235,922) |
| Total | $140,086 | $5,807 | ($187,095) |
| Total\trecognized\tas\tnet\tperiodic\tpension\tcost,\tregulatory\tasset,\tand/or\tAOCI\n(before\ttax) | $354,307 | $220,660 | $134,043 |
| Estimated\tamortization\tamounts\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\nperiodic\tcost\tin\tthe\tfollowing\tyear: |  |  |  |
| Prior\tservice\tcost | $398 | $261 | $1,079 |
| Net\tloss | $274,104 | $227,720 | $195,321 |

The	Registrant	Subsidiaries'	total	2017,	2016,	and	2015	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:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $20,358 | $27,698 | $5,890 | $2,500 | $5,455 | $6,145 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 51,776 | 59,235 | 14,927 | 7,163 | 13,569 | 12,364 |
| Expected\treturn\ton\tassets | (81,707) | (92,067) | (24,526) | (11,199) | (24,722) | (18,650) |
| Recognized\tnet\tloss | 46,560 | 49,417 | 12,213 | 6,632 | 9,241 | 11,857 |
| Net\tpension\tcost | $36,987 | $44,283 | $8,504 | $5,096 | $3,543 | $11,716 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit |  |  |  |  |  |  |
| obligations\trecognized\tas\ta\tregulatory |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before\ttax) |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |
| Net\tloss | $51,569 | $57,510 | $14,681 | $8,601 | $1,109 | $27,733 |
| Amounts\treclassified\tfrom\tregulatory\tasset |  |  |  |  |  |  |
| and/or\tAOCI\tto\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tnet\tloss | (46,560) | (49,417) | (12,213) | (6,632) | (9,241) | (11,857) |
| Total | $5,009 | $8,093 | $2,468 | $1,969 | ($8,132) | $15,876 |
| Total\trecognized\tas\tnet\tperiodic\tpension |  |  |  |  |  |  |
| (income)/cost,\tregulatory\tasset,\tand/or |  |  |  |  |  |  |
| AOCI\t(before\ttax) | $41,996 | $52,376 | $10,972 | $7,065 | ($4,589) | $27,592 |
| Estimated\tamortization\tamounts\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing\tyear |  |  |  |  |  |  |
| Net\tloss | $53,650 | $57,800 | $14,438 | $7,816 | $10,503 | $14,859 |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $20,724 | $28,194 | $6,250 | $2,625 | $5,664 | $6,263 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 52,219 | 59,478 | 15,245 | 7,256 | 14,228 | 11,966 |
| Expected\treturn\ton\tassets | (79,087) | (88,383) | (23,923) | (10,748) | (24,248) | (17,836) |
| Recognized\tnet\tloss | 43,745 | 47,783 | 11,938 | 6,460 | 9,358 | 10,415 |
| Net\tpension\tcost | $37,601 | $47,072 | $9,510 | $5,593 | $5,002 | $10,808 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit |  |  |  |  |  |  |
| obligations\trecognized\tas\ta\tregulatory |  |  |  |  |  |  |
| asset\tand/or\tAOCI\t(before\ttax) |  |  |  |  |  |  |
| Arising\tthis\tperiod: |  |  |  |  |  |  |
| Net\tloss | $60,968 | $46,742 | $10,942 | $5,463 | $3,816 | $20,805 |
| Amounts\treclassified\tfrom\tregulatory\tasset |  |  |  |  |  |  |
| and/or\tAOCI\tto\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tnet\tloss | (43,745) | (47,783) | (11,938) | (6,460) | (9,358) | (10,415) |
| Total | $17,223 | ($1,041) | ($996) | ($997) | ($5,542) | $10,390 |
| Total\trecognized\tas\tnet\tperiodic\tpension |  |  |  |  |  |  |
| (income)/\tcost,\tregulatory\tasset,\tand/or |  |  |  |  |  |  |
| AOCI\t(before\ttax) | $54,824 | $46,031 | $8,514 | $4,596 | ($540) | $21,198 |
| Estimated\tamortization\tamounts\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing\tyear |  |  |  |  |  |  |
| Net\tloss | $46,560 | $49,417 | $12,213 | $6,632 | $9,241 | $11,857 |

| 2015 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Net\tperiodic\tpension\tcost: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $26,646 | $34,396 | $7,929 | $3,395 | $6,582 | $7,827 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 61,885 | 69,465 | 18,007 | 8,432 | 17,414 | 13,970 |
| Expected\treturn\ton\tassets | (80,102) | (90,803) | (24,420) | (10,899) | (24,887) | (18,271) |
| Recognized\tnet\tloss | 54,254 | 59,802 | 14,896 | 8,053 | 12,950 | 13,055 |
| Net\tpension\tcost | $62,683 | $72,860 | $16,412 | $8,981 | $12,059 | $16,581 |
| 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 | $16,687 | $16,618 | $6,329 | $1,853 | ($4,488) | $101 |
| Amounts\treclassified\tfrom\tregulatory\tasset |  |  |  |  |  |  |
| and/or\tAOCI\tto\tnet\tperiodic\tpension\tcost\tin |  |  |  |  |  |  |
| the\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tnet\tloss | (54,254) | (59,802) | (14,896) | (8,053) | (12,950) | (13,055) |
| Total | ($37,567) | ($43,184) | ($8,567) | ($6,200) | ($17,438) | ($12,954) |
| Total\trecognized\tas\tnet\tperiodic\tpension |  |  |  |  |  |  |
| (income)/cost,\tregulatory\tasset,\tand/or |  |  |  |  |  |  |
| AOCI\t(before\ttax) | $25,116 | $29,676 | $7,845 | $2,781 | ($5,379) | $3,627 |
| Estimated\tamortization\tamounts\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\tin\tthe\tfollowing\tyear |  |  |  |  |  |  |
| Net\tloss | $43,747 | $47,809 | $11,938 | $6,460 | $9,358 | $10,414 |

# Qualified	Pension	Obligations,	Plan	Assets,	Funded	Status,	Amounts	Recognized	in	the	Balance	Sheet

Qualified	pension	obligations,	plan	assets,	funded	status,	amounts	recognized	in	the	Consolidated	Balance	Sheets	for	Entergy	Corporation and	its	Subsidiaries	as	of	December	31,	2017	and	2016	are	as	follows:

| Balance	at	January	1 | $7,142,567 | $6,848,238 |
| :--- | :--- | :--- |
| Service\tcost | 133,641 | 143,244 |
| Interest\tcost | 260,824 | 261,613 |
| Curtailment | — | 2,039 |
| Actuarial\tloss | 767,849 | 209,360 |
| Employee\tcontributions | 40 | 23 |
| Benefits\tpaid | (317,834) | (321,950) |
| Balance\tat\tDecember\t31 | $7,987,087 | $7,142,567 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tJanuary\t1 | $5,171,202 | $4,707,433 |
| Actual\treturn\ton\tplan\tassets | 808,007 | 395,596 |
| Employer\tcontributions | 409,901 | 390,100 |
| Employee\tcontributions | 40 | 23 |
| Benefits\tpaid | (317,834) | (321,950) |
| Fair\tvalue\tof\tassets\tat\tDecember\t31 | $6,071,316 | $5,171,202 |
| Funded\tstatus | ($1,915,771) | ($1,971,365) |
| Amount\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Non-current\tliabilities | ($1,915,771) | ($1,971,365) |
| Amount\trecognized\tas\ta\tregulatory\tasset |  |  |
| Net\tloss | $2,418,206 | $2,326,349 |
| Amount\trecognized\tas\tAOCI\t(before\ttax) |  |  |
| Prior\tservice\tcost | $398 | $659 |
| Net\tloss | 667,766 | 619,276 |
|  | $668,164 | $619,935 |

Qualified	pension	obligations,	plan	assets,	funded	status,	amounts	recognized	in	the	Balance	Sheets	for	the	Registrant	Subsidiaries	as	of December	31,	2017	and	2016	are	as	follows:

| 2017 | Entergy	Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tProjected\tBenefit\nObligation\t(PBO) |  |  |  |  |  |  |
| Balance\tat\tJanuary\t1 | $1,454,310 | $1,624,233 | $419,201 | $197,464 | $386,366 | $335,381 |
| Service\tcost | 20,358 | 27,698 | 5,890 | 2,500 | 5,455 | 6,145 |
| Interest\tcost | 51,776 | 59,235 | 14,927 | 7,163 | 13,569 | 12,364 |
| Actuarial\tloss | 131,729 | 147,704 | 38,726 | 19,507 | 25,339 | 45,471 |
| Benefits\tpaid | (77,417) | (73,170) | (21,195) | (8,738) | (20,009) | (15,312) |
| Balance\tat\tDecember\t31 | $1,580,756 | $1,785,700 | $457,549 | $217,896 | $410,720 | $384,049 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\nJanuary\t1 | $1,041,592 | $1,169,147 | $314,349 | $142,488 | $317,576 | $235,144 |
| Actual\treturn\ton\tplan\tassets | 161,868 | 182,261 | 48,572 | 22,104 | 48,952 | 36,387 |
| Employer\tcontributions | 79,625 | 87,503 | 19,116 | 9,893 | 17,004 | 18,213 |
| Benefits\tpaid | (77,417) | (73,170) | (21,195) | (8,738) | (20,009) | (15,312) |
| Fair\tvalue\tof\tassets\tat\tDecember\t31 | $1,205,668 | $1,365,741 | $360,842 | $165,747 | $363,523 | $274,432 |
| Funded\tstatus | ($375,088) | ($419,959) | ($96,707) | ($52,149) | ($47,197) | ($109,617) |
| Amounts\trecognized\tin\tthe\tbalance\nsheet\t(funded\tstatus) |  |  |  |  |  |  |
| Non-current\tliabilities | ($375,088) | ($419,959) | ($96,707) | ($52,149) | ($47,197) | ($109,617) |
| Amounts\trecognized\tas\tregulatory\nasset |  |  |  |  |  |  |
| Net\tloss | $706,783 | $701,324 | $191,877 | $96,913 | $145,412 | $185,774 |
| Amounts\trecognized\tas\tAOCI\n(before\ttax) |  |  |  |  |  |  |
| Net\tloss | $— | $44,765 | $— | $— | $— | $— |

| 2016 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tProjected\tBenefit\nObligation\t(PBO) |  |  |  |  |  |  |
| Balance\tat\tJanuary\t1 | $1,400,511 | $1,564,710 | $408,604 | $191,064 | $383,627 | $311,542 |
| Service\tcost | 20,724 | 28,194 | 6,250 | 2,625 | 5,664 | 6,263 |
| Interest\tcost | 52,219 | 59,478 | 15,245 | 7,256 | 14,228 | 11,966 |
| Actuarial\tloss | 62,187 | 48,357 | 11,343 | 5,573 | 4,274 | 20,661 |
| Benefits\tpaid | (81,331) | (76,506) | (22,241) | (9,054) | (21,427) | (15,051) |
| Balance\tat\tDecember\t31 | $1,454,310 | $1,624,233 | $419,201 | $197,464 | $386,366 | $335,381 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tJanuary\t1 | $959,618 | $1,071,234 | $292,297 | $129,975 | $298,378 | $212,006 |
| Actual\treturn\ton\tplan\tassets | 80,306 | 89,998 | 24,325 | 10,858 | 24,705 | 17,692 |
| Employer\tcontributions | 82,999 | 84,421 | 19,968 | 10,709 | 15,920 | 20,497 |
| Benefits\tpaid | (81,331) | (76,506) | (22,241) | (9,054) | (21,427) | (15,051) |
| Fair\tvalue\tof\tassets\tat\tDecember\t31 | $1,041,592 | $1,169,147 | $314,349 | $142,488 | $317,576 | $235,144 |
| Funded\tstatus | ($412,718) | ($455,086) | ($104,852) | ($54,976) | ($68,790) | ($100,237) |
| Amounts\trecognized\tin\tthe\tbalance\nsheet\t(funded\tstatus) |  |  |  |  |  |  |
| Non-current\tliabilities | ($412,718) | ($455,086) | ($104,852) | ($54,976) | ($68,790) | ($100,237) |
| Amounts\trecognized\tas\tregulatory\nasset |  |  |  |  |  |  |
| Net\tloss | $701,774 | $686,337 | $189,409 | $94,944 | $153,544 | $169,897 |
| Amounts\trecognized\tas\tAOCI\n\t(before\ttax) |  |  |  |  |  |  |
| Net\tloss | $— | $51,660 | $— | $— | $— | $— |

# Accumulated	Pension	Benefit	Obligation

The	accumulated	benefit	obligation	for	Entergy's	qualified	pension	plans	was	 $7.4	billion	 and	$6.7	billion	 at	December	31,	2017	and 2016,	respectively.

The	qualified	pension	accumulated	benefit	obligation	for	each	of	the	Registrant	Subsidiaries	for	their	employees	as	of	December	31,	2017 and	2016	was	as	follows:

|  | December	31, | December	31, |
| :--- | :--- | :--- |
|  | 2017 | 2016 |
|  | (In\tThousands) | (In\tThousands) |
| Entergy\tArkansas | $1,492,876 | $1,379,265 |
| Entergy\tLouisiana | $1,652,939 | $1,513,884 |
| Entergy\tMississippi | $430,268 | $396,081 |
| Entergy\tNew\tOrleans | $205,316 | $186,247 |
| Entergy\tTexas | $387,083 | $365,251 |
| System\tEnergy | $359,258 | $315,131 |

# Other	Postretirement	Benefits

Entergy	also	currently	offers	retiree	medical,	dental,	vision,	and	life	insurance	benefits	(other	postretirement	benefits)	for	eligible	retired employees.		Employees	who	commenced	employment	before	July	1,	2014	and	who	satisfy	certain	eligibility	requirements	(including	retiring	from Entergy	after	a	certain	age	and/or	years	of	service	with	Entergy	and	immediately	commencing	their	Entergy	pension	benefit),	may	become	eligible for	other	postretirement	benefits.

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.		Entergy	Arkansas,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas have	received	regulatory	approval	to	recover	accrued	other	postretirement	benefit	costs	through	rates.		The	LPSC	ordered	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	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.

# 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	 2017,	2016,	and	2015	other	postretirement	benefit	costs,	including	amounts	capitalized and	amounts	recognized	as	a	regulatory	asset	and/or	other	comprehensive	income,	included	the	following	components:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Other\tpostretirement\tcosts: |  |  |  |
| Service\tcost\t-\tbenefits\tearned\tduring\tthe\tperiod | $26,915 | $32,291 | $45,305 |
| Interest\tcost\ton\taccumulated\tpostretirement\tbenefit\tobligation\t(APBO) | 55,838 | 56,331 | 71,934 |
| Expected\treturn\ton\tassets | (37,630) | (41,820) | (45,375) |
| Amortization\tof\tprior\tservice\tcredit | (41,425) | (45,490) | (37,280) |
| Recognized\tnet\tloss | 21,905 | 18,214 | 31,573 |
| Net\tother\tpostretirement\tbenefit\tcost | $25,603 | $19,526 | $66,157 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\tas\ta\tregulatory\tasset\nand\t/or\tAOCI\t(before\ttax) |  |  |  |
| Arising\tthis\tperiod: |  |  |  |
| Prior\tservice\tcredit\tfor\tperiod | ($2,564) | ($20,353) | ($48,192) |
| Net\t(gain)/loss | (66,922) | 49,805 | (154,339) |
| Amounts\treclassified\tfrom\tregulatory\tasset\tand\t/or\tAOCI\tto\tnet\tperiodic\tbenefit\tcost\tin\nthe\tcurrent\tyear: |  |  |  |
| Amortization\tof\tprior\tservice\tcredit | 41,425 | 45,490 | 37,280 |
| Amortization\tof\tnet\tloss | (21,905) | (18,214) | (31,573) |
| Total | ($49,966) | $56,728 | ($196,824) |
| Total\trecognized\tas\tnet\tperiodic\tbenefit\tincome/(cost),\tregulatory\tasset,\tand/or\tAOCI\n(before\ttax) | ($24,363) | $76,254 | ($130,667) |
| Estimated\tamortization\tamounts\tfrom\tregulatory\tasset\tand/or\tAOCI\tto\tnet\tperiodic\nbenefit\tcost\tin\tthe\tfollowing\tyear |  |  |  |
| Prior\tservice\tcredit | ($37,002) | ($41,425) | ($45,485) |
| Net\tloss | $13,729 | $21,905 | $18,214 |

Total	2017,	2016,	and	2015	other	postretirement	benefit	costs	of	the	Registrant	Subsidiaries,	including	amounts	capitalized	and	deferred, for	their	employees	included	the	following	components:

| 2017 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\nduring\tthe\tperiod | $3,451 | $6,373 | $1,160 | $567 | $1,488 | $1,278 |
| Interest\tcost\ton\tAPBO | 9,020 | 12,101 | 2,759 | 1,874 | 4,494 | 2,236 |
| Expected\treturn\ton\tassets | (15,836) | — | (4,801) | (4,635) | (8,720) | (2,869) |
| Amortization\tof\tprior\tservice\ncredit | (5,110) | (7,735) | (1,823) | (745) | (2,316) | (1,513) |
| Recognized\tnet\tloss | 4,460 | 1,859 | 1,675 | 418 | 3,303 | 1,560 |
| Net\tother\tpostretirement\nbenefit\t(income)/cost | ($4,015) | $12,598 | ($1,030) | ($2,521) | ($1,751) | $692 |
| 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 | (29,534) | (1,256) | 506 | (7,342) | (22,255) | (5,459) |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost |  |  |  |  |  |  |
| in\tthe\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\ncredit | 5,110 | 7,735 | 1,823 | 745 | 2,316 | 1,513 |
| Amortization\tof\tnet\tloss | (4,460) | (1,859) | (1,675) | (418) | (3,303) | (1,560) |
| Total | ($28,884) | $4,620 | $654 | ($7,015) | ($23,242) | ($5,506) |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |
| postretirement |  |  |  |  |  |  |
| income/(cost),\tregulatory |  |  |  |  |  |  |
| asset,\tand/or\tAOCI\t(before |  |  |  |  |  |  |
| tax) | ($32,899) | $17,218 | ($376) | ($9,536) | ($24,993) | ($4,814) |
| Estimated\tamortization |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($5,110) | ($7,735) | ($1,823) | ($745) | ($2,316) | ($1,513) |
| Net\tloss | $1,154 | $1,550 | $1,508 | $137 | $823 | $932 |

| 2016 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\nduring\tthe\tperiod | $3,913 | $7,476 | $1,543 | $622 | $1,590 | $1,337 |
| Interest\tcost\ton\tAPBO | 9,297 | 13,041 | 2,835 | 1,791 | 4,154 | 2,117 |
| Expected\treturn\ton\tassets | (17,855) | — | (5,517) | (4,617) | (9,575) | (3,257) |
| Amortization\tof\tprior\tservice\ncredit | (5,472) | (7,787) | (934) | (745) | (2,722) | (1,570) |
| Recognized\tnet\tloss | 4,256 | 2,926 | 893 | 146 | 2,148 | 1,149 |
| Net\tother\tpostretirement\nbenefit\t(income)/cost | ($5,861) | $15,656 | ($1,180) | ($2,803) | ($4,405) | ($224) |
| 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 | ($1,007) | ($4,647) | ($6,219) | $— | $— | $— |
| Net\t(gain)/loss | 3,331 | (13,117) | 8,715 | 5,717 | 13,378 | 4,997 |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost |  |  |  |  |  |  |
| in\tthe\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\ncredit | 5,472 | 7,787 | 934 | 745 | 2,722 | 1,570 |
| Amortization\tof\tnet\tloss | (4,256) | (2,926) | (893) | (146) | (2,148) | (1,149) |
| Total | $3,540 | ($12,903) | $2,537 | $6,316 | $13,952 | $5,418 |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |
| postretirement |  |  |  |  |  |  |
| income/(cost),\tregulatory |  |  |  |  |  |  |
| asset,\tand/or\tAOCI\t(before |  |  |  |  |  |  |
| tax) | ($2,321) | $2,753 | $1,357 | $3,513 | $9,547 | $5,194 |
| Estimated\tamortization |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($5,110) | ($7,739) | ($1,824) | ($745) | ($2,316) | ($1,513) |
| Net\tloss | $4,460 | $1,859 | $1,675 | $418 | $3,303 | $1,560 |

| 2015 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Other\tpostretirement\tcosts: |  |  |  |  |  |  |
| Service\tcost\t-\tbenefits\tearned\nduring\tthe\tperiod | $6,957 | $9,893 | $2,028 | $818 | $2,000 | $1,881 |
| Interest\tcost\ton\tAPBO | 12,518 | 16,311 | 3,436 | 2,608 | 5,366 | 2,511 |
| Expected\treturn\ton\tassets | (19,190) | — | (6,166) | (4,804) | (10,351) | (3,644) |
| Amortization\tof\tprior\tservice\ncredit | (2,441) | (7,467) | (916) | (709) | (2,723) | (1,465) |
| Recognized\tnet\tloss | 5,356 | 7,118 | 860 | 470 | 2,740 | 1,198 |
| Net\tother\tpostretirement\nbenefit\t(income)/cost | $3,200 | $25,855 | ($758) | ($1,617) | ($2,968) | $481 |
| 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 | ($18,035) | ($1,361) | $— | $— | $— | ($644) |
| Net\t(gain)/loss | (11,978) | (47,043) | 774 | (5,810) | (4,907) | 305 |
| Amounts\treclassified\tfrom |  |  |  |  |  |  |
| regulatory\tasset\tand/or\tAOCI |  |  |  |  |  |  |
| to\tnet\tperiodic\tpension\tcost |  |  |  |  |  |  |
| in\tthe\tcurrent\tyear: |  |  |  |  |  |  |
| Amortization\tof\tprior\tservice\ncredit | 2,441 | 7,467 | 916 | 709 | 2,723 | 1,465 |
| Amortization\tof\tnet\tloss | (5,356) | (7,118) | (860) | (470) | (2,740) | (1,198) |
| Total | ($32,928) | ($48,055) | $830 | ($5,571) | ($4,924) | ($72) |
| Total\trecognized\tas\tnet |  |  |  |  |  |  |
| periodic\tother |  |  |  |  |  |  |
| postretirement |  |  |  |  |  |  |
| income/(cost),\tregulatory |  |  |  |  |  |  |
| asset,\tand/or\tAOCI\t(before |  |  |  |  |  |  |
| tax) | ($29,728) | ($22,200) | $72 | ($7,188) | ($7,892) | $409 |
| Estimated\tamortization |  |  |  |  |  |  |
| amounts\tfrom\tregulatory |  |  |  |  |  |  |
| asset\tand/or\tAOCI\tto\tnet |  |  |  |  |  |  |
| periodic\tcost\t\tin\tthe |  |  |  |  |  |  |
| following\tyear |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($5,472) | ($7,783) | ($933) | ($745) | ($2,722) | ($1,570) |
| Net\tloss | $4,256 | $2,926 | $893 | $146 | $2,148 | $1,149 |

# Other	Postretirement	Benefit	Obligations,	Plan	Assets,	Funded	Status,	and	Amounts	Not	Yet	Recognized	and	Recognized	in	the	Balance Sheet

Other	postretirement	benefit	obligations,	plan	assets,	funded	status,	and	amounts	not	yet	recognized	and	recognized	in	the	Consolidated Balance	Sheets	of	Entergy	Corporation	and	its	Subsidiaries	as	of	December	31,	2017	and	2016	are	as	follows:

| Balance	at	January	1 | $1,568,963 | $1,530,829 |
| :--- | :--- | :--- |
| Service\tcost | 26,915 | 32,291 |
| Interest\tcost | 55,838 | 56,331 |
| Plan\tamendments | (2,564) | (20,353) |
| Plan\tparticipant\tcontributions | 35,080 | 27,686 |
| Actuarial\t(gain)/loss | (23,409) | 46,201 |
| Benefits\tpaid | (97,829) | (104,477) |
| Medicare\tPart\tD\tsubsidy\treceived | 493 | 455 |
| Balance\tat\tDecember\t31 | $1,563,487 | $1,568,963 |
| Change\tin\tPlan\tAssets |  |  |
| Fair\tvalue\tof\tassets\tat\tJanuary\t1 | $596,660 | $579,069 |
| Actual\treturn\ton\tplan\tassets | 81,143 | 38,216 |
| Employer\tcontributions | 44,273 | 56,166 |
| Plan\tparticipant\tcontributions | 35,080 | 27,686 |
| Benefits\tpaid | (97,829) | (104,477) |
| Fair\tvalue\tof\tassets\tat\tDecember\t31 | $659,327 | $596,660 |
| Funded\tstatus | ($904,160) | ($972,303) |
| Amounts\trecognized\tin\tthe\tbalance\tsheet |  |  |
| Current\tliabilities | ($45,237) | ($45,255) |
| Non-current\tliabilities | (858,923) | (927,048) |
| Total\tfunded\tstatus | ($904,160) | ($972,303) |
| Amounts\trecognized\tas\ta\tregulatory\tasset |  |  |
| Prior\tservice\tcredit | ($40,461) | ($54,896) |
| Net\tloss | 144,966 | 222,540 |
|  | $104,505 | $167,644 |
| Amounts\trecognized\tas\tAOCI\t(before\ttax) |  |  |
| Prior\tservice\tcredit | ($65,047) | ($89,474) |
| Net\tloss | 161,322 | 172,575 |
|  | $96,275 | $83,101 |

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,	2017	and	2016	are	as	follows:

| 2017 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |
| Balance\tat\tJanuary\t1 | $258,787 | $342,500 | $78,485 | $55,515 | $127,700 | $62,498 |
| Service\tcost | 3,451 | 6,373 | 1,160 | 567 | 1,488 | 1,278 |
| Interest\tcost | 9,020 | 12,101 | 2,759 | 1,874 | 4,494 | 2,236 |
| Plan\tparticipant\tcontributions | 7,875 | 7,855 | 2,160 | 1,151 | 2,453 | 1,779 |
| Actuarial\t(gain)/loss | (11,691) | (1,256) | 5,858 | (899) | (12,469) | (2,233) |
| Benefits\tpaid | (18,497) | (22,273) | (5,823) | (4,670) | (6,980) | (4,205) |
| Medicare\tPart\tD\tsubsidy\nreceived | 74 | 89 | 22 | 10 | 16 | 28 |
| Balance\tat\tDecember\t31 | $249,019 | $345,389 | $84,621 | $53,548 | $116,702 | $61,381 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tJanuary |  |  |  |  |  |  |
| 1 | $250,926 | $— | $75,945 | $74,236 | $137,069 | $44,885 |
| Actual\treturn\ton\tplan\tassets | 33,679 | — | 10,153 | 11,078 | 18,506 | 6,095 |
| Employer\tcontributions | 695 | 14,418 | (2) | 3,709 | 3,123 | 570 |
| Plan\tparticipant\tcontributions | 7,875 | 7,855 | 2,160 | 1,151 | 2,453 | 1,779 |
| Benefits\tpaid | (18,497) | (22,273) | (5,823) | (4,670) | (6,980) | (4,205) |
| Fair\tvalue\tof\tassets\tat\nDecember\t31 | $274,678 | $— | $82,433 | $85,504 | $154,171 | $49,124 |
| Funded\tstatus | $25,659 | ($345,389) | ($2,188) | $31,956 | $37,469 | ($12,257) |
| Amounts\trecognized\tin\tthe\nbalance\tsheet |  |  |  |  |  |  |
| Current\tliabilities | $— | ($18,794) | $— | $— | $— | $— |
| Non-current\tliabilities | 25,659 | (326,595) | (2,188) | 31,956 | 37,469 | (12,257) |
| Total\tfunded\tstatus | $25,659 | ($345,389) | ($2,188) | $31,956 | $37,469 | ($12,257) |
| Amounts\trecognized\tin\nregulatory\tasset |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($16,574) | $— | ($6,687) | ($1,427) | ($5,980) | ($3,819) |
| Net\tloss | 42,394 | — | 25,247 | 4,269 | 24,478 | 16,386 |
|  | $25,820 | $— | $18,560 | $2,842 | $18,498 | $12,567 |
| Amounts\trecognized\tin\tAOCI\n(before\ttax) |  |  |  |  |  |  |
| Prior\tservice\tcredit | $— | ($19,999) | $— | $— | $— | $— |
| Net\tloss | — | 51,585 | — | — | — | — |
|  | $— | $31,586 | $— | $— | $— | $— |

| 2016 | Entergy	Arkansas | Entergy	Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |  |
| Change\tin\tAPBO |  |  |  |  |  |  |
| Balance\tat\tJanuary\t1 | $258,900 | $356,253 | $77,382 | $51,951 | $114,582 | $57,645 |
| Service\tcost | 3,913 | 7,476 | 1,543 | 622 | 1,590 | 1,337 |
| Interest\tcost | 9,297 | 13,041 | 2,835 | 1,791 | 4,154 | 2,117 |
| Plan\tamendments | (1,007) | (4,647) | (6,219) | — | — | — |
| Plan\tparticipant\tcontributions | 6,330 | 6,273 | 1,721 | 1,213 | 1,927 | 1,390 |
| Actuarial\t(gain)/loss | 2,453 | (13,117) | 8,230 | 4,774 | 12,389 | 4,806 |
| Benefits\tpaid | (21,178) | (22,893) | (7,031) | (4,852) | (6,977) | (4,818) |
| Medicare\tPart\tD\tsubsidy\nreceived | 79 | 114 | 24 | 16 | 35 | 21 |
| Balance\tat\tDecember\t31 | $258,787 | $342,500 | $78,485 | $55,515 | $127,700 | $62,498 |
| Change\tin\tPlan\tAssets |  |  |  |  |  |  |
| Fair\tvalue\tof\tassets\tat\tJanuary |  |  |  |  |  |  |
| 1 | $243,206 | $— | $75,538 | $69,881 | $130,374 | $44,917 |
| Actual\treturn\ton\tplan\tassets | 16,977 | — | 5,032 | 3,674 | 8,586 | 3,066 |
| Employer\tcontributions | 5,591 | 16,620 | 685 | 4,320 | 3,159 | 330 |
| Plan\tparticipant\tcontributions | 6,330 | 6,273 | 1,721 | 1,213 | 1,927 | 1,390 |
| Benefits\tpaid | (21,178) | (22,893) | (7,031) | (4,852) | (6,977) | (4,818) |
| Fair\tvalue\tof\tassets\tat\nDecember\t31 | $250,926 | $— | $75,945 | $74,236 | $137,069 | $44,885 |
| Funded\tstatus | ($7,861) | ($342,500) | ($2,540) | $18,721 | $9,369 | ($17,613) |
| Amounts\trecognized\tin\tthe\nbalance\tsheet |  |  |  |  |  |  |
| Current\tliabilities | $— | ($19,209) | $— | $— | $— | $— |
| Non-current\tliabilities | (7,861) | (323,291) | (2,540) | 18,721 | 9,369 | (17,613) |
| Total\tfunded\tstatus | ($7,861) | ($342,500) | ($2,540) | $18,721 | $9,369 | ($17,613) |
| Amounts\trecognized\tin\nregulatory\tasset |  |  |  |  |  |  |
| Prior\tservice\tcredit | ($21,684) | $— | ($8,511) | ($2,172) | ($8,296) | ($5,332) |
| Net\tloss | 76,388 | — | 26,416 | 12,029 | 50,036 | 23,405 |
|  | $54,704 | $— | $17,905 | $9,857 | $41,740 | $18,073 |
| Amounts\trecognized\tin\tAOCI\n(before\ttax) |  |  |  |  |  |  |
| Prior\tservice\tcredit | $— | ($27,735) | $— | $— | $— | $— |
| Net\tloss | — | 54,700 | — | — | — | — |
|  | $— | $26,965 | $— | $— | $— | $— |

# 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	$37.6	million	in	2017,	$24.9	million	in	2016,	and	$22.8	million in	2015.		In	2017,	2016,	and	2015	Entergy	recognized	$20.3	million,	$8.1	million,	and	$5.1	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	$162.3	million	and	$169.3	million	as	of	December	31,	2017	and	2016,	respectively.		The	accumulated	benefit	obligation	was	 $144.7	million and	$151.0	million	as	of	December	31,	2017	and	2016,	respectively.

Entergy's	non-qualified,	non-current	pension	liability	at	December	31,	2017	and	2016	was	$136	million	and	$137.6	million,	respectively; and	its	current	liability	was	$26.4	million	 and	$31.7	million,	respectively.		The	unamortized	prior	service	cost	and	net	loss	are	recognized	in regulatory	assets	($55.2	million	at	December	31,	2017	and	$59.8	million	at	December	31,	2016)	and	accumulated	other	comprehensive	income before	taxes	($35.9	million	at	December	31,	2017	and	$31.6	million	at	December	31,	2016).

The	following	Registrant	Subsidiaries	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	2017,	2016,	and	2015,	was	as follows:

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2017 | $679 | $185 | $251 | $73 | $499 |
| 2016 | $1,819 | $231 | $236 | $65 | $504 |
| 2015 | $446 | $377 | $235 | $64 | $595 |

Included	in	the	2017	net	periodic	pension	cost	above	are	settlement	charges	of	$269	thousand	for	Entergy	Arkansas	related	to	the	lump sum	benefits	paid	out	of	the	plan.	Included	in	the	2016	net	periodic	pension	cost	above	are	settlement	charges	of	$1.4	million	and	$1	thousand	for Entergy	Arkansas	and	Entergy	Mississippi,	respectively,	related	to	the	lump	sum	benefits	paid	out	of	the	plan.	Included	in	the	2015	net	periodic pension	cost	above	are	settlement	charges	of	$108	thousand	and	$2	thousand	for	Entergy	Louisiana	and	Entergy	Mississippi,	respectively,	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,	2017	and	2016	was	as	follows:

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2017 | $4,221 | $2,061 | $2,737 | $583 | $8,913 |
| 2016 | $3,897 | $2,134 | $2,296 | $514 | $8,665 |

The	accumulated	benefit	obligation	for	their	employees	for	the	non-qualified	plans	as	of	December	31,	2017	and	2016	was	as	follows:

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2017 | $3,825 | $2,061 | $2,250 | $519 | $8,602 |
| 2016 | $3,439 | $2,134 | $1,961 | $452 | $8,333 |

The	following	amounts	were	recorded	on	the	balance	sheet	as	of	December	31,	2017	and	2016:

| 2017 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Current\tliabilities | ($376) | ($231) | ($135) | ($21) | ($788) |
| Non-current\tliabilities | (3,845) | (1,830) | (2,603) | (562) | (8,125) |
| Total\tfunded\tstatus | ($4,221) | ($2,061) | ($2,738) | ($583) | ($8,913) |
| Regulatory\tasset/(liability) | $2,995 | $166 | $1,186 | ($140) | $133 |
| Accumulated\tother\tcomprehensive\tincome\t(before\ttaxes) | $— | $11 | $— | $— | $— |

| 2016 | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Current\tliabilities | ($242) | ($233) | ($137) | ($20) | ($773) |
| Non-current\tliabilities | (3,655) | (1,901) | (2,159) | (495) | (7,892) |
| Total\tfunded\tstatus | ($3,897) | ($2,134) | ($2,296) | ($515) | ($8,665) |
| Regulatory\tasset/(liability) | $2,914 | $175 | $876 | ($148) | ($316) |
| Accumulated\tother\tcomprehensive\tincome\t(before\ttaxes) | $— | $13 | $— | $— | $— |

# Reclassification	out	of	Accumulated	Other	Comprehensive	Income	(Loss)

Entergy	and	Entergy	Louisiana	reclassified	the	following	costs	out	of	accumulated	other	comprehensive	income	(loss)	(before	taxes	and including	amounts	capitalized)	as	of	December	31,	2017:

|  | Qualified<br>Pension	Costs | Other	Postretirement<br>Costs | Non-Qualified<br>Pension	Costs | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Entergy |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | ($261) | $26,867 | ($355) | $26,251 |
| Amortization\tof\tloss | (73,800) | (8,805) | (3,397) | (86,002) |
| Settlement\tloss | — | — | (7,544) | (7,544) |
|  | ($74,061) | $18,062 | ($11,296) | ($67,295) |
| Entergy\tLouisiana |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | $— | $7,735 | ($1) | $7,734 |
| Amortization\tof\tloss | (3,459) | (1,859) | (9) | (5,327) |
|  | ($3,459) | $5,876 | ($10) | $2,407 |

|  | Qualified<br>Pension	Costs | Other	Postretirement<br>Costs | Non-Qualified<br>Pension	Costs | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Entergy |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | ($1,079) | $30,949 | ($456) | $29,414 |
| Acceleration\tof\tprior\tservice\tcost\tdue\tto\tcurtailment | (1,045) | — | — | (1,045) |
| Amortization\tof\tloss | (49,930) | (8,248) | (2,515) | (60,693) |
| Settlement\tloss | — | — | (2,007) | (2,007) |
|  | ($52,054) | $22,701 | ($4,978) | ($34,331) |
| Entergy\tLouisiana |  |  |  |  |
| Amortization\tof\tprior\tservice\tcost | $— | $7,787 | ($1) | $7,786 |
| Amortization\tof\tloss | (3,345) | (2,926) | (10) | (6,281) |
|  | ($3,345) | $4,861 | ($11) | $1,505 |

# 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	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 Louisiana	recovers	other	postretirement	benefit	costs	on	a	pay-as-you-go	basis	and	records	the	unrecognized	prior	service	cost,	gains	and	losses, and	transition	obligation	for	its	other	postretirement	benefit	obligation	as	other	comprehensive	income.		Accounting	standards	also

require	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.

The	target	asset	allocation	for	pension	adjusts	dynamically	based	on	the	pension	plans'	funded	status.	The	current	targets	are	shown below.	The	expectation	is	that	the	allocation	to	fixed	income	securities	will	increase	as	the	pension	plans'	funded	status	increases.		The	following ranges	were	established	to	produce	an	acceptable,	economically	efficient	plan	to	manage	around	the	targets.

For	postretirement	assets	the	target	and	range	asset	allocations	(as	shown	below)	reflect	recommendations	made	in	the	latest	optimization study.	The	target	asset	allocations	for	postretirement	assets	adjust	dynamically	based	on	the	funded	status	of	each	sub-account	within	each	trust. The	current	weighted	average	targets	shown	below	represent	the	aggregate	of	all	targets	for	all	sub-accounts	within	all	trusts.

Entergy's	qualified	pension	and	postretirement	weighted-average	asset	allocations	by	asset	category	at	 December	31,	2017	and	2016	and the	target	asset	allocation	and	ranges	for	2017	are	as	follows:

| Pension	Asset	Allocation | Target |  | Range |  | Actual	2017 | Actual	2016 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Domestic\tEquity\tSecurities | 45% | 37% | to | 53% | 45% | 46% |
| International\tEquity\tSecurities | 20% | 16% | to | 24% | 20% | 20% |
| Fixed\tIncome\tSecurities | 35% | 32% | to | 38% | 34% | 33% |
| Other | 0% | 0% | to | 10% | 1% | 1% |

| Postretirement	Asset	Allocation |  |  | Non-Taxable	and	Taxable | Non-Taxable	and	Taxable | Non-Taxable	and	Taxable |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Target |  | Range |  | Actual\t2017 | Actual\t2016 |
| Domestic\tEquity\tSecurities | 27% | 22% | to | 32% | 30% | 40% |
| International\tEquity\tSecurities | 18% | 13% | to | 23% | 20% | 27% |
| Fixed\tIncome\tSecurities | 55% | 50% | to | 60% | 50% | 33% |
| Other | 0% | 0% | to | 5% | 0% | 0% |

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	some	investment managers.

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	assets.	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	aggregate	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	postretirement	assets	(as	described	above),	and	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,	2017,	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	credit	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,	 2017,	 and December	31,	2016,	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	Defined	Benefit	Pension	Plan	Trusts

| 2017 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |
| Corporate\tstocks: |  |  |  |  |  |  |
| Preferred | $11,461 | (b) | $— |  | $— | $11,461 |
| Common | 663,923 | (b) | 34 | (b) | — | 663,957 |
| Common\tcollective\ttrusts\t(c) |  |  |  |  |  | 3,198,799 |
| Registered\tinvestment\tcompanies | 125,174 | (d) | — |  | — | 125,174 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | — | (b) | 638,832 | (a) | — | 638,832 |
| Corporate\tdebt\tinstruments | — |  | 619,735 | (a) | — | 619,735 |
| Registered\tinvestment\tcompanies\t(e) | 45,768 | (d) | 2,735 | (d) | — | 764,251 |
| Other | 46 | (f) | 62,559 | (f) | — | 62,605 |
| Other: |  |  |  |  |  |  |
| Insurance\tcompany\tgeneral\taccount\t(unallocated\ncontracts) | — |  | 37,994 | (g) | — | 37,994 |
| Total\tinvestments | $846,372 |  | $1,361,889 |  | $— | $6,122,808 |
| Cash |  |  |  |  |  | 1,508 |
| Other\tpending\ttransactions |  |  |  |  |  | 5,179 |
| Less:\tOther\tpostretirement\tassets\tincluded\tin\ntotal\tinvestments |  |  |  |  |  | (58,179) |
| Total\tfair\tvalue\tof\tqualified\tpension\tassets |  |  |  |  |  | $6,071,316 |

| 2016 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Short-term\tinvestments | $— |  | $3,610 | (a) | $— | $3,610 |
| Equity\tsecurities: |  |  |  |  |  |  |
| Corporate\tstocks: |  |  |  |  |  |  |
| Preferred | 6,423 | (b) | — |  | — | 6,423 |
| Common | 745,715 | (b) | 39 | (b) | — | 745,754 |
| Common\tcollective\ttrusts\t(c) |  |  |  |  |  | 2,072,743 |
| 103-12\tinvestment\tentities\t(h) |  |  |  |  |  | 335,818 |
| Registered\tinvestment\tcompanies | 258,879 | (d) | — |  | — | 258,879 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 136 | (b) | 370,545 | (a) | — | 370,681 |
| Corporate\tdebt\tinstruments | — |  | 630,726 | (a) | — | 630,726 |
| Registered\tinvestment\tcompanies\t(e) | 35,216 | (d) | 2,695 | (d) | — | 640,836 |
| Other | 34 | (f) | 105,613 | (f) | — | 105,647 |
| Other: |  |  |  |  |  |  |
| Insurance\tcompany\tgeneral\taccount\t(unallocated\ncontracts) | — |  | 37,111 | (g) | — | 37,111 |
| Total\tinvestments | $1,046,403 |  | $1,150,339 |  | $— | $5,208,228 |
| Cash |  |  |  |  |  | 929 |
| Other\tpending\ttransactions |  |  |  |  |  | 8,869 |
| Less:\tOther\tpostretirement\tassets\tincluded\tin\ntotal\tinvestments |  |  |  |  |  | (46,824) |
| Total\tfair\tvalue\tof\tqualified\tpension\tassets |  |  |  |  |  | $5,171,202 |

# Other	Postretirement	Trusts

| 2017 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |
| Common\tcollective\ttrust\t(c) |  |  |  |  |  | $300,139 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 81,602 | (b) | 76,790 | (a) | — | 158,392 |
| Corporate\tdebt\tinstruments | — |  | 92,869 | (a) | — | 92,869 |
| Registered\tinvestment\tcompanies | 3,127 | (d) | — |  | — | 3,127 |
| Other | — |  | 45,627 | (f) | — | 45,627 |
| Total\tinvestments | $84,729 |  | $215,286 |  | $— | $600,154 |
| Other\tpending\ttransactions |  |  |  |  |  | 994 |
| Plus:\t\tOther\tpostretirement\tassets\tincluded\tin\tthe |  |  |  |  |  |  |
| investments\tof\tthe\tqualified\tpension\ttrust |  |  |  |  |  | 58,179 |
| Total\tfair\tvalue\tof\tother\tpostretirement\tassets |  |  |  |  |  | $659,327 |

| 2016 | Level	1 |  | Level	2 |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |
| Common\tcollective\ttrust\t(c) |  |  |  |  |  | $368,704 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |
| U.S.\tGovernment\tsecurities | 30,632 | (b) | 43,097 | (a) | — | 73,729 |
| Corporate\tdebt\tinstruments | — |  | 58,787 | (a) | — | 58,787 |
| Registered\tinvestment\tcompanies | 3,123 | (d) | — |  | — | 3,123 |
| Other | — |  | 45,389 | (f) | — | 45,389 |
| Total\tinvestments | $33,755 |  | $147,273 |  | $— | $549,732 |
| Other\tpending\ttransactions |  |  |  |  |  | 104 |
| Plus:\t\tOther\tpostretirement\tassets\tincluded\tin\tthe |  |  |  |  |  |  |
| investments\tof\tthe\tqualified\tpension\ttrust |  |  |  |  |  | 46,824 |
| Total\tfair\tvalue\tof\tother\tpostretirement\tassets |  |  |  |  |  | $596,660 |

(a) Certain	preferred	stocks	and	certain	fixed	income	debt	securities	(corporate,	government,	and	securitized)	are	stated	at	fair	value	as determined	by	broker	quotes.

(b) Common	stocks,	certain	preferred	stocks,	and	certain	fixed	income	debt	securities	(government)	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	common	collective trusts	estimate	fair	value.	Certain	of	these	common	collective	trusts	are	not	publicly	quoted,	and	are	valued	by	the	fund	administrators using	net	asset	value	as	a	practical	expedient.	Accordingly,	these	funds	are	not	assigned	a	level	in	the	fair	value	table.

(d) Registered	 investment	 companies	 are	 money	 market	 mutual	 funds	 with	 a	 stable	 net	 asset	 value	 of	 one	 dollar	 per	 share.	Registered investment	companies	may	hold	investments	in	domestic	and	international	bond	markets	or	domestic	equities	and	estimate	fair	value	using net	asset	value	per	share.

(e) Certain	of	these	registered	investment	companies	are	not	publicly	quoted,	and	are	valued	by	the	fund	administrators	using	net	asset	value as	a	practical	expedient.	Accordingly,	these	funds	are	not	assigned	a	level	in	the	fair	value	table.

(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.

(h) 103-12	investment	entities	hold	investments	in	accordance	with	stated	objectives.	The	investment	strategy	of	the	investment	entities	is	to capture	the	growth	potential	of	international	equity	markets	by	replicating	the	performance	of	a	specified	index.	103-12	investment	entities estimate	fair	value	using	net	asset	value	as	a	practical	expedient.	Accordingly,	these	funds	are	not	assigned	a	level	in	the	fair	value	table.

# Estimated	Future	Benefit	Payments

Based	upon	the	assumptions	used	to	measure	Entergy's	qualified	pension	and	other	postretirement	benefit	obligations	at	 December	31, 2017,	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 | Estimated	Future	Benefits	Payments |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Qualified\tPension | Non-Qualified\nPension | Other\tPostretirement\n(before\tMedicare\tSubsidy) | Estimated\tFuture\nMedicare\tSubsidy\tReceipts |
|  |  |  | (In\tThousands) |  |
| Year(s) |  |  |  |  |
| 2018 | $412,057 | $26,375 | $82,087 | $745 |
| 2019 | $435,880 | $10,108 | $86,685 | $842 |
| 2020 | $447,224 | $13,364 | $89,508 | $956 |
| 2021 | $462,624 | $10,765 | $92,087 | $1,071 |
| 2022 | $470,846 | $17,425 | $94,427 | $1,195 |
| 2023\t-\t2027 | $2,478,959 | $72,181 | $475,991 | $8,109 |

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	Qualified	Pension<br>Benefits	Payments | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |  |
| 2018 | $87,295 | $93,155 | $25,833 | $11,484 | $25,333 | $17,780 |
| 2019 | $87,832 | $96,060 | $25,977 | $12,202 | $25,656 | $18,566 |
| 2020 | $88,905 | $100,179 | $27,198 | $12,463 | $26,399 | $19,398 |
| 2021 | $90,278 | $103,810 | $27,508 | $13,087 | $26,756 | $20,279 |
| 2022 | $92,061 | $107,609 | $27,389 | $13,207 | $26,310 | $21,714 |
| 2023\t-\t2027 | $479,160 | $571,926 | $141,912 | $69,595 | $130,905 | $117,835 |

| Estimated	Future	Non-Qualified	Pension	Benefits<br>Payments | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |
| 2018 | $376 | $231 | $135 | $21 | $788 |
| 2019 | $300 | $219 | $137 | $55 | $764 |
| 2020 | $355 | $208 | $290 | $36 | $895 |
| 2021 | $310 | $196 | $192 | $39 | $723 |
| 2022 | $506 | $186 | $201 | $41 | $662 |
| 2023\t-\t2027 | $2,196 | $749 | $1,462 | $459 | $3,762 |

# Estimated	Future	Other

| Estimated	Future	Other<br>Postretirement	Benefits	Payments<br>(before	Medicare	Part	D	Subsidy) | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |  |
| 2018 | $15,282 | $18,962 | $4,677 | $3,954 | $6,485 | $3,246 |
| 2019 | $15,398 | $19,767 | $4,818 | $4,000 | $6,842 | $3,363 |
| 2020 | $15,349 | $20,287 | $5,043 | $3,952 | $7,101 | $3,381 |
| 2021 | $15,483 | $20,756 | $5,218 | $3,899 | $7,369 | $3,537 |
| 2022 | $15,419 | $21,250 | $5,331 | $3,800 | $7,519 | $3,595 |
| 2023\t-\t2027 | $75,293 | $108,290 | $26,723 | $17,698 | $36,897 | $17,677 |

| Estimated	Future	Medicare	Part	D<br>Subsidy | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Year(s) |  |  |  |  |  |  |
| 2018 | $164 | $168 | $58 | $38 | $64 | $23 |
| 2019 | $185 | $187 | $65 | $39 | $69 | $27 |
| 2020 | $209 | $210 | $70 | $41 | $75 | $33 |
| 2021 | $230 | $234 | $76 | $43 | $81 | $38 |
| 2022 | $254 | $257 | $82 | $46 | $88 | $46 |
| 2023\t-\t2027 | $1,646 | $1,720 | $514 | $259 | $552 | $346 |

# Contributions

Entergy	currently	expects	to	contribute	approximately	$352.1	million	to	its	qualified	pension	plans	and	approximately	 $52.3	million	to other	postretirement	plans	in	2018.		The	expected	2018	pension	and	other	postretirement	plan	contributions	of	the	Registrant	Subsidiaries	for	their employees	are	shown	below.		The	2018	required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are completed,	which	is	expected	by	April	1,	2018.

The	Registrant	Subsidiaries	expect	to	contribute	approximately	the	following	to	the	qualified	pension	and	other	postretirement	plans	for their	employees	in	2018:

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System	Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| Pension\tContributions | $64,062 | $71,917 | $14,933 | $7,250 | $10,883 | $13,786 |
| Other\tPostretirement\tContributions | $472 | $18,962 | $110 | $3,669 | $3,231 | $16 |

# Actuarial	Assumptions

The	significant	actuarial	assumptions	used	in	determining	the	pension	PBO	and	the	other	postretirement	benefit	APBO	as	of	 December	31, 2017	and	2016	were	as	follows:

The	significant	actuarial	assumptions	used	in	determining	the	net	periodic	pension	and	other	postretirement	benefit	costs	for	 2017,	2016, and	2015	were	as	follows:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tdiscount\trate: |  |  |  |
| Qualified\tpension: |  |  |  |
| \t\t\t\tService\tcost | 4.75% | 5.00% | 4.27% |
| \t\t\t\tInterest\tcost | 3.73% | 3.90% | 4.27% |
| Other\tpostretirement: |  |  |  |
| \t\t\t\tService\tcost | 4.60% | 4.92% | 4.23% |
| \t\t\t\tInterest\tcost | 3.61% | 3.78% | 4.23% |
| Non-qualified\tpension: |  |  |  |
| \t\t\t\tService\tcost | 3.65% | 3.65% | 3.61% |
| \t\t\t\tInterest\tcost | 3.10% | 3.10% | 3.61% |
| Weighted-average\trate\tof\tincrease\tin\tfuture\ncompensation\tlevels | 3.98% | 4.23% | 4.23% |
| Expected\tlong-term\trate\tof\treturn\ton\tplan\tassets: |  |  |  |
| Pension\tassets | 7.50% | 7.75% | 8.25% |
| Other\tpostretirement\tnon-taxable\tassets | 6.50%\t-\t7.50% | 7.75% | 8.05% |
| Other\tpostretirement\ttaxable\tassets | 5.75% | 6.00% | 6.25% |
| Assumed\thealth\tcare\ttrend\trate: |  |  |  |
| Pre-65 | 6.55% | 6.75% | 7.10% |
| Post-65 | 7.25% | 7.55% | 7.70% |
| Ultimate\trate | 4.75% | 4.75% | 4.75% |

In	 2016,	 Entergy	 refined	 its	 approach	 to	 estimating	 the	 service	 cost	 and	 interest	 cost	 components	 of	 qualified	 pension,	 other postretirement,	and	non-qualified	pension	costs.	Under	the	refined	approach,	instead	of	using	the	weighted-average	obligation	discount	rates	at	the beginning	of	the	year,	2016	service	cost	and	interest	costs'	expected	cash	flows	were	discounted	by	the	applicable	spot	rates.	The	refinement	in approach	was	a	change	in	accounting	estimate	and,	accordingly,	the	effect	was	reflected	prospectively.	The	measurement	of	the	benefit	obligation was	not	affected.

With	respect	to	the	mortality	assumptions,	Entergy	used	the	RP-2014	Employee	and	Healthy	Annuitant	Tables	(adjusted	to	base	year 2006)	with	a	fully	generational	MP-2017	projection	scale,	in	determining	its	December	31,	2017	pension	plans'	PBOs	and	other	postretirement benefit	APBO.	Entergy	used	the	RP-2014	Employee	and	Healthy	Annuitant	Tables	(adjusted	to	base	year	2006)	with	a	fully	generational	MP- 2016	projection	scale,	in	determining	its	December	31,	2016	pension	plans'	PBOs	and	other	postretirement	benefit	APBO.

Entergy's	health	care	cost	trend	is	affected	by	both	medical	cost	inflation,	and	with	respect	to	capped	costs,	the	effects	of	general	inflation. A	one	percentage	point	change	in	Entergy's	assumed	health	care	cost	trend	rate	for	2017	would	have	the	following	effects:

|  | 1	Percentage	Point	Increase |  | 1	Percentage	Point	Decrease | 1	Percentage	Point	Decrease |
| :--- | :--- | :--- | :--- | :--- |
| 2017 | Impact\ton\tthe\nAPBO | Impact\ton\tthe\tsum\tof\tservice\ncosts\tand\tinterest\tcost | Impact\ton\tthe\nAPBO | Impact\ton\tthe\tsum\tof\tservice\ncosts\tand\tinterest\tcost |
|  |  | Increase\t/(Decrease) |  |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tCorporation\tand\tits\nsubsidiaries | $166,814 | $10,221 | ($139,648) | ($8,385) |

The	Registrant	Subsidiaries'	health	care	cost	trend	is	affected	by	both	medical	cost	inflation,	and	with	respect	to	capped	costs,	the	effects of	general	inflation.	A	one	percentage	point	change	in	the	assumed	health	care	cost	trend	rate	for	2017	would	have	the	following	effects	for	the Registrant	Subsidiaries	for	their	employees:

|  | 1	Percentage	Point	Increase |  | 1	Percentage	Point	Decrease |  |
| :--- | :--- | :--- | :--- | :--- |
| 2017 | Impact\ton\tthe\nAPBO | Impact\ton\tthe\tsum\tof\tservice\ncosts\tand\tinterest\tcost | Impact\ton\tthe\nAPBO | Impact\ton\tthe\tsum\tof\tservice\ncosts\tand\tinterest\tcost |
|  |  | Increase/(Decrease) |  |  |
|  |  | (In\tThousands) |  |  |
| Entergy\tArkansas | $23,612 | $1,369 | ($19,810) | ($1,133) |
| Entergy\tLouisiana | $37,240 | $2,333 | ($31,063) | ($1,909) |
| Entergy\tMississippi | $8,666 | $448 | ($7,276) | ($370) |
| Entergy\tNew\tOrleans | $4,585 | $251 | ($3,895) | ($208) |
| Entergy\tTexas | $12,444 | $751 | ($10,452) | ($618) |
| System\tEnergy | $7,334 | $475 | ($6,074) | ($387) |

# 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	certain	of	its	subsidiaries.	The	participating	Entergy	subsidiary	makes	matching contributions	to	the	System	Savings	Plan	for	all	eligible	participating	employees	in	an	amount	equal	to	either	70%	or	100%	of	the	participants' basic	contributions,	up	to	6%	of	their	eligible	earnings	per	pay	period.		The	matching	contribution	is	allocated	to	investments	as	directed	by	the employee.

Entergy	also	sponsors	the	Savings	Plan	of	Entergy	Corporation	and	Subsidiaries	IV	(established	in	March	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	certain	of	its	subsidiaries.

Entergy's	subsidiaries'	contributions	to	defined	contribution	plans	collectively	were	$49.1	million	in	2017,	$47	million	in	2016,	and	$44.4 million	in	2015.		The	majority	of	the	contributions	were	to	the	System	Savings	Plan.

The	Registrant	Subsidiaries'	2017,	2016,	and	2015	contributions	to	defined	contribution	plans	for	their	employees	were	as	follows:

| Year | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| 2017 | $3,741 | $5,079 | $2,133 | $731 | $1,865 |
| 2016 | $3,528 | $4,746 | $1,997 | $708 | $1,778 |
| 2015 | $3,242 | $4,324 | $1,920 | $721 | $1,620 |

# NOTE	12.				STOCK-BASED	COMPENSATION	(Entergy	Corporation)

Entergy	grants	stock	options,	restricted	stock,	performance	units,	and	restricted	stock	unit	awards	 to	key	employees	of	 the	Entergy subsidiaries	 under	 its	 Equity	 Ownership	 Plans	 which	 are	 shareholder-approved	 stock-based	 compensation	 plans.	 	 Effective	 May	 8,	 2015, Entergy's	shareholders	approved	 the	2015	Equity	Ownership	and	Long-Term	Cash	Incentive	Plan	(2015	Plan).	 	The	maximum	number	of common	shares	that	can	be	issued	from	the	2015	Plan	for	stock-based	awards	is	6,900,000	with	no	more	than	1,500,000	available	for	incentive stock	option	grants.		The	2015	Plan	only	applies	to	awards	granted	on	or	after	May	8,	2015	and	awards	will	expire	ten	years	from	the	date	of	grant. As	 of	December	31,	2017,	there	were	3,498,788	authorized	shares	remaining	for	stock-based	awards,	including	1,500,000	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	10	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:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tconsolidated\tnet\tincome | $4.4 | $4.4 | $4.3 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tconsolidated\tnet\tincome | $1.7 | $1.7 | $1.6 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $0.7 | $0.7 | $0.7 |

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:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
| Stock\tprice\tvolatility | 18.39% | 20.38% | 23.62% |
| Expected\tterm\tin\tyears | 7.35 | 7.25 | 7.06 |
| Risk-free\tinterest\trate | 2.31% | 1.77% | 1.59% |
| Dividend\tyield | 4.75% | 4.50% | 4.50% |
| Dividend\tpayment\tper\tshare | $3.50 | $3.42 | $3.34 |

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	net-of-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,	2017	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,\t2017 | 7,137,210 | $84.91 |  |  |
| Options\tgranted | 791,900 | $70.53 |  |  |
| Options\texercised | (1,109,306) | $72.74 |  |  |
| Options\tforfeited/expired | (1,654,950) | $91.36 |  |  |
| Options\toutstanding\tas\tof\tDecember\t31,\t2017 | 5,164,854 | $83.26 | $— | 4.18\tyears |
| Options\texercisable\tas\tof\tDecember\t31,\t2017 | 4,027,902 | $86.37 | $— | 2.94\tyears |

The	weighted-average	grant-date	fair	value	of	options	granted	during	the	year	was	$7.40	for	2016	and	$11.41	for	2015.		The	total	intrinsic	value of	stock	options	exercised	was	$11	million	during	2017,	$5	million	during	2016,	and	$5	million	during	2015.		The	intrinsic	value,	which	has	no effect	on	net	income,	of	the	outstanding	stock	options	exercised	is	calculated	by	the	positive	difference	between	the	weighted	average	exercise price	of	the	stock	options	granted	and	Entergy	Corporation's	common	stock	price	as	of	December	31,	2017.		Because	Entergy's	year-end	common stock	price	was	less	than	the	weighted	average	exercise	price,	the	aggregate	intrinsic	value	of	stock	options	outstanding	as	of	December	31,	2017 was	zero.	The	intrinsic	value	of	"in	the	money"	stock	options	is	$32	million	as	of	December	31,	2017.	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	$6	million during	2017,	$5	million	 during	2016,	 and	$4	million	 during	2015.	Cash	received	from	option	exercises	was	$81	million	for	the	year	ended December	31,	2017.	The	tax	benefits	realized	from	options	exercised	was	$4	million	for	the	year	ended	December	31,	2017.

The	following	table	summarizes	information	about	stock	options	outstanding	as	of	December	31,	2017:

|  |  |  | Options	Outstanding |  | Options	Exercisable |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Weighted-Average |  | Number |  |
| Range\tof | Range\tof | As\tof | Remaining\tContractual | \t Weighted\tAverage | Exercisable\tas\tof | \t Weighted\tAverage |
| Exercise\tPrices | Exercise\tPrices | 12/31/2017 | Life-Yrs. | Exercise\tPrice | 12/31/2017 | Exercise\tPrice |
| $51\t- | $64.99 | 502,709 | 5.73 | $63.68 | 502,709 | $63.68 |
| $65\t- | $78.99 | 2,790,045 | 5.56 | $72.94 | 1,751,402 | $74.36 |
| $79\t- | $91.99 | 441,000 | 7.08 | $89.90 | 342,691 | $89.90 |
| $92\t- | $108.20 | 1,431,100 | 0.06 | $108.20 | 1,431,100 | $108.20 |
| $51\t- | $108.20 | 5,164,854 | 4.18 | $83.26 | 4,027,902 | $86.37 |

Stock-based	 compensation	 cost	 related	 to	 non-vested	 stock	 options	 outstanding	 as	 of	December	 31,	 2017	 not	 yet recognized is approximately	$6	million	and	is	expected	to	be	recognized	over	a	weighted-average	period	of	 1.70	years.

# Restricted	Stock	Awards

Entergy	grants	restricted	stock	awards	earned	under	its	stock	benefit	plans	in	the	form	of	stock	units.	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.	In January	2017	the	Board	approved	and	Entergy	granted	379,850	restricted	stock	awards	under	the	2015	Equity	Ownership	and	Long-term	Cash Incentive	Plan.		The	restricted	stock	awards	were	made	effective	as	of	January	26,	2017	and	were	valued	at	$70.53	per	share,	which	was	the closing	price	of	Entergy	Corporation's	common	stock	on	that	date.

The	following	table	includes	information	about	the	restricted	stock	awards	outstanding	as	of	December	31,	2017:

|  | Shares | Weighted-Average	Grant<br>Date	Fair	Value	Per	Share |
| :--- | :--- | :--- |
| Outstanding\tshares\tat\tJanuary\t1,\t2017 | 683,474 | $74.80 |
| Granted | 410,787 | $70.71 |
| Vested | (330,816) | $73.61 |
| Forfeited | (53,834) | $75.63 |
| Outstanding\tshares\tat\tDecember\t31,\t2017 | 709,611 | $72.92 |

The	following	table	includes	financial	information	for	restricted	stock	for	each	of	the	years	presented:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tconsolidated\tnet\tincome | $19.7 | $19.8 | $19.5 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tconsolidated\tnet\tincome | $7.6 | $7.6 | $7.5 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $5.2 | $4.5 | $3.9 |

The	total	fair	value	of	the	restricted	stock	awards	granted	was	$29	million	for	each	of	the	years	ended	December	31,	2017,	2016,	and 2015.

The	total	fair	value	of	the	restricted	stock	awards	vested	was	$24	million,	$23	million,	and	$29	million	for	the	years	ended	December	31, 2017,	2016,	and	2015,	respectively.

# Long-Term	Performance	Unit	Program

Entergy	grants	long-term	incentive	awards	earned	under	its	stock	benefit	plans	in	the	form	of	performance	units,	which	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	Long-Term	Performance	Unit	Program	specifies	a	minimum,	target,	and	maximum	achievement	level,	the	achievement of	 which	 will	 determine	 the	 number	 of	 performance	 units	 that	 may	 be	 earned.	Entergy	 measures	 performance	 by	 assessing	 Entergy's	 total shareholder	return	relative	to	the	total	shareholder	return	of	the	companies	in	the	Philadelphia	Utility	Index.	There	is	no	payout	for	performance that	falls	within	the	lowest	quartile	of	performance	of	the	peer	companies.		For	top	quartile	performance,	a	maximum	payout	of	200%	of	target	is earned.

The	costs	of	incentive	awards	are	charged	to	income	over	the	3-year	period.		In	January	2017	the	Board	approved	and	Entergy	granted 220,450	performance	units	under	the	2015	Equity	Ownership	and	Long-Term	Cash	Incentive	Plan.		The	performance	units	were	made	effective	as of	January	26,	2017,	and	were	valued	at	$71.40	per	share.	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	information	about	the	long-term	performance	units	outstanding	at	the	target	level	as	of	December	31,	 2017:

|  | Shares | Weighted-Average<br>Grant	Date	Fair	Value<br>Per	Share |
| :--- | :--- | :--- |
| Outstanding\tshares\tat\tJanuary\t1,\t2017 | 571,551 | $82.02 |
| Granted | 258,808 | $72.28 |
| Vested | (86,964) | $67.16 |
| Forfeited | (209,244) | $72.12 |
| Outstanding\tshares\tat\tDecember\t31,\t2017 | 534,151 | $83.60 |

The	following	table	includes	financial	information	for	the	long-term	performance	units	for	each	of	the	years	presented:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tconsolidated\tnet\tincome | $10.8 | $12.3 | $11.8 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tconsolidated\tnet\tincome | $4.2 | $4.8 | $4.5 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $3.0 | $2.9 | $2.3 |

In	January	2017,	Entergy	issued	86,964	shares	of	Entergy	Corporation	common	stock	at	a	share	price	of	$71.89	for	awards	earned	and dividends	 accrued	 under	 the	 2014-2016	 Long-Term	 Performance	 Unit	 Program.	In	 January	 2016,	 Entergy	 issued	54,103	 shares	 of	 Entergy Corporation	common	stock	at	a	share	price	of	$68.09	for	awards	earned	and	dividends	accrued	under	the	2013-2015	Long-Term	Performance	Unit Program.	In	January	2015,	Entergy	issued	105,503	shares	of	Entergy	Corporation	common	stock	at	a	share	price	of	$88.67	for	awards	earned	and dividends	accrued	under	the	2012-2014	Long-Term	Performance	Unit	Program.

# Restricted	Stock	Unit	Awards

Entergy	grants	restricted	stock	unit	awards	earned	under	its	stock	benefit	plans	in	the	form	of	stock	units	that	are	subject	to	time-based restrictions.		The	restricted	stock	units	may	be	settled	in	shares	of	Entergy	Corporation	common	stock	or	the	cash	value	of	shares	of	Entergy Corporation	common	stock	at	the	time	of	vesting.		The	costs	of	restricted	stock	unit	awards	are	charged	to	income	over	the	restricted	period,	which varies	from	grant	to	grant.		The	average	vesting	period	for	restricted	stock	unit	awards	granted	is	41	months.		As	of	December	31,	2017,	there were	201,570	unvested	restricted	stock	units	that	are	expected	to	vest	over	an	average	period	of	24	months.

The	following	table	includes	information	about	the	restricted	stock	unit	awards	outstanding	as	of	December	31,	2017:

|  | Shares | Weighted-Average<br>Grant	Date	Fair	Value<br>Per	Share |
| :--- | :--- | :--- |
| Outstanding\tshares\tat\tJanuary\t1,\t2017 | 181,650 | $74.94 |
| Granted | 40,170 | $79.10 |
| Vested | (5,800) | $73.22 |
| Forfeited | (14,450) | $79.69 |
| Outstanding\tshares\tat\tDecember\t31,\t2017 | 201,570 | $75.48 |

The	following	table	includes	financial	information	for	restricted	stock	unit	awards	for	each	of	the	years	presented:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Compensation\texpense\tincluded\tin\tEntergy's\tconsolidated\tnet\tincome | $2.5 | $2.2 | $0.9 |
| Tax\tbenefit\trecognized\tin\tEntergy's\tconsolidated\tnet\tincome | $1.0 | $0.8 | $0.4 |
| Compensation\tcost\tcapitalized\tas\tpart\tof\tfixed\tassets\tand\tinventory | $0.6 | $0.4 | $0.3 |

The	total	fair	value	of	the	restricted	stock	unit	awards	granted	was	$3	million,	$5	million,	and	$4	million	for	the	years	ended	December	31, 2017,	2016,	and	2015,	respectively.

The	total	fair	value	of	the	restricted	stock	unit	awards	vested	was	$0.4	million,	$2	million,	and	$1	million	for	the	years	ended	December 31,	2017,	2016,	and	2015,	respectively.

Entergy's	reportable	segments	as	of	December	31,	2017	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,	operation,	and	decommissioning	of	nuclear	power	plants	located in	the	northern	United	States	and	the	sale	of	the	electric	power	produced	by	its	operating	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.

Entergy's	segment	financial	information	is	as	follows:

| 2017 | Utility | Entergy	Wholesale<br>Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $9,417,866 | $1,656,730 | $— | ($115) | $11,074,481 |
| Asset\twrite-offs,\timpairments,\tand\nrelated\tcharges | $— | $538,372 | $— | $— | $538,372 |
| Depreciation,\tamortization,\t&amp;\ndecommissioning | $1,345,906 | $448,079 | $1,678 | $— | $1,795,663 |
| Interest\tand\tinvestment\tincome | $218,317 | $224,121 | $21,669 | ($175,910) | $288,197 |
| Interest\texpense | $547,301 | $23,714 | $139,619 | ($48,291) | $662,343 |
| Income\ttaxes | $794,616 | ($146,480) | ($105,566) | $— | $542,570 |
| Consolidated\tnet\tincome\t(loss) | $773,148 | ($172,335) | ($47,840) | ($127,620) | $425,353 |
| Total\tassets | $42,978,669 | $5,638,009 | $1,011,612 | ($2,921,141) | $46,707,149 |
| Investment\tin\taffiliates\t-\tat\tequity | $198 | $— | $— | $— | $198 |
| Cash\tpaid\tfor\tlong-lived\tasset\tadditions | $3,680,513 | $320,667 | $438 | $— | $4,001,618 |

| 2016 | Utility | Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $8,996,106 | $1,849,638 | $— | ($99) | $10,845,645 |
| Asset\twrite-offs,\timpairments,\tand\nrelated\tcharges | $— | $2,835,637 | $— | $— | $2,835,637 |
| Depreciation,\tamortization,\t&amp;\ndecommissioning | $1,298,043 | $374,922 | $1,647 | $— | $1,674,612 |
| Interest\tand\tinvestment\tincome | $189,994 | $108,466 | $27,385 | ($180,718) | $145,127 |
| Interest\texpense | $557,546 | $22,858 | $139,090 | ($53,124) | $666,370 |
| Income\ttaxes | $424,388 | ($1,192,263) | ($49,384) | $— | ($817,259) |
| Consolidated\tnet\tincome\t(loss) | $1,151,133 | ($1,493,124) | ($94,917) | ($127,595) | ($564,503) |
| Total\tassets | $41,098,751 | $6,696,038 | $1,283,816 | ($3,174,171) | $45,904,434 |
| Investment\tin\taffiliates\t-\tat\tequity | $198 | $— | $— | $— | $198 |
| Cash\tpaid\tfor\tlong-lived\tasset\tadditions | $3,754,225 | $289,639 | $393 | $— | $4,044,257 |

| 2015 | Utility | Entergy	Wholesale<br>Commodities* | All	Other | Eliminations | Consolidated |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $9,451,486 | $2,061,827 | $— | ($62) | $11,513,251 |
| Asset\twrite-offs,\timpairments,\tand\nrelated\tcharges | $68,672 | $2,036,234 | $— | $— | $2,104,906 |
| Depreciation,\tamortization,\t&amp;\ndecommissioning | $1,238,832 | $376,560 | $2,156 | $— | $1,617,548 |
| Interest\tand\tinvestment\tincome | $191,546 | $148,654 | $34,303 | ($187,441) | $187,062 |
| Interest\texpense | $543,132 | $26,788 | $129,750 | ($56,201) | $643,469 |
| Income\ttaxes | $16,761 | ($610,339) | ($49,349) | $— | ($642,927) |
| Consolidated\tnet\tincome\t(loss) | $1,114,516 | ($1,065,657) | ($74,353) | ($131,240) | ($156,734) |
| Total\tassets | $38,356,906 | $8,210,183 | ($461,505) | ($1,457,903) | $44,647,681 |
| Investment\tin\taffiliates\t-\tat\tequity | $199 | $4,142 | $— | $— | $4,341 |
| Cash\tpaid\tfor\tlong-lived\tasset\tadditions | $2,495,194 | $569,824 | $236 | $— | $3,065,254 |

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.

On	December	29,	2014,	the	Vermont	Yankee	plant	ceased	power	production	and	entered	its	decommissioning	phase.	 In	December	2015, Rhode	Island	State	Energy	Center,	a	natural	gas-fired	combined	cycle	generating	plant,	was	sold.	In	October	2015	management	announced	the intention	 to	 shutdown	 the	 FitzPatrick	 plant	 in	 2017	 and	 the	 Pilgrim	 plant	 in	 2019,	 earlier	 than	 previously	 expected.	In	 2016	 management announced	the	planned	sale	of	Vermont	Yankee	in	2018,	the	planned	sale	of	FitzPatrick	in	2017,	and	the	planned	amendment	of	the	Consumers Energy	PPA	to	terminate	early,	in	May	2018,	and	the	subsequent	plan	to	shut	down	the	Palisades	plant	in	2018,	earlier	than	expected.	 In	January 2017	management	announced	a	settlement	with	New	York	State	to	shut	down	Indian	Point	2	in	2020	and	Indian	Point	3	in	2021,	both	earlier	than expected.	In	March	2017	 the	FitzPatrick	plant	was	sold	 to	Exelon.	In	September	2017	management	announced	 the	 termination	of	 the	PPA amendment	agreement	with	Consumers	Energy	and	the	revised	plan	to	continue	to	operate	Palisades	under	the	current	PPA	and	to	shut	down Palisades	permanently	on	May	31,	2022.

Management	expects	these	transactions	to	result	in	the	cessation	of	merchant	power	generation	at	all	Entergy	Wholesale	Commodities nuclear	power	plants	owned	and	operated	by	Entergy	by	2022.	Entergy	will	continue	to	have	the	obligation	to	decommission	the	nuclear	plants owned	by	Entergy.

These	decisions	and	transactions	resulted	in	asset	impairments;	employee	retention	and	severance	expenses	and	other	benefits-related costs;	and	contracted	economic	development	contributions.	The	employee	retention	and	severance	expenses	and	other	benefits-related	costs,	and contracted	economic	development	contributions	are	included	in	"Other	operation	and	maintenance"	in	the	consolidated	statement	of	operations.

Total	restructuring	charges	in	2017	were	comprised	of	the	following:

| Balance	as	of	January	1,	2017 | $70 | $21 | $91 |
| :--- | :--- | :--- | :--- |
| Restructuring\tcosts\taccrued | 113 | — | 113 |
| Non-cash\tportion | — | (7) | (7) |
| Cash\tpaid\tout | 100 | — | 100 |
| Balance\tas\tof\tDecember\t31,\t2017 | $83 | $14 | $97 |

| Balance	as	of	January	1,	2016 | $— | $— | $— |
| :--- | :--- | :--- | :--- |
| Restructuring\tcosts\taccrued | 74 | 21 | 95 |
| Non-cash\tportion | (3) | — | (3) |
| Cash\tpaid\tout | 1 | — | 1 |
| Balance\tas\tof\tDecember\t31,\t2016 | $70 | $21 | $91 |

In	addition,	Entergy	Wholesale	Commodities	incurred	$0.5	billion	in	2017	and	$2.8	billion	in	2016	of	impairment	and	other	related	charges associated	with	these	strategic	decisions	and	transactions.	See	Note	14	to	the	financial	statements	for	further	discussion	of	these	impairment charges.

Going	forward,	Entergy	Wholesale	Commodities	expects	to	incur	employee	retention	and	severance	expenses	of	approximately	 $165 million	in	2018	and	approximately	$205	million	from	2019	through	mid-2022	associated	with	these	strategic	transactions.

# Geographic	Areas

For	the	years	ended	December	31,	2017,	2016,	and	2015,	the	amount	of	revenue	Entergy	derived	from	outside	of	the	United	States	was insignificant.		As	of	December	31,	2017	and	2016,	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. 	 ACQUISITIONS,	 DISPOSITIONS,	 AND IMPAIRMENT	 OF	 LONG-LIVED	 ASSETS (Entergy	 Corporation,	 Entergy Arkansas,	Entergy	Louisiana,	and	Entergy	New	Orleans)

# Acquisitions

# Union	Power	Station

In	March	2016,	Entergy	Arkansas,	Entergy	Louisiana,	and	Entergy	New	Orleans	purchased	 the	Union	Power	Station,	a	 1,980	 MW (summer	rating)	power	generation	facility	located	near	El	Dorado,	Arkansas,	from	Union	Power	Partners,	L.P.	The	Union	Power	Station	consists of	four	natural	gas-fired,	combined-cycle	gas	turbine	power	blocks,	each	rated	at	495	MW	(summer	rating).	Entergy	Louisiana	purchased	two	of the	power	blocks	and	a	50%	undivided	ownership	interest	in	certain	assets	related	to	the	facility,	and	Entergy	Arkansas	and	Entergy	New	Orleans each	purchased	one	power	block	and	a	25%	undivided	ownership	interest	in	such	related	assets.	The	aggregate	purchase	price	for	the	Union	Power Station	was	approximately	$949	million	(approximately	$237	million	for	each	power	block	and	associated	assets).

# 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	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	$28	million	in	2017,	$13	million	in	2016,	and	$15	million	in	2015.

In	December	2016,	Entergy	reached	an	agreement	with	Consumers	Energy	to	amend	the	existing	PPA	to	terminate	early,	on	May	31, 2018.	Pursuant	to	the	agreement	to	amend	the	PPA,	Consumers	Energy	would	pay	Entergy	$172	million	for	the	early	termination	of	the	PPA.	The PPA	amendment	agreement	was	subject	to	regulatory	approvals,	including	approval	by	the	Michigan	Public	Service	Commission.	Separately, Entergy	intended	to	shut	down	the	Palisades	nuclear	power	plant	permanently	on	October	1,	2018,	after	refueling	in	the	spring	of	2017	and operating	through	the	end	of	that	fuel	cycle.	Entergy	updated	the	liability	amortization	calculation	to	reflect	the	expected	early	termination	of	the PPA.

In	September	2017	the	Michigan	Public	Service	Commission	issued	an	order	conditionally	approving	the	PPA	amendment	transaction, but	only	granting	Consumers	Energy	recovery	of	$136.6	million	of	the	$172	million	requested	early	termination	payment.	As	a	result,	Entergy	and Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement.	Entergy	will	continue	to	operate	Palisades	under	the	current	PPA	with Consumers	Energy,	instead	of	shutting	down	in	the	fall	of	2018	as	previously	planned.	Entergy	intends	to	shut	down	the	Palisades	nuclear	power plant	permanently	on	May	31,	2022.	Based	on	that	decision,	the	amounts	to	be	amortized	to	revenue	for	the	next	five	years	will	be	approximately $6	million	in	2018,	$10	million	in	2019,	$11	million	in	2020,	$12	million	in	2021,	and	$5	million	in	2022.

# 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	made	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	paid	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	was	due	by	January	15	of	the	following	year,	and	the	final	payment	to	NYPA	was made	 in	 January	 2015.	 	 Entergy	 recorded	 the	 liability	 for	 payments	 to	 NYPA	 as	 power	 was	 generated	 and	 sold	 by	 Indian	 Point	 3	 and FitzPatrick.		An	amount	equal	to	the	liability	was	recorded	to	the	plant	asset	account	as	contingent	purchase	price	consideration	for	the	plants.

# Dispositions

# Vermont	Yankee

In	November	2016,	Entergy	entered	into	an	agreement	to	sell	100%	of	the	membership	interests	in	Entergy	Nuclear	Vermont	Yankee, LLC	to	a	subsidiary	of	NorthStar.	Entergy	Nuclear	Vermont	Yankee	is	the	owner	of	the	Vermont	Yankee	plant	and	is	in	the	Entergy	Wholesale Commodities	segment.	The	sale	of	Entergy	Nuclear	Vermont	Yankee	to	NorthStar	will	include	the	transfer	of	the	nuclear	decommissioning	trust fund	and	the	asset	retirement	obligation	for	the	spent	fuel	management	and	decommissioning	of	the	plant.

Entergy	Nuclear	Vermont	Yankee	has	an	outstanding	credit	facility	with	borrowing	capacity	of	 $145	million	to	pay	for	dry	fuel	storage costs.	This	credit	facility	is	guaranteed	by	Entergy	Corporation.	At	or	before	closing,	a	subsidiary	of	Entergy	will	assume	the	obligations	under	the existing	credit	facility	or	enter	into	a	new	credit	facility	and	Entergy	will	guarantee	the	credit	facility.	At	the	closing	of	the	sale	transaction, NorthStar	will	pay	$1,000	for	the	membership	interests	in	Entergy	Nuclear	Vermont	Yankee,	and	NorthStar	will	cause	Entergy	Nuclear	Vermont Yankee	to	issue	a	promissory	note	to	an	Entergy	subsidiary.	The	amount	of	the	promissory	note	issued	will	be	equal	to	the	amount	drawn	under the	credit	facility	or	the	amount	drawn	under	the	new	credit	facility,	plus	borrowing	fees	and	costs	incurred	by	Entergy	in	connection	with	such facility.	The	principal	amount	drawn	under	the	outstanding	credit	facility	was	$104	million	as	of	December	31,	2017,	and	the	net	book	value	of Entergy	Nuclear	Vermont	Yankee,	including	unrealized	gains	on	the	decommissioning	trust	fund,	as	of	December	31,	2017,	was	approximately $123	million.

The	transaction	is	subject	to	certain	closing	conditions,	including	approval	by	the	NRC;	approval	by	the	State	of	Vermont	Public	Utility Commission,	including	approval	of	revised	site	restoration	standards	that	have	been	proposed	as	part	of	the	transaction;	the	transfer	of	all	spent nuclear	fuel	to	dry	fuel	storage	on	the	independent	spent	fuel	storage	installation;	and	that	the	market	value	of	the	fund	assets	held	in	the decommissioning	trust	fund	for	the	Vermont	Yankee	Nuclear	Power	Station,	less	the	hypothetical	income	tax	on	the	aggregate	unrealized	net	gain of	 such	 fund	 assets	 at	 closing,	 is	 equal	 to	 or	 exceeds	$451.95	million,	 subject	 to	 adjustments.	Entergy	 has	 the	 option	 to	 contribute	 to	 the decommissioning	trust	fund	if	the	value	is	less	than	$451.95	million,	subject	to	adjustments.	The	transaction	is	planned	to	close	by	the	end	of 2018.

# FitzPatrick

In	August	2016,	Entergy	entered	into	an	agreement	to	sell	the	FitzPatrick	plant,	an	 838	MW	nuclear	power	plant	owned	by	Entergy	in	the Entergy	Wholesale	Commodities	segment.	As	a	result	of	the	sales	agreement	and	the	status	of	the	necessary	regulatory	approvals,	the	assets	and liabilities	associated	with	the	sale	of	FitzPatrick	to	Exelon	were	classified	as	held	for	sale	on	Entergy	Corporation	and	Subsidiaries'	Consolidated Balance	Sheet	as	of	December	31,	2016.	At	December	31,	2016,	the	receivable	for	the	beneficial	interest	in	the	decommissioning	trust	fund	was $785	million,	classified	within	other	deferred	debits,	and	the	asset	retirement	obligation	was	 $714	million,	classified	within

other	non-current	liabilities.	See	Note	9	to	the	financial	statements	for	further	discussion	of	FitzPatrick's	decommissioning	liability	and	see	Note 16	to	the	financial	statements	for	further	discussion	of	the	receivables	for	the	beneficial	interest	in	FitzPatrick's	decommissioning	trust	fund.

In	March	2017	the	NRC	approved	the	sale	of	the	plant	to	Exelon.	The	transaction	closed	in	March	2017	for	a	purchase	price	of	$110 million,	 which	 included	 a	$10	million	non-refundable	signing	fee	paid	in	August	2016,	in	addition	to	the	assumption	by	Exelon	of	certain liabilities	related	to	the	FitzPatrick	plant,	resulting	in	a	pre-tax	gain	on	the	sale	of	$16	million.	At	the	transaction	close,	Exelon	paid	an	additional $8	million	for	the	proration	of	certain	expenses	prepaid	by	Entergy.	The	disposition-date	fair	value	of	the	decommissioning	trust	fund	was	$805 million,	classified	within	other	deferred	debits,	and	the	disposition-date	fair	value	of	the	asset	retirement	obligation	was	 $727	million,	classified within	other	non-current	liabilities.	The	transaction	also	included	property,	plant,	and	equipment	with	a	net	book	value	of	zero,	materials	and supplies,	and	prepaid	assets.

As	part	of	the	transaction,	Entergy	entered	into	a	reimbursement	agreement	with	Exelon	pursuant	to	which	Exelon	reimbursed	Entergy	for specified	out-of-pocket	costs	associated	with	Entergy's	operation	of	FitzPatrick	prior	to	closing	of	the	sale.	In	the	first	quarter	2017,	Entergy	billed Exelon	for	reimbursement	of	$98	million	of	other	operation	and	maintenance	expenses,	$7	million	in	lost	operating	revenues,	and	$3	million	in taxes	other	than	income	taxes,	partially	offset	by	a	$10	million	defueling	credit	to	Exelon.

As	discussed	in	Note	3	to	the	financial	statements,	as	a	result	of	the	sale	of	FitzPatrick	on	March	31,	2017,	Entergy	redetermined	the plant's	tax	basis,	resulting	in	a	$44	million	income	tax	benefit	in	the	first	quarter	2017.

# Top	Deer

# Rhode	Island	State	Energy	Center

# 2015	Impairment	Conclusions

Entergy	determined	in	October	2015	that	it	would	close	FitzPatrick	at	the	end	of	its	fuel	cycle,	which	was	planned	for	January	27,	2017, because	of	poor	market	conditions	that	led	to	reduced	revenues,	a	poor	market	design	that	failed	to	properly	compensate	nuclear	generators	for	the benefits	they	provide,	and	increased	operational	costs.	This	decision	came	after	management's	extensive	analysis	of	whether	it	was	advisable economically	to	refuel	the	plant,	as	scheduled,	in	the	fall	of	2016.	Entergy	also	had	discussions	with	the	State	of	New	York	regarding	the	future	of FitzPatrick.	Because	of	the	uncertainty	regarding	the	refueling	decision	and	its	implications	to	the	plant's	expected	operating	life,	Entergy	tested the	recoverability	of	the	plant	and	related	assets	as	of	September	30,	2015.	See	above	in	the	Dispositions	section	for	further	information	on	the subsequent	decision	to	sell	the	FitzPatrick	plant.

Entergy	determined	in	October	2015	that	it	would	close	Pilgrim	no	later	than	June	1,	2019	because	of	poor	market	conditions	that	led	to reduced	revenues,	a	poor	market	design	 that	failed	 to	properly	compensate	nuclear	generators	for	 the	benefits	 they	provide,	and	 increased operational	costs.	The	decision	came	after	management's	extensive	analysis	of	the	economics	and	operating	life	of	the	plant	following	the	NRC's decision	in	September	2015

to	place	the	plant	in	its	"multiple/repetitive	degraded	cornerstone	column"	(Column	4)	of	its	Reactor	Oversight	Process	Action	Matrix.	Because	of the	uncertainty	regarding	the	plant's	operating	life	created	by	the	NRC's	decision	and	management's	analysis	of	the	plant,	Entergy	tested	the recoverability	of	the	plant	and	related	assets	as	of	September	30,	2015.

Due	to	the	announced	plant	closures	in	October	2015,	as	well	as	the	continued	challenging	market	price	trend,	the	high	level	of	investment required	to	continue	to	operate	the	Entergy	Wholesale	Commodities	plants,	and	the	inadequate	compensation	provided	to	nuclear	generators	for their	capacity	benefits	under	the	current	market	design,	in	the	fourth	quarter	2015,	Entergy	tested	the	recoverability	of	the	plant	and	related	assets of	the	two	remaining	operating	nuclear	power	generating	facilities	in	the	Entergy	Wholesale	Commodities	business,	Palisades	and	Indian	Point. For	purposes	of	that	evaluation,	Entergy	considered	a	number	of	factors	associated	with	the	facilities'	continued	operation,	including	the	status	of the	associated	NRC	licenses,	the	status	of	state	regulatory	issues,	existing	power	purchase	agreements,	and	the	supply	region	in	which	the	nuclear facilities	sell	energy	and	capacity.

Under	 generally	 accepted	 accounting	 principles	 the	 determination	 of	 an	 asset's	 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	operations	of	the	plant	and	pending	legal	and	state	regulatory	matters,	as	well	as	projections	of	future	revenues	and	costs	over	the	estimated remaining	life	of	the	plant.

The	tests	for	FitzPatrick	and	Pilgrim	indicated	that	the	probability-weighted	undiscounted	net	cash	flows	did	not	exceed	the	carrying values	of	the	plants	and	related	assets	as	of	September	30,	2015.

The	test	for	Palisades	indicated	that	the	probability-weighted	undiscounted	net	cash	flows	did	not	exceed	the	carrying	value	of	the	plant and	related	assets	as	of	December	31,	2015.

The	test	for	Indian	Point	indicated	that	the	probability-weighted	undiscounted	net	cash	flows	exceeded	the	carrying	value	of	the	plant	and related	assets	as	of	December	31,	2015.	As	such,	the	carrying	value	of	Indian	Point	was	not	impaired	as	of	December	31,	2015.

As	of	September	30,	2015,	the	estimated	fair	value	of	the	FitzPatrick	plant	and	related	long-lived	assets	was	 $29	million,	while	the carrying	value	was	$742	million,	resulting	in	an	impairment	charge	of	$713	million.	Materials	and	supplies	were	evaluated	and	written	down	by $48	million.	In	addition,	FitzPatrick	had	a	contract	asset	recorded	for	an	agreement	between	Entergy	subsidiaries	and	NYPA	entered	when Entergy	 subsidiaries	 purchased	 FitzPatrick	 from	 NYPA	 in	 2000	 and	 NYPA	 retained	 the	 decommissioning	 trusts	 and	 the	 decommissioning liabilities.	The	agreement	gave	NYPA	the	right	to	require	the	Entergy	subsidiaries	to	assume	the	decommissioning	liability	provided	that	it	assigns the	decommissioning	trust,	up	to	a	specified	level,	to	Entergy.	If	NYPA	retained	the	decommissioning	liabilities,	the	Entergy	subsidiaries	would perform	the	decommissioning	of	the	plant	at	a	price	equal	to	the	lesser	of	a	pre-specified	level	or	the	amount	in	the	decommissioning	trusts.	The contract	asset	represented	an	estimate	of	the	present	value	of	the	difference	between	the	Entergy	subsidiaries'	stipulated	contract	amount	for decommissioning	 the	plants	 less	 the	decommissioning	costs	estimated	 in	 independent	decommissioning	cost	studies.	See	Note	9	for	further discussion	of	the	contract	asset.	Due	to	a	change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows,	the	result	was	a	write	down of	the	contract	asset	from	$335	million	to	$131	million,	for	a	charge	of	$204	million.	In	summary,	as	of	September	30,	2015,	the	impairment	and related	charges	for	FitzPatrick	was	$965	million	($624	million	net-of-tax).

As	of	September	30,	2015,	the	estimated	fair	value	of	the	Pilgrim	plant	and	related	long-lived	assets	is	 $65	million,	while	the	carrying value	 was	$718	million,	resulting	in	an	impairment	charge	of	$653	million.	Materials	and	supplies	were	evaluated	and	written	down	by	$24 million.	In	summary,	as	of	September	30,	2015,	the	total	impairment	loss	and	related	charges	for	Pilgrim	was	$677	million	($438	million	net-of- tax).	The	pre-impairment	carrying	value	of	$718	million	includes	the	effect	of	a	$134	million	increase	in	Pilgrim's	estimated	decommissioning cost	liability	and	the	related	asset	retirement	cost	asset.	The	increase	in	the	estimated	decommissioning	cost	liability	primarily	resulted	from	the change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows.

As	of	December	31,	2015,	the	estimated	fair	value	of	the	Palisades	plant	and	related	long-lived	assets	was	 $463	million,	while	the carrying	value	was	$859	million,	resulting	in	an	impairment	charge	of	$396	million	($256	million	net-of-tax).	The	pre-impairment	carrying	value of	$859	million	includes	the	effect	of	a	$42	million	increase	in	Palisades'	estimated	decommissioning	cost	liability	and	the	related	asset	retirement cost	asset.	The	increase	in	the	estimated	decommissioning	cost	liability	primarily	resulted	from	the	assessment	of	the	estimated	decommissioning cash	flows	that	occurred	in	conjunction	with	the	impairment	analysis.

As	discussed	in	more	detail	above	in	the	Acquisitions	section,	in	December	2016,	Entergy	reached	an	agreement	with	Consumers	Energy to	amend	the	existing	PPA	to	terminate	early,	on	May	31,	2018.	 The	PPA	amendment	agreement	was	subject	to	regulatory	approvals,	including approval	by	the	Michigan	Public	Service	Commission.	Separately,	Entergy	intended	to	shut	down	the	Palisades	nuclear	power	plant	permanently on	October	1,	2018,	after	refueling	in	the	spring	of	2017	and	operating	through	the	end	of	that	fuel	cycle.	As	a	result	of	the	planned	PPA termination	and	its	intention	to	shut	down	the	plant,	Entergy	tested	the	recoverability	of	the	plant	and	related	assets	as	of	December	31,	2016. Entergy	and	Consumers	Energy	subsequently	agreed	to	terminate	the	PPA	amendment	agreement	and	Entergy	now	intends	to	shut	down	the Palisades	plant	permanently	on	May	31,	2022.

Indian	Point	2	and	Indian	Point	3	have	an	application	pending	for	renewed	NRC	licenses.		Various	parties,	including	the	State	of	New York,	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.		Indian	Point	2	reached	the	expiration	date	of	its original	NRC	operating	license	on	September	28,	2013,	and	Indian	Point	3	reached	the	expiration	date	of	its	original	NRC	operating	license	on December	12,	2015.	Upon	expiration	of	their	operating	licenses,	each	plant	entered	into	a	period	of	extended	operation	under	the	timely	renewal rule.

In	January	2017,	Entergy	announced	that	it	reached	a	settlement	with	New	York	State	to	shut	down	Indian	Point	2	by	April	30,	2020	and Indian	Point	3	by	April	30,	2021,	and	resolve	all	New	York	State-initiated	legal	challenges	to	Indian	Point's	operating	license	renewal.	 As	part	of the	 settlement,	 New	York	 State	 agreed	 to	 issue	 Indian	 Point's	 water	 quality	 certification	 and	 Coastal	 Zone	 Management	Act	 consistency certification	and	to	withdraw	its	objection	to	license	renewal	before	the	NRC.	New	York	State	also	agreed	to	issue	a	water	discharge	permit,	which is	required	regardless	of	whether	the	plant	is	seeking	a	renewed	NRC	license.	The	shutdowns	are	conditioned,	among	other	things,	upon	such actions	being	taken	by	New	York	State.	As	a	result	of	its	evaluation	of	alternatives	to	the	continued	operation	of	the	Indian	Point	plants,	and	taking into	consideration	the	status	of	negotiations	with	the	State	of	New	York,	Entergy	tested	the	recoverability	of	the	plants	and	related	assets	as	of December	31,	2016.

The	tests	for	Palisades	and	Indian	Point	indicated	that	the	probability-weighted	undiscounted	net	cash	flows	did	not	exceed	the	carrying values	of	the	plants	and	related	assets	as	of	December	31,	2016.

As	of	December	31,	2016	the	estimated	fair	value	of	the	Palisades	plant	and	related	long-lived	assets	was	 $206	million,	while	the	carrying value	 was	$558	million,	resulting	in	an	impairment	charge	of	$352	million.	Materials	and	supplies	were	evaluated	and	written	down	by	$48 million.	In	summary,	as	of	December	31,	2016,	the	total	impairment	loss	and	related	charges	for	Palisades	was	$400	million	($258	million	net-of- tax).	The	pre-impairment	carrying	value	of	$558	million	included	the	effect	of	a	$129	million	increase	in	Palisades'	estimated	decommissioning cost	liability	and	the	related	asset	retirement	cost	asset.	The	increase	in	the	estimated	decommissioning	cost	liability	primarily	resulted	from	the change	in	expectation	regarding	the	timing	of	decommissioning	cash	flows.	See	Note	9	to	the	financial	statements	for	further	discussion	regarding the	Palisades	decommissioning	cost	revision.

As	of	December	31,	2016	the	estimated	fair	value	of	the	Indian	Point	plants	and	related	long-lived	assets	was	 $433	million,	while	the carrying	value	was	$2,619	million,	resulting	in	an	impairment	charge	of	$2,186	million.	Materials	and	supplies	were	evaluated	and	written	down by	$157	million.	In	summary,	as	of	December	31,	2016,	the	total	impairment	loss	and	related	charges	for	Indian	Point	was	 $2,343	million	($1,511 million	net-of-tax).	The	pre-

impairment	carrying	value	of	$2,619	million	included	the	effect	of	a	$392	million	increase	in	Indian	Point's	estimated	decommissioning	cost liability	and	the	related	asset	retirement	cost	asset.	The	increase	in	the	estimated	decommissioning	cost	liability	primarily	resulted	from	the	change in	expectation	regarding	the	timing	of	decommissioning	cash	flows.	See	Note	9	to	the	financial	statements	for	further	discussion	regarding	the Indian	Point	decommissioning	cost	revision.

In	2017	Entergy	management	continued	to	execute	the	strategy	to	reduce	the	size	of	Entergy	Wholesale	Commodities'	merchant	fleet, with	the	planned	shutdowns	of	Pilgrim	by	May	31,	2019,	Indian	Point	2	by	April	30,	2020,	Indian	Point	3	by	April	30,	2021,	and,	as	discussed	in further	detail	above	in	the	Acquisitions	section,	Palisades	on	May	31,	2022.	The	FitzPatrick	plant	was	classified	as	held-for-sale	at	December	31, 2016,	and	subsequently	sold	to	Exelon	in	March	2017.

In	2017	Entergy	Wholesale	Commodities	incurred	$538	million	of	impairment	charges	related	to	nuclear	fuel	spending,	nuclear	refueling outage	spending,	and	expenditures	for	capital	assets.	These	costs	were	charged	to	expense	as	incurred	as	a	result	of	the	impaired	fair	value	of	the Entergy	Wholesale	Commodities	nuclear	plants'	long-lived	assets	due	to	the	significantly	reduced	remaining	estimated	operating	lives	associated with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale	Commodities'	merchant	fleet.

As	discussed	above	in	the	Acquisitions	section,	as	a	result	of	the	Michigan	Public	Service	Commission	only	granting	Consumers	Energy partial	recovery	of	the	requested	early	termination	payment,	Entergy	and	Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement	in September	2017.	Entergy	will	continue	to	operate	Palisades	under	the	current	PPA	with	Consumers	Energy,	instead	of	shutting	down	in	the	fall	of 2018	as	previously	planned.	Entergy	intends	to	shut	down	the	Palisades	plant	permanently	on	May	31,	2022.	As	a	result	of	the	change	in	expected operating	life	of	the	Palisades	plant,	the	expected	probability-weighted	undiscounted	net	cash	flows	as	of	September	30,	2017	exceeded	the carrying	value	of	the	plant	and	related	assets.	Accordingly,	nuclear	fuel	spending,	nuclear	refueling	outage	spending,	and	expenditures	for	capital assets	incurred	at	Palisades	after	September	30,	2017	are	no	longer	charged	to	expense	as	incurred,	but	recorded	as	assets	and	depreciated	or amortized,	subject	to	the	typical	periodic	impairment	reviews	prescribed	in	the	accounting	rules.

# Overall	Regarding	All	Impairments

The	impairments	and	other	related	charges	are	recorded	as	a	separate	line	item	in	Entergy's	consolidated	statements	of	operations	and	are included	within	the	results	of	the	Entergy	Wholesale	Commodities	segment.	In	addition	to	the	impairments	and	other	related	charges,	Entergy expects	to	incur	additional	charges	through	mid-2022	associated	with	these	strategic	transactions.	See	Note	13	to	the	financial	statements	for further	discussion	of	these	additional	charges.

The	fair	value	analyses	for	FitzPatrick,	Pilgrim,	and	Palisades	in	2015,	and	Palisades	and	Indian	Point	in	2016,	were	performed	based	on the	income	approach,	a	discounted	cash	flow	method,	to	determine	the	amount	of	impairment.	The	estimates	of	fair	value	were	based	on	the	prices that	Entergy	would	expect	to	receive	in	hypothetical	sales	of	the	FitzPatrick,	Pilgrim,	Palisades,	and	Indian	Point	plants	and	related	assets	to	a market	participant.	In	order	to	determine	these	prices,	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	plants	and	related	assets,	the	amount	and	timing	of	recoveries	from	future	litigation	with	the	DOE	related	to	spent fuel	storage	costs,	and	the	expected	operating	life	of	the	plant.		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,	are	classified	as	Level	3	in	the	fair	value	hierarchy	discussed	in Note	15	to	the	financial	statements.

The	following	table	sets	forth	a	description	of	significant	unobservable	inputs	used	in	the	valuation	of	the	FitzPatrick,	Pilgrim,	Palisades, and	Indian	Point	plants	and	related	assets:

| Significant	Unobservable	Inputs | Amount | Weighted-Average |
| :--- | :--- | :--- |
| 2015 |  |  |
| Weighted-average\tcost\tof\tcapital |  |  |
| FitzPatrick | 7.5% | 7.5% |
| Pilgrim\t(a) | 7.5%-8.0% | 7.9% |
| Palisades | 7.5% | 7.5% |
| Long-term\tpre-tax\toperating\tmargin\t(cash\tbasis) |  |  |
| FitzPatrick | 10.2% | 10.2% |
| Pilgrim\t(a) | 2.4%-10.6% | 8.1% |
| Palisades\t(b) | 30.8% | 30.8% |
| 2016 |  |  |
| Weighted-average\tcost\tof\tcapital |  |  |
|  | 7.0%-7.5% |  |
| Indian\tPoint\t(c) |  | 7.2% |
| Palisades | 6.5% | 6.5% |
| Long-term\tpre-tax\toperating\tmargin\t(cash\tbasis)\nIndian\tPoint | 19.7% | 19.7% |
|  | 17.8%-38.8% |  |
| Palisades\t(b)\t(d) |  | 34.6% |

(a) The	fair	value	of	Pilgrim	was	based	on	the	probability	weighting	of	two	potential	scenarios.

(b) Most	 of	 the	 Palisades	 output	 is	 sold	 under	 a	15-year	power	purchase	agreement,	entered	at	 the	plant's	acquisition	 in	2007,	 that	 is scheduled	 to	 expire	 in	 2022.	The	 power	 purchase	 agreement	 prices	 currently	 exceed	 market	 prices	 and	 escalate	 each	 year,	 up	 to $61.50/MWh	in	2022.

(c) The	cash	flows	extending	through	the	2021	shutdown	at	Indian	Point	3	were	assigned	a	higher	discount	factor	to	incorporate	the	increased risk	associated	with	longer	operations.

(d) The	fair	value	of	Palisades	at	December	31,	2016	is	based	on	the	probability	weighting	of	whether	the	PPA	will	terminate	before	the originally	scheduled	termination	in	2022.

Entergy's	Accounting	 Policy	 and	 Entergy	Wholesale	 Commodities	Accounting	 group,	 which	 reports	 to	 the	 Chief	Accounting	 Officer,	 was primarily	responsible	for	determining	the	valuation	of	the	FitzPatrick,	Pilgrim,	Palisades	and	Indian	Point	plants	and	related	assets,	in	consultation with	external	advisors.	Entergy's	Accounting	Policy	group	obtained	and	reviewed	information	from	other	Entergy	departments	with	expertise	on the	various	inputs	and	assumptions	that	were	necessary	to	calculate	the	fair	values	of	the	asset	groups.

# NOTE	 15. 	 RISK	 MANAGEMENT	 AND	 FAIR	 VALUES (Entergy	 Corporation,	 Entergy	 Arkansas,	 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	commodity	or	instrument.		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.

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	use	derivative	instruments	to	hedge	the	exposure	to	price	volatility	inherent	in their	purchased	power,	fuel,	and	gas	purchased	for	resale	costs	that	are	recovered	from	customers.

As	a	wholesale	generator,	Entergy	Wholesale	Commodities'	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.		Entergy Wholesale	Commodities	enters	into	forward	contracts	with	its	customers	and	also	sells	energy	and	capacity	in	the	day	ahead	or	spot	markets.		In addition	 to	 its	 forward	 physical	 power	 and	 gas	 contracts,	 Entergy	Wholesale	 Commodities	 also	 uses	 a	 combination	 of	 financial	 contracts, including	swaps,	collars,	and	options,	to	mitigate	commodity	price	risk.		When	the	market	price	falls,	the	combination	of	instruments	is	expected to	settle	in	gains	that	offset	lower	revenue	from	generation,	which	results	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	to	manage	natural	risks	inherent	in	its	physical	or	financial	assets	or	liabilities.	Electricity	over-the-counter instruments	and	futures	contracts	that	financially	settle	against	day-ahead	power	pool	prices	are	used	to	manage	price	exposure	for	Entergy Wholesale	 Commodities	 generation.	 	 The	 maximum	 length	 of	 time	 over	 which	 Entergy	 Wholesale	 Commodities	 is	 currently	 hedging	 the variability	in	future	cash	flows	with	derivatives	for	forecasted	power	transactions	at	December	31,	2017	is	approximately	3.25	years.		Planned generation	currently	under	contract	from	Entergy	Wholesale	Commodities	nuclear	power	plants	is	98%	for	2018,	of	which	approximately	79%	is sold	under	financial	derivatives	and	the	remainder	under	normal	purchase/normal	sale	contracts.		Total	planned	generation	for	2018	is	27.9	TWh.

Entergy	 may	 use	 standardized	 master	 netting	 agreements	 to	 help	 mitigate	 the	 credit	 risk	 of	 derivative	 instruments.	These	 master agreements	facilitate	the	netting	of	cash	flows	associated	with	a	single	counterparty	and	may	include	collateral	requirements.	Cash,	letters	of credit,	and	parental/affiliate	guarantees	may	be	obtained	as	security	from	counterparties	in	order	to	mitigate	credit	risk.	The	collateral	agreements require	a	counterparty	to	post	cash	or	letters	of	credit	in	the	event	an	exposure	exceeds	an	established	threshold.	The	threshold	represents	an unsecured	credit	limit,	which	may	be	supported	by	a	parental/affiliate	guaranty,	as	determined	in	accordance	with	Entergy's	credit	policy.

In	addition,	collateral	agreements	allow	for	termination	and	liquidation	of	all	positions	in	the	event	of	a	failure	or	inability	to	post	collateral.

Certain	of	the	agreements	to	sell	the	power	produced	by	Entergy	Wholesale	Commodities	power	plants	contain	provisions	that	require	an Entergy	subsidiary	to	provide	credit	support	to	secure	its	obligations	depending	on	the	mark-to-market	values	of	the	contracts.		The	primary	form of	credit	support	to	satisfy	these	requirements	is	an	Entergy	Corporation	guarantee.		As	of	December	31,	2017,	derivative	contracts	with	eight counterparties	were	in	a	liability	position	(approximately	$65	million	total).	In	addition	to	the	corporate	guarantee,	$1	million	in	cash	collateral was	required	to	be	posted	by	the	Entergy	subsidiary	to	its	counterparties	and	$4	million	in	cash	collateral	and	$34	million	in	letters	of	credit	were required	to	be	posted	by	its	counterparties	to	the	Entergy	subsidiary.	As	of	December	31,	2016,	derivative	contracts	with	three	counterparties	were in	a	liability	position	(approximately	$8	million	 total).	In	addition	to	the	corporate	guarantee,	$2	million	in	cash	collateral	was	required	to	be posted	by	the	Entergy	subsidiary	to	its	counterparties.	If	the	Entergy	Corporation	credit	rating	falls	below	investment	grade,	Entergy	would	have to	post	collateral	equal	to	the	estimated	outstanding	liability	under	the	contract	at	the	applicable	date.

Entergy	manages	fuel	price	volatility	for	its	Louisiana	jurisdictions	(Entergy	Louisiana	and	Entergy	New	Orleans)	and	Entergy	Mississippi through	the	purchase	of	short-term	natural	gas	swaps	that	financially	settle	against	NYMEX	futures.	These	swaps	are	marked-to-market	through fuel	expense	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	at	Entergy	Louisiana	and	Entergy	Mississippi	and projected	winter	purchases	for	gas	distribution	at	Entergy	Louisiana	and	Entergy	New	Orleans.	The	total	volume	of	natural	gas	swaps	outstanding as	of	December	31,	2017	is	38,540,750	MMBtu	for	Entergy,	including	31,361,500	MMBtu	for	Entergy	Louisiana,	6,714,250	MMBtu	for	Entergy Mississippi,	and	465,000	MMBtu	for	Entergy	New	Orleans.		Credit	support	for	these	natural	gas	swaps	is	covered	by	master	agreements	that	do not	require	collateral	based	on	mark-to-market	value,	but	do	carry	adequate	assurance	language	that	may	lead	to	requests	for	collateral.

During	the	second	quarter	2017,	Entergy	participated	in	the	annual	financial	transmission	rights	auction	process	for	the	MISO	planning year	of	June	1,	2017	through	May	31,	2018.	Financial	transmission	rights	are	derivative	instruments	which	represent	economic	hedges	of	future congestion	charges	that	will	be	incurred	in	serving	Entergy's	customer	load.	They	are	not	designated	as	hedging	instruments.	Entergy	initially records	financial	transmission	rights	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	financial	transmission	rights	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 financial	transmission	rights.	The	total	volume	of	financial	transmission	rights	outstanding	as	of	December	31,	2017	is	46,474	GWh	for	Entergy, including	10,479	GWh	for	Entergy	Arkansas,	20,590	GWh	for	Entergy	Louisiana,	6,391	GWh	for	Entergy	Mississippi,	2,366	GWh	for	Entergy New	 Orleans,	 and	6,322	GWh	for	Entergy	Texas.	Credit	support	for	financial	transmission	rights	held	by	the	Utility	operating	companies	is covered	by	cash	and/or	letters	of	credit	issued	by	each	Utility	operating	company	as	required	by	MISO.	Credit	support	for	financial	transmission rights	 held	 by	 Entergy	 Wholesale	 Commodities	 is	 covered	 by	 cash.	No	 cash	 or	 letters	 of	 credit	 were	 required	 to	 be	 posted	 for	 financial transmission	rights	exposure	for	Entergy	Wholesale	Commodities	as	of	December	31,	2017	and	December	31,	2016.	Letters	of	credit	posted	with MISO	covered	the	financial	transmission	rights	exposure	for	Entergy	Arkansas,	Entergy	Mississippi,	and	Entergy	Texas	as	of	December	31	2017 and	for	Entergy	Arkansas	and	Entergy	Mississippi	as	of	December	31,	2016.

The	fair	values	of	Entergy's	derivative	instruments	in	the	consolidated	balance	sheet	as	of	 December	31,	2017	are	shown	in	the	table below.	Certain	investments,	including	those	not	designated	as	hedging	instruments,	are	subject	to	master	netting	agreements	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\t(current | $25 | ($14) | $11 | Entergy\tWholesale |
|  | portion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tdeferred\tdebits\tand\tother | $6 | ($6) | $— | Entergy\tWholesale |
|  | assets\t(non-current\tportion) |  |  |  | Commodities |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tcurrent\tliabilities | $11 | ($10) | $1 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tnon-current\tliabilities | $16 | ($7) | $9 | Entergy\tWholesale |
|  | (non-current\tportion) |  |  |  | Commodities |
| Derivatives\tnot\tdesignated\tas\nhedging\tinstruments |  |  |  |  |  |
| Assets:\nElectricity\tswaps\tand\toptions | Prepayments\tand\tother\t(current | $18 | ($13) | $5 | Entergy\tWholesale |
|  | portion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tdeferred\tdebits\tand\tother | $5 | ($5) | $— | Entergy\tWholesale |
|  | assets\t(non-current\tportion) |  |  |  | Commodities |
| Natural\tgas\tswaps | Prepayments\tand\tother | $13 | $— | $13 | \t Utility |
| Financial\ttransmission\trights | Prepayments\tand\tother | $22 | ($1) | $21 | Utility\tand\tEntergy |
|  |  |  |  |  | Wholesale |
|  |  |  |  |  | Commodities |
| Liabilities:\nElectricity\tswaps\tand\toptions | Other\tcurrent\tliabilities | $18 | ($17) | $1 | Entergy\tWholesale |
|  | (current\tportion) |  |  |  | Commodities |
| Electricity\tswaps\tand\toptions | Other\tnon-current\tliabilities | $4 | ($4) | $— | Entergy\tWholesale |

(a) Represents	the	gross	amounts	of	recognized	assets/liabilities

(b) Represents	the	netting	of	fair	value	balances	with	the	same	counterparty

(c) Represents	the	net	amounts	of	assets/liabilities	presented	on	the	Entergy	Corporation	and	Subsidiaries'	Consolidated	Balance	Sheet

(d) Excludes	cash	collateral	in	the	amount	of	$1	million	posted	and	$4	million	held	as	of	December	31,	2017	and	$2	million	posted	as	of December	31,	2016.	Also	excludes	$34	million	in	letters	of	credit	held	as	of	December	31,	2017.

The	effects	of	Entergy's	derivative	instruments	designated	as	cash	flow	hedges	on	the	consolidated	income	statements	for	the	years	ended December	31,	2017,	2016,	and	2015	are	as	follows:

At	each	reporting	period,	Entergy	measures	 its	hedges	for	 ineffectiveness.	Any	ineffectiveness	is	recognized	in	earnings	during	the period.	The	 ineffective	 portion	 of	 cash	 flow	 hedges	 is	 recorded	 in	 competitive	 businesses	 operating	 revenues.	The	change	 in	fair	value	of Entergy's	cash	flow	hedges	due	to	ineffectiveness	was	($3)	million,	($356)	thousand,	and	$150	thousand	for	the	years	ended	December	31,	2017, 2016,	and	2015,	respectively.

Based	on	market	prices	as	of	December	31,	2017,	unrealized	gains	recorded	in	accumulated	other	comprehensive	income	on	cash	flow hedges	relating	to	power	sales	totaled	$55	million	of	net	unrealized	losses.		Approximately	($59)	million	is	expected	to	be	reclassified	from accumulated	other	comprehensive	income	to	operating	revenues	in	the	next	twelve	months.		The	actual	amount	reclassified	from	accumulated other	comprehensive	income,	however,	could	vary	due	to	future	changes	in	market	prices.

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	effects	of	Entergy's	derivative	instruments	not	designated	as	hedging	instruments	on	the	consolidated	income	statements	for	the	years ended	December	31,	2017,	2016,	and	2015	are	as	follows:

(a) 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.

(b) Due	to	regulatory	treatment,	the	changes	in	the	estimated	fair	value	of	financial	transmission	rights	for	the	Utility	operating	companies	are recorded	through	purchased	power	expense	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	financial	transmission	rights	for	the	Utility	operating companies	are	settled	are	recovered	or	refunded	through	fuel	cost	recovery	mechanisms.

(c) Amount	of	gain	(loss)	recognized	 in	accumulated	other	comprehensive	 income	from	electricity	swaps	and	options	de-designated	as hedged	items.

The	fair	values	of	the	Registrant	Subsidiaries'	derivative	instruments	not	designated	as	hedging	instruments	on	their	balance	sheets	as	of December	31,	2017	and	2016	are	as	follows:

(a) As	of	December	31,	2017,	letters	of	credit	posted	with	MISO	covered	financial	transmission	rights	exposure	of	 $0.2	million	for	Entergy Arkansas,	$0.1	million	for	Entergy	Mississippi,	and	$0.05	million	for	Entergy	Texas.	As	of	December	31,	2016,	letters	of	credit	posted with	MISO	covered	financial	transmission	rights	exposure	of	$0.3	million	for	Entergy	Arkansas	and	$0.1	million	for	Entergy	Mississippi.

The	effects	of	the	Registrant	Subsidiaries'	derivative	instruments	not	designated	as	hedging	instruments	on	their	income	statements	for	the years	ended	December	31,	2017,	2016,	and	2015	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:

Level	2	consists	primarily	of	individually-owned	debt	instruments.

•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	financial	transmission	rights	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	are	performed	by	the	Business	Unit	Risk Control	group	and	the	Accounting	Policy	and	Entergy	Wholesale	Commodities	Accounting	group.		The	primary	functions	of	the	Business	Unit Risk	Control	group	include:	gathering,	validating	and	reporting	market	data,	providing	market	risk	analyses	and	valuations	in	support	of	Entergy Wholesale	Commodities'	commercial	transactions,	developing	and	administering	protocols	for	the	management	of	market	risks,	and	implementing and	maintaining	controls	around	changes	to	market	data	in	the	energy	trading	and	risk	management	system.		The	Business	Unit	Risk	Control group	is	also	responsible	for	managing	the	energy	trading	and	risk	management	system,	forecasting	revenues,	forward	positions	and	analysis.		The Accounting	Policy	and	Entergy	Wholesale	Commodities	Accounting	group	performs	functions	related	to	market	and	counterparty	settlements, revenue	reporting	and	analysis	and	financial	accounting.	The	Business	Unit	Risk	Control	group	reports	to	the	Vice	President	and	Treasurer	while the	Accounting	Policy	and	Entergy	Wholesale	Commodities	Accounting	group	reports	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	U.S.	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,	the	Business	Unit	Risk	Control	group	calculates	the	mark-to-market	for	electricity	swaps	and	options.		The	Business	Unit Risk	Control	group	also	validates	forward	market	prices	by	comparing	them	to	other	sources	of	forward	market	prices	or	to	settlement	prices	of actual	market	transactions.		Significant	differences	are	analyzed	and	potentially	adjusted	based	on	these	other	sources	of	forward	market	prices	or settlement	prices	of	actual	market	transactions.		Implied	volatilities	used	to	value	options	are	also	validated	using	actual	counterparty	quotes	for Entergy	Wholesale	Commodities	transactions	when	available	and	compared	with	other	sources	of	market	implied	volatilities.		Moreover,	on	at least	a	monthly	basis,	the	Office	of	Corporate	Risk	Oversight	confirms	the	mark-to-market	calculations	and	prepares	price	scenarios	and	credit downgrade	scenario	analysis.	 	The	scenario	analysis	 is	communicated	 to	senior	management	within	Entergy	and	within	Entergy	Wholesale Commodities.		Finally,	for	all

proposed	derivative	transactions,	an	analysis	is	completed	to	assess	the	risk	of	adding	the	proposed	derivative	to	Entergy	Wholesale	Commodities' portfolio.		In	particular,	the	credit	and	liquidity	effects	are	calculated	for	this	analysis.		This	analysis	is	communicated	to	senior	management within	Entergy	and	Entergy	Wholesale	Commodities.

The	values	of	financial	transmission	rights	are	based	on	unobservable	inputs,	including	estimates	of	congestion	costs	in	MISO	between applicable	generation	and	load	pricing	nodes	based	on	the	50th	percentile	of	historical	prices.		They	are	classified	as	Level	3	assets	and	liabilities. The	valuations	of	these	assets	and	liabilities	are	performed	by	the	Business	Unit	Risk	Control	group.		The	values	are	calculated	internally	and verified	against	the	data	published	by	MISO.	Entergy's	Accounting	Policy	and	Entergy	Wholesale	Commodities	Accounting	group	reviews	these valuations	for	reasonableness,	with	the	assistance	of	others	within	the	organization	with	knowledge	of	the	various	inputs	and	assumptions	used	in the	valuation.	The	Business	Unit	Risk	Control	groups	report	to	the	Vice	President	and	Treasurer.		The	Accounting	Policy	and	Entergy	Wholesale Commodities	Accounting	group	reports	to	the	Chief	Accounting	Officer.

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,	2017	and	December	31,	2016.		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.

| 2017 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $725 | $— | $— | $725 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | 526 | — | — | 526 |
| Debt\tsecurities | 1,125 | 1,425 | — | 2,550 |
| Common\ttrusts\t(b) |  |  |  | 4,136 |
| Power\tcontracts | — | — | 5 | 5 |
| Securitization\trecovery\ttrust\taccount | 45 | — | — | 45 |
| Escrow\taccounts | 406 | — | — | 406 |
| Financial\ttransmission\trights | — | — | 21 | 21 |
|  | $2,827 | $1,425 | $26 | $8,414 |
| Liabilities: |  |  |  |  |
| Power\tcontracts | $— | $— | $70 | $70 |
| Gas\thedge\tcontracts | 6 | — | — | 6 |
|  | $6 | $— | $70 | $76 |

| 2016 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $1,058 | $— | $— | $1,058 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | 480 | — | — | 480 |
| Debt\tsecurities | 985 | 1,228 | — | 2,213 |
| Common\ttrusts\t(b) |  |  |  | 3,031 |
| Power\tcontracts | — | — | 16 | 16 |
| Securitization\trecovery\ttrust\taccount | 46 | — | — | 46 |
| Escrow\taccounts | 433 | — | — | 433 |
| Gas\thedge\tcontracts | 13 | — | — | 13 |
| Financial\ttransmission\trights | — | — | 21 | 21 |
|  | $3,015 | $1,228 | $37 | $7,311 |
| Liabilities: |  |  |  |  |
| Power\tcontracts | $— | $— | $11 | $11 |

(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	9	to	the	financial statements	for	additional	information	on	the	investment	portfolios.

(b) Common	trust	funds	are	not	publicly	quoted,	and	are	valued	by	the	fund	administrators	using	net	asset	value	as	a	practical	expedient. Accordingly,	these	funds	are	not	assigned	a	level	in	the	fair	value	table.	The	fund	administrator	of	these	investments	allows	daily	trading at	the	net	asset	value	and	trades	settle	at	a	later	date.

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,	2017,	2016,	and	2015:

|  |  | 2017 | 2016 | 2016 |  | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Power\nContracts | Financial\ntransmission\nrights | Power\nContracts | Financial\ntransmission\nrights | Power\nContracts | Financial\ntransmission\nrights |
|  |  |  | (In\tMillions) |  |  |  |
| Balance\tas\tof\tJanuary\t1, | $5 | $21 | $189 | $23 | $215 | $47 |
| Total\tgains\t(losses)\tfor\tthe\nperiod\t(a) |  |  |  |  |  |  |
| Included\tin\tearnings | (3) | 1 | (10) | — | (20) | (1) |
| Included\tin\tother\ncomprehensive\tincome | 44 | — | 135 | — | 254 | — |
| Included\tas\ta\tregulatory\nliability/asset | — | 76 | — | 68 | — | 63 |
| Issuances\tof\tfinancial\ntransmission\trights | — | 62 | — | 55 | — | 80 |
| Purchases | — | — | — | — | 15 | — |
| Settlements | (111) | (139) | (309) | (125) | (275) | (166) |
| Balance\tas\tof\tDecember |  |  |  |  |  |  |
| 31, | ($65) | $21 | $5 | $21 | $189 | $23 |

(a) Change	in	unrealized	gains	or	losses	for	the	period	included	in	earnings	for	derivatives	held	at	the	end	of	the	reporting	period	is	$0.9 million,	$0.2	million,	and	$3	million	for	the	years	ended	December	31,	2017,	2016,	and	2015,	respectively.

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,	2017:

| Fair	Value	as	of<br>December	31,	2017 | Significant	Unobservable<br>Inputs | Range	from<br>Average	% | Effect	on	Fair<br>Value |
| :--- | :--- | :--- | :--- |
| (In\tMillions) |  |  | (In\tMillions) |
| ($65) | \t Unit\tcontingent\tdiscount | +/-\t4%\t-\t4.75% | $6\t-\t$7 |

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:

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,	2017	and	December	31,	2016.		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.

| 2017 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | $11.7 | $— | $— | $11.7 |
| Debt\tsecurities | 115.8 | 232.4 | — | 348.2 |
| Common\ttrusts\t(b) |  |  |  | 585.0 |
| Securitization\trecovery\ttrust\taccount | 3.7 | — | — | 3.7 |
| Escrow\taccounts | 2.4 | — | — | 2.4 |
| Financial\ttransmission\trights | — | — | 3.0 | 3.0 |
|  | $133.6 | $232.4 | $3.0 | $954.0 |

| 2016 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | $3.6 | $— | $— | $3.6 |
| Debt\tsecurities | 112.5 | 196.8 | — | 309.3 |
| Common\ttrusts\t(b) |  |  |  | 521.8 |
| Securitization\trecovery\ttrust\taccount | 4.1 | — | — | 4.1 |
| Escrow\taccounts | 7.1 | — | — | 7.1 |
| Financial\ttransmission\trights | — | — | 5.4 | 5.4 |
|  | $127.3 | $196.8 | $5.4 | $851.3 |

| 2016 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $76.8 | $— | $— | $76.8 |
| Escrow\taccounts | 31.8 | — | — | 31.8 |
| Gas\thedge\tcontracts | 2.3 | — | — | 2.3 |
| Financial\ttransmission\trights | — | — | 3.2 | 3.2 |
|  | $110.9 | $— | $3.2 | $114.1 |

| 2017 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $115.5 | $— | $— | $115.5 |
| Securitization\trecovery\ttrust\taccount | 37.7 | — | — | 37.7 |
| Financial\ttransmission\trights | — | — | 3.4 | 3.4 |
|  | $153.2 | $— | $3.4 | $156.6 |

| 2016 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $5.0 | $— | $— | $5.0 |
| Securitization\trecovery\ttrust\taccount | 37.5 | — | — | 37.5 |
| Financial\ttransmission\trights | — | — | 3.1 | 3.1 |
|  | $42.5 | $— | $3.1 | $45.6 |

# System	Energy

| 2017 | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $287.1 | $— | $— | $287.1 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | 3.1 | — | — | 3.1 |
| Debt\tsecurities | 187.2 | 143.3 | — | 330.5 |
| Common\ttrusts\t(b) |  |  |  | 572.1 |
|  | $477.4 | $143.3 | $— | $1,192.8 |
| 2016 | Level\t1 | Level\t2 |  |  |

|  |  |  | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| Assets: |  |  |  |  |
| Temporary\tcash\tinvestments | $245.1 | $— | $— | $245.1 |
| Decommissioning\ttrust\tfunds\t(a): |  |  |  |  |
| Equity\tsecurities | 0.3 | — | — | 0.3 |
| Debt\tsecurities | 248.3 | 58.3 | — | 306.6 |
| Common\ttrusts\t(b) |  |  |  | 473.6 |
|  | $493.7 | $58.3 | $— | $1,025.6 |

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,	2017.

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Balance\tas\tof\tJanuary\t1, | $5.4 | $8.5 | $3.2 | $1.1 | $3.1 |
| Issuances\tof\tfinancial\ttransmission\trights | 8.9 | 31.0 | 9.6 | 5.0 | 7.1 |
| Gains\t(losses)\tincluded\tas\ta\tregulatory\nliability/asset | 30.4 | 16.5 | 8.2 | 5.2 | 15.5 |
| Settlements | (41.7) | (45.8) | (18.9) | (9.1) | (22.3) |
| Balance\tas\tof\tDecember\t31, | $3.0 | $10.2 | $2.1 | $2.2 | $3.4 |

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Balance\tas\tof\tJanuary\t1, | $7.9 | $8.5 | $2.4 | $1.5 | $2.2 |
| Issuances\tof\tfinancial\ttransmission\trights | 18.8 | 18.1 | 5.9 | 2.8 | 9.3 |
| Gains\tincluded\tas\ta\tregulatory\nliability/asset | 1.9 | 51.6 | 11.5 | 0.9 | 1.8 |
| Settlements | (23.2) | (69.7) | (16.6) | (4.1) | (10.2) |
| Balance\tas\tof\tDecember\t31, | $5.4 | $8.5 | $3.2 | $1.1 | $3.1 |

# NOTE	16.				DECOMMISSIONING	TRUST	FUNDS	(Entergy	Corporation,	Entergy	Arkansas,	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,	Indian	Point	2,	Indian	Point	3,	Vermont	Yankee,	and	Palisades.		The	funds	are	invested	primarily	in	equity	securities,	fixed-rate debt	securities,	and	cash	and	cash	equivalents.

For	the	Indian	Point	3	and	FitzPatrick	plants	purchased	in	2000	from	NYPA,	NYPA	retained	the	decommissioning	trust	funds	and	the decommissioning	 liabilities.	NYPA	and	Entergy	subsidiaries	executed	decommissioning	agreements,	which	specified	 their	decommissioning obligations.	At	the	time	of	the	acquisition	of	the	plants	Entergy	recorded	a	contract	asset	that	represented	an	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.

In	 August	 2016,	 Entergy	 entered	 into	 a	 trust	 transfer	 agreement	 with	 NYPA	 to	 transfer the decommissioning trust funds and decommissioning	liabilities	for	the	Indian	Point	3	and	FitzPatrick	plants	to	Entergy.	The	transaction

was	contingent	upon	receiving	approval	from	the	NRC,	which	was	received	in	January	2017.		As	a	result	of	the	agreement	with	NYPA,	in	the	third quarter	 2016,	 Entergy	 removed	 the	 contract	 asset	 from	 its	 balance	 sheet,	 and	 recorded	 receivables	 for	 the	 beneficial	 interests	 in	 the decommissioning	trust	funds	and	recorded	asset	retirement	obligations	for	the	decommissioning	liabilities.	At	December	31,	2016,	the	fair	values of	the	decommissioning	trust	funds	held	by	NYPA	were	$719	million	for	the	Indian	Point	3	plant	and	$785	million	for	the	FitzPatrick	plant.	The fair	values	were	based	on	the	trust	statements	received	from	NYPA	and	were	valued	by	the	fund	administrator	using	net	asset	value	as	a	practical expedient.	Accordingly,	these	funds	were	not	assigned	a	level	in	the	fair	value	hierarchy.	For	Indian	Point	3,	the	receivable	for	the	beneficial interest	in	the	decommissioning	trust	fund	was	recorded	in	other	deferred	debits	on	the	consolidated	balance	sheet	as	of	December	31,	2016.	For FitzPatrick,	the	receivable	for	the	beneficial	interest	in	the	decommissioning	trust	fund	was	classified	as	held	for	sale	within	other	deferred	debits on	the	consolidated	balance	sheet	as	of	December	31,	2016.	In	January	2017,	NYPA	transferred	to	Entergy	the	Indian	Point	3	decommissioning trust	funds	with	a	fair	value	of	$726	million	and	the	FitzPatrick	decommissioning	trust	fund	with	a	fair	value	of	 $793	million.	In	March	2017, Entergy	closed	on	the	sale	of	the	FitzPatrick	plant	to	Exelon.	As	part	of	the	transaction,	Entergy	transferred	the	FitzPatrick	decommissioning	trust fund	 to	 Exelon.	The	 FitzPatrick	 decommissioning	 trust	 fund	 had	 a	 disposition-date	 fair	 value	 of	$805	million.	 See	 Note	 9	 to	 the	 financial statements	 for	 further	 discussion	 of	 the	 decommissioning	 agreements	 with	 NYPA	 and	 see	 Note	 14	 to	 the	 financial	 statements	 for	 further discussion	of	the	sale	of	FitzPatrick.

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 30%	interest	in	River	Bend	formerly	owned	by	Cajun,	Entergy	Louisiana	records	an	offsetting	amount	in	other	deferred	credits	for	the	excess	trust earnings	not	currently	expected	to	be	needed	to	decommission	the	plant.		Decommissioning	trust	funds	for	Pilgrim,	Indian	Point	1,	Indian	Point	2, Indian	Point	3,	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,	2017	and	2016	are	summarized	as	follows:

|  |  | 2017 |  |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\tValue | Total\nUnrealized\nGains | Total\nUnrealized\nLosses | Fair\tValue | Total\nUnrealized\nGains | Total\nUnrealized\nLosses |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Equity\tSecurities | $4,662 | $2,131 | $1 | $3,511 | $1,673 | $1 |
| Debt\tSecurities | 2,550 | 44 | 16 | 2,213 | 34 | 27 |
| Total | $7,212 | $2,175 | $17 | $5,724 | $1,707 | $28 |

The	fair	values	of	the	decommissioning	trust	funds	related	to	the	Entergy	Wholesale	Commodities	nuclear	plants	as	of	December	31,	 2017 are	$491	million	for	Indian	Point	1,	$621	million	for	Indian	Point	2,	$798	million	for	Indian	Point	3,	$458	million	for	Palisades,	$1,068	million	for Pilgrim,	and	$613	million	for	Vermont	Yankee.	The	fair	values	of	the	decommissioning	trust	funds	related	to	the	Entergy	Wholesale	Commodities nuclear	plants	as	of	December	31,	2016	are	$443	million	for	Indian	Point	1,	$564	million	for	Indian	Point	2,	$412	million	for	Palisades,	$960 million	for	Pilgrim,	and	$584	million	for	Vermont	Yankee.	 The	fair	values	of	the	decommissioning	trust	funds	for	the	Registrant	Subsidiaries' nuclear	plants	are	detailed	below.

Deferred	taxes	on	unrealized	gains/(losses)	are	recorded	in	other	comprehensive	income	(loss)	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 $479	million	and	$399	million	as	of	December	31,	2017	and	2016,	respectively.		The	amortized	cost	of	debt	securities	was	 $2,539	million	as	of December	31,	2017	and	$2,212	million	as	of	December	31,	2016.		As	of	December	31,	2017,	the	debt	securities	have	an	average	coupon	rate	of approximately	3.24%,	 an	 average	 duration	 of	 approximately	6.33	 years,	 and	 an	 average	 maturity	 of	 approximately	9.99	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	equity	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,	2017	and	2016:

|  | Equity	Securities |  | Debt	Securities |  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  |  |  | (In\tMillions) |  |  |  |  |
| Less\tthan\t12\tmonths | $8 | $1 | $1,099 | $7 | $23 | $1 | $1,169 | $26 |
| More\tthan\t12\tmonths | — | — | 265 | 9 | 1 | — | 20 | 1 |
| Total | $8 | $1 | $1,364 | $16 | $24 | $1 | $1,189 | $27 |

The	fair	value	of	debt	securities,	summarized	by	contractual	maturities,	as	of	December	31,	2017	and	2016	are	as	follows:

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $74 | $125 |
| 1\tyear\t-\t5\tyears | 902 | 763 |
| 5\tyears\t-\t10\tyears | 812 | 719 |
| 10\tyears\t-\t15\tyears | 147 | 109 |
| 15\tyears\t-\t20\tyears | 100 | 73 |
| 20\tyears+ | 515 | 424 |
| Total | $2,550 | $2,213 |

During	the	years	ended	December	31,	2017,	2016,	and	2015,	proceeds	from	the	dispositions	of	securities	amounted	to	$3,163	million, $2,409	million,	and	$2,492	million,	respectively.		During	the	years	ended	December	31,	2017,	2016,	and	2015,	gross	gains	of	$149	million,	$32 million,	and	$72	million,	respectively,	and	gross	losses	of	 $13	million,	$13	million,	and	$13	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,	2017	and	2016	are	summarized	as	follows:

|  |  | 2017 |  |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Equity\tSecurities | $596.7 | $354.9 | $— | $525.4 | $281.5 | $— |
| Debt\tSecurities | 348.2 | 2.1 | 3.0 | 309.3 | 3.4 | 4.2 |
| Total | $944.9 | $357.0 | $3.0 | $834.7 | $284.9 | $4.2 |

The	 amortized	 cost	 of	 debt	 securities	 was	$349.1	million	 as	 of	December	 31,	 2017	 and	$310.1	 million	 as	 of	December	 31,	 2016.	 	As	 of December	31,	2017,	the	debt	securities	have	an	average	coupon	rate	of	approximately	2.64%,	an	average	duration	of	approximately	5.61	years, and	an	average	maturity	of	approximately	7.00	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	equity	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities |  | Equity	Securities |  | Debt	Securities |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  |  |  | (In\tMillions) |  |  |  |  |
| Less\tthan\t12\tmonths | $— | $— | $168.0 | $1.2 | $— | $— | $146.7 | $4.2 |
| More\tthan\t12\tmonths | — | — | 41.4 | 1.8 | — | — | — | — |
| Total | $— | $— | $209.4 | $3.0 | $— | $— | $146.7 | $4.2 |

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $13.0 | $16.7 |
| 1\tyear\t-\t5\tyears | 123.4 | 106.2 |
| 5\tyears\t-\t10\tyears | 180.6 | 161.2 |
| 10\tyears\t-\t15\tyears | 4.8 | 7.7 |
| 15\tyears\t-\t20\tyears | 3.4 | 1.0 |
| 20\tyears+ | 23.0 | 16.5 |
| Total | $348.2 | $309.3 |

During	the	years	ended	December	31,	2017,	2016,	and	2015,	proceeds	from	the	dispositions	of	securities	amounted	to	$339.4	million, $197.4	million,	and	$213	million,	respectively.		During	the	years	ended	December	31,

Entergy	Louisiana	holds	debt	and	equity	securities,	classified	as	available-for-sale,	in	nuclear	decommissioning	trust	accounts. 	The securities	held	as	of	December	31,	2017	and	2016	are	summarized	as	follows:

|  |  | 2017 |  |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Equity\tSecurities | $818.3 | $461.2 | $— | $715.9 | $346.6 | $— |
| Debt\tSecurities | 493.8 | 10.9 | 3.6 | 424.8 | 8.0 | 5.0 |
| Total | $1,312.1 | $472.1 | $3.6 | $1,140.7 | $354.6 | $5.0 |

The	 amortized	 cost	 of	 debt	 securities	 was	$490	 million	 as	 of	December	 31,	 2017	 and	$421.9	 million	 as	 of	December	 31,	 2016.	 	 As	 of December	31,	2017,	the	debt	securities	have	an	average	coupon	rate	of	approximately	3.88%,	an	average	duration	of	approximately	6.17	years, and	an	average	maturity	of	approximately	12.06	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	equity	securities	are	held	in	funds	intended	to	replicate	the	return of	the	Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities |  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  |  |  | (In\tMillions) |  |  |  |  |
| Less\tthan\t12\tmonths | $— | $— | $135.3 | $1.1 | $— | $— | $198.8 | $4.8 |
| More\tthan\t12\tmonths | — | — | 84.4 | 2.5 | — | — | 4.8 | 0.2 |
| Total | $— | $— | $219.7 | $3.6 | $— | $— | $203.6 | $5.0 |

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $23.2 | $31.4 |
| 1\tyear\t-\t5\tyears | 122.8 | 99.1 |
| 5\tyears\t-\t10\tyears | 109.3 | 122.8 |
| 10\tyears\t-\t15\tyears | 52.7 | 41.4 |
| 15\tyears\t-\t20\tyears | 50.7 | 30.9 |
| 20\tyears+ | 135.1 | 99.2 |
| Total | $493.8 | $424.8 |

System	Energy	holds	debt	and	equity	securities,	classified	as	available-for-sale,	in	nuclear	decommissioning	trust	accounts.		The	securities held	as	of	December	31,	2017	and	2016	are	summarized	as	follows:

|  |  | 2017 |  |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses | Fair\tValue | Total\tUnrealized\nGains | Total\tUnrealized\nLosses |
|  |  |  | (In\tMillions) | (In\tMillions) |  |  |
| Equity\tSecurities | $575.2 | $308.6 | $— | $473.9 | $221.9 | $0.1 |
| Debt\tSecurities | 330.5 | 4.2 | 1.2 | 306.6 | 2.0 | 4.5 |
| Total | $905.7 | $312.8 | $1.2 | $780.5 | $223.9 | $4.6 |

The	 amortized	 cost	 of	 debt	 securities	 was	$327.5	million	 as	 of	December	 31,	 2017	 and	$309.1	 million	 as	 of	December	 31,	 2016.	 	As	 of December	31,	2017,	the	debt	securities	have	an	average	coupon	rate	of	approximately	2.67%,	an	average	duration	of	approximately	6.48	years, and	an	average	maturity	of	approximately	9.22	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	equity	securities	are	held	in	funds	intended	to	replicate	the	return	of	the Wilshire	4500	Index.

|  | Equity	Securities |  | Debt	Securities |  | Equity	Securities |  | Debt	Securities | Debt	Securities |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses | Fair\nValue | Gross\nUnrealized\nLosses |
|  |  |  |  | (In\tMillions) |  |  |  |  |
| Less\tthan\t12\tmonths | $— | $— | $196.9 | $1.0 | $— | $— | $220.9 | $4.4 |
| More\tthan\t12\tmonths | — | — | 10.4 | 0.2 | — | 0.1 | 0.8 | 0.1 |
| Total | $— | $— | $207.3 | $1.2 | $— | $0.1 | $221.7 | $4.5 |

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) | (In\tMillions) |
| less\tthan\t1\tyear | $4.1 | $6.6 |
| 1\tyear\t-\t5\tyears | 173.0 | 188.2 |
| 5\tyears\t-\t10\tyears | 78.5 | 78.5 |
| 10\tyears\t-\t15\tyears | 1.0 | 1.3 |
| 15\tyears\t-\t20\tyears | 6.9 | 7.8 |
| 20\tyears+ | 67.0 | 24.2 |
| Total | $330.5 | $306.6 |

# Other-than-temporary	impairments	and	unrealized	gains	and	losses

Entergy	evaluates	investment	securities	in	the	Entergy	Wholesale	Commodities'	nuclear	decommissioning	trust	funds	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.		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,	2017,	2016,	and	2015.		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.		Entergy	did	not record	material	charges	to	other	income	in	2017,	2016,	or	2015	resulting	from	the	recognition	of	the	other-than-temporary	impairment	of	equity securities	held	in	its	decommissioning	trust	funds.

# NOTE	 17.	 	 VARIABLE	 INTEREST	 ENTITIES (Entergy	 Corporation,	 Entergy	Arkansas,	 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	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	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	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	New	Orleans	Storm	Recovery	Funding	I,	L.L.C.,	a	company	wholly-owned	and	consolidated	by	Entergy	New	Orleans,	is	a variable	interest	entity,	and	Entergy	New	Orleans	is	the	primary	beneficiary.	In	July	2015,

Entergy	New	Orleans	Storm	Recovery	Funding	issued	storm	cost	recovery	bonds	to	recover	Entergy	New	Orleans's	Hurricane	Isaac	storm restoration	 costs,	 including	 carrying	 costs,	 the	 costs	 of	 funding	 and	 replenishing	 the	 storm	 recovery	 reserve,	 and	 up-front	 financing	 costs associated	with	the	securitization.	With	the	proceeds,	Entergy	New	Orleans	Storm	Recovery	Funding	purchased	from	Entergy	New	Orleans	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	New	Orleans	balance	sheet.	The creditors	of	Entergy	New	Orleans	do	not	have	recourse	to	the	assets	or	revenues	of	Entergy	New	Orleans	Storm	Recovery	Funding,	including	the storm	recovery	property,	and	the	creditors	of	Entergy	New	Orleans	Storm	Recovery	Funding	do	not	have	recourse	to	the	assets	or	revenues	of Entergy	New	Orleans.	Entergy	New	Orleans	has	no	payment	obligations	to	Entergy	New	Orleans	Storm	Recovery	Funding	except	to	remit	storm recovery	charge	collections.	See	Note	5	to	the	financial	statements	for	additional	details	regarding	the	securitization	bonds.

Entergy	Louisiana	was	considered	to	hold	a	variable	interest	in	the	lessor	from	which	it	leased	an	undivided	interest	in	the	Waterford	3 nuclear	 plant.	After	Entergy	Louisiana	acquired	a	beneficial	interest	in	the	leased	assets	in	March	2016,	however,	the	lessor	was	no	longer considered	a	variable	interest	entity.	Entergy	Louisiana	made	payments	on	its	lease,	including	interest,	of	$9.2	million	through	March	2016	and $28.8	million	in	2015.		See	Note	10	to	the	financial	statements	for	a	discussion	of	Entergy	Louisiana's	purchase	of	the	Waterford	3	leased	assets.

System	Energy	is	considered	to	hold	a	variable	interest	in	the	lessor	from	which	it	leases	an	undivided	interest	in	the	Grand	Gulf	nuclear plant.		System	Energy	is	the	lessee	under	this	arrangement,	which	is	described	in	more	detail	in	Note	10	to	the	financial	statements.	System Energy	made	payments	on	its	lease,	including	interest,	of	$17.2	million	in	2017,	$17.2	million	in	2016,	and	$52.3	million	in	2015.		The	lessor	is	a bank	acting	in	the	capacity	of	owner	trustee	for	the	benefit	of	equity	investors	in	the	transaction	pursuant	to	trust	agreement	entered	solely	for	the purpose	of	facilitating	the	lease	transaction.		It	is	possible	that	System	Energy	may	be	considered	as	the	primary	beneficiary	of	the	lessor,	but Entergy	is	unable	to	apply	the	authoritative	accounting	guidance	with	respect	to	this	VIE	because	the	lessor	is	not	required	to,	and	could	not, provide	 the	 necessary	 financial	 information	 to	 consolidate	 the	 lessor.	 	 Because	 Entergy	 accounts	 for	 this	 leasing	 arrangement	 as	 a	 capital financing,	however,	Entergy	believes	that	consolidating	the	lessor	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	sheet	materially	represent	the	company's	potential	exposure	to	loss.

Entergy	has	also	reviewed	various	lease	arrangements,	power	purchase	agreements,	including	agreements	for	renewable	power,	and	other agreements	that	represent	variable	interests	in	other	legal	entities	which	have	been	determined	to	be	variable	interest	entities.		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	18.			TRANSACTIONS	WITH	AFFILIATES	(Entergy	Arkansas,	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	the	FERC.		The	Registrant	Subsidiaries	receive	management,	technical,	advisory,	operating,	and	administrative	services	from	Entergy Services;	and	receive	management,	technical,	and	operating	services	from	Entergy	Operations.		These	transactions	are	on	an	"at	cost"	basis.

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.		As	described	in	Note	2	to	the	financial	statements,	Entergy	Louisiana	receives	preferred	membership	interest distributions	from	Entergy	Holdings	Company.

The	tables	below	contain	the	various	affiliate	transactions	of	the	Utility	operating	companies,	System	Energy,	and	other	Entergy	affiliates.

# Intercompany	Interest	and	Investment	Income

|  | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy<br>New<br>Orleans | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |  |
| 2017 | $128.0 | $— | $0.2 | $0.9 |
| 2016 | $127.7 | $0.1 | $— | $0.1 |
| 2015 | $133.6 | $— | $— | $— |

# Transactions	with	Equity	Method	Investees

EWO	Marketing,	LLC,	an	indirect	wholly-owned	subsidiary	of	Entergy,	paid	capacity	charges	and	gas	transportation	to	RS	Cogen	in	the amounts	of	$24.6	million	in	2017,	$24.7	million	in	2016,	and	$24.5	million	in	2015.

Entergy's	operating	transactions	with	its	other	equity	method	investees	were	not	significant	in	 2017,	2016,	or	2015.

# NOTE	19.		QUARTERLY	FINANCIAL	DATA	(UNAUDITED)	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Operating	results	for	the	four	quarters	of	2017	and	2016	for	Entergy	Corporation	and	subsidiaries	were:

| First	Quarter | $2,588,458 | $174,803 | $86,051 | $82,605 |
| :--- | :--- | :--- | :--- | :--- |
| Second\tQuarter | $2,618,550 | $143,509 | $413,368 | $409,922 |
| Third\tQuarter | $3,243,628 | $729,469 | $401,644 | $398,198 |
| Fourth\tQuarter | $2,623,845 | $211,901 | ($475,710) | ($479,113) |
| 2016: |  |  |  |  |
| First\tQuarter | $2,609,852 | $498,218 | $235,242 | $229,966 |
| Second\tQuarter | $2,462,562 | $442,258 | $572,590 | $567,314 |
| Third\tQuarter | $3,124,703 | $772,060 | $393,204 | $388,170 |
| Fourth\tQuarter | $2,648,528 | ($2,599,001) | ($1,765,539) | ($1,769,068) |

# Earnings	(loss)	per	average	common	share

|  | 2017 |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Basic | Diluted | Basic | Diluted |
| First\tQuarter | $0.46 | $0.46 | $1.29 | $1.28 |
| Second\tQuarter | $2.28 | $2.27 | $3.17 | $3.16 |
| Third\tQuarter | $2.22 | $2.21 | $2.17 | $2.16 |
| Fourth\tQuarter | ($2.67) | ($2.66) | ($9.89) | ($9.86) |

Results	of	operations	for	2017	include:	1)	$538	million	($350	million	net-of-tax)	of	impairment	charges	due	to	costs	being	charged	to expense	 as	 incurred	 as	 a	 result	 of	 the	 impaired	 value	 of	 the	 Entergy	Wholesale	 Commodities	 nuclear	 plants'	 long-lived	 assets	 due	 to	 the significantly	reduced	remaining	estimated	operating	lives	associated	with	management's	strategy	to	reduce	the	size	of	the	Entergy	Wholesale Commodities'	merchant	fleet;	2)	a	reduction	in	income	of	$181	million,	including	a	$34	million	net-of-tax	reduction	of	regulatory	liabilities,	at Utility	and	$397	million	at	Entergy	Wholesale	Commodities	and	an	increase	in	income	of	$52	million	at	Parent	and	Other	as	a	result	of	Entergy's re-measurement	of	its	deferred	tax	assets	and	liabilities	not	subject	to	the	ratemaking	process	due	to	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in December	2017,	which	 lowered	 the	federal	corporate	 income	 tax	rate	from	35%	 to	21%;	and	3)	a	reduction	in	income	tax	expense,	net	of unrecognized	 tax	 benefits,	 of	$373	 million	 as	 a	 result	 of	 a	 change	 in	 the	 tax	 classification	 of	 legal	 entities	 that	 own	 Entergy	 Wholesale Commodities	nuclear	power	plants.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges.	See	Note 3	to	the	financial	statements	for	further	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act	and	the	change	in	the	tax	classification.

Results	of	operations	for	2016	include:	1)	$2,836	million	($1,829	million	net-of-tax)	of	impairment	and	related	charges	primarily	to	write down	the	carrying	values	of	the	Entergy	Wholesale	Commodities'	Palisades,	Indian	Point	2,	and	Indian	Point	3	plants	and	related	assets	to	their fair	values;	2)	a	reduction	of	income	tax	expense,	net	of	unrecognized	tax	benefits,	of	$238	million	as	a	result	of	a	change	in	the	tax	classification of	a	legal	entity	that	owned	one	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants;	income	tax	benefits	as	a	result	of	the	settlement	of the	2010-2011	IRS	audit,	including	a	$75	million	tax	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment

of	the	Vidalia	purchased	power	agreement	and	a	$54	million	net	benefit	recognized	by	Entergy	Louisiana	related	to	the	treatment	of	proceeds received	in	2010	for	the	financing	of	Hurricane	Gustav	and	Hurricane	Ike	storm	costs	pursuant	to	Louisiana	Act	55;	and	3)	a	reduction	in	expenses of	$100	million	($64	million	net-of-tax)	due	to	the	effects	of	recording	in	2016	the	final	court	decisions	in	several	lawsuits	against	the	DOE related	to	spent	nuclear	fuel	storage	costs.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	impairment	and	related	charges,	see Note	3	to	the	financial	statements	for	additional	discussion	of	the	income	tax	items,	and	see	Note	8	to	the	financial	statements	for	discussion	of	the spent	nuclear	fuel	litigation.

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	2017	and	2016	were:

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2017: |  |  |  |  |  |  |
| First\tQuarter | $474,351 | $880,783 | $258,443 | $168,989 | $363,927 | $154,787 |
| Second\tQuarter | $496,662 | $1,083,434 | $291,212 | $176,222 | $378,488 | $164,956 |
| Third\tQuarter | $673,226 | $1,290,494 | $349,197 | $199,017 | $432,909 | $156,106 |
| Fourth\tQuarter | $495,680 | $1,045,839 | $299,377 | $171,842 | $369,569 | $157,609 |
| 2016: |  |  |  |  |  |  |
| First\tQuarter | $465,373 | $955,145 | $263,046 | $149,340 | $378,304 | $137,693 |
| Second\tQuarter | $504,252 | $999,034 | $248,138 | $164,920 | $412,922 | $151,323 |
| Third\tQuarter | $654,599 | $1,249,452 | $309,739 | $201,336 | $442,085 | $114,039 |
| Fourth\tQuarter | $462,384 | $973,417 | $273,726 | $149,867 | $382,308 | $145,236 |

# Operating	Income

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2017: |  |  |  |  |  |  |
| First\tQuarter | $39,847 | $152,648 | $39,608 | $21,762 | $38,842 | $41,544 |
| Second\tQuarter | $68,994 | $193,779 | $55,262 | $27,606 | $47,787 | $40,717 |
| Third\tQuarter | $169,755 | $290,089 | $84,035 | $33,415 | $78,950 | $37,459 |
| Fourth\tQuarter | $14,507 | $210,325 | $42,169 | $12,333 | $33,800 | $41,073 |
| 2016: |  |  |  |  |  |  |
| First\tQuarter | $54,378 | $181,618 | $41,573 | $21,880 | $41,269 | $47,466 |
| Second\tQuarter | $73,447 | $193,752 | $61,890 | $26,913 | $58,039 | $45,020 |
| Third\tQuarter | $188,660 | $312,951 | $88,312 | $42,279 | $107,964 | $43,886 |
| Fourth\tQuarter | $29,843 | $111,066 | $32,464 | $8,807 | $38,338 | $44,781 |

# Net	Income	(Loss)

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy	Texas | System<br>Energy |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) | (In\tThousands) |  |  |
| 2017: |  |  |  |  |  |  |
| First\tQuarter | $14,304 | $94,378 | $17,158 | $10,978 | $10,854 | $20,347 |
| Second\tQuarter | $38,550 | $124,479 | $28,303 | $14,882 | $21,101 | $19,350 |
| Third\tQuarter | $92,638 | $186,284 | $46,545 | $18,529 | $39,588 | $20,583 |
| Fourth\tQuarter | ($5,648) | ($88,794) | $18,026 | $164 | $4,630 | $18,316 |
| 2016: |  |  |  |  |  |  |
| First\tQuarter | $19,294 | $111,606 | $17,118 | $11,167 | $14,562 | $25,958 |
| Second\tQuarter | $33,891 | $253,325 | $32,194 | $11,843 | $24,058 | $25,090 |
| Third\tQuarter | $110,148 | $189,506 | $46,612 | $23,701 | $56,133 | $22,370 |
| Fourth\tQuarter | $3,879 | $67,610 | $13,260 | $2,138 | $12,785 | $23,326 |

# Earnings	(Loss)	Applicable	to	Common	Equity

|  | Entergy<br>Arkansas | Entergy<br>Mississippi | Entergy	New<br>Orleans |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| 2017: |  |  |  |
| First\tQuarter | $13,947 | $16,920 | $10,737 |
| Second\tQuarter | $38,193 | $28,064 | $14,641 |
| Third\tQuarter | $92,281 | $46,307 | $18,288 |
| Fourth\tQuarter | ($6,005) | $17,788 | $46 |
| 2016: |  |  |  |
| First\tQuarter | $17,576 | $16,411 | $10,926 |
| Second\tQuarter | $32,173 | $31,487 | $11,602 |
| Third\tQuarter | $108,672 | $45,905 | $23,460 |
| Fourth\tQuarter | $3,521 | $12,938 | $1,896 |

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	distribution	operations.		Entergy	owns and	operates	power	plants	with	approximately	30,000	MW	of	electric	generating	capacity,	including	nearly	9,000	MW	of	nuclear	power.	Entergy delivers	electricity	to	2.9	million	utility	customers	in	Arkansas,	Louisiana,	Mississippi,	and	Texas.		Entergy	had	annual	revenues	of	$11.1	billion in	2017	and	had	more	than	13,000	employees	as	of	December	31,	2017.

•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	operation	of	a	small	natural	gas	distribution	business. •The	Entergy	Wholesale	Commodities	business	segment	includes	the	ownership,	operation,	and	decommissioning	of	nuclear	power plants	located	in	the	northern	United	States	and	the	sale	of	the	electric	power	produced	by	its	operating	plants	to	wholesale	customers. Entergy	Wholesale	Commodities	also	provides	services	to	other	nuclear	power	plant	owners	and	owns	interests	in	non-nuclear	power plants	 that	 sell	 the	 electric	 power	 produced	 by	 those	 plants	 to	 wholesale	 customers.	See "MANAGEMENT'S FINANCIAL DISCUSSION	AND	ANALYSIS	-	 Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power	Business "	for	discussion	of	the operation	and	planned	shutdown	or	sale	of	each	of	the	Entergy	Wholesale	Commodities	nuclear	power	plants.

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	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.	 	To accomplish	this,	Entergy	has	established	strategic	imperatives	for	each	business	segment.		For	the	Utility,	the	strategic	imperative	is	to	modernize its	operations,	maintain	reliability,	and	better	serve	its	customers	while	growing	the	business.	For	Entergy	Wholesale	Commodities,	the	strategic imperative	is	to	continue	to	manage	the	risk	of	its	operating	portfolio	as	Entergy	completes	its	exit	from	the	merchant	power	business.

The	Utility	business	segment	includes	five	wholly-owned	retail	electric	utility	subsidiaries:	Entergy	Arkansas,	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	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	five	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,	2017,	the	Utility	operating	companies	provided	retail	electric	and	gas	service	to	customers	in	Arkansas,	Louisiana, Mississippi,	and	Texas,	as	follows:

# 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	July	20,	2017,	Entergy	reached	a	2017	peak	demand	of	21,671	MWh,	compared	to	the	2016 peak	of	21,387	MWh	recorded	on	July	21,	2016.		Selected	electric	energy	sales	data	is	shown	in	the	table	below:

# Selected	2017	Electric	Energy	Sales	Data

|  | Entergy<br>Arkansas | Entergy<br>Louisiana | Entergy<br>Mississippi | Entergy	New<br>Orleans | Entergy<br>Texas | System<br>Energy | Entergy	(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tGWh) |  |  |  |
| Sales\tto\tretail\tcustomers | 20,888 | 55,243 | 13,048 | 5,622 | 18,058 | — | 112,859 |
| Sales\tfor\tresale: |  |  |  |  |  |  |  |
| Affiliates | 1,782 | 4,793 | — | — | 1,534 | 6,675 | — |
| Others | 6,549 | 1,711 | 857 | 1,703 | 729 | — | 11,550 |
| Total | 29,219 | 61,747 | 13,905 | 7,325 | 20,321 | 6,675 | 124,409 |
| Average\tuse\tper\tresidential\tcustomer\t(kWh) | 12,349 | 14,377 | 14,142 | 11,986 | 14,597 | — | 13,716 |

(a) Includes	the	effect	of	intercompany	eliminations.

The	following	table	illustrates	the	Utility	operating	companies'	2017	combined	electric	sales	volume	as	a	percentage	of	total	electric	sales volume,	and	2017	combined	electric	revenues	as	a	percentage	of	total	2017	electric	revenue,	each	by	customer	class.

| Customer	Class | %	of	Sales	Volume | %	of	Revenue |
| :--- | :--- | :--- |
| Residential | 27.2 | 36.2 |
| Commercial | 23.1 | 26.7 |
| Industrial\t(a) | 38.4 | 27.8 |
| Governmental | 2.0 | 2.5 |
| Wholesale/Other | 9.3 | 6.8 |

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

See	"Selected	Financial	Data"	for	each	of	the	Utility	operating	companies	for	the	detail	of	their	sales	by	customer	class	for	2013-2017.

# Selected	2017	Natural	Gas	Sales	Data

Entergy	New	Orleans	and	Entergy	Louisiana	provide	both	electric	power	and	natural	gas	to	retail	customers.		Entergy	New	Orleans	and Entergy	 Louisiana	 sold	 9,745,874	 and	 6,017,174	 Mcf,	 respectively,	 of	 natural	 gas	 to	 retail	 customers	 in	 2017.	 	 In	 2017,	 99%	 of	 Entergy Louisiana's	operating	revenue	was	derived	from	the	electric	utility	business,	and	only	1%	from	the	natural	gas	distribution	business.		For	Entergy New	Orleans,	88%	of	operating	revenue	was	derived	from	the	electric	utility	business	and	12%	from	the	natural	gas	distribution	business	in 2017.

Following	is	data	concerning	Entergy	New	Orleans's	2017	retail	operating	revenue	sources.

| Customer	Class | Electric	Operating	Revenue | Natural	Gas	Operating<br>Revenue |
| :--- | :--- | :--- |
| Residential | 42% | 46% |
| Commercial | 39% | 28% |
| Industrial | 6% | 7% |
| Governmental/Municipal | 13% | 19% |

# Retail	Rate	Regulation

General	(Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	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.

|  | Rate	base	(in<br>billions) | Current<br>authorized<br>return	on<br>common	equity | Weighted<br>average	cost<br>of	capital<br>(after-tax) | Equity<br>ratio | Regulatory	construct |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  | -\tforward\ttest\tyear\tformula\trate\tplan |
|  |  |  |  |  | -\triders:\tMISO,\tcapacity,\tGrand |
|  |  |  |  |  | Gulf,\tenergy\tefficiency,\tfuel\tand |
| Entergy\tArkansas | $7.095\t(a) | 9.25%\t-10.25% | 4.67% | 31.69% | purchased\tpower |
|  |  |  |  |  | -\tformula\trate\tplan\tthrough\t2016\ttest |
|  |  |  |  |  | year |
| Entergy\tLouisiana |  |  |  |  | -\triders/specific\trecovery:\tMISO, |
| (electric) | $8.303\t(b) | 9.15%\t-\t10.75% | 7.35% | 49.64% | capacity,\tfuel |
|  |  |  |  |  | -\tgas\trate\tstabilization\tplan |
| Entergy\tLouisiana\n(gas) | $0.059\t(c) | 9.45%\t-\t10.45% | 7.54% | 51.63% | -\trider:\tgas\tinfrastructure |
|  |  |  |  |  | -\tformula\trate\tplan\twith |
|  |  |  |  |  | forward-looking\tfeatures |
|  |  |  |  |  | -\triders:\tpower\tmanagement,\tGrand |
|  |  |  |  |  | Gulf,\tfuel,\tMISO,\tunit\tpower\tcost, |
| Entergy |  |  |  |  | storm\tdamage,\tenergy\tefficiency,\tad |
| Mississippi | $2.131\t(d) | 9.47%\t-\t11.49% | 7.35% | 49.37% | valorem\ttax\tadjustment |
|  |  |  |  |  | -\trate\tcase |
| Entergy\tNew |  |  |  |  | -\triders/specific\trecovery:\tfuel, |
| Orleans\t(electric) | $0.299\t(e) | 10.7%\t-\t11.5% | 8.58% | 50.08% | \t\t\tcapacity |
|  |  |  |  |  | -\trate\tcase |
| Entergy\tNew\nOrleans\t(gas) | $0.089\t(f) | 10.25%\t-\t11.25% | 8.40% | 50.08% | -\trider:\tpurchased\tgas |
|  |  |  |  |  | -\trate\tcase |
|  |  |  |  |  | -\triders:\tfuel,\tdistribution\tand |
|  |  |  |  |  | \t\t\ttransmission,\tRPCE\tpayments |
|  |  |  |  |  | \t\t\tand\trate\tcase\texpenses,\tamong |
| Entergy\tTexas | $1.634\t(g) | 9.8% | 8.22% | 48.6% | \t\t\tothers |
| System\tEnergy | $1.201\t(h) | 10.94% | 8.90% | 65% | -\tmonthly\tcost\tof\tservice |

(e) Based	on	December	31,	2011	test	year	and	excludes	approximately	$228	million	first-year	average	rate	base	for	Union.

(g) Based	 on	 March	 31,	 2013	 adjusted	 test	 year	 and	 excludes	 approximately	 $331	 million for rate	 base	 being recovered through the distribution	cost	recovery	rider	and	the	transmission	cost	recovery	rider

Entergy	Arkansas's	rate	schedules	include	an	energy	cost	recovery	rider	to	recover	fuel	and	purchased	power	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.

# Fuel	Recovery

Entergy	Louisiana's	rate	schedules	include	a	fuel	adjustment	clause	designed	to	recover	the	cost	of	fuel	and	purchased	power	costs.		The fuel	 adjustment	 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.	In January	2018,	Entergy	Louisiana	filed	an	application	with	the	LPSC	to	suspend	these	seasonal	hedging	programs	and	implement	financial	hedges with	terms	up	to	five	years	for	a	portion	of	its	natural	gas	exposure.	A	decision	is	expected	in	2018.

Entergy	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	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	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.

# Storm	Cost	Recovery

See	Note	2	to	the	financial	statements	for	a	discussion	of	Entergy	Louisiana's	filings	to	recover	storm-related	costs.

# Other

In	March	2016	the	LPSC	opened	two	dockets	to	examine,	on	a	generic	basis,	issues	that	it	identified	in	connection	with	its	review	of Cleco	Corporation's	acquisition	by	third	party	investors.		The	first	docket	is	captioned	"In	re:	Investigation	of	double	leveraging	issues	for	all LPSC-jurisdictional	utilities,"	and	the	second	is	captioned	"In	re:	Investigation	of	tax	structure	issues	for	all	LPSC-jurisdictional	utilities."		In April	2016	the	LPSC	clarified	that	the	concerns	giving	rise	to	the	two	dockets	arose	as	a	result	of	its	review	of	the	structure	of	the	recently- approved	Cleco-Macquarie	transaction	and	that	the	specific	intent	of	the	directives	is	to	seek	more	information	regarding	intra-corporate	debt financing	of	a	utility's	capital	structure	as	well	as	 the	use	of	 investment	 tax	credits	 to	mitigate	 the	 tax	obligation	at	 the	parent	 level	of	a consolidated	entity.		No	schedule	has	been	set	for	either	docket,	and	limited	discovery	has	occurred.

Entergy	Mississippi's	rate	schedules	include	energy	cost	recovery	riders	to	recover	fuel	and	purchased	power	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.

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.

See	Note	2	to	the	financial	statements	for	a	discussion	of	proceedings	regarding	recovery	of	Entergy	Mississippi's	storm-related	costs.

# Formula	Rate	Plan

In	August	2012	the	MPSC	opened	inquiries	to	review	whether	the	current	formulaic	methodology	used	to	calculate	the	return	on	common equity	in	both	Entergy	Mississippi's	formula	rate	plan	and	Mississippi	Power	Company's	annual	formula	rate	plan	was	still	appropriate	or	could be	improved	to	better	serve	the	public	interest.	The	intent	of	this	inquiry	and	review	was	for	informational	purposes	only;	the	evaluation	of	any recommendations	for	changes	to	the	existing	methodology	would	take	place	in	a	general	rate	case	or	in	the	existing	formula	rate	plan	docket.	In March	2013	the	Mississippi	Public	Utilities	Staff	filed	its	consultant's	report	which	noted	the	return	on	common	equity	estimation	methods	used by	Entergy	Mississippi	and	Mississippi	Power	Company	are	commonly	used	throughout	the	electric	utility	industry.	The	report	suggested	ways	in which	the	methods	used	by	Entergy	Mississippi	and	Mississippi	Power	Company	might	be	improved,	but	did	not	recommend	specific	changes	in the	return	on	common	equity	formulas

or	calculations	at	that	time.	In	June	2014	the	MPSC	expanded	the	scope	of	the	August	2012	inquiry	to	study	the	merits	of	adopting	a	uniform formula	rate	plan	that	could	be	applied,	where	possible	in	whole	or	in	part,	to	both	Entergy	Mississippi	and	Mississippi	Power	Company	in	order	to achieve	greater	consistency	in	the	plans.	The	MPSC	directed	the	Mississippi	Public	Utilities	Staff	to	investigate	and	review	Entergy	Mississippi's formula	rate	plan	rider	schedule	and	Mississippi	Power	Company's	Performance	Evaluation	Plan	by	considering	the	merits	and	deficiencies	and possibilities	for	improvement	of	each	and	then	to	propose	a	uniform	formula	rate	plan	that,	where	possible,	could	be	applicable	to	both	companies. No	procedural	schedule	has	been	set.	In	October	2014	the	Mississippi	Public	Utilities	Staff	conducted	a	public	technical	conference	to	discuss performance	benchmarking	and	its	potential	application	to	the	electric	utilities'	formula	rate	plans.	The	docket	remains	open.

To	help	stabilize	gas	costs,	Entergy	New	Orleans	seeks	approval	annually	from	the	City	Council	to	continue	implementation	of	its	natural gas	hedging	program	consistent	with	the	City	Council's	stated	policy	objectives.		The	program	uses	financial	instruments	to	hedge	exposure	to volatility	in	the	wholesale	price	of	natural	gas	purchased	to	serve	Entergy	New	Orleans	gas	customers.		Entergy	New	Orleans	hedges	up	to	25%	of actual	gas	sales	made	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	proceedings	are	discussed	in	Note	2	to	the	financial	statements.

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,	but	will	continue	to	evaluate	the	benefits of	utilizing	the	new	rider	to	recover	future	capacity	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.

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	Court,	which	found	in	favor	of	the	PUCT	in	an	order	issued	in	October	2014.	In November	2014,	Entergy	Texas	appealed	the	District	Court's	order	which	moves	the	appeal	to	the	Third	Court	of	Appeals.	Entergy

Texas	and	opposing	parties	filed	briefs	and	responses	in	the	first	quarter	2015.	Oral	argument	was	held	in	May	2015.	In	March	2016	the	Court	of Appeals	upheld	the	District	Court's	ruling	favoring	the	PUCT.	In	May	2016,	Entergy	Texas	filed	with	the	Texas	Supreme	Court	a	petition	for review	of	the	Court	of	Appeals	ruling.	In	January	2017,	Entergy	Texas	filed	its	petitioner's	brief	on	the	merits	with	the	Texas	Supreme	Court.	 In June	2017	the	Texas	Supreme	Court	denied	Entergy	Texas's	petition	in	this	matter.

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.

# Franchises

Entergy	 Arkansas	 holds	 exclusive	 franchises	 to	 provide	 electric	 service	 in	 approximately 308 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	Louisiana	holds	non-exclusive	franchises	to	provide	electric	service	in	approximately	175	incorporated	municipalities	and	in	the unincorporated	areas	of	approximately	59	parishes	of	Louisiana.		Entergy	Louisiana	holds	non-exclusive	franchises	to	provide	natural	gas	service to	customers	in	the	City	of	Baton	Rouge	and	in	East	Baton	Rouge	Parish.		Municipal	franchise	agreement	terms	range	from	25	to	60	years	while parish	franchise	terms	range	from	25	to	99	years.

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.		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	typically	obtains	25-year	franchise	agreements	as	existing	agreements	expire.		Entergy	Texas's	electric	franchises expire	during	2018-2058.

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

# Property	and	Other	Generation	Resources

# Owned	Generating	Stations

The	 total	 capability	 of	 the	 generating stations	 owned and leased	 by the	 Utility	 operating companies and	 System	 Energy as	 of December	31,	2017,	is	indicated	below:

# Owned	and	Leased	Capability	MW(a)

|  |  |  | Owned	and	Leased	Capability	MW(a) | Owned	and	Leased	Capability	MW(a) |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Company | Total | Gas/Oil | Nuclear | Coal | Hydro | Solar |
| Entergy\tArkansas | 5,217 | 2,136 | 1,821 | 1,189 | 71 | — |
| Entergy\tLouisiana | 9,099 | 6,603 | 2,136 | 360 | — | — |
| Entergy\tMississippi | 3,359 | 2,944 | — | 414 | — | 1 |
| Entergy\tNew\tOrleans | 492 | 491 | — | — | — | 1 |
| Entergy\tTexas | 2,331 | 2,065 | — | 266 | — | — |
| System\tEnergy | 1,271 | — | 1,271 | — | — | — |
| Total | 21,769 | 14,239 | 5,228 | 2,229 | 71 | 2 |

(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.

Summer	peak	load	for	the	Utility	has	averaged	21,533	MW	over	the	previous	decade.

The	Utility	operating	companies'	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,	the	economy,	environmental	regulations,	public	policy	goals,	and	the	age	and	condition	of	Entergy's	existing	infrastructure.

The	Utility	operating	companies'	long-term	resource	strategy	(Portfolio	Transformation	Strategy)	calls	for	the	bulk	of	capacity	needs	to	be met	through	long-term	resources,	whether	owned	or	contracted.		Over	the	past	decade,	the	Portfolio	Transformation	Strategy	has	resulted	in	the addition	 of	 about	 6,800	 MW	 of	 new	 long-term	 resources	 and	 the	 deactivation	 of	 over	 5,200	 MW	 of	 legacy	 generation.	As	 MISO	 market participants,	the	Utility	operating	companies	also	participate	in	MISO's	Day	Ahead	and	Real	Time	Energy	and	Ancillary	Services	markets	to economically	dispatch	generation	and	purchase	energy	to	serve	customers	reliably	and	at	the	lowest	reasonable	cost.

# Other	Generation	Resources

# RFP	Procurements

The	Utility	operating	companies	from	time	to	time	issue	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	RFPs	issued	by	the	Utility	operating	companies have	sought	resources	needed	to	meet	near-term	MISO	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.		The	RFP	process	has resulted	in	selections	or	acquisitions,	including,	among	other	things:

•Entergy	Louisiana's	June	2005	purchase	of	the	718	MW,	gas-fired	Perryville	plant,	of	which	35%	of	the	output	is	sold	to	Entergy	Texas; •Entergy	 Arkansas's	 September	 2008	 purchase	 of	 the	 789	 MW,	 combined-cycle,	 gas-fired	 Ouachita	 Generating	 Facility.	 Entergy Louisiana,	as	successor	in	interest	to	Entergy	Gulf	States	Louisiana,	owns	one-third	of	the	facility;

•Entergy	Arkansas's	November	2012	purchase	of	the	620	MW,	combined-cycle,	gas-fired	Hot	Spring	Energy	facility;

•Entergy	Mississippi's	November	2012	purchase	of	the	450	MW,	combined-cycle,	gas-fired	Hinds	Energy	facility;

•Entergy	Louisiana's	construction	of	the	560	MW,	combined-cycle,	gas	turbine	Ninemile	6	generating	facility	at	its	existing	Ninemile Point	electric	generating	station.	The	facility	reached	commercial	operation	in	December	2014;

•Entergy	Louisiana's	construction	of	the	980	MW,	combined-cycle,	gas	turbine	St.	Charles	generating	facility	at	its	existing	Little	Gypsy electric	generating	station.	Entergy	Louisiana	received	regulatory	approval	from	the	LPSC	in	December	2016	and	the	facility	is	scheduled to	be	in	service	by	mid-2019;

•Entergy	Texas's	construction	of	the	993	MW,	combined-cycle,	gas	turbine	Montgomery	County	generating	facility	at	its	existing	Lewis Creek	electric	generating	station.	Entergy	Texas	received	regulatory	approval	from	the	PUCT	in	July	2017	and	the	facility	is	scheduled	to be	in	service	by	mid-2021;	and

•Entergy	Louisiana's	construction	of	the	994	MW,	combined-cycle,	gas	turbine	Lake	Charles	generating	facility	at	its	existing	Nelson electric	generating	station.	Entergy	Louisiana	received	regulatory	approval	from	the	LPSC	in	July	2017	and	the	facility	is	scheduled	to	be in	service	by	mid-2020.

The	RFP	process	has	also	resulted	in	the	selection,	or	confirmation	of	the	economic	merits	of,	long-term	purchased	power	agreements (PPAs),	including,	among	others:

•River	Bend	30%	life-of-unit	PPA	between	Entergy	Louisiana	and	Entergy	New	Orleans	for	100	MW	related	to	Entergy	Louisiana's unregulated	portion	of	the	River	Bend	nuclear	station,	which	portion	was	formerly	owned	by	Cajun;

•Entergy	Arkansas	wholesale	base	load	capacity	life-of-unit	PPAs	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	had	not	been	included	in	Entergy	Arkansas's	retail	rates); •In	December	2009,	Entergy	Texas	and	Exelon	Generation	Company,	LLC	executed	a	10-year	agreement	for	150-300	MW	from	the Frontier	Generating	Station	located	in	Grimes	County,	Texas;

•In	May	2011,	Entergy	Texas	and	Calpine	Energy	Services,	L.P.	executed	a	10-year	agreement	for	485	MW	from	the	Carville	Energy Center	located	in	St.	Gabriel,	Louisiana.	Entergy	Louisiana	purchases	50%	of	the	facility's	capacity	and	energy	from	Entergy	Texas.	In July	2014,	LS	Power	purchased	the	Carville	Energy	Center	and	replaced	Calpine	Energy	Services	as	the	counterparty	to	the	agreement; •In	September	2012,	Entergy	Gulf	States	Louisiana	executed	a	20-year	agreement	for	28	MW,	with	the	potential	to	purchase	an	additional 9	MW	when	available,	from	Rain	CII	Carbon	LLC's	pet	coke	calcining	facility	in	Sulphur,	Louisiana.	The	facility	began	commercial operation	in	May	2013.	Entergy	Louisiana,	as	successor	in	interest	to	Entergy	Gulf	States	Louisiana,	now	holds	the	agreement	with	the facility;

•In	 March	 2013,	 Entergy	 Gulf	 States	 Louisiana	 executed	 a	 20-year	 agreement	 for	 8.5	 MW	 from	Agrilectric	 Power	 Partners,	 LP's refurbished	rice	hull-fueled	electric	generation	facility	located	in	Lake	Charles,	Louisiana.	Entergy	Louisiana,	as	successor	in	interest	to Entergy	Gulf	States	Louisiana,	now	holds	the	agreement	with	Agrilectric;

•In	September	2013,	Entergy	Louisiana	executed	a	10-year	agreement	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;

•Entergy	Mississippi's	cost-based	purchase,	beginning	in	January	2013,	of	90	MW	from	Entergy	Arkansas's	share	of	Grand	Gulf	(only	60 MW	of	this	PPA	came	through	the	RFP	process).	Cost	recovery	for	the	90	MW	was	approved	by	the	MPSC	in	January	2013; •In	April	2015,	Entergy	Arkansas	and	Stuttgart	Solar,	LLC	executed	a	20-year	agreement	for	81	MW	from	a	solar	photovoltaic	electric generation	facility	located	near	Stuttgart,	Arkansas.	The	APSC	has	approved	the	project,	and	the	expected	commercial	operation	date	is	in June	2019;

•In	November	2016,	Entergy	Louisiana	and	LS	Power	executed	a	10-year	agreement	for	485	MW	from	the	Carville	Energy	Center	located in	St.	Gabriel,	Louisiana.	The	transaction	has	received	regulatory	approval	and	will	begin	in	June	2022;

•In	November	2016,	Entergy	Louisiana	and	Occidental	Chemical	Corporation	executed	a	10-year	agreement	for	500	MW	from	the	Taft Cogeneration	facility	located	in	Hahnville,	Louisiana.	The	transaction	has	received	regulatory	approval	and	will	begin	in	June	2018;	and •In	June	2017,	Entergy	Arkansas	and	Chicot	Solar,	LLC	executed	20-year	agreement	for	100	MW	from	a	solar	photovoltaic	electric generating	facility	located	in	Chicot	County,	Arkansas.	Entergy	Arkansas	filed	for	regulatory	approval	in	October	2017.

In	June	2016,	Entergy	Services,	on	behalf	of	Entergy	Louisiana,	issued	an	RFP	for	long-term	renewable	generation	resources.	The	RFP was	seeking	up	to	200	MW	of	renewable	resources	that	could	provide	energy,	fuel	diversity,	and	other	benefits	to	customers.	Two	proposals	were placed	in	the	primary	selection	list	and	the	transactions	are	currently	in	negotiations.

In	July	2016,	Entergy	Services,	on	behalf	of	Entergy	New	Orleans,	issued	an	RFP	for	long-term	renewable	generation	resources.	The	RFP was	seeking	up	to	20	MW	of	renewable	resources	that	could	provide	increased	depth	and	diversity	to	Entergy	New	Orleans's	generation	resource portfolio.	In	May	2017,	Entergy	New	Orleans	selected	three	proposals,	including	a	5	MW	self-build	option	for	an	aggregated	solar	photovoltaic resource	located	within	Orleans	Parish,	Louisiana.	In	October	2017,	Entergy	New	Orleans	filed	an	application	seeking	City	Council	approval	for the	self-build	option,	which	is	pending	before	the	City	Council.	Following	unsuccessful	negotiations	related	to	the	other	proposals	selected	in	May 2017,	Entergy	New	Orleans	suspended	negotiations	in	November	2017	and	invited	bidders	to	re-submit	proposals	with	current	information.	From these	submissions,	in	January	2018,	Entergy	New	Orleans	selected	three	proposals	with	an	anticipated	total	capacity	of	90	MW.	The	updated proposals	selected	are	in	addition	to	the	self-build	option.

# Other	Procurements	From	Third	Parties

The	Utility	operating	companies	have	also	made	resource	acquisitions	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;	Entergy	Louisiana's	April	2011	acquisition	of	the	580	MW,	combined-cycle,	gas- fired	Acadia	Energy	Center	Unit	2;	and	Entergy	Arkansas's	(Power	Block	2),	Entergy	Louisiana's	(Power	Blocks	3	and	4),	and	Entergy	New Orleans's	(Power	Block	1)	March	2016	acquisitions	of	the	1,980	MW	(summer	rating),	natural	gas-fired,	combined-cycle	gas	turbine	Union Power	Station	power	blocks,	each	rated	at	495	MW	(summer	rating).	The	Utility	operating	companies	have	also	entered	into	various	limited-	and long-term	contracts	in	recent	years	as	a	result	of	bilateral	negotiations.

The	Washington	Parish	Energy	Center	is	a	361	MW	natural	gas-fired	peaking	power	plant	under	advanced	development	approximately	60 miles	north	of	New	Orleans	on	a	partially	developed	site	Calpine	has	owned	since	2001.	This	simple-cycle	power	plant	 is	proposed	 to	be developed	pursuant	to	an	agreement	with	Entergy	Louisiana,	which	will	purchase	the	plant	upon	completion	in	2021	for	a	fixed	payment	to reimburse	 construction	 costs	 plus	 an	 associated	 premium.	In	 May	 2017,	 Entergy	 Louisiana	 filed	 an	 application	 with	 the	 LPSC	 seeking certification	of	the	plant.	The	application	is	pending.

# Interconnections

The	Utility	operating	companies'	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	MISO.	Entergy's Utility	operating	companies	are	MISO	market	participants	and	are	interconnected	with	many	neighboring	utilities.		MISO	is	an	essential	link	in	the safe,	 cost-effective	 delivery	 of	 electric	 power	 across	 all	 or	 parts	 of	 15	 U.S.	 states	 and	 the	 Canadian	 province	 of	 Manitoba.	As	 a	 Regional Transmission	Organization,	MISO	assures	consumers	of	unbiased	regional	grid	management	and	open	access	to	the	transmission

facilities	under	MISO's	functional	supervision.	In	addition,	the	Utility	operating	companies	are	members	of	the	SERC	Reliability	Corporation (SERC).	SERC	is	a	nonprofit	corporation	responsible	for	promoting	and	improving	the	reliability,	adequacy,	and	critical	infrastructure	of	the	bulk power	supply	systems	in	all	or	portions	of	16	central	and	southeastern	states.	SERC	serves	as	a	regional	entity	with	delegated	authority	from	the North	American	Electric	Reliability	Corporation	(NERC)	for the	purpose	of	proposing	and	enforcing	reliability	standards	within the	SERC Region.

# Gas	Property

As	of	December	31,	2017,	Entergy	New	Orleans	distributed	and	transported	natural	gas	for	distribution	within	New	Orleans,	Louisiana, through	approximately	2,500	miles	of	gas	pipeline.		As	of	December	31,	2017,	the	gas	properties	of	Entergy	Louisiana,	which	are	located	in	and around	Baton	Rouge,	Louisiana,	were	not	material	to	Entergy	Louisiana's	financial	position.

# Title

The	Utility	operating	companies'	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	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	2015-2017 were:

|  | Natural	Gas | Natural	Gas | Nuclear | Nuclear | Coal | Coal | Purchased	Power | Purchased	Power | MISO	Purchases | MISO	Purchases |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year | %\tof\nGen | Cents\tPer\nkWh | %\tof\nGen | Cents\tPer\nkWh | %\tof\nGen | Cents\tPer\nkWh | %\tof\nGen | Cents\tPer\nkWh | %\tof\nGen | Cents\tPer\nkWh |
| 2017 | 38 | 2.60 | 26 | 0.86 | 8 | 2.35 | 8 | 4.02 | 20 | 3.09 |
| 2016 | 41 | 2.44 | 28 | 0.63 | 7 | 2.65 | 9 | 3.71 | 15 | 3.13 |
| 2015 | 35 | 2.65 | 31 | 0.85 | 7 | 2.85 | 11 | 3.63 | 16 | 3.24 |

Actual	2017	and	projected	2018	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	Power<br>(d) | Purchased	Power<br>(d) | MISO	Purchases<br>(e) | MISO	Purchases<br>(e) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 |
| Entergy\tArkansas\t(a) | 28% | 33% | 49% | 51% | 18% | 15% | —% | 1% | 5% | — |
| Entergy\tLouisiana | 38% | 49% | 26% | 33% | 3% | 4% | 9% | 14% | 24% | — |
| Entergy\tMississippi\t(b) | 47% | 55% | 18% | 30% | 13% | 15% | —% | — | 22% | — |
| Entergy\tNew\tOrleans\t(b) | 53% | 57% | 33% | 41% | 2% | 1% | —% | 1% | 12% | — |
| Entergy\tTexas | 30% | 33% | 10% | 17% | 7% | 9% | 28% | 41% | 25% | — |
| System\tEnergy\t(c) | — | — | 100% | 100% | — | — | — | — | — | — |
| Utility\t(a)\t(b) | 38% | 44% | 26% | 36% | 8% | 9% | 8% | 11% | 20% | — |

(a) Hydroelectric	power	provided	less	than	1%	of	Entergy	Arkansas's	generation	in	2017	and	is	expected	to	provide	about	less	than1%	of	its generation	in	2018.

(b) Solar	power	provided	less	than	1%	of	Entergy	Mississippi's	and	Entergy	New	Orleans's	generation	in	2017	and	is	expected	to	provide	less than	1%	of	each	of	Entergy	Mississippi's	and	Entergy	New	Orleans's	generation	in	2018.

(c) 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	Louisiana,	Entergy Mississippi,	and	Entergy	New	Orleans.

(d) Excludes	MISO	purchases

(e) In	December	2013,	Entergy	integrated	its	transmission	system	into	the	MISO	RTO.	Entergy	offers	all	of	its	generation	into	the	MISO energy	market	on	a	day-ahead	and	real-time	basis	and	bids	for	power	in	the	MISO	energy	market	to	serve	the	demand	of	its	customers, with	MISO	making	dispatch	decisions.	MISO	purchases	cannot	be	projected	for	2018.

Some	of	the	Utility's	gas-fired	plants	are	also	capable	of	using	fuel	oil,	if	necessary.	Although	based	on	current	economics	the	Utility	does	not expect	fuel	oil	use	in	2018,	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.	Over 50%	of	the	Utility	operating	companies'	power	plants	maintain	some	level	of	long-term	firm	transportation.	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.

Many	 factors,	 including	 wellhead	 deliverability,	 storage,	 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	eight	one-	to	three-year	and	two	spot	contracts	that	will	supply	approximately	85%	of	the	total	coal supply	needs	in	2018.		These	contracts	are	staggered	in	term	so	that	not	all	contracts	have	to	be	renewed	the	same	year.		The	remaining	15%	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	2018.		Coal	will	be	transported	to	Arkansas	via	an	existing	transportation	agreement	that	is	expected	to	provide	all	of	Entergy Arkansas's	rail	transportation	requirements	for	2018.

Entergy	Louisiana	has	committed	to	five	one-	to	three-year	contracts	that	will	supply	approximately	90%	of	Nelson	Unit	6	coal	needs	in 2018.		If	needed,	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	2018.		Coal will	be	 transported	 to	Nelson	primarily	via	an	existing	 transportation	agreement	 that	 is	expected	 to	provide	all	of	Entergy	Louisiana's	rail transportation	requirements	for	2018.

For	the	year	2017,	coal	transportation	delivery	to	Entergy	Arkansas-and	Entergy	Louisiana-operated	coal-fired	units	was	adequate	for	the majority	of	the	year	but	experienced	some	delays	in	the	fourth	quarter	of	2017.	It	is	expected	that	delivery	times	will	improve	in	2018.	Both Entergy	Arkansas	and	Entergy	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	Louisiana	and	Entergy	Texas	that	it	has	adequate rail	car	and	barge	capacity	to	meet	the	volumes	of	PRB	coal	requested	for	2018.		Entergy	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	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	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	2018	or	beyond.		The	nuclear	fuel	supply	portfolio	for	the Entergy	Wholesale	Commodities	segment	is	being	adjusted	to	reflect	reduced	overall	requirements	related	to	the	planned	permanent	shutdowns	of the

Palisades,	Pilgrim,	Indian	Point	2,	and	Indian	Point	3	plants.	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	supply	alternatives	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's	ability	to	assure	nuclear	fuel	supply	also	depends	upon	the	performance	reliability	of	conversion,	enrichment,	and	fabrication services	providers.	There	are	fewer	of	these	providers	than	for	uranium.	For	conversion	and	enrichment	services,	like	uranium,	Entergy	diversifies its	supply	by	supplier	and	country	and	may	take	special	measures	as	needed	to	ensure	supply	of	enriched	uranium	for	the	reliable	fabrication	of nuclear	 fuel.	For	fabrication	services,	each	plant	 is	dependent	upon	 the	effective	performance	of	 the	fabricator	of	 that	plant's	nuclear	fuel, therefore,	Entergy	provides	additional	monitoring,	inspection,	and	oversight	for	the	fabrication	process	to	assure	reliability	and	quality.

Entergy	Arkansas,	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	credit	facilities	are	subject	to	periodic renewal,	and	the	notes	are	issued	periodically,	typically	for	terms	between	three	and	seven	years.

# 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	Centerpoint	Energy	Services	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	Centerpoint Energy	Service	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.

Entergy	Louisiana	purchased	natural	gas	for	resale	in	2017	under	a	firm	contract	from	Sequent	Energy	Management	L.P.		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	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	sales	of	electricity	rates	and	interstate	transmission	of	electricity,	including	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.	 See Note	2	to	the	financial	statements	for	further	discussion	of	federal	regulation	proceedings.

System	Agreement	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas)

Prior	to	each	operating	company's	termination	of	participation	in	the	System	Agreement	(Entergy	Arkansas	in	December	2013,	Entergy Mississippi	in	November	2015,	and	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas	each	in	August	2016),	the	Utility	operating companies	engaged	in	the	coordinated	planning,	construction,	and	operation	of	generating	and	bulk	transmission	facilities	under	the	terms	of	the System	Agreement,	which	was	a	rate	schedule	approved	by	the	FERC.	Under	the	terms	of	the	System	Agreement,	generating	capacity	and	other power	 resources	 were	 jointly	 operated	 by	 the	 Utility	 operating	 companies	 that	 were	 participating	 in	 the	 System	Agreement.	 	 The	 System Agreement	provided,	among	other	things,	that	parties	having	generating	reserves	greater	than	their	allocated	share	of	reserves	(long	companies) would	 receive	 payments	 from	 those	 parties	 having	 generating	 reserves	 that	 were	 less	 than	 their	 allocated	 share	 of	 reserves	 (short companies).		Such	payments	were	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	were	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	 were required	to	pay	the	cost	of	fuel	consumed	in	generating	such	energy	plus	a	charge	to	cover	other	associated	costs.	Entergy	Arkansas	terminated	its participation	in	the	System	Agreement	in	December	2013.	Entergy	Mississippi	terminated	its	participation	in	the	System	Agreement	in	November 2015.	The	System	Agreement	terminated	with	respect	to	its	remaining	participants	in	August	2016.

Although	 the	System	Agreement	has	 terminated,	certain	of	 the	Utility	operating	companies'	and	 their	retail	regulators	are	pursuing litigation	involving	the	System	Agreement	at	the	FERC	and	in	federal	courts.	The	proceedings	include	challenges	to	the	allocation	of	costs	as defined	by	the	System	Agreement	and	other	matters.	See	Note	2	to	the	financial	statements	for	discussion	of	legal	proceedings	at	the	FERC	and	in federal	courts	involving	the	System	Agreement.

# Transmission	and	MISO	Markets

On	December	19,	2013,	the	Utility	operating	companies	integrated	into	the	MISO	RTO.	Although	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,	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.	MISO	 also	 exercises	 functional	 control	 of transmission	planning	and	congestion	management	and	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	markets.	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	 pursuant	 to	 the	 MISO	 tariff	 and	 market	 rules.	Each	Utility	operating	company	has	 its	own transmission	pricing	zone	and	a	formula	rate	template	(included	as	Attachment	O	to	the	MISO	tariff)	used	to	establish	transmission	rates	within MISO.	The	terms	and	conditions	of	the	MISO	tariff,	including	provisions	related	to	the	design	and	implementation	of	wholesale	markets	and	the allocation	of	transmission	upgrade	costs,	are	subject	to	regulation	by	the	FERC.

# 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.				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.	See	Note	2	to	the	financial	statements	for discussion	of	a	complaint	filed	with	the	FERC	in	January	2017	regarding	System	Energy's	return	on	equity.

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	unit	power	cost	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	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	one	outstanding	series	of	first	mortgage	bonds.		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	a	supplement	as	security	for	its	one	outstanding	series	of	first	mortgage	bonds.	The	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.	No	such	consent	would	be	required	to	terminate	the	Capital	Funds	Agreement	or	the	supplement	thereto	at	this	time.

# 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	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	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	Louisiana,	as	successor	in	interest	to	Entergy	Gulf	States	Louisiana, 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	Louisiana	pursuant	to	a	life-of-unit	purchased	power	agreement	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	purchased	power	agreement.		In	connection	with the	termination	of	the	System	Agreement	effective	August	31,	2016,	the	purchased	power	agreements	that	were	put	in	place	for	certain	legacy units	at	the	time	of	the	jurisdictional	separation	were	also	terminated	at	that	time.	See	Note	2	to	the	financial	statements	for	additional	discussion of	the	purchased	power	agreements.

On	October	1,	2015,	the	businesses	formerly	conducted	by	Entergy	Louisiana	(Old	Entergy	Louisiana)	and	Entergy	Gulf	States	Louisiana (Old	Entergy	Gulf	States	Louisiana)	were	combined	into	a	single	public	utility.	In	order	to	effect	the	business	combination,	under	the	Texas Business	Organizations	Code	(TXBOC),	Old	Entergy	Louisiana	allocated	substantially	all	of	its	assets	to	a	new	subsidiary,	Entergy	Louisiana Power,	LLC,	a	Texas	limited	liability	company	(New	Entergy	Louisiana),	and	New	Entergy	Louisiana	assumed	the	liabilities	of	Old	Entergy Louisiana,	in	a	transaction	regarded	as	a	merger	under	the	TXBOC.	Under	the	TXBOC,	Old	Entergy	Gulf	States	Louisiana	allocated	substantially all	of	its	assets	to	a	new	subsidiary	(New	Entergy	Gulf	States	Louisiana)	and	New	Entergy	Gulf	States

Louisiana	assumed	the	liabilities	of	Old	Entergy	Gulf	States	Louisiana,	in	a	transaction	regarded	as	a	merger	under	the	TXBOC.	New	Entergy Gulf	States	Louisiana	then	merged	into	New	Entergy	Louisiana	with	New	Entergy	Louisiana	surviving	the	merger.	Thereupon,	Old	Entergy Louisiana	changed	its	name	from	"Entergy	Louisiana,	LLC"	to	"EL	Investment	Company,	LLC"	and	New	Entergy	Louisiana	changed	its	name from	"Entergy	Louisiana	Power,	LLC"	to	"Entergy	Louisiana,	LLC"	(Entergy	Louisiana).	With	the	completion	of	the	business	combination, Entergy	Louisiana	holds	substantially	all	of	the	assets,	and	has	assumed	the	liabilities,	of	Old	Entergy	Louisiana	and	Old	Entergy	Gulf	States Louisiana.	See	Note	2	to	the	financial	statements	for	additional	discussion	of	the	business	combination.

# Entergy	New	Orleans	Internal	Restructuring

In	November	2017,	pursuant	to	the	agreement	in	principle,	Entergy	New	Orleans,	Inc.	undertook	a	multi-step	restructuring,	including	the following:

•Under	the	Texas	Business	Organizations	Code	(TXBOC),	Entergy	New	Orleans,	Inc.	allocated	substantially	all	of	its	assets	to	a	new subsidiary,	Entergy	New	Orleans	Power,	LLC,	a	Texas	limited	liability	company	(Entergy	New	Orleans	Power),	and	Entergy	New	Orleans Power	assumed	substantially	all	of	the	liabilities	of	Entergy	New	Orleans,	Inc.	in	a	transaction	regarded	as	a	merger	under	the	TXBOC. Entergy	New	Orleans,	Inc.	remained	in	existence	and	held	the	membership	interests	in	Entergy	New	Orleans	Power.

•Entergy	New	Orleans,	Inc.	contributed	the	membership	interests	in	Entergy	New	Orleans	Power	to	an	affiliate	(Entergy	Utility	Holding Company,	LLC,	a	Texas	limited	liability	company	and	subsidiary	of	Entergy	Corporation).	As	a	result	of	the	contribution,	Entergy	New Orleans	Power	is	a	wholly-owned	subsidiary	of	Entergy	Utility	Holding	Company,	LLC.

# 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, |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| Entergy\tArkansas | 2.87 | 3.32 | 2.04 | 3.08 | 3.62 |
| Entergy\tLouisiana | 3.85 | 3.57 | 3.36 | 3.44 | 3.30 |
| Entergy\tMississippi | 4.49 | 3.96 | 3.59 | 3.23 | 3.19 |
| Entergy\tNew\tOrleans | 4.50 | 4.61 | 4.90 | 3.55 | 1.85 |
| Entergy\tTexas | 2.41 | 2.92 | 2.22 | 2.39 | 1.94 |
| System\tEnergy | 4.91 | 5.39 | 4.53 | 4.04 | 5.66 |

# 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, |  |  |
|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| Entergy\tArkansas | 2.81 | 3.09 | 1.85 | 2.76 | 3.25 |
| Entergy\tLouisiana | 3.85 | 3.57 | 3.24 | 3.28 | 3.14 |
| Entergy\tMississippi | 4.36 | 3.71 | 3.34 | 3.00 | 2.97 |
| Entergy\tNew\tOrleans | 4.24 | 4.30 | 4.50 | 3.26 | 1.70 |

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,	operation,	and	decommissioning	of	nuclear	power	plants,	located	in	the	northern United	States	and	the	sale	of	the	electric	power	produced	by	its	operating	plants	to	wholesale	customers.	 	Entergy	Wholesale	Commodities revenues	are	primarily	derived	from	sales	of	energy	and	generation	capacity	from	these	plants.		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	interests	in	non-nuclear	power	plants	that	sell	the	electric	power	produced	by those	plants	to	wholesale	customers.

On	 December	 29,	 2014,	 Entergy	 Wholesale	 Commodities'	 Vermont	 Yankee	 plant	 was	 removed	 from	 the	 grid,	 after	 42	 years	 of operations.	The	decision	 to	close	and	decommission	Vermont	Yankee,	which	was	announced	 in	August	2013,	was	due	 to	numerous	 issues including	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	Northeast	region.	In	November	2016,	Entergy entered	into	an	agreement	to	sell	100%	of	its	membership	interest	in	Entergy	Nuclear	Vermont	Yankee,	LLC	to	a	subsidiary	of	NorthStar.	 Entergy Nuclear	Vermont	Yankee	is	the	owner	of	the	Vermont	Yankee	plant.		The	sale	of	Entergy	Nuclear	Vermont	Yankee	to	NorthStar	will	include	the transfer	of	Entergy	Nuclear	Vermont	Yankee's	nuclear	decommissioning	trust	fund	and	the	asset	retirement	obligation	for	spent	fuel	management and	decommissioning	of	the	plant.	Entergy	plans	to	transfer	all	spent	nuclear	fuel	to	dry	cask	storage	by	the	end	of	2018	in	advance	of	the	planned transaction	close.	Under	the	sale	and	related	agreements	to	be	entered	into	at	the	closing,	NorthStar	will	commit	to	initiate	decommissioning	and site	restoration	by	2021	and	complete	those	activities,	along	with	partial	restoration	of	the	Vermont	Yankee	site,	with	the	exception	of	the independent	 spent	 fuel	 storage	 installation	 and	 switchyard,	 by	 2030.	The	original	completion	date,	as	outlined	 in	Entergy's	Post	Shutdown Decommissioning	Activities	Report	filed	with	 the	NRC,	was	2075.	The	 transaction	 is	contingent	upon	certain	closing	conditions,	 including approval	by	the	NRC;	approval	by	the	State	of	Vermont	Public	Utility	Commission,	including	approval	of	site	restoration	standards	that	will	be proposed	as	part	of	the	transaction;	the	transfer	of	all	spent	nuclear	fuel	to	dry	fuel	storage	on	the	independent	spent	fuel	storage	installation;	and that	the	market	value	of	the	assets	held	in	the	decommissioning	trust	fund	for	the	Vermont	Yankee	Nuclear	Power	Station,	less	the	hypothetical income	tax	on	the	aggregate	unrealized	net	gain	of	such	assets	at	closing,	is	equal	to	or	exceeds	$451.95	million,	subject	to	adjustments.

In	October	2015,	Entergy	determined	that	it	would	close	the	FitzPatrick	plant	at	the	end	of	its	fuel	cycle	in	January	2017.	In	August	2016, Entergy	entered	into	an	agreement	to	sell	the	FitzPatrick	plant	to	Exelon.	The	transaction	was	contingent	upon,	among	other	things,	the	expiration of	the	applicable	waiting	period	under	the	Hart-Scott-Rodino	Antitrust	Improvements	Act	of	1976,	as	amended,	the	receipt	of	necessary	regulatory approvals	from	the	FERC,	the	NRC,	and	the	Public	Service	Commission	of	the	State	of	New	York	(NYPSC),	and	the	receipt	of	a	private	letter ruling	from	the	IRS.	Because	certain	specified	conditions	were	satisfied	in	November	2016,	including	the	continued	effectiveness	of	the	Clean Energy	Standards/Zero	Emissions	Credit	program	(CES/ZEC),	the	establishment	of	certain	long-term	agreements	on	acceptable	terms	with	the Energy	Research	and	Development	Authority	of	the	State	of	New	York	in	connection	with	the	CES/ZEC	program,	and	NYPSC	approval	of	the transaction	on	acceptable	terms,	Entergy

refueled	the	FitzPatrick	plant	in	January	and	February	2017.	The	sale	closed	in	March	2017	after	obtaining	all	the	necessary	approvals.

In	October	2015,	Entergy	determined	that	it	would	close	the	Pilgrim	plant.	The	decision	came	after	management's	extensive	analysis	of the	economics	and	operating	life	of	the	plant	following	the	NRC's	decision	in	September	2015	to	place	the	plant	in	its	"multiple/repetitive degraded	cornerstone	column"	(Column	4)	of	its	Reactor	Oversight	Process	Action	Matrix.	The	Pilgrim	plant	is	expected	to	cease	operations	on May	31,	2019,	after	refueling	in	the	spring	of	2017	and	operating	through	the	end	of	that	fuel	cycle.

In	December	2015,	Entergy	Wholesale	Commodities	closed	on	the	sale	of	its	583	MW	Rhode	Island	State	Energy	Center,	in	Johnston, Rhode	 Island.	The	base	sales	price,	excluding	adjustments,	was	approximately	$490	million.	Entergy	Wholesale	Commodities	purchased	the Rhode	Island	State	Energy	Center	for	$346	million	in	December	2011.

In	December	2016,	Entergy	announced	that	it	had	reached	an	agreement	with	Consumers	Energy	to	terminate	the	existing	PPA	for	the Palisades	plant	on	May	31,	2018.	Pursuant	to	the	agreement,	Consumers	Energy	would	pay	Entergy	$172	million	for	the	early	termination	of	the PPA.	The	PPA	amendment	agreement	was	subject	to	regulatory	approvals,	including	approval	by	the	Michigan	Public	Service	Commission. Separately,	Entergy	intended	to	shut	down	the	Palisades	nuclear	power	plant	permanently	on	October	1,	2018,	after	refueling	in	the	spring	of	2017 and	operating	through	the	end	of	that	fuel	cycle.	In	September	2017	the	Michigan	Public	Service	Commission	issued	an	order	conditionally approving	the	PPA	amendment	transaction,	but	granting	Consumers	Energy	recovery	of	only	$136.6	million	of	the	$172	million	requested	early termination	payment.	As	a	result,	Entergy	and	Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement.	Entergy	will	continue	to operate	Palisades	under	the	current	PPA	with	Consumers	Energy,	instead	of	shutting	down	in	the	fall	of	2018	as	previously	planned.	 Entergy intends	to	shut	down	the	Palisades	nuclear	power	plant	permanently	on	May	31,	2022.

With	 the	 settlement	 concerning	 Indian	 Point,	 Entergy	 has	 announced	 plans	 for	 the	 disposition	 of	 all	 of	 the	 Entergy	 Wholesale Commodities	nuclear	power	plants,	including	the	sales	of	Vermont	Yankee	and	FitzPatrick,	and	the	earlier	than	previously	expected	shutdowns	of Pilgrim,	Palisades,	Indian	Point	2,	and	Indian	Point	3.	See	"Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power	Business "	for further	discussion.

# Property

# Nuclear	Generating	Stations

Entergy	Wholesale	Commodities	includes	the	ownership	of	the	following	nuclear	power	plants:

(a) In	October	2015,	Entergy	determined	that	it	would	close	the	Pilgrim	plant	no	later	than	June	1,	2019,	as	discussed	above.

(b) In	January	2017,	Entergy	announced	that	it	reached	a	settlement	with	New	York	State	to	shut	down	Indian	Point	2	by	April	30,	2020	and Indian	Point	3	by	April	30,	2021,	and	resolve	all	New	York	State-initiated	legal	challenges	to	Indian	Point's	operating	license	renewal. See	below	for	discussion	of	Indian	Point	2	and	Indian	Point	3	entering	their	"period	of	extended	operation"	after	expiration	of	the	plants' initial	license	terms	under	"timely	renewal."

(c) On	December	29,	2014,	the	Vermont	Yankee	plant	ceased	power	production.	 In	November	2016,	Entergy	entered	into	an	agreement	to sell	100%	of	the	membership	interest	in	Entergy	Nuclear	Vermont	Yankee,	to	NorthStar.	 Entergy	Nuclear	Vermont	Yankee	is	the	owner of	the	Vermont	Yankee	plant.

(d) In	December	2016,	Entergy	announced	that	it	had	reached	an	agreement	with	Consumers	Energy	to	terminate	the	existing	PPA	for	the Palisades	plant	in	2018.	Separately,	and	assuming	regulatory	approvals	are	obtained	for	the	PPA	termination	agreement,	Entergy	intended to	shut	down	the	Palisades	nuclear	power	plant	permanently	on	October	1,	2018,	after	refueling	in	the	spring	of	2017	and	operating through	the	end	of	 that	fuel	cycle.	In	September	2017,	as	a	result	of	the	Michigan	Public	Service	Commission's	order,	Entergy	and Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement.	Entergy	intends	to	shut	down	the	Palisades	nuclear	power	plant permanently	on	May	31,	2022.

In	October	2015,	Entergy	determined	that	it	would	close	the	FitzPatrick	plant	at	the	end	of	the	fuel	cycle,	in	January	2017,	but	in	August 2016,	Entergy	entered	into	an	agreement	to	sell	the	FitzPatrick	plant	to	Exelon,	and	the	sale	closed	in	March	2017.

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	April	2007,	Entergy	submitted	to	the	NRC	a	joint	application	to	renew	the	operating	licenses	for	Indian	Point	2	and	Indian	Point	3	for	an additional	20	years.	The	original	expiration	dates	of	the	NRC	operating	licenses	for	Indian	Point	2	and	Indian	Point	3	were	September	28,	2013 and	December	12,	2015,	respectively.	Authorization	to	operate	Indian	Point	2	and	Indian	Point	3	rests	on	Entergy's	having	timely	filed	a	license renewal	application	that	remains	pending	before	the	NRC.	Indian	Point	2	and	Indian	Point	3	have	now	entered	their	"period	of	extended	operation" after	expiration	of	the	plants'	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	until	the	license	renewal	process	has	been completed.	The	license	renewal	application	for	Indian	Point	2	and	Indian	Point	3	qualifies	for	timely	renewal	protection	because	it	met	NRC regulatory	standards	for	timely	filing.	The	NRC	is	not	expected	to	issue	renewed	licenses	earlier	than	third	quarter	2018.	For	additional	discussion of	the	license	renewal	applications	and	the	settlement	with	New	York	State,	see	"Entergy	Wholesale	Commodities

Authorizations	to	Operate	Indian	Point"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

# Non-nuclear	Generating	Stations

In	November	2016,	Entergy	sold	its	50%	membership	interest	in	Top	Deer	Wind	Ventures,	LLC,	a	wind-powered	electric	generation	joint venture	 owned	 in	 the	 Entergy	 Wholesale	 Commodities	 segment	 and	 accounted	 for	 as	 an	 equity	 method	 investment.	Entergy	 sold	 its	 50% membership	interest	in	Top	Deer	for	$0.5	million	and	realized	a	pre-tax	loss	of	$0.2	million.

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 |
| :--- | :--- | :--- | :--- | :--- |
| Independence\tUnit\t2;\t\t\t842\tMW | \t Newark,\tAR | 14% | 121\tMW(b) | \t Coal |
| 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.

# Independent	System	Operators

The	Pilgrim	plant	falls	under	the	authority	of	the	Independent	System	Operator	New	England	(ISO-NE)	and	the	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-NE,	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'	core	business	is	selling	energy,	measured	in	MWh,	to	its	customers.		Entergy Wholesale	Commodities	enters	 into	forward	contracts	with	 its	customers	and	also	sells	energy	 in	 the	day	ahead	or	spot	markets.	 	Entergy Wholesale	Commodities	also	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'	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.		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	in	2007,	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	receives	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.	In	December	2016,	Entergy	announced	 that	 it	reached	an	agreement	with Consumers	Energy	to	terminate	the	existing	PPA	for	the	Palisades	plant	in	2018.	Entergy	intended	to	shut	down	the	Palisades	nuclear	power	plant permanently	on	October	1,	2018,	after	refueling	in	the	spring	of	2017	and	operating	through	the	end	of	that	fuel	cycle.	In	September	2017,	as	a result	of	the	Michigan	Public	Service	Commission's	order,	Entergy	and	Consumers	Energy	agreed	to	terminate	the	PPA	amendment	agreement. Entergy	 intends	 to	shut	down	 the	Palisades	nuclear	power	plant	permanently	on	May	31,	2022.	See	discussion	above	for	additional	details regarding	the	agreement.

Entergy	 Wholesale	 Commodities'	 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-NE,	NYISO,	and	MISO.	Substantially	all of	the	credit	exposure	associated	with	the	planned	energy	output	under	contract	for	Entergy	Wholesale	Commodities	nuclear	plants	is	with counterparties	or	their	guarantors	that	have	public	investment	grade	credit	ratings.

# Competition

The	ISO-NE	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'	current	output	is	contracted	to	Consumers	Energy	through	2022.	Entergy	Wholesale	Commodities	does	not	expect	to	be	materially affected	by	competition	in	the	MISO	market	in	the	near	term.

# Seasonality

Entergy	Wholesale	Commodities'	revenues	and	operating	income	are	subject	to	fluctuations	during	the	year	due	to	seasonal	factors, weather	conditions,	and	contract	pricing.		Refueling	outages	are	generally	in	the	spring	and	fall,	and	cause	volumetric	decreases	during	those seasons.		When	outdoor	and	cooling	water	temperatures	are	low,	generally	during	colder	months,	Entergy	Wholesale	Commodities	nuclear	power plants	operate	more	efficiently,	and	consequently,	generate	more	electricity.		Many	of	Entergy	Wholesale	Commodities'	contracts	provide	for shaped	pricing	over	the	course	of	the	year.		As	a	result	of	these	factors,	Entergy	Wholesale	Commodities'	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	plant owners.

# 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's	functions	include	origination	of	new	energy	and	capacity	transactions	and	generation	scheduling.

Entergy	Nuclear,	Inc.	can	pursue	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.

TLG	Services,	a	subsidiary	of	Entergy	Nuclear,	Inc.,	offers	decommissioning,	engineering,	and	related	services	to	nuclear	power	plant owners.

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	 in	 November	 2010. In	 2010	 an	 Entergy	 subsidiary	 signed	 an	 agreement	 to	 extend	 the management	support	services	to	Cooper	Nuclear	Station	by	15	years,	through	January	2029.	In	2017	the	contract	was	amended	so	that	it	could	not be	terminated	prior	to	December	21,	2022.

# 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;

•the	reliability	of	the	high	voltage	interstate	transmission	system	through	reliability	standards;

•sale	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	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.	 Pursuant	to	recent	legislation	enacted	in	Tennessee, Entergy	Arkansas	is	subject	to	complaints	before	the	Tennessee	Regulatory	Authority	only	if	it	fails	to	treat	its	retail	customers	in	Tennessee	in	the same	manner	as	its	retail	customers	in	Arkansas.	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	Louisiana's	electric	and	gas	business	is	subject	to	regulation	by	the	LPSC	as	to:

•utility	service;

•retail	rates	and	charges;

•certification	of	generating	facilities	and	certain	transmission	projects;

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

•service	areas;

•facilities;

•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;

•issuance	and	sale	of	certain	securities;	and

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	and	generation	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	Louisiana, and	System	Energy,	as	owners	of	all	or	portions	of	ANO,	River	Bend	and	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	 operators	 of	 Pilgrim,	 Indian	 Point	 Energy	 Center,	Vermont	Yankee,	 and Palisades.	 	 Substantial	 capital	 expenditures,	 increased	 operating	 expenses,	 and/or	 higher	 decommissioning	 costs	 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	have	been	charged	fees	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, 2017	of	$183.3	million	for	the	one-time	fee.		Entergy	accepted	assignment	of	the	Pilgrim,	FitzPatrick	and	Indian	Point	3,	Indian	Point	1	and	Indian Point	2,	Vermont	Yankee,	Palisades,	and	Big	Rock	Point	spent	fuel	disposal	contracts	with	 the	DOE	held	by	 their	previous	owners.	 	The FitzPatrick	spent	fuel	disposal	contract	was	assigned	to	Exelon	as	part	of	the	sale	of	the	plant,	completed	in	March	2017.	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. Specific	steps	were	taken	to	discontinue	the	Yucca	Mountain	project,	including	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.	Although	the	NRC	completed	the	safety	evaluation	report	for	the	license review	in	2015,	the	previously	appropriated	funds	are	not	sufficient	to	complete	the	review,	including	required	hearings.	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	 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	per	net	kWh	generated	and	sold	after	April	7,	1983 fee.	In	November	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.	In	January	2014	the	DOE	submitted	the proposal	to	Congress	under	protest,	and	also	filed	a	petition	for	rehearing	with	the	D.C.	Circuit.	The	petition	for	rehearing	was	denied.	The	zero spent	fuel	fee	went	into	effect	prospectively	in	May	2014.	Management	cannot	predict	the	potential	timing	or	magnitude	of	future	spent	fuel	fee revisions	that	may	occur.

As	a	result	of	the	DOE's	failure	to	begin	disposal	of	spent	nuclear	fuel	in	1998	pursuant	to	the	Nuclear	Waste	Policy	Act	of	1982	and	the spent	fuel	disposal	contracts,	Entergy's	nuclear	owner/licensee	subsidiaries	have	incurred	and	will	continue	to	incur	damages.	These	subsidiaries have	been,	and	continue	to	be,	involved	in	litigation	to	recover	the	damages	caused	by	the	DOE's	delay	in	performance.	Through	2017,	Entergy's subsidiaries	won	and	collected	on	judgments	against	the	government	totaling	over	$500	million.

In	April	2015	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	amount	of	$29	million	in	favor	of	Entergy	Arkansas	and	against the	DOE	in	the	second	round	ANO	damages	case.	Also	in	April	2015	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	amount	of	$44 million	in	favor	of	System	Energy	and	against	the	DOE	in	the	second	round	Grand	Gulf	damages	case.	In	June	2015,	Entergy	Arkansas	and System	Energy	appealed	to	the	U.S.	Court	of	Appeals	for	the	Federal	Circuit	portions	of	those	decisions	relating	to	cask	loading	costs.	In	April 2016	the	Federal	Circuit	issued	a	decision	in	both	appeals	in	favor	of	Entergy	Arkansas	and	System	Energy,	and	remanded	the	cases	back	to	the U.S.	Court	of	Federal	Claims.	In	June	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	amount	of	$49	million	in	favor	of System	Energy	and	against	the	DOE	in	the	second	round	Grand	Gulf	damages	case,	and	Entergy	received	the	payment	from	the	U.S.	Treasury	in August	2016.	In	July	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	amount	of	$31	million	in	favor	of	Entergy	Arkansas	and against	the	DOE	in	the	second	round	ANO	damages	case,	and	Entergy	received	payment	from	the	U.S.	Treasury	in	October	2016.

In	May	2015	the	U.S.	Court	of	Federal	Claims	issued	a	final	partial	summary	judgment	on	a	portion,	$21	million,	of	the	claims	in	the Palisades	case.	The	DOE	did	not	appeal	that	decision,	and	Entergy	received	the	payment	from	the	U.S.	Treasury	in	October	2015.

In	December	2015	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	amount	of	$81	million	in	favor	of	Entergy	Nuclear	Indian Point	3	and	Entergy	Nuclear	FitzPatrick	in	the	first	round	Indian	Point	3/FitzPatrick	damages	case,	and	Entergy	received	the	payment	from	the U.S.	Treasury	in	June	2016.

In	January	2016	the	U.S.	Court	of	Federal	Claims	issued	a	judgment	in	the	amount	of	$49	million	in	favor	of	Entergy	Louisiana	and against	the	DOE	in	the	first	round	Waterford	3	damages	case.	In	April	2016,	Entergy	Louisiana	appealed	to	the	U.S.	Court	of	Appeals	for	the Federal	Circuit	the	portion	of	that	decision	relating	to	cask	loading	costs.	After	the	ANO	and	Grand	Gulf	appeal	was	rendered,	the	U.S.	Court	of Appeals	for	the	Federal	Circuit	remanded	the	Waterford	3	case	back	to	the	U.S.	Court	of	Federal	Claims	for	decision	in	accordance	with	the	U.S. Court	of	Appeals	ruling	on	cask	loading	costs.	In	August	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	Waterford	3	case	in the	amount	of	$53	million,	and	Entergy	Louisiana	received	the	payment	from	the	U.S.	Treasury	in	November	2016.

In	April	2016	the	U.S.	Court	of	Federal	Claims	issued	a	partial	judgment	in	the	amount	of	$42	million	in	favor	of	Entergy	Louisiana	and against	the	DOE	in	the	first	round	River	Bend	damages	case,	reserving	the	issue	of	cask	loading	costs	pending	resolution	of	the	appeal	on	the same	issues	in	the	Entergy	Arkansas	and	System	Energy	cases.	Entergy	Louisiana	received	payment	from	the	U.S.	Treasury	in	August	2016.	In September	2016	the	U.S.	Court	of	Federal	Claims	issued	a	further	judgment	in	the	River	Bend	case	in	the	amount	of	$5	million.	Entergy	Louisiana received	the	payment	from	the	U.S.	Treasury	in	January	2017.	In	May	2017	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	first round	River	Bend	damages	case	for	$0.6	million,	awarding	certain	cask	loading	costs	that	had	not	previously	been	adjudicated	by	the	court.

In	May	2016,	Entergy	Nuclear	Vermont	Yankee	and	the	DOE	entered	into	a	stipulated	agreement	and	the	U.S.	Court	of	Federal	Claims issued	a	judgment	in	the	amount	of	$19	million	in	favor	of	Entergy	Nuclear	Vermont	Yankee	and	against	the	DOE	in	the	second	round	Vermont Yankee	damages	case.	Entergy	received	payment	from	the	U.S.	Treasury	in	June	2016.

In	September	2016	the	U.S.	Court	of	Federal	Claims	issued	a	final	judgment	in	the	Entergy	Nuclear	Palisades	case	in	the	amount	of	$14 million.	Entergy	Nuclear	Palisades	received	payment	from	the	U.S.	Treasury	in	January	2017.

In	October	2016	the	U.S.	Supreme	Court	of	Federal	Claims	issued	a	judgment	in	the	second	round	Entergy	Nuclear	Indian	Point	2	case	in the	amount	of	$34	million.	Entergy	Nuclear	Indian	Point	2	received	payment	from	the	U.S.	Treasury	in	January	2017.

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,	at	Waterford	3	in	2011,	and	at	Pilgrim	in	2015.		These	facilities	will be	expanded	as	needed.

Entergy	Arkansas,	Entergy	Louisiana,	and	System	Energy	are	entitled	to	recover	from	customers	through	electric	rates	the	estimated decommissioning	costs	for	ANO,	Waterford	3,	and	Grand	Gulf,	respectively.		In	addition,	Entergy	Louisiana	and	Entergy	Texas	are	entitled	to recover	from	customers	through	electric	rates	the	estimated	decommissioning	costs	for	the	portion	of	River	Bend	subject	to	retail	rate	regulation. 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.

In	July	2010	the	LPSC	approved	increased	decommissioning	collections	for	Waterford	3	and	the	Louisiana	regulated	share	of	River	Bend and	in	December	2010	the	PUCT	approved	increased	decommissioning	collections	for	the	Texas	share	of	River	Bend	to	address	previously identified	funding	shortfalls.		In	December	2016	the	APSC	ordered	continued	collections	for	decommissioning	for	ANO	2,	while	finding	that ANO	1's	decommissioning	was	adequately	funded	without	continued	collections.	In	December	2017	the	APSC	ordered	continued	collections	for decommissioning	 for	 ANO	 2,	 and	 again	 found	 that	 ANO	 1's	 decommissioning	 was	 adequately	 funded	 without	 continued	 collections.	In September	2016	the	NRC	issued	a	20-year	operating	license	renewal	for	Grand	Gulf.	In	a	2017	filing	at	the	FERC,	System	Energy	stated	that	with the	 renewed	 operating	 license,	 Grand	 Gulf's	 decommissioning	 trust	 was	 sufficiently	 funded,	 and	 proposed	 (among	 other	 things)	 to	 cease decommissioning	collections	for	Grand	Gulf	effective	October	1,	2017.	The	FERC	accepted	the	proposal	subject	to	refund,	and	appointed	a settlement	judge	to	oversee	settlement	negotiations	in	the	case.	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.

In	November	2016,	Entergy	entered	into	an	agreement	to	sell	100%	of	the	membership	interest	in	Entergy	Nuclear	Vermont	Yankee	to	a subsidiary	of	NorthStar.	Upon	closing	of	 the	sale,	NorthStar	will	assume	ownership	of	Vermont	Yankee	and	 its	decommissioning	and	site restoration	trusts,	together	with	complete	responsibility	for	the	facility's	decommissioning	and	site	restoration.	The	sale	is	subject	to	certain closing	conditions,	including	approval	from	the	NRC	and	the	State	of	Vermont	Public	Utility	Commission.	See	Note	9	to	the	financial	statements for	further	discussion	of	Vermont	Yankee	decommissioning	costs	and	see	" Entergy	Wholesale	Commodities	Exit	from	the	Merchant	Power Business"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	further	discussion	of	the	NorthStar transaction.

For	the	Indian	Point	3	and	FitzPatrick	plants	purchased	in	2000	from	NYPA,	NYPA	retained	the	decommissioning	trust	funds	and	the decommissioning	liabilities	with	the	right	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.		In	August	2016,	Entergy	entered	into	a	trust transfer	agreement	with	NYPA	to	transfer	the	decommissioning	trust	funds	and	decommissioning	liabilities	for	the	Indian	Point	3	and	FitzPatrick plants	 to	 Entergy,	 which	 was	 completed	 in	 January	 2017.	In	March	2017,	Entergy	sold	 the	FitzPatrick	plant	 to	Exelon,	and	as	part	of	 the transaction,	the	FitzPatrick	decommissioning	trust	fund,	along	with	the	decommissioning	obligation	for	that	plant,	was	transferred	to	Exelon.	The FitzPatrick	spent	fuel	disposal	contract	was	assigned	to	Exelon	as	part	of	the	transaction.	See	Note	14	to	the	financial	statements	for	discussion	of the	FitzPatrick	sale.

In	 March	 2017	 filings	 with	 the	 NRC	 were	 made	 for	 certain	 Entergy	 subsidiaries'	 nuclear	 plants	 reporting	 on	 decommissioning funding.		Those	reports	showed	that	decommissioning	funding	for	each	of	those	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	16 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	$127.3	million	per	reactor	(with	102	nuclear	industry	reactors	currently	participating).		In	the	case	of	a	nuclear	event in	which	Entergy	Arkansas,	Entergy	Louisiana,	System	Energy,	or	an	Entergy	Wholesale	Commodities	company	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.

# NRC	Reactor	Oversight	Process

The	NRC's	Reactor	Oversight	Process	is	a	program	to	collect	information	about	plant	performance,	assess	the	information	for	its	safety significance,	and	provide	for	appropriate	licensee	and	NRC	response.	The	NRC	evaluates	plant	performance	by	analyzing	two	distinct	inputs: inspection	findings	resulting	from	the	NRC's	inspection	program	and	performance	indicators	reported	by	the	licensee.	The	evaluations	result	in the	placement	of	each	plant	in	one	of	the	NRC's	Reactor	Oversight	Process	Action	Matrix	columns:	"licensee	response	column,"	or	Column	1, "regulatory	 response	 column,"	 or	 Column	 2,	 "degraded	 cornerstone	 column,"	 or	 Column	 3,	 and	 "multiple/repetitive	 degraded	 cornerstone column,"	or	Column	4.	Plants	in	Column	1	are	subject	to	normal	NRC	inspection	activities.	Plants	in	Column	2,	Column	3,	or	Column	4	are subject	to	progressively	increasing	levels	of	inspection	by	the	NRC	with,	in	general,	progressively	increasing	levels	of	associated	costs.	Waterford 3,	River	Bend,	Indian	Point	2,	Indian	Point	3,	and	Palisades	are	in	Column	1.	Grand	Gulf	is	in	Column	2.	ANO	1	and	2	are	in	Column	4,	and	are subject	to	an	extensive	set	of	required	NRC	inspections.	Pilgrim	is	also	in	Column	4	and	is	subject	to	an	extensive,	but	limited,	set	of	required NRC	inspections.	See	Note	8	to	the	financial	statements	for	further	discussion	of	the	placement	of	ANO	1	and	2,	and	Pilgrim	in	Column	4	of	the NRC's	matrix.

# 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,	with	reference	to possible	exceptions	noted	below.		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	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,	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	permit	programs	and	enforcement	of	these	and	other	Clean	Air	Act	programs;

•Regional	Haze	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	follows	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	and	on	other	legal	issues	that	affect	this	program.

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, including	NSR	requirements	and	air	permits	issued	by	the	Arkansas	Department	of	Environmental	Quality.	In	August	2011,	Entergy's	Nelson facility,	located	in	Louisiana,	received	a	similar	request	for	information	from	the	EPA.	In	September	2015	a	subsequent	request	for	similar information	was	received	for	the	White	Bluff	facility.	Entergy	responded	to	all	requests.	None	of	these	EPA	requests	for	information	alleged	that the	facilities	were	in	violation	of	law.

In	January	2018	and	February	2018,	Entergy	Arkansas,	Entergy	Mississippi,	Entergy	Power,	and	other	co-owners	received	60-day	notice of	intent	to	sue	letters	from	the	Sierra	Club	and	the	National	Parks	Conservation	Association	concerning	allegations	of	violations	of	new	source review	and	permitting	provisions	of	the	Clean	Air	Act	at	the	Independence	and	White	Bluff	coal-burning	units,	respectively.	 Entergy	is	reviewing these	claims	and	will	respond	accordingly.

# Ozone	Nonattainment

Entergy	Texas	operates	one	fossil-fueled	generating	facility	(Lewis	Creek)	and	is	in	the	process	of	permitting	and	constructing	one	fossil- fueled	facility	(Montgomery	Count	Power	Station)	in	a	geographic	area	that	is	not	in	attainment	with	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	1997	8-hour	ozone	standard	with an	attainment	date	of	June	15,	2010.	 	In	June	2007	 the	Texas	governor	petitioned	 the	EPA	 to	reclassify	Houston-Galveston-Brazoria	from "moderate"	to	"severe"	and	the	EPA	granted	the	request	in	October	2008.		In	February	2015	the	Texas	Commission	on	Environmental	Quality (TCEQ)	submitted	a	request	to	the	EPA	for	a	finding	that	the	Houston-Galveston-Brazoria	area	is	in	attainment	with	the	1997	8-hour	ozone standard.	The	EPA	issued	this	finding	in	December	2015.	In	April	2015	the	EPA	revoked	the	1997	ozone	NAAQS	and	in	May	2016,	the	EPA issued	a	proposed	rule	approving	a	substitute	for	the	Houston-Galveston-Brazoria	area.	This	redesignation	indicates	that	the	area	has	attained	the revoked	1997	8-hour	ozone	NAAQS	due	to	permanent	and	enforceable	emission	reductions	and	that	it	will	maintain	that	NAAQS	for	10	years from	the	date	of	the	approval.	Final	approval,	which	was	effective	in	December	2016,	resulted	in	the	area	no	longer	being	subject	to	any	remaining anti-backsliding	or	non-attainment	new	source	review	requirements	associated	with	the	revoked	1997	NAAQS.

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.	 In	April	 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.	In	August	2015	and	January	2016,	the	EPA	proposed determinations	that	the	Baton	Rouge	and	Memphis	areas	had	attained	the	2008	standard.	In	May	2016	the	EPA	finalized	those	determinations	and extended	the	Houston-Galveston-Brazoria	area's	attainment	date	for	the	2008	Ozone	standard	to	July	20,	2016	and	reclassified	the	Baton	Rouge area	as	attainment	for	ozone	under	the	2008	8-hour	ozone	standard.	In	December	2016	the	EPA	determined	that	the	Houston-Galveston-Brazoria area	had	failed	to	attain	the	2008	ozone	standard	by	the	2016	attainment	date.	This	finding	reclassifies	the	Houston-Galveston-Brazoria	area	from marginal	to	"moderate."

In	October	2015	the	EPA	issued	a	final	rule	lowering	the	primary	and	secondary	NAAQS	for	ozone	to	a	level	of	70	parts	per	billion. States	were	required	to	assess	their	attainment	status	and	recommend	designations	to	the	EPA.	In	January	2018	the	EPA	proposed	that	the following	counties	and	parishes	in	Entergy's	service	territory	be	listed	as	in	non-attainment:	in	Louisiana,	Ascension	Parish,	East	Baton	Rouge Parish,	 West	 Baton	 Rouge	 Parish,	 Iberville	 Parish,	and	 Livingston	 Parish;	 in	 Texas,	 Montgomery	 County.	In	 addition	 to	 Lewis	 Creek	 in Montgomery	County,	Texas,	Entergy	owns	or	operates	fossil-fueled	generating	units	in	East	Baton	Rouge	Parish	(Louisiana	Station)	and	in Iberville	Parish	(Willow	Glen),	Louisiana.	The	EPA's	final	designations	are	pending.	 Entergy	will	continue	to	work	with	state	environmental agencies	on	appropriate	methods	for	assessing	attainment	and	non-attainment	with	 the	new	standard	and,	where	necessary,	 in	planning	for compliance.	Following	designations	by	the	EPA,	states	will	be	required	to	develop	plans	intended	to	return	non-attainment	areas	to	a	condition	of attainment.	The	timing	for	that	action	depends	largely	on	the	severity	of	non-attainment	in	a	given	area.

# 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	 indicated	 that	 it	 would	 delay designations	except	for	those	areas	with	existing	monitoring	data	from	2009	to	2011	indicating	violations	of	the	new	standard.	In	August	2013	the 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	July	2016	the	EPA finalized	another	round	of	designations	for	areas	with	newly	monitored	violations	of	the	2010	standard	and	those	with	stationary	sources	that	emit over	a	threshold	amount	of	SO2.	Counties	and	parishes	in	which	Entergy	owns	and	operates	fossil	generating	facilities	that	were	included	in	this round	of	designations	include	Independence	County	and	Jefferson	County,	Arkansas	and	Calcasieu	Parish,	Louisiana.	Independence	County	and Calcasieu	Parish	were	designated	"unclassifiable,"	and	Jefferson	County	was	designated	"unclassifiable/attainment."	In	August	2015	the	EPA issued	a	final	data	requirement	rule	for	the	SO2	1-hour	standard.	This	rule	will	guide	the	process	to	be	followed	by	the	states	and	the	EPA	to determine	the	appropriate	designation	for	the	remaining	unclassified	areas	in	the	country.	In	August	2017	the	EPA	issued	a	letter	indicating	that East	Baton	Rouge	and	St.	Charles	parishes	would	be	designated	by	December	31,	2020	as	monitors	were	installed	to	determine	compliance.	In January	2018	the	EPA	published	a	final	rule	designating	a	third	round	of	attainment	and	non-attainment	areas.	Evangeline	Parish,	Louisiana,	was designated	 non-attainment.	Entergy	does	not	have	a	generation	asset	in	that	parish.	Additional	capital	projects	or	operational	changes	may	be required	to	continue	operating	Entergy	facilities	in	areas	eventually	designated	as	in	non-attainment	of	the	standard	or	designated	as	contributing	to non-attainment	areas.

# Hazardous	Air	Pollutants

The	EPA	released	the	final	Mercury	and	Air	Toxics	Standard	(MATS)	rule	in	December	2011,	which	had	a	compliance	date,	with	a	widely granted	one-year	extension,	of	April	2016.	The	required	controls	have	been	installed	and	are	operational	at	all	affected	Entergy	units.

# Cross-State	Air	Pollution

In	March	2005	the	EPA	finalized	the	Clean	Air	Interstate	Rule	(CAIR),	which	was	intended	to	reduce	SO 2	and	NOx	emissions	from electric	generation	plants	in	order	to	improve	air	quality	in	twenty-nine	eastern	states.		The	rule	required	a	combination	of	capital	investment	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,	CAIR	and	its	subsequent	versions,	now	known	as	the	Cross	State	Air	Pollution	Rule	(CSAPR),	have been	remanded	to	and	modified	by	the	EPA	on	multiple	occasions.	In	July	2015	the	D.C.	Circuit	invalidated	the	allowance	budgets	created	by	the EPA	for	several	states,	including	Texas,	and	remanded	that	portion	of	the	rule	to	the	EPA	for	further	action.	 The	court	did	not	stay	or	vacate	the rule	in	the	interim.	CSAPR	remains	in	effect.

The	CSAPR	Phase	1	implementation	became	effective	January	1,	2015.	Entergy	has	developed	a	compliance	plan	that	could,	over	time, include	both	installation	of	controls	at	certain	facilities	and	an	emission	allowance	procurement	strategy.

In	September	2016	the	EPA	finalized	the	CSAPR	Update	Rule	to	address	interstate	transport	for	the	2008	ozone	NAAQS.	Starting	in	2017 the	final	rule	will	require	reductions	in	summer	nitrogen	oxides	(NOx)	emissions.	Several	states,	including	Arkansas	and	Texas,	filed	a	challenge to	the	Update	Rule,	which	remains	pending.

# Regional	Haze

In	June	2005	the	EPA	issued	its	final	Clean	Air	Visibility	Rule	(CAVR)	regulations	that	potentially	could	result	in	a	requirement	to	install SO2	and	NOx	pollution	control	technology	as	Best	Available	Retrofit	Control	Technology	(BART)	to	continue	operating	certain	of	Entergy's	fossil generation	units.		The	rule	leaves	certain	CAVR	determinations	to	the	states.

In	Arkansas,	the	Arkansas	Department	of	Environmental	Quality	prepared	a	state	implementation	plan	(SIP)	for	Arkansas	facilities	to implement	its	obligations	under	the	CAVR.			In	April	2012	the	EPA	finalized	a	decision

addressing	the	Arkansas	Regional	Haze	SIP,	in	which	it	disapproved	a	large	portion	of	the	Arkansas	plan,	including	the	emission	limits	for	NO x and	SO2	at	White	Bluff.		In	April	2015	the	EPA	published	a	proposed	federal	implementation	plan	(FIP)	for	Arkansas,	taking	comment	on requiring	 installation	 of	 scrubbers	 and	 low	 NOx	 burners	 to	 continue	 operating	 both	 units	 at	 the	 White	 Bluff	 plant	 and	 both	 units	 at	 the Independence	plant	and	NOx	controls	to	continue	operating	the	Lake	Catherine	plant.	Entergy	filed	comments	by	the	deadline	in	August	2015. Among	 other	 comments,	 including	 opposition	 to	 the	 EPA's	 proposed	 controls	 on	 the	 Independence	 units,	 Entergy	 proposed	 to	 meet	 more stringent	SO2	and	NOx	limits	at	both	White	Bluff	and	Independence	within	three	years	of	the	effective	date	of	the	final	FIP	and	to	cease	the	use	of coal	at	the	White	Bluff	units	at	a	later	date.

In	September	2016	the	EPA	published	the	final	Arkansas	Regional	Haze	FIP.	 In	most	respects,	the	EPA	finalized	its	original	proposal	but shortened	the	time	for	compliance	for	installation	of	the	NOx	controls.	The	FIP	required	an	emission	limitation	consistent	with	SO2	scrubbers	at both	White	Bluff	and	Independence	by	October	2021	and	NOx	controls	by	April	2018.	The	EPA	declined	to	adopt	Entergy's	proposals	related	to ceasing	coal	use	as	an	alternative	to	SO2	scrubbers	for	White	Bluff	SO2	BART.	In	November	2016,	Entergy	and	other	interested	parties,	including the	State	of	Arkansas,	filed	petitions	for	administrative	reconsideration	and	stay	at	the	EPA	as	well	as	petitions	for	judicial	review	in	the	U.S. Court	of	Appeals	for	the	Eighth	Circuit.	The	Eighth	Circuit	continues	to	review	its	prior	grant	of	the	government's	motion	to	hold	the	appeal litigation	in	abeyance	pending	settlement	discussions	and	pending	the	State's	development	of	a	SIP	that,	if	approved	by	the	EPA,	would	replace the	FIP.	The	state	has	proposed	its	replacement	SIP	in	two	parts:	Part	I	considers	NOx	requirements,	and	Part	II	considers	SO 2	requirements.	The EPA	approved	the	Part	I	NO x	SIP	in	January	2018.	Arkansas	has	proposed	a	Part	II	SIP	which	is	still	under	consideration	at	the	state	level.	The public	comment	period	on	Part	II	ended	on	February	2,	2018.

In	Louisiana,	Entergy	worked	with	the	Louisiana	Department	of	Environmental	Quality	(LDEQ)	and	the	EPA	to	revise	the	Louisiana	SIP for	regional	haze,	which	was	disapproved	in	part	in	2012.	The	LDEQ	submitted	a	revised	SIP	in	February	2017.	In	May	2017	the	EPA	proposed	to approve	a	majority	of	the	revisions.	In	September	2017	the	EPA	issued	a	proposed	SIP	approval	for	the	Nelson	plant,	requiring	an	emission limitation	consistent	with	the	use	of	low-sulfur	coal,	with	a	compliance	date	three	years	from	the	effective	date	of	the	final	EPA	approval.	The EPA's	final	approval	decision	was	issued	in	December	2017	and	is	on	appeal	to	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit.

# New	and	Existing	Source	Performance	Standards	for	Greenhouse	Gas	Emissions

As	a	part	of	a	climate	plan	announced	in	June	2013,	the	EPA	was	directed	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 January	2014	the	EPA	issued	the	proposed	New	Source	Performance	Standards	rule	for	new	sources.	In	June	2014	the	EPA	issued	proposed standards	for	existing	power	plants.		Entergy	was	actively	engaged	in	the	rulemaking	process,	and	submitted	comments	to	the	EPA	in	December 2014.	The	EPA	issued	the	final	rules	for	both	new	and	existing	sources	in	August	2015,	and	they	were	published	in	the	Federal	Register	in October	2015.	The	existing	source	rule,	also	called	the	Clean	Power	Plan,	requires	states	to	develop	plans	for	compliance	with	the	EPA's	emission standards.	In	February	2016	the	U.S.	Supreme	Court	issued	a	stay	halting	the	effectiveness	of	the	rule	until	the	rule	is	reviewed	by	the	D.C.	Circuit and	 by	 the	 U.S.	 Supreme	 Court,	 if	 further	 review	 is	 granted.	In	 March	 2017	 the	 current	 administration	 issued	 an	 executive	 order	 entitled "Promoting	Energy	Independence	and	Economic	Growth"	instructing	the	EPA	to	review	and	then	to	suspend,	revise,	or	rescind	the	Clean	Power Plan,	if	appropriate.	The	EPA	subsequently	asked	the	D.C.	Circuit	to	hold	the	challenges	to	the	Clean	Power	Plan	and	the	greenhouse	gas	new source	performance	standards	in	abeyance	and	signed	a	notice	of	withdrawal	of	the	proposed	federal	plan,	model	trading	rules,	and	the	Clean Energy	Incentive	Program.	The	court	placed	the	litigation	in	abeyance	in	April	2017.	The	EPA	Administrator	also	sent	a	letter	to	the	affected governors	explaining	that	states	are	not	currently	required	to	meet	Clean	Power	Plan	deadlines,	some	of	which	have	passed.	In	October	2017	the EPA	proposed	a	new	rule	that	would	repeal	the	Clean	Power	Plan	on	the	grounds	that	it	exceeds	the	EPA's	statutory	authority	under	the	Clean	Air Act.	In	December

2017	the	EPA	issued	an	advanced	notice	of	proposed	rulemaking	regarding	section	111(d),	seeking	comment	on	the	form	and	content	of	a replacement	for	the	Clean	Power	Plan,	if	one	is	promulgated.	Entergy	will	continue	to	be	engaged	in	this	rulemaking	process.

# 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	NO x,	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;

•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	and	its	use	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;

•efforts	by	certain	external	groups	to	encourage	reporting	and	disclosure	of	carbon	dioxide	emissions	and	risk;

•the	listing	of	additional	species	as	threatened	or	endangered,	the	protection	of	critical	habitat	for	these	species,	and	developments	in	the legal	protection	of	eagles	and	migratory	birds;	and

•the	regulation	of	the	management,	disposal,	and	beneficial	reuse	of	coal	combustion	residuals.

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	megawatt-hour	of electricity	generated.		In	anticipation	of	the	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	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	to	include	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.	 In	 2011,	 Entergy	 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,	45.5	million tons	in	2012,	46.2	million	tons	in	2013,	42.4	million	tons	in	2014,	39.5	million	tons	in	2015,	42.5	million	tons	in	2016,	and	39.9	million	tons	in 2017.	The	decrease

in	this	number	from	2014	to	2015	was	largely	attributable	to	the	impact	on	the	calculation	methodology	of	the	Utility	operating	companies' transition	 into	 the	 MISO	 system.	Participation	 in	 this	system	resulted	 in	fewer	power	purchases	being	classified	as	"controllable"	and	 thus included	in	the	calculation	of	the	emissions	total.

Entergy	participates	in	the	M.J.	Bradley	&	Associates'	Annual	Benchmarking	Air	Emissions	Report,	an	annual	analysis	of	the	100	largest U.S.	electric	power	producers.	The	report	is	available	on	the	M.J.	Bradley	website.	Entergy's	annual	CO2	emissions	audit	is	also	third-party verified,	and	that	certification	is	made	available	on	 the	American	Carbon	Registry	website.	Entergy	participates	annually	 in	 the	Dow	Jones Sustainability	Index	and	in	2017	was	listed	on	the	North	American	Index.

# 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.

For	thirteen	years,	Entergy	participated	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.		That	proceeding	recently	was	settled	along	with other	 ongoing	 proceedings.	For	a	discussion	of	the	recent	Indian	Point	settlement,	see	"Entergy	Wholesale	Commodities	Authorization	to Operate	Indian	Point"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

# 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.	After litigation,	the	EPA	issued	a	new	final	316(b)	rule	in	August	2014.	Entergy	is	developing	a	compliance	plan	for	each	affected	facility	in	accordance with	the	requirements	of	the	final	rule.

Entergy	filed	a	petition	for	review	of	the	final	rule	as	a	co-petitioner	with	the	Utility	Water	Act	Group.	The	U.S.	Court	of	Appeals	for	the Second	Circuit	heard	oral	argument	in	September	2017.	A	decision	is	expected	in	2018.

# 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.	 For	 a discussion	of	the	recent	Indian	Point	settlement,	including	the	CZMA	proceedings	related	to	Indian	Point	license	renewal,	see	"Entergy

# Wholesale	 Commodities	 Authorizations to	 Operate Indian	 Point" in	 Entergy	 Corporation and	 Subsidiaries	 Management's	 Financial Discussion	and	Analysis.

# 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	said	would	inform	the	rulemaking.	This	report	was	finalized	in	January	2015.	The	final	rule was	published	in	the	Federal	Register	in	June	2015.	The	rule	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.	The	final	rule	has	been	challenged	in	various	federal	courts	by	several	parties,	including	most	states.	In	August	2015	the District	Court	for	North	Dakota	issued	a	preliminary	injunction	staying	the	new	rule	in	13	states,	including	Arkansas.	In	October	2015	the	U.S. Court	of	Appeals	for	the	Sixth	Circuit	issued	a	nationwide	stay	of	the	rule.	In	February	2017	the	current	administration	issued	an	executive	order instructing	the	EPA	and	the	U.S.	Army	Corps	of	Engineers	to	review	the	Waters	of	the	United	States	rule	and	to	revise	or	rescind,	as	appropriate. In	June	2017	the	EPA	and	the	U.S.	Army	Corps	of	Engineers	released	a	proposed	rule	that	rescinds	the	June	2015	rule	and	recodifies	the definition	of	"waters	of	the	U.S."	that	was	in	effect	prior	to	the	2015	rule.	The	administration	is	expected	to	propose	a	definition	of	"waters	of	the U.S."	at	a	later	date.	In	January	2018	the	Supreme	Court	determined	that	the	Sixth	Circuit	lacked	jurisdiction	over	the	petition	to	review	the	2015 rule	and	that	the	challenges	should	be	heard	in	the	federal	district	court.	The	matter	has	been	remanded	to	the	Sixth	Circuit,	which	is	expected	to lift	 the	 nationwide	 stay.	After	 the	 Supreme	 Court	 decision,	 the	 EPA	 and	 the	 U.S.	Army	 Corps	 of	 Engineers	 finalized	 a	 rule	 delaying	 the applicability	date	of	the	2015	rule	to	early	2020.	In	February	2018	the	states	of	Louisiana,	Mississippi,	and	Texas	filed	suit	in	Texas	federal district	court	seeking	a	preliminary	injunction	of	the	2015	rule.	Entergy	will	continue	to	monitor	this	rulemaking	and	litigation.

# Groundwater	at	Certain	Nuclear	Sites

The	NRC	requires	nuclear	power	plants	to	monitor	and	report	regularly	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,	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	 and	 other radionuclides.		Based	on	current	information,	the	concentrations	and	locations	of	radionuclides	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.

In	February	2016,	Entergy	disclosed	that	elevated	tritium	levels	had	been	detected	in	samples	from	several	monitoring	wells	that	are	part of	Indian	Point's	groundwater	monitoring	program.		Investigation	of	the	source	of	elevated	tritium	has	determined	that	the	source	is	related	to	a temporary	system	to	process	water	in	preparation	for	the	regularly	scheduled	refueling	outage	at	Indian	Point	2.	The	system	was	secured	and	is	no longer	in	use	and	additional	measures	have	been	taken	to	prevent	reoccurrence	should	the	system	be	needed	again.	In	June	2016,	Indian	Point detected	trace	amounts	of	cobalt	58	in	a	single	well.	This	was	associated	with	the	draining	and	disassembly	of	a	temporary	heat

exchanger	operated	in	support	of	the	Indian	Point	2	outage.	Oversight	by	NRC	and	other	federal/state	government	bodies	continues.	The	NRC	has issued	 a	 green	 notice	 of	 violation	 related	 to	 the	 adequacy	 of	 Entergy's	 controls	 to	 prevent	 the	 introduction	 of	 radioactivity	 into	 the	 site groundwater.	Entergy	has	completed	all	required	corrective	actions	and	expects	the	NRC	to	close	the	notice	of	violation	by	March	2018.

# 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	potentially	material CERCLA	and	similar	state	program	liabilities	are	discussed	in	the	"Other	Environmental	Matters"	section	below.

In	June	2010	the	EPA	issued	a	proposed	rule	on	coal	combustion	residuals	(CCRs)	that	contained	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	reused	in	certain	processes	would	remain	excluded from	hazardous	waste	regulation.	In	April	2015	the	EPA	published	the	final	CCR	rule	with	the	material	being	regulated	under	the	second	scenario presented	above	-	as	non-hazardous	wastes	regulated	under	RCRA	Subtitle	D.

The	final	regulations	create	new	compliance	requirements	including	modified	storage,	new	notification	and	reporting	practices,	product disposal	considerations,	and	CCR	unit	closure	criteria.		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.	As	of	December	31,	2017,	Entergy's	has	recorded	asset	retirement	obligations related	to	CCR	management	of	$8.6	million,	including	$3.9	million	at	Entergy	Arkansas,	$1.8	million	at	Entergy	Louisiana,	$1.1	million	at Entergy	Mississippi,	and	$1.3	million	at	Entergy	Texas.

In	December	2016	the	Water	Infrastructure	Improvements	for	the	Nation	Act	(WIIN	Act)	was	signed	into	law,	which	authorizes	states	to regulate	coal	ash	rather	than	leaving	primary	enforcement	to	citizen	suit	actions.	States	may	submit	to	the	EPA	proposals	for	a	permit	programs. In	September	2017	the	EPA	agreed	to	reconsider	certain	provisions	of	the	CCR	rule	in	light	of	the	WIIN	Act.	 The	EPA	has	not	yet	initiated	a	new round	of	rulemaking	and	did	not	extend	the	existing	mid-October	2017	groundwater	monitoring	deadline.	Entergy	met	the	existing	monitoring deadline,	is	monitoring	state	agency	actions,	and	will	participate	in	the	regulatory	development	process.

In	late-2017,	Entergy	determined	that	certain	in-ground	wastewater	treatment	system	recycle	ponds	at	its	White	Bluff	and	Independence facilities	require	management	under	the	new	EPA	regulations.	Entergy	is	taking	action	to	address	the	operational	and	regulatory	management	of these	facilities.	Entergy	also	has	monitored	levels	of	constituents	in	the	groundwater	monitoring	system	surrounding	its	coal	combustion	residual landfills	at	these	locations	that	require	reporting	and	additional	monitoring.	Reporting	has	occurred	as	required,	and	monitoring	will	continue.	Any potential

requirements	for	corrective	action	or	operational	changes	under	the	new	EPA	rule	are	currently	being	assessed.	Moreover,	the	rule	is	currently under	review	at	the	EPA	for	potential	changes,	and	the	nature	and	cost	of	any	corrective	action	requirements	may	depend,	in	part,	on	the	outcome of	the	EPA's	review.

# Other	Environmental	Matters

# Entergy	Louisiana	and	Entergy	Texas

Entergy	Louisiana,	as	successor	in	interest	to	Entergy	Gulf	States	Louisiana,	currently	is	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,	apparently	was	routed to	a	portion	of	the	property	for	disposal.		The	same	area	also	has	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.		The	EPA	released	the	second Five	Year	Review	in	2015.	The	EPA	indicated	that	the	current	remediation	technique	was	insufficient	and	that	Entergy	would	need	to	utilize	other remediation	technologies	on	the	site.	In	July	2015,	Entergy	submitted	a	Focused	Feasibility	Study	to	the	EPA	outlining	the	potential	remedies	and suggesting	installation	of	a	waterloo	barrier.	The	estimated	cost	for	this	remedy	is	approximately	$2	million.	Entergy	is	awaiting	comments	and direction	from	the	EPA	on	the	Focused	Feasibility	Study	and	potential	remedy	selection.		In	early	2017	the	EPA	indicated	that	the	new	remedial method,	a	waterloo	barrier,	may	not	be	necessary	and	requested	revisions	to	the	Focused	Feasibility	Study.	The	EPA	plans	to	provide	comments on	the	revised	2017	Focused	Feasibility	Study	in	the	next	Five	Year	Review	in	2020.	Entergy	is	continuing	discussions	with	the	EPA	regarding the	ongoing	actions	at	the	site.

# Entergy	Arkansas,	Entergy	Louisiana,	Entergy	New	Orleans,	and	Entergy	Texas

The	Texas	Commission	on	Environmental	Quality	(TCEQ)	notified	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	New	Orleans,	and Entergy	Texas	that	the	TCEQ	believes	those	entities	are	potentially	responsible	parties	(PRPs)	concerning	contamination	existing	at	the	San Angelo	Electric	Service	Company	(SESCO)	facility	in	San	Angelo,	Texas.		The	facility	operated	as	a	transformer	repair	and	scrapping	facility from	 the	 1930s	 until	 2003.	 	 Both	 soil	 and	 groundwater	 contamination	 exists	 at	 the	 site.	 	 Entergy	 subsidiaries	 sent	 transformers	 to	 this facility.		Entergy	Arkansas,	Entergy	Louisiana,	and	Entergy	Texas	responded	to	an	information	request	from	the	TCEQ	and	continue	to	cooperate in	this	investigation.		Entergy	Louisiana	and	Entergy	Texas	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	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	variable	depending	on	ultimate	remediation	design	and	performance,	indicate	that	Entergy's	total	share	of remediation	costs	likely	will	be	approximately	$1.5	million	to	$2	million.		Remediation	activities	continue	at	the	site.

In	December	2016	a	transformer	inside	the	Hartburg,	Texas	Substation	had	an	internal	fault	resulting	in	a	release	of	approximately	15,000 gallons	of	non-PCB	mineral	oil.	Cleanup	ensued	immediately;	however,	rain	caused	much	of	the	oil	to	spread	across	the	substation	yard	and	into	a nearby	 wetland.	The	Texas	Commission	on	Environmental	Quality	(TCEQ)	and	the	National	Response	Center	were	immediately	notified,	and TCEQ	responded	to	the	site	approximately	two	hours	after	the	cleanup	was	initiated.	The	remediation	liability	is	estimated	at	$2.2	million; however,	this	number	could	fluctuate	depending	on	the	remediation	extent	and	wetland	mitigation	requirements.	In	July	2017,

Entergy	 entered	 into the	Voluntary	 Cleanup	 Program	 with	TCEQ.	Additional	direction is	expected	from	TCEQ	regarding	final	remediation requirements	for	the	site.

# Entergy

In	May	2015	a	transformer	at	the	Indian	Point	facility	failed,	resulting	in	a	fire	and	the	release	of	non-PCB	oil	to	the	ground	surface.	The fire	was	extinguished	by	the	facility's	fire	deluge	system.	No	injuries	occurred	due	to	the	transformer	failure	or	company	response.	An	estimated 3,000	gallons	of	oil	were	released	into	the	facility's	discharge	canal	and	the	environment	surrounding	the	transformer	and	discharge	canal, including	the	Hudson	River,	as	a	result	of	the	failure,	fire,	and	fire	suppression.	Once	the	fire	was	extinguished,	Indian	Point	personnel	and contractors	 began	 recovering	 free-product	 from	 the	 damaged	 transformer,	 the	 transformer	 containment	 moat,	 and	 the	 area	 surrounding	 the transformer.	The	United	States	Coast	Guard	designated	Entergy	as	the	responsible	party	under	the	Oil	Pollution	Act	of	1990	and	assessed	a $1,000	civil	penalty	for	the	discharge	of	oil	into	navigable	waters.	As	required,	Entergy	established	a	claims	process	including	a	voluntary	hotline. Entergy	received	no	reports	to	the	voluntary	hotline	or	claims	under	the	established	claims	process.	In	September	2016,	Indian	Point	personnel identified	an	oil	sheen	in	the	discharge	canal.	Further	investigation	revealed	that	an	estimated	600	gallons	of	lubricating	oil	had	leaked	from	the Indian	Point	3	turbine	system.	The	leaking	component	has	been	taken	out	of	service	and	no	oil	has	been	discovered	in	the	Hudson	River.	In October	2016	the	New	York	Department	of	Environmental	Conservation	issued	two	notices	of	violation,	one	for	each	of	these	events,	and	a proposed	order	on	consent	for	the	2015	event.	In	January	2017,	Entergy	and	the	New	York	Department	of	Environmental	Conservation	resolved this	matter	with	an	order	on	consent.	Pursuant	to	the	order,	Entergy	paid	approximately	$600	thousand	in	civil	penalties,	natural	resource	damages, and	oversight	costs.	Additionally,	Entergy	repaired	a	section	of	the	discharge	canal	wall	and	will	conduct	daily	visual	inspections	of	the	discharge canal	wall	to	help	identify	additional	material	erosion	or	material	structural	deficiencies.	Entergy	has	completed	all	compliance	obligations	under the	consent	order	and	the	Department	of	Environmental	Conservation	closed	the	matter	in	December	2017.

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.

See	Note	8	to	the	financial	statements	for	a	discussion	of	this	litigation.

Employment	and	Labor-related	Proceedings	(Entergy	Corporation,	Entergy	Arkansas,	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,	2017,	Entergy	subsidiaries	employed 13,504	people.

| Utility: |  |
| :--- | :--- |
| Entergy\tArkansas | 1,278 |
| Entergy\tLouisiana | 1,713 |
| Entergy\tMississippi | 737 |
| Entergy\tNew\tOrleans | 274 |
| Entergy\tTexas | 616 |
| System\tEnergy | — |
| Entergy\tOperations | 3,361 |
| Entergy\tServices | 3,264 |
| Entergy\tNuclear\tOperations | 2,211 |
| Other\tsubsidiaries | 50 |
| Total\tEntergy | 13,504 |

Approximately	4,600	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	annual	and	quarterly	reports	on Forms	10-K	and	10-Q	(including	related	filings	in	XBRL	format)	and	current	reports	on	Form	8-K;	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	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	can	be	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,	including	adjustment	upon	the	initiative	of	a	regulator	or	affected stakeholders.

In	addition,	regulators	may	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	may	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.		Traditional	base	rate	proceedings,	as	opposed	to	formula	rate	plans,	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	these	base	rate	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	Texas	are	established	largely	in	traditional	base	rate	case	proceedings.	Apart	from	base	rate	proceedings, Entergy	Texas	has	also	filed	to	use	rate	riders	to	recover	the	revenue	requirements	associated	with	certain	authorized	historical	costs.	For	example, Entergy	Texas	has	recovered	distribution-related	capital	investments	through	the	distribution	cost	recovery	factor	rider	mechanism,	transmission- related	capital	investments	and	certain	non-fuel	MISO	charges	through	the	transmission	cost	recovery	factor	rider	mechanism,	and	MISO	fuel	and energy-related	costs	through	the	fixed	fuel	factor	mechanism.	Entergy	Texas	is	also	required	to	make	a	filing	every	three	years,	at	a	minimum, reconciling	its	fuel	and	purchased	power	costs	and	fuel	factor	revenues.	In	the	course	of	this	reconciliation,	the	PUCT	determines	whether	eligible fuel	and	fuel-related	expenses	and	revenues	are	necessary	and	reasonable,	and	makes	a	prudence	finding	for	each	of	the	fuel-related	contracts	for the	reconciliation	period.

Between	base	rate	cases,	Entergy	Arkansas	and	Entergy	Mississippi	are	able	to	adjust	base	rates	annually	through	formula	rate	plans	that utilize	a	forward	test	year	(Entergy	Arkansas)	or	forward-looking	features	(Entergy	Mississippi).	In	response	to	Entergy	Arkansas's	application	for a	general	change	in	rates	in	2015,	the	APSC	approved	the	formula	rate	plan	tariff	proposed	by	Entergy	Arkansas	including	its	use	of	a	projected year	test	period	and	an	initial	five-year	term.	The	initial	five-year	term	expires	in	2021	unless	Entergy	Arkansas	requests,	and	the	APSC	approves, the	extension	of	the	formula	rate	plan	tariff	for	an	additional	five	years	through	2026.	In	the	event	that	Entergy	Arkansas's	formula	rate	plan	is terminated	or	is	not	extended	beyond	the	initial	term,	Entergy	Arkansas	could	file	an

application	for	a	general	change	in	rates	that	may	include	a	request	for	continued	regulation	under	a	formula	rate	review	mechanism.	If	Entergy Mississippi's	formula	rate	plan	is	terminated,	it	would	revert	to	the	more	traditional	rate	case	environment	or	seek	approval	of	a	new	formula	rate plan.	Entergy	Arkansas	and	Entergy	Mississippi	recover	fuel	and	purchased	energy	and	certain	non-fuel	costs	through	other	APSC-approved	and MPSC-approved	tariffs,	respectively.

Entergy	Louisiana	historically	sets	electric	base	rates	annually	through	a	formula	rate	plan	using	an	historic	test	year.	The	form	of	the formula	rate	plan,	on	a	combined	basis,	was	approved	in	connection	with	the	business	combination	of	Entergy	Louisiana	and	Entergy	Gulf	States Louisiana	and	largely	followed	the	formula	rate	plans	that	were	approved	by	the	LPSC	in	connection	with	the	full	electric	base	rate	cases	filed	by those	companies	in	February	2013.	The	formula	rate	plan	was	approved	for	continued	use	through	the	test	year	2016	filing	and	included	a	cap	in cost	of	service	increases	at	a	cumulative	total	of	$30	million	through	the	formula	rate	plan	cycle,	which	cap	was	not	reached.	The	LPSC	also approved	 in	 the	business	combination	Entergy	Louisiana's	continuation	of	a	mechanism	 to	recover	non-fuel	MISO-related	costs,	which	are calculated	separately	from	the	formula	rate	plan	requirements,	but	embedded	in	the	formula	rate	plan	factor	applied	on	customer	bills.	This recovery	mechanism	expired	following	the	2015	test	year,	but	was	renewed	for	the	2016	test	year.	MISO	fuel	and	energy-related	costs	are recoverable	in	Entergy	Louisiana's	fuel	adjustment	clause.	The	formula	rate	plan	includes	exceptions	from	the	rate	cap	and	sharing	requirements for	certain	large	capital	investment	projects,	including	acquisition	or	construction	of	generating	facilities,	as	well	as	purchase	power	agreements approved	by	the	LPSC,	among	other	items.	In	August	2017,	Entergy	Louisiana	filed	to	extend	the	formula	rate	plan	for	an	additional	three	years and	to	reset	rates	to	the	authorized	mid-point	return	on	equity	of	9.95%.	The	filing	also	seeks	certain	modifications	to	the	formula	rate	plan, including	 a	 narrower,	 80	 basis	 points	 earnings	 sharing	 bandwidth	 and	 implementation	 of	 a	 rider	 to	 recover	 certain	 transmission-related investments,	when	those	investments	begin	delivering	benefits	to	customers.	In	the	event	that	the	electric	formula	rate	plan	is	not	renewed	or extended,	Entergy	Louisiana	would	revert	to	the	more	traditional	rate	case	environment.

Entergy	New	Orleans	previously	operated	under	a	formula	rate	plan	that	ended	with	the	2011	test	year.	Currently,	based	on	a	settlement agreement	approved	by	the	City	Council,	with	limited	exceptions,	no	action	may	be	taken	with	respect	to	Entergy	New	Orleans's	base	rates	until rates	 are	 implemented	 from	 a	 base	 rate	 case	 that	 must	 be	 filed	 for	 its	 electric	 and	 gas	 operations	 in	 2018.	The	 limited	 exceptions	 include implementation	of	the	final	year	of	a	four-year	phased-in	rate	increase	for	its	Algiers	operations	in	the	Fifteenth	Ward	of	the	City	of	New	Orleans and	certain	exceptional	cost	increases	or	decreases	in	its	base	revenue	requirement.

The	rates	of	System	Energy	are	established	by	the	FERC,	and	the	costs	allowed	to	be	charged	pursuant	to	these	rates	are,	in	turn,	passed through	to	the	participating	Utility	operating	companies	through	the	Unit	Power	Sales	Agreement,	which	allows	monthly	adjustments	to	reflect	the current	operating	costs	of,	and	investment	in,	Grand	Gulf.

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	in	spending,	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	the	Utility	operating	companies,	see	Note	2	to	the	financial	statements.

# The	Utility	operating	companies	recover	fuel,	purchased	power,	and	associated	costs	through	rate	mechanisms	that	are	subject	to	risks of	delay	or	disallowance	in	regulatory	proceedings.

The	Utility	operating	companies	recover	their	fuel,	purchased	power,	and	associated	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,	including	the	cost	of	replacement	power	purchased	when	generators	experience	outages,	with	the	possibility	of	refunds	to ratepayers,	there	exists	some	risk	to	the	ultimate	recovery	of	those	costs.		Regulators	may	also	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	and,	therefore,	there	can be	no	assurance	that	existing	recovery	mechanisms	will	remain	unchanged	or	in	effect	at	all.

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.

# There	remains	uncertainty	regarding	the	effect	of	the	termination	of	the	System	Agreement	on	the	Utility	operating	companies.

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	had	been	approved	by	the	FERC. The	System	Agreement	terminated	in	its	entirety	on	August	31,	2016.

There	remains	uncertainty	regarding	the	long-term	effect	of	the	termination	of	the	System	Agreement	on	the	Utility	operating	companies because	of	 the	significant	effect	of	 the	agreement	on	 the	generation	and	 transmission	functions	of	 the	Utility	operating	companies	and	 the significant	period	of	time	(over	30	years)	that	it	had	been	in	existence.	In	the	absence	of	the	System	Agreement,	there	remains	uncertainty	around the	effectiveness	of	governance	processes	and	the	potential	absence	of	federal	authority	to	resolve	certain	issues	among	the	Utility	operating companies	and	their	retail	regulators.

In	 addition,	 although	 the	 System	Agreement	 terminated	 in	 its	 entirety	 in	August	 2016,	 there	 are	 a	 number	 of	 outstanding	 System Agreement	proceedings	at	the	FERC	that	may	require	future	adjustments,	including	challenges	to	the	level	and	timing	of	payments	made	by Entergy	Arkansas	under	the	System	Agreement.	The	outcome	and	timing	of	these	FERC	proceedings	and	resulting	recovery	and	impact	on	rates cannot	be	predicted	at	this	time.

For	further	information	regarding	the	regulatory	proceedings	relating	to	the	System	Agreement,	see	Note	2	to	the	financial	statements.

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.	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	pursuant	to	the	MISO	tariff	and	market	rules.	The	Utility	operating	companies	are	subject	to	economic	risks	associated with	participation	in	the	MISO	markets.	MISO	tariff	rules	and	system	conditions,	including	transmission	congestion,	could	affect	the	Utility operating	companies'	ability	to	sell	power	in	certain	regions	and/or	the	economic	value	of	such	sales,	and	MISO	market	rules	may	change	in	ways that	cause	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	pay	transmission	rates	that	reflect	the	cost	of	transmission	projects	that	the Utility	operating	companies	do	not	own,	which	could	increase	cash	or	financing	needs.	MISO	is	currently	evaluating	through	its	stakeholder process	potential	changes	in	the	transmission	project	criteria	in	MISO.	These	changes,	if	adopted,	could	potentially	result	in	a	larger

volume	of	competitively	bid	and	regionally	cost	allocated	transmission	projects.	In	addition	to	the	cash	and	financing-related	risks	arising	from	the potential	additional	cost	allocation	to	the	Utility	operating	companies	from	these	projects,	there	is	a	risk	that	the	Utility	operating	companies' business	and	financial	position	could	be	harmed	as	a	result	of	lost	investment	opportunities	and	other	effects	that	flow	from	an	increased	number of	competitive	projects	being	approved	and	constructed	that	are	interconnected	with	their	transmission	systems.	Further,	the	terms	and	conditions of	the	MISO	tariff,	including	provisions	related	to	the	design	and	implementation	of	wholesale	markets	and	the	allocation	of	transmission	upgrade costs,	are	subject	to	regulation	by	the	FERC.	The	operation	of	the	Utility	operating	companies'	transmission	system	pursuant	to	the	MISO	tariff and	their	participation	in	the	MISO	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.	In	addition,	orders	from	each	of	the	Utility	operating companies'	respective	retail	regulators	generally	require	that	the	Utility	operating	companies	make	periodic	filings	setting	forth	the	results	of analysis	of	the	costs	and	benefits	realized	from	MISO	membership	as	well	as	the	projected	costs	and	benefits	of	continued	membership	in	MISO and/or	 requesting	 approval	 of	 their	 continued	 membership	 in	 MISO.	These	 filings	 have	 been	 submitted	 periodically	 by	 each	 of	 the	 Utility operating	companies	as	required	by	their	respective	retail	regulators,	and	the	outcome	of	the	resulting	proceedings	may	affect	the	Utility	operating companies'	continued	membership	in	MISO.

# (Entergy	Corporation,	Entergy	Arkansas,	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,	Shutdown	and	Regulatory	Risks

# (Entergy	Corporation,	Entergy	Arkansas,	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,	consistent	with	safety	requirements.	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'	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'	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	the	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,	enrichment,	and	fabrication).	These	risks	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	2018.		The	nuclear	fuel	supply	portfolio	for	the	Entergy	Wholesale	Commodities	segment	is	being	adjusted	to	reflect	reduced overall	requirements	related	to	the	planned	permanent	shutdown	of	the	Palisades,	Pilgrim,	Indian	Point	2	and	Indian	Point	3	plants	over	the	next two	to	five	years.	Entergy's	ability	to	purchase	nuclear	fuel	at	reasonably	predictable	prices,	however,	depends	upon	the	performance	reliability	of uranium	miners.	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	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	changes	could	materially	affect the	liquidity,	financial	condition,	and	results	of	operations	of	certain	of	the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale Commodities.

Entergy's	 ability	 to	 assure	 nuclear	 fuel	 supply	 also	 depends	 upon	 the	 performance	 and	 reliability	 of	 conversion,	 enrichment,	 and fabrication	 services	 providers.	These	service	providers	are	fewer	in	number	than	uranium	suppliers.	For	conversion	and	enrichment	services, Entergy	 diversifies	 its	 supply	 by	 supplier	 and	 country	 and	 may	 take	 special	 measures	 to	 ensure	 a	 reliable	 supply	 of	 enriched	 uranium	 for fabrication	into	nuclear	fuel.	For	fabrication	services,	each	plant	is	dependent	upon	the	performance	of	the	fabricator	of	that	plant's	nuclear	fuel; therefore,	Entergy	relies	upon	additional	monitoring,	inspection,	and	oversight	of	the	fabrication	process	to	assure	reliability	and	quality	of	its nuclear	 fuel.	Certain	of	the	suppliers	and	service	providers	are	located	in	or	dependent	upon	countries,	such	as	Russia,	in	which	deteriorating economic	conditions	or	international	sanctions	could	restrict	the	ability	of	such	suppliers	to	continue	to	supply	fuel	or	provide	such	services.		The inability	of	such	suppliers	or	service	providers	to	perform	such	obligations	could	materially	affect	the	liquidity,	financial	condition,	and	results	of operations	of	certain	of	the	Utility	operating	companies,	System	Energy,	and	Entergy	Wholesale	Commodities.

Entergy	Arkansas,	Entergy	Louisiana,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business	face	the	risk	that	the	NRC will	change	or	modify	its	regulations,	suspend,	not	renew,	or	revoke	their	licenses,	or	increase	oversight	of	their	nuclear	plants,	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,	not	renew,	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.	The	license	renewal	process	in	some	cases	may	be	the	subject	of	significant	public	debate	and	legislative	review	and	scrutiny	at the	federal	and,	in	some	cases,	state	level,	though	the	decision	whether	to	renew	is	subject	to	the	exclusive	jurisdiction	of	the	NRC.	Interested parties	may	also	intervene	which	could	result	in	prolonged	proceedings.	A	change	in	the	Atomic	Energy	Act,	other	applicable	statutes,	or	the applicable	regulations	or	licenses,	or	the	NRC's	interpretation	thereof,	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.		A	change	in	the	classification	of	a	plant	owned	by one	of	these	companies	under	the	NRC's	Reactor	Oversight	Process,	which	is	the	NRC's	program	to	collect	information	about	plant	performance, assess	the	information	for	its	safety	significance,	and	provide	for	appropriate	licensee	and	NRC	response,	also	could	cause	the	owner	of	the	plant to	 incur	material	additional	costs	as	a	result	of	 the	 increased	oversight	activity	and	potential	response	costs	associated	with	 the	change	 in classification.	For	additional	information	concerning	the	current	classification	of	the	plants	owned	by	Entergy	Arkansas,	Entergy	Louisiana, System	Energy,	and	the	Entergy	Wholesale	Commodities	business,	see	"Regulation	of	Entergy's	Business	-	Regulation	of	the	Nuclear	Power Industry	-	NRC	Reactor	Oversight	Process"	in	Part	I,	Item	1	and	Note	8	to	the	financial	statements.

Events	at	nuclear	plants	owned	by	one	of	these	companies,	as	well	as	those	owned	by	others,	may	lead	to	a	change	in	laws	or	regulations or	the	terms	of	the	applicable	licenses,	or	the	NRC's	interpretation	thereof,	or	may	cause	the	NRC	to	increase	oversight	activity	or	initiate	actions to	modify,	suspend,	or	revoke	licenses,	shut	down	a	nuclear	facility,	or	impose	civil	penalties.		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.

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	safely	and	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 increased	 costs,	 some	 of	 which	 costs	 may	 not	 be	 fully	 recoverable	 by	 the	 Utility	 operating	 companies	 and	 System	 Energy	 in	 regulatory proceedings.		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	the	Utility	operating	companies	and	System	Energy,	this	could	result	in	certain	costs	being	stranded	and	potentially	not	fully recoverable	in	regulatory	proceedings.	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.	In	addition,	the	operation and	maintenance	of	Entergy's	nuclear	facilities	require	the	commitment	of	substantial	human	resources	that	can	result	in	increased	costs.

The	nuclear	industry	continues	to	address	susceptibility	to	the	effects	of	stress	corrosion	cracking	and	other	corrosion	mechanisms	on certain	materials	within	plant	systems.		The	issue	is	applicable	at	all	nuclear	units	to	varying	degrees	and	is	managed	in	accordance	with	industry standard	practices	and	guidelines	that	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.

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	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	NRC	licensing	of the	Yucca	Mountain	repository	is	effectively	at	a	standstill.	These	actions	are	prolonging	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 will	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	 and	 maintenance	 costs	 on	 existing	 storage	 facilities,	 including	 aging management	of	fuel	storage	casks,	may	increase.		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	Louisiana,	and	System	Energy	and	Note	8	to	the	financial	statements.

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	$127.3	million	per	reactor.			With	102	reactors	currently	participating,	this	translates	to	a	total public	liability	cap	of	approximately	$13	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	(which	is	$450	million	for	each	operating	site	as	of	January	1,	2018).		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	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	primary	insurance	level,	up	to a	maximum	of	approximately	$127.3	million	per	reactor	per	incident	(Entergy's	maximum	total	contingent	obligation	per	incident	is	$1.146 billion).		The	retrospective	premium	payment	is	currently	limited	to	approximately	$19	million	per	year	per	incident	per	reactor	until	the	aggregate public	liability	for	each	licensee	is	paid	up	to	the	$127.3	million	cap.

NEIL	is	a	utility	industry	mutual	insurance	company,	owned	by	its	members,	including	the	Utility	operating	companies,	System	Energy, and	 the	 owners	 of	 the	 Entergy	Wholesale	 Commodities	 plants.	All	member	plants	could	be	subject	 to	an	annual	assessment	(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	December	31,	2017,	the	maximum	annual	assessment	amounts	total	$112.2	million	for	the	Utility	plants.		Retrospective	premium	insurance available	 through	 NEIL's	 reinsurance	 treaty	 can	 cover	 the	 potential	 assessments	 and	 the	 Entergy	 Wholesale	 Commodities	 plants	 currently maintain	the	retrospective	premium	insurance	to	cover	those	potential	assessments.

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.

The	decommissioning	trust	fund	assets	for	the	nuclear	power	plants	owned	by	the	Utility	operating	companies,	System	Energy	and	the Entergy	Wholesale	Commodities	nuclear	plant	owners	may	not	be	adequate	to	meet	decommissioning	obligations	if	market	performance	and other	changes	decrease	the	value	of	assets	in	the	decommissioning	trusts,	if	one	or	more	of	Entergy's	nuclear	power	plants	is	retired	earlier than	the	anticipated	shutdown	date,	if	the	plants	cost	more	to	decommission	than	estimated,	or	if	current	regulatory	requirements	change, 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,	as	adjusted	from	time	to	time	by	rate	regulators,	are	generally	based	upon	operating	license lives	and	trust	fund	balances	as	well	as	estimated	trust	fund	earnings	and	decommissioning	costs.		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.

In	connection	with	the	acquisition	of	certain	nuclear	plants,	the	Entergy	Wholesale	Commodities	plant	owners	acquired	decommissioning trust	funds	that	are	funded	in	accordance	with	NRC	regulations.		Under	NRC	regulations,	Entergy	Wholesale	Commodities'	nuclear	subsidiaries are	permitted	to	project	the	NRC-required	decommissioning	amount,	based	on	an	NRC	formula	or	a	site-specific	estimate,	and	the	amount	that will	 be	 available	 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	 individual	 plants'	 decommissioning	 trusts	 exceeds	 the	 NRC-required decommissioning	amount,	then	its	decommissioning	obligations	are	considered	to	be	funded	in	accordance	with	NRC	regulations.		If	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,	or	funding	is	otherwise	inadequate,	or	if	the	formula,	formula	inputs,	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.

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	or may	restrict	the	decommissioning-related	costs	that	can	be	paid	from	the	decommissioning	trusts.		As	a	result,	under	any	of	these	circumstances, Entergy's	results	of	operations,	liquidity,	and	financial	condition	could	be	materially	affected.

An	 early	 plant	 shutdown	 (either	 generally	 or	 relative	 to	 current	 expectations),	 poor	 investment	 results	 or	 higher	 than	 anticipated decommissioning	costs	(including	as	a	result	of	changing	regulatory	requirements)	could	cause	trust	fund	assets	to	be	insufficient	to	meet	the decommissioning	obligations,	with	the	result	that	the	Utility	operating	companies,	System	Energy	or	the	Entergy	Wholesale	Commodities	nuclear plant	owners	may	be	required	to	provide	significant	additional	funds	or	credit	support	to	satisfy	regulatory	requirements	for	decommissioning, which,	with	respect	to	the	Utility	operating	companies,	may	not	be	recoverable	from	customers	in	a	timely	fashion	or	at	all.

For	further	information	regarding	nuclear	decommissioning	costs,	management's	decision	to	exit	the	merchant	power	business	and	the impairment	charges	that	resulted	from	such	decision,	see	the	"Critical	Accounting	Estimates	-	Nuclear	Decommissioning	Costs"	section	of Management's	 Financial	 Discussion	 and	 Analysis	 for	 Entergy,	 Entergy	 Arkansas,	 Entergy	 Louisiana,	 and	 System	 Energy, the	 " Entergy Wholesale	Commodities	Exit	from	the	Merchant	Power	Business"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy Corporation	and	Subsidiaries	and	Notes	9	and	14	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	 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	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	and	decommissioning	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	 most	 of	 the	 current	 fleet	 of	 Entergy	 Wholesale	 Commodities	 nuclear	 power	 plants	 is 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,	additional	requirements	or	restrictions	related	to	spent	nuclear	fuel	on-site	storage	and eventual	disposal,	or	other	adverse	effects	on	owning,	operating	and	decommissioning	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' Indian	Point	nuclear	power	plants	could	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition,	and	liquidity	and	could lead	to	an	acceleration	of	the	timing	for	the	funding	of	decommissioning	obligations.

The	license	renewal	and	related	processes	for	the	Entergy	Wholesale	Commodities'	Indian	Point	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	date	of	the	operating	license	for	Indian	Point	2	was	September	2013	and	the	original	expiration	date	of	the	operating license	for	Indian	Point	3	was	December	2015.		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.

In	January	2017,	Entergy	announced	that	it	plans	to	shut	down	Indian	Point	2	in	2020	and	Indian	Point	3	in	2021.	The	early	and	orderly shutdown	is	part	of	a	settlement	under	which	New	York	State	has	agreed	to	drop	legal	challenges	and	support	renewal	of	the	operating	licenses	for Indian	 Point.	For	 additional	 discussion	 of	 the	 settlement	 agreement	 with	 New	 York	 State,	 see	 the "Entergy	 Wholesale	 Commodities Authorizations	to	Operate	Indian	Point"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

If	the	NRC	were	to	deny	the	applications	for	the	renewal	of	operating	licenses	for	the	Indian	Point	nuclear	power	plants,	or	if	Indian	Point fails	to	obtain	other	approvals,	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	until	the	proposed	shutdown	date,	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	Indian	Point	nuclear	power	plants,	see	the	"Entergy	Wholesale	Commodities	Authorizations	to Operate	Indian	Point"	in	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis.

# 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.		As	a result,	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,	2017,	Entergy	Wholesale Commodities'	nuclear	power	generation	plants	had	sold	forward	98%	in	2018,	91%	in	2019,	51%	in	2020,	74%	in	2021,	and	67%	in	2022	of	its generation	portfolio's	planned	energy	output,	reflecting	the	planned	shutdown	or	sale	of	the	Entergy	Wholesale	Commodities	nuclear	power plants	by	mid-2022.

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	effects	of	sustained	low	natural	gas	prices	and	power	market	structure	challenges	have	resulted	in	lower	market	prices	for	electricity in	the	power	regions	where	the	Entergy	Wholesale	Commodities	nuclear	power	plants	are	located.	In	addition,	currently	the	market	design	under which	the	plants	operate	does	not	adequately	compensate	merchant	nuclear	plants	for	their	environmental	and	fuel	diversity	benefits	in	the	region. These	conditions	were	primary	factors	leading	to	Entergy's	decision	to	shut	down	(or	sell)	Entergy	Wholesale	Commodities'	nuclear	power	plants before	the	end	of	their	operating	licenses	(or	requested	operating	licenses	for	Indian	Point	2	and	Indian	Point	3).

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'	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'	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	"Market	and	Credit	Risk	Sensitive	Instruments"	section	of	Management's	Financial	Discussion	and	Analysis	for	Entergy Corporation	and	Subsidiaries.		Since	Entergy	Wholesale	Commodities	has	announced	the	closure	(or	sale)	of	its	nuclear	plants,	Entergy	Wholesale Commodities	may	enter	into	fewer	forward	sales	contracts	for	output	from	such	plants.

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'	nuclear	markets; •union	and	labor	relations;

•changes	in	Federal	and	state	energy	and	environmental	laws	and	regulations	and	other	initiatives,	such	as	the	Regional	Greenhouse	Gas Initiative,	including	but	not	limited	to,	the	price	impacts	of	proposed	emission	controls;

•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	regulation	under	federal,	state,	and	local	laws.	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	that	generates	electricity,	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	and/or	owning wholesale	electric	transmission	facilities.		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'	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'	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'	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	may	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.	Further,	 the	 New	York	 Independent	 System Operator	could	determine	that	the	timing	of	the	shutdown	of	the	Indian	Point	units	could	be	inconsistent	with	its	market	power	rules,	and	impose certain	penalties	that	could	affect	Entergy	Wholesale	Commodities.	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	is	subject	to	changes	as	a	result	of	restructuring	initiatives	at	both	the state	and	federal	levels.	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,	 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,	and	have made	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	expected	operating	life	of	the	assets,	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	further	impairment	in connection	with	the	closure	or	sale	of	the	plants	discussed	below.	Moreover,	prior	to	the	closure	or	sale	of	these	plants,	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,	a	reduction	in	the	expected	remaining	useful	life	of	a	unit	(including	if	the	operating	licenses	for	the	Indian	Point	power	plants	are	not renewed	by	the	NRC),	or	a	decline	in	observable	industry	market	multiples	could	all	result	in	potential	additional	impairment	charges	for	the affected	assets.

On	August	 27,	 2013,	 Entergy	 announced	 its	 plan	 to	 close	 and	 decommission	 Vermont	 Yankee.	 	 Vermont	 Yankee	 ceased	 power production	in	the	fourth	quarter	2014	at	the	end	of	a	fuel	cycle.		This	decision	was	approved	by	the	Board	in	August	2013,	and	resulted	in	the recognition	of	impairment	charges	in	2013	and	2014.	In	October	2015,	Entergy	determined	that	it	will	close	the	Pilgrim	and	FitzPatrick	plants. The	Pilgrim	plant	will	cease	operations	no	later	than	June	1,	2019.	FitzPatrick	was	expected	to	shut	down	at	the	end	of	its	current	fuel	cycle, planned	for	January	27,	2017,	but	in	March	2017,	Entergy	sold	the	FitzPatrick	plant	to	Exelon	Generation	Company,	LLC	which	continues	to operate	the	plant.	During	the	third	quarter	2015,	Entergy	recorded	impairment	and	other	related	charges	to	write	down	the	carrying	values	of	the FitzPatrick	and	Pilgrim	plants	and	related	assets	to	their	fair	values.	In	addition,	in	the	fourth	quarter	2015,	Entergy	recorded	impairment	and	other related	charges	to	write	down	the	carrying	value	of	the	Palisades	plant	and	related	assets	to	their	fair	value.	In	December	2016,	Entergy	reached	an agreement	with	Consumers	Energy	to	terminate	the	PPA	for	the	Palisades	plant	and	to	shut	down	the	plant	in	2018,	but	the	agreement	was terminated	in	September	2017	after	the	Michigan	Public	Service	Commission	decided	that	Consumers	Power	could	not	recover	costs	incurred under	the	agreement.	Entergy	intends	to	shut	down	the	Palisades	plant	permanently	on	May	31,	2022.	In	January	2017,	Entergy	announced	that	it reached	a	settlement	with	New	York	State	and	plans	to	close	the	Indian	Point	2	plant	in	2020	and	the	Indian	Point	3	plant	in	2021.	As	a	result,	in the	fourth	quarter	of	2016,	Entergy	recorded	impairment	and	other	related	charges	to	write	down	the	carrying	values	of	the	Palisades	and	Indian Point	2	and	Indian	Point	3	plants	and	related	assets	to	their	fair	value.	In	addition	to	the	impairments	and	other	related	charges,	Entergy	has incurred	severance	and	employee	retention	costs	and	expects	to	incur	additional	charges	through	2022	relating	to	the	decisions	to	shut	down Vermont	Yankee,	Palisades,	Pilgrim,	Indian	Point	2	and	Indian	Point	3,	and	the	sale	of	FitzPatrick.

If	Entergy	concludes	that	any	of	its	nuclear	power	plants	is	unlikely	to	operate	through	its	planned	shutdown	date,	which	conclusion	would be	based	on	a	variety	of	factors,	such	a	conclusion	could	result	in	a	further	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.	For	further	information	regarding	evaluating	long-lived	assets	for	impairment,	see	the "Critical	Accounting	 Estimates -	Impairment	 of	 Long-lived	Assets	 and	 Trust	 Fund	 Investments"	 section	 of	 Management's	 Financial Discussion	and	Analysis	for	Entergy	Corporation	and	Subsidiaries	and	for	further	discussion	of	the	impairment	charges,	see	Note	14	to	the financial	statements.

# 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,	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	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	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, 2017,	based	on	power	prices	at	that	time,	Entergy	had	liquidity	exposure	of	$167	million	under	the	guarantees	in	place	supporting	Entergy Wholesale	Commodities	transactions	and	$8	million	of	posted	cash	collateral.	In	the	event	of	a	decrease	in	Entergy	Corporation's	credit	rating	to below	investment	grade,	based	on	power	prices	as	of	December	31,	2017,	Entergy	would	have	been	required	to	provide	approximately	$98 million	of	additional	cash	or	letters	of	credit	under	some	of	the	agreements.	In	the	event	of	a	decrease	in	the	credit	ratings	of	Entergy's	Utility operating	companies	to	below	investment	grade,	those	companies	collectively	could	be	required	to	provide	up	to	$50	million	of	additional	cash	or letters	 of	 credit	 to	 MISO.	As	 of	 December	 31,	 2017,	 the	 liquidity	 exposure	 associated	 with	 Entergy	 Wholesale	 Commodities	 assurance requirements,	including	return	of	previously	received	collateral	from	counterparties,	would	increase	by	$372	million	for	a	$1	per	MMBtu	increase in	gas	prices	in	both	the	short-	and	long-term	markets.

# Recent	U.S.	tax	legislation	may	materially	adversely	affect	Entergy's	financial	condition,	results	of	operations,	cash	flows,	and	credit

# ratings.

The	recently	enacted	H.R.	1,	also	known	as	the	Tax	Cuts	and	Jobs	Act	of	2017,	will	significantly	change	the	U.S.	Internal	Revenue	Code, including	taxation	of	U.S.	corporations,	by,	among	other	things,	reducing	the	federal	corporate	income	tax	rate,	limiting	interest	deductions,	and altering	the	expensing	of	capital	expenditures.	The	legislation	is	unclear	in	certain	respects	and	will	require	interpretations	and	implementing regulations	by	the	IRS,	as	well	as	state	tax	authorities,	and	the	legislation	could	be	subject	to	potential	amendments	and	technical	corrections,	any of	which	could	 lessen	or	 increase	certain	 impacts	of	 the	 legislation.	In	addition,	 the	regulatory	 treatment	of	 the	 impacts	of	 this	 legislation, particularly	on	companies	like	Entergy	and	the	Registrant	Subsidiaries,	will	be	subject	to	the	discretion	of	federal,	state,	and	local	public	utility regulators.

As	further	described	in	Note	3	to	the	financial	statements,	Entergy	recorded	a	reduction	of	certain	of	its	net	deferred	income	tax	assets (including	the	value	of	its	net	operating	loss	carryforwards)	and	regulatory	liabilities,	resulting	in	a	charge	against	earnings	in	the	fourth	quarter 2017	of	$526	million,	including	a	$34	million	net-of-tax	reduction	of	regulatory	liabilities,	and	Entergy	and	the	Utility	operating	companies recorded	a	reduction	of	approximately	$3.7	billion	on	a	consolidated	basis	in	certain	of	its	net	deferred	tax	liabilities	and	a	corresponding	increase in	net	regulatory	liabilities.	Depending	on	the	outcome	of	the	ratemaking	process,	IRS	examinations,	or	tax	positions	and	elections	that	Entergy may	elect,	Entergy	and	the	Registrant	Subsidiaries	may	be	required	to	record	additional	charges	or	credits	to	income	tax	expense.	Further,	the amount	and	timing	of	the	return	of	the	deferred	taxes	to	customers	is	dependent	upon	the	regulatory	treatment	received,	and,	if	the	Registrant Subsidiaries	are	unsuccessful	 in	receiving	balanced	regulatory	 treatment,	Entergy's	or	 the	Utility	operating	companies'	cash	flow	could	be materially	 adversely	 affected.	Further,	there	may	be	other	material	effects	resulting	from	the	legislation	that	have	not	been	identified.	While Entergy	plans	to	finance	its	cash	needs	that	result	from	the	Act	through	a	combination	of	Registrant	Subsidiary	debt	and	Entergy	Corporation	debt and	equity,	there	can	be	no	assurance	that	Entergy	or	the	Registrant	Subsidiaries	will	obtain	debt	or	equity	financing	on	terms	that	are	satisfactory or	consistent	with	their	current	expectations.

In	addition,	while	Moody's	changed	the	ratings	outlooks	for	Entergy	Corporation	to	negative	from	stable	in	reaction	to	the	legislation,	it	is unclear	when	or	how	capital	markets,	other	credit	rating	agencies,	the	FERC	or	state	or	local	regulators	may	respond	to	this	legislation.	Entergy expects	that	certain	financial	metrics	used	by	credit	rating	agencies	will	be	negatively	affected	as	a	result	of	the	return	of	excess	deferred	taxes	to customers,	increased	debt,	and	the	decrease	in	the	Registrant	Subsidiaries'	revenue	requirements,	and	related	decrease	in	operating	cash	flows, expected	as	a	consequence	of	the	lower	federal	corporate	income	tax	rate	while,	at	the	same	time,	the	loss	of	the	bonus	depreciation	tax	deduction will	increase	taxable	income	in	the	future.	Also,	the	timing	of	the	return	of	excess	deferred	income	taxes

to	customers	will	not	exactly	match	the	lower	taxes	that	Entergy	will	be	paying	which	will	result	in	cash	outflows	to	customers.	It	is	also	uncertain how	other	credit	rating	agencies	will	treat	the	impacts	of	this	legislation	on	their	credit	ratings	and	metrics,	and	whether	additional	avenues	will evolve	for	companies	to	manage	the	adverse	aspects	of	this	legislation.	These	avenues,	to	the	extent	available	and	if	successfully	applied,	could lessen	the	impacts	on	certain	credit	metrics,	although	there	can	be	no	assurance	in	this	regard.

Entergy	believes	that	interpretations	and	implementing	regulations	by	the	IRS,	as	well	as	potential	amendments	and	technical	corrections, could	result	in	lessening	the	impacts	of	certain	aspects	of	this	legislation.	If	Entergy	is	unable	to	successfully	pursue	avenues	to	manage	the	effects of	 the	 new	 tax	 legislation,	 or	 if	 additional	 interpretations,	 regulations,	 amendments,	 or	 technical	 corrections	 exacerbate	 the	 effects	 of	 the legislation,	the	legislation	could	have	a	material	effect	on	Entergy's	results	of	operations,	financial	condition,	and	cash	flows,	and	could	result	in additional	credit	rating	agency	actions.	Any	such	actions	by	credit	rating	agencies	may	make	it	more	difficult	and	costly	for	Entergy	to	issue	debt securities	and	certain	other	types	of	financing	and	could	increase	borrowing	costs	under	its	credit	facilities.

For	 further	 information	 regarding	 the	 effects	 of	 the	 Act,	 see the	 "Income	 Tax	 Legislation" section	 of	 Management's	 Financial Discussion	and	Analysis	for	Entergy.	Also,	Note	3	to	the	financial	statements	contains	additional	discussion	of	the	effect	of	the	Act	on	2017 results	of	operations	and	financial	position,	the	provisions	of	the	Act,	and	the	uncertainties	associated	with	accounting	for	the	Act,	and	Note	2	to the	financial	statements	discusses	proceedings	commenced	or	other	responses	by	Entergy's	regulators	to	the	Act.

# 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	 provisions	 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	income	taxes,	see	Note	3	to	the	financial	statements.

Entergy	and	its	subsidiaries'	ability	to	successfully	complete	strategic	transactions,	including	merger,	acquisition,	divestiture,	joint venture,	 restructuring	 or	 other	 strategic	 transactions,	 is	 subject	 to	 significant	 risks,	 including	 the	 risk	 that	 required	 regulatory	 or governmental	approvals	may	not	be	obtained,	risks	relating	to	unknown	or	undisclosed	problems	or	liabilities,	and	the	risk	that	for	these	or other	reasons,	Entergy	and	its	subsidiaries	may	be	unable	to	achieve	some	or	all	of	the	benefits	that	they	anticipate	from	such	transactions.

From	 time	 to	 time,	 Entergy	 and	 its	 subsidiaries	 have	 pursued	 and	 may	 continue	 to	 pursue	 strategic	 transactions	 including	 merger, acquisition,	divestiture,	joint	venture,	restructuring	or	other	strategic	transactions.	For	example,	in	November	2016,	Entergy	announced	that	it	had entered	into	a	purchase	and	sale	agreement	with	NorthStar	for	the	sale	of	100%	of	the	membership	interests	in	Entergy	Nuclear	Vermont	Yankee, which	owns	the	Vermont	Yankee	plant.	 In	addition,	as	part	of	Entergy's	plan	to	exit	the	merchant	power	business,	it	plans	to	shut	down	its remaining	merchant	nuclear	power	plants	by	mid-2022.	These	transactions	and	plans	are	or	may	become	subject	to	regulatory	approval	and	other material	conditions	or	contingencies.	The	failure	to	complete	these	transactions	or	plans	or	any	future	strategic	transaction	successfully	or	on	a timely	basis	could	have	an	adverse	effect	on	Entergy's	financial	condition,	results	of	operations	and	the	market's	perception	of	Entergy's	ability	to execute	 its	 strategy.	Further,	 these	 transactions,	 and	 any	 completed	 or	 future	 strategic	 transactions,	 involve	 substantial	 risks,	 including	 the following:

•the	disposition	of	a	business	or	asset	may	involve	continued	financial	involvement	in	the	divested	business,	such	as	through continuing	equity	ownership,	transition	service	agreements,	guarantees,	indemnities,	or	other	current	or	contingent	financial obligations;

•Entergy	may	encounter	difficulty	in	finding	buyers	or	executing	alternative	exit	strategies	on	acceptable	terms	in	a	timely	manner when	it	decides	to	sell	an	asset	or	a	business,	which	could	delay	the	accomplishment	of	its	strategic	objectives.	Alternatively,

Entergy	may	dispose	of	a	business	or	asset	at	a	price	or	on	terms	that	are	less	than	what	it	had	anticipated,	or	with	the	exclusion	of assets	that	must	be	divested	or	run	off	separately;

•the	disposition	of	a	business	could	result	in	impairments	and	related	write-offs	of	the	carrying	values	of	the	relevant	assets;

•acquired	businesses	or	assets	may	not	produce	revenues,	earnings	or	cash	flow	at	anticipated	levels;

•acquired	businesses	or	assets	could	have	environmental,	permitting	or	other	problems	for	which	contractual	protections	prove inadequate;

•Entergy	and/or	its	subsidiaries	may	assume	liabilities	that	were	not	disclosed	to	them,	that	exceed	their	estimates,	or	for	which	their rights	to	indemnification	from	the	seller	are	limited;

•the	disposition	of	a	business,	including	Entergy's	planned	exit	from	the	merchant	power	business,	could	divert	management's attention	from	other	business	concerns;

•Entergy	and/or	its	subsidiaries	may	be	unable	to	obtain	the	necessary	regulatory	or	governmental	approvals	to	close	a	transaction, such	approvals	may	be	granted	subject	to	terms	that	are	unacceptable	to	them,	or	Entergy	or	its	subsidiaries	otherwise	may	be unable	to	achieve	anticipated	regulatory	treatment	of	any	such	transaction	or	acquired	business	or	assets;	and

•Entergy	or	its	subsidiaries	otherwise	may	be	unable	to	achieve	the	full	strategic	and	financial	benefits	that	they	anticipate	from	the transaction,	or	such	benefits	may	be	delayed	or	may	not	occur	at	all.

Entergy	may	not	be	successful	in	managing	these	or	any	other	significant	risks	that	it	may	encounter	in	acquiring	or	divesting	a	business, or	engaging	in	other	strategic	transactions,	which	could	have	a	material	effect	on	its	business.

# 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,	or	make	other	capital improvements,	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	or	other	capital	improvements	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.	 	 In	 addition,	 the	 Utility	 operating companies	could	be	exposed	 to	higher	costs	and	market	volatility,	which	could	affect	cash	flow	and	cost	recovery,	should	 their	respective regulators	decline	to	approve	the	construction	of	new	generation	needed	to	meet	the	reliability	needs	of	customers	at	the	lowest	reasonable	cost.

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,	certain	migratory	birds	and	eagles,	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 potentially	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	Entergy	Wholesale	Commodities	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.

# 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	electric	cooling	demand	and	revenues,	and	temperatures	below	normal levels	in	the	winter	tend	to	increase	electric	and	gas	heating	demand	and	revenues.		As	a	corollary,	moderate	temperatures	in	either	season	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	economic	conditions,	weather,	customer	bill	sizes	(large bills	tend	to	induce	conservation),	trends	in	energy	efficiency,	new	technologies	and	self-generation	alternatives,	including	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	effect	on	Entergy's	operating results.		Others,	such	as	the	increasing	adoption	of	energy	efficient	appliances,	new	building	codes,	distributed	energy	resources,	energy	storage, demand	side	management	and	new	technologies	such	as	rooftop	solar	are	having	a	more	permanent	effect	of	reducing	sales	growth	rates	from historical	 norms.	As	a	result	of	these	emerging	efficiencies	and	technologies,	the	Utility	operating	companies	may	experience	lower	usage	per customer	in	the	residential	and	commercial	classes,	and	further	advances	have	the	potential	to	limit	sales	growth	in	the	future.		Electricity	sales	to industrial	customers,	in	particular,	benefit	from	steady	economic	growth	and	favorable	commodity	prices;	however,	they	are	sensitive	to	changes in	conditions	in	the	markets	in	which	its	customers	operate.		Any	negative	change	in	any	of	these	or	other	factors	has	the	potential	to	result	in slower	 sales	 growth	 or	 sales	 declines	 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,	System	Energy,	and	the	Entergy	Wholesale	Commodities	business.

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,	 the	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.	 	During	2012	and	2014,	 the	EPA	proposed	CO 2 emission	standards	for	new	and	existing	sources.	The	EPA	finalized	these	standards	in	2015;	however,	in	late	2017,	the	EPA	proposed	to	repeal the	regulations	and	issued	an	Advanced	Notice	of	Proposed	Rulemaking	for	replacing	certain	aspects	of	the	standards	for	existing	sources.	As examples	of	state	action,	in	the	Northeast,	the	Regional	Greenhouse	Gas	Initiative	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.	The	impact	that	recent	changes	in	the	federal	government	will	have	on	existing	and	pending	environmental	laws	and regulations	related	to	greenhouse	gas	emissions	is	currently	unclear.

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.		These	requirements	could,	in	turn,	lead	to	changes	in	the	planning	or	operations	of	balancing authorities	or	organized	markets	in	areas	where	the	Utility	operating	companies,	System	Energy,	or	Entergy	Wholesale	Commodities	do	business. 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	have	occurred	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,	potential	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	increases	in	precipitation,	drought,	or	changes	in	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's,	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	the	Entergy	Wholesale	Commodities business.

Water	 is	 a	 vital	 natural	 resource	 that	 is	 also	 critical	 to	 the	 Utility	 operating	 companies',	 System	 Energy's,	 and	 Entergy	Wholesale Commodities'	business	operations.		Entergy's	facilities	use	water	for	cooling,	boiler	make-up,	sanitary	uses,	potable	supply,	and	many	other uses.		Three	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	and/or	state	water	pollution	control	provisions. 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	and	enrichment,	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's	over-the-counter	financial	derivatives	are	subject	to	rules	implementing	the	Dodd-Frank	Wall	Street	Reform	and	Consumer Protection	Act	that	are	designed	to	promote	transparency,	mitigate	systemic	risk	and	protect	against	market	abuse.	Entergy	cannot	predict	the impact	any	proposed	or	not	fully-implemented	final	rules	will	have	on	its	ability	to	hedge	its	commodity	price	risk	or	on	over-the-counter derivatives	markets	as	a	whole,	but	such	rules	and	regulations	could	have	a	material	effect	on	Entergy's	risk	exposure,	as	well	as	reduce	market liquidity	and	further	increase	the	cost	of	hedging	activities.

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,	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.

# Market	performance	and	other	changes	may	decrease	the	value	of	benefit	plan	assets,	which	then	could	require	additional	funding and	result	in	increased	benefit	plan	costs.

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	and	also result	in	higher	benefit	costs.	As	the	value	of	the	assets	decreases,	the	"expected	return	on	assets"	component	of	benefit	costs	decreases,	resulting in	higher	benefits	costs.	Additionally,	asset	losses	are	incorporated	into	benefit	costs	over	time,	thus	increasing	benefits	costs.		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	 and	 recognition	 of	 higher	 liability	 carrying	 costs.	 	 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.

# Domestic	 or	 international	 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,	transmission	operations	centers,	or	distribution	infrastructure used	to	manage	and	transport	power	to	customers.	An	actual	act	could	affect	Entergy's	ability	to	operate,	including	its	ability	to	operate	the information	technology	systems	and	network	infrastructure	on	which	it	relies	to	conduct	its	business.	While	malware	was	recently	discovered	on our	corporate	network	and	remediated	on	a	timely	basis,	it	did	not	affect	the	company's	operational	systems,	nuclear	plants	or	transmission network,	 nor	 did	 it	 have	 a	 material	 effect	 on	 our	 operations.	Additionally,	 within	 Entergy's	 industry,	 there	 have	 been	 attacks	 on	 energy infrastructure,	but	with	minimal	impact	to	operations,	and	there	may	be	more	attacks	in	the	future.	The	Utility	operating	companies	also	face heightened	risk	of	an	act	or	threat	by	cyber	criminals	intent	on	accessing	personal	information	for	the	purpose	of	committing	identity	theft,	taking company-sensitive	data,	or	disrupting	the	company's	ability	to	operate.

Entergy	and	its	subsidiaries	operate	in	a	highly	regulated	industry	that	requires	the	continued	operation	of	sophisticated	information technology	systems	and	network	infrastructure	in	accordance	with	mandatory	and	prescriptive	standards.	Despite	the	implementation	of	multiple layers	of	security	by	Entergy	and	its	subsidiaries,

technology	systems	remain	vulnerable	to	potential	threats	that	could	lead	to	unauthorized	access	or	loss	of	availability	to	critical	systems	essential to	the	reliable	operation	of	Entergy's	electric	system.	Moreover,	the	functionality	of	Entergy's	technology	systems	depends	on	both	its	and	third- party	systems	to	which	Entergy	is	connected	directly	or	indirectly	(such	as	systems	belonging	to	suppliers,	vendors	and	contractors).	While Entergy	has	processes	in	place	to	assess	systems	of	certain	of	these	suppliers,	vendors	and	contractors,	Entergy	does	not	ultimately	control	the adequacy	of	their	defenses	against	cyber	and	other	attacks,	but	has	implemented	oversight	measures	to	assess	maturity	and	manage	third-party risk.	If	Entergy's	or	its	subsidiaries'	technology	systems	were	compromised	and	unable	to	detect	or	recover	in	a	timely	fashion	to	a	normal	state	of operations,	Entergy	or	its	subsidiaries	may	be	unable	to	perform	critical	business	functions	that	are	essential	to	the	company's	well-being	and	the health,	safety,	and	security	needs	of	its	customers.	In	addition,	an	attack	on	its	information	technology	infrastructure	may	result	in	a	loss	of	its confidential,	sensitive,	and	proprietary	information,	including	personal	information	of	its	customers,	employees,	vendors,	and	others	in	Entergy's care.

Any	such	attacks,	failures	or	breaches	could	have	a	material	effect	on	Entergy's	and	the	Utility	operating	companies'	business,	financial condition,	results	of	operations	or	reputation.	Insurance	may	not	be	adequate	to	cover	losses	that	might	arise	in	connection	with	these	events.	The risk	of	such	attacks,	failures,	or	breaches	may	cause	Entergy	and	the	Utility	operating	companies	to	incur	increased	capital	and	operating	costs	to implement	increased	security	for	its	power	generation,	transmission,	and	distribution	assets	and	other	facilities,	such	as	additional	physical	facility security	and	security	personnel,	and	for	systems	to	protect	its	information	technology	and	network	infrastructure	systems.	Such	events	may	also expose	Entergy	to	an	increased	risk	of	litigation	(and	associated	damages	and	fines).

# The	effect	of	higher	purchased	gas	cost	charges	to	customers	taking	gas	service	may	adversely	affect	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	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	New	Orleans	recovers	from	its	customers.		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	New	Orleans,	customer	usage	may	decrease,	especially	in weaker	economic	times,	resulting	in	lower	distribution	charges	for	Entergy	New	Orleans,	which	could	adversely	affect	results	of	operations.

# System	 Energy	 owns	 and, through	 an	 affiliate,	 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	expires	in	November	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	Notes	8	and	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	articles	of	incorporation	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	Note	7	to	the	financial	statements.

# Net	Income

Net	 income	 decreased	$27.4	million	primarily	due	to	higher	nuclear	refueling	outage	expenses,	higher	depreciation	and	amortization expenses,	higher	taxes	other	than	income	taxes,	and	higher	interest	expense,	partially	offset	by	higher	other	income.

Net	income	increased	$92.9	million	primarily	due	to	higher	net	revenue	and	lower	other	operation	and	maintenance	expenses,	partially offset	by	a	higher	effective	income	tax	rate	and	higher	depreciation	and	amortization	expenses.

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	2017	to	2016.

| 2016	net	revenue | $1,520.5 |
| :--- | :--- |
| Retail\telectric\tprice | 33.8 |
| Opportunity\tsales | 5.6 |
| Asset\tretirement\tobligation | (14.8) |
| Volume/weather | (29.0) |
| Other | 6.5 |
| 2017\tnet\trevenue | $1,522.6 |

The	retail	electric	price	variance	is	primarily	due	to	the	implementation	of	formula	rate	plan	rates	effective	with	the	first	billing	cycle	of January	2017	and	an	increase	in	base	rates	effective	February	24,	2016,	each	as	approved	by	the	APSC.	A	significant	portion	of	the	base	rate increase	was	related	to	the	purchase	of	Power	Block	2	of	the	Union	Power	Station	in	March	2016.	The	increase	was	partially	offset	by	decreases in	the	energy	efficiency	rider,	as	approved	by	the	APSC,	effective	April	2016	and	January	2017.	 See	Note	2	to	the	financial	statements	for	further discussion	of	the	rate	case	and	formula	rate	plan	filings.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Union	Power	Station purchase.

The	opportunity	sales	variance	results	from	the	estimated	net	revenue	effect	of	the	2017	and	2016	FERC	orders	in	the	opportunity	sales proceeding	attributable	to	wholesale	customers.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	opportunity	sales	proceeding.

The	asset	retirement	obligation	affects	net	revenue	because	Entergy	Arkansas	records	a	regulatory	charge	or	credit	for	the	difference between	 asset	 retirement	 obligation-related	 expenses	 and	 decommissioning	 trust	 fund	 earnings	 plus	 asset	 retirement	 obligation-related	 costs collected	in	revenue.	The	variance	is	primarily	caused	by	a	decrease	in	regulatory	credits	because	of	an	increase	in	decommissioning	trust	fund earnings,	including	portfolio	rebalancing	for	the	ANO	1	and	ANO	2	decommissioning	trust	funds.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales	during	the	billed and	unbilled	sales	periods.	The	decrease	was	partially	offset	by	an	increase	of	733	GWh,	 or	11%,	in	industrial	usage	primarily	due	to	a	new customer	in	the	primary	metals	industry.

| 2015	net	revenue | $1,362.2 |
| :--- | :--- |
| Retail\telectric\tprice | 161.5 |
| Other | (3.2) |
| 2016\tnet\trevenue | $1,520.5 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	base	rates,	as	approved	by	the	APSC.	The	new	base	rates	were	effective February	24,	2016	and	began	billing	with	the	first	billing	cycle	of	April	2016.	The	increase	includes	an	interim	base	rate	adjustment	surcharge, effective	with	the	first	billing	cycle	of	April	2016,	to	recover	the	incremental	revenue	requirement	for	the	period	February	24,	2016	through	March 31,	2016.	A	significant	portion	of	the	increase	was	related	to	the	purchase	of	Power	Block	2	of	the	Union	Power	Station	in	March	2016.	See	Note 2	to	the	financial	statements	for	further	discussion	of	the	rate	case.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Union Power	Station	purchase.

# Other	Income	Statement	Variances

Nuclear	refueling	outage	expenses	increased	primarily	due	to	the	amortization	of	higher	costs	associated	with	the	most	recent	outages compared	to	previous	outages.

Other	operation	and	maintenance	expenses	increased	primarily	due	to:

•the	deferral	in	the	first	quarter	2016	of	$7.7	million	of	previously-incurred	costs	related	to	ANO	post-Fukushima	compliance	and	 $9.9 million	of	previously-incurred	costs	related	to	ANO	flood	barrier	compliance,	as	approved	by	the	APSC	as	part	of	the	2015	rate	case settlement.	These	costs	are	being	amortized	over	a	ten-year	period	beginning	March	2016.	See	Note	2	to	the	financial	statements	for further	discussion	of	the	rate	case	settlement;

•an	increase	of	$9.5	million	in	transmission	and	distribution	expenses	primarily	due	to	higher	vegetation	maintenance	costs	and	higher labor	costs,	including	contract	labor;

•an	increase	of	$5.9	million	in	compensation	and	benefits	costs	primarily	due	to	higher	incentive-based	compensation	accruals	in	2017	as compared	to	the	prior	year;	and

•the	effect	of	recording	in	July	2016	the	final	court	decision	in	a	lawsuit	against	the	DOE	related	to	spent	nuclear	fuel	storage	costs.	The damages	awarded	included	the	reimbursement	of	$5.5	million	of	spent	nuclear	fuel

storage	 costs	 previously	 recorded	 as	 other	 operation	 and	 maintenance	 expense.	See	 Note	 8 to the financial	 statements for further discussion	of	Entergy	Arkansas's	spent	nuclear	fuel	litigation.

•a	decrease	of	$16	million	in	nuclear	generation	expenses	primarily	due	to	a	decrease	in	regulatory	compliance	costs	compared	to	the	prior year,	partially	offset	by	higher	nuclear	labor	costs,	including	contract	labor,	to	position	the	nuclear	fleet	to	meet	its	operational	goals.	The decrease	in	regulatory	compliance	costs	is	primarily	related	to	NRC	inspection	activities	in	2016	as	a	result	of	the	NRC's	March	2015 decision	to	move	ANO	into	the	"multiple/repetitive	degraded	cornerstone	column"	of	the	NRC's	reactor	oversight	process	action	matrix. See	Note	8	to	the	financial	statements	for	a	discussion	of	the	ANO	stator	incident	and	subsequent	NRC	reviews; •a	decrease	of	$11.5	million	in	energy	efficiency	expenses	primarily	due	to	the	timing	of	recovery	from	customers;	and •a	decrease	of	$5.2	million	in	fossil-fueled	generation	expenses	primarily	due	to	lower	long-term	service	agreement	costs,	partially	offset by	an	overall	higher	scope	of	work	including	plant	outages	in	2017	compared	to	2016.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	primarily	due	to	higher	assessments	and	higher millage	rates	and	an	increase	in	local	franchise	taxes	primarily	due	to	higher	billing	factors.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	Power	Block	2	of	the	Union Power	Station	purchased	in	March	2016.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Union	Power	Station	purchase.

Other	income	increased	primarily	due	to	higher	realized	gains	in	2017	compared	to	2016	on	the	decommissioning	trust	fund	investments, including	portfolio	rebalancing	for	the	ANO	1	and	ANO	2	decommissioning	trust	funds.

Interest	expense	increased	primarily	due	to:

•an	increase	of	$3.3	million	in	estimated	interest	expense	recorded	in	connection	with	the	opportunity	sales	proceeding.	See	Note	2	to	the financial	statements	for	further	discussion	of	the	opportunity	sales	proceeding;	and

•the	issuance	in	May	2017	of	$220	million	of	3.5%	Series	first	mortgage	bonds	and	the	issuance	in	June	2016	of	$55	million	of	3.5%	Series first	mortgage	bonds,	partially	offset	by	 the	redemption	 in	July	2016	of	$60	million	of	6.38%	Series	first	mortgage	bonds	and	 the redemption	in	February	2016	of	$175	million	of	5.66%	Series	first	mortgage	bonds.	See	Note	5	to	the	financial	statements	for	further discussion	of	long-term	debt.

Other	operation	and	maintenance	expenses	decreased	primarily	due	to:

•a	decrease	of	$21.6	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	net	periodic	pension	and	other	postretirement benefits	costs	as	a	result	of	an	increase	in	the	discount	rate	used	to	value	the	benefit	liabilities	and	a	refinement	in	the	approach	used	to estimate	the	service	cost	and	interest	cost	components	of	pension	and	other	postretirement	costs.	See	"Critical	Accounting	Estimates" below	and	Note	11	to	the	financial	statements	for	further	discussion	of	pension	and	other	postretirement	benefits	costs;

Entergy	Arkansas,	Inc.	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

•the	 deferral	 of	$7.7	million	of	previously-incurred	costs	related	to	ANO	post-Fukushima	compliance	and	 $9.9	million	of	previously- incurred	costs	related	to	ANO	flood	barrier	compliance,	as	approved	by	the	APSC	as	part	of	the	2015	rate	case	settlement.	These	costs	are being	amortized	over	a	ten-year	period	beginning	March	2016.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	rate case	settlement;	and

•a	decrease	of	$7.2	million	in	energy	efficiency	costs,	including	the	effects	of	true-ups	to	the	energy	efficiency	filings	for	fixed	costs	to	be collected	from	customers	and	incentives	recognized	as	a	result	of	participation	in	energy	efficiency	programs.

The	decrease	was	partially	offset	by	an	increase	of	$24.1	million	in	nuclear	generation	expenses	primarily	due	to	an	overall	higher	scope	of	work performed	during	plant	outages	and	higher	nuclear	labor	costs	compared	to	prior	year	and	an	increase	of	$8.2	million	in	fossil-fueled	generation expenses	primarily	due	to	the	purchase	of	Power	Block	2	of	the	Union	Power	Station	in	March	2016.	See	Note	14	to	the	financial	statements	for further	discussion	of	the	Union	Power	Station	purchase.

Taxes	 other	 than	 income	 taxes	 decreased	 primarily	 due	 to	 a	 decrease in local franchise taxes resulting from lower residential	 and commercial	revenues	compared	to	the	prior	year	and	a	decrease	in	payroll	taxes.

•$5.1	million	in	estimated	interest	expense	recorded	in	connection	with	the	FERC	orders	issued	in	April	2016	in	the	opportunity	sales proceeding.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	opportunity	sales	proceeding;	and

•the	net	issuance	of	$230	million	of	first	mortgage	bonds	in	2016.	See	Note	5	to	the	financial	statements	for	further	discussion	of	long-term debt.

The	effective	 income	 tax	rates	for	2017,	2016,	and	2015	were	40.1%,	39.2%,	 and	35.3%, respectively.	See	Note	3	to	the	financial statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rates.

See	the	"Income	Tax	Legislation"	section	of	Entergy	Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for discussion	of	the	Tax	Cuts	and	Jobs	Act,	the	federal	income	tax	legislation	enacted	in	December	2017.	Note	3	to	the	financial	statements	contains additional	discussion	of	the	effect	of	the	Act	on	2017	results	of	operations	and	financial	position,	the	provisions	of	the	Act,	and	the	uncertainties associated	with	accounting	for	the	Act,	and	Note	2	to	the	financial	statements	discusses	proceedings	commenced	or	other	responses	by	Entergy's regulators	to	the	Act.

# Cash	Flow

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $20,509 | $9,135 | $218,505 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 555,556 | 676,511 | 474,890 |
| Investing\tactivities | (829,312) | (947,995) | (685,274) |
| Financing\tactivities | 259,463 | 282,858 | 1,014 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (14,293) | 11,374 | (209,370) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,216 | $20,509 | $9,135 |

# Operating	Activities

Net	cash	flow	provided	by	operating	activities	decreased	$121	million	in	2017	primarily	due	to	income	tax	refunds	of	$8.1	million	in	2017 compared	to	income	tax	refunds	of	$135.7	million	in	2016.	Entergy	Arkansas	had	income	tax	refunds	in	2016	and	2017	in	accordance	with	an intercompany	income	tax	allocation	agreement.	The	income	tax	refunds	in	2017	resulted	from	the	utilization	of	Entergy	Arkansas's	net	operating losses.	The	2016	income	tax	refunds	resulted	primarily	from	adjustments	associated	with	the	settlement	of	the	2010-2011	IRS	audit.	See	Note	3	to the	financial	statements	for	a	discussion	of	the	income	tax	audit.

Net	cash	flow	provided	by	operating	activities	increased	$201.6	million	in	2016	primarily	due	to:

•income	tax	refunds	of	$135.7	million	in	2016	compared	to	income	tax	payments	of	$103.3	million	in	2015.	Entergy	Arkansas	had	income tax	refunds	in	2016	and	income	tax	payments	in	2015	in	accordance	with	an	intercompany	income	tax	allocation	agreement.	The	2016 income	tax	refunds	resulted	primarily	from	adjustments	associated	with	the	settlement	of	the	2010-2011	IRS	audit	whereas	the	income	tax payments	in	2015	resulted	primarily	from	final	settlement	of	amounts	outstanding	associated	with	the	2006-2007	IRS	audit	as	well	as adjustments	associated	with	the	settlement	of	the	2008-2009	IRS	audit.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the income	tax	audits;

•the	timing	of	payments	to	vendors;	and

•an	increase	in	net	revenue.

The	increase	was	partially	offset	by	a	decrease	due	to	the	timing	of	recovery	of	fuel	and	purchased	power	costs.

Net	cash	flow	used	in	investing	activities	decreased	$118.7	million	in	2017	primarily	due	to	the	purchase	of	Power	Block	2	of	the	Union Power	Station	in	March	2016	for	approximately	$237	million	and	a	decrease	of	$35.5	million	in	transmission	construction	expenditures	primarily due	to	a	lower	scope	of	work	performed	in	2017.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Union	Power	Station purchase.

•an	increase	of	$50.4	million	in	nuclear	construction	expenditures	primarily	due	to	a	higher	scope	of	work	performed	on	various	nuclear projects	in	2017;

•an	increase	of	$37.7	million	as	a	result	of	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	service	deliveries,	and	the	timing	of	cash	payments	during	the nuclear	fuel	cycle;

•an	 increase	 of	$32.9	million in information technology	construction	expenditures	primarily	due to increased	spending	on	substation technology	upgrades;

•an	increase	of	$22.3	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	a	higher	scope	of	work	performed	on various	projects	in	2017;	and

•an	increase	of	$11.2	million	due	to	increased	spending	on	advanced	metering	infrastructure.

Net	cash	flow	used	in	investing	activities	increased	$262.7	million	in	2016	primarily	due	to	the	purchase	of	Power	Block	2	of	the	Union Power	Station	in	March	2016	for	approximately	$237	million.	See	Note	14	to	the	financial	statements	for	further	discussion	of	the	Union	Power Station	purchase.	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	service	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel cycle.

Net	cash	flow	provided	by	financing	activities	decreased	$23.4	million	in	2017	primarily	due	to:

•a	$200	million	capital	contribution	received	from	Entergy	Corporation	in	March	2016	primarily	in	anticipation	of	Entergy	Arkansas's purchase	of	Power	Block	2	of	the	Union	Power	Station;

•the	net	issuance	of	$119.1	million	of	long-term	debt	in	2017	compared	to	the	net	issuance	of	$189.1	million	of	long-term	debt	in	2016;	and •$15	million	in	common	stock	dividends	paid	in	2017	resulting	from	Entergy	Arkansas's	routine	evaluation	of	its	ability	to	pay	dividends. There	were	no	common	stock	dividends	paid	in	2016	in	anticipation	of	the	purchase	of	Power	Block	2	of	the	Union	Power	Station.

•money	pool	activity;

•the	redemptions	of	$75	million	of	6.45%	Series	preferred	stock	and	$10	million	of	6.08%	Series	preferred	stock	in	2016;	and •net	short-term	borrowings	of	$50	million	on	the	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	credit	facility	in	2017 compared	to	net	repayments	of	$11.7	million	in	2016.

Increases	in	Entergy	Arkansas's	payable	to	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Arkansas's	payable	to	the	money	pool increased	 by	$114.9	 million	 in	 2017	 compared	 to	 decreasing	 by	$1.5	 million	 in	 2016.	The	 money	 pool	 is	 an	 inter-company	 borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	flow	provided	by	financing	activities	increased	$281.8	million	in	2016	primarily	due	to:

•the	net	issuance	of	$189.1	million	of	long-term	debt	in	2016	compared	to	the	net	retirement	of	$13.2	million	of	long-term	debt	in	2015; •a	$200	million	capital	contribution	received	from	Entergy	Corporation	in	March	2016	primarily	in	anticipation	of	Entergy	Arkansas's purchase	of	Power	Block	2	of	the	Union	Power	Station;	and

•net	repayments	of	$11.7	million	on	the	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	credit	facility	in	2016	compared	to net	repayments	of	$36.3	million	in	2015.

The	increase	was	partially	offset	by	the	redemptions	of	$75	million	of	6.45%	Series	preferred	stock	and	$10	million	of	6.08%	Series	preferred stock	in	2016	and	money	pool	activity.

Decreases	in	Entergy	Arkansas's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Arkansas's	payable	to	the	money	pool decreased	by	$1.5	million	in	2016	compared	to	increasing	by	$52.7	million	in	2015.

See	Note	5	to	the	financial	statements	for	further	details	of	long-term	debt.

Entergy	Arkansas's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.

|  | December	31,<br>2017 | December	31,<br>2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 55.5% | 55.3% |
| Effect\tof\texcluding\tthe\tsecuritization\tbonds | (0.3%) | (0.4%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 55.2% | 54.9% |
| Effect\tof\tsubtracting\tcash | —% | (0.2%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 55.2% | 54.7% |

(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.

Entergy	Arkansas	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital while	also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.		To	the	extent	that	operating	cash	flows	are	in excess	of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to maintain	the	targeted	capital	structure.		To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	Entergy	Arkansas may	issue	incremental	debt	or	reduce	dividends,	or	both,	to	maintain	its	targeted	capital	structure.		In	addition,	in	certain	infrequent	circumstances, such	as	large	transactions	that	would	materially	alter	the	capital	structure	if	financed	entirely	with	debt	and	reducing	dividends,	Entergy	Arkansas may	receive	equity	contributions	to	maintain	the	targeted	capital	structure.

# 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 | $190 | $240 | $225 |
| :--- | :--- | :--- | :--- |
| Transmission | 170 | 165 | 175 |
| Distribution | 225 | 245 | 225 |
| Utility\tSupport | 110 | 85 | 85 |
| Total | $695 | $735 | $710 |

Following	are	the	amounts	of	Entergy	Arkansas's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2018 | 2019-2020 | 2021-2022 | after	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $125 | $266 | $672 | $4,208 | $5,271 |
| Operating\tleases | $17 | $29 | $16 | $24 | $86 |
| Purchase\tobligations\t(b) | $595 | $1,050 | $863 | $5,369 | $7,877 |

(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	are	discussed	in	Note	8	to	the	financial	statements.

In	addition	 to	 the	contractual	obligations	given	above,	Entergy	Arkansas	currently	expects	 to	contribute	approximately $64.1	million to	 its qualified	pension	plans	and	approximately	$472	thousand	to	its	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the 2018	required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by April	1,	2018. 	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	 ($117.7)	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,	such	as	transmission	projects	to	enhance	reliability,	reduce	congestion,	and	enable	economic	growth;	distribution	spending	to enhance	reliability	and	improve	service	to	customers,	including	investment	to	support	advanced	metering;	resource	planning,	including	potential generation	projects;	system	improvements;	investments	in	ANO	1	and	2;	and	other	investments.	Estimated	capital	expenditures	are	subject	to periodic	 review	 and	 modification	 and	 may	 vary	 based	 on	 the	 ongoing	 effects	 of	 regulatory	 constraints	 and	 requirements,	 environmental compliance,	business	opportunities,	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	discussed	above	in	"Capital	Structure,"	Entergy	Arkansas	routinely	evaluates	its	ability	to	pay	dividends	to	Entergy	Corporation	from its	earnings.	Provisions	in	Entergy	Arkansas's	articles	of	incorporation	relating	to	preferred

stock	restrict	the	amount	of	retained	earnings	available	for	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred stock.

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	or	(payables	to)	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| ($166,137) | ($51,232) | ($52,742) | $2,218 |

See	Note	4	to	the	financial	statements	for	a	description	of	the	money	pool.

Entergy	Arkansas	has	a	credit	facility	in	the	amount	of	$150	million	scheduled	to	expire	in	August	2022.	Entergy	Arkansas	also	has	a	$20 million	credit	facility	scheduled	to	expire	in	April	2018.		The	$150	million	credit	facility	permits	the	issuance	of	letters	of	credit	against	$5	million of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2017,	there	were	no	cash	borrowings	and	no	letters	of	credit	outstanding	under	the credit	 facilities.	In	addition,	Entergy	Arkansas	is	a	party	to	an	uncommitted	letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its obligations	to	MISO.	As	of	December	31,	2017,	a	$1	million	letter	of	credit	was	outstanding	under	Entergy	Arkansas's	uncommitted	letter	of credit	facility.	See	Note	4	to	the	financial	statements	for	further	discussion	of	the	credit	facilities.

The	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	 $80	million	scheduled	to	expire in	May	2019.		As	of	December	31,	2017,	$50	million	in	letters	of	credit	to	support	a	like	amount	of	commercial	paper	issued	and	 $24.9	million	in loans	were	outstanding	under	the	Entergy	Arkansas	nuclear	fuel	company	variable	interest	entity	credit	facility.	See	Note	4	to	the	financial statements	for	further	discussion	of	the	nuclear	fuel	company	variable	interest	entity	credit	facility.

Entergy	Arkansas	obtained	authorizations	from	the	FERC	through	October	2019	for	short-term	borrowings	not	to	exceed	an	aggregate amount	of	$250	million	at	any	time	outstanding	and	borrowings	by	its	nuclear	fuel	company	variable	interest	entity.	See	Note	4	to	the	financial statements	for	further	discussion	of	Entergy	Arkansas's	short-term	borrowing	limits.	The	long-term	securities	issuances	of	Entergy	Arkansas	are limited	to	amounts	authorized	by	the	APSC,	and	the	current	authorization	extends	through	December	2018.

In	April	2015,	Entergy	Arkansas	filed	with	the	APSC	for	a	general	change	in	rates,	charges,	and	tariffs.	 The	filing	notified	the	APSC	of Entergy	Arkansas's	intent	to	implement	a	forward	test	year	formula	rate	plan	pursuant	to	Arkansas	legislation	passed	in	2015,	and	requested	a retail	rate	increase	of	$268.4	million,	with	a	net	increase	in	revenue	of	$167	million.	The	filing	requested	a	10.2%	return	on	common	equity.	In September	2015	the	APSC	staff	and	intervenors	filed	direct	testimony,	with	the	APSC	staff	recommending	a	revenue	requirement	of	$217.9 million	and	a	9.65%	return	on	common	equity.	In	December	2015,	Entergy	Arkansas,	the	APSC	staff,	and	certain	of	the	intervenors	in	the	rate case	filed	with	the	APSC	a	joint	motion	for	approval	of	a	settlement	of	the	case	that	proposed	a	retail	rate	increase	of	approximately	$225	million with	a	net	increase	in	revenue	of	approximately	$133	million;	an	authorized	return	on	common	equity	of	9.75%;	and	a	formula	rate	plan	tariff	that provides	a	+/-	50	basis	point	band	around	the	9.75%	allowed	return	on	common	equity.	A	significant	portion	of	the	rate	increase	is	related	to Entergy	Arkansas's	acquisition	in	March	2016	of	Union	Power	Station	Power	Block	2	for	a	base	purchase	price	of	$237	million.	The	settlement agreement	also	provided	for	amortization	over	a	10-year	period	of	$7.7	million	of	previously-incurred	costs	related	to	ANO	post-Fukushima compliance	 and	$9.9	million	of	previously-incurred	costs	related	to	ANO	flood	barrier	compliance.	A	settlement	hearing	was	held	in	January 2016.	In	February	2016	the	APSC	approved	the	settlement	with	one	exception	that	reduced	the	retail	rate	increase	proposed	in	the	settlement	by $5	million.	The	settling	parties	agreed	to	the	APSC	modifications	in	February	2016.	The	new	rates	were	effective	February	24,	2016	and	began billing	with	the	first	billing	cycle	of	April	2016.	In	March	2016,	Entergy	Arkansas	made	a	compliance	filing	regarding	the

new	rates	that	included	an	interim	base	rate	adjustment	surcharge,	effective	with	the	first	billing	cycle	of	April	2016,	to	recover	the	incremental revenue	requirement	for	the	period	February	24,	2016	through	March	31,	2016.	The	interim	base	rate	adjustment	surcharge	was	designed	to recover	a	total	of	$21.1	million	over	the	nine-month	period	from	April	2016	through	December	2016.

In	July	2017,	Entergy	Arkansas	filed	with	the	APSC	its	2017	formula	rate	plan	filing	showing	Entergy	Arkansas's	projected	earned	return on	common	equity	for	the	twelve	months	ended	December	31,	2018	test	period	to	be	below	the	formula	rate	plan	bandwidth.		The	filing	projected a	$129.7	 million	 revenue	 requirement	 increase	 to	 achieve	 Entergy	Arkansas's	 target	 earned	 return	 on	 common	 equity	 of	 9.75%.	 	 Entergy Arkansas's	 formula	 rate	 plan	 is	 subject	 to	 a	four	percent	annual	revenue	constraint	and	 the	projected	annual	revenue	requirement	 increase exceeded	the	four	percent,	resulting	in	a	proposed	increase	for	the	2017	formula	rate	plan	of	$70.9	million.	In	October	2017,	Entergy	Arkansas filed	with	the	APSC	revised	formula	rate	plan	attachments	that	projected	a	$126.2	million	revenue	requirement	increase	based	on	acceptance	of certain	adjustments	and	recommendations	made	by	the	APSC	staff	and	other	intervenors.	The	revised	formula	rate	plan	filing	included	a	proposed $71.1	million	revenue	requirement	increase	based	on	a	revision	to	the	four	percent	constraint	calculation.	In	October	2017,	Entergy	Arkansas	and the	parties	to	the	proceeding	filed	a	joint	motion	to	approve	a	unanimous	settlement	agreement	resolving	all	issues	in	the	docket	and	providing	for recovery	of	the	2017	and	2018	nuclear	costs.	In	December	2017	the	APSC	approved	the	settlement	agreement	and	the	$71.1	million	revenue requirement	increase,	as	well	as	Entergy	Arkansas's	formula	rate	plan	compliance	tariff,	and	the	rates	became	effective	with	the	first	billing	cycle of	January	2018.

In	November	2017,	Entergy	Arkansas	filed	an	application	with	the	APSC	seeking	authorization	to	undertake	a	restructuring	that	would result	in	the	transfer	of	substantially	all	of	the	assets	and	operations	of	Entergy	Arkansas	to	a	new	entity,	which	would	ultimately	be	owned	by	an existing	Entergy	subsidiary	holding	company.	The	restructuring	is	subject	to	regulatory	review	and	approval	by	the	APSC,	the	FERC,	and	the NRC.	Entergy	Arkansas	also	filed	a	notice	with	the	Missouri	Public	Service	Commission	in	December	2017	out	of	an	abundance	of	caution, although

Entergy	Arkansas	 does	 not	 serve	 any	 retail	 customers	 in	 Missouri.	If	 the	APSC	approves	 the	restructuring	by	September	1,	2018,	and	 the restructuring	closes	on	or	before	December	1,	2018,	Entergy	Arkansas	proposed	in	its	application	to	credit	retail	customers	$66	million	over	six years,	beginning	 in	2019.	In	February	2018,	Entergy	Arkansas	filed	supplemental	testimony	reducing	the	proposed	retail	customer	credits	to $39.6	million	over	six	years.	If	the	APSC,	the	FERC,	and	the	NRC	approvals	are	obtained,	Entergy	Arkansas	expects	the	restructuring	will	be consummated	on	or	before	December	1,	2018.

•Entergy	Arkansas	will	contribute	the	membership	interests	in	Entergy	Arkansas	Power	to	an	affiliate	(Entergy	Utility	Holding	Company,

LLC,	a	Texas	limited	liability	company	and	subsidiary	of	Entergy	Corporation).	As	a	result	of	the	contribution,	Entergy	Arkansas	Power will	be	a	wholly-owned	subsidiary	of	Entergy	Utility	Holding	Company,	LLC.

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	the	costs	from	customers	over	twelve	months.

In	May	2015,	Entergy	Arkansas	filed	its	annual	redetermination	of	the	production	cost	allocation	rider,	which	included	a $38	million payment	made	by	Entergy	Arkansas	as	a	result	of	the	FERC's	February	2014	order	related	to	the	comprehensive	bandwidth	recalculation	for calendar	year	2006,	2007,	and	2008	production	costs.	The	redetermined	rate	for	the	2015	production	cost	allocation	rider	update	was	added	to	the redetermined	rate	from	the	2014	production

cost	allocation	rider	update	and	the	combined	rate	was	effective	with	the	first	billing	cycle	of	July	2015.	This	combined	rate	was	effective	through December	2015.	The	collection	of	the	remainder	of	the	redetermined	rate	for	the	2015	production	cost	allocation	rider	update	continued	through June	2016.

In	 January	 2014,	 Entergy	Arkansas	 filed	 a	 motion	 with	 the	APSC	 relating	 to	 its	 redetermination	 of	 its	 energy	 cost	 rate	 that	 was subsequently	filed	in	March	2014.	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	redetermination	of	its	2014	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.	In	July	2017,	Entergy	Arkansas	filed	for	a	change	in	rates	pursuant	to	its	formula	rate	plan	rider.	In	that proceeding,	the	APSC	approved	a	settlement	agreement	agreed	upon	by	the	parties,	including	a	provision	that	requires	Entergy	Arkansas	to	initiate a	proceeding	for	the	purpose	of	recovering	funds	currently	withheld	from	rates	and	related	to	the	stator	incident,	including	the	$65.9	million	of deferred	fuel	and	purchased	energy	costs	previously	noted,	subject	to	certain	timelines	and	conditions	set	forth	in	the	settlement	agreement.	See the	"ANO	Damage,	Outage,	and	NRC	Reviews"	section	in	Note	8	to	the	financial	statements	for	further	discussion	of	the	ANO	stator	incident.

# 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	 allocated	 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	prohibited	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	challenged	sales	made	beginning	in	2002	and	requests	refunds.		In	July	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	FERC	subsequently	ordered	a	hearing	in	the	proceeding.

In	August	 2013	 the	 presiding	 judge	 issued	 an	 initial	 decision	 in	 the	 calculation	 proceeding.	The	 initial	 decision	 concluded	 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	concluded	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	recognized	that	the	LPSC's	methodology	would	result	in	an inequitable	windfall	to	the	other	Utility	operating	companies	and,	therefore,	concluded	that	any	payments	by	Entergy	Arkansas	should	be	reduced by	20%.	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	the	FERC	reverse	the	initial	decision	and	a	brief	opposing	certain	exceptions	taken	by	the	LPSC	and	FERC	staff.

In	April	2016	the	FERC	issued	orders	addressing	requests	for	rehearing	filed	in	July	2012	and	the	ALJ's	August	2013	initial	decision.	 The first	order	denied	Entergy's	request	for	rehearing	and	affirmed	the	FERC's	earlier	rulings	that	Entergy's	original	methodology	for	allocating energy	 costs	 to	 the	 opportunity	 sales	 was	 incorrect	 and,	 as	 a	 result,	 Entergy	Arkansas	 must	 make	 payments	 to	 the	 other	 Utility	 operating companies	to	put	them	in	the	same	position	that	they	would	have	been	in	absent	the	incorrect	allocation.	The	FERC	clarified	that	interest	should be	included	with	the	payments.	The	second	order	affirmed	in	part,	and	reversed	in	part,	the	rulings	in	the	ALJ's	August	2013	initial	decision regarding	the	methodology	that	should	be	used	to	calculate	the	payments	Entergy	Arkansas	is	to	make	to	the	other	Utility	operating	companies. The	FERC	affirmed	the	ALJ's	ruling	that	a	full	re-run	of	intra-system	bills	should	be	performed,	but	required	that	methodology	be	modified	so that	the	sales	have	the	same	priority	for	purposes	of	energy	allocation	as	joint	account	sales.	The	FERC	reversed	the	ALJ's	decision	that	any payments	 by	 Entergy	Arkansas	 should	 be	 reduced	 by	20%.	 The	 FERC	 also	 reversed	 the	ALJ's	 decision	 that	 adjustments	 to	 other	 System Agreement	service	schedules	and	excess	bandwidth	payments	should	not	be	taken	into	account	when	calculating	the	payments	to	be	made	by Entergy	 Arkansas.	The	FERC	held	that	such	adjustments	and	excess	bandwidth	payments	should	be	taken	into	account,	but	ordered	further proceedings	before	an	ALJ	to	address	whether	a	cap	on	any	reduction	due	to	bandwidth	payments	was	necessary	and	to	implement	the	other adjustments	to	the	calculation	methodology.

The	effect	of	the	FERC's	decisions	thus	far	in	the	case	would	be	that	Entergy	Arkansas	will	make	payments	to	some	or	all	of	the	other Utility	operating	companies.	Because	further	proceedings	will	still	occur	in	the	case,	the	amount	and	recipients	of	payments	by	Entergy	Arkansas are	unknown	at	this	time.	Based	on	testimony	previously	submitted	in	the	case	and	its	assessment	of	the	April	2016	FERC	orders,	in	the	first quarter	2016,	Entergy	Arkansas	recorded	a	liability	of	$87	million,	which	includes	interest,	for	its	estimated	increased	costs	and	payment	to	the other	Utility	operating	companies.	This	estimate	is	subject	to	change	depending	on	how	the	FERC	resolves	the	issues	that	are	still	outstanding	in the	case,	including	its	review	of	the	July	2017	initial	decision.	Entergy	Arkansas's	increased	costs	will	be	attributed	to	Entergy	Arkansas's	retail and	wholesale	businesses,	and	it	is	not	probable	that	Entergy	Arkansas	will	recover	the	wholesale	portion.	Entergy	Arkansas,	therefore,	recorded	a deferred	fuel	regulatory	asset	in	the	first	quarter	2016	of	approximately	$75	million,	which	represents	its	estimate	of	the	retail	portion	of	the	costs. Following	its	assessment	of	the	course	of	the	proceedings,	including	the	FERC's	denial	of	rehearing	in	November	2017

described	above,	in	the	fourth	quarter	2017,	Entergy	Arkansas	recorded	an	additional	liability	of	$35	million	and	a	regulatory	asset	of	$31	million. Because	management	currently	expects	to	recover	the	retail	portion	of	the	costs	through	a	base	rate	proceeding	or	newly	proposed	rider,	the regulatory	asset	is	reflected	as	Other	regulatory	assets	as	of	December	31,	2017.

See the	 "Rate,	 Cost-recovery,	 and	 Other	 Regulation	 –	 Federal	 Regulation" section	 of	 Entergy	 Corporation and	 Subsidiaries Management's	Financial	Discussion	and	Analysis	and	Note	2	to	the	financial	statements	for	a	discussion	of	federal	regulation.

Entergy	Arkansas	owns	and,	through	an	affiliate,	operates	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	related	to:	the	use,	storage,	and	handling	and	disposal	of high-level	and	 low-level	radioactive	materials;	 the	substantial	financial	requirements,	both	for	capital	 investments	and	operational	needs,	 to position	Entergy's	nuclear	fleet	to	meet	its	operational	goals,	including	the	financial	requirements	to	address	emerging	issues	like	stress	corrosion cracking	of	certain	materials	within	the	plant	systems	and	the	Fukushima	event;	regulatory	requirements	and	potential	future	regulatory	changes, including	 changes	 affecting	 the	 regulations	 governing	 nuclear	 plant	 ownership,	 operations,	 license	 renewal	 and	 amendments,	 and decommissioning;	the	performance	and	capacity	factors	of	these	nuclear	plants;	the	availability	of	interim	or	permanent	sites	for	the	disposal	of spent	nuclear	fuel	and	nuclear	waste,	including	the	fees	charged	for	such	disposal;	the	sufficiency	of	nuclear	decommissioning	trust	fund	assets and	earnings	to	complete	decommissioning	of	each	site	when	required;	and	limitations	on	the	amounts	and	types	of	insurance	commercially available	for	losses	in	connection	with	nuclear	plant	operations	and	catastrophic	events	such	as	a	nuclear	accident.	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.

# 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,	with	reference	to possible	exceptions	noted	in	"Regulation	of	Entergy's	Business -	Environmental	Regulation" in	 Part	 I,	 Item	 1.	 	 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.

See	 "Utility	 Regulatory	 Accounting" in the	 "Critical	 Accounting	 Estimates" section	 of	 Entergy	 Corporation and	 Subsidiaries Management's	Financial	Discussion	and	Analysis	for	discussion	of	accounting	for	the	effects	of	rate	regulation.

See	 "Unbilled	 Revenue" in	 the	 "Critical	Accounting	 Estimates"	 section	 of	 Entergy	 Corporation	 and	 Subsidiaries	 Management's Financial	Discussion	and	Analysis	for	discussion	of	the	estimates	associated	with	the	unbilled	revenue	amounts.

See	"Impairment	of	Long-lived	Assets	and	Trust	Fund	Investments"	in	the	"Critical	Accounting	Estimates"	section	of	Entergy Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	discussion	of	the	estimates	associated	with	the	impairment	of long-lived	assets	and	trust	fund	investments.

# See	"Taxation	and	Uncertain	Tax	Positions"	in	the	"Critical	Accounting	Estimates"	section	of	Entergy	Corporation	and	Subsidiaries

Management's	Financial	Discussion	and	Analysis	for	further	discussion.

Entergy	Arkansas's	qualified	pension	and	other	postretirement	reported	costs,	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	Assumption | Impact	on	2018	Qualified<br>Pension	Cost | Impact	on	2017	Qualified<br>Projected	Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $3,107 | $47,040 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $2,914 | $- |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $1,353 | $6,446 |

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	Assumption | Impact	on	2018<br>Postretirement	Benefit	Cost | Impact	on	2017<br>Accumulated	Postretirement<br>Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $506 | $7,552 |
| Health\tcare\tcost\ttrend | 0.25% | $782 | $5,513 |

# Costs	and	Funding

Total	qualified	pension	cost	for	Entergy	Arkansas	in	2017	was	$37	million.		Entergy	Arkansas	anticipates	2018	qualified	pension	cost	to be	$43	million.	In	2016,	Entergy	Arkansas	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified	pension costs,	which	had	the	effect	of	lowering	qualified	pension	costs	by	$13.3	million.	Entergy	Arkansas	contributed	$79.6	million	to	its	qualified pension	 plan	in	2017	and	estimates	pension	contributions	will	be	approximately	$64.1	million	in	2018,	although	the	2018	required	pension contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	other	postretirement	health	care	and	life	insurance	benefit	income	for	Entergy	Arkansas	in	2017	was	$4	million.		Entergy	Arkansas expects	2018	postretirement	health	care	and	life	insurance	benefit	income	of	approximately	$10.2	million.		In	2016,	Entergy	Arkansas	refined	its approach	to	estimating	the	service	cost	and	interest	cost	components	of	other	postretirement	costs,	which	had	the	effect	of	lowering	qualified	other postretirement	costs	by	$2.5	million.	Entergy	Arkansas	contributed	$695	thousand	to	its	other	postretirement	plans	in	2017	and	estimates	2018 contributions	will	be	approximately	$472	thousand.

See	"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	"Other	Contingencies"	in	the	"Critical	Accounting	Estimates"	section	of	Entergy	Corporation	and	Subsidiaries	Management's Financial	Discussion	and	Analysis	for	a	discussion	of	the	estimates	associated	with	environmental,	litigation,	and	other	risks.

See "New	 Accounting	 Pronouncements" section of	 Note 1 to the financial statements for a discussion of new accounting pronouncements.

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Arkansas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31, 2017	and	2016,	the	related	consolidated	statements	of	income,	cash	flows	and	changes	in	common	equity	(pages	319	through	324	and	applicable items	in	pages	55	through	230),	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	and	the	related	notes	(collectively	referred	to as	the	"financial	statements").	In	our	opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company as	of	December	31,	2017	and	2016,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2017,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

These	financial	statements	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	the	Company's financial	statements	based	on	our	audits.	We	are	a	public	accounting	firm	registered	with	the	Public	Company	Accounting	Oversight	Board (United	States)	(PCAOB)	and	are	required	to	be	independent	with	respect	to	the	Company	in	accordance	with	the	U.S.	federal	securities	laws	and the	applicable	rules	and	regulations	of	the	Securities	and	Exchange	Commission	and	the	PCAOB.

We	conducted	our	audits	in	accordance	with	the	standards	of	the	PCAOB.	Those	standards	require	that	we	plan	and	perform	the	audit	to	obtain reasonable	assurance	about	whether	the	financial	statements	are	free	of	material	misstatement,	whether	due	to	error	or	fraud.	The	Company	is	not required	to	have,	nor	were	we	engaged	to	perform,	an	audit	of	its	internal	control	over	financial	reporting.	As	part	of	our	audits,	we	are	required	to obtain	an	understanding	of	internal	control	over	financial	reporting	but	not	for	the	purpose	of	expressing	an	opinion	on	the	effectiveness	of	the Company's	internal	control	over	financial	reporting.	Accordingly,	we	express	no	such	opinion.

Our	audits	included	performing	procedures	to	assess	the	risks	of	material	misstatement	of	the	financial	statements,	whether	due	to	error	or	fraud, and	performing	procedures	that	respond	to	those	risks.	Such	procedures	included	examining,	on	a	test	basis,	evidence	regarding	the	amounts	and disclosures	in	the	financial	statements.	Our	audits	also	included	evaluating	the	accounting	principles	used	and	significant	estimates	made	by management,	as	well	as	evaluating	the	overall	presentation	of	the	financial	statements.	We	believe	that	our	audits	provide	a	reasonable	basis	for our	opinion.

We	have	served	as	the	Company's	auditor	since	2001.

# CONSOLIDATED	INCOME	STATEMENTS

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $2,139,919 | $2,086,608 | $2,253,564 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 402,777 | 325,036 | 535,919 |
| Purchased\tpower | 230,652 | 233,350 | 380,081 |
| Nuclear\trefueling\toutage\texpenses | 83,968 | 56,650 | 51,411 |
| Other\toperation\tand\tmaintenance | 707,825 | 706,573 | 734,118 |
| Decommissioning | 56,860 | 53,610 | 50,414 |
| Taxes\tother\tthan\tincome\ttaxes | 103,662 | 93,109 | 99,926 |
| Depreciation\tand\tamortization | 277,146 | 264,215 | 246,897 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (16,074) | 7,737 | (24,608) |
| TOTAL | 1,846,816 | 1,740,280 | 2,074,158 |
| OPERATING\tINCOME | 293,103 | 346,328 | 179,406 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 18,452 | 17,099 | 14,227 |
| Interest\tand\tinvestment\tincome | 35,882 | 19,087 | 22,382 |
| Miscellaneous\t-\tnet | (299) | (1,446) | (3,385) |
| TOTAL | 54,035 | 34,740 | 33,224 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 122,075 | 115,311 | 105,622 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (8,585) | (9,228) | (7,805) |
| TOTAL | 113,490 | 106,083 | 97,817 |
| INCOME\tBEFORE\tINCOME\tTAXES | 233,648 | 274,985 | 114,813 |
| Income\ttaxes | 93,804 | 107,773 | 40,541 |
| NET\tINCOME | 139,844 | 167,212 | 74,272 |
| Preferred\tdividend\trequirements | 1,428 | 5,270 | 6,873 |
| EARNINGS\tAPPLICABLE\tTO\tCOMMON\tSTOCK | $138,416 | $161,942 | $67,399 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $139,844 | $167,212 | $74,272 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 427,394 | 414,933 | 400,156 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 67,711 | 201,219 | (4,330) |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (23,397) | (39,118) | 20,813 |
| Fuel\tinventory | 3,402 | 29,929 | (11,791) |
| Accounts\tpayable | 16,011 | 143,645 | (2,528) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 40,127 | 37,485 | (54,531) |
| Interest\taccrued | 1,635 | (3,303) | (367) |
| Deferred\tfuel\tcosts | 33,190 | (105,741) | 151,332 |
| Other\tworking\tcapital\taccounts | 15,087 | (46,490) | (44,784) |
| Provisions\tfor\testimated\tlosses | 16,047 | 13,130 | (137) |
| Other\tregulatory\tassets | (76,762) | (95,464) | 60,279 |
| Other\tregulatory\tliabilities | 1,043,507 | 62,994 | (11,123) |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (1,047,837) | — | — |
| Pension\tand\tother\tpostretirement\tliabilities | (70,826) | (36,805) | (110,936) |
| Other\tassets\tand\tliabilities | (29,577) | (67,115) | 8,565 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 555,556 | 676,511 | 474,890 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (735,816) | (666,289) | (624,546) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 19,211 | 17,754 | 15,882 |
| Nuclear\tfuel\tpurchases | (151,424) | (102,050) | (132,252) |
| Proceeds\tfrom\tsale\tof\tnuclear\tfuel | 51,029 | 39,313 | 52,281 |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 339,434 | 197,390 | 212,954 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (352,138) | (213,093) | (223,357) |
| Payment\tfor\tpurchase\tof\tplant | — | (237,323) | — |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | — | — | 2,218 |
| Insurance\tproceeds | — | 10,404 | 11,654 |
| Other | 392 | 5,899 | (108) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (829,312) | (947,995) | (685,274) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 294,656 | 817,563 | — |
| Retirement\tof\tlong-term\tdebt | (175,560) | (628,433) | (13,234) |
| Capital\tcontribution\tfrom\tparent | — | 200,000 | — |
| Redemption\tof\tpreferred\tstock | — | (85,283) | — |
| Change\tin\tmoney\tpool\tpayable\t-\tnet | 114,905 | (1,510) | 52,742 |
| Changes\tin\tshort-term\tborrowings\t-\tnet | 49,974 | (11,690) | (36,278) |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (15,000) | — | — |
| Preferred\tstock | (1,428) | (6,631) | (6,873) |
| Other | (8,084) | (1,158) | 4,657 |
| Net\tcash\tflow\tprovided\tby\tfinancing\tactivities | 259,463 | 282,858 | 1,014 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (14,293) | 11,374 | (209,370) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 20,509 | 9,135 | 218,505 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,216 | $20,509 | $9,135 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $115,162 | $112,912 | $100,435 |
| Income\ttaxes | ($8,141) | ($135,709) | $103,296 |

| Cash | $6,184 | $20,174 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 32 | 335 |
| Total\tcash\tand\tcash\tequivalents | 6,216 | 20,509 |
| Securitization\trecovery\ttrust\taccount | 3,748 | 4,140 |
| Accounts\treceivable: |  |  |
| Customer | 110,016 | 102,229 |
| Allowance\tfor\tdoubtful\taccounts | (1,063) | (1,211) |
| Associated\tcompanies | 38,765 | 35,286 |
| Other | 65,209 | 58,153 |
| Accrued\tunbilled\trevenues | 105,120 | 100,193 |
| Total\taccounts\treceivable | 318,047 | 294,650 |
| Deferred\tfuel\tcosts | 63,302 | 96,690 |
| Fuel\tinventory\t-\tat\taverage\tcost | 29,358 | 32,760 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 192,853 | 182,600 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 56,485 | 81,313 |
| Prepayments\tand\tother | 12,108 | 14,293 |
| TOTAL | 682,117 | 726,955 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 944,890 | 834,735 |
| Other | 3,160 | 7,912 |
| TOTAL | 948,050 | 842,647 |
| UTILITY\tPLANT |  |  |
| Electric | 11,059,538 | 10,488,060 |
| Property\tunder\tcapital\tlease | — | 716 |
| Construction\twork\tin\tprogress | 280,888 | 304,073 |
| Nuclear\tfuel | 277,345 | 307,352 |
| TOTAL\tUTILITY\tPLANT | 11,617,771 | 11,100,201 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 4,762,352 | 4,635,885 |
| UTILITY\tPLANT\t-\tNET | 6,855,419 | 6,464,316 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 62,646 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof\t$28,583\tas\tof\tDecember\t31,\t2017\tand\t$41,164\tas\tof\nDecember\t31,\t2016) | 1,567,437 | 1,428,029 |
| Deferred\tfuel\tcosts | 67,096 | 66,898 |
| Other | 13,910 | 14,626 |
| TOTAL | 1,648,443 | 1,572,199 |
| TOTAL\tASSETS | $10,134,029 | $9,606,117 |

| Currently	maturing	long-term	debt | $— | $114,700 |
| :--- | :--- | :--- |
| Short-term\tborrowings | 49,974 | — |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 365,915 | 239,711 |
| Other | 215,942 | 185,153 |
| Customer\tdeposits | 97,687 | 97,512 |
| Taxes\taccrued | 47,321 | 7,194 |
| Interest\taccrued | 18,215 | 16,580 |
| Other | 29,922 | 36,557 |
| TOTAL | 824,976 | 697,407 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 1,190,669 | 2,186,623 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 34,104 | 35,305 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 985,823 | — |
| Other\tregulatory\tliabilities | 363,591 | 305,907 |
| Decommissioning | 981,213 | 924,353 |
| Accumulated\tprovisions | 34,729 | 18,682 |
| Pension\tand\tother\tpostretirement\tliabilities | 353,274 | 424,234 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$34,662\tas\tof\tDecember\t31,\t2017\tand\t$48,139\tas\tof\tDecember\t31,\n2016) | 2,952,399 | 2,715,085 |
| Other | 5,147 | 13,854 |
| TOTAL | 6,900,949 | 6,624,043 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 31,350 | 31,350 |
| COMMON\tEQUITY |  |  |
| 2016 | 470 | 470 |
| Paid-in\tcapital | 790,264 | 790,243 |
| Retained\tearnings | 1,586,020 | 1,462,604 |
| TOTAL | 2,376,754 | 2,253,317 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $10,134,029 | $9,606,117 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	COMMON	EQUITY

|  | Common	Stock | Paid-in	Capital | Retained	Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Balance\tat\tDecember\t31,\t2014 | $470 | $588,471 | $1,235,296 | $1,824,237 |
| Net\tincome | — | — | 74,272 | 74,272 |
| Preferred\tstock\tdividends | — | — | (6,873) | (6,873) |
| Other | — | 22 | — | 22 |
| Balance\tat\tDecember\t31,\t2015 | $470 | $588,493 | $1,302,695 | $1,891,658 |
| Net\tincome | — | — | 167,212 | 167,212 |
| Capital\tcontributions\tfrom\tparent | — | 200,000 | — | 200,000 |
| Capital\tstock\tredemption | — | 1,750 | (2,033) | (283) |
| Preferred\tstock\tdividends | — | — | (5,270) | (5,270) |
| Balance\tat\tDecember\t31,\t2016 | $470 | $790,243 | $1,462,604 | $2,253,317 |
| Net\tincome | — | — | 139,844 | 139,844 |
| Common\tstock\tdividends | — | — | (15,000) | (15,000) |
| Preferred\tstock\tdividends | — | — | (1,428) | (1,428) |
| Other | — | 21 | — | 21 |
| Balance\tat\tDecember\t31,\t2017 | $470 | $790,264 | $1,586,020 | $2,376,754 |

# ENTERGY	LOUISIANA,	LLC	AND	SUBSIDIARIES

Net	income	decreased	$305.7	million	primarily	due	to	the	effect	of	the	enactment	of	the	Tax	Cuts	and	Jobs	Act,	in	December	2017,	which resulted	in	a	decrease	of	$182.6	million	in	net	income	in	2017,	and	the	effect	of	a	settlement	with	the	IRS	related	to	the	2010-2011	IRS	audit, which	resulted	in	a	$136.1	million	reduction	of	income	tax	expense	in	2016.	Also	contributing	to	the	decrease	in	net	income	were	higher	other operation	and	maintenance	expenses.	The	decrease	was	partially	offset	by	higher	net	revenue	and	higher	other	income.	See	Note	3	to	the	financial statements	for	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act	and	the	IRS	audit.

Net	income	increased	$175.4	million	primarily	due	to	the	effect	of	a	settlement	with	the	IRS	related	to	the	2010-2011	IRS	audit,	which resulted	 in	 a	 $136.1	 million	 reduction	 of	 income	 tax	 expense	 in	 2016.	Also	 contributing	 to	 the	 increase	 were	 lower	 other	 operation	 and maintenance	expenses,	higher	net	revenue,	and	higher	other	income.	The	increase	was	partially	offset	by	higher	depreciation	and	amortization expenses,	higher	interest	expense,	and	higher	nuclear	refueling	outage	expenses.	See	Note	3	to	the	financial	statements	for	discussion	of	the	IRS audit.

| 2016	net	revenue | $2,438.4 |
| :--- | :--- |
| Regulatory\tcredit\tresulting\tfrom\treduction\tof\tthe\n\t\tfederal\tcorporate\tincome\ttax\trate | 55.5 |
| Retail\telectric\tprice | 42.8 |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | 17.2 |
| Volume/weather | (12.4) |
| Other | 19.0 |
| 2017\tnet\trevenue | $2,560.5 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	formula	rate	plan	revenues,	implemented	with	the	first	billing	cycle	of March	2016,	to	collect	the	estimated	first-year	revenue	requirement	related	to	the	purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station	in March	 2016	 and	 a	 provision	 recorded	 in	 2016	 related	 to	 the	 settlement	 of	 the	Waterford	 3	 replacement	 steam	 generator	 prudence	 review proceeding.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	formula	rate	plan	revenues	and	the	Waterford	3	replacement	steam generator	prudence	review	proceeding.

The	Louisiana	Act	55	financing	savings	obligation	variance	results	from	a	regulatory	charge	recorded	in	2016	for	tax	savings	to	be	shared with	customers	per	an	agreement	approved	by	the	LPSC.	The	tax	savings	resulted	from	the	2010-2011	IRS	audit	settlement	on	the	treatment	of the	Louisiana	Act	55	financing	of	storm	costs	for	Hurricane	Gustav	and	Hurricane	Ike.	See	Note	3	to	the	financial	statements	for	additional discussion	of	the	settlement	and	benefit	sharing.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales	and	decreased usage	during	the	unbilled	sales	period.	The	decrease	was	partially	offset	by	an	increase	of	1,237	GWh,	or	4%,	in	industrial	usage	primarily	due	to an	increase	in	demand	from	existing	customers	and	expansion	projects	in	the	chemicals	industry.

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	2016	to	2015.

| 2015	net	revenue | $2,408.8 |
| :--- | :--- |
| Retail\telectric\tprice | 62.5 |
| Volume/weather | (6.7) |
| Louisiana\tAct\t55\tfinancing\tsavings\tobligation | (17.2) |
| Other | (9.0) |
| 2016\tnet\trevenue | $2,438.4 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	formula	rate	plan	revenues,	implemented	with	the	first	billing	cycle	of March	2016,	to	collect	the	estimated	first-year	revenue	requirement	related	to	the	purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station. See	Note	2	to	the	financial	statements	for	further	discussion.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	sales,	partially	offset	by	an	increase	in industrial	usage	and	an	increase	in	volume	during	the	unbilled	period.	The	increase	in	industrial	usage	is	primarily	due	to	increased	demand	from new	customers	and	expansion	projects,	primarily	in	the	chemicals	industry.

Included	in	Other	is	a	provision	of	$23	million	recorded	in	2016	related	to	the	settlement	of	the	Waterford	3	replacement	steam	generator prudence	review	proceeding,	offset	by	a	provision	of	$32	million	recorded	in	2015	related	to	the	uncertainty	at	that	time	associated	with	the resolution	of	the	Waterford	3	replacement	steam	generator	prudence

review	proceeding.		See	Note	2	to	the	financial	statements	for	a	discussion	of	the	Waterford	3	replacement	steam	generator	prudence	review proceeding.

•an	increase	of	$17.8	million	in	nuclear	generation	expenses	primarily	due	to	higher	nuclear	labor	costs,	including	contract	labor,	to position	the	nuclear	fleet	to	meet	its	operational	goals,	partially	offset	by	a	lower	scope	of	work	performed	during	plant	outages	in	2017;

•an	increase	of	$4.1	million	as	a	result	of	the	amount	of	transmission	costs	allocated	by	MISO.	See	Note	2	to	the	financial	statements	for further	information	on	the	recovery	of	these	costs;

•an	increase	of	$3.6	million	in	transmission	and	distribution	expenses	due	to	higher	vegetation	maintenance	costs;	and

•an	increase	of	$3.2	million	in	write-offs	of	customer	accounts.

Taxes	other	than	income	taxes	increased	primarily	due	to	increases	in	ad	valorem	taxes,	state	franchise	taxes,	and	payroll	taxes.	Ad valorem	taxes	increased	primarily	due	to	higher	assessments,	including	the	assessment	of	Arkansas	ad	valorem	taxes	on	the	Union	Power	Station beginning	in	2017.	State	franchise	taxes	increased	primarily	due	to	a	change	in	the	Louisiana	franchise	tax	law	which	became	effective	for	2017.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	Power	Blocks	3	and	4	of	the Union	Power	Station	purchased	in	March	2016,	and	the	effects	of	recording	in	third	quarter	2016	final	court	decisions	in	the	River	Bend	and Waterford	 3	 lawsuits	 against	 the	 DOE	 related	 to	 spent	 nuclear	 fuel	 storage	 costs.	The	 damages	 awarded	 include	 the	 reimbursement	 of approximately	$6	million	of	spent	nuclear	fuel	storage	costs	previously	recorded	as	depreciation	expense.	See	Note	14	to	the	financial	statements for	discussion	of	the	Union	Power	Station	purchase.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation.

Other	income	increased	primarily	due	to	an	increase	in	the	allowance	for	equity	funds	used	during	construction	due	to	higher	construction work	 in	 progress	 in	 2017,	 which	 includes	 the	 St.	 Charles	 Power	 Station	 project,	 and	 higher	 realized	 gains	 in	 2017	 on	 the	 River	 Bend decommissioning	trust	fund	investments,	including	portfolio	rebalancing	to	the	30%	interest	in	River	Bend	formerly	owned	by	Cajun.

Interest	expense	decreased	primarily	due	to	an	increase	in	the	allowance	for	borrowed	funds	used	during	construction	due	to	higher construction	work	in	progress	in	2017,	which	includes	the	St.	Charles	Power	Station	project.

Nuclear	refueling	outage	expenses	increased	primarily	due	to	the	amortization	of	higher	expenses	associated	with	the	refueling	outages	at Waterford	3.

•the	$45	million	write-off	recorded	in	2015	to	recognize	the	portion	of	the	assets	associated	with	the	Waterford	3	replacement	steam generator	project	no	longer	probable	of	recovery.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	prudence	review proceeding;	and

Entergy	Louisiana,	LLC	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

•a	decrease	of	$35	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	net	periodic	pension	and	other	postretirement costs	as	a	result	of	higher	discount	rates	used	to	value	the	benefit	liabilities	and	a	refinement	in	the	approach	used	to	estimate	the	service cost	and	interest	cost	components	of	pension	and	other	postretirement	costs.	See	"Critical	Accounting	Estimates	-	Qualified	Pension and	 Other	 Postretirement	 Benefits"	 below	 and	 Note	 11 to	 the	 financial	 statements	 for	 further	 discussion	 of	 pension	 and	 other postretirement	benefit	costs.

The	decrease	was	partially	offset	by	an	increase	of	$19.9	million	in	nuclear	generation	expenses	primarily	due	to	higher	nuclear	labor	costs, including	contract	labor.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	Power	Blocks	3	and	4	of	the Union	Power	Station	purchased	in	March	2016.

Other	income	increased	primarily	due	to	an	increase	in	the	allowance	for	equity	funds	used	during	construction	due	to	higher	construction work	 in	progress	 in	2016,	which	 included	 the	St.	Charles	Power	Station	project,	and	 increased	distribution	and	 transmission	spending.	The increase	was	also	due	to	higher	income	in	2016	on	the	River	Bend	and	Waterford	3	decommissioning	trust	fund	investments.

•the	issuance	in	March	2016	of	$425	million	of	3.25%	Series	collateral	trust	mortgage	bonds;

•the	issuance	in	March	2016	of	$200	million	of	4.95%	Series	first	mortgage	bonds;	and

•the	issuance	in	October	2016	of	$400	million	of	2.40%	Series	collateral	trust	mortgage	bonds.

The	increase	was	partially	offset	by	the	refinancing	at	lower	interest	rates	of	certain	first	mortgage	bonds.	See	Note	5	to	the	financial	statements for	details	of	long-term	debt.

The	effective	income	tax	rates	for	2017,	2016,	and	2015	were	60.5%,	12.6%,	and	28.6%,	respectively.	The	difference	in	the	effective income	tax	rate	of	60.5%	for	2017	versus	the	statutory	rate	of	35%	for	2017	was	primarily	due	to	the	enactment	of	the	Tax	Cuts	and	Jobs	Act, signed	by	President	Trump	in	December	2017,	which	changed	the	federal	corporate	income	tax	rate	from	35%	to	21%	effective	in	2018.	See	Note 3	to	the	financial	statements	for	further	discussion	of	the	effects	of	the	Tax	Cuts	and	Jobs	Act.	The	difference	in	the	effective	income	tax	rate	of 12.6%	for	2016	versus	the	statutory	rate	of	35%	for	2016	was	primarily	due	to	the	reversal	of	a	portion	of	the	provision	for	uncertain	tax	positions as	a	result	of	the	settlement	of	the	2010-2011	IRS	audit	in	the	second	quarter	2016	and	book	and	tax	differences	related	to	the	non-taxable	income distributions	 earned	 on	 preferred	 membership	 interests,	 partially	 offset	 by	 state	 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.

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $213,850 | $35,102 | $320,516 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 1,337,545 | 1,037,912 | 1,155,516 |
| Investing\tactivities | (1,787,409) | (1,474,065) | (994,208) |
| Financing\tactivities | 271,921 | 614,901 | (446,722) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (177,943) | 178,748 | (285,414) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $35,907 | $213,850 | $35,102 |

Net	cash	flow	provided	by	operating	activities	increased	$299.6	million	in	2017	primarily	due	to:

•income	tax	refunds	of	$234.2	million	in	2017	compared	to	income	tax	payments	of	$156.6	million	in	2016.	Entergy	Louisiana	received income	tax	refunds	in	2017	and	made	income	tax	payments	in	2016	in	accordance	with	an	intercompany	income	tax	allocation	agreement. The	income	tax	refunds	in	2017	resulted	from	the	utilization	of	Entergy	Louisiana's	net	operating	losses.	The	income	tax	payments	in 2016	resulted	primarily	from	adjustments	associated	with	the	settlement	of	the	2010-2011	IRS	audit,	payments	for	state	taxes	resulting from	the	effect	of	the	final	settlement	of	the	2006-2007	IRS	audit,	and	the	effect	of	net	operating	loss	limitations.	See	Note	3	to	the financial	statements	for	a	discussion	of	the	audits;

•an	increase	due	to	the	timing	of	recovery	of	fuel	and	purchased	power	costs;	and

•an	interest	payment	of	$60	million	made	in	March	2016	related	to	the	purchase	of	a	beneficial	interest	in	the	Waterford	3	leased	assets.

•a	refund	to	customers	in	January	2017	of	approximately	$71	million	as	a	result	of	the	settlement	approved	by	the	LPSC	related	to	the Waterford	3	replacement	steam	generator	project.	See	Note	2	to	the	financial	statements	for	discussion	of	the	settlement	and	refund; •an	increase	of	$62.8	million	in	spending	on	nuclear	refueling	outages;	and

•proceeds	of	$37.8	million	received	in	August	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel	storage	costs	that were	previously	expensed.	See	Note	8	to	the	financial	statements	for	a	discussion	of	the	spent	nuclear	fuel	litigation.

Net	cash	flow	provided	by	operating	activities	decreased	$117.6	million	in	2016	primarily	due	to:

•an	increase	of	$67.5	million	in	income	tax	payments	in	2016.	Entergy	Louisiana	had	income	tax	payments	in	2016	and	2015	in	accordance with	intercompany	income	tax	allocation	agreements.	The	income	tax	payments	in	2016	resulted	primarily	from	adjustments	associated with	the	settlement	of	the	2010-2011	IRS	audit,	payments	for	state	taxes	resulting	from	the	effect	of	the	final	settlement	of	the	2006-2007 IRS	audit,	and	the	effect	of	net	operating	loss	limitations.	The	2015	income	tax	payments	resulted	primarily	from	adjustments

associated	with	the	settlement	of	the	2008-2009	IRS	audit.	See	Note	3	to	the	financial	statements	for	a	discussion	of	the	income	tax	audits; •an	increase	of	$80.7	million	in	interest	paid	resulting	from	an	increase	in	interest	expense,	including	a	payment	of	$60	million	made	in March	2016	related	to	the	purchase	of	a	beneficial	interest	in	the	Waterford	3	leased	assets.	See	Note	10	to	the	financial	statements	for	a discussion	of	the	purchase	of	a	beneficial	interest	in	the	Waterford	3	leased	assets;

•the	timing	of	collections	from	customers	and	payments	to	vendors;	and

•a	decrease	due	to	the	timing	of	recovery	of	fuel	and	purchased	power	costs	in	2016.

The	decrease	was	partially	offset	by	proceeds	of	$37.8	million	received	in	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear fuel	storage	costs	that	were	previously	expensed	and	a	decrease	of	$30.5	million	in	spending	on	nuclear	refueling	outages	in	2016.	See	Note	8	to the	financial	statements	for	a	discussion	of	the	spent	nuclear	fuel	litigation.

Net	cash	flow	used	in	investing	activities	increased	$313.3	million	in	2017	primarily	due	to:

•an	increase	of	$364.3	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	higher	spending	on	the	St.	Charles Power	Station	and	Lake	Charles	Power	Station	projects	in	2017;

•an	increase	of	$148.9	million	in	transmission	construction	expenditures	due	to	a	higher	scope	of	work	performed	in	2017;

•proceeds	of	$57.9	million	received	in	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel	storage	costs	that	were previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation;

•an	increase	of	$53.6	million	in	nuclear	construction	expenditures	primarily	due	to	increased	spending	on	various	nuclear	projects	in	2017; •an	increase	of	$30.4	million	in	distribution	construction	expenditures	due	to	increased	spending	on	digital	technology	improvements within	the	customer	contact	centers;

•an	increase	of	$19.9	million	due	to	increased	spending	on	advanced	metering	infrastructure;	and

•an	increase	of	$12.3	million	due	to	various	information	technology	projects	and	upgrades	in	2017.

•the	purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station	for	an	aggregate	purchase	price	of	approximately	$475	million	in	March 2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase;

•money	pool	activity;	and

•an	increase	in	the	allowance	for	equity	funds	used	during	construction	due	to	higher	construction	work	in	progress	in	2017.

Decreases	in	Entergy	Louisiana's	receivable	from	the	money	pool	are	a	source	of	cash	flow,	and	Entergy	Louisiana's	receivable	from	the money	pool	decreased	by	$11.3	million	in	2017	compared	to	increasing	by	$16.3	million	in	2016.	The	money	pool	is	an	inter-company	borrowing arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

•an	increase	of	$130.7	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	spending	on	the	St.	Charles	Power Station	project	in	2016;

•cash	proceeds	of	$59.6	million	received	in	2015	from	the	transfer	of	Algiers	assets	to	Entergy	New	Orleans	in	September	2015.	See "State	and	Local	Rate	Regulation	and	Fuel-Cost	Recovery	-	Retail	Rates	-	Electric	-	Filings	with	the	City	Council"	below	for	further discussion	of	the	transfer;

•an	increase	of	$52	million	in	transmission	construction	expenditures	due	to	a	higher	scope	of	work	performed	in	2016;	and •an	increase	of	$20.5	million	due	to	various	information	technology	projects	and	upgrades	in	2016.

•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	service	deliveries,	and	the	timing	of	cash	payments	during	the	nuclear	fuel	cycle;

•proceeds	of	$57.9	million	received	in	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel	storage	costs	that	were previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation;	and

•a	decrease	of	$16.9	million	in	nuclear	construction	expenditures	primarily	due	to	decreased	spending	on	compliance	with	NRC	post- Fukushima	requirements.

Net	cash	flow	provided	by	financing	activities	decreased	$343	million	in	2017	primarily	due	to	the	net	issuance	of	$325.6	million	of	long- term	debt	in	2017	compared	to	the	net	issuance	of	$961.2	million	in	2016.	The	decrease	was	partially	offset	by:

•a	decrease	of	$194.3	million	of	common	equity	distributions	primarily	as	a	result	of	higher	construction	expenditures	and	higher	nuclear fuel	purchases	in	2017;	and

•net	 borrowings	 of	 $39.7	 million	 on the	 nuclear fuel	 company	 variable interest	 entities'	 credit facilities in	 2017	 compared to	 net repayments	of	$56.6	million	in	2016.

Entergy	Louisiana's	financing	activities	provided	$614.9	million	of	cash	in	2016	compared	to	using	$446.7	million	in	2015	primarily	due to	the	following	activity:

•the	net	issuance	of	$961.2	million	of	long-term	debt	in	2016	compared	to	the	net	retirement	of	$103.4	million	of	long-term	debt	in	2015; •the	redemption	in	September	2015	of	$100	million	of	6.95%	Series	and	$10	million	of	8.25%	Series	preferred	membership	interests	in connection	with	the	Entergy	Louisiana	and	Entergy	Gulf	States	Louisiana	business	combination;

•net	repayments	of	borrowings	of	$56.6	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2016	compared	to net	borrowings	of	$14.3	million	in	2015;	and

•an	increase	of	$59.5	million	in	common	equity	distributions	in	2016.	Equity	distributions	were	lower	in	2015	in	anticipation	of	the purchase	of	Power	Blocks	3	and	4	of	the	Union	Power	Station.

See	Note	5	to	the	financial	statements	for	details	of	long-term	debt.

Entergy	Louisiana's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.

|  | December	31,<br>2017 | December	31,<br>2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 53.8% | 53.4% |
| Effect\tof\texcluding\tsecuritization\tbonds | (0.3%) | (0.5%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 53.5% | 52.9% |
| Effect\tof\tsubtracting\tcash | (0.1%) | (0.9%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 53.4% | 52.0% |

(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	and	common	equity.		Net	capital	consists	of	capital	less	cash	and	cash	equivalents.		Entergy	Louisiana 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	 Louisiana's	 financial	 condition	 because	 the	 securitization	 bonds	 are	 non-recourse	 to	 Entergy Louisiana,	as	more	fully	described	in	Note	5	to	the	financial	statements.	Entergy	Louisiana	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	 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	on	hand.

Entergy	Louisiana	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital while	also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.		To	the	extent	that	operating	cash	flows	are	in excess	of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to maintain	the	targeted	capital	structure.		To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	Entergy	Louisiana may	issue	incremental	debt	or	reduce	dividends,	or	both,	to	maintain	its	targeted	capital	structure.		In	addition,	in	certain	infrequent	circumstances, such	as	large	transactions	that	would	materially	alter	the	capital	structure	if	financed	entirely	with	debt	and	reducing	dividends,	Entergy	Louisiana may	receive	equity	contributions	to	maintain	the	targeted	capital	structure.

Entergy	Louisiana	requires	capital	resources	for:

•debt	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	Louisiana's	planned	construction	and	other	capital	investments.

| Generation | $875 | $530 | $330 |
| :--- | :--- | :--- | :--- |
| Transmission | 465 | 350 | 285 |
| Distribution | 325 | 395 | 365 |
| Utility\tSupport | 165 | 110 | 135 |
| Total | $1,830 | $1,385 | $1,115 |

Following	are	the	amounts	of	Entergy	Louisiana's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2018 | 2019-2020 | 2021-2022 | After	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $940 | $903 | $843 | $6,785 | $9,471 |
| Operating\tleases | $22 | $41 | $24 | $19 | $106 |
| Purchase\tobligations\t(b) | $633 | $1,420 | $1,366 | $7,125 | $10,544 |

(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	$71.9	million	to	its qualified	pension	plans	and	approximately	$19	million	to	its	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the	2018 required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April 1,	 2018.	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	Louisiana	has	$926.6	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	Louisiana	includes specific	investments,	such	as	the	St.	Charles	Power	Station	and	Lake	Charles	Power	Station,	each	discussed	below;	transmission	projects	to enhance	reliability,	reduce	congestion,	and	enable	economic	growth;	distribution	spending	to	enhance	reliability	and	improve	service	to	customers, including	investment	to	support	advanced	metering;	resource	planning,	including	potential	generation	projects;	system	improvements;	investments in	River	Bend	and	Waterford	3;	and	other	investments.		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	and requirements,

environmental	compliance,	business	opportunities,	market	volatility,	economic	trends,	business	restructuring,	changes	in	project	plans,	and	the ability	to	access	capital.

As	a	wholly-owned	subsidiary	of	Entergy	Utility	Holding	Company,	LLC,	Entergy	Louisiana	pays	distributions	from	its	earnings	at	a percentage	determined	monthly.

In	November	2016,	Entergy	Louisiana	filed	an	application	seeking	a	finding	from	the	LPSC	that	Entergy	Louisiana's	deployment	of advanced	electric	and	gas	metering	infrastructure	is	in	the	public	interest.	Entergy	Louisiana	proposed	to	deploy	advanced	meters	that	enable	two- way	data	communication;	design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement	support	systems.	AMI is	intended	to	serve	as	the	foundation	of	Entergy	Louisiana's	modernized	power	grid.	The	filing	included	an	estimate	of	implementation	costs	for AMI	 of	$330	million.	The	filing	identified	a	number	of	quantified	and	unquantified	benefits,	and	Entergy	Louisiana	provided	a	cost/benefit analysis	showing	that	its	combined	electric	and	gas	AMI	deployment	is	expected	to	produce	a	nominal	net	benefit	to	customers	of	$607	million. Entergy	Louisiana	also	sought	to	continue	to	include	in	rate	base	the	remaining	book	value,	approximately	$92	million	at	December	31,	2015,	of the	existing	electric	meters	and	also	to	depreciate	those	assets	using	current	depreciation	rates.	Entergy	Louisiana	proposed	a	15-year	useful	life for	the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019.	The	communications	network	deployment

is	expected	to	begin	by	late-2018,	after	the	necessary	information	technology	infrastructure	is	in	place.	Entergy	Louisiana	proposed	to	recover	the cost	of	AMI	through	the	implementation	of	a	customer	charge,	net	of	certain	benefits,	phased	in	over	the	period	2019	through	2022.	The	parties reached	an	uncontested	stipulation	permitting	implementation	of	Entergy	Louisiana's	proposed	AMI	system,	with	modifications	to	the	proposed customer	charge.	In	July	2017	the	LPSC	approved	the	stipulation.	Entergy	Louisiana	expects	to	recover	the	undepreciated	balance	of	its	existing meters	through	a	regulatory	asset	at	current	depreciation	rates.

Entergy	Louisiana's	sources	to	meet	its	capital	requirements	include:

•debt	or	preferred	membership	interest	issuances;	and

Entergy	Louisiana	may	refinance,	redeem,	or	otherwise	retire	debt	prior	to	maturity,	to	the	extent	market	conditions	and	interest	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	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $11,173 | $22,503 | $6,154 | $2,815 |

Entergy	Louisiana	has	a	credit	facility	in	the	amount	of	$350	million	scheduled	to	expire	in	August	2022.	The	credit	facility	allows Entergy	Louisiana	to	issue	letters	of	credit	against	$15	million	of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2017,	there	were	no cash	 borrowings	 and	 a	 $9.1	 million	 letter	 of	 credit	 outstanding	 under	 the	 credit	 facility.	In	 addition,	 Entergy	 Louisiana	 is	 a	 party	 to	 an uncommitted	letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	to	MISO.		As	of	December	31,	2017,	a	$29.7	million letter	 of	 credit	 was	 outstanding	 under	 Entergy	 Louisiana's	 uncommitted	 letter	 of	 credit	 facility.	See	 Note	 4	 to	 the	 financial	 statements	 for additional	discussion	of	the	credit	facilities.

The	Entergy	Louisiana	nuclear	fuel	company	variable	interest	entities	have	two	separate	credit	facilities,	one	in	the	amount	of	$105 million	and	one	in	the	amount	of	$85	million,	both	scheduled	to	expire	in	May	2019.	As	of	December	31,	2017,	$65.7	million	of	loans	were outstanding	under	the	credit	facility	for	the	Entergy	Louisiana	River	Bend	nuclear	fuel	company	variable	interest	entity.	As	of	December	31, 2017,	$43.5	million	in	letters	of	credit	to	support	a	like	amount	of	commercial	paper	issued	and	$36.4	million	in	loans	were	outstanding	under	the Entergy	Louisiana	Waterford	nuclear	fuel	company	variable	interest	entity	credit	facility.	 See	Note	4	to	the	financial	statements	for	additional discussion	of	the	nuclear	fuel	company	variable	interest	entity	credit	facilities.

Entergy	Louisiana	obtained	authorizations	from	the	FERC	through	October	2019	for	the	following:

•short-term	borrowings	not	to	exceed	an	aggregate	amount	of	$450	million	at	any	time	outstanding;

•long-term	borrowings	and	security	issuances;	and

•long-term	borrowings	by	its	nuclear	fuel	company	variable	interest	entities.

See	Note	4	to	the	financial	statements	for	further	discussion	of	Entergy	Louisiana's	short-term	borrowing	limits.

In	June	2014	the	LPSC	voted	to	approve	a	series	of	orders	which	(i)	quantified	$290.8	million	of	Hurricane	Isaac	system	restoration	costs as	prudently	incurred;	(ii)	determined	$290	million	as	the	level	of	storm	reserves	to	be	re-established;	(iii)	authorized	Entergy	Louisiana	to	utilize Louisiana	Act	55	financing	for	Hurricane	Isaac	system	restoration	costs;	and	(iv)	granted	other	requested	relief	associated	with	storm	reserves	and Act	55	financing	of	Hurricane	Isaac	system	restoration	costs.	Entergy	Louisiana	committed	to	pass	on	to	customers	a	minimum	of	$30.8	million of	customer	benefits	through	annual	customer	credits	of	approximately	$6.2	million	for	five	years.	Approvals	for	the	Act	55	financings	were obtained	from	the	Louisiana	Utilities	Restoration	Corporation	and	the	Louisiana	State	Bond	Commission.	See	Note	2	to	the	financial	statements for	a	discussion	of	the	August	2014	issuance	of	bonds	under	Act	55	of	the	Louisiana	Legislature.

# 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	 connection	 with	 the	 approval	 of	 the	 business	 combination	 of	 Entergy	 Gulf	 States	 Louisiana	 and	 Entergy	 Louisiana,	 the	 LPSC authorized	the	filing	of	a	single,	joint,	formula	rate	plan	evaluation	report	for	Entergy	Gulf	States	Louisiana's	and	Entergy	Louisiana's	2014 calendar	year	operations.	The	joint	evaluation	report	was	filed	in	September	2015	and	reflected	an	earned	return	on	common	equity	of	9.09%.	As such,	no	adjustment	 to	base	formula	rate	plan	revenue	was	required.	The	following	adjustments	were	required	under	the	formula	rate	plan, however:	a	 decrease	 in	 the	 additional	 capacity	 mechanism	 for	 Entergy	 Louisiana	 of	$17.8	 million;	 an	 increase	 in	 the	 additional	 capacity mechanism	for	Entergy	Gulf	States	Louisiana	of	$4.3	million;	and	a	reduction	of	$5.5	million	to	the	MISO	cost	recovery	mechanism	to	collect approximately	$35.7	million	on	a	combined-company	basis.	Under	the	order	approving	the	business	combination,	following	completion	of	the prescribed	review	period,	rates	were	implemented	with	the	first	billing	cycle	of	December	2015,	subject	to	refund.	In	June	2017	the	LPSC	staff and	Entergy	Louisiana	filed	an	unopposed	joint	report	of	proceedings,	which	was	accepted	by	the	LPSC	in	June	2017,	finalizing	the	results	of	this proceeding	with	no	changes	to	rates	already	implemented.

In	November	2016,	Entergy	Louisiana	filed	with	the	LPSC	a	request	to	extend	the	MISO	cost	recovery	mechanism	rider	provision	of	its formula	 rate	 plan.	In	March	2017	the	LPSC	staff	submitted	direct	testimony	generally	supportive	of	a	one-year	extension	of	the	MISO	cost recovery	mechanism	and	the	intervenor	in	the	proceeding	did	not

oppose	an	extension	for	this	period	of	time.	In	July	2017	an	uncontested	joint	stipulation	authorizing	a	one-year	extension	of	the	MISO	cost recovery	mechanism	rider	was	approved.

In	August	2017,	Entergy	Louisiana	filed	a	request	with	the	LPSC	seeking	to	extend	its	formula	rate	plan	for	three	years	(2017-2019)	with limited	modifications	 to	 its	 terms.	 	Those	modifications	 include:	a	one-time	resetting	of	base	rates	 to	 the	midpoint	of	 the	band	at	Entergy Louisiana's	authorized	return	on	equity	of	9.95%	for	the	2017	test	year;	narrowing	of	the	formula	rate	plan	bandwidth	from	a	total	of	160	basis points	 to	80	basis	points;	and	a	forward-looking	mechanism	that	would	allow	Entergy	Louisiana	to	recover	certain	transmission-related	costs contemporaneously	with	when	those	projects	begin	delivering	benefits	to	customers.		Entergy	Louisiana	requested	that	the	LPSC	consider	its request	on	an	expedited	basis,	in	an	effort	to	maintain	Entergy	Louisiana's	current	cycle	for	implementing	rate	adjustments,	i.e.,	September	2018, without	 the	 need	 for	 filing	 a	 full	 base	 rate	 case	 proceeding.	Several	 parties	 have	 intervened	 in	 the	 proceeding	 and	 all	 parties	 have	 been participating	in	settlement	discussions.

Following	the	completion	of	the	Waterford	3	replacement	steam	generator	project,	the	LPSC	undertook	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.	In	July	2014	the	LPSC	staff	filed	 testimony	recommending	potential	project	and	replacement	power	cost	disallowances	of	up	 to	$71 million,	 citing	 a	 need	 for	 further	 explanation	 or	 documentation	 from	 Entergy	 Louisiana.	 	 An	 intervenor	 filed	 testimony	 recommending disallowance	of	$141	million	of	incremental	project	costs,	claiming	the	steam	generator	fabricator	was	imprudent.		Entergy	Louisiana	provided further	documentation	and	explanation	requested	by	the	LPSC	staff.	An	evidentiary	hearing	was	held	in	December	2014.	At	the	hearing	the parties	maintained	the	positions	reflected	in	pre-filed	testimony.	Entergy	Louisiana	believed	that	the	replacement	steam	generator	costs	were prudently	incurred	and	applicable	legal	principles	supported	their	recovery	in	rates.		Nevertheless,	Entergy	Louisiana	recorded	a	write-off	of	$16 million	of	Waterford	3's	plant	balance	in	December	2014	because	of	the	uncertainty	at	the	time	associated	with	the	resolution	of	the	prudence review.	In	December	2015	the	ALJ	issued	a	proposed	recommendation,	which	was	subsequently	finalized,	concluding	that	Entergy	Louisiana prudently	managed	the	Waterford	3	replacement	steam	generator	project,	including	the	selection,	use,	and	oversight	of	contractors,	and	could	not reasonably	have	anticipated	the	damage	to	the	steam	generators.	Nevertheless,	the	ALJ	concluded	that	Entergy	Louisiana	was	liable	for	the conduct	of	its	contractor	and	subcontractor	and,	therefore,	recommended	a	disallowance	of	$67	million	in	capital	costs.	Additionally,	the	ALJ concluded	that	Entergy	Louisiana	did	not	sufficiently	justify	the	incurrence	of	$2	million	in	replacement	power	costs	during	the	replacement outage.	Although	the	ALJ's	recommendation	had	not	yet	been	considered	by	the	LPSC,	after	considering	the	progress	of	the	proceeding	in	light	of the	ALJ	recommendation,	Entergy

Louisiana	recorded	in	the	fourth	quarter	2015	approximately	$77	million	in	charges,	including	a	 $45	million	asset	write-off	and	a	$32	million regulatory	charge,	to	reflect	that	a	portion	of	the	assets	associated	with	the	Waterford	3	replacement	steam	generator	project	was	no	longer probable	of	recovery.	Entergy	Louisiana	maintained	that	the	ALJ's	recommendation	contained	significant	factual	and	legal	errors.

In	accordance	with	the	settlement	of	Entergy	Gulf	States	Louisiana's	gas	rate	stabilization	plan	for	the	test	year	ended	September	30, 2012,	in	August	2014,	Entergy	Gulf	States	Louisiana	submitted	for	consideration	a	proposal	for	implementation	of	an	infrastructure	rider	to recover	expenditures	associated	with	strategic	plant	investment	and	relocation	projects	mandated	by	local	governments.	After	review	by	the	LPSC staff	and	inclusion	of	certain	customer	safeguards	required	by	the	LPSC	staff,	in	December	2014,	Entergy	Gulf	States	Louisiana	and	the	LPSC staff	 submitted	 a	 joint	 settlement	 for	 implementation	 of	 an	 accelerated	 gas	 pipe	 replacement	 program	 providing	 for	 the	 replacement	 of approximately	100	miles	of	pipe	over	the	next	ten	years,	as	well	as	relocation	of	certain	existing	pipe	resulting	from	local	government-related infrastructure	projects,	and	for	a	rider	to	recover	the	investment	associated	with	these	projects.	The	rider	allows	for	recovery	of	approximately	$65 million	over	ten	years.	The	rider	recovery	will	be	adjusted	on	a	quarterly	basis	to	include	actual	investment	incurred	for	the	prior	quarter	and	is subject	to	the	following	conditions,	among	others:	a	ten-year	term;	application	of	any	earnings	in	excess	of	10.45%	as	an	offset	to	the	revenue requirement	of	the	infrastructure	rider;	adherence	to	a	specified	spending	plan,	within	plus	or	minus	20%	annually;	annual	filings	comparing actual	 versus	 planned	 rider	 spending	 with	 actual	 spending	 and	 explanation	 of	 variances	 exceeding	10%;	 and	 an	 annual	 true-up.	The	 joint settlement	was	approved	by	the	LPSC	in	January	2015.	Implementation	of	the	infrastructure	rider	commenced	with	bills	rendered	on	and	after	the first	billing	cycle	of	April	2015.

In	January	2017,	Entergy	Louisiana	filed	with	the	LPSC	its	gas	rate	stabilization	plan	for	the	test	year	ended	September	30,	2016.	The filing	of	the	evaluation	report	for	test	year	2016	reflected	an	earned	return	on	common	equity	of	6.37%.	As	part	of	the	original	filing,	pursuant	to the	 extraordinary	 cost	 provision	 of	 the	 rate	 stabilization	 plan,	 Entergy	 Louisiana	 sought	 to	 recover	 approximately	$1.5	 million	 in	 deferred operation	and	maintenance	expenses	incurred	to	restore	service	and	repair	damage	resulting	from	flooding	and	widespread	rainfall	in	southeast Louisiana	that	occurred	in	August	2016.	Entergy	Louisiana	requested	to	recover	the	prudently	incurred	August	2016	storm	restoration	costs	over ten	years,	outside	of	the	rate	stabilization	plan	sharing	provisions.	As	a	result,	Entergy	Louisiana's	filing	sought	an	annual	increase	in	revenue	of $1.4	million.	Following	review	of	the	filing,	except	for	the	proposed	extraordinary	cost	recovery,	the	LPSC	staff	confirmed	Entergy	Louisiana's filing	was	consistent	with	the	principles	and	requirements	of	the	rate	stabilization	plan.	The	extraordinary	cost	recovery	request	associated	with	the 2016	flood-related	deferred	operation	and	maintenance	expenses	incurred	for	gas	operations	was	removed	from	the	rate	stabilization	plan	pending LPSC	consideration	in	a	separate	docket.	In	April	2017	the	LPSC	approved	a	joint	report	of	proceedings	and	Entergy	Louisiana	submitted	a revised	evaluation	report	reflecting	a	$1.2	million	annual	increase	in	revenue	with	rates	implemented	with	the	first	billing	cycle	of	May	2017.

# Fuel	and	purchased	power	recovery

Entergy	Louisiana	recovers	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	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.

Due	to	higher	fuel	costs	for	the	operating	month	of	January	2018	resulting	in	part	from	recent	cold	weather,	higher	Henry	Hub	prices,	and an	increase	in	total	fuel	and	purchased	power	costs,	Entergy	Louisiana	plans	to	cap	the

average	fuel	adjustment	charge	to	be	billed	in	March	2018	at	$0.03060	per	kWh	and	to	defer	billing	of	all	fuel	costs	in	excess	of	the	capped amounts	by	including	such	costs	in	the	over-	or	under-recovery	account.

# Industrial	and	Commercial	Customers

Entergy	 Louisiana's	 large	 industrial	 and	 commercial	 customers	 continually	 explore	 ways	 to	 reduce	 their	 energy	 costs.	In	 particular, cogeneration	is	an	option	available	to	a	portion	of	Entergy	Louisiana's	industrial	customer	base.	Entergy	Louisiana	responds	by	working	with industrial	and	commercial	customers	and	negotiating	electric	service	contracts	to	provide	competitive	rates	that	match	specific	customer	needs	and load	 profiles.	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	owns	and,	through	an	affiliate,	operates	the	River	Bend	and	Waterford	3	nuclear	power	plants.	Entergy	Louisiana	is, therefore,	subject	to	the	risks	related	to	owning	and	operating	nuclear	plants.	These	include	risks	related	to:	the	use,	storage,	and	handling	and disposal	of	high-level	and	low-level	radioactive	materials;	the	substantial	financial	requirements,	both	for	capital	investments	and	operational needs,	to	position	Entergy's	nuclear	fleet	to	meet	its	operational	goals,	including	the	financial	requirements	to	address	emerging	issues	like	stress corrosion	cracking	of	certain	materials	within	the	plant	systems	and	the	Fukushima	event;	regulatory	requirements	and	potential	future	regulatory changes,	 including	 changes	 affecting	 the	 regulations	 governing	 nuclear	 plant	 ownership,	 operations,	 license	 renewal	 and	 amendments,	 and decommissioning;	the	performance	and	capacity	factors	of	these	nuclear	plants;	the	availability	of	interim	or	permanent	sites	for	the	disposal	of spent	nuclear	fuel	and	nuclear	waste,	including	the	fees	charged	for	such	disposal;	the	sufficiency	of	nuclear	decommissioning	trust	fund	assets and	earnings	to	complete	decommissioning	of	each	site	when	required;	and	limitations	on	the	amounts	and	types	of	insurance	commercially available	for	losses	in	connection	with	nuclear	plant	operations	and	catastrophic	events	such	as	a	nuclear	accident.	In	the	event	of	an	unanticipated early	shutdown	of	River	Bend	or	Waterford	3,	Entergy	Louisiana	may	be	required	 to	provide	additional	funds	or	credit	support	 to	satisfy regulatory	requirements	for	decommissioning.

Waterford	3's	operating	license	is	currently	due	to	expire	in	December	2024.		In	March	2016,	Entergy	Louisiana	filed	an	application	with the	NRC	for	an	extension	of	Waterford	3's	operating	license	to	2044.	River	Bend's	operating	license	is	currently	due	to	expire	in	August	2025.	In May	2017,	Entergy	Louisiana	filed	an	application	with	the	NRC	for	an	extension	of	River	Bend's	operating	license	to	2045.	In	October	2017	an intervenor	filed	with	the	NRC	a	petition	to	intervene	and	request	for	a	hearing	on	the	River	Bend	license	renewal	application.	As	provided	by NRC	procedure,	a	panel	of	the	Atomic	Safety	and	Licensing	Board	has	been	designated	to	determine	whether	the	intervenor's	three	proposed contentions,	or	allegations	of	errors	or	omissions	in	the	license	renewal	application,	are	admissible	and,	if	so,	to	rule	on	any	admitted	contentions. In	January	2018	the	Atomic	Safety	and	Licensing	Board	denied	the	petition	to	intervene	and	the	request	for	hearing.

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,	with	reference	to possible	exceptions	noted	in

"Regulation	of	Entergy's	Business	-	Environmental	Regulation"	in	Part	I,	Item	1.	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.

Entergy	Louisiana's	qualified	pension	and	other	postretirement	reported	costs,	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.

# Cost	Sensitivity

| Actuarial	Assumption | Change	in	Assumption | Impact	on	2018	Qualified<br>Pension	Cost | Impact	on	2017	Projected<br>Qualified	Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $3,737 | $54,506 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $3,309 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $1,726 | $8,824 |

| Actuarial	Assumption | Change	in	Assumption | Impact	on	2018<br>Postretirement	Benefit	Cost | postretirement	Benefit<br>Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $753 | $10,727 |
| Health\tcare\tcost\ttrend | 0.25% | $1,219 | $8,675 |

Total	qualified	pension	cost	for	Entergy	Louisiana	in	2017	was	$44.3	million.		Entergy	Louisiana	anticipates	2018	qualified	pension	cost to	be	$52.1	million.			In	2016,	Entergy	Louisiana	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified pension	costs,	which	had	the	effect	of	lowering	qualified	pension	costs	by	$14.2	million.		Entergy	Louisiana	contributed	$87.5	million	to	its pension	plans	in	2017	and	estimates	pension	contributions	will	be	approximately	$71.9	million	in	2018,	although	the	2018	required	pension contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	postretirement	health	care	and	life	insurance	benefit	costs	for	Entergy	Louisiana	in	2017	were	$12.6	million.		Entergy	Louisiana expects	2018	postretirement	health	care	and	life	insurance	benefit	costs	of	approximately	$11.2	million.		In	2016,	Entergy	Louisiana	refined	its approach	to	estimating	the	service	cost	and	interest	cost	components	of	other	postretirement	costs,	which	had	the	effect	of	lowering	qualified	other postretirement	costs	by	$3.5	million.	Entergy	Louisiana	contributed	$14.4	million	to	its	other	postretirement	plans	in	2017	and	estimates	that	2018 contributions	will	be	approximately	$19	million.

# To	the	members	and	Board	of	Directors	of

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Louisiana,	LLC	and	Subsidiaries	(the	"Company")	as	of	December	31, 2017	and	2016,	the	related	consolidated	statements	of	income,	comprehensive	income,	cash	flows,	and	changes	in	equity	(pages	349	through	354 and	applicable	 items	 in	pages	55	 through	230),	for	each	of	 the	 three	years	 in	 the	period	ended	December	31,	2017,	and	 the	related	notes (collectively	referred	to	as	the	"financial	statements").	In	our	opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial position	of	the	Company	as	of	December	31,	2017	and	2016,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the period	ended	December	31,	2017,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $4,246,020 | $4,126,343 | $4,361,524 |
| Natural\tgas | 54,530 | 50,705 | 55,622 |
| TOTAL | 4,300,550 | 4,177,048 | 4,417,146 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 912,060 | 804,433 | 850,869 |
| Purchased\tpower | 980,070 | 890,058 | 1,129,910 |
| Nuclear\trefueling\toutage\texpenses | 52,074 | 51,361 | 44,480 |
| Other\toperation\tand\tmaintenance | 969,400 | 923,779 | 997,546 |
| Decommissioning | 49,457 | 46,944 | 43,445 |
| Taxes\tother\tthan\tincome\ttaxes | 175,359 | 165,665 | 167,966 |
| Depreciation\tand\tamortization | 467,369 | 451,290 | 437,036 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (152,080) | 44,131 | 27,562 |
| TOTAL | 3,453,709 | 3,377,661 | 3,698,814 |
| OPERATING\tINCOME | 846,841 | 799,387 | 718,332 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 51,485 | 27,925 | 19,192 |
| Interest\tand\tinvestment\tincome | 164,550 | 154,778 | 150,168 |
| Miscellaneous\t-\tnet | (11,960) | (11,597) | (13,190) |
| TOTAL | 204,075 | 171,106 | 156,170 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 275,185 | 273,283 | 259,894 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (25,914) | (14,571) | (10,702) |
| TOTAL | 249,271 | 258,712 | 249,192 |
| INCOME\tBEFORE\tINCOME\tTAXES | 801,645 | 711,781 | 625,310 |
| Income\ttaxes | 485,298 | 89,734 | 178,671 |
| NET\tINCOME | 316,347 | 622,047 | 446,639 |
| Preferred\tdistribution\trequirements\tand\tother | — | — | 5,737 |
| EARNINGS\tAPPLICABLE\tTO\tCOMMON\tEQUITY | $316,347 | $622,047 | $440,902 |

# CONSOLIDATED	STATEMENTS	OF	COMPREHENSIVE	INCOME

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| Net\tIncome | $316,347 | $622,047 | $446,639 |
| Other\tcomprehensive\tincome |  |  |  |
| Pension\tand\tother\tpostretirement\tliabilities |  |  |  |
| (net\tof\ttax\texpense\tof\t$234,\t$5,034,\tand\t$14,316) | 2,042 | 7,970 | 22,811 |
| Other\tcomprehensive\tincome | 2,042 | 7,970 | 22,811 |
| Comprehensive\tIncome | $318,389 | $630,017 | $469,450 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $316,347 | $622,047 | $446,639 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 621,018 | 620,211 | 593,635 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 575,804 | 178,549 | 97,461 |
| Changes\tin\tworking\tcapital: |  |  |  |
| Receivables | (53,829) | (102,200) | (12,795) |
| Fuel\tinventory | 11,010 | (2,693) | (887) |
| Accounts\tpayable | 58,880 | (36,720) | 23,641 |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 128,261 | (235,246) | 105,687 |
| Interest\taccrued | (70) | 1,218 | 2,933 |
| Deferred\tfuel\tcosts | 23,236 | (17,023) | 4,222 |
| Other\tworking\tcapital\taccounts | (30,911) | 6,462 | (41,890) |
| Changes\tin\tprovisions\tfor\testimated\tlosses | (8,324) | 490 | (8,946) |
| Changes\tin\tother\tregulatory\tassets | 492,696 | 57,579 | 130,762 |
| Changes\tin\tother\tregulatory\tliabilities | 605,453 | 62,351 | 96,234 |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (1,207,808) | — | — |
| Changes\tin\tpension\tand\tother\tpostretirement\tliabilities | (32,309) | (52,559) | (98,695) |
| Other | (161,909) | (64,554) | (182,485) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 1,337,545 | 1,037,912 | 1,155,516 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (1,662,835) | (1,030,416) | (845,227) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 51,485 | 27,925 | 19,192 |
| Insurance\tproceeds | 5,305 | 10,564 | — |
| Nuclear\tfuel\tpurchases | (197,829) | (73,618) | (244,040) |
| Proceeds\tfrom\tthe\tsale\tof\tnuclear\tfuel | 42,634 | 63,304 | 54,595 |
| Payment\tfor\tpurchase\tof\tplant | — | (474,670) | — |
| Payments\tto\tstorm\treserve\tescrow\taccount | (2,110) | (1,063) | (308) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 8,835 | — | — |
| Changes\tin\tsecuritization\taccount | 880 | 351 | (137) |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 231,293 | 219,182 | 123,474 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (266,592) | (257,209) | (158,028) |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | 11,330 | (16,349) | (3,339) |
| Proceeds\tfrom\tsale\tof\tassets | — | — | 59,610 |
| Payment\tfor\tpurchase\tof\tassets | (9,805) | — | — |
| Litigation\tproceeds\tfor\treimbursement\tof\tspent\tnuclear\tfuel\tstorage\tcosts | — | 57,934 | — |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (1,787,409) | (1,474,065) | (994,208) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 733,344 | 2,450,063 | 77,172 |
| Retirement\tof\tlong-term\tdebt | (407,736) | (1,488,870) | (180,595) |
| Redemption\tof\tpreferred\tmembership\tinterests | — | — | (110,286) |
| Changes\tin\tcredit\tborrowings\t-\tnet | 39,746 | (56,562) | 14,322 |
| Distributions\tpaid: |  |  |  |
| Common\tequity | (91,250) | (285,500) | (226,000) |
| Preferred\tmembership\tinterests | — | — | (6,082) |
| Other | (2,183) | (4,230) | (15,253) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | 271,921 | 614,901 | (446,722) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (177,943) | 178,748 | (285,414) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 213,850 | 35,102 | 320,516 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $35,907 | $213,850 | $35,102 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $266,871 | $324,456 | $243,745 |
| Income\ttaxes | ($234,199) | $156,605 | $89,124 |
| Non-cash\tfinancing\tactivities: |  |  |  |
| Capital\tcontribution\tfrom\tparent | $— | $— | ($267,826) |

| Cash | $5,836 | $49,972 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 30,071 | 163,878 |
| Total\tcash\tand\tcash\tequivalents | 35,907 | 213,850 |
| Accounts\treceivable: |  |  |
| Customer | 254,308 | 213,517 |
| Allowance\tfor\tdoubtful\taccounts | (8,430) | (6,277) |
| Associated\tcompanies | 143,524 | 155,794 |
| Other | 60,893 | 54,186 |
| Accrued\tunbilled\trevenues | 153,118 | 159,176 |
| Total\taccounts\treceivable | 603,413 | 576,396 |
| Fuel\tinventory | 39,728 | 50,738 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 299,881 | 294,421 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 65,711 | 22,535 |
| Prepaid\ttaxes | — | 110,104 |
| Prepayments\tand\tother | 34,035 | 41,687 |
| TOTAL | 1,078,675 | 1,309,731 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investment\tin\taffiliate\tpreferred\tmembership\tinterests | 1,390,587 | 1,390,587 |
| Decommissioning\ttrust\tfunds | 1,312,073 | 1,140,707 |
| Storm\treserve\tescrow\taccount | 284,759 | 291,485 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 245,255 | 217,494 |
| Other | 18,999 | 28,844 |
| TOTAL | 3,251,673 | 3,069,117 |
| UTILITY\tPLANT |  |  |
| Electric | 19,678,536 | 18,827,532 |
| Natural\tgas | 191,899 | 172,816 |
| Construction\twork\tin\tprogress | 1,281,452 | 670,201 |
| Nuclear\tfuel | 337,402 | 249,807 |
| TOTAL\tUTILITY\tPLANT | 21,489,289 | 19,920,356 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 8,703,047 | 8,420,596 |
| UTILITY\tPLANT\t-\tNET | 12,786,242 | 11,499,760 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 470,480 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof\t$71,367\tas\tof\tDecember\t31,\t2017\tand\t$92,951\tas\tof\nDecember\t31,\t2016) | 1,145,842 | 1,168,058 |
| Deferred\tfuel\tcosts | 168,122 | 168,122 |
| Other | 18,310 | 16,003 |
| TOTAL | 1,332,274 | 1,822,663 |
| TOTAL\tASSETS | $18,448,864 | $17,701,271 |

| Currently	maturing	long-term	debt | $675,002 | $200,198 |
| :--- | :--- | :--- |
| Short-term\tborrowings | 43,540 | 3,794 |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 126,685 | 82,106 |
| Other | 404,374 | 358,741 |
| Customer\tdeposits | 150,623 | 148,601 |
| Taxes\taccrued | 18,157 | — |
| Interest\taccrued | 75,528 | 75,598 |
| Deferred\tfuel\tcosts | 71,447 | 48,211 |
| Other | 79,037 | 80,013 |
| TOTAL | 1,644,393 | 997,262 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 2,050,371 | 2,691,118 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 121,870 | 126,741 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 725,368 | — |
| Other\tregulatory\tliabilities | 761,059 | 880,974 |
| Decommissioning | 1,140,461 | 1,082,685 |
| Accumulated\tprovisions | 302,448 | 310,772 |
| Pension\tand\tother\tpostretirement\tliabilities | 748,384 | 780,278 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$77,736\tas\tof\tDecember\t31,\t2017\tand\t$99,217\tas\tof\tDecember\t31,\n2016) | 5,469,069 | 5,612,593 |
| Other | 176,637 | 137,039 |
| TOTAL | 11,495,667 | 11,622,200 |
| Commitments\tand\tContingencies |  |  |
| EQUITY |  |  |
| Member's\tequity | 5,355,204 | 5,130,251 |
| Accumulated\tother\tcomprehensive\tloss | (46,400) | (48,442) |
| TOTAL | 5,308,804 | 5,081,809 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $18,448,864 | $17,701,271 |

|  |  | Common	Equity | Common	Equity |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Preferred\nMembership\nInterests | Member's\tEquity | Accumulated\tOther\nComprehensive\tIncome\n(Loss) | Total |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2014 | $110,000 | $4,316,210 | ($79,223) | $4,346,987 |
| Net\tincome | — | 446,639 | — | 446,639 |
| Other\tcomprehensive\tincome | — | — | 22,811 | 22,811 |
| Preferred\tstock\tredemption | (110,000) | — | — | (110,000) |
| Non-cash\tcontribution\tfrom\tparent | — | 267,826 | — | 267,826 |
| Distributions\tto\tparent | — | (226,000) | — | (226,000) |
| Distributions\tdeclared\ton\tpreferred\tmembership\tinterests | — | (5,737) | — | (5,737) |
| Other | — | (5,214) | — | (5,214) |
| Balance\tat\tDecember\t31,\t2015 | $— | $4,793,724 | ($56,412) | $4,737,312 |
| Net\tincome | — | 622,047 | — | 622,047 |
| Other\tcomprehensive\tincome | — | — | 7,970 | 7,970 |
| Distributions\tto\tparent | — | (285,500) | — | (285,500) |
| Other | — | (20) | — | (20) |
| Balance\tat\tDecember\t31,\t2016 | $— | $5,130,251 | ($48,442) | $5,081,809 |
| Net\tincome | — | 316,347 | — | 316,347 |
| Other\tcomprehensive\tincome | — | — | 2,042 | 2,042 |
| Distributions\tdeclared\ton\tcommon\tequity | — | (91,250) | — | (91,250) |
| Other | — | (144) | — | (144) |
| Balance\tat\tDecember\t31,\t2017 | $— | $5,355,204 | ($46,400) | $5,308,804 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $4,300,550 | $4,177,048 | $4,417,146 | $4,740,504 | $4,399,511 |
| Net\tincome | $316,347 | $622,047 | $446,639 | $446,022 | $414,126 |
| Total\tassets | $18,448,864 | $17,701,271 | $16,387,447 | $16,423,825 | $15,275,863 |
| Long-term\tobligations\t(a) | $5,469,069 | $5,612,593 | $4,806,790 | $4,882,813 | $4,383,273 |

(a)	Includes	long-term	debt	(excluding	currently	maturing	debt).

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $1,198 | $1,196 | $1,292 | $1,358 | $1,304 |
| Commercial | 956 | 930 | 989 | 1,044 | 1,003 |
| Industrial | 1,534 | 1,350 | 1,420 | 1,569 | 1,457 |
| Governmental | 69 | 67 | 67 | 70 | 68 |
| Total\tretail | 3,757 | 3,543 | 3,768 | 4,041 | 3,832 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 278 | 368 | 406 | 427 | 320 |
| Non-associated\tcompanies | 64 | 50 | 36 | 80 | 48 |
| Other | 147 | 165 | 152 | 121 | 140 |
| Total | $4,246 | $4,126 | $4,362 | $4,669 | $4,340 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 13,357 | 13,810 | 14,399 | 14,415 | 14,026 |
| Commercial | 11,342 | 11,478 | 11,700 | 11,555 | 11,402 |
| Industrial | 29,754 | 28,517 | 27,713 | 27,025 | 25,734 |
| Governmental | 790 | 794 | 756 | 732 | 723 |
| Total\tretail | 55,243 | 54,599 | 54,568 | 53,727 | 51,885 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 4,793 | 7,345 | 7,500 | 6,240 | 5,168 |
| Non-associated\tcompanies | 1,711 | 1,690 | 770 | 1,051 | 979 |
| Total | 61,747 | 63,634 | 62,838 | 61,018 | 58,032 |

Net	income	increased	$0.8	million	primarily	due	to	higher	other	income,	lower	other	operation	and	maintenance	expenses,	and	lower interest	expense,	substantially	offset	by	higher	depreciation	and	amortization	expenses	and	a	higher	effective	income	tax	rate.

Net	income	increased	$16.5	million	primarily	due	to	lower	other	operation	and	maintenance	expenses,	higher	net	revenues,	and	a	lower effective	income	tax	rate,	partially	offset	by	higher	depreciation	and	amortization	expenses.

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	2017	to	2016.

| 2016	net	revenue | $705.4 |
| :--- | :--- |
| Volume/weather | (18.2) |
| Retail\telectric\tprice | 13.5 |
| Other | 2.4 |
| 2017\tnet\trevenue | $703.1 |

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales.

The	retail	electric	price	variance	is	primarily	due	to	a	$19.4	million	net	annual	increase	in	rates,	effective	with	the	first	billing	cycle	of July	2016,	and	an	increase	in	the	energy	efficiency	rider,	effective	with	the	first	billing	cycle	of	February	2017,	each	as	approved	by	the	MPSC. The	increase	was	partially	offset	by	decreased	storm	damage	rider	revenues	due	to	resetting	the	storm	damage	provision	to	zero	beginning	with	the November	2016	billing	cycle.	Entergy	Mississippi	resumed	billing	the	storm	damage	rider	effective	with	the	September	2017	billing	cycle.	See Note	2	to	the	financial	statements	for	more	discussion	of	the	formula	rate	plan	and	the	storm	damage	rider.

| 2015	net	revenue | $696.3 |
| :--- | :--- |
| Retail\telectric\tprice | 12.9 |
| Volume/weather | 4.7 |
| Net\twholesale\trevenue | (2.4) |
| Reserve\tequalization | (2.8) |
| Other | (3.3) |
| 2016\tnet\trevenue | $705.4 |

The	retail	electric	price	variance	is	primarily	due	to	a	$19.4	million	net	annual	increase	in	revenues,	as	approved	by	the	MPSC,	effective with	the	first	billing	cycle	of	July	2016,	and	an	increase	in	revenues	collected	through	the	storm	damage	rider.		See	Note	2	to	the	financial statements	for	more	discussion	of	the	formula	rate	plan	and	the	storm	damage	rider.

The	volume/weather	variance	is	primarily	due	to	an	increase	of	153	GWh,	or	1%,	in	billed	electricity	usage,	including	an	increase	in industrial	usage,	partially	offset	by	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales.	The	increase	in	industrial	usage	is primarily	due	to	expansion	projects	in	the	pulp	and	paper	industry,	increased	demand	for	existing	customers,	primarily	in	the	metals	industry,	and new	customers	in	the	wood	products	industry.

The	net	wholesale	revenue	variance	is	primarily	due	to	Entergy	Mississippi's	exit	from	the	System	Agreement	in	November	2015.

The	reserve	equalization	revenue	variance	is	primarily	due	to	the	absence	of	reserve	equalization	revenue	as	compared	to	the	same	period in	2015	resulting	from	Entergy	Mississippi's	exit	from	the	System	Agreement	in	November	2015.

•a	decrease	of	$12	million	in	fossil-fueled	generation	expenses	primarily	due	to	lower	long-term	service	agreement	costs	and	a	lower	scope of	work	done	during	plant	outages	in	2017	as	compared	to	the	same	period	in	2016;	and

•a	decrease	of	$3.6	million	in	storm	damage	provisions.	See	Note	2	to	the	financial	statements	for	a	discussion	on	storm	cost	recovery.

The	decrease	was	partially	offset	by	an	increase	of	$4.8	million	in	energy	efficiency	costs	and	an	increase	of	$2.7	million	in	compensation	and benefits	costs	primarily	due	to	higher	incentive-based	compensation	accruals	in	2017	as	compared	to	the	prior	year.

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

Other	income	increased	primarily	due	to	interest	income	recorded	in	connection	with	the	opportunity	sales	proceeding,	interest	income recorded	on	the	deferred	fuel	balance,	and	an	increase	in	the	allowance	for	equity	funds	used	during	construction	due	to	higher	construction	work in	progress	in	2017	as	compared	to	2016.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	opportunity	sales	proceeding.

Interest	 expense	 decreased	 primarily	 due	 to	 the	 refinancing	 at	 lower	 interest	 rates	 of	 certain	 first	 mortgage	 bonds	 in	 2016	 and	 the retirement,	at	maturity,	of	$125	million	of	3.25%	Series	first	mortgage	bonds	in	June	2016.	See	Note	5	to	the	financial	statements	for	details	of long-term	debt.

•a	decrease	of	$9.4	million	in	fossil-fueled	generation	expenses	primarily	due	to	a	lower	scope	of	work	done	during	plant	outages	in	2016 as	compared	to	the	same	period	in	2015;

•a	decrease	of	$6.1	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	net	periodic	pension	and	other	postretirement benefits	costs	as	a	result	of	an	increase	in	the	discount	rate	used	to	value	the	benefit	liabilities	and	a	refinement	in	the	approach	used	to estimate	the	service	cost	and	interest	cost	components	of	pension	and	other	postretirement	costs.	See	"MANAGEMENT'S	FINANCIAL DISCUSSION	AND	ANALYSIS	 -	Critical	Accounting	Estimates	-	Qualified	Pension	and	Other	Postretirement	Benefits "	below and	Note	11	to	the	financial	statements	for	further	discussion	of	pension	and	other	postretirement	benefit	costs;

•a	decrease	of	$2	million	due	to	lower	write-offs	of	uncollectible	customer	accounts	in	2016;

•a	decrease	of	$2	million	in	energy	efficiency	costs;	and

•several	individually	insignificant	items.

The	decrease	was	partially	offset	by	an	increase	of	$7.1	million	in	storm	damage	provisions	and	an	increase	of	$6	million	in	distribution	expenses primarily	due	to	higher	vegetation	maintenance.	See	Note	2	to	the	financial	statements	for	a	discussion	of	storm	cost	recovery.

The	effective	 income	 tax	rates	for	2017,	2016,	and	2015	were	40.2%,	 36.9%,	 and	 40.0%, respectively.	See	Note	3	to	the	financial statements	for	a	reconciliation	of	the	federal	statutory	rate	of	35%	to	the	effective	income	tax	rates.

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $76,834 | $145,605 | $61,633 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 226,585 | 212,280 | 372,279 |
| Investing\tactivities | (417,226) | (289,444) | (245,127) |
| Financing\tactivities | 119,903 | 8,393 | (43,180) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (70,738) | (68,771) | 83,972 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,096 | $76,834 | $145,605 |

Net	cash	flow	provided	by	operating	activities	increased	$14.3	million	in	2017	primarily	due	to	the	timing	of	recovery	of	fuel	and purchased	power	costs	in	2017	as	compared	to	2016	and	an	increase	of	$12.6	million	in	income	tax	refunds	in	2017	as	compared	to	2016.	Entergy Mississippi	had	income	tax	refunds	in	2017	and	2016	in	accordance	with	an	intercompany	income	tax	allocation	agreement.	The	2017	income	tax refunds	were	primarily	due	to	the	utilization	of	Entergy	Mississippi's	federal	net	operating	losses	and	state	income	tax	refunds	resulting	from	the carryback	of	net	operating	losses.	The	increase	was	partially	offset	by	the	timing	of	payments	to	vendors.

Net	cash	flow	provided	by	operating	activities	decreased	$160	million	 in	2016	primarily	due	 to	 the	 timing	of	recovery	of	fuel	and purchased	power	costs	in	2016	as	compared	to	the	same	period	in	2015	and	$15.3	million	in	insurance	proceeds	received	in	2015	related	to	the unplanned	outage	event	that	occurred	at	the	Baxter	Wilson	(Unit	1)	power	plant	in	September	2013.	The	decrease	was	partially	offset	by	income tax	refunds	of	$12.5	million	in	2016	compared	to	income	tax	payments	of	$61.3	million	in	2015.	Entergy	Mississippi	had	income	tax	refunds	in 2016	and	income	tax	payments	in	2015	in	accordance	with	an	intercompany	income	tax	allocation	agreement.	The	2016	income	tax	refunds resulted	primarily	from	adjustments	associated	with	the	settlement	of	the	2010-2011	IRS	audit	whereas	the	income	tax	payments	in	2015	were primarily	due	to	the	results	of	operations	and	the	reversal	of	taxable	temporary	differences	as	well	as	final	settlement	of	amounts	outstanding associated	with	the	2006-2007	IRS	audit.	See	Note	3	to	the	financial	statements	for	a	discussion	of	the	income	tax	audits.

•an	increase	of	$48.4	million	in	transmission	construction	expenditures	primarily	due	to	a	higher	scope	of	work	performed	in	2017	as compared	to	2016;

•an	increase	of	$39.2	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	a	higher	scope	of	work	performed	in 2017	as	compared	to	2016;	and

•an	increase	of	$30.2	million	in	distribution	construction	expenditures	primarily	due	to	an	increase	in	storm	spending	in	2017	as	compared to	2016	and	increased	spending	on	digital	technology	improvements	within	the	customer	contact	centers.

•insurance	proceeds	of	$12.9	million	received	in	2015	related	to	the	unplanned	outage	event	that	occurred	at	the	Baxter	Wilson	(Unit	1) power	plant	in	September	2013;

•an	increase	of	$11.4	million	in	distribution	construction	expenditures	primarily	due	to	a	higher	scope	of	non-storm	related	work	performed in	2016	as	compared	to	2015;	and

•an	increase	of	$10.1	million	due	to	various	information	technology	projects	and	upgrades.

The	increase	was	partially	offset	by	a	decrease	of	$20.1	million	in	fossil-fueled	generation	construction	expenditures	primarily	due	to	a	decreased scope	of	work	performed	during	plant	outages	in	2016	as	compared	to	2015	and	money	pool	activity.

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	$15.3	million	in	2016	compared	to	increasing	by	$25.3	million	in	2015.	The	money	pool	is	an	inter-company borrowing	arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	flow	provided	by	financing	activities	increased	$111.5	million	in	2017	primarily	due	to	the	issuance	of	$150	million	of	3.25% Series	first	mortgage	bonds	in	November	2017	and	the	redemption	of	$30	million	of	6.25%	Series	preferred	stock	in	2016,	partially	offset	by	the net	issuance	of	$61.4	million	of	long-term	debt	in	2016.

Entergy	Mississippi's	financing	activities	provided	$8.4	million	of	cash	in	2016	compared	to	using	$43.2	million	in	2015	primarily	due	to the	net	issuance	of	$61.4	million	of	long-term	debt	in	2016	and	a	decrease	of	$16	million	in	common	stock	dividends	paid	in	2016,	partially	offset by	the	redemption	of	$30	million	of	6.25%	Series	preferred	stock.	The	decrease	in	dividends	paid	was	primarily	because	of	lower	operating	cash flows	and	higher	capital	expenditures,	each	discussed	above.

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	increase	in	the	debt	to capital	ratio	for	Entergy	Mississippi	is	primarily	due	to	the	issuance	of	long-term	debt	in	2017.

|  | December	31,<br>2017 | December	31,<br>2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 51.5% | 50.2% |
| Effect\tof\tsubtracting\tcash | (0.2%) | (1.8%) |
| Net\tdebt\tto\tnet\tcapital | 51.3% | 48.4% |

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	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital while	also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.		To	the	extent	that	operating	cash	flows	are	in excess	of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to maintain	the	targeted	capital	structure.		To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	Entergy	Mississippi may	issue	incremental	debt	or	reduce	dividends,	or	both,	to	maintain	its	targeted	capital	structure.		In	addition,	in	certain	infrequent	circumstances, such	 as	 large	 transactions	 that	 would	 materially	 alter	 the	 capital	 structure	 if	 financed	 entirely	 with	 debt	 and	 reducing	 dividends,	 Entergy Mississippi	may	receive	equity	contributions	to	maintain	the	targeted	capital	structure.

Entergy	Mississippi	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Mississippi's	planned	construction	and	other	capital	investments.

|  | 2018 | 2019 | 2020 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $55 | $45 | $260 |
| Transmission | 145 | 100 | 105 |
| Distribution | 125 | 140 | 130 |
| Utility\tSupport | 70 | 50 | 35 |
| Total | $395 | $335 | $530 |

Following	are	the	amounts	of	Entergy	Mississippi's	existing	debt	obligations	and	lease	obligations	(includes	estimated	interest	payments) and	other	purchase	obligations.

|  | 2018 | 2019-2020 | 2021-2022 | After	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $50 | $234 | $80 | $1,784 | $2,148 |
| Operating\tleases | $12 | $19 | $12 | $6 | $49 |
| Purchase\tobligations\t(b) | $280 | $519 | $490 | $5,304 | $6,593 |

(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	$14.9	million	to	its qualified	pension	plans	and	approximately	$110	thousand	to	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the	2018 required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April 1,	2018		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 amounts	associated	with	specific	investments	such	as	transmission	projects	to	enhance	reliability,	reduce	congestion,	and	enable	economic	growth; distribution	spending	 to	enhance	reliability	and	 improve	service	 to	customers,	 including	 investment	 to	support	advanced	metering;	resource planning,	including	potential	generation	projects;	system	improvements;	and	other	investments.		Estimated	capital	expenditures	are	subject	to periodic	 review	 and	 modification	 and	 may	 vary	 based	 on	 the	 ongoing	 effects	 of	 regulatory	 constraints	 and	 requirements,	 environmental compliance,	business	opportunities,	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	 Mississippi	 dividends	 its	 earnings	 to	 Entergy	 Corporation	 at	 a	 percentage	 determined monthly.		Provisions	in	Entergy	Mississippi's	articles	of	incorporation	relating	to	preferred	stock	restrict	the	amount	of	retained	earnings	available for	the	payment	of	cash	dividends	or	other	distributions	on	its	common	and	preferred	stock.

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.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $1,633 | $10,595 | $25,930 | $644 |

Entergy	Mississippi	has	four	separate	credit	facilities	in	the	aggregate	amount	of	$102.5	million	scheduled	to	expire	May	2018.	No borrowings	were	outstanding	under	the	credit	facilities	as	of	December	31,	2017.		In	addition,	Entergy	Mississippi	is	a	party	to	an	uncommitted letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	to	MISO.	As	of	December	31,	2017,	a	$15.3	million	letter	of	credit was	outstanding	under	Entergy	Mississippi's	uncommitted	letter	of	credit	facility.	See	Note	4	to	the	financial	statements	for	additional	discussion of	the	credit	facilities.

Entergy	Mississippi	obtained	authorizations	from	the	FERC	through	October	2019	for	short-term	borrowings	not	to	exceed	an	aggregate amount	of	$175	million	at	any	time	outstanding	and	long-term	borrowings	and	security	issuances.	See	Note	4	to	the	financial	statements	for further	discussion	of	Entergy	Mississippi's	short-term	borrowing	limits.

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	2017,	Entergy	Mississippi	submitted	its	formula	rate	plan	2017	test	year	filing	and	2016	look-back	filing	showing	Entergy Mississippi's	earned	return	for	the	historical	2016	calendar	year	and	projected	earned	return	for	the	2017	calendar	year	to	be	within	the	formula rate	plan	bandwidth,	resulting	in	no	change	in	rates.	In	June	2017,	Entergy	Mississippi	and	the	Mississippi	Public	Utilities	Staff	entered	into	a stipulation	that	confirmed	that	Entergy

Mississippi's	earned	returns	for	both	the	2016	look-back	filing	and	2017	test	year	were	within	the	respective	formula	rate	plan	bandwidths.	In June	2017	the	MPSC	approved	the	stipulation,	which	resulted	in	no	change	in	rates.

In	November	2016,	Entergy	Mississippi	filed	its	annual	redetermination	of	the	annual	factor	to	be	applied	under	the	energy	cost	recovery rider.	The	calculation	of	the	annual	factor	included	an	over-recovery	of	less	than	$2	million	as	of	September	30,	2016.	In	January	2017	the	MPSC approved	the	annual	factor	effective	with	February	2017	bills.	Also	in	January	2017	the	MPSC	certified	to	the	Mississippi	Legislature	the	audit reports	of	its	independent	auditors	for	the	fuel	year	ending	September	30,	2016.	In	its	order,	the	MPSC	expressly	reserved	the	right	to	review	and determine	the	recoverability	of	any	and	all	purchased	power	expenditures	made	during	fiscal	year	2016.	The	MPSC	hired	independent	auditors	to conduct	an	annual	operations	audit	and	a	financial	audit.	The	independent	auditors	issued	their	audit	reports	in	December	2017.	The	audit	reports included	several	recommendations	for	action	by	Entergy	Mississippi	but	did	not	recommend	any	cost	disallowances.	In	January	2018	the	MPSC certified	the	audit	reports	to	the	Mississippi	Legislature.	In	November	2017	the	Public	Utilities	Staff	separately	engaged	a	consultant	to	review	the outage	at	the	Grand	Gulf	Nuclear	Station	that	began	in	2016.	The	review	is	currently	in	progress.

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.

# Storm	Damage	Provision

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,	with	reference to	possible	exceptions	noted	in	"Regulation	of	Entergy's	Business	 -	Environmental	Regulation"	in	Part	I,	Item	1.		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.

See	"Impairment	of	Long-lived	Assets	and	Trust	Fund	Investments"	in	the	"Critical	Accounting	Estimates"	section	of	Entergy Corporation	and	Subsidiaries	Management's	Financial	Discussion	and	Analysis	for	discussion	of	the	estimates	associated	with	the	impairment	of long-lived	assets.

Entergy	Mississippi's	qualified	pension	and	other	postretirement	reported	costs,	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.

| Discount	rate | (0.25%) | $874 | $13,479 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $867 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $381 | $1,848 |

| Discount	rate | (0.25%) | $184 | $2,561 |
| :--- | :--- | :--- | :--- |
| Health\tcare\tcost\ttrend | 0.25% | $296 | $2,024 |

Total	qualified	pension	cost	for	Entergy	Mississippi	in	2017	was	$8.5	million.	Entergy	Mississippi	anticipates	2018	qualified	pension	cost to	be	$10.8	million.	In	2016,	Entergy	Mississippi	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified pension	costs,	which	had	the	effect	of	lowering	qualified	pension	costs	by	$3.8	million.		Entergy	Mississippi	contributed	$19.1	million	to	its qualified	pension	plans	in	2017	and	estimates	2018	pension	contributions	will	be	approximately	$14.9	million,	although	the	2018	required	pension contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	postretirement	health	care	and	life	insurance	benefit	income	for	Entergy	Mississippi	in	2017	was	$1	million.	Entergy	Mississippi expects	2018	postretirement	health	care	and	life	insurance	benefit	income	of	approximately	$1.5	million.	In	2016,	Entergy	Mississippi	refined	its approach	to	estimating	the	service	cost	and	interest	cost	components	of	other	postretirement	costs,	which	had	the	effect	of	lowering	qualified	other postretirement	costs	by	$770	thousand.	In	2017,	Entergy	Mississippi's	contributions	(that	is,	contributions	to	the	external	trusts	plus	claims payments)	were	offset	by	trust	claims	reimbursements,	resulting	in	a	net	reimbursement	of	$2	thousand.	Entergy	Mississippi	estimates	that	2018 contributions	will	be	approximately	$110	thousand.

# See	"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.

We	have	audited	the	accompanying	balance	sheets	of	Entergy	Mississippi,	Inc.	(the	"Company")	as	of	December	31,	2017	and	2016,	the	related statements	of	income,	cash	flows	and	changes	in	common	equity	(pages	370	through	374	and	applicable	items	in	pages	55	through	230),	for	each of	the	three	years	in	the	period	ended	December	31,	2017,	and	the	related	notes	(collectively	referred	to	as	the	"financial	statements").	In	our opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company	as	of	December	31,	2017	and	2016, and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

# INCOME	STATEMENTS

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $1,198,229 | $1,094,649 | $1,396,985 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 185,816 | 95,090 | 291,666 |
| Purchased\tpower | 328,463 | 297,902 | 389,950 |
| Other\toperation\tand\tmaintenance | 243,480 | 250,443 | 261,255 |
| Taxes\tother\tthan\tincome\ttaxes | 95,051 | 94,482 | 94,152 |
| Depreciation\tand\tamortization | 143,479 | 136,214 | 129,029 |
| Other\tregulatory\tcharges\t(credits)\t-\tnet | (19,134) | (3,721) | 19,027 |
| TOTAL | 977,155 | 870,410 | 1,185,079 |
| OPERATING\tINCOME | 221,074 | 224,239 | 211,906 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 9,667 | 5,801 | 3,095 |
| Interest\tand\tinvestment\tincome | 85 | 656 | 195 |
| Miscellaneous\t-\tnet | 510 | (3,531) | (4,418) |
| TOTAL | 10,262 | 2,926 | (1,128) |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 51,260 | 57,114 | 57,842 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (3,875) | (2,987) | (1,644) |
| TOTAL | 47,385 | 54,127 | 56,198 |
| INCOME\tBEFORE\tINCOME\tTAXES | 183,951 | 173,038 | 154,580 |
| Income\ttaxes | 73,919 | 63,854 | 61,872 |
| NET\tINCOME | 110,032 | 109,184 | 92,708 |
| Preferred\tdividend\trequirements\tand\tother | 953 | 2,443 | 2,828 |
| EARNINGS\tAPPLICABLE\tTO\tCOMMON\tSTOCK | $109,079 | $106,741 | $89,880 |

# STATEMENTS	OF	CASH	FLOWS

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $110,032 | $109,184 | $92,708 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation\tand\tamortization | 143,479 | 136,214 | 129,029 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 84,816 | 60,986 | 18,673 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (29,528) | (28,819) | 50,199 |
| Fuel\tinventory | 5,266 | 401 | (8,537) |
| Accounts\tpayable | 3,595 | 33,733 | (26,682) |
| Taxes\taccrued | 18,803 | 20,579 | (10,104) |
| Interest\taccrued | 1,248 | 822 | (2,341) |
| Deferred\tfuel\tcosts | (25,487) | (114,711) | 105,560 |
| Other\tworking\tcapital\taccounts | 5,115 | (5,222) | (663) |
| Provisions\tfor\testimated\tlosses | (9,676) | 6,378 | (2,080) |
| Other\tregulatory\tassets | (17,412) | (3,626) | 39,582 |
| Other\tregulatory\tliabilities | 405,395 | (2,986) | 9,172 |
| \t\t\t\t\tDeferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (452,429) | — | — |
| Pension\tand\tother\tpostretirement\tliabilities | (8,055) | (10,648) | (14,939) |
| Other\tassets\tand\tliabilities | (8,577) | 9,995 | (7,298) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 226,585 | 212,280 | 372,279 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (427,616) | (310,356) | (235,894) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 9,667 | 5,801 | 3,095 |
| Insurance\tproceeds | — | — | 12,932 |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | 8,962 | 15,335 | (25,286) |
| Payment\tfor\tpurchase\tof\tassets | (6,958) | — | — |
| Other | (1,281) | (224) | 26 |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (417,226) | (289,444) | (245,127) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 148,185 | 623,812 | — |
| Retirement\tof\tlong-term\tdebt | — | (562,400) | — |
| Redemption\tof\tpreferred\tstock | — | (30,000) | — |
| Dividends\tpaid: |  |  |  |
| Common\tstock | (26,000) | (24,000) | (40,000) |
| Preferred\tstock | (953) | (2,755) | (2,828) |
| Other | (1,329) | 3,736 | (352) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | 119,903 | 8,393 | (43,180) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (70,738) | (68,771) | 83,972 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 76,834 | 145,605 | 61,633 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $6,096 | $76,834 | $145,605 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $47,631 | $53,693 | $57,576 |
| Income\ttaxes | ($25,043) | ($12,487) | $61,333 |

# BALANCE	SHEETS

| Cash | $1,607 | $16 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 4,489 | 76,818 |
| Total\tcash\tand\tcash\tequivalents | 6,096 | 76,834 |
| Accounts\treceivable: |  |  |
| Customer | 72,039 | 51,218 |
| Allowance\tfor\tdoubtful\taccounts | (574) | (549) |
| Associated\tcompanies | 45,081 | 45,973 |
| Other | 9,738 | 12,006 |
| Accrued\tunbilled\trevenues | 54,256 | 51,327 |
| Total\taccounts\treceivable | 180,540 | 159,975 |
| Deferred\tfuel\tcosts | 32,444 | 6,957 |
| Fuel\tinventory\t-\tat\taverage\tcost | 45,606 | 50,872 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 42,571 | 41,146 |
| Prepayments\tand\tother | 7,041 | 8,873 |
| TOTAL | 314,298 | 344,657 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 4,592 | 4,608 |
| Escrow\taccounts | 31,969 | 31,783 |
| TOTAL | 36,561 | 36,391 |
| UTILITY\tPLANT |  |  |
| Electric | 4,660,297 | 4,321,214 |
| Property\tunder\tcapital\tlease | 125 | 1,590 |
| Construction\twork\tin\tprogress | 149,367 | 118,182 |
| TOTAL\tUTILITY\tPLANT | 4,809,789 | 4,440,986 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 1,681,306 | 1,602,711 |
| UTILITY\tPLANT\t-\tNET | 3,128,483 | 2,838,275 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 38,284 |
| Other\tregulatory\tassets | 397,909 | 342,213 |
| Other | 2,124 | 2,320 |
| TOTAL | 400,033 | 382,817 |
| TOTAL\tASSETS | $3,879,375 | $3,602,140 |

| Associated	companies | $55,689 | $43,647 |
| :--- | :--- | :--- |
| Other | 77,326 | 80,227 |
| Customer\tdeposits | 83,654 | 84,112 |
| Taxes\taccrued | 82,843 | 64,040 |
| Interest\taccrued | 22,901 | 21,653 |
| Other | 12,785 | 9,554 |
| TOTAL | 335,198 | 303,233 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 488,806 | 861,331 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 8,867 | 8,667 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 411,011 | — |
| Asset\tretirement\tcost\tliabilities | 9,219 | 8,722 |
| Accumulated\tprovisions | 44,764 | 54,440 |
| Pension\tand\tother\tpostretirement\tliabilities | 101,498 | 109,551 |
| Long-term\tdebt | 1,270,122 | 1,120,916 |
| Other | 11,639 | 20,108 |
| TOTAL | 2,345,926 | 2,183,735 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | 20,381 | 20,381 |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t12,000,000\tshares;\tissued\tand\toutstanding\t8,666,357\tshares\tin\t2017\tand\t2016 | 199,326 | 199,326 |
| Capital\tstock\texpense\tand\tother | 167 | 167 |
| Retained\tearnings | 978,377 | 895,298 |
| TOTAL | 1,177,870 | 1,094,791 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $3,879,375 | $3,602,140 |

# STATEMENTS	OF	CHANGES	IN	COMMON	EQUITY

|  | Common	Stock | Capital	Stock<br>Expense	and	Other | Retained	Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |  |
| Balance\tat\tDecember\t31,\t2014 | $199,326 | ($690) | $763,534 | $962,170 |
| Net\tincome | — | — | 92,708 | 92,708 |
| Common\tstock\tdividends | — | — | (40,000) | (40,000) |
| Preferred\tstock\tdividends | — | — | (2,828) | (2,828) |
| Balance\tat\tDecember\t31,\t2015 | $199,326 | ($690) | $813,414 | $1,012,050 |
| Net\tincome | — | — | 109,184 | 109,184 |
| Common\tstock\tdividends | — | — | (24,000) | (24,000) |
| Preferred\tstock\tdividends | — | — | (2,443) | (2,443) |
| Preferred\tstock\tredemption | — | 857 | (857) | — |
| Balance\tat\tDecember\t31,\t2016 | $199,326 | $167 | $895,298 | $1,094,791 |
| Net\tincome | — | — | 110,032 | 110,032 |
| Common\tstock\tdividends | — | — | (26,000) | (26,000) |
| Preferred\tstock\tdividends | — | — | (953) | (953) |
| Balance\tat\tDecember\t31,\t2017 | $199,326 | $167 | $978,377 | $1,177,870 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,198,229 | $1,094,649 | $1,396,985 | $1,524,193 | $1,334,540 |
| Net\tincome | $110,032 | $109,184 | $92,708 | $74,821 | $82,159 |
| Total\tassets | $3,879,375 | $3,602,140 | $3,477,407 | $3,358,625 | $3,234,875 |
| Long-term\tobligations\t(a) | $1,290,503 | $1,141,924 | $972,058 | $1,097,182 | $1,092,786 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $502 | $459 | $565 | $585 | $527 |
| Commercial | 423 | 374 | 465 | 481 | 432 |
| Industrial | 159 | 134 | 164 | 175 | 156 |
| Governmental | 41 | 38 | 47 | 47 | 42 |
| Total\tretail | 1,125 | 1,005 | 1,241 | 1,288 | 1,157 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | — | 1 | 75 | 153 | 92 |
| Non-associated\tcompanies | 18 | 30 | 10 | 14 | 24 |
| Other | 55 | 59 | 71 | 69 | 62 |
| Total | $1,198 | $1,095 | $1,397 | $1,524 | $1,335 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 5,308 | 5,617 | 5,661 | 5,672 | 5,629 |
| Commercial | 4,783 | 4,894 | 4,913 | 4,821 | 4,815 |
| Industrial | 2,536 | 2,493 | 2,283 | 2,297 | 2,265 |
| Governmental | 421 | 439 | 433 | 414 | 409 |
| Total\tretail | 13,048 | 13,443 | 13,290 | 13,204 | 13,118 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | — | — | 1,419 | 2,657 | 1,543 |
| Non-associated\tcompanies | 857 | 1,021 | 261 | 193 | 304 |
| Total | 13,905 | 14,464 | 14,970 | 16,054 | 14,965 |

# ENTERGY	NEW	ORLEANS,	LLC	AND	SUBSIDIARIES

Net	income	decreased	$4.3	million	primarily	due	to	higher	taxes	other	than	income	taxes,	lower	net	revenue,	and	a	higher	effective income	tax	rate,	partially	offset	by	lower	other	operation	and	maintenance	expenses	and	higher	other	income.

Net	income	increased	$3.9	million	primarily	due	to	higher	net	revenue,	partially	offset	by	higher	depreciation	and	amortization	expenses, higher	interest	expense,	and	lower	other	income.

| 2016	net	revenue | $317.2 |
| :--- | :--- |
| Retail\telectric\tprice | (6.4) |
| Volume/weather | (4.3) |
| Other | 5.4 |
| 2017\tnet\trevenue | $311.9 |

The	retail	electric	price	variance	is	primarily	due	to	a	net	decrease	in	the	purchased	power	and	capacity	acquisition	cost	recovery	rider. There	was	an	increase	in	the	rider	primarily	due	to	credits	to	customers	as	part	of	the	Entergy	New	Orleans	internal	restructuring	agreement	in principle,	effective	with	the	first	billing	cycle	of	June	2017,	partially	offset	by	lower	credits	to	customers	in	2017	related	to	the	retirement	of Michoud	Units	2	and	3.	See	Note	2	to	the	financial	statements	for	further	discussion	of	the	credits	associated	with	Entergy	New	Orleans's	internal restructuring	and	the	Michoud	retirement.

The	volume/weather	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales,	partially	offset by	an	increase	in	residential	and	commercial	usage	resulting	from	a	1%	increase	in	the	average	number	of	residential	and	commercial	electric customers.

| 2015	net	revenue | $293.9 |
| :--- | :--- |
| Retail\telectric\tprice | 39.0 |
| Net\tgas\trevenue | (2.5) |
| Volume/weather | (5.1) |
| Other | (8.1) |
| 2016\tnet\trevenue | $317.2 |

The	retail	electric	price	variance	is	primarily	due	to	an	increase	in	the	purchased	power	and	capacity	acquisition	cost	recovery	rider,	as approved	by	the	City	Council,	effective	with	the	first	billing	cycle	of	March	2016,	primarily

related	to	the	purchase	of	Power	Block	1	of	the	Union	Power	Station.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power Station	purchase.

The	net	gas	revenue	variance	is	primarily	due	to	the	effect	of	less	favorable	weather	on	residential	and	commercial	sales.

The	volume/weather	variance	is	primarily	due	to	a	decrease	of	112	GWh,	or	2%,	in	billed	electricity	usage,	partially	offset	by	the	effect	of favorable	weather	on	commercial	sales	and	a	2%	increase	in	the	average	number	of	electric	customers.

•a	decrease	of	$7.9	million	in	fossil-fueled	generation	expenses	primarily	due	to	lower	outage	costs	at	Power	Block	1	of	the	Union	Power Station	in	2017	as	compared	to	2016,	the	deactivation	of	Michoud	Units	2	and	3	effective	May	2016,	and	asbestos	loss	provisions	in	2016; •a	decrease	of	$4.5	million	in	other	loss	provisions;	and

•a	decrease	of	$2.8	million	due	to	lower	write-offs	of	uncollectible	customer	accounts.

•an	increase	of	$4	million	in	distribution	expenses	primarily	due	to	higher	labor	costs,	including	contract	labor,	and	higher	vegetation maintenance	costs;	and

•an	increase	of	$1.3	million	in	energy	efficiency	costs.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	and	higher	local	franchise	taxes.	Ad	valorem taxes	 increased	 primarily	 due	 to	 higher	 assessments,	 including	 the	 assessment	 of	Arkansas	 ad	 valorem	 taxes	 on	 the	 Union	 Power	 Station beginning	in	2017.	Local	franchise	taxes	increased	primarily	due	to	higher	electric	retail	revenues	in	2017	as	compared	to	2016.

Other	income	increased	primarily	due	to	a	decrease	in	charitable	contributions	made	in	2017	as	compared	to	2016.

•a	decrease	of	$6.1	million	due	to	lower	transmission	equalization	expenses,	as	allocated	under	the	System	Agreement	as	compared	to	the same	 period	 in	 2015	 primarily	 due	 to	 the	 termination	 of	 the	 System	Agreement.	See	Note	2	 to	 the	financial	statements	for	further discussion	on	the	System	Agreement	termination;

•a	decrease	of	$4.4	million	due	to	the	cessation	of	storm	damage	provisions	in	August	2015.	See	Note	2	to	the	financial	statements	for further	discussion	of	storm	cost	recovery;	and

•an	increase	of	$5.7	million	in	fossil-fueled	generation	expenses	primarily	due	to	an	increase	as	a	result	of	the	purchase	of	Power	Block	1	of the	Union	Power	Station	in	March	2016,	partially	offset	by	a	decrease	as	a	result	of	the	deactivation	of	Michoud	Units	2	and	3	effective May	2016.		See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase;

•an	increase	of	$3.1	million	in	loss	provisions;	and

•an	increase	of	$2.8	million	due	to	higher	write-offs	of	uncollectible	customer	accounts	in	2016	as	compared	to	2015.

Depreciation	and	amortization	expenses	increased	primarily	due	to	additions	to	plant	in	service,	including	the	purchase	of	Power	Block	1 of	the	Union	Power	Station	in	March	2016,	partially	offset	by	the	retirement	of	Michoud	Units	2	and	3	effective	May	2016.

Interest	expense	increased	primarily	due	to	the	issuance	of	$110	million	of	5.50%	Series	first	mortgage	bonds	in	March	2016	and	the issuance	of	$98.7	million	of	storm	cost	recovery	bonds	in	July	2015.	See	Note	5	to	the	financial	statements	for	details	on	long-term	debt.

Other	income	decreased	primarily	due	to	an	increase	in	charitable	contributions	made	in	2016	as	compared	to	2015.

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $103,068 | $88,876 | $42,389 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 127,797 | 205,211 | 105,068 |
| Investing\tactivities | (109,500) | (322,681) | (173,460) |
| Financing\tactivities | (88,624) | 131,662 | 114,879 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (70,327) | 14,192 | 46,487 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $32,741 | $103,068 | $88,876 |

Net	cash	flow	provided	by	operating	activities	decreased	$77.4	million	in	2017	primarily	due	to	a	decrease	of	$77.3	million	in	income	tax refunds	in	2017	compared	to	2016	and	the	timing	of	collections	from	customers	and	payments	to	vendors.	Entergy	New	Orleans	had	income	tax refunds	in	2017	and	2016	in	accordance	with	an	intercompany	income	tax	allocation	agreement.	The	2016	income	tax	refunds	resulted	primarily from	deductible	temporary	differences.	The	decrease	was	partially	offset	by	an	increase	due	to	the	timing	of	recovery	of	fuel	and	purchased	power costs.

Net	cash	flow	provided	by	operating	activities	increased	$100.1	million	in	2016	primarily	due	to	income	tax	refunds	of	$86	million	in 2016	as	compared	to	income	tax	payments	of	$8.1	million	in	2015.	Entergy	New	Orleans	had	income	tax	refunds	in	2016	and	income	tax payments	in	2015	in	accordance	with	an	intercompany	income	tax	allocation	agreement.	The	2016	income	tax	refunds	resulted	primarily	from deductible	temporary	differences.

Net	cash	flow	used	in	investing	activities	decreased	$213.2	million	in	2017	primarily	due	to	the	purchase	of	Power	Block	1	of	the	Union Power	Station	for	approximately	$237	million	in	March	2016.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station purchase.	The	decrease	was	partially	offset	by	an	increase	of	$16.7	million	in	distribution	construction	expenditures	primarily	due	to	a	higher scope	of	work	performed	in	2017	as	compared	to	2016.

Net	cash	flow	used	in	investing	activities	increased	$149.2	million	in	2016	primarily	due	to	the	purchase	of	Power	Block	1	of	the	Union Power	Station	for	approximately	$237	million	in	March	2016.	The	increase	was	partially	offset	by	a	deposit	of	$63.9	million	into	the	storm reserve	escrow	account	in	July	2015	and	money	pool	activity.	See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station purchase.	See	Note	5	to	the	financial	statements	for	a	discussion	of	the	issuance	in	July	2015	of	securitization	bonds	to	recover	storm	costs.

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	$1.6	million	in	2016	compared	to	increasing	$15.4	million	in	2015.	 	The	money	pool	is	an	inter-company borrowing	arrangement	designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings

Entergy	New	Orleans's	financing	activities	used	$88.6	million	of	cash	in	2017	compared	to	providing	$131.7	million	in	2016	primarily due	to	the	following	activity:

•the	issuance	of	$110	million	of	5.50%	Series	first	mortgage	bonds	in	March	2016;

•an	increase	of	$55.5	million	in	common	equity	distributions	in	2017	as	compared	to	2016.	Common	equity	distributions	in	2017	increased primarily	as	a	result	of	Entergy	New	Orleans's	cash	position	in	excess	of	its	working	capital	requirements.	There	were	no	common	equity distributions	in	first	quarter	2016	in	anticipation	of	the	purchase	of	Power	Block	1	of	the	Union	Power	Station	in	March	2016; •a	decrease	of	$27.8	million	in	capital	contributions	received	from	Entergy	Corporation	in	2017	compared	to	2016.	The	2017	contribution was	made	in	consideration	of	Entergy	New	Orleans's	upcoming	capital	requirements.	The	2016	contribution	was	made	in	anticipation	of Entergy	New	Orleans's	purchase	of	Power	Block	1	of	the	Union	Power	Station;	and

•the	redemptions	of	$7.8	million	of	4.75%	Series	preferred	stock,	$6	million	of	5.56%	Series	preferred	stock,	and	$6	million	of	4.36% Series	preferred	stock	in	2017	in	connection	with	the	internal	restructuring,	as	discussed	above.

See	Note	14	to	the	financial	statements	for	discussion	of	the	Union	Power	Station	purchase.

•the	purchase	of	Entergy	Louisiana's	Algiers	assets	in	September	2015.	The	cash	portion	of	the	purchase	is	reflected	as	a	repayment	of	a long-term	payable	due	 to	Entergy	Louisiana	 in	 the	cash	flow	statement.	See	Note	2	 to	 the	financial	statements	and	"Algiers	Asset Transfer"	below	for	further	discussion	of	the	Algiers	asset	transfer	and	accounting	for	the	transaction; •the	issuance	of	$110	million	of	5.50%	Series	first	mortgage	bonds	in	March	2016;	and

•the	issuance	of	$85	million	of	4%	Series	first	mortgage	bonds	in	May	2016.	Entergy	New	Orleans	used	the	proceeds	to	pay,	prior	to maturity,	its	$33.271	million	of	5.6%	Series	first	mortgage	bonds	due	September	2024	and	to	pay,	prior	to	maturity,	its	$37.772	million	of 5.65%	Series	first	mortgage	bonds	due	September	2029.

# The	increase	was	offset	by:

•the	issuance	of	$98.7	million	of	storm	costs	recovery	bonds	in	July	2015;

•a	$47.8	million	capital	contribution	received	from	Entergy	Corporation	in	2016	as	compared	to	an	$87.5	million	capital	contribution received	from	Entergy	Corporation	in	2015,	both	in	anticipation	of	Entergy	New	Orleans's	purchase	of	Power	Block	1	of	the	Union	Power Station;	and

•an	increase	of	$11.5	million	in	common	equity	distributions	in	2016.	Common	equity	distributions	were	lower	in	2015	in	anticipation	of the	purchase	of	Power	Block	1	of	the	Union	Power	Station.

See	Note	5	to	the	financial	statements	for	more	details	on	long-term	debt.

Entergy	New	Orleans's	capitalization	is	balanced	between	equity	and	debt	as	shown	in	the	following	table.	The	increase	in	the	debt	to capital	ratio	is	primarily	due	to	the	redemptions	of	preferred	stock	in	2017.

|  | December	31,	2017 | December	31,	2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 51.3% | 50.1% |
| Effect\tof\texcluding\tsecuritization\tbonds | (4.7%) | (5.2%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 46.6% | 44.9% |
| Effect\tof\tsubtracting\tcash | (2.4%) | (8.0%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 44.2% | 36.9% |

(a)	Calculation	excludes	the	securitization	bonds,	which	are	non-recourse	to	Entergy	New	Orleans.

Net	debt	consists	of	debt	less	cash	and	cash	equivalents.	Debt	consists	of	short-term	borrowings,	long-term	debt,	including	the	currently	maturing portion,	and	the	long-term	payable	to	Entergy	Louisiana.	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	ratios	excluding	securitization	bonds	in analyzing	its	financial	condition	and	believes	they	provide	useful	information	to	its	investors	and	creditors	in	evaluating	Entergy	New	Orleans's financial	condition	because	the	securitization	bonds	are	non-recourse	to	Entergy	New	Orleans,	as	more	fully	described	in	Note	5	to	the	financial statements.	Entergy	New	Orleans	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	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	on	hand.

Entergy	New	Orleans	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital while	also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.		To	the	extent	that	operating	cash	flows	are	in excess	of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to maintain	the	targeted	capital	structure.		To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	Entergy	New Orleans	may	issue	incremental	debt	or	reduce	dividends,	or	both,	to	maintain	its	targeted	capital	structure.		In	addition,	in	certain	infrequent circumstances,	such	as	large	transactions	that	would	materially	alter	the	capital	structure	if	financed	entirely	with	debt	and	reducing	dividends, Entergy	New	Orleans	may	receive	equity	contributions	to	maintain	the	targeted	capital	structure.

Entergy	New	Orleans	requires	capital	resources	for:

•working	capital	purposes,	including	the	financing	of	fuel	and	purchased	power	costs;

•debt	maturities	or	retirements;	and

•distribution	and	interest	payments.

Following	are	the	amounts	of	Entergy	New	Orleans's	planned	construction	and	other	capital	investments.

|  | 2018 | 2019 | 2020 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tMillions) |  |
| Planned\tconstruction\tand\tcapital\tinvestment: |  |  |  |
| Generation | $115 | $80 | $15 |
| Transmission | 15 | 10 | 5 |
| Distribution | 80 | 85 | 80 |
| Utility\tSupport | 20 | 15 | 15 |
| Total | $230 | $190 | $115 |

Following	are	the	amounts	of	Entergy	New	Orleans's	existing	debt	and	lease	obligations	(includes	estimated	interest	payments)	and	other purchase	obligations.

|  | 2018 | 2019-2020 | 2021-2022 | After	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $31 | $87 | $59 | $674 | $851 |
| Operating\tleases | $2 | $3 | $1 | $2 | $8 |
| Purchase\tobligations\t(b) | $245 | $480 | $463 | $3,669 | $4,857 |

(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	$7.3	million	to	its qualified	pension	plan	and	approximately	$3.7	million	to	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the	2018 required	pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April 1,	 2018.	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	$238.2	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	such	as	the	New	Orleans	Power	Station	discussed	below;	transmission	projects	to	enhance	reliability,	reduce	congestion,	and enable	economic	growth;	distribution	spending	to	enhance	reliability	and	improve	service	to	customers,	including	investment	to	support	advanced metering;	system	improvements;	and	other	investments.		Estimated	capital	expenditures	are	subject	to	periodic	review	and	modification	and	may vary	based	on	the	ongoing	effects	of	regulatory	constraints	and	requirements,	environmental	compliance,	business	opportunities,	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	of	Entergy	Utility	Holding	Company,	LLC,	Entergy	New	Orleans	pays	distributions	from	its	earnings	at	a percentage	determined	monthly.

In	June	2016,	Entergy	New	Orleans	filed	an	application	with	the	City	Council	seeking	a	public	interest	determination	and	authorization	to construct	the	New	Orleans	Power	Station,	a	226	MW	advanced	combustion	turbine	in	New	Orleans,	Louisiana,	at	the	site	of	the	existing	Michoud generating	facility,	which	was	retired	effective	May	31,	2016.	In	January	2017	several	intervenors	filed	testimony	opposing	the	construction	of	the New	Orleans	Power	Station	on	various	grounds.	In	July	2017,	Entergy	New	Orleans	submitted	a	supplemental	and	amending	application	to	the City	Council	seeking	approval	to	construct	either	the	originally	proposed	226	MW	advanced	combustion	turbine,	or	alternatively,	a	128	MW	unit composed	of	natural	gas-fired	reciprocating	engines	and	a	related	cost	recovery	plan.	The	application	included	an	updated	cost	estimate	of	$232 million	for	 the	226	MW	advanced	combustion	 turbine.	The	cost	estimate	for	 the	alternative	128	MW	unit	 is	$210	million.	In	addition,	the application	renewed	the	commitment	to	pursue	up	to	100	MW	of	renewable	resources	to	serve	New	Orleans.	In	testimony	filed	subsequent	to Entergy	New	Orleans's	supplemental	and	amending	application,	several	intervenors	oppose	City	Council	approval	of	either	alternative,	while	the City	Council	advisors	and	one	intervenor	support	the	smaller	alternative.	A	contested	hearing	was	held	in	December	2017	and	post-hearing	briefs were	filed	in	January	2018.	In	February	2018	the	City	Council	Utility	Committee	adopted	a	resolution	approving	construction	of	the	128	MW unit.	The	full	City	Council	is	expected	to	vote	on	the	resolution	in	March	2018.	The	commercial	operation	date	is	dependent	on	the	alternative selected	by	the	City	Council	and	the	receipt	of	other	permits	and	approvals.

# Gas	Infrastructure	Rebuild	Plan

In	September	2016,	Entergy	New	Orleans	submitted	to	the	City	Council	a	request	for	authorization	for	Entergy	New	Orleans	to	proceed with	annual	incremental	capital	funding	of	$12.5	million	for	its	gas	infrastructure	rebuild	plan,	which	would	replace	of	all	of	Entergy	New Orleans's	low	pressure	cast	iron,	steel,	and	vintage	plastic	pipe	over	a	ten-year	period	commencing	in	2017.		Entergy	New	Orleans	also	proposed that	recovery	of	the	investment	to	fund	its	gas	infrastructure	replacement	plan	be	determined	in	connection	with	its	next	base	rate	case,	which	is anticipated	to	be	filed	in	2018.		The	City	Council	has	authorized	Entergy	New	Orleans	to	proceed	with	its	replacement	plans	at	the	requested	pace until	such	time	that	rates	resulting	from	the	anticipated	2018	rate	case	are	implemented	(approximately	13	months	after	filing).		As	a	result	of	the anticipated	2018	rate	case,	the	City	Council	may	establish	new	overall	gas	base	rates	to	allow	Entergy	New	Orleans	to	continue	to	recover	these replacement	costs.		The	City	Council	has	established	a	schedule	for	proceedings	in	advance	of	the	rate	case	intended	to	provide	an	opportunity	for evaluation	of	the	gas	infrastructure	replacement	plan	that	would	best	serve	the	public	interest	and	the	effect	on	customers	of	the	approval	of	any such	plan.

In	 October	 2016,	 Entergy	 New	 Orleans	 filed	 an	 application	 seeking	 a	 finding	 from	 the	 City	 Council	 that	 Entergy	 New	 Orleans's deployment	of	advanced	electric	and	gas	metering	infrastructure	is	in	the	public	interest.		Entergy	New	Orleans	proposed	to	deploy	advanced meters	that	enable	two-way	data	communication;	design	and	build	a	secure	and	reliable	network	to	support	such	communications;	and	implement support	systems.		AMI	is	intended	to	serve	as	the	foundation	of	Entergy	New	Orleans's	modernized	power	grid.		The	filing	included	an	estimate	of implementation	costs	for	AMI	of	$75	million.	The	filing	identified	a	number	of	quantified	and	unquantified	benefits,	and	Entergy	New	Orleans provided	a	cost/benefit	analysis	showing	that	its	combined	electric	and	gas	AMI	deployment	is	expected	to	produce	a	nominal	net	benefit	to customers	of	$101	million.		Entergy	New	Orleans	also	sought	to	continue	to	include	in	rate	base	the	remaining	book	value,	approximately	$21 million	at	December	31,	2015,	of	the	existing	electric	meters	and	also	to	depreciate	those	assets	using	current	depreciation	rates.		Entergy	New Orleans	proposed	a	15-year	depreciable	life	for	the	new	advanced	meters,	the	three-year	deployment	of	which	is	expected	to	begin	in	2019. Deployment	of	the	information	technology	infrastructure	began	in	2017	and	deployment	of	the	communications	network	is	expected	to	begin	in 2018.		Entergy	New	Orleans	proposed	to	recover	the	cost	of	AMI	through	the	implementation	of	a	customer	charge,	net	of	certain	benefits,	phased in	over	the	period	2019	through	2022.		The	City	Council's	advisors	filed	testimony	in	May	2017	recommending	the	adoption	of	AMI	subject	to certain	modifications,	including	the	denial	of	Entergy	New	Orleans's	proposed	customer	charge	as	a	cost	recovery	mechanism.	In	January	2018	a settlement	was	reached	between

Entergy	New	Orleans,	LLC	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

the	City	Council's	advisors	and	Entergy	New	Orleans.	In	February	2018	the	City	Council	approved	the	settlement,	which	deferred	cost	recovery to	the	2018	Entergy	New	Orleans	rate	case,	but	also	stated	that	an	adjustment	for	2018-2019	AMI	costs	can	be	filed	in	the	rate	case	and	that,	for all	subsequent	AMI	costs,	the	mechanism	to	be	approved	in	the	2018	rate	case	will	allow	for	the	timely	recovery	of	such	costs.

Entergy	New	Orleans's	sources	to	meet	its	capital	requirements	include:

•debt	and	preferred	membership	interest	issuances;	and

Entergy	New	Orleans	may	refinance,	redeem,	or	otherwise	retire	debt	prior	to	maturity,	to	the	extent	market	conditions	and	interest	rates are	favorable.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $12,723 | $14,215 | $15,794 | $442 |

Entergy	New	Orleans	has	a	credit	facility	in	the	amount	of	$25	million	scheduled	to	expire	in	November	2018.	The	credit	facility	allows Entergy	New	Orleans	to	issue	letters	of	credit	against	$10	million	of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2017,	there	were no	cash	borrowings	and	a	$0.8	million	letter	of	credit	was	outstanding	under	the	facility.	In	addition,	Entergy	New	Orleans	is	a	party	to	an uncommitted	letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	to	MISO.		As	of	December	31,	2017,	a	$1.4	million letter	 of	 credit	 was	 outstanding	 under	 Entergy	 New	 Orleans's	 letter	 of	 credit	 facility.	See	Note	4	 to	 the	financial	statements	for	additional discussion	of	the	credit	facilities.

Entergy	New	Orleans	obtained	authorization	from	the	FERC	through	October	2019	for	short-term	borrowings	not	to	exceed	an	aggregate amount	of	$150	million	at	any	time	outstanding	and	long-term	borrowings	and	securities	issuances.	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	not	only	by	the	FERC,	but	also	by	the	City	Council,	and	the	current	City	Council	authorization	extends	through	June	2018.

# 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.

See	"Algiers	Asset	Transfer"	below	for	discussion	of	the	Algiers	asset	transfer.	As	a	provision	of	the	settlement	agreement	approved	by the	City	Council	in	May	2015	providing	for	the	Algiers	asset	transfer,	it	was	agreed	that,	with	limited	exceptions,	no	action	may	be	taken	with respect	to	Entergy	New	Orleans's	base	rates	until	rates	are	implemented

from	a	base	rate	case	that	must	be	filed	for	its	electric	and	gas	operations	in	2018.	This	provision	eliminated	the	formula	rate	plan	applicable	to Algiers	 operations.	The	limited	exceptions	included	continued	implementation	of	the	then-remaining	two	years	of	the	four-year	phased-in	rate increase	for	the	Algiers	area	and	certain	exceptional	cost	increases	or	decreases	in	the	base	revenue	requirement.	An	additional	provision	of	the settlement	agreement	allowed	for	continued	recovery	of	 the	revenue	requirement	associated	with	 the	capacity	and	energy	from	Ninemile	6 received	by	Entergy	New	Orleans	under	a	power	purchase	agreement	with	Entergy	Louisiana	(Algiers	PPA).	The	settlement	authorized	Entergy New	Orleans	to	recover	the	remaining	revenue	requirement	related	to	the	Algiers	PPA	through	base	rates	charged	to	Algiers	customers.	 The settlement	also	provided	for	continued	implementation	of	the	Algiers	MISO	recovery	rider.

A	2008	rate	case	settlement	included	$3.1	million	per	year	in	electric	rates	to	fund	the	Energy	Smart	energy	efficiency	programs.		The	rate settlement	provided	an	incentive	for	Entergy	New	Orleans	to	meet	or	exceed	energy	savings	targets	set	by	the	City	Council	and	provided	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	January	2015	the	City	Council	approved	funding	for	the	Energy	Smart	program	from	April	2015	through	March	2017 using	 the	 remainder	 of	 the	 approximately	$12.8	million	of	2014	rough	production	cost	equalization	funds,	with	any	remaining	costs	being recovered	through	the	fuel	adjustment	clause.	This	funding	methodology	was	modified	in	November	2015	when	the	City	Council	directed	Entergy New	Orleans	to	use	a	combination	of	guaranteed	customer	savings	related	to	a	prior	agreement	with	the	City	Council	and	rough	production	cost equalization	funds	to	cover	program	costs	prior	to	recovering	any	costs	through	the	fuel	adjustment	clause.	In	April	2017	the	City	Council approved	an	implementation	plan	for	the	Energy	Smart	program	from	April	2017	through	December	2019.	The	City	Council	directed	that	the $11.8	million	balance	reported	for	Energy	Smart	funds	be	used	to	continue	funding	the	program	for	Entergy	New	Orleans's	legacy	customers	and that	the	Energy	Smart	Algiers	program	continue	to	be	funded	through	the	Algiers	fuel	adjustment	clause,	until	additional	customer	funding	is required	for	the	legacy	customers.	In	September	2017,	Entergy	New	Orleans	filed	a	supplemental	plan	and	proposed	several	options	for	an	interim cost	recovery	mechanism	necessary	to	recover	program	costs	during	the	period	between	when	existing	funds	directed	to	Energy	Smart	programs are	depleted	(estimated	to	be	June	2018)	and	when	new	rates	from	the	anticipated	2018	combined	rate	case,	which	will	include	a	cost	recovery mechanism	for	Energy	Smart	funding,	take	effect	(estimated	to	be	August	2019).	Entergy	New	Orleans	requested	that	the	City	Council	approve	a cost	recovery	mechanism	prior	to	June	2018.	In	December	2017	the	City	Council	approved	an	energy	efficiency	cost	recovery	rider	as	an	interim funding	mechanism	for	Energy	Smart,	subject	to	verification	that	no	additional	funding	sources	exist.

# Algiers	Asset	Transfer

# Show	Cause	Order

In	July	2016	the	City	Council	approved	the	issuance	of	a	show	cause	order,	which	directed	Entergy	New	Orleans	to	make	a	filing	on	or before	September	29,	2016	to	demonstrate	the	reasonableness	of	its	actions	or	positions	with	regard	to	certain	issues	in	four	existing	dockets	that relate	to	Entergy	New	Orleans's:	(i)	storm	hardening	proposal;	(ii)	2015	integrated	resource	plan;	(iii)	gas	infrastructure	rebuild	proposal;	and	(iv) proposed	sizing	of	the	New	Orleans	Power	Station	and	its	community	outreach	prior	to	the	filing.	In	September	2016,	Entergy	New	Orleans	filed its	response	to	the	City	Council's	show	cause	order.	The	City	Council	has	not	established	any	further	procedural	schedule	with	regard	to	this proceeding.

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,	 with reference to	 possible	 exceptions	 noted in	 "Regulation	 of	 Entergy's	 Business -	Environmental	 Regulation" in	 Part	 I,	 Item	 1.	 	 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.

Entergy	New	Orleans's	qualified	pension	and	other	postretirement	reported	costs,	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

| certain	actuarial	assumptions	(dollars	in	thousands). |  |  |  |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | Change\tin\tAssumption | Impact\ton\t2018\tPostretirement\tBenefit\nCost | Impact\ton\t2017\nAccumulated\tPostretirement\nBenefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | ($12) | $1,406 |
| Health\tcare\tcost\ttrend | 0.25% | $54 | $1,074 |

Total	qualified	pension	cost	for	Entergy	New	Orleans	in	2017	was	$5.1	million.	Entergy	New	Orleans	anticipates	2018	qualified	pension cost	to	be	$5.8	million.		In	2016,	Entergy	New	Orleans	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified pension	costs,	which	had	the	effect	of	lowering	qualified	pension	costs	by	$1.7	million.		Entergy	New	Orleans	contributed	$9.9	million	to	its pension	 plans	 in	 2017	 and	 estimates	 2018	 pension	 contributions	 will	 be	 approximately	 $7.3	 million,	 although	 the	 2018	 required	 pension contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	postretirement	health	care	and	life	insurance	benefit	income	for	Entergy	New	Orleans	in	2017	was	$2.5	million.		Entergy	New Orleans	expects	2018	postretirement	health	care	and	life	insurance	benefit	income	of	approximately	$3.7	million.		In	2016,	Entergy	New	Orleans refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	other	postretirement	costs,	which	had	the	effect	of	lowering qualified	other	postretirement	costs	by	$548	thousand.	Entergy	New	Orleans	contributed	$3.7	million	to	its	other	postretirement	plans	in	2017	and estimates	2018	contributions	will	be	approximately	$3.7	million.

We	 have	 audited	 the	 accompanying	 consolidated	 balance	 sheets	 of	 Entergy	 New	 Orleans,	 LLC	 and	 Subsidiaries	 (the	 "Company")	 as	 of December	31,	2017	and	2016,	the	related	consolidated	statements	of	income,	cash	flows,	and	changes	in	common	equity	(pages	392	through	396 and	applicable	 items	 in	pages	55	 through	230),	for	each	of	 the	 three	years	 in	 the	period	ended	December	31,	2017,	and	 the	related	notes (collectively	referred	to	as	the	"financial	statements").	In	our	opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial position	of	the	Company	as	of	December	31,	2017	and	2016,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the period	ended	December	31,	2017,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $631,744 | $586,820 | $584,322 |
| Natural\tgas | 84,326 | 78,643 | 87,124 |
| TOTAL | 716,070 | 665,463 | 671,446 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 111,082 | 40,489 | 96,307 |
| Purchased\tpower | 282,178 | 299,551 | 277,851 |
| Other\toperation\tand\tmaintenance | 109,270 | 117,471 | 119,087 |
| Taxes\tother\tthan\tincome\ttaxes | 54,590 | 48,078 | 46,660 |
| Depreciation\tand\tamortization | 52,945 | 51,737 | 43,205 |
| Other\tregulatory\tcharges\t-\tnet | 10,889 | 8,258 | 3,366 |
| TOTAL | 620,954 | 565,584 | 586,476 |
| OPERATING\tINCOME | 95,116 | 99,879 | 84,970 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 2,418 | 1,178 | 1,404 |
| Interest\tand\tinvestment\tincome | 707 | 256 | 73 |
| Miscellaneous\t-\tnet | 24 | (3,144) | 339 |
| TOTAL | 3,149 | (1,710) | 1,816 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 21,281 | 21,061 | 17,312 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (847) | (446) | (641) |
| TOTAL | 20,434 | 20,615 | 16,671 |
| INCOME\tBEFORE\tINCOME\tTAXES | 77,831 | 77,554 | 70,115 |
| Income\ttaxes | 33,278 | 28,705 | 25,190 |
| NET\tINCOME | 44,553 | 48,849 | 44,925 |
| Preferred\tdividend\trequirements\tand\tother | 841 | 965 | 965 |
| EARNINGS\tAPPLICABLE\tTO\tCOMMON\tEQUITY | $43,712 | $47,884 | $43,960 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $44,553 | $48,849 | $44,925 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation\tand\tamortization | 52,945 | 51,737 | 43,205 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 64,036 | 140,283 | 22,180 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (18,058) | (3,888) | 7,878 |
| Fuel\tinventory | (49) | 71 | 1,104 |
| Accounts\tpayable | 1,874 | 15,434 | 2,738 |
| Prepaid\ttaxes\tand\ttaxes\taccrued | (22,100) | (1,685) | (1,050) |
| Interest\taccrued | 44 | 534 | 1,270 |
| Deferred\tfuel\tcosts | 12,592 | (33,839) | (182) |
| Other\tworking\tcapital\taccounts | (2,711) | 4,165 | (1,945) |
| Provisions\tfor\testimated\tlosses | (3,430) | 4,326 | 58,310 |
| Other\tregulatory\tassets | 16,673 | (2,784) | (70,471) |
| Other\tregulatory\tliabilities | 110,147 | (3,997) | (7,359) |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (111,170) | — | — |
| Pension\tand\tother\tpostretirement\tliabilities | (15,994) | (6,859) | (18,831) |
| Other\tassets\tand\tliabilities | (1,555) | (7,136) | 23,296 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 127,797 | 205,211 | 105,068 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (115,584) | (90,512) | (91,928) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 2,418 | 1,178 | 1,404 |
| Payment\tfor\tpurchase\tof\tplant | — | (237,335) | — |
| Investments\tin\taffiliates | — | (38) | — |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | 1,492 | 1,579 | (15,352) |
| Payments\tto\tstorm\treserve\tescrow\taccount | (597) | (438) | (68,886) |
| Receipts\tfrom\tstorm\treserve\tescrow\taccount | 2,488 | 3 | 5,922 |
| Changes\tin\tsecuritization\taccount | 283 | 2,882 | (4,620) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (109,500) | (322,681) | (173,460) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | — | 240,604 | 95,367 |
| Retirement\tof\tlong-term\tdebt | (10,600) | (132,526) | — |
| Repayment\tof\tlong-term\tpayable\tdue\tto\tEntergy\tLouisiana | (2,104) | (4,973) | (59,610) |
| Redemption\tof\tpreferred\tstock | (20,599) | — | — |
| Capital\tcontributions\tfrom\tparent | 20,000 | 47,750 | 87,500 |
| Distributions/dividends\tpaid: |  |  |  |
| Common\tequity | (74,250) | (18,720) | (7,250) |
| Preferred\tstock | (1,083) | (965) | (965) |
| Other | 12 | 492 | (163) |
| Net\tcash\tflow\tprovided\tby\t(used\tin)\tfinancing\tactivities | (88,624) | 131,662 | 114,879 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (70,327) | 14,192 | 46,487 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 103,068 | 88,876 | 42,389 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $32,741 | $103,068 | $88,876 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $20,180 | $19,317 | $14,951 |
| Income\ttaxes | ($8,660) | ($85,962) | $8,110 |

| Cash | $30 | $28 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 32,711 | 103,040 |
| Total\tcash\tand\tcash\tequivalents | 32,741 | 103,068 |
| Securitization\trecovery\ttrust\taccount | 1,455 | 1,738 |
| Accounts\treceivable: |  |  |
| Customer | 51,006 | 43,536 |
| Allowance\tfor\tdoubtful\taccounts | (3,057) | (3,059) |
| Associated\tcompanies | 22,976 | 16,811 |
| Other | 6,471 | 5,926 |
| Accrued\tunbilled\trevenues | 20,638 | 18,254 |
| Total\taccounts\treceivable | 98,034 | 81,468 |
| Deferred\tfuel\tcosts | — | 4,818 |
| Fuel\tinventory\t-\tat\taverage\tcost | 1,890 | 1,841 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 10,381 | 8,416 |
| Prepaid\ttaxes | 26,479 | 4,379 |
| Prepayments\tand\tother | 8,030 | 6,587 |
| TOTAL | 179,010 | 212,315 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Non-utility\tproperty\tat\tcost\t(less\taccumulated\tdepreciation) | 1,016 | 1,016 |
| Storm\treserve\tescrow\taccount | 79,546 | 81,437 |
| Other | 2,373 | 7,160 |
| TOTAL | 82,935 | 89,613 |
| UTILITY\tPLANT |  |  |
| Electric | 1,302,235 | 1,258,934 |
| Natural\tgas | 261,263 | 240,408 |
| Construction\twork\tin\tprogress | 46,993 | 24,975 |
| TOTAL\tUTILITY\tPLANT | 1,610,491 | 1,524,317 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 631,178 | 604,825 |
| UTILITY\tPLANT\t-\tNET | 979,313 | 919,492 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Deferred\tfuel\tcosts | 4,080 | 4,080 |
| Other\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof\t$72,095\tas\tof\tDecember\t31,\t2017\tand\t$82,272\tas\tof\nDecember\t31,\t2016) | 251,433 | 268,106 |
| Other | 1,065 | 963 |
| TOTAL | 256,578 | 273,149 |
| TOTAL\tASSETS | $1,497,836 | $1,494,569 |

| Payable	due	to	Entergy	Louisiana | $2,077 | $2,104 |
| :--- | :--- | :--- |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 47,472 | 39,260 |
| Other | 29,777 | 35,920 |
| Customer\tdeposits | 28,442 | 28,667 |
| Interest\taccrued | 5,487 | 5,443 |
| Deferred\tfuel\tcosts | 7,774 | — |
| Other | 7,351 | 11,415 |
| TOTAL\tCURRENT\tLIABILITIES | 128,380 | 122,809 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 283,302 | 334,953 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 2,323 | 622 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 119,259 | 9,074 |
| Asset\tretirement\tcost\tliabilities | 3,076 | 2,875 |
| Accumulated\tprovisions | 85,083 | 88,513 |
| Pension\tand\tother\tpostretirement\tliabilities | 20,755 | 36,750 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$74,419\tas\tof\tDecember\t31,\t2017\tand\t$84,776\tas\tof\tDecember\t31,\n2016) | 418,447 | 428,467 |
| Long-term\tpayable\tdue\tto\tEntergy\tLouisiana | 16,346 | 18,423 |
| Other | 5,317 | 5,357 |
| TOTAL\tNON-CURRENT\tLIABILITIES | 953,908 | 925,034 |
| Commitments\tand\tContingencies |  |  |
| Preferred\tstock\twithout\tsinking\tfund | — | 19,780 |
| EQUITY |  |  |
| Member's\tequity | 415,548 | 426,946 |
| TOTAL | 415,548 | 426,946 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $1,497,836 | $1,494,569 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	MEMBER'S	EQUITY

| Balance	at	December	31,	2014 | $228,025 |
| :--- | :--- |
| Net\tincome | 44,925 |
| Net\tincome\tattributable\tto\tEntergy\tLouisiana | (2,203) |
| Capital\tcontributions\tfrom\tparent | 87,500 |
| Common\tequity\tdistributions | (7,250) |
| Preferred\tstock\tdividends | (965) |
| Balance\tat\tDecember\t31,\t2015 | $350,032 |
| Net\tincome | 48,849 |
| Capital\tcontributions\tfrom\tparent | 47,750 |
| Common\tequity\tdistributions | (18,720) |
| Preferred\tstock\tdividends | (965) |
| Balance\tat\tDecember\t31,\t2016 | $426,946 |
| Net\tincome | 44,553 |
| Capital\tcontributions\tfrom\tparent | 20,000 |
| Common\tequity\tdistributions | (74,250) |
| Preferred\tstock\tdividends | (841) |
| Other | (860) |
| Balance\tat\tDecember\t31,\t2017 | $415,548 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $716,070 | $665,463 | $671,446 | $735,192 | $659,746 |
| Net\tincome | $44,553 | $48,849 | $44,925 | $31,030 | $12,608 |
| Total\tassets | $1,497,836 | $1,494,569 | $1,215,144 | $1,014,916 | $964,482 |
| Long-term\tobligations\t(a) | $434,793 | $466,670 | $357,687 | $323,280 | $318,034 |

(a)	Includes	long-term	debt	(including	the	long-term	payable	to	Entergy	Louisiana	and	excluding	currently	maturing	debt)	and	preferred	stock	without	sinking	fund.

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $250 | $231 | $220 | $230 | $221 |
| Commercial | 228 | 206 | 186 | 196 | 194 |
| Industrial | 36 | 33 | 30 | 33 | 35 |
| Governmental | 77 | 69 | 64 | 67 | 69 |
| Total\tretail | 591 | 539 | 500 | 526 | 519 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | — | 30 | 66 | 78 | 27 |
| Non-associated\tcompanies | 29 | 3 | — | 4 | — |
| Other | 12 | 15 | 18 | 17 | 19 |
| Total | $632 | $587 | $584 | $625 | $565 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 2,155 | 2,231 | 2,301 | 2,262 | 2,152 |
| Commercial | 2,248 | 2,268 | 2,257 | 2,181 | 2,130 |
| Industrial | 429 | 441 | 463 | 455 | 484 |
| Governmental | 790 | 794 | 825 | 783 | 778 |
| Total\tretail | 5,622 | 5,734 | 5,846 | 5,681 | 5,544 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | — | 1,071 | 1,644 | 1,379 | 517 |
| Non-associated\tcompanies | 1,703 | 141 | 11 | 18 | 14 |
| Total | 7,325 | 6,946 | 7,501 | 7,078 | 6,075 |

# ENTERGY	TEXAS,	INC.	AND	SUBSIDIARIES

Net	income	decreased	$31.4	million	primarily	due	to	lower	net	revenue,	higher	depreciation	and	amortization	expenses,	higher	other operation	and	maintenance	expenses,	and	higher	taxes	other	than	income	taxes.

Net	income	increased	$37.9	million	primarily	due	to	lower	other	operation	and	maintenance	expenses,	the	asset	write-off	of	its	receivable associated	with	the	Spindletop	gas	storage	facility	in	2015,	and	higher	net	revenue.

| 2016	net	revenue | $644.2 |
| :--- | :--- |
| Net\twholesale\trevenue | (35.1) |
| Purchased\tpower\tcapacity | (5.9) |
| Transmission\trevenue | (5.4) |
| Reserve\tequalization | 5.6 |
| Retail\telectric\tprice | 19.0 |
| Other | 4.4 |
| 2017\tnet\trevenue | $626.8 |

The	net	wholesale	revenue	variance	is	primarily	due	to	lower	net	capacity	revenues	resulting	from	the	termination	of	the	purchased	power agreements	between	Entergy	Louisiana	and	Entergy	Texas	in	August	2016.

The	purchased	power	capacity	variance	is	primarily	due	to	increased	expenses	due	to	capacity	cost	changes for	ongoing	purchased	power	capacity	contracts.

The	transmission	revenue	variance	is	primarily	due	to	a	decrease	in	the	amount	of	transmission	revenues	allocated	by	MISO.

The	reserve	equalization	variance	is	due	to	the	absence	of	reserve	equalization	expenses	in	2017	as	a	result	of	Entergy	Texas's	exit	from the	System	Agreement	in	August	2016.	See	Note	2	to	the	financial	statements	for	a	discussion	of	the	System	Agreement.

The	retail	electric	price	variance	is	primarily	due	to	the	implementation	of	the	transmission	cost	recovery	factor	rider	in	September	2016 and	an	increase	in	the	transmission	cost	recovery	factor	rider	rate	in	March	2017,	each	as	approved	by	the	PUCT.	See	Note	2	to	the	financial statements	for	further	discussion	of	the	transmission	cost	recovery	factor	rider	filing.

| 2015	net	revenue | $637.2 |
| :--- | :--- |
| Reserve\tequalization | 14.3 |
| Purchased\tpower\tcapacity | 12.4 |
| Transmission\trevenue | 7.0 |
| Retail\telectric\tprice | 5.4 |
| Net\twholesale\trevenue | (27.8) |
| Other | (4.3) |
| 2016\tnet\trevenue | $644.2 |

The	reserve	equalization	variance	is	primarily	due	to	a	reduction	in	reserve	equalization	expense	primarily	due	to	changes	in	the	Entergy System	generation	mix	compared	to	the	same	period	in	2015	as	a	result	of	the	execution	of	a	new	purchased	power	agreement	and	Entergy Mississippi's	exit	from	the	System	Agreement,	each	in	November	2015,	and	Entergy	Texas's	exit	from	the	System	Agreement	in	August	2016. See	Note	2	to	the	financial	statements	for	a	discussion	of	the	System	Agreement.

The	purchased	power	capacity	variance	is	primarily	due	to	decreased	expenses	due	to	the	termination	of	the	purchased	power	agreements between	Entergy	Louisiana	and	Entergy	Texas	in	August	2016,	as	well	as	capacity	cost	changes	for	ongoing	purchased	power	capacity	contracts.

The	transmission	revenue	variance	is	primarily	due	to	an	increase	in	Attachment	O	rates	charged	by	MISO	to	transmission	customers	and a	settlement	of	Attachment	O	rates	previously	billed	to	transmission	customers	by	MISO.

The	retail	electric	price	variance	is	primarily	due	to	the	implementation	of	the	transmission	cost	recovery	factor	rider,	as	approved	by	the PUCT	and	implemented	in	September	2016,	and	the	increase	in	the	distribution	cost	recovery	rider,	as	approved	by	the	PUCT	and	implemented	in January	2016.	This	increase	was	partially	offset	by	a	decrease	in	energy	efficiency	revenues.	See	Note	2	to	the	financial	statements	for	further discussion	of	the	transmission	cost	recovery	factor	rider	and	distribution	cost	recovery	factor	rider	filings.

The	net	wholesale	revenue	variance	is	primarily	due	to	lower	capacity	revenues	resulting	from	the	termination	of	the	purchased	power agreements	between	Entergy	Louisiana	and	Entergy	Texas	in	August	2016.

•an	increase	of	$5.1	million	in	transmission	and	distribution	expenses	primarily	due	to	higher	vegetation	maintenance	costs;

•an	increase	of	$4.3	million	in	fossil-fueled	generation	expenses	primarily	due	to	a	higher	scope	of	work	performed	during	plant	outages	in 2017	as	compared	to	2016;	and

•an	increase	of	$2.8	million	in	compensation	and	benefits	costs	primarily	due	to	higher	incentive-based	compensation	accruals	in	2017	as compared	to	2016.

The	increase	was	partially	offset	by	a	decrease	of	$4.5	million	due	to	the	absence	of	transmission	equalization	expenses,	as	allocated	under	the System	Agreement,	as	a	result	of	Entergy	Texas's	exit	from	the	System	Agreement	in	August	2016.

Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	ad	valorem	taxes	resulting	from	higher	assessments	and	a	true-up to	the	sales	and	use	tax	accruals	recorded	in	2016	resulting	from	an	audit	settlement.

•a	decrease	of	$11.2	million	in	fossil-fueled	generation	expenses	primarily	due	to	an	overall	lower	scope	of	work	performed	in	2016	as compared	to	2015;

•a	decrease	of	$7	million	in	transmission	expenses	primarily	due	to	lower	transmission	equalization	expenses,	as	allocated	under	the System	Agreement,	as	compared	to	the	same	period	in	2015	as	a	result	of	Entergy	Mississippi's	exit	from	the	System	Agreement	in November	2015	and	Entergy	Texas's	exit	from	the	System	Agreement	in	August	2016;

•a	decrease	of	$5.7	million	in	compensation	and	benefits	costs	primarily	due	to	a	decrease	in	net	periodic	pension	and	other	postretirement benefits	costs	as	a	result	of	an	increase	in	the	discount	rate	used	to	value	the	benefit	liabilities	and	a	refinement	in	the	approach	used	to estimate	the	service	cost	and	interest	cost	components	of	pension	and	other	postretirement	costs.	See	"Critical	Accounting	Estimates	- Qualified	Pension	and	Other	Postretirement	Benefits"	below	and	Note	11	to	the	financial	statements	for	further	discussion	of	pension and	other	postretirement	benefit	costs;

•the	write-off	in	the	third	quarter	2015	of	$4.3	million	of	rate	case	expenses	and	acquisition	costs	related	to	the	proposed	Union	Power Station	acquisition	upon	Entergy	Texas's	withdrawal	of	its	2015	rate	case	and	dismissal	of	its	certificate	of	convenience	and	necessity filing;	and

•a	decrease	of	$4.2	million	in	energy	efficiency	costs.

The	asset	write-off	variance	is	due	to	the	$23.5	million	($15.3	million	net-of-tax)	write-off	recorded	in	2015	of	the	receivable	associated with	the	Spindletop	gas	storage	facility.	See	Note	2	to	the	financial	statements	for	discussion	of	the	write-off.

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $6,181 | $2,182 | $30,441 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 301,396 | 306,601 | 284,268 |
| Investing\tactivities | (383,176) | (330,191) | (315,293) |
| Financing\tactivities | 191,112 | 27,589 | 2,766 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 109,332 | 3,999 | (28,259) |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $115,513 | $6,181 | $2,182 |

Net	cash	flow	provided	by	operating	activities	decreased	$5.2	million	in	2017	primarily	due	to	lower	net	income,	the	timing	of	recovery	of fuel	and	purchased	power	costs,	and	an	increase	of	$13.7	million	in	storm	spending	primarily	as	a	result	of	Hurricane	Harvey.	The	decrease	was partially	offset	by	income	tax	refunds	of	$21.1	million	in	2017	compared	to	income	tax	payments	of	$28.5	million	in	2016.	Entergy	Texas	had income	tax	refunds	in	2017	and	income	tax	payments	in	2016	in	accordance	with	an	intercompany	income	tax	allocation	agreement.		The	income tax	 refunds	 in	 2017	 primarily	 resulted	 from	 deductible	 temporary	 differences.	The	 income	 tax	 payments	 in	 2016	 resulted	 primarily	 from adjustments	associated	with	the	settlement	of	the	2010-2011	IRS	audit.	See	Note	3	to	the	financial	statements	for	a	discussion	of	the	income	tax audit.

Net	cash	flow	provided	by	operating	activities	increased	$22.3	million	in	2016	primarily	due	to	increased	net	income	and	a	decrease	of $31.8	million	in	income	tax	payments	in	2016.	Entergy	Texas	had	income	tax	payments	in	2016	and	2015	in	accordance	with	an	intercompany income	tax	allocation	agreement.		The	income	tax	payments	in	2016	resulted	primarily	from	adjustments	associated	with	the	settlement	of	the 2010-2011	IRS	audit.	The	income	tax	payments	in	2015	resulted	primarily	from	the	results	of	operations	and	the	reversal	of	taxable	temporary differences.	See	Note	3	to	the	financial	statements	for	a	discussion	of	the	income	tax	audit.	The	increase	was	partially	offset	by	an	increase	of	$5.2 million	in	interest	paid	in	2016	due	to	the	issuance	of	$125	million	of	2.55%	Series	first	mortgage	bonds	in	March	2016	and	the	timing	of collections	from	customers.

•an	increase	of	$34.9	million	in	distribution	construction	expenditures	primarily	due	to	increased	storm	spending	primarily	as	a	result	of Hurricane	Harvey	and	spending	on	digital	technology	improvements	within	the	customer	contact	centers;

•an	increase	of	$8.5	million	in	spending	on	advanced	metering	infrastructure.

The	increase	was	partially	offset	by	a	decrease	of	$51.7	million	in	transmission	construction	expenditures	primarily	due	to	a	lower	scope	of	work performed	in	2017	as	compared	to	2016.

Increases	in	Entergy	Texas's	receivable	from	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Texas's	receivable	from	the	money	pool increased	by	$44.2	million	in	2017	compared	to	increasing	by	$0.7	million	in	2016.	The	money	pool	is	an	inter-company	borrowing	arrangement designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

Net	cash	flow	used	in	investing	activities	increased	$14.9	million	in	2016	primarily	due	to	increases	of	$27.7	million	in	transmission construction	expenditures	and	$11.7	million	in	distribution	construction	expenditures	primarily	due	to	a	greater	scope	of	projects	in	2016	as compared	to	the	same	period	 in	2015.	The	increase	was	partially	offset	by	a	$21.4	million	decrease	in	fossil-fueled	generation	construction expenditures	primarily	due	to	a	decreased	scope	of	work	performed	during	plant	outages	in	2016	as	compared	to	the	same	period	in	2015.

•a	$115	million	capital	contribution	received	from	Entergy	Corporation in	December	2017 in	anticipation	of	upcoming	construction expenditures;

•the	issuance	of	$150	million	of	2.55%	Series	first	mortgage	bonds	in	December	2017	compared	to	the	issuance	of	$125	million	of	2.55% Series	first	mortgage	bonds	in	March	2016;	and

Decreases	in	Entergy	Texas's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Texas's	payable	to	the	money	pool	decreased by	$22.1	million	in	2016.

Net	cash	flow	provided	by	financing	activities	increased	$24.8	million	in	2016	primarily	due	to	the	retirement	of	$200	million	of	3.6% Series	first	mortgage	bonds	in	June	2015	and	the	issuance	of	$125	million	of	2.55%	Series	first	mortgage	bonds	in	March	2016,	partially	offset	by the	issuance	of	$250	million	of	5.15%	Series	first	mortgage	bonds	in	May	2015	and	money	pool	activity.

Decreases	in	Entergy	Texas's	payable	to	the	money	pool	are	a	use	of	cash	flow,	and	Entergy	Texas's	payable	to	the	money	pool	decreased by	$22.1	million	in	2016	compared	to	increasing	by	$22.1	million	in	2015.

Entergy	Texas's	capitalization	is	balanced	between	equity	and	debt,	as	shown	in	the	following	table.	The	decrease	in	the	debt	to	capital ratio	for	Entergy	Texas	is	primarily	due	to	the	capital	contribution	received	from	Entergy	Corporation	and	an	increase	in	retained	earnings.

|  | December	31,<br>2017 | December	31,<br>2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 55.7% | 58.5% |
| Effect\tof\texcluding\tthe\tsecuritization\tbonds | (6.3%) | (8.3%) |
| Debt\tto\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 49.4% | 50.2% |
| Effect\tof\tsubtracting\tcash | (2.5%) | (0.1%) |
| Net\tdebt\tto\tnet\tcapital,\texcluding\tsecuritization\tbonds\t(a) | 46.9% | 50.1% |

(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	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital	while also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.	To	the	extent	that	operating	cash	flows	are	in	excess of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to	maintain	the targeted	capital	structure.	To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	Entergy	Texas	may	issue incremental	 debt	 or	 reduce	 dividends,	 or	 both,	 to	 maintain	 its	 targeted	 capital	 structure.	In	 addition,	 Entergy	 Texas	 may	 receive	 equity contributions	to	maintain	the	targeted	capital	structure	for	certain	circumstances	such	as	large	transactions	that	would	materially	alter	the	capital structure	if	financed	entirely	with	debt	and	reduced	dividends.

Entergy	Texas	requires	capital	resources	for:

Following	are	the	amounts	of	Entergy	Texas's	planned	construction	and	other	capital	investments.

| Generation | $175 | $385 | $265 |
| :--- | :--- | :--- | :--- |
| Transmission | 195 | 240 | 165 |
| Distribution | 105 | 165 | 145 |
| Utility\tSupport | 55 | 30 | 30 |
| Total | $530 | $820 | $605 |

Following	are the	amounts	of	Entergy	Texas's	existing	debt	and lease	obligations	(includes	estimated interest	payments)	and	other purchase	obligations.

|  | 2018 | 2019-2020 | 2021-2022 | After	2022 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tMillions) |  |  |
| Long-term\tdebt\t(a) | $159 | $749 | $385 | $1,168 | $2,461 |
| Operating\tleases\t(b) | $4 | $5 | $2 | $2 | $13 |
| Purchase\tobligations\t(c) | $279 | $555 | $527 | $1,188 | $2,549 |

(b) Does	not	include	power	purchase	agreements	that	are	accounted	for	as	leases	that	are	included	in	purchase	obligations.

(c) 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	$10.9	million	to	its	qualified pension	plans	and	approximately	$3.2	million	to	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the	2018	required pension	contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018. 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	$15.8	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	such	as	the	Montgomery	County	Power	Station,	discussed	below;	transmission	projects	to	enhance	reliability,	reduce	congestion,	and enable	economic	growth;	distribution	spending	to	enhance	reliability	and	improve	service	to	customers,	including	investment	to	support	advanced metering;	system	improvements;	and	other	investments.	Estimated	capital	expenditures	are	subject	to	periodic	review	and	modification	and	may vary	based	on	the	ongoing	effects	of	regulatory	constraints	and	requirements,	environmental	compliance,	business	opportunities,	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	discussed	above	in	"Capital	Structure,"	Entergy	Texas	routinely	evaluates	its	ability	to	pay	dividends	to	Entergy	Corporation	from	its earnings.

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	indenture	and	other	agreements.	Entergy	Texas	has	sufficient	capacity	under	these	tests	to	meet	its	foreseeable capital	needs.

Entergy	Texas's	receivables	from	or	(payables	to)	the	money	pool	were	as	follows	as	of	December	31	for	each	of	the	following	years.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $44,903 | $681 | ($22,068) | $306 |

Entergy	Texas	has	a	credit	facility	in	the	amount	of	$150	million	scheduled	to	expire	in	August	2022.	The	credit	facility	allows	Entergy Texas	to	issue	letters	of	credit	against	$30	million	of	the	borrowing	capacity	of	the	facility.	As	of	December	31,	2017,	there	were	no	cash borrowings	and	$25.6	million	of	letters	of	credit	outstanding	under	the	credit	facility.	In	addition,	Entergy	Texas	is	a	party	to	an	uncommitted letter	of	credit	facility	as	a	means	to	post	collateral	to	support	its	obligations	to	MISO.	As	of	December	31,	2017,	a	$22.8	million	letter	of	credit was	outstanding	under	Entergy	Texas's	letter	of	credit	facility.	 See	Note	4	to	the	financial	statements	for	additional	discussion	of	the	credit facilities.

Entergy	Texas	obtained	authorizations	from	the	FERC	through	October	2019	for	short-term	borrowings,	not	to	exceed	an	aggregate amount	of	$200	million	at	any	time	outstanding,	and	long-term	borrowings	and	security	issuances.	See	Note	4	to	the	financial	statements	for further	discussion	of	Entergy	Texas's	short-term	borrowing	limits.

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	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	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	included	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	provided	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

Entergy	Texas,	Inc.	and	Subsidiaries Management's	Financial	Discussion	and	Analysis

million	because	the	PUCT	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	believed	that	it was	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	also	filed	motions	for	rehearing	of	the	PUCT's	order.		The	PUCT	subsequently	denied rehearing	of	substantive	issues.		Several	parties,	including	Entergy	Texas,	appealed	various	aspects	of	the	PUCT's	order	to	the	Travis	County District	Court.	A	hearing	was	held	in	July	2014.	In	October	2014	the	Travis	County	District	Court	issued	an	order	upholding	the	PUCT's	decision except	as	to	the	line-loss	factor	issue	referenced	above,	which	was	found	in	favor	of	Entergy	Texas.	In	November	2014,	Entergy	Texas	and	other parties,	including	the	PUCT,	appealed	the	Travis	County	District	Court	decision	to	the	Third	Court	of	Appeals.	Oral	argument	before	the	court panel	was	held	in	September	2015.	In	April	2016	the	Third	Court	of	Appeals	issued	its	opinion	affirming	the	District	Court's	decision	on	all points.	Entergy	Texas	petitioned	the	Texas	Supreme	Court	to	hear	its	appeal	of	the	Third	Court's	ruling.	 In	September	2017	the	Texas	Supreme Court	denied	the	petitions	for	review.	Entergy	Texas	filed	a	motion	for	rehearing	of	the	Texas	Supreme	Court's	denial	of	the	petition	for	review.	In January	2018	the	Texas	Supreme	Court	denied	Entergy	Texas's	motion	for	rehearing.

In	September	2015,	Entergy	Texas	filed	for	a	TCRF	rider	requesting	a	$13	million	increase,	incremental	to	base	rates.	Testimony	was	filed in	November	2015,	with	 the	PUCT	staff	and	other	parties	proposing	various	disallowances	 involving,	among	other	 things,	MISO	charges, vegetation	management	costs,	and	bad	debt	expenses	that	would	reduce	the	requested	increase	by	approximately	$2	million.	In	addition	to	those recommended	disallowances,	a	number	of	parties	recommended	that	Entergy	Texas's	request	be	reduced	by	an	additional	$3.4	million	to	account for	 load	 growth	 since	 base	 rates	 were	 last	 set.	A	 hearing	 on	 the	 merits	 was	 held	 in	 December	 2015.	In	 February	 2016	 a	 State	 Office	 of Administrative	Hearings	ALJ	issued	a	proposal	for	decision	recommending	that	the	PUCT	disallow	approximately	$2	million	from	Entergy Texas's	$13	million	request,	but	recommending	that	the	PUCT	not	accept	the	load	growth	offset.	In	June	2016	the	PUCT	indicated	that	it	would take	up	in	a	future	rulemaking	project	the	issue	of	whether	a	load	growth	adjustment	should	apply	to	a	TCRF.	In	July	2016	the	PUCT	issued	an order	generally	accepting	the	proposal	for	decision	but	declining	to	adjust	the	TCRF	baseline	in	two	instances	as	recommended	by	the	ALJ,	which resulted	 in	 a	 total	 annual	 allowance	 of	 approximately	$10.5	million.	The	PUCT	also	ordered	 its	staff	and	Entergy	Texas	 to	 track	all	spare autotransformer	transfers	going	forward	so	that	it	could	address	the	appropriate	accounting	treatment	and	prudence	of	such	transfers	in	Entergy Texas's	next	base	rate	case.	Entergy	Texas	implemented	the	TCRF	rider	beginning	with	September	2016	bills.

In	September	2016,	Entergy	Texas	filed	with	 the	PUCT	a	request	 to	amend	 its	TCRF	rider.	 The	proposed	amended	TCRF	rider	 is designed	to	collect	approximately	$29.5	million	annually	from	Entergy	Texas's	retail	customers.	This	amount	includes	the	approximately	$10.5 million	annually	that	Entergy	Texas	is	currently	authorized	to	collect	through	the	TCRF	rider,	as	discussed	above.	In	December	2016,	concurrent with	 the	2016	fuel	reconciliation	stipulation	and	settlement	agreement	discussed	above,	Entergy	Texas	and	 the	PUCT	reached	a	settlement agreeing	 to	 the	 amended	 TCRF	 annual	 revenue	 requirement	 of	$29.5	 million.	 As	 discussed	 below,	 the	 terms	 of	 the	 two	 settlements	 are interdependent.	The	PUCT	approved	the	settlement	and	issued	a	final	order	in	March	2017.	Entergy	Texas	implemented	the	amended	TCRF	rider beginning	with	bills	covering	usage	on	and	after	March	20,	2017.

In	August	2014,	Entergy	Texas	filed	an	application	seeking	PUCT	approval	to	implement	an	interim	fuel	refund	of	approximately $24.6 million	for	over-collected	fuel	costs	incurred	during	the	months	of	November	2012	through	April	2014.	This	refund	resulted	from	(i)	applying $48.6	million	in	bandwidth	remedy	payments	that	Entergy	Texas	received	in	May	2014	related	to	the	June	-	December	2005	period	to	Entergy Texas's	$8.7	million	under-recovered	fuel	balance	as	of	April	30,	2014	and	(ii)	netting	that	fuel	balance	against	the	 $15.3	million	bandwidth remedy	payment	that	Entergy	Texas	made	related	to	calendar	year	2013	production	costs.	Also	in	August	2014,	Entergy	Texas	filed	an	unopposed motion	for	interim	rates	to	implement	these	refunds	for	most	customers	over	a	two-month	period	commencing	with	September	2014.	The	PUCT issued	its	order	approving	the	interim	relief	in	August	2014	and	Entergy	Texas	completed	the	refunds	in	October	2014. 	Parties	intervened	in	this matter,	and	all	parties	agreed	that	the	proceeding	should	be	bifurcated	such	that	the	proposed	interim	refund	would	become	final	in	a	separate proceeding,	which	refund	was	approved	by	the	PUCT	in	March	2015.			In	July	2015	certain	parties	filed	briefs	in	the	open	proceeding	asserting that	Entergy	Texas	should	refund	to	retail	customers	an	additional	$10.9	million	in	bandwidth	remedy	payments	Entergy	Texas	received	related	to calendar	year	2006	production	costs.		In	October	2015	an	ALJ	issued	a	proposal	for	decision	recommending	that	the	additional	$10.9	million	in bandwidth	remedy	payments	be	refunded	to	retail	customers.	In	January	2016	the	PUCT	issued	its	order	affirming	the	ALJ's	recommendation,	and Entergy	Texas	filed	a	motion	for	rehearing	of	the	PUCT's	decision,	which	the	PUCT	denied.	In	March	2016,	Entergy	Texas	filed	a	complaint	in Federal	District	Court	for	the	Western	District	of	Texas	and	a	petition	in	the	Travis	County	(State)	District	Court	appealing	the	PUCT's	decision. The	pending	appeals	did	not	stay	the	PUCT's	decision.	In	April	2016,	Entergy	Texas	filed	with	the	PUCT	an	application	to	refund	to	customers approximately	$56.2	million.	The	refund	resulted	from	(i)	$41.8	million	of	fuel	cost	recovery	over-collections	through	February	2016,	(ii)	the $10.9	million	in	bandwidth	remedy	payments,	discussed	above,	that	Entergy	Texas	received	related	to	calendar	year	2006	production	costs,	and (iii)	$3.5	million	in	bandwidth	remedy	payments	that	Entergy	Texas	received	related	to	2006-2008	production	costs.	In	June	2016,	Entergy	Texas filed	an	unopposed	settlement	agreement	that	added	additional	over-recovered	fuel	costs	for	the	months	of	March	and	April	2016.	The	settlement resulted	 in	 a	$68	million	 refund.	The	ALJ	approved	the	refund	on	an	interim	basis	to	be	made	to	most	customers	over	a	four-month	period beginning	with	the	first	billing	cycle	of	July	2016.	In	July	2016	the	PUCT	issued	an	order	approving	the	interim	refund.	The	federal	appeal	of	the PUCT's	January	2016	decision	was	heard	in	December	2016,	and	the	Federal	District	Court	granted	Entergy	Texas's	requested	relief.	In	January 2017	the	PUCT	and	an	intervenor	filed	petitions	for	appeal	to	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	of	the	Federal	District	Court	ruling. Oral	argument	was	held	before	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit	in	February	2018,	and	a	decision	is	pending.	The	State	District Court	appeal	of	the	PUCT's	January	2016	decision	also	remains	pending.

In	July	2016,	Entergy	Texas	filed	an	application	to	reconcile	its	fuel	and	purchased	power	costs	for	the	period	April	1,	2013	through March	31,	2016.	Under	a	recent	PUCT	rule	change,	a	fuel	reconciliation	is	required	to	be	filed	at	least	once	every	three	years	and	outside	of	a	base rate	case	filing.	During	the	reconciliation	period,	Entergy	Texas	incurred	approximately	$1.77	billion	in	Texas	jurisdictional	eligible	fuel	and purchased	power	expenses,	net	of	certain	revenues	credited	to	such	expenses	and	other	adjustments.	Entergy	Texas	estimated	an	over-recovery balance	of

approximately	$19.3	 million,	 including	 interest,	 which	 Entergy	 Texas	 requested	 authority	 to	 carry	 over	 as	 the	 beginning	 balance	 for	 the subsequent	reconciliation	period	beginning	Apri1	2016.	Entergy	Texas	also	noted,	however,	that	the	estimated	$19.3	million	over	collection	was being	refunded	to	customers	as	a	portion	of	the	interim	fuel	refund	beginning	with	the	first	billing	cycle	of	July	2016,	discussed	above.	Entergy Texas	also	requested	a	prudence	finding	for	each	of	the	fuel-related	contracts	and	arrangements	entered	into	or	modified	during	the	reconciliation period	that	have	not	been	reviewed	by	the	PUCT	in	a	prior	proceeding.	In	December	2016,	Entergy	Texas	entered	into	a	stipulation	and	settlement agreement	resulting	in	a	$6	million	disallowance	not	associated	with	any	particular	issue	raised	and	a	refund	of	the	over-recovery	balance	of	 $21 million	as	of	November	30,	2016,	to	most	customers	beginning	April	2017	through	June	2017.	This	settlement	was	developed	concurrently	with the	stipulation	and	settlement	agreement	in	the	2016	transmission	cost	recovery	factor	rider	amendment	discussed	above,	and	the	terms	and conditions	in	both	settlements	are	interdependent.	The	fuel	reconciliation	settlement	was	approved	by	the	PUCT	in	March	2017	and	the	refunds were	made.

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'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,	with	reference	to	possible exceptions	noted	in	"Regulation	of	Entergy's	Business	-	Environmental	Regulation"	in	Part	I,	Item	1.	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.

Entergy	Texas's	 qualified	 pension	 and	 other	 postretirement	 reported	 costs,	 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	and	qualified	projected	benefit	obligation	cost	to	changes	in	certain actuarial	assumptions	(dollars	in	thousands).

| Discount	rate | (0.25%) | $701 | $11,425 |
| :--- | :--- | :--- | :--- |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $868 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $301 | $1,488 |

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

Total	qualified	pension	cost	for	Entergy	Texas	in	2017	was	$3.5	million.	 Entergy	Texas	anticipates	2018	qualified	pension	income	to	be $4.2	million.	In	2016,	Entergy	Texas	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified	pension	costs, which	had	the	effect	of	lowering	qualified	pension	costs	by	$3.6	million.	Entergy	Texas	contributed	$17	million	to	its	qualified	pension	plans	in 2017	and	estimates	2018	pension	contributions	will	be	approximately	$10.9	million,	although	the	2018	required	pension	contributions	will	be known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	postretirement	health	care	and	life	insurance	benefit	income	for	Entergy	Texas	in	2017	was	$1.8	million.	Entergy	Texas	expects 2018	postretirement	health	care	and	life	insurance	benefit	income	to	approximate	$6.2	million.	In	2016,	Entergy	Texas	refined	its	approach	to estimating	 the	 service	 cost	 and	 interest	 cost	 components	 of	 other	 postretirement	 costs,	 which	 had	 the	 effect	 of	 lowering	 qualified	 other postretirement	 costs	 by	 $1.1	 million.	Entergy	Texas	 contributed	 $3.1	 million	 to	 its	 other	 postretirement	 plans	 in	 2017	 and	 estimates	 2018 contributions	will	be	approximately	$3.2	million.

# To	the	shareholder	and	Board	of	Directors	of

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Entergy	Texas,	Inc.	and	Subsidiaries	(the	"Company")	as	of	December	31, 2017	and	2016,	the	related	consolidated	statements	of	income,	cash	flows,	and	changes	in	common	equity	(pages	414	through	418	and	applicable items	in	pages	55	through	230),	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	and	the	related	notes	(collectively	referred	to as	the	"financial	statements").	In	our	opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company as	of	December	31,	2017	and	2016,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31, 2017,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $1,544,893 | $1,615,619 | $1,707,203 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 225,517 | 271,968 | 277,810 |
| Purchased\tpower | 610,279 | 616,597 | 709,947 |
| Other\toperation\tand\tmaintenance | 230,616 | 220,566 | 254,731 |
| Asset\twrite-off | — | — | 23,472 |
| Taxes\tother\tthan\tincome\ttaxes | 79,254 | 70,973 | 72,945 |
| Depreciation\tand\tamortization | 117,520 | 107,026 | 102,410 |
| Other\tregulatory\tcharges\t-\tnet | 82,328 | 82,879 | 82,243 |
| TOTAL | 1,345,514 | 1,370,009 | 1,523,558 |
| OPERATING\tINCOME | 199,379 | 245,610 | 183,645 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 6,722 | 7,617 | 5,678 |
| Interest\tand\tinvestment\tincome | 981 | 987 | 684 |
| Miscellaneous\t-\tnet | 193 | (746) | (798) |
| TOTAL | 7,896 | 7,858 | 5,564 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 86,719 | 87,776 | 86,024 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (4,098) | (4,943) | (3,690) |
| TOTAL | 82,621 | 82,833 | 82,334 |
| INCOME\tBEFORE\tINCOME\tTAXES | 124,654 | 170,635 | 106,875 |
| Income\ttaxes | 48,481 | 63,097 | 37,250 |
| NET\tINCOME | $76,173 | $107,538 | $69,625 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $76,173 | $107,538 | $69,625 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation\tand\tamortization | 117,520 | 107,026 | 102,410 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 42,119 | 20,794 | (23,292) |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | (15,934) | (9,300) | 21,443 |
| Fuel\tinventory | (25,054) | 9,765 | 2,960 |
| Accounts\tpayable | 32,842 | (22,462) | (16,913) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 30,308 | 10,018 | 3,484 |
| Interest\taccrued | (421) | (3,229) | (551) |
| Deferred\tfuel\tcosts | 12,758 | 29,419 | 36,985 |
| Other\tworking\tcapital\taccounts | (7,852) | (3,354) | 2,468 |
| Provisions\tfor\testimated\tlosses | 2,531 | (1,735) | (2,899) |
| Other\tregulatory\tassets | 184,574 | 74,389 | 125,133 |
| Other\tregulatory\tliabilities | 410,968 | 2,106 | 1,271 |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (520,547) | — | — |
| Pension\tand\tother\tpostretirement\tliabilities | (49,445) | (10,204) | (33,474) |
| Other\tassets\tand\tliabilities | 10,856 | (4,170) | (4,382) |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 301,396 | 306,601 | 284,268 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (348,027) | (337,963) | (320,408) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 6,874 | 7,743 | 5,751 |
| Insurance\tproceeds | 2,431 | — | — |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | (44,222) | (681) | 306 |
| Changes\tin\tsecuritization\taccount | (232) | 710 | (942) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities | (383,176) | (330,191) | (315,293) |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 148,277 | 123,502 | 246,607 |
| Retirement\tof\tlong-term\tdebt | (71,683) | (68,593) | (265,734) |
| Capital\tcontributions\tfrom\tparent | 115,000 | — | — |
| Change\tin\tmoney\tpool\tpayable\t-\tnet | — | (22,068) | 22,068 |
| Other | (482) | (5,252) | (175) |
| Net\tcash\tflow\tprovided\tby\tfinancing\tactivities | 191,112 | 27,589 | 2,766 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 109,332 | 3,999 | (28,259) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 6,181 | 2,182 | 30,441 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $115,513 | $6,181 | $2,182 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $84,556 | $88,489 | $83,290 |
| Income\ttaxes | ($21,107) | $28,523 | $60,359 |

| Cash | $32 | $1,216 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 115,481 | 4,965 |
| Total\tcash\tand\tcash\tequivalents | 115,513 | 6,181 |
| Securitization\trecovery\ttrust\taccount | 37,683 | 37,451 |
| Accounts\treceivable: |  |  |
| Customer | 74,382 | 71,803 |
| Allowance\tfor\tdoubtful\taccounts | (463) | (828) |
| Associated\tcompanies | 90,629 | 39,447 |
| Other | 9,831 | 14,756 |
| Accrued\tunbilled\trevenues | 50,682 | 39,727 |
| Total\taccounts\treceivable | 225,061 | 164,905 |
| Fuel\tinventory\t-\tat\taverage\tcost | 42,731 | 37,177 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 38,605 | 36,631 |
| Prepayments\tand\tother | 19,710 | 18,599 |
| TOTAL | 479,303 | 300,944 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Investments\tin\taffiliates\t-\tat\tequity | 457 | 600 |
| Non-utility\tproperty\t-\tat\tcost\t(less\taccumulated\tdepreciation) | 376 | 376 |
| Other | 19,235 | 18,801 |
| TOTAL | 20,068 | 19,777 |
| UTILITY\tPLANT |  |  |
| Electric | 4,569,295 | 4,274,069 |
| Construction\twork\tin\tprogress | 102,088 | 111,227 |
| TOTAL\tUTILITY\tPLANT | 4,671,383 | 4,385,296 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 1,579,387 | 1,526,057 |
| UTILITY\tPLANT\t-\tNET | 3,091,996 | 2,859,239 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 105,816 |
| \t\tOther\tregulatory\tassets\t(includes\tsecuritization\tproperty\tof\t$313,123\tas\tof\tDecember\t31,\t2017\tand\t$384,609\tas\tof\nDecember\t31,\t2016) | 661,398 | 740,156 |
| Other | 26,973 | 7,149 |
| TOTAL | 688,371 | 853,121 |
| TOTAL\tASSETS | $4,279,738 | $4,033,081 |

| Associated	companies | $59,347 | $47,867 |
| :--- | :--- | :--- |
| Other | 126,095 | 77,342 |
| Customer\tdeposits | 40,925 | 44,419 |
| Taxes\taccrued | 45,659 | 15,351 |
| Interest\taccrued | 25,556 | 25,977 |
| Deferred\tfuel\tcosts | 67,301 | 54,543 |
| Other | 8,132 | 9,388 |
| TOTAL | 373,015 | 274,887 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 544,642 | 1,027,647 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 11,983 | 12,934 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 412,620 | — |
| Other\tregulatory\tliabilities | 6,850 | 8,502 |
| Asset\tretirement\tcost\tliabilities | 6,835 | 6,470 |
| Accumulated\tprovisions | 10,115 | 7,584 |
| Pension\tand\tother\tpostretirement\tliabilities | 17,853 | 67,313 |
| Long-term\tdebt\t(includes\tsecuritization\tbonds\tof\t$358,104\tas\tof\tDecember\t31,\t2017\tand\t$429,043\tas\tof\tDecember\t31,\n2016) | 1,587,150 | 1,508,407 |
| Other | 48,508 | 50,343 |
| TOTAL | 2,646,556 | 2,689,200 |
| Commitments\tand\tContingencies |  |  |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t200,000,000\tshares;\tissued\tand\toutstanding\t46,525,000\tshares\tin\t2017\tand\n2016 |  |  |
|  | 49,452 | 49,452 |
| Paid-in\tcapital | 596,994 | 481,994 |
| Retained\tearnings | 613,721 | 537,548 |
| TOTAL | 1,260,167 | 1,068,994 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $4,279,738 | $4,033,081 |

|  | Common	Stock | Paid-in	Capital | Retained	Earnings | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2014 | $49,452 | $481,994 | $360,385 | $891,831 |
| Net\tincome | — | — | 69,625 | 69,625 |
| Balance\tat\tDecember\t31,\t2015 | $49,452 | $481,994 | $430,010 | $961,456 |
| Net\tincome | — | — | 107,538 | 107,538 |
| Balance\tat\tDecember\t31,\t2016 | $49,452 | $481,994 | $537,548 | $1,068,994 |
| Net\tincome | — | — | 76,173 | 76,173 |
| Capital\tcontributions\tfrom\tparent | — | 115,000 | — | 115,000 |
| Balance\tat\tDecember\t31,\t2017 | $49,452 | $596,994 | $613,721 | $1,260,167 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tThousands) |  |  |
| Operating\trevenues | $1,544,893 | $1,615,619 | $1,707,203 | $1,851,982 | $1,728,799 |
| Net\tincome | $76,173 | $107,538 | $69,625 | $74,804 | $57,881 |
| Total\tassets | $4,279,738 | $4,033,081 | $3,898,582 | $3,897,989 | $3,909,470 |
| Long-term\tobligations\t(a) | $1,587,150 | $1,508,407 | $1,451,967 | $1,268,835 | $1,544,549 |
| (a)\tIncludes\tlong-term\tdebt\t(excluding\tcurrently\tmaturing\tdebt). |  |  |  |  |  |
|  | 2017 | 2016 | 2015 | 2014 | 2013 |
|  |  |  | (Dollars\tIn\tMillions) |  |  |
| Electric\tOperating\tRevenues: |  |  |  |  |  |
| Residential | $636 | $613 | $633 | $654 | $596 |
| Commercial | 378 | 356 | 369 | 384 | 327 |
| Industrial | 384 | 365 | 372 | 422 | 325 |
| Governmental | 25 | 24 | 25 | 26 | 24 |
| Total\tretail | 1,423 | 1,358 | 1,399 | 1,486 | 1,272 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 58 | 178 | 259 | 316 | 369 |
| Non-associated\tcompanies | 22 | 40 | 14 | 23 | 47 |
| Other | 42 | 40 | 35 | 27 | 41 |
| Total | $1,545 | $1,616 | $1,707 | $1,852 | $1,729 |
| Billed\tElectric\tEnergy\tSales\t(GWh): |  |  |  |  |  |
| Residential | 5,716 | 5,836 | 5,889 | 5,810 | 5,726 |
| Commercial | 4,548 | 4,570 | 4,548 | 4,471 | 4,402 |
| Industrial | 7,521 | 7,493 | 7,036 | 7,140 | 6,404 |
| Governmental | 273 | 283 | 276 | 277 | 282 |
| Total\tretail | 18,058 | 18,182 | 17,749 | 17,698 | 16,814 |
| Sales\tfor\tresale: |  |  |  |  |  |
| Associated\tcompanies | 1,534 | 4,625 | 5,853 | 4,763 | 6,287 |
| Non-associated\tcompanies | 729 | 1,086 | 254 | 200 | 712 |
| Total | 20,321 | 23,893 | 23,856 | 22,661 | 23,813 |

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	decreased	$18.1	million	primarily	due	to	provisions	against	revenue	recorded	in	2017	in	connection	with	the	complaint against	System	Energy's	return	on	equity	and	a	higher	effective	income	tax	rate	in	2017.	See	"Federal	Regulation	-	Complaint	Against	System Energy"	below	for	further	discussion	of	the	complaint	against	System	Energy.

Net	income	decreased	$14.6	million	primarily	due	to	a	higher	effective	income	tax	rate	in	2016.

The	effective	income	tax	rates	for	2017,	2016,	and	2015	were	47.1%,	42.3%,	and	32.3%,	respectively.	The	difference	in	the	effective income	tax	rate	of	47.1%	for	2017	versus	the	statutory	rate	of	35%	for	2017	was	primarily	due	to	certain	book	and	tax	differences	related	to	utility plant	items	and	state	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.

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tThousands) |  |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | $245,863 | $230,661 | $223,179 |
| Net\tcash\tprovided\tby\t(used\tin): |  |  |  |
| Operating\tactivities | 371,278 | 341,939 | 502,536 |
| Investing\tactivities | (174,250) | (232,602) | (137,562) |
| Financing\tactivities | (155,704) | (94,135) | (357,492) |
| Net\tincrease\tin\tcash\tand\tcash\tequivalents | 41,324 | 15,202 | 7,482 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $287,187 | $245,863 | $230,661 |

•a	decrease	in	spending	of	$35.7	million	on	nuclear	refueling	outages	in	2017	as	compared	to	the	prior	year;

•the	timing	of	collection	of	receivables;	and

•proceeds	of	$28.4	million	received	in	August	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel	storage	costs	that were	previously	expensed.	See	Note	8	to	the	financial	statements	for	a	discussion	of	the	spent	nuclear	fuel	litigation;	and •a	decrease	of	$21.3	million	in	income	tax	refunds	in	2017.	System	Energy	received	income	tax	refunds	in	2017	and	2016	in	accordance with	an	intercompany	income	tax	allocation	agreement.	The	income	tax	refunds	in	2017	and	2016	resulted	primarily	from	the	adoption	of a	new	accounting	method	for	income	tax	purposes	in	which	System	Energy	will	treat	its	nuclear	decommissioning	costs	as	production costs	of	electricity	includable	in	cost	of	goods	sold.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the	adoption	of	the	new accounting	method.

Net	cash	flow	provided	by	operating	activities	decreased	$160.6	million	in	2016	primarily	due	to:

•a	decrease	of	$90.5	million	in	income	tax	refunds	in	2016.	System	Energy	received	income	tax	refunds	in	2016	and	2015	in	accordance with	an	intercompany	income	tax	allocation	agreement.	The	income	tax	refunds	in	2016	and	2015	resulted	primarily	from	the	adoption	of a	new	accounting	method	for	income	tax	purposes	in	which	System	Energy	will	treat	its	nuclear	decommissioning	costs	as	production costs	of	electricity	includable	in	cost	of	goods	sold.	See	Note	3	to	the	financial	statements	for	further	discussion	of	the	adoption	of	the	new accounting	method;	and

•an	increase	in	spending	of	$35.1	million	on	nuclear	refueling	outages	in	2016	as	compared	to	2015.

The	decrease	was	partially	offset	by	proceeds	of	$28.4	million	received	in	August	2016	from	the	DOE	resulting	from	litigation	regarding	spent nuclear	fuel	storage	costs	that	were	previously	expensed.	See	Note	8	to	the	financial	statements	for	a	discussion	of	the	spent	nuclear	fuel	litigation.

Net	cash	flow	used	in	investing	activities	decreased	$58.4	million	in	2017	primarily	due	to	a	decrease	of	$159.4	million	as	a	result	of 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.	The	decrease	was	partially	offset	by money	pool	activity	and	proceeds	of	$15.8	million	received	in	August	2016	from	the	DOE	resulting	from	litigation	regarding	spent	nuclear	fuel storage	costs	that	were	previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the	spent	nuclear	fuel	litigation.

Increases	in	System	Energy's	receivable	from	the	money	pool	are	a	use	of	cash	flow	and	System	Energy's	receivable	from	the	money	pool increased	by	$77.9	million	in	2017	compared	to	decreasing	by	$6.1	million	in	2016.		The	money	pool	is	an	inter-company	borrowing	arrangement designed	to	reduce	the	Utility	subsidiaries'	need	for	external	short-term	borrowings.

•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;	and •an	increase	in	nuclear	construction	expenditures	primarily	as	a	result	of	a	higher	scope	of	work	performed	in	2016	on	Grand	Gulf	outage projects,	partially	offset	by	decreased	spending	in	2016	on	compliance	with	NRC	post-Fukushima	requirements.

The	increase	was	partially	offset	by	money	pool	activity	and	proceeds	of	$15.8	million	received	in	August	2016	from	the	DOE	resulting	from litigation	regarding	spent	nuclear	fuel	storage	costs	that	were	previously	capitalized.	See	Note	8	to	the	financial	statements	for	discussion	of	the spent	nuclear	fuel	litigation.

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	by	$6.1	million	in	2016	compared	to	increasing	by	$37.6	million	in	2015.

Net	cash	flow	used	in	financing	activities	increased	$61.6	million	in	2017	primarily	due	to:

•net	repayments	of	short-term	borrowings	of	$49.1	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2017	as compared	to	net	short-term	borrowings	of	$66.9	million	on	the	nuclear	fuel	variable	interest	entity's	credit	facility	in	2016;	and •the	payment	in	February	2017,	at	maturity,	of	$50	million	of	the	System	Energy	nuclear	fuel	company	variable	interest	entity's	4.02% Series	H	notes.

•net	long-term	borrowings	of	$50	million	in	2017	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility;

•a	decrease	of	$32.4	million	in	common	stock	dividends	and	distributions	in	2017	in	order	to	maintain	System	Energy's	targeted	capital structure;	and

•the	repayment	in	May	2016	of	$22	million	of	5.875%	pollution	control	revenue	bonds	due	2022	issued	on	behalf	of	System	Energy.

Net	cash	flow	used	in	financing	activities	decreased	$263.4	million	in	2016	primarily	due	to:

•net	borrowings	of	$66.9	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2016	compared	to	net	repayments of	$20.4	million	on	the	nuclear	fuel	company	variable	interest	entity's	credit	facility	in	2015;

•a	decrease	of	$61.8	million	in	common	stock	dividends	and	distributions	as	a	result	of	lower	operating	cash	flows	and	higher	nuclear	fuel purchases	in	2016	as	compared	to	the	prior	year;

•the	redemption	in	April	2015,	at	maturity,	of	$60	million	of	System	Energy	nuclear	fuel	company	variable	interest	entity's	5.33%	Series	G notes;	and

The	decrease	was	partially	offset	by	the	repayment	in	May	2016	of	$22	million	of	5.875%	pollution	control	revenue	bonds	due	2022	issued	on behalf	of	System	Energy.

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	is	primarily	due	to	the	payment	in	February	2017,	at	maturity,	of	$50	million	of	the	System	Energy	nuclear	fuel	company variable	interest	entity's	4.02%	Series	H	notes.

|  | December	31,<br>2017 | December	31,<br>2016 |
| :--- | :--- | :--- |
| Debt\tto\tcapital | 44.5% | 45.5% |
| Effect\tof\tsubtracting\tcash | (16.0%) | (12.0%) |
| Net\tdebt\tto\tnet\tcapital | 28.5% | 33.5% |

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	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	seeks	to	optimize	its	capital	structure	in	accordance	with	its	regulatory	requirements	and	to	control	its	cost	of	capital	while also	maintaining	equity	capitalization	at	a	level	consistent	with	investment-grade	debt	ratings.	To	the	extent	that	operating	cash	flows	are	in	excess of	planned	investments,	cash	may	be	used	to	reduce	outstanding	debt	or	may	be	paid	as	a	dividend,	or	both,	in	appropriate	amounts	to	maintain	the targeted	capital	structure.		To	the	extent	that	operating	cash	flows	are	insufficient	to	support	planned	investments,	System	Energy	may	issue incremental	debt	or	reduce	dividends,	or	both,	to	maintain	its	targeted	capital	structure.

System	Energy	requires	capital	resources	for:

•construction	and	other	capital	investments; •debt	maturities	or	retirements;

System	Energy	Resources,	Inc. Management's	Financial	Discussion	and	Analysis

•working	capital	purposes,	including	the	financing	of	fuel	costs;	and •dividend,	distribution,	and	interest	payments.

Following	are	the	amounts	of	System	Energy's	planned	construction	and	other	capital	investments.

| Generation | $180 | $130 | $150 |
| :--- | :--- | :--- | :--- |
| Utility\tSupport | 15 | 15 | 10 |
| Total | $195 | $145 | $160 |

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	$13.8	million	to	its	qualified	pension plans	and	approximately	$16	thousand	to	other	postretirement	health	care	and	life	insurance	plans	in	2018,	although	the	2018	required	pension contributions	will	be	known	with	more	certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.	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	$433	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	Grand	Gulf	investments and	initiatives.

As	a	wholly-owned	subsidiary,	System	Energy	dividends	its	earnings	to	Entergy	Corporation	at	a	percentage	determined	monthly.

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.

| 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- |
|  | (In\tThousands) | (In\tThousands) |  |
| $111,667 | $33,809 | $39,926 | $2,373 |

The	System	Energy	nuclear	fuel	company	variable	interest	entity	has	a	credit	facility	in	the	amount	of	$120	million	scheduled	to	expire	in May	2019.	As	of	December	31,	2017,	$17.8	million	in	letters	of	credit	to	support	a	like	amount	of	commercial	paper	issued	and	$50	million	in loans	 were	 outstanding	 under	 the	 System	 Energy	 nuclear	 fuel	 company	 variable	 interest	 entity	 credit	 facility.	See	 Note	 4	 to	 the	 financial statements	for	additional	discussion	of	the	variable	interest	entity	credit	facility.

System	Energy	obtained	authorizations	from	the	FERC	through	October	2019	for	the	following:

•short-term	borrowings	not	to	exceed	an	aggregate	amount	of	$200	million	at	any	time	outstanding;

•long-term	borrowings	by	its	nuclear	fuel	company	variable	interest	entity.

See	Note	4	to	the	financial	statements	for	further	discussion	of	System	Energy's	short-term	borrowing	limits.

In	January	2017	the	APSC	and	MPSC	filed	a	complaint	with	the	FERC	against	System	Energy.	The	complaint	seeks	a	reduction	in	the return	on	equity	component	of	the	Unit	Power	Sales	Agreement	pursuant	to	which	System	Energy	sells	its	Grand	Gulf	capacity	and	energy	to Entergy	Arkansas,	 Entergy	 Louisiana,	 Entergy	 Mississippi,	 and	 Entergy	 New	 Orleans.	Entergy	Arkansas	also	sells	some	of	 its	Grand	Gulf capacity	and	energy	to	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy	New	Orleans	under	separate	agreements.	The	current	return	on	equity under	the	Unit	Power	Sales	Agreement	is	10.94%.	The	complaint	alleges	that	the	return	on	equity	is	unjust	and	unreasonable	because	current capital	market	and	other	considerations	indicate	that	it	is	excessive.	The	complaint	requests	the	FERC	to	institute	proceedings	to	investigate	the return	on	equity	and	establish	a	lower	return	on	equity,	and	also	requests	that	the	FERC	establish	January	23,	2017	as	a	refund	effective	date.	The complaint	includes	return	on	equity	analysis	that	purports	to	establish	that	the	range	of	reasonable	return	on	equity	for	System	Energy	is	between 8.37%	and	8.67%.	System	Energy	answered	the	complaint	in	February	2017	and	disputes	that	a	return	on	equity	of	8.37%	to	8.67%	is	just	and reasonable.	The	LPSC	and	the	City	Council	intervened	in	the	proceeding	expressing	support	for	the	complaint.	System	Energy	is	recording	a provision	against	revenue	for	the	potential	outcome	of	this	proceeding.	In	September	2017	the	FERC	established	a	refund	effective	date	of	January 23,	2017,	consolidated	the	return	on	equity	complaint	with	the	proceeding	described	in	Unit	Power	Sales	Agreement	below,	and	directed	the parties	to	engage	in	settlement

proceedings	before	an	ALJ.	If	the	parties	fail	to	come	to	an	agreement	during	settlement	proceedings,	a	prehearing	conference	will	be	held	to establish	a	procedural	schedule	for	hearing	proceedings.

System	Energy	owns	and,	through	an	affiliate,	operates	Grand	Gulf.		System	Energy	is,	therefore,	subject	to	the	risks	related	to	owning and	operating	a	nuclear	plant.		These	include	risks	related	to:	the	use,	storage,	and	handling	and	disposal	of	high-level	and	low-level	radioactive materials;	the	substantial	financial	requirements,	both	for	capital	investments	and	operational	needs,	to	position	Entergy's	nuclear	fleet	to	meet	its operational	goals,	including	the	financial	requirements	to	address	emerging	issues	like	stress	corrosion	cracking	of	certain	materials	within	the plant	 systems	 and	 the	 Fukushima	 event;	 regulatory	 requirements	 and	 potential	 future	 regulatory	 changes,	 including	 changes	 affecting	 the regulations	governing	nuclear	plant	ownership,	operations,	license	renewal	and	amendments,	and	decommissioning;	the	performance	and	capacity factors	of	these	nuclear	plants;	the	availability	of	interim	or	permanent	sites	for	the	disposal	of	spent	nuclear	fuel	and	nuclear	waste,	including	the fees	charged	for	such	disposal;	the	sufficiency	of	nuclear	decommissioning	trust	fund	assets	and	earnings	to	complete	decommissioning	of	each site	when	required;	and	limitations	on	the	amounts	and	types	of	insurance	commercially	available	for	losses	in	connection	with	nuclear	plant operations	and	catastrophic	events	such	as	a	nuclear	accident.	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.		In	December	2016,	the	NRC granted	the	extension	of	Grand	Gulf's	operating	license	to	2044.

# Grand	Gulf	Outage	and	NRC	review

Based	on	the	plant's	performance	indicators,	in	November	2016	the	NRC	placed	Grand	Gulf	in	the	"regulatory	response	column,"	or Column	 2,	 of	 its	 Reactor	 Oversight	 Process	Action	 Matrix.	Entergy	 is	 implementing	a	plan	 to	restore	Grand	Gulf	 to	Column	1,	 including addressing	the	issues	related	to	the	three	very	low	safety	significance	non-cited	violations	identified	in	the	NRC's	report	on	the	results	of	its October	2016	special	inspection.	Depending	on	the	success	of	implementing	that	plan	and	the	plant's	performance	indicators,	there	is	risk	that	the NRC	could	move	Grand	Gulf	into	the	"degraded	cornerstone	column,"	or	Column	3,	of	the	NRC's	Reactor	Oversight	Process	Action	Matrix.

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,	with	reference	to	possible exceptions	noted	in	"Regulation	of	Entergy's	Business	-	Environmental	Regulation"	in	Part	I,	Item	1.		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	second	quarter	2017,	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	$35.9	million	reduction	in	its	decommissioning	cost	liability,	along	with a	corresponding	reduction	in	the	related	asset	retirement	cost	asset	that	will	be	depreciated	over	the	remaining	life	of	the	unit.

System	Energy's	qualified	pension	and	other	postretirement	reported	costs,	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	assumptions	(dollars	in	thousands). |  |  |  |
| :--- | :--- | :--- | :--- |
| Actuarial\tAssumption | \t Change\tin\tAssumption | Impact\ton\t2018\tQualified\tPension\nCost | Impact\ton\t2017\tProjected\nQualified\tBenefit\tObligation |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $820 | $11,922 |
| Rate\tof\treturn\ton\tplan\tassets | (0.25%) | $664 | $— |
| Rate\tof\tincrease\tin\tcompensation | 0.25% | $329 | $1,473 |

| Actuarial	Assumption | Change	in<br>Assumption | Impact	on	2018	Postretirement<br>Benefit	Cost | Impact	on	2017	Accumulated<br>Postretirement	Benefit	Obligation |
| :--- | :--- | :--- | :--- |
|  |  | Increase/(Decrease) |  |
| Discount\trate | (0.25%) | $154 | $2,042 |
| Health\tcare\tcost\ttrend | 0.25% | $239 | $1,704 |

Total	qualified	pension	cost	for	System	Energy	in	2017	was	$11.7	million.		System	Energy	anticipates	2018	qualified	pension	cost	to	be $14.9	million.		In	2016,	System	Energy	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	qualified	pension	costs, which	had	the	effect	of	lowering	qualified	pension	costs	by	$2.8	million.	System	Energy	contributed	$18.2	million	to	its	pension	plans	in	2017	and estimates	2018	pension	contributions	will	approximate	$13.8	million,	although	the	2018	required	pension	contributions	will	be	known	with	more certainty	when	the	January	1,	2018	valuations	are	completed,	which	is	expected	by	April	1,	2018.

Total	postretirement	health	care	and	life	insurance	benefit	cost	for	System	Energy	in	2017	was	$692	thousand.	System	Energy	expects 2018	postretirement	health	care	and	life	insurance	benefit	income	to	approximate	$490	thousand.

In	2016,	System	Energy	refined	its	approach	to	estimating	the	service	cost	and	interest	cost	components	of	other	postretirement	costs,	which	had the	effect	of	lowering	qualified	other	postretirement	costs	by	$555	thousand.	System	Energy	contributed	$570	thousand	to	its	other	postretirement plans	in	2017	and	expects	2018	contributions	to	approximate	$16	thousand.

We	have	audited	the	accompanying	balance	sheets	of	System	Energy	Resources,	Inc.	(the	"Company")	as	of	December	31,	2017	and	2016,	the related	statements	of	income,	cash	flows,	and	changes	in	common	equity	(pages	431	through	436	and	applicable	items	in	pages	55	through	230), for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	and	the	related	notes	(collectively	referred	to	as	the	"financial	statements").	In our	opinion,	the	financial	statements	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company	as	of	December	31,	2017	and 2016,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.

|  |  | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tREVENUES |  |  |  |
| Electric | $633,458 | $548,291 | $632,405 |
| OPERATING\tEXPENSES |  |  |  |
| Operation\tand\tMaintenance: |  |  |  |
| Fuel,\tfuel-related\texpenses,\tand\tgas\tpurchased\tfor\tresale | 71,700 | 27,416 | 89,598 |
| Nuclear\trefueling\toutage\texpenses | 17,968 | 19,512 | 21,654 |
| Other\toperation\tand\tmaintenance | 213,534 | 153,064 | 156,552 |
| Decommissioning | 43,347 | 50,797 | 47,993 |
| Taxes\tother\tthan\tincome\ttaxes | 26,180 | 25,195 | 27,281 |
| Depreciation\tand\tamortization | 137,767 | 136,195 | 143,133 |
| Other\tregulatory\tcredits\t-\tnet | (37,831) | (45,041) | (39,434) |
| TOTAL | 472,665 | 367,138 | 446,777 |
| OPERATING\tINCOME | 160,793 | 181,153 | 185,628 |
| OTHER\tINCOME |  |  |  |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 6,345 | 7,944 | 8,494 |
| Interest\tand\tinvestment\tincome | 17,538 | 14,793 | 14,437 |
| Miscellaneous\t-\tnet | (521) | (556) | (876) |
| TOTAL | 23,362 | 22,181 | 22,055 |
| INTEREST\tEXPENSE |  |  |  |
| Interest\texpense | 37,141 | 37,529 | 45,532 |
| Allowance\tfor\tborrowed\tfunds\tused\tduring\tconstruction | (1,551) | (2,000) | (2,244) |
| TOTAL | 35,590 | 35,529 | 43,288 |
| INCOME\tBEFORE\tINCOME\tTAXES | 148,565 | 167,805 | 164,395 |
| Income\ttaxes | 69,969 | 71,061 | 53,077 |
| NET\tINCOME | $78,596 | $96,744 | $111,318 |

|  | For	the	Years	Ended	December	31, | For	the	Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2017 | 2016 | 2015 |
|  |  | (In\tThousands) |  |
| OPERATING\tACTIVITIES |  |  |  |
| Net\tincome | $78,596 | $96,744 | $111,318 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tflow\tprovided\tby\toperating\tactivities: |  |  |  |
| Depreciation,\tamortization,\tand\tdecommissioning,\tincluding\tnuclear\tfuel\tamortization | 240,962 | 224,879 | 270,514 |
| Deferred\tincome\ttaxes,\tinvestment\ttax\tcredits,\tand\tnon-current\ttaxes\taccrued | 7,827 | 99,531 | 200,797 |
| Changes\tin\tassets\tand\tliabilities: |  |  |  |
| Receivables | 9,210 | (15,846) | 5,879 |
| Accounts\tpayable | 15,969 | 2,720 | (352) |
| Prepaid\ttaxes\tand\ttaxes\taccrued | 62,466 | (6,555) | (32,594) |
| Interest\taccrued | (660) | (134) | (19,013) |
| Other\tworking\tcapital\taccounts | 12,083 | (15,470) | 13,576 |
| Other\tregulatory\tassets | 60,012 | (58,279) | (4,565) |
| Other\tregulatory\tliabilities | 331,251 | 33,438 | (33,686) |
| Deferred\ttax\trate\tchange\trecognized\tas\tregulatory\tliability/asset | (325,707) | — | — |
| Pension\tand\tother\tpostretirement\tliabilities | 4,024 | 5,586 | (16,888) |
| Other\tassets\tand\tliabilities | (124,755) | (24,675) | 7,550 |
| Net\tcash\tflow\tprovided\tby\toperating\tactivities | 371,278 | 341,939 | 502,536 |
| INVESTING\tACTIVITIES |  |  |  |
| Construction\texpenditures | (91,705) | (88,037) | (70,358) |
| Allowance\tfor\tequity\tfunds\tused\tduring\tconstruction | 6,345 | 7,944 | 8,494 |
| Nuclear\tfuel\tpurchases | (49,728) | (151,068) | (64,977) |
| Proceeds\tfrom\tthe\tsale\tof\tnuclear\tfuel | 69,516 | 11,467 | 57,681 |
| Proceeds\tfrom\tnuclear\tdecommissioning\ttrust\tfund\tsales | 565,416 | 499,252 | 390,371 |
| Investment\tin\tnuclear\tdecommissioning\ttrust\tfunds | (596,236) | (534,083) | (421,220) |
| Changes\tin\tmoney\tpool\treceivable\t-\tnet | (77,858) | 6,117 | (37,553) |
| Litigation\tproceeds\tfor\treimbursement\tof\tspent\tnuclear\tfuel\tstorage\tcosts | — | 15,806 | — |
|  | (174,250) | (232,602) | (137,562) |
| Net\tcash\tflow\tused\tin\tinvesting\tactivities |  |  |  |
| FINANCING\tACTIVITIES |  |  |  |
| Proceeds\tfrom\tthe\tissuance\tof\tlong-term\tdebt | 150,100 | — | — |
| Retirement\tof\tlong-term\tdebt | (150,103) | (22,002) | (136,310) |
| Changes\tin\tcredit\tborrowings\t-\tnet | (49,063) | 66,893 | (20,404) |
| Common\tstock\tdividends\tand\tdistributions | (106,610) | (139,000) | (200,750) |
| Other | (28) | (26) | (28) |
| Net\tcash\tflow\tused\tin\tfinancing\tactivities | (155,704) | (94,135) | (357,492) |
| Net\tincrease\tin\tcash\tand\tcash\tequivalents | 41,324 | 15,202 | 7,482 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 245,863 | 230,661 | 223,179 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $287,187 | $245,863 | $230,661 |
| SUPPLEMENTAL\tDISCLOSURE\tOF\tCASH\tFLOW\tINFORMATION: |  |  |  |
| Cash\tpaid\t(received)\tduring\tthe\tperiod\tfor: |  |  |  |
| Interest\t-\tnet\tof\tamount\tcapitalized | $26,251 | $36,152 | $47,864 |
| Income\ttaxes | ($2,227) | ($23,565) | ($114,092) |

| Cash | $78 | $786 |
| :--- | :--- | :--- |
| Temporary\tcash\tinvestments | 287,109 | 245,077 |
| Total\tcash\tand\tcash\tequivalents | 287,187 | 245,863 |
| Accounts\treceivable: |  |  |
| Associated\tcompanies | 170,149 | 104,390 |
| Other | 6,526 | 3,637 |
| Total\taccounts\treceivable | 176,675 | 108,027 |
| Materials\tand\tsupplies\t-\tat\taverage\tcost | 88,424 | 82,469 |
| Deferred\tnuclear\trefueling\toutage\tcosts | 7,908 | 24,729 |
| Prepayments\tand\tother | 2,489 | 20,111 |
| TOTAL | 562,683 | 481,199 |
| OTHER\tPROPERTY\tAND\tINVESTMENTS |  |  |
| Decommissioning\ttrust\tfunds | 905,686 | 780,496 |
| TOTAL | 905,686 | 780,496 |
| UTILITY\tPLANT |  |  |
| Electric | 4,327,849 | 4,331,668 |
| Property\tunder\tcapital\tlease | 588,281 | 585,084 |
| Construction\twork\tin\tprogress | 69,937 | 43,888 |
| Nuclear\tfuel | 207,513 | 259,635 |
| TOTAL\tUTILITY\tPLANT | 5,193,580 | 5,220,275 |
| Less\t-\taccumulated\tdepreciation\tand\tamortization | 3,175,018 | 3,063,249 |
| UTILITY\tPLANT\t-\tNET | 2,018,562 | 2,157,026 |
| DEFERRED\tDEBITS\tAND\tOTHER\tASSETS |  |  |
| Regulatory\tassets: |  |  |
| Regulatory\tasset\tfor\tincome\ttaxes\t-\tnet | — | 93,127 |
| Other\tregulatory\tassets | 444,327 | 411,212 |
| Other | 7,629 | 4,652 |
| TOTAL | 451,956 | 508,991 |
| TOTAL\tASSETS | $3,938,887 | $3,927,712 |

| Currently	maturing	long-term	debt | $85,004 | $50,003 |
| :--- | :--- | :--- |
| Short-term\tborrowings | 17,830 | 66,893 |
| Accounts\tpayable: |  |  |
| Associated\tcompanies | 16,878 | 5,843 |
| Other | 62,868 | 50,558 |
| Taxes\taccrued | 46,584 | — |
| Interest\taccrued | 13,389 | 14,049 |
| Other | 2,434 | 2,957 |
| TOTAL | 244,987 | 190,303 |
| NON-CURRENT\tLIABILITIES |  |  |
| Accumulated\tdeferred\tincome\ttaxes\tand\ttaxes\taccrued | 776,420 | 1,112,865 |
| Accumulated\tdeferred\tinvestment\ttax\tcredits | 39,406 | 41,663 |
| Regulatory\tliability\tfor\tincome\ttaxes\t-\tnet | 246,122 | — |
| Other\tregulatory\tliabilities | 455,991 | 370,862 |
| Decommissioning | 861,664 | 854,202 |
| Pension\tand\tother\tpostretirement\tliabilities | 121,874 | 117,850 |
| Long-term\tdebt | 466,484 | 501,129 |
| Other | 15,130 | 15 |
| TOTAL | 2,983,091 | 2,998,586 |
| Commitments\tand\tContingencies |  |  |
| COMMON\tEQUITY |  |  |
| Common\tstock,\tno\tpar\tvalue,\tauthorized\t1,000,000\tshares;\tissued\tand\toutstanding\t789,350\tshares\tin\t2017\tand\t2016 | 658,350 | 679,350 |
| Retained\tearnings | 52,459 | 59,473 |
| TOTAL | 710,809 | 738,823 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $3,938,887 | $3,927,712 |

|  | Common	Equity | Common	Equity |  |
| :--- | :--- | :--- | :--- |
|  | Common\tStock | Retained\tEarnings | Total |
|  | (In\tThousands) | (In\tThousands) |  |
| Balance\tat\tDecember\t31,\t2014 | $789,350 | $81,161 | $870,511 |
| Net\tincome | — | 111,318 | 111,318 |
| Common\tstock\tdividends\tand\tdistributions | (70,000) | (130,750) | (200,750) |
| Balance\tat\tDecember\t31,\t2015 | $719,350 | $61,729 | $781,079 |
| Net\tincome | — | 96,744 | 96,744 |
| Common\tstock\tdividends\tand\tdistributions | (40,000) | (99,000) | (139,000) |
| Balance\tat\tDecember\t31,\t2016 | $679,350 | $59,473 | $738,823 |
| Net\tincome | — | 78,596 | 78,596 |
| Common\tstock\tdividends\tand\tdistributions | (21,000) | (85,610) | (106,610) |
| Balance\tat\tDecember\t31,\t2017 | $658,350 | $52,459 | $710,809 |

|  | 2017 | 2016 | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Dollars\tIn\tThousands) |  |  |
| Operating\trevenues | $633,458 | $548,291 | $632,405 | $664,364 | $735,089 |
| Net\tincome | $78,596 | $96,744 | $111,318 | $96,334 | $113,664 |
| Total\tassets | $3,938,887 | $3,927,712 | $3,728,875 | $3,826,193 | $3,537,414 |
| Long-term\tobligations\t(a) | $466,484 | $501,129 | $572,665 | $630,603 | $702,273 |
| Electric\tenergy\tsales\t(GWh) | 6,675 | 5,384 | 10,547 | 9,219 | 9,794 |

# Item	2.			Properties

Information	regarding	the	registrant's	properties	is	included	in	Part	I.	Item	1.	-	Entergy's	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	2017	are	discussed	in	Part	I.	Item	1.	-	Entergy's	Business	under	the	sections	titled	"Retail Rate	 Regulation,"	 "Environmental	 Regulation,"	 and	 "Litigation"	 and	 "Impairment	 of	 Long-lived	Assets" in	 Note	 14 to the financial statements.

# Item	4.			Mine	Safety	Disclosures

Not	applicable.

# EXECUTIVE	OFFICERS	OF	ENTERGY	CORPORATION

(a) In	addition,	this	officer	is	an	executive	officer	and/or	director	of	various	other	wholly	owned	subsidiaries	of	Entergy	Corporation	and	its operating	companies.

Each	officer	of	Entergy	Corporation	is	elected	yearly	by	the	Board	of	Directors.	Each	officer's	age	and	title	is	provided	as	of	December

# PART	II

# Item	5.		Market	for	Registrants'	Common	Equity	and	Related	Stockholder	Matters

The	shares	of	Entergy	Corporation's	common	stock	are	listed	on	the	New	York	Stock	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	2017	and	2016	were	as	follows:

|  | 2017 |  | 2016 | 2016 |
| :--- | :--- | :--- | :--- | :--- |
|  | High | Low | High | Low |
|  |  | (In\tDollars) |  |  |
| First | 77.51 | 69.63 | 79.72 | 65.38 |
| Second | 80.61 | 74.88 | 81.36 | 72.67 |
| Third | 80.49 | 74.83 | 82.09 | 75.99 |
| Fourth | 87.95 | 75.01 | 76.56 | 66.71 |

Consecutive	quarterly	cash	dividends	on	common	stock	were	paid	to	stockholders	of	Entergy	Corporation	in	 2017	and	2016.		Quarterly dividends	of	$0.85	per	share	were	paid	through	third	quarter	2016.	In	fourth	quarter	2016	and	through	third	quarter	2017,	dividends	of	$0.87	per share	were	paid.	In	fourth	quarter	2017,	dividends	of	$0.89	per	share	were	paid.

As	of	January	31,	2018,	there	were	26,213	stockholders	of	record	of	Entergy	Corporation.

# Unregistered	Sales	of	Equity	Securities	and	Use	of	Proceeds

# Issuer	Purchases	of	Equity	Securities	(1)

|  |  |  |  |  | Maximum	$	Amount	of |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Total\tNumber\tof\tShares | Shares\tthat\tMay\tYet\tbe |
|  |  | Total\tNumber\tof\tShares | Average\tPrice\tPaid | Purchased\tas\tPart\tof\ta | Purchased\tUnder\ta\tPlan |
| Period | Period | Purchased | per\tShare | Publicly\tAnnounced\tPlan | (2) |
| 10/01/2017 | -10/31/2017 | — | $— | — | $350,052,918 |
| 11/01/2017 | -11/30/2017 | — | $— | — | $350,052,918 |
| 12/01/2017 | -12/31/2017 | — | $— | — | $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.		In	addition	to	this	authority,	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.	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	2017,	Entergy	withheld	1,054	shares	of	its	common	stock	at	$70.58	per	share, 122,148	shares	of	its	common	stock	at	$70.61	per	share,	and	31,243	shares	of	its	common	stock	at	$71.89	per	share	to	pay	income	taxes	due	upon vesting	of	restricted	stock	granted	and	payout	of	performance	units	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	relates	only	to	the	$500	million	plan	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	equity	of	the	Registrant	Subsidiaries.		Cash	dividends	and	distributions	on	common	equity	paid	by	the Registrant	Subsidiaries	during	2017	and	2016,	were	as	follows:

|  | 2017 | 2016 |
| :--- | :--- | :--- |
|  | (In\tMillions) |  |
| Entergy\tArkansas | $15.0 | $— |
| Entergy\tLouisiana | $91.3 | $285.5 |
| Entergy\tMississippi | $26.0 | $24.0 |
| Entergy\tNew\tOrleans | $74.3 | $18.7 |
| Entergy\tTexas | $— | $— |
| System\tEnergy | $106.6 | $139.0 |

Information	with	respect	to	restrictions	that	limit	the	ability	of	the	Registrant	Subsidiaries	to	pay	dividends	or	distributions	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	 LOUISIANA,	 LLC	 AND	 SUBSIDIARIES, ENTERGY	 MISSISSIPPI,	 INC.,	 ENTERGY	 NEW	 ORLEANS,	LLC	 AND	 SUBSIDIARIES,	 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	 LOUISIANA,	 LLC	 AND	 SUBSIDIARIES, ENTERGY	 MISSISSIPPI,	 INC.,	 ENTERGY	 NEW	 ORLEANS,	LLC	 AND	 SUBSIDIARIES,	 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	Louisiana,	LLC,	Entergy	Mississippi, Inc.,	Entergy	New	Orleans,	LLC,	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 Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	or	System	Energy.

# Item	9A.		Controls	and	Procedures

# Disclosure	Controls	and	Procedures

As	of	December	31,	2017,	evaluations	were	performed	under	the	supervision	and	with	the	participation	of	Entergy	Corporation,	Entergy Arkansas,	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

(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System

# Energy)

The	managements	of	Entergy	Corporation,	Entergy	Arkansas,	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, 2017.		In	making	this	assessment,	each	Registrant's	management	used	the	criteria	set	forth	by	the	Committee	of	Sponsoring	Organizations	of	the Treadway	 Commission	 (COSO)	 in	 Internal	 Control	 -	 Integrated	 Framework.	The	 2013	 COSO	 Framework	 was	 utilized	 for	 management's assessment.

Based	on	each	management's	assessment	and	the	criteria	set	forth	by	the	2013	COSO	Framework,	each	Registrant's	management	believes that	each	Registrant	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2017.

The	 report	 of	 Deloitte	 &	 Touche	 LLP,	 Entergy	 Corporation's	 independent	 registered	 public	 accounting	 firm,	 regarding	 Entergy Corporation's	internal	control	over	financial	reporting	is	included	herein.	The	report	of	Deloitte	&	Touche	LLP	is	not	applicable	to	Entergy Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy	because	these	Registrants	are	non- accelerated	filers.

# 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,	2017	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

# Opinion	on	Internal	Control	over	Financial	Reporting

We	have	audited	the	internal	control	over	financial	reporting	of	Entergy	Corporation	and	Subsidiaries	(the	"Corporation")	as	of	December	31, 2017,	based	on	criteria	established	in	Internal	Control	-Integrated	Framework	(2013)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the Treadway	Commission	(COSO).	In	our	opinion,	the	Corporation	maintained,	in	all	material	respects,	effective	internal	control	over	financial reporting	as	of	December	31,	2017,	based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(2013)	issued	by	COSO.

We	have	also	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States)	(PCAOB),	the consolidated	financial	statements	as	of	and	for	the	year	ended	December	31,	2017	of	the	Corporation	and	our	report	dated	February	26,	2018 expressed	an	unqualified	opinion	of	those	consolidated	financial	statements.

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	Item	9A,	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	are	a	public	accounting	firm	registered with	the	PCAOB	and	are	required	to	be	independent	with	respect	to	the	Corporation	in	accordance	with	the	U.S.	federal	securities	laws	and	the applicable	rules	and	regulations	of	the	Securities	and	Exchange	Commission	and	the	PCAOB.

We	conducted	our	audit	in	accordance	with	the	standards	of	the	PCAOB.	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.

# Definition	and	Limitations	of	Internal	Control	over	Financial	Reporting

A	company's	internal	control	over	financial	reporting	is	a	process	designed	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	its	inherent	limitations,	internal	control	over	financial	reporting	may	not	prevent	or	detect	misstatements.	Also,	projections	of	any evaluation	of	effectiveness	to	future	periods	are	subject	to	the	risk	that	controls	may	become	inadequate	because	of	changes	in	conditions,	or	that the	degree	of	compliance	with	the	policies	or	procedures	may	deteriorate.

New	Orleans,	Louisiana

# PART	III

# Item	 10.		Directors	and	Executive	Officers	of	the	Registrants	(Entergy	Corporation,	Entergy	Arkansas,	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	4,	2018,	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.

# ENTERGY	LOUISIANA,	LLC

# Directors

Each	director	and	officer	of	the	applicable	Entergy	company	is	elected	yearly	to	serve	by	the	unanimous	consent	of	the	sole	common stockholder	with	the	exception	of	the	directors	and	officers	of	Entergy	Louisiana,	LLC	and	Entergy	New	Orleans,	LLC,	who	are	elected	yearly	to serve	 by	 the	 unanimous	 consent	 of	 the	 sole	 common	 membership	 owner,	 Entergy	 Utility	 Holding	 Company,	 LLC.	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:

Patrick	J.	Condon	(Chairman)

Maureen	S.	Bateman

Philip	L.	Frederickson

# Blanche	L.	Lincoln

Karen	A.	Puckett

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.		The	Board	has	determined	that	each	of	Patrick	J.	Condon	and Philip	L.	Frederickson	is	an	"audit	committee	financial	expert"	as	such	term	is	defined	by	the	rules	of	the	SEC.

# 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	Provisions	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	expected	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,	including	any amendments	or	any	waivers	thereto,	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	will	consider	candidates	identified	by	current	directors,	management,	third-party	search	firms engaged	by	the	Corporate	Governance	Committee	and	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	stock	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	discussed	in	the	Proxy	Statement	under	"Corporate Governance	at	Entergy	-	Our	Board	Structure	-	Identifying	Director	Candidates";	and

•the	candidate's	signed	consent	to	be	named	in	the	Proxy	Statement	and	to	serve	as	a	director	if	elected.

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	4,	2018,	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	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	2017	is	discussed.	Each	officer's	title	is	provided as	of	December	31,	2017.

(1) Messrs.	Bakken,	Brown,	Denault,	Marsh,	and	West	hold	the	positions	referenced	above	as	executive	officers of	Entergy	Corporation	and	are	members	of	Entergy	Corporation's	Office	of	the	Chief	Executive.	No	additional	compensation	was	paid	in 2017	to	any	of	these	officers	for	their	service	as	Named	Executive	Officers	of	the	Utility	operating	companies.

# CD&A	Highlights

# Executive	Compensation	Programs	and	Practices

Entergy	Corporation	regularly	reviews	its	executive	compensation	programs	to	align	them	with	commonly	viewed	best	practices	in	the market	and	to	reflect	feedback	from	discussions	with	investors	on	executive	compensation.

# Sound	Program	Design

Entergy	Corporation's	executive	compensation	programs	are	designed	to:

# •Pay	for	performance

•Attract,	retain,	and	motivate	key	executive	officers	who	drive	Entergy	Corporation's	success	and	industry	leadership •Provide	market	compensation	payout	opportunities

•Align	with	the	interests	of	Entergy	Corporation's	long-term	shareholders

•Reflect	best	practices	in	the	market

# 	Executive	Compensation	Best	Practices:

* Maximum	payout	capped	at	200%	of	target	under	the	Long-Term	Performance	Unit	Program	and	under	the	Annual Incentive	Plan	for	members	of	the	Office	of	the	Chief	Executive

* Minimum	vesting	periods	for	equity-based	awards

* Long-term	compensation	mix	weighted	more	toward	performance	units	than	service-based	equity	awards

* All	long-term	performance	units	settled	in	shares	of	Entergy	Corporation	common	stock

* Rigorous	stock	ownership	requirements

* Executives	required	to	hold	substantially	all	equity	compensation	received	by	Entergy	Corporation	until	stock ownership	guidelines	are	met

* Annual	Say	on	Pay	vote

* No	option	repricing	or	cash	buy-outs	for	underwater	options

* No	agreements	providing	for	severance	payments	to	executive	officers	that	exceed	2.99	times	annual	base	salary and	annual	incentive	awards	without	shareholder	approval

* No	hedging	or	pledging	of	Entergy	Corporation	common	stock

* No	unusual	or	excessive	perquisites

* New	officers	are	excluded	from	participation	in	the	System	Executive	Retirement	Plan

* No	grants	of	supplemental	service	credit	to	newly-hired	officers	under	any	of	Entergy	Corporation's	non-qualified retirement	plans

# Entergy	Corporation's	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	its	annual	and	long-term	incentive	plans.	It	believes	the	executive	pay	programs	described	in	this	section	and	in	the	accompanying	tables	have played	a	significant	role	in	its	ability	to	drive	strong	financial	and	operational	results	and	to	attract	and	retain	a	highly	experienced	and	successful management	team.	The	Annual	Incentive	Plan	incentivizes	and	rewards	the	achievement	of	financial	metrics	that	are	deemed	by	the	Personnel Committee	 to	 be	 consistent	 with	 the	 overall	 goals	 and	 strategic	 direction	 that	 the	 Entergy	 Corporation	 Board	 has	 approved	 for	 Entergy Corporation.	The	long-term	incentive	programs	further	align	the	interests	of	Entergy	Corporation's	executives	and	its	shareholders	by	directly tying	the	value	of	the	equity	awards	granted	to	executives	under	these	programs	to	Entergy	Corporation's	stock	price	performance	and	total shareholder	 return.	By	incentivizing	officers	to	achieve	important	financial	and	operational	objectives	and	create	long-term	shareholder	value, these	programs	play	a	key	role	in	creating	sustainable	value	for	the	benefit	of	all	of	Entergy	Corporation's	stakeholders,	including	owners, customers,	employees,	and	communities.

# Incentive	Programs	and	2017	Incentive	Pay	Outcomes

Entergy	Corporation	believes	that	the	2017	incentive	pay	outcomes	for	the	Named	Executive	Officers	demonstrated	the	application	of	its pay	for	performance	philosophy.

# Annual	Incentive	Plan

Awards	under	the	Executive	Annual	Incentive	Plan,	or	Annual	Incentive	Plan,	are	tied	to	Entergy	Corporation's	financial	and	operational performance	through	the	Entergy	Achievement	Multiplier	(EAM),	which	is	the	performance	metric	used	to	determine	the	maximum	funding available	for	awards	under	 the	plan.	The	2017	EAM	was	determined	based	in	equal	part	on	Entergy	Corporation's	success	in	achieving	its consolidated	operational	earnings	per	share	and	consolidated	operational	operating	cash	flow	goals	set	at	the	beginning	of	the	year.	These	goals were	approved	by	the	Personnel	Committee	based	on	Entergy	Corporation's	financial	plan	and	the	Board's	overall	goals	for	Entergy	Corporation and	were	consistent	with	its	published	earnings	guidance.

•2017	Annual	Incentive	Plan	Payout.	For	2017, the	Personnel	Committee,	based	on	a	recommendation	of	 the	Finance	Committee, determined	that	management	exceeded	its	consolidated	operational	earnings	per	share	goal	of	$5.05	per	share	by	$2.17,	but	fell	short	of	its consolidated	operational	operating	cash	flow	goal	of	$3.000	billion	by	approximately	$227	million.	Based	on	the	targets	and	ranges previously	established	by	the	Committee,	these	results	resulted	in	a	calculated	EAM	of	129%.	This	determined	the	maximum	funding level	for	the	plan	and	the	maximum	award,	as	a	percentage	of	target,	that	could	be	received	by	any	of	the	executive	officers,	subject	to downward	adjustment	based	on	individual	performance.	After	considering	individual	performance,	including	the	role	played	by	each	of the	Named	Executive	Officers,	who	are	members	of	the	Office	of	the	Chief	Executive,	in	advancing	Entergy	Corporation's	strategies	and delivering	the	strong	financial	results	in	2017,	the	Personnel	Committee	approved	payouts	of	129%	of	target	for	each	of	the	Named Executive	Officers,	who	are	members	of	the	Office	of	the	Chief	Executive.

After	the	EAM	was	established	to	determine	overall	funding	for	the	Annual	Incentive	Plan,	Entergy	Corporation's	Chief	Executive Officer	allocated	incentive	award	funding	to	individual	business	units	based	on	business	unit	results.		Individual	awards	were	determined for	the	Named	Executive	Officers	who	are	not	members	of	the	Office	of	the	Chief	Executive	by	their	immediate	supervisor	based	on	the individual	officer's	key	accountabilities,	accomplishments,	and	performance.	This	resulted	in	payouts	that	ranged	from	79%	of	target	to 204%	of	target	for	the	Named	Executive	Officers	who	are	not	members	of	Entergy	Corporation's	Office	of	the	Chief	Executive.

# Long-Term	Incentives

Long	term	incentives	consist	of	three	components	to	incentivize	long-term	value	creation	-	performance	units,	stock	options,	and	restricted stock.	Performance	under	the	Long-Term	Performance	Unit	Program	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.	Payouts,	if	any,	are	based	on	Entergy	Corporation's	total	shareholder	return	performance	in	relation	to its	peers	and	are	not	subject	to	adjustment	by	the	Personnel	Committee.	Beginning	with	the	2018-2020	performance	period,	Entergy	Corporation will	be	using	a	cumulative	utility	earnings	measure,	as	well	as	relative	total	shareholder	return	to	assess	performance	under	the	Long-Term Performance	Unit	Program.	Entergy	Corporation	also	uses	stock	options,	which	reward	increases	in	the	market	value	of	its	common	stock,	and restricted	stock,	which	is	an	effective	retention	mechanism.

•Long-Term	Performance	Unit	Program	Payout.	For	the	three-year	performance	period	ending	in	2017,	Entergy	Corporation's	total shareholder	return	was	in	the	third	quartile,	resulting	in	a	payout	of	31%	of	target	for	its	executive	officers.	Payouts	were	made	in	shares	of Entergy	Corporation	common	stock	which	are	required	to	be	held	by	executive	officers	until	they	satisfy	the	executive	stock	ownership guidelines.

# What	Entergy	Corporation	Pays	and	Why

# How	Entergy	Corporation	Sets	Target	Pay

To	develop	a	competitive	compensation	program,	the	Personnel	Committee	annually	reviews	compensation	data	from	two	sources:

# Use	of	Competitive	Data

The	Personnel	Committee	uses	published	and	private	compensation	survey	data	to	develop	marketplace	compensation	levels	for	Entergy Corporation's	executive	officers.	The	data	compiled	by	the	Committee's	independent	compensation	consultant,	Pay	Governance	LLC,	compare 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.	The	Committee	reviews:

•For	non-industry	specific	positions,	general	industry	data	for	total	cash	compensation	(base	salary	and	annual	incentive)	since	the	market for	talent	is	broader	than	the	utility	sector.

•For	management	positions	that	are	industry-specific,	such	as	Group	President,	Utility	Operations,	data	from	utility	companies	for	total cash	compensation.

•For	all	positions,	utility	market	data	for	long-term	incentives.

The	survey	data	reviewed	by	the	Committee	cover	hundreds	of	companies	across	a	broad	range	of	industries	and	approximately	60	investor- owned	utility	companies.	In	evaluating	compensation	levels	against	the	survey	data,	the	Committee	considers	only	the	aggregated	survey	data. The	identities	of	the	companies	participating	in	the	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	in	the	aggregate.	The	survey	data	are	the	primary	data	used	for	purposes	of	assessing target	 compensation.	As	a	result,	Mr.	Denault,	Entergy	Corporation's	Chief	Executive	Officer,	is	compensated	at	a	higher	level	than	the	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	7	other	executive officers	who	constitute	what	is	referred	to	as	the	Office	of	the	Chief	Executive	each	has	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,	Entergy	Corporation	performance,	and	internal	pay	equity.

# Proxy	Analysis

Although	the	survey	data	described	above	are	the	primary	data	used	in	benchmarking	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	Personnel	Committee identified	the	Philadelphia	Utility	Index	as	the	appropriate	industry	peer	group	because	the	companies	included	in	this	index,	in	the	aggregate,	are comparable	to	Entergy	Corporation	in	terms	of	business	and	scale.	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.	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	from	the	2016	filings	were	compiled:

# Executive	Compensation	Elements

The	following	table	summarizes	the	elements	of	total	direct	compensation	(TDC)	granted	or	paid	to	the	executive	officers	under	Entergy Corporation's	 2017	 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.	The	Personnel	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.

# How	This	Amount	Is

| Element | Key	Characteristics | Why	This	Element	Is	Paid | Determined | 2017	Decisions |
| :--- | :--- | :--- | :--- | :--- |
| Base\tSalary | Fixed\tcompensation\tcomponent\npayable\tin\tcash.\tReviewed\nannually\tand\tadjusted\twhen\nappropriate. | Provides\ta\tbase\tlevel\tof\tcompetitive\ncash\tcompensation\tfor\texecutive\ntalent. |  |  |
| Annual\tIncentive\nAwards |  | Motivate\tand\treward\texecutives\tfor\nperformance\ton\tkey\tfinancial\tand\noperational\tmeasures\tduring\tthe\nyear. | Target\topportunity\tis\tdetermined\nbased\ton\tjob\tscope,\tmarket\tdata,\nand\tinternal\tpay\tequity.\nFor\t2017,\tawards\twere\ndetermined\tbased\ton\tsuccess\tin\nmeeting\tconsolidated\toperational\nearnings\tper\tshare\tand\nconsolidated\toperational\noperating\tcash\tflow\ttargets,\nsubject\tto\tdownward\tadjustment\nat\tthe\tPersonnel\tCommittee's\ndiscretion\tfor\tmembers\tof\tthe\nOffice\tof\tthe\tChief\tExecutive. | Mr.\tDenault's\ttarget\tannual\tincentive\naward\tfor\t2017\twas\t135%\tof\tbase\tsalary,\nand\ttarget\tawards\twere\tin\tthe\trange\tof\n40%\tto\t70%\tof\tbase\tsalary\tfor\tthe\tother\nNamed\tExecutive\tOfficers.\nStrong\toperational\tand\tfinancial\nperformance\tand\ta\treview\tof\tindividual\nperformance\tresulted\tin\tan\taward\tat\n129%\tof\ttarget\tfor\tEntergy\tCorporation's\nChief\tExecutive\tOfficer,\tand\tawards\tthat\nranged\tfrom\t79%\tto\t204%\tof\ttarget\tfor\nthe\tother\tNamed\tExecutive\tOfficers. |
| Long-Term\nPerformance\nUnit\nProgram | Each\tperformance\tunit\tequals\none\tshare\tof\tEntergy\nCorporation's\tcommon\tstock.\nPerformance\tis\tmeasured\tat\tthe\nend\tof\ta\tthree-year\tperformance\nperiod.\tEach\tunit\talso\tearns\tthe\nequivalent\tof\tthe\tdividends\tpaid\nduring\tthe\tperformance\tperiod.\nPerformance\tunits\tgranted\tunder\nthe\tLong-Term\tPerformance\nUnit\tProgram\talong\twith\naccrued\tdividend\tequivalents\tare\nsettled\tin\tshares\tof\tEntergy\nCorporation\tcommon\tstock. | Focuses\texecutive\tofficers\ton\nbuilding\tlong-term\tshareholder\nvalue\tand\tincreases\texecutive\nofficers'\townership\tof\tEntergy\nCorporation\tcommon\tstock. | Formulaic.\tpayout\tbased\ton\nEntergy\tCorporation's\ttotal\nshareholder\treturn\trelative\tto\tthe\ntotal\tshareholder\treturn\tof\tthe\ncompanies\tin\tthe\tPhiladelphia\nUtility\tIndex.\nBeginning\twith\tthe\t2018-2020\nperformance\tperiod,\tpayouts\twill\nbe\tbased\ton\ta\tcumulative\tutility\nearnings\tmetric,\tas\twell\tas\ttotal\nshareholder\treturn. | Performance\tunit\tgrants\tfor\tthe\t2017-\n2019\tperformance\tperiod\trepresented\napproximately\t39%\tof\ttarget\tTDC\tfor\nEntergy\tCorporation's\tChief\tExecutive\nOfficer\tand\tapproximately\t21%\tto\t31%\nof\ttarget\tfor\tthe\tother\tNamed\tExecutive\nOfficers.\nUnfavorable\trelative\ttotal\tshareholder\nreturn\tin\t2015\tand\t2016,\tpartially\toffset\nby\tstrong\trelative\ttotal\tshareholder\treturn\nin\t2017,\tresulted\tin\tperformance\tin\tthe\nthird\tquartile\twith\ta\t6.7%\tTSR\tfor\tthe\n2015-2017\tperformance\tperiod,\tyielding\na\tpayout\tof\t31%\tof\ttarget\tfor\tthe\tNamed\nExecutive\tOfficers. |
| Stock\nOptions | Non-qualified\tstock\toptions\tare\ngranted\tat\tfair\tmarket\tvalue,\nhave\ta\tten-year\tterm,\tand\tvest\nover\t3\tyears\t-\t33\t1/3%\ton\teach\nanniversary\tof\tthe\tgrant\tdate. | Reward\texecutives\tfor\tabsolute\nvalue\tcreation\tand\tcoupled\twith\nrestricted\tstock\tprovide\tcompetitive\ncompensation,\tretain\texecutive\ntalent,\tand\tincrease\tthe\texecutive\nofficers'\townership\tin\tEntergy\nCorporation's\tcommon\tstock. | Job\tscope,\tmarket\tdata,\tindividual\nperformance,\tand\tEntergy\nCorporation\tperformance. |  |

| Restricted | Restricted	stock	awards	vest | Coupled	with	stock	options,	align | Job	scope,	market	data,	individual | Restricted	stock	in	2017	represented |
| :--- | :--- | :--- | :--- | :--- |
| Stock | over\t3\tyears\t-\t33\t1/3%\ton\teach | interests\tof\texecutives\twith\tlong- | performance,\tand\tEntergy | approximately\t13%\tof\ttarget\tTDC\tfor |
| Awards | anniversary\tof\tthe\tgrant\tdate, | term\tshareholder\tvalue,\tprovide | Corporation\tperformance. | Entergy\tCorporation's\tChief\tExecutive |
|  | have\tvoting\trights,\tand\taccrue | competitive\tcompensation,\tretain |  | Officer\tand\tapproximately\t7%\t-\t10% |
|  | dividends\tduring\tthe\tvesting | executive\ttalent,\tand\tincrease\tthe |  | for\tthe\tother\tNamed\tExecutive |
|  | period. | executive\tofficers'\townership\tof |  | Officers. |

# Fixed	Compensation

# Base	Salary

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	immediate	supervisors	using	the	same criteria.	The	Committee	also	considers	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	2017,	all	of	the	Named	Executive	Officers	received	merit	increases	in	their	base	salaries	ranging	from	approximately	1.5%	to	7.3%. The	increases	in	base	salary	were	based	on	the	market	data	previously	discussed	in	this	CD&A	under	"What	Entergy	Corporation	Pays	and	Why	- How	Entergy	Corporation	Sets	Target	Pay,"	as	well	as	an	internal	pay	equity	comparison.

The	following	table	sets	forth	the	2016	and	2017	base	salaries	for	the	Named	Executive	Officers.	Changes	in	base	salaries	for	2017	were effective	in	April	2017.

| Named	Executive	Officer | 2016	Base	Salary | 2017	Base	Salary |
| :--- | :--- | :--- |
| A.\tChristopher\tBakken,\tIII | $605,000 | $620,125 |
| Marcus\tV.\tBrown | $605,000 | $630,000 |
| Leo\tP.\tDenault | $1,200,000 | $1,230,000 |
| Haley\tR.\tFisackerly | $350,000 | $355,300 |
| Andrew\tS.\tMarsh | $559,408 | $600,000 |
| Phillip\tR.\tMay,\tJr. | $356,650 | $366,150 |
| Sallie\tT.\tRainer | $319,475 | $328,275 |
| Charles\tL.\tRice,\tJr. | $280,424 | $286,424 |
| Richard\tC.\tRiley | $335,000 | $344,200 |
| Roderick\tK.\tWest | $659,120 | $675,598 |

# Variable	Compensation

# Short-Term	Incentive	Compensation

Entergy	 Corporation	 includes	 performance-based	 incentives	 in	 the	 Named	 Executive	 Officers'	 compensation	 packages	 because	 it believes	 performance-based	 incentives	 encourage	 the	 Named	 Executive	 Officers	 to	 pursue	 objectives	 consistent	 with	 the	 overall	 goals	 and strategic	direction	that	the	Board	has	approved	for	Entergy	Corporation.	The	EAM	is	the	performance	metric	used	to	determine	the	maximum percentage	of	target	annual	plan	opportunities	that	will	be	paid	each	year	to	each	Named	Executive	Officer	who	are	members	of	the	Office	of	the Chief	Executive	under	the	Annual	Incentive	Plan.	Once	the	EAM	has	been	determined,	individual	awards	for	the	Office	of	the	Chief

Executive	members	may	be	adjusted	downward,	but	not	upward,	from	the	EAM	at	the	Personnel	Committee's	discretion,	based	on	individual performance	and	other	factors	deemed	relevant	by	the	Personnel	Committee.	For	2017,	the	target	Annual	Incentive	Plan	opportunities	for	each	of the	Named	Executive	Officers,	expressed	as	a	percentage	of	the	officer's	base	salary,	were:

The	target	opportunities	established	for	these	officers	were	comparable	to	the	target	opportunities	historically	set	for	these	positions	and levels	 of	 responsibility.	Target	opportunities	for	 the	Named	Executive	Officers	who	are	members	of	 the	Office	of	 the	Chief	Executive	are established	by	the	Personnel	Committee,	and	these	Named	Executive	Officers	may	earn	a	maximum	payout	ranging	from	0%	to	200%	of	their target	opportunity,	calculated	as	described	in	the	table	below.

Target	 award	 opportunities	 are	 set	 based	 on	 an	 executive	 officer's	 position	 and	 executive	 management	 level	 within	 the	 Entergy organization.	Executive	management	levels	at	Entergy	Corporation	range	from	Level	1	through	Level	4.	At	December	31,	2017,	Mr.	Denault	held a	Level	1	position,	Messrs.	Bakken,	Brown,	Marsh,	and	West	held	positions	in	Level	2,	Mr.	May	held	a	Level	3	position,	and	the	remaining Named	Executive	Officers	held	positions	in	Level	4.	Accordingly,	their	respective	incentive	award	opportunities	differ	from	one	another	based	on their	management	level	and	the	external	market	data	developed	by	the	Committee's	independent	compensation	consultant.

Each	 year	 the	 Personnel	 Committee	 reviews	 the	 performance	 measures	 used	 to	 determine	 the	 EAM	 pool.	In	 December	 2016,	 the Personnel	 Committee	 decided	 to	 retain	 consolidated	 operational	 earnings	 per	 share	 and	 consolidated	 operational	 operating	 cash	 flow,	 each measure	weighted	equally,	as	the	performance	measures	for	determining	the	EAM	pool.	The	Committee	considered	a	variety	of	other	potential measures,	but	determined	that	consolidated	operational	earnings	per	share	and	consolidated	operational	operating	cash	flow	continued	to	be	the best	metrics	to	use	because,	among	other	things,	they	are	objective	measures	that	Entergy	Corporation's	investors	consider	to	be	important	in evaluating	 its	financial	performance	and	because	Entergy	Corporation's	goals	 in	 that	regard	are	broadly	communicated	both	 internally	and externally.	This	provides	both	discipline	and	transparency	that	the	Committee	believes	are	important	objectives	of	any	well	designed	incentive compensation	plan.

The	Personnel	Committee	also	engages	in	a	rigorous	process	each	year	to	establish	the	target	achievement	levels	for	each	of	the	EAM performance	measures	with	a	goal	of	establishing	target	achievement	levels	that	are	consistent	with	Entergy	Corporation's	strategy	and	business objectives	for	the	upcoming	year,	as	reflected	in	its	financial	plan,	and	sufficient	to	drive	results	that	represent	a	high	level	of	achievement,	taking into	consideration	the	applicable	business	environment	and	specific	challenges	facing	it.	These	targets	are	approved	based	on	a	comprehensive review	by	the	full	Board	of	Entergy	Corporation's	financial	plan,	conducted	in	December	of	the	preceding	year	and	updated	in	January	to	reflect the	most	current	information	concerning	changes	in	commodity	market	conditions	and	other	key	drivers	of	anticipated	changes	in	performance from	the	preceding	year.	The	Committee	also	reviews	the	effects	on	plan	results	of	various	risks	and	opportunities	that	are	recognized	at	the	time the	plan	is	set,	to	assure	that	targets	that	are	determined	based	on	the	plan	reflect	an	appropriate	balance	of	risks	and	opportunities.	The	Committee further	confirms	that	the	earnings	target	it	approves	is	aligned	with	the	earnings	guidance	that	will	be	communicated	to	the	financial	markets,	thus ensuring	that	the	internal	earnings	target	set	for	purposes	of	Entergy	Corporation's	incentive	compensation	plans	is	aligned	with	the	external expectations	set	and	communicated	to	Entergy	Corporation's	shareholders.

In	January	2017,	after	full	Board	review	of	management's	2017	financial	plan	for	Entergy	Corporation	and	engaging	in	the	process discussed	above,	the	Committee	determined	the	Annual	Incentive	Plan	targets	to	be	used	for	purposes	of	determining	Annual	Incentive	Plan awards	for	2017.	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	reported	results	of	any	major	storms	that	may	occur	during	the	year.	This	exclusion	was	viewed	by	the Committee

as	appropriate	because	although	Entergy	Corporation	includes	estimates	for	storm	costs	in	its	financial	plan,	it	does	not	include	estimates	for	a major	storm	event,	such	as	a	hurricane.	The	Committee	also	approved	exclusions	from	reported	results,	for	purposes	of	calculating	achievement levels,	for	the	impact	of	certain	longstanding	unresolved	litigation	relating	to	the	System	Agreement	among	the	Utility	operating	companies,	and for	the	potential	effects	of	changes	in	tax	laws,	given	the	possibility	that	significant	unanticipated	changes	in	tax	laws	might	be	enacted	during	the year	 that	 could	 impact	 reported	 results.	The	Committee	believed	 that	each	of	 these	adjustments	was	appropriate	because	of	 the	significant uncertainty	around	each	such	item	and	management's	inability	to	influence	any	of	the	related	outcomes.

In	determining	the	targets	to	set	for	2017,	the	Committee	reviewed	anticipated	drivers	for	consolidated	operational	earnings	per	share and	consolidated	operational	operating	cash	flow	for	2017	as	set	forth	in	Entergy	Corporation's	financial	plan	and	as	reflected	in	its	published earnings	guidance.	Under	the	plan,	consolidated	operational	earnings	per	share	were	expected	to	decline	from	2016	results	due	primarily	to	the significant	impact	on	2016	operational	results	of	certain	tax	benefits	and,	to	a	lesser	extent,	favorable	weather,	which	were	not	anticipated	to	recur in	 2017.	Together,	 these	 factors	 accounted	 for	 $2.06	 of	 consolidated	 operational	 earnings	 per	 share	 for	 2016.	Under	 the	 plan,	 consolidated operational	operating	cash	flow	was	expected	to	increase	slightly	in	2017	from	2016	results.

In	evaluating	the	proposed	targets,	the	Committee	considered	the	potential	impact	on	consolidated	operational	earnings	per	share	and consolidated	operational	operating	cash	flow	of	certain	risks	and	opportunities,	including	differences	in	wholesale	energy	prices	and	capacity factors	at	Entergy	Wholesale	Commodities,	utility	sales,	operations	and	maintenance	costs,	interest	expense,	and	certain	tax	and	regulatory	risks. This	evaluation	indicated	that	there	was	significantly	more	downside	risk	than	upside	opportunity	in	the	targets	and,	as	a	result,	that	there	was	a reasonable	degree	of	challenge	embedded	in	the	targets.

After	adjusting	to	eliminate	the	impact	of	weather	and	tax	benefits,	the	2017	plan	targets	required	management	to	achieve	(i)	slight growth	in	utility	operational	earnings	despite	higher	nuclear	and	pension	costs	and	the	absence	of	certain	favorable	items	from	2016	and	(ii) modest	growth	in	Entergy	Wholesale	Commodities	operational	earnings,	despite	an	expectation	for	further	declines	in	wholesale	energy	and capacity	revenues	due	in	part	to	the	sale	of	FitzPatrick	in	the	first	quarter	of	2017.	While	the	resulting	earnings	target	represented	a	decline	from 2016	operational	results,	the	Committee	recognized	that	in	addition	to	the	favorable	weather	and	tax	items	that	were	not	expected	to	recur	in	2017, management	 would	 be	 challenged	 in	 2017	 by	 significantly	 higher	 nuclear	 costs	 as	 they	 executed	 on	 its	 nuclear	 strategic	 plan.	Thus,	 the Committee	concluded,	based	on	a	careful	review	of	the	overall	plan,	that	the	targets	derived	from	the	plan	challenged	management	appropriately to	deliver	growth	in	Entergy	Corporation's	core	business	while	continuing	to	manage	the	significant	risks	at	Entergy	Wholesale	Commodities	and represented	an	appropriate	balancing	of	Entergy	Corporation's	business	risks	and	opportunities	for	2017.

The	following	table	shows	the	resulting	Annual	Incentive	Plan	targets	established	by	the	Personnel	Committee	in	January	2017,	and 2017	results:

# Annual	Incentive	Plan	Targets	and	Results

|  |  | Performance	Goals(1) |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Minimum | Target | Maximum | 2017\tResults |
| Consolidated\tOperational\tEarnings\tPer\tShare | $4.55 | $5.05 | $5.55 | $7.22 |
| Consolidated\tOperational\tOperating\tCash\tFlow\t($\tbillion) | $2.600 | $3.000 | $3.400 | $2.773 |
| EAM\tas\t%\tof\tTarget | 25% | 100% | 200% | 129% |

(1) Payouts	for	performance	between	minimum	and	target	achievement	levels	and	between	target	and	maximum	levels	are	calculated using	straight-line	interpolation.	There	is	no	payout	for	performance	below	minimum.

In	January	2018,	the	Finance	and	Personnel	Committees	jointly	reviewed	Entergy	Corporation's	financial	results	against	the	performance objectives	 reflected	 in	 the	 table	 above.	Management	 discussed	 with	 the	 Committees	 the	 consolidated	 operational	 earnings	 per	 share	 and consolidated	operational	operating	cash	flow	results	for	2017,	including	primary	factors	explaining	how	those	results	compared	to	the	2017 business	plan	and	Annual	Incentive	Plan	targets.	Consolidated	operational	earnings	per	share	exceeded	the	operational	earnings	per	share	goal	of $5.05	per	share	set	at	the	beginning	of	the	year	by	$2.17,	due	in	large	part	to	a	non-cash	restructuring	tax	benefit,	but	management	fell	short	of achieving	its	consolidated	operational	operating	cash	flow	goal	of	$3.000	billion	by	approximately	$227	million,	leading	to	a	calculated	EAM	of 129%.	Operational	results	excluded	the	impact	of	certain	special	items	that	were	excluded	from	as-reported	(GAAP)	earnings	per	share	and operating	cash	flow	to	determine	consolidated	operational	earnings	per	share	and	consolidated	operational	operating	cash	flow,	including	asset impairments	and	related	write-offs	at	Entergy	Wholesale	Commodities	related	to	Entergy	Corporation's	2016	decision	to	close	two	nuclear generating	plants,	and	certain	costs	associated	with	nuclear	plant	closings,	and	charges	recorded	at	the	end	of	2017	relating	to	the	impact	of recently	enacted	federal	income	tax	law	changes.	Consistent	with	determinations	made	by	the	Personnel	Committee	when	the	targets	were	set, adjustments	were	made	to	the	reported	results	to	exclude	the	impact	of	Hurricane	Harvey	and	the	resolution	of	certain	longstanding	System Agreement	litigation,	but	these	adjustments	had	only	a	negligible	impact	on	the	calculated	EAM.

					The	Committee	reviewed	certain	sensitivities	as	part	of	its	review	of	the	calculation	of	the	EAM	and	noted	that	Entergy	Corporation	far exceeded	its	consolidated	operational	earnings	per	share	goal	in	2017,	as	noted,	due	in	large	part	to	a	restructuring	tax	benefit,	partially	offset	by unfavorable	weather	at	the	utility,	and	that	unfavorable	weather	at	the	utility	also	accounted	for	approximately	$128	million	of	the	$227	million shortfall	in	consolidated	operational	operating	cash	flow.	Had	the	EAM	been	calculated	to	exclude	both	the	impact	of	the	restructuring	tax	benefit and	unfavorable	weather,	the	calculated	EAM	would	have	been	140%.	This	indicated	that	the	underlying	performance	of	the	core	business, without	regard	to	the	impact	of	tax	items	and	weather,	was	significantly	stronger	than	implied	by	the	calculated	EAM.	However,	consistent	with the	plan	design,	the	Personnel	Committee	did	not	make	any	adjustments	for	these	factors	to	the	consolidated	operational	earnings	per	share	and consolidated	operational	operating	cash	flow	results	to	determine	the	EAM	for	2017.	The	Committee	also	noted	that	its	utility,	parent,	and	other adjusted	earnings	of	$4.57	per	share	for	2017	were	slightly	above	the	high	end	of	the	guidance	range	Entergy	Corporation	had	provided	to investors	at	the	beginning	of	the	year	for	this	extremely	important	measure	of	its	core	utility	earnings.

In	determining	individual	executive	officer	awards	under	the	Annual	Incentive	Plan,	for	Entergy	Corporation's	Chief	Executive	Officers and	the	Named	Executive	Officers,	who	are	members	of	the	Office	of	the	Chief	Executive,	the	Committee	considered	individual	performance	and, in	particular,	whether	there	were	additional	factors	beyond	those	captured	by	the	EAM	measures	that	should	be	taken	into	account	in	determining whether	 to	 exercise	 negative	 discretion	 to	 reduce	 awards	 below	 the	 levels	 determined	 by	 the	 EAM.	In	 determining	 the	 extent	 of	 negative discretion,	if	any,	that	it	would	exercise	with	respect	to	each	executive	officer,	the	Committee	considered	the	executive's	key	accountabilities	and accomplishments,	 and	 individual	 performance	 executing	 on	 Entergy	 Corporation's	 strategies	 in	 2017.	Based	 on	 these	 considerations,	 the Committee	decided	to	award	a	payout	equal	to	the	EAM,	or	129%	of	target,	for	Entergy	Corporation's	Chief	Executive	Officer	and	the	other Named	Executive	Officers	who	are	members	of	the	Office	of	the	Chief	Executive.

After	the	EAM	was	established	to	determine	overall	funding	for	the	Annual	Incentive	Plan,	Entergy	Corporation's	Chief	Executive Officer	allocated	incentive	award	funding	to	individual	business	units	based	on	business	unit	results.		Individual	awards	were	determined	for	the remaining	Named	Executive	Officers	who	are	not	members	of	the	Office	of	the	Chief	Executive	by	their	immediate	supervisor	based	on	the individual	officer's	key	accountabilities,	accomplishments,	and	performance.		This	resulted	in	payouts	that	ranged	from	79%	of	target	to	204%	of target	for	the	Named	Executive	Officers	who	are	not	members	of	the	Office	of	the	Chief	Executive.

Based	on	the	foregoing	evaluation	of	management	performance,	the	Personnel	Committee	approved	the	following	Annual	Incentive	Plan payouts	to	each	Named	Executive	Officer	for	2017:

|  |  | Target	as	Percentage | Payout	as	Percentage	of | 2017	Annual |
| :--- | :--- | :--- | :--- | :--- |
| Named\tExecutive\tOfficer | Base\tSalary | of\tBase\tSalary | Target | Incentive\tAward |
| A.\tChristopher\tBakken,\tIII | $620,125 | 70% | 129% | $559,973 |
| Marcus\tV.\tBrown | $630,000 | 70% | 129% | $568,890 |
| Leo\tP.\tDenault | $1,230,000 | 135% | 129% | $2,142,045 |
| Haley\tR.\tFisackerly | $355,300 | 40% | 119% | $169,123 |
| Andrew\tS.\tMarsh | $600,000 | 70% | 129% | $541,800 |
| Phillip\tR.\tMay,\tJr. | $366,150 | 60% | 137% | $300,000 |
| Sallie\tT.\tRainer | $328,275 | 40% | 119% | $156,259 |
| Charles\tL.\tRice,\tJr. | $286,424 | 40% | 79% | $91,000 |
| Richard\tC.\tRiley | $344,200 | 40% | 204% | $280,661 |
| Roderick\tK.\tWest | $675,598 | 70% | 129% | $610,065 |

# 	Nuclear	Retention	Plan

Mr.	Bakken	participates	 in	 the	Nuclear	Retention	Plan,	a	retention	plan	for	officers	and	other	 leaders	with	expertise	 in	 the	nuclear industry.	The	Personnel	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.	Mr.	Bakken's	participation	in	the	plan	commenced	in	May	2016	and	in	accordance	with	the	terms	and	conditions	of	the	plan,	in	May 2017,	2018,	and	2019,	subject	to	his	continued	employment,	Mr.	Bakken	will	receive	a	cash	bonus	equal	to	30%	of	his	base	salary	as	of	May	1, 2016.	This	plan	does	not	allow	for	accelerated	or	prorated	payout	upon	termination	of	any	kind.	The	three-year	coverage	period	and	percentage	of base	salary	payable	under	the	plan	are	consistent	with	the	terms	of	participation	of	other	senior	nuclear	officers	who	participate	in	this	plan.	In May	2017,	Mr.	Bakken	received	a	cash	bonus	of	$181,500	which	equaled	30%	of	his	May	1,	2016,	base	salary	of	$605,000.

# Long-Term	Incentive	Compensation

Entergy	Corporation's	goal	for	its	long-term	incentive	compensation	is	to	focus	the	executive	officers	on	building	shareholder	value	and to	increase	the	executive	officers'	ownership	of	Entergy	Corporation's	common	stock	in	order	to	more	closely	align	their	interest	with	those	of Entergy	Corporation's	shareholders.	In	its	long-term	incentive	compensation	programs,	Entergy	Corporation	uses	a	mix	of	performance	units, restricted	stock,	and	stock	options.	Performance	units	are	used	to	deliver	more	than	a	majority	of	the	total	target	long-term	incentive	awards.	For periods	through	the	end	of	2017,	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.	Beginning	with	the 2018-2020	performance	period,	a	cumulative	utility	earnings	metric	has	been	added	to	the	Long-Term	Performance	Unit	Program	to	supplement the	relative	total	shareholder	return	measure	that	historically	has	been	used	in	this	program	with	each	measure	equally	weighted.	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	value	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,	based	on	the	value	the	compensation	model	seeks	to	deliver.	Awards	for	individual	Named	Executive	Officers	may	vary	from this	target	as	a	result	of	individual	performance,	promotions,	and	internal	pay	equity.

The	performance	units	for	the	2015-2017	performance	period	were	awarded	under	the	2011	Equity	Ownership	Plan	and	Long-Term	Cash Incentive	Plan	(the	"2011	Equity	Ownership	Plan")	and	the	performance	units	for	the

2016-2018	and	2017-2019	performance	periods	and	all	of	the	shares	of	restricted	stock	and	stock	options	granted	to	the	Named	Executive	Officers in	2017	were	granted	pursuant	to	the	2015	Equity	Ownership	Plan	(the	"2015	Equity	Ownership	Plan,"	and	together	with	the	2011	Equity Ownership	Plan	(the	"Equity	Ownership	Plans").	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

Entergy	Corporation	issues	performance	unit	awards	to	the	Named	Executive	Officers	under	its	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	approved	by	the	Personnel Committee	are	met.	The	Personnel	Committee	has	no	discretion	to	make	awards	if	minimum	performance	goals	are	not	achieved.

The	performance	units	granted	under	the	Long-Term	Performance	Unit	Program	and	accrued	dividends	on	any	shares	earned	during	the performance	period	are	settled	in	shares	of	Entergy	Corporation	common	stock	rather	than	cash.	No	shares	are	issued,	including	shares	attributable to	accrued	dividends,	unless	performance	goals	are	achieved.	All	shares	paid	out	under	the	Long-Term	Performance	Unit	Program	are	required	to be	retained	by	the	officers	until	applicable	executive	stock	ownership	requirements	are	met.

The	Long-Term	Performance	Unit	Program	specifies	a	minimum,	target,	and	maximum	achievement	level,	the	achievement	of	which will	determine	the	number	of	performance	units	that	may	be	earned	by	each	participant.	Entergy	Corporation	measures	performance	by	assessing Entergy	Corporation's	total	shareholder	return	relative	to	the	total	shareholder	return	of	the	companies	in	the	Philadelphia	Utility	Index,	which Entergy	Corporation	refers	to	as	it	peer	companies.	The	Personnel	Committee	identified	the	Philadelphia	Utility	Index	as	the	appropriate	industry peer	group	for	this	purpose	because	the	companies	included	in	this	index,	in	the	aggregate,	are	comparable	to	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	ranking	of	Entergy	Corporation's	total	shareholder	return	against	the	total	shareholder	return	of	the companies	in	the	Philadelphia	Utility	Index.

Performance	Unit	Program	Grants.	At	any	given	time,	a	participant	in	the	Long-Term	Performance	Unit	Program	may	be	participating	in up	to	three	performance	periods.	During	2017,	eligible	participants	were	participating	in	the	2015-2017,	2016-2018,	and	2017-2019	performance periods.	Subject	to	achievement	of	the	applicable	performance	levels	as	described	below,	the	Personnel	Committee	established	the	following target	performance	unit	payout	opportunities	for	each	of	the	2015-2017,	2016-2018,	and	2017-2019	performance	periods.

|  | 2015-2017 | 2016-2018 | 2017-2019 |
| :--- | :--- | :--- | :--- |
| Named\tExecutive\tOfficer | Target | Target | \tTarget |
| A.\tChristopher\tBakken,\tIII\t (1) | 3,639 | 7,289 | 8,300 |
| Marcus\tV.\tBrown | 6,550 | 8,200 | 8,300 |
| Leo\tP.\tDenault | 33,100 | 41,700 | 48,700 |
| Haley\tR.\tFisackerly | 1,450 | 1,800 | 1,850 |
| Andrew\tS.\tMarsh | 6,550 | 8,200 | 8,300 |
| Phillip\tR.\tMay,\tJr. | 2,050 | 2,700 | 3,150 |
| Sallie\tT.\tRainer | 1,450 | 1,800 | 1,850 |
| Charles\tL.\tRice,\tJr. | 1,450 | 1,800 | 1,850 |
| Richard\tC.\tRiley | 1,450 | 1,800 | 1,850 |
| Roderick\tK.\tWest | 6,550 | 8,200 | 8,300 |

For	all	performance	periods,	there	is	no	payout	for	performance	that	falls	within	the	lowest	quartile	of	performance	of	the	peer	companies, and	for	top	quartile	performance	a	maximum	payout	of	200%	of	target	is	earned.	Payouts	between	minimum	and	target	and	between	target	and maximum	are	calculated	by	interpolating	between	the	performance	of	the	company	at	the	top	of	the	fourth	quartile	of	performance	of	the	peer companies	and	the	median	or	between	the	median	and	the	performance	of	the	company	at	the	bottom	position	of	the	top	quartile	of	performance	of the	peer	companies,	respectively.

Payout	for	the	2015-2017	Performance	Period.	In	January	2018,	the	Committee	reviewed	Entergy	Corporation's	total	shareholder	return for	the	2015-2017	performance	period	in	order	to	determine	the	payout	to	participants.	The	Committee	compared	Entergy	Corporation's	total shareholder	return	against	 the	 total	shareholder	return	of	 the	companies	 that	comprise	 the	Philadelphia	Utility	Index,	with	 the	performance measures	and	range	of	potential	payouts	for	the	2015-2017	performance	period	similar	to	that	discussed	above.	As	recommended	by	the	Finance Committee,	the	Personnel	Committee	concluded	that	Entergy	Corporation's	relative	total	shareholder	return	for	the	2015-2017	performance	period fell	in	the	bottom	of	the	third	quartile,	yielding	a	payout	of	31%	of	target	for	the	Named	Executive	Officers.

|  | 2015-2017 | Number	of	Shares | Value	of	Shares | Grant	Date	Fair |
| :--- | :--- | :--- | :--- | :--- |
| Named\tExecutive\tOfficer | Target | Issued | Actually\tIssued(1) | Value |
| A.\tChristopher\tBakken,\tIII (2) | 3,639 | 1,212 | $95,154 | $360,334 |
| Marcus\tV.\tBrown | 6,550 | 2,287 | $179,552 | $648,581 |
| Leo\tP.\tDenault | 33,100 | 11,554 | $907,105 | $3,277,562 |
| Haley\tR.\tFisackerly | 1,450 | 506 | $39,726 | $143,579 |
| Andrew\tS.\tMarsh | 6,550 | 2,287 | $179,552 | $648,581 |
| Phillip\tR.\tMay,\tJr. | 2,050 | 716 | $56,213 | $202,991 |
| Sallie\tT.\tRainer | 1,450 | 506 | $39,726 | $143,579 |
| Charles\tL.\tRice,\tJr. | 1,450 | 506 | $39,726 | $143,579 |
| Richard\tC.\tRiley | 1,450 | 506 | $39,726 | $143,579 |
| Roderick\tK.\tWest | 6,550 | 2,287 | $179,552 | $648,581 |

(1) Value	 determined	 based	 on	 the	 closing	 price	 of	 Entergy	 Corporation's	 common	 stock	 on	 January	 17,	 2018 ($78.51), the	 date the Personnel	Committee	certified	the	2015-2017	performance	period	results.

(2) As	a	new	hire	in	2016,	Mr.	Bakken	received	pro-rated	target	award	opportunities	for	the	2015-2017	performance	period.

# Stock	Options	and	Restricted	Stock

Entergy	Corporation	grants	stock	options	and	restricted	stock	as	a	long-term	incentive	to	its	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	Entergy	Corporation	and	individual	performance,	internal	pay	equity,	prevailing	market	practice,	targeted long-term	value	created	by	the	use	of	stock	options	and	restricted	stock,	and	the	potential	dilutive	effect	of	stock	option	and	restricted	stock	grants. Of	 these	 factors,	 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	the	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	of	the	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.

The	following	table	sets	forth	the	number	of	stock	options	and	shares	of	restricted	stock	granted	to	each	Named	Executive	Officer	in 2017.	The	exercise	price	for	each	option	was	$70.53,	which	was	the	closing	price	of	Entergy	Corporation's	common	stock	on	the	date	of	grant.

| Named	Executive	Officer | Stock	Options | Shares	of	Restricted	Stock |
| :--- | :--- | :--- |
| A.\tChristopher\tBakken,\tIII | 37,600 | 5,200 |
| Marcus\tV.\tBrown | 44,000 | 6,100 |
| Leo\tP.\tDenault | 179,400 | 17,000 |
| Haley\tR.\tFisackerly | 7,600 | 850 |
| Andrew\tS.\tMarsh | 44,000 | 6,100 |
| Phillip\tR.\tMay,\tJr. | 10,500 | 1,100 |
| Sallie\tT.\tRainer | 7,800 | 900 |
| Charles\tL.\tRice,\tJr. | 3,900 | 550 |
| Richard\tC.\tRiley | 8,000 | 1,000 |
| Roderick\tK.\tWest | 29,200 | 3,200 |

# Benefits	and	Perquisites

Entergy	Corporation's	Named	Executive	Officers	are	eligible	to	participate	in	or	receive	the	following	benefits:

Cash	Balance	Plan	-	a	tax-qualified	cash	balance	defined	benefit	pension	plan	that	covers	a broad	group	of	employees	hired	on	or	after	July	1,	2014.

Pension	Equalization	Plan	-	a	non-qualified	pension	restoration	plan	for	a	select	group	of management	or	highly	compensated	employees	who	participate	in	the	Entergy	Retirement	Plan. Cash	 Balance	 Equalization	 Plan -	 a	 non-qualified	 restoration	 plan for	 a select	 group	 of management	or	highly	compensated	employees	who	participate	in	the	Cash	Balance	Plan.

System	 Executive	 Retirement	 Plan	 -	 a	 non-qualified	 supplemental retirement plan for individuals	who	became	executive	officers	before	July	1,	2014.

Entergy	Corporation	provides	these	benefits	to	its	Named	Executive	Officers	as	part	of	providing	a	competitive	executive	compensation	program and	because	it	believes	that	these	benefits	are	important	retention	and	recruitment	tools	since	many	of	the	companies	with	which	it	competes	for executive	talent	provide	similar	arrangements	to	their	senior	executive	officers.

# Compensation	Arrangements

The	 Personnel	 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	many	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	of	Entergy	Corporation	and	its	subsidiaries.	Severance	payments	under	the	System	Executive	Continuity	Plan generally	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	for the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	the	termination	of	employment	occurs.	Under	Entergy	Corporation's policy,	under	no	circumstances	can	this	multiple	exceed	2.99	times	the	sum	of	the	executive	officer's	annual	base	salary	and	his	or	her	annual incentive,	calculated	in	accordance	with	this	policy.	Entergy	Corporation	strives	to	ensure	that	the	benefits	and	payment	levels	under	the	System Executive	 Continuity	 Plan	 are	 consistent	 with	 market	 practices.	Entergy	 Corporation's	 executive	 officers,	 including	 the	 Named	 Executive Officers,	will	not	receive	any	tax	gross	up	payments	on	any	severance	benefits	received	under	this	plan.	For	more	information	regarding	the System	Executive	Continuity	Plan,	see	"2017	Potential	Payments	Upon	Termination	or	Change	in	Control-System	Executive	Continuity	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	employment	or	severance	agreements	providing	severance benefits	in	excess	of	2.99	times	the	sum	of	an	officer's	annual	base	salary	and	annual	incentive	award	(other	than	the	value	of	the	vesting	or payment	of	an	outstanding	equity-based	award	or	the	pro	rata	vesting	or	payment	of	an	outstanding	long-term	incentive	award)	must	be	approved by	Entergy	Corporation's	shareholders.

Entergy	Corporation	currently	has	a	retention	agreement	with	Mr.	Denault.	In	general,	Mr.	Denault's	retention	agreement	provides	for certain	payments	and	benefits	in	the	event	of	his	termination	of	employment	by	his	Entergy	employer	other	than	for	cause,	by	Mr.	Denault	for good	reason	or	on	account	of	his	death	or	disability.	See	"2017	Potential	Payments	Upon	Termination	or	Change	in	Control	-	Mr.	Denault's	2006 Retention	 Agreement."	Because	Mr.	Denault	has	reached	age	55,	certain	severance	payment	provisions	in	his	retention	agreement	no	longer apply.	Mr.	Denault	will	not	receive	tax	gross	up	payments	on	any	payments	or	benefits	he	may	receive	under	his	agreement.	Mr.	 Denault's retention	agreement	was	entered	 into	 in	2006	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	played 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,	at	the	time	the	agreement	was	entered	into,	believed	the	benefits	and	payment	levels	under Mr.	Denault's	retention	agreement	were	consistent	with	market	practices.

# 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	other	companies	in	the	S&P	500.	Some	of	these	practices	include	the	following:

# Clawback	Provisions

Entergy	Corporation	has	adopted	a	clawback	policy	that	covers	all	individuals	subject	to	Section	16	of	the	Securities	Exchange	Act	of 1934	(the	Exchange	Act),	including	the	members	of	the	Office	of	the	Chief	Executive.	Under	the	policy,	which	goes	beyond	the	requirements	of Sarbanes-Oxley	Act	of	2002	(Sarbanes-Oxley),	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	determined	to	be	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,	in	each	case,	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,	it	will	seek	to	recover	any	compensation	received	by	its	Chief Executive	Officer	and	Chief	Financial	Officer	that	is	required	to	be	reimbursed	under	Sarbanes-Oxley.

# 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.

Entergy	Corporation's	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;

•all	net	after-tax	shares	of	restricted	stock	and	restricted	stock	units	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	Entergy	Corporation	securities,	including	gifts,	other	than	the	exercise	of	employee	stock options.	Trading	is	generally	permitted	only	during	specified	open	trading	windows	beginning	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	the	policy	by	permitting	shares	to	be	bought	or	sold	without	pre- approval	or	when	trading	is	restricted.

Entergy	Corporation	also	prohibits	 its	directors	and	executive	officers,	 including	 the	Named	Executive	Officers,	from	pledging	any Entergy	Corporation	securities	or	entering	 into	margin	accounts	 involving	Entergy	Corporation	securities.	These	 transactions	are	prohibited 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	has	also	adopted	an	anti-hedging	policy	that	prohibits	officers,	directors,	and	employees	from	entering	into	hedging or	monetization	transactions	involving	Entergy	Corporation	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	common	stock	or	transactions	involving	"short-sales"	of	Entergy	Corporation's	common	stock.	The	Board	adopted	this	policy	to require	officers,	directors,	and	employees	to	continue	to	own	Entergy	Corporation's	common	stock	with	the	full	risks	and	rewards	of	ownership, thereby	ensuring	continued	alignment	of	their	objectives	with	those	of	Entergy	Corporation's	other	shareholders.

# How	Entergy	Corporation	Makes	Compensation	Decisions

# Role	of	the	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	 Entergy	 Corporation's	 Named	 Executive	 Officers.	 The	 Committee	 works	 with	 Entergy Corporation's	 executive	 management	 to	 ensure	 that	 the	 compensation	 policies	 and	 practices	 are	 consistent	 with	 its	 values	 and	 support	 the successful	 recruitment,	 development,	 and	 retention	 of	 executive	 talent	 so	 that	 Entergy	 Corporation	 can	 achieve	 its	 business	 objectives	 and optimize	its	long-term	financial	returns.	Annually,	management	presents	the	Personnel	Committee	with	the	proposed	compensation	model	for	the following	year,	including	the	compensation	elements,	mix	of	elements,	and	measures	for	each	element,	and	consults	with	Entergy	Corporation's Chief	Executive	Officer	on	recommended	compensation	for	senior	executives.	The	Committee	evaluates	executive	pay	each	year	to	ensure	that Entergy	Corporation's	compensation	policies	and	practices	are	consistent	with	its	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	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	the	Chief	Executive	Officer.

# Role	of	the	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	 who	 are	 members	 of	 Entergy	 Corporation's	 Office	 of	 the	 Chief	 Executive.	Entergy Corporation's	 Chief	 Executive	 Officer	 provides	 the	 Personnel	 Committee	 with	 an	 assessment	 of	 the	 performance	 of	 each	 of	 these	 Named Executive	Officers	and	recommends	compensation	levels	to	be	awarded	to	each	of	them.	In	addition,	the	Committee	may	request	that	the	Chief Executive

Officer	provide	management	feedback	and	recommendations	on	changes	in	the	design	of	compensation	programs,	such	as	special	retention	plans or	changes	in	incentive	program	structure.	However,	the	Chief	Executive	Officer	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	Entergy	Corporation's	Senior	Vice	President,	Human	Resources	with	respect	to	compensation decisions,	policies,	and	practices.

The	Chief	Executive	Officer	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.	Since	he	is	not	a	member	of	the	Committee,	he	has	no	vote	on	matters	submitted	to	the Committee.	During	2017,	Mr.	Denault	attended	9	meetings	of	the	Personnel	Committee.

# Role	of	the	Compensation	Consultant

Entergy	Corporation's	Personnel	Committee	has	the	sole	authority	for	the	appointment,	compensation,	and	oversight	of	its	outside compensation	 consultant.	The	Committee	conducts	an	annual	review	of	the	compensation	consultant,	and	in	2017,	it	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	 Entergy	 Corporation's	 compensation	 programs.	Also	 in	 2017,	 the	 Corporate	 Governance	 Committee	 retained	 Pay Governance	to	review	and	perform	a	competitive	analysis	of	non-employee	director	compensation.

During	2017,	Pay	Governance	assisted	the	Committee	with	its	responsibilities	related	to	Entergy	Corporation's	compensation	programs for	its	executives.	The	Committee	directed	Pay	Governance	to:	(i)	regularly	attend	meetings	of	the	Committee;	(ii)	conduct	studies	of	competitive compensation	practices;	(iii)	identify	Entergy	Corporation's	market	surveys	and	proxy	peer	group;	(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	 programs	 for	 consideration	 by	 the	 Committee.	A	 senior	 consultant	 from	 Pay	 Governance	 attended	 all	 Personnel Committee	meetings	to	which	he	was	invited	in	2017.

# Compensation	Consultant	Independence

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	or	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	2017,	the	Personnel	Committee's	independent	compensation	consultant, Pay	Governance,	did	not	provide	any	services	to	Entergy	Corporation	other	than	its	services	to	the	Personnel	Committee	and	the	Corporate Governance	 Committee	 in	 connection	 with	 Entergy	 Corporation's	 non-employee	 director	 compensation	 program.	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.	The	Committee	also	assesses	Pay	Governance's	independence	under NYSE	rules	and	has	concluded	that	no	conflict	of	interests	exists	that	would	prevent	Pay	Governance	from	independently	advising	the	Personnel Committee.

# Tax	and	Accounting	Considerations

Section	162(m)	of	the	Internal	Revenue	Code	(the	Code)	limits	the	tax	deductibility	by	a	publicly-held	corporation	of	compensation	in excess	of	$1	million	paid	to	the	Chief	Executive	Officer	and	any	of	its	other	Section	162(m)	covered	employees.	Historically,	an	exception	was provided	for	compensation	that	was	"performance-based	compensation"	within	the	meaning	of	Section	162(m).		Effective	as	of	January	1,	2018, this	exception	no	longer	applies,	other	than	with	respect	to	certain	grandfathered	arrangements.	In	structuring	the	compensation	packages	that	are provided	to	the	Named	Executive	Officers,	the	Personnel	Committee	takes	into	account	the	tax	effects	of	Section	162(m)	and	considers	the financial	accounting	consequences.	However,	the	Personnel	Committee	and	the	Board	believe	that	it	is	in	the	best	interest	of	Entergy	Corporation that	the	Personnel	Committee	retains	the	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	corporate	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

# 2017	Summary	Compensation	Tables

The	following	table	summarizes	the	total	compensation	paid	or	earned	by	each	of	the	Named	Executive	Officers	for	the	fiscal	year	ended December	31,	2017,	and	to	the	extent	required	by	SEC	executive	compensation	disclosure	rules,	the	fiscal	years	ended	December	31,	2016	and 2015.		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.		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 | All |  |
|  |  |  |  |  |  | Plan | Compen- | Other |  |
| Name\tand\tPrincipal |  |  |  | Stock | Option | Compen- | sation | Compens- |  |
| Position | Year | Salary | Bonus | Awards | Awards | sation | Earnings | ation | Total |
| (1) |  | (2) | (3) | \t(4) | \t(5) | (6) | \t(7) | \t(8) |  |
| A.\tChristopher\tBakken,\nIII | 2017 | $615,791 | $181,500 | $959,376 | $245,904 | $559,973 | $33,000 | $114,494 | $2,710,038 |
| Chief\tNuclear\tOfficer\tof\nEntergy\tCorp. | 2016 | $426,990 | $650,000 | $3,292,700 | $— | $529,375 | $27,900 | $140,601 | $5,067,566 |
| Marcus\tV.\tBrown | 2017 | $622,788 | $— | $1,022,853 | $287,760 | $568,890 | $1,217,200 | $43,269 | $3,762,760 |
| General\tCounsel\tof\nEntergy\tCorp. | 2016 | $563,208 | $— | $1,144,648 | $333,000 | $550,550 | $934,600 | $34,381 | $3,560,387 |
| Leo\tP.\tDenault | 2017 | $1,221,346 | $— | $4,676,190 | $1,173,276 | $2,142,045 | $3,819,500 | $125,863 | $13,158,220 |
| Chairman\tof\tthe | 2016 | $1,191,462 | $— | $4,632,276 | $1,235,800 | $2,154,600 | $4,166,800 | $97,786 | $13,478,724 |
| Board\tand\tCEO\t- | 2015 | $1,153,385 | $— | $4,356,362 | $1,004,080 | $1,681,875 | $4,802,400 | $88,795 | $13,086,897 |
| Entergy\tCorp. |  |  |  |  |  |  |  |  |  |
| Haley\tR.\tFisackerly | 2017 | $354,451 | $— | $192,041 | $49,704 | $169,123 | $406,300 | $35,724 | $1,207,343 |
| CEO\t-\tEntergy | 2016 | $320,067 | $— | $229,752 | $49,580 | $168,000 | $268,600 | $34,243 | $1,070,242 |
| Mississippi | 2015 | $320,131 | $— | $219,994 | $51,345 | $190,000 | $102,300 | $43,987 | $927,757 |
| Andrew\tS.\tMarsh | 2017 | $588,291 | $— | $1,022,853 | $287,760 | $541,800 | $801,900 | $51,647 | $3,294,251 |
| Executive\tVice | 2016 | $553,284 | $— | $1,144,648 | $333,000 | $509,061 | $593,700 | $47,484 | $3,181,177 |
| President\tand\tCFO\t- | 2015 | $532,245 | $— | $2,600,401 | $273,840 | $508,308 | $670,200 | $39,131 | $4,624,125 |
| Entergy\tCorp., |  |  |  |  |  |  |  |  |  |
| Entergy\tArkansas, |  |  |  |  |  |  |  |  |  |
| Entergy\tLouisiana, |  |  |  |  |  |  |  |  |  |
| Entergy\tMississippi, |  |  |  |  |  |  |  |  |  |
| Entergy\tNew |  |  |  |  |  |  |  |  |  |
| Orleans,\tEntergy |  |  |  |  |  |  |  |  |  |
| Texas |  |  |  |  |  |  |  |  |  |
| Phillip\tR.\tMay,\tJr. | 2017 | $363,410 | $— | $302,493 | $68,670 | $300,000 | $503,400 | $26,981 | $1,564,954 |
| CEO\t-\tEntergy | 2016 | $353,690 | $— | $326,988 | $71,040 | $224,690 | $600,000 | $26,018 | $1,602,426 |
| Louisiana | 2015 | $344,035 | $— | $279,406 | $57,050 | $315,000 | $288,100 | $25,970 | $1,309,561 |

| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | Change\tin |  |  |
|  |  |  |  |  |  |  | Pension |  |  |
|  |  |  |  |  |  |  | Value\tand |  |  |
|  |  |  |  |  |  | Non-Equity | Non-qualified |  |  |
|  |  |  |  |  |  | Incentive | Deferred | All |  |
|  |  |  |  |  |  | Plan | Compen- | Other |  |
| Name\tand\tPrincipal |  |  |  | Stock | Option | Compen- | sation | Compens- |  |
| Position | Year | Salary | Bonus | Awards | Awards | sation | Earnings | ation | Total |
| (1) |  | (2) | (3) | \t(4) | \t(5) | (6) | \t(7) | \t(8) |  |
| Sallie\tT.\tRainer | 2017 | $325,737 | $— | $195,567 | $51,012 | $156,259 | $435,900 | $35,785 | $1,200,260 |
| CEO\t-\tEntergy | 2016 | $316,003 | $— | $229,752 | $49,580 | $153,348 | $346,300 | $53,797 | $1,148,780 |
| Texas | 2015 | $304,783 | $— | $211,004 | $43,358 | $190,000 | $189,100 | $41,565 | $979,810 |
| Charles\tL.\tRice,\tJr. | 2017 | $284,681 | $— | $170,882 | $25,506 | $91,000 | $221,200 | $30,842 | $824,111 |
| CEO\t-\tEntergy\tNew | 2016 | $276,998 | $— | $229,752 | $49,580 | $67,302 | $177,600 | $33,807 | $835,039 |
| Orleans | 2015 | $266,752 | $— | $211,004 | $51,345 | $173,000 | $104,500 | $33,416 | $840,017 |
| Richard\tC.\tRiley | 2017 | $341,723 | $— | $202,620 | $52,320 | $280,661 | $437,700 | $38,695 | $1,353,719 |
| CEO\t-\tEntergy | 2016 | $325,020 | $— | $226,224 | $34,780 | $167,500 | $277,900 | $102,112 | $1,133,536 |
| Arkansas |  |  |  |  |  |  |  |  |  |
| Roderick\tK.\tWest | 2017 | $670,876 | $— | $818,316 | $190,968 | $610,065 | $867,200 | $52,220 | $3,209,645 |
| Group\tPresident | 2016 | $654,514 | $— | $1,116,424 | $303,400 | $461,384 | $601,000 | $73,706 | $3,210,428 |
| Utility\tOperations\tof | 2015 | $638,876 | $— | $1,071,111 | $262,430 | $607,677 | $543,900 | $71,790 | $3,195,784 |

Entergy	Corp.

(1) Mr.	Bakken	was	named	Executive	Vice	President	and	Chief	Nuclear	Officer	in	April	2016.	Mr.	Brown	was	not	a	Named	Executive Officer	in	2015.	Mr.	Riley	was	named	Chief	Executive	Officer,	Entergy	Arkansas	in	May	2016.

(2) The	amounts	in	column	(c)	represent	the	actual	base	salary	paid	to	the	Named	Executive	Officers.		The	2017	changes	in	base	salaries noted	in	the	Compensation	Discussion	and	Analysis	were	effective	in	April	2017.

(3) The	amount	in	column	(d)	in	2017	for	Mr.	Bakken	represents	the	cash	bonus	paid	to	him	pursuant	to	the	Nuclear	Retention	Plan.	See "Nuclear	Retention	Plan"	in	Compensation	Discussion	and	Analysis.	The	amount	in	column	(d)	in	2016	represents	a	cash	sign-on	bonus paid	to	Mr.	Bakken	in	connection	with	his	commencement	of	employment	with	Entergy	Corporation.

(4) The	amounts	in	column	(e)	represent	the	aggregate	grant	date	fair	value	of	restricted	stock,	performance	units,	and	restricted	stock	units granted	under	 the	Equity	Ownership	Plans,	each	calculated	 in	accordance	with	FASB	ASC	Topic	718,	without	 taking	 into	account estimated	forfeitures.		The	grant	date	fair	value	of	the	restricted	stock	and	restricted	stock	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	interest	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	2017	are	as	follows:		Mr. Bakken,	$1,170,798;	Mr.	Brown,	$1,170,798;	Mr.	Denault,	$6,869,622;	Mr.	Fisackerly,	$260,961;	Mr.	Marsh,	$1,170,798;	Mr.	May, $444,339;	Ms.	Rainer,	$260,961;	Mr.	Rice,	$260,961;	Mr.	Riley,	$260,961;	and	Mr.	West,	$1,170,798.	 The	amount	in	2016	for	Mr. Bakken	includes	restricted	stock	units	granted	to	him	in	connection	with	his	commencement	of	employment	as	Chief	Nuclear	Officer.

(5) The	amounts	in	column	(f)	represent	the	aggregate	grant	date	fair	value	of	stock	options	granted	under	the	Equity	Ownership	Plans 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.

(6) The	amounts	in	column	(g)	represent	cash	payments	made	under	the	Annual	Incentive	Plan.

(7) For	all	Named	Executive	Officers,	the	amounts	in	column	(h)	include	the	annual	actuarial	increase	in	the	present	value	of	these	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	"2017	Pension	Benefits").		None	of	the	increases	for	any	of the	Named	Executive	Officers	is	attributable	to	above-market	or	preferential	earnings	on	non-qualified	deferred	compensation	(see	"2017 Non-qualified	Deferred	Compensation").

(8) The	amounts	in	column	(i)	for	2017	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	Officer | Company<br>Contribution	–<br>Savings	Plan | Dividends	Paid	on<br>Restricted	Stock | Life	Insurance<br>Premium | Tax	Gross<br>Up<br>Payments | Perquisites	and<br>Other<br>Compensation | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| A.\tChristopher\tBakken,\tIII | $16,200 | $— | $11,887 | $1,299 | $85,108 | $114,494 |
| Marcus\tV.\tBrown | $— | $35,517 | $7,482 | $— | $270 | $43,269 |
| Leo\tP.\tDenault | $11,340 | $93,206 | $7,482 | $— | $13,835 | $125,863 |
| Haley\tR.\tFisackerly | $11,340 | $7,907 | $2,306 | $4,082 | $10,089 | $35,724 |
| Andrew\tS.\tMarsh | $11,139 | $35,517 | $4,991 | $— | $— | $51,647 |
| Phillip\tR.\tMay,\tJr. | $11,340 | $9,673 | $5,279 | $— | $689 | $26,981 |
| Sallie\tT.\tRainer | $11,340 | $7,696 | $6,477 | $2,952 | $7,320 | $35,785 |
| Charles\tL.\tRice,\tJr. | $11,340 | $6,849 | $4,874 | $2,637 | $5,142 | $30,842 |
| Richard\tC.\tRiley | $11,340 | $8,756 | $5,040 | $4,832 | $8,727 | $38,695 |
| Roderick\tK.\tWest | $11,340 | $38,270 | $2,610 | $— | $— | $52,220 |

# Perquisites	and	Other	Compensation

The	amounts	set	forth	in	column	(i)	include	perquisites	and	other	personal	benefits	that	Entergy	Corporation	provides	to	its	Named Executive	Officers	as	part	of	providing	a	competitive	executive	compensation	program	and	for	employee	retention.	The	following	perquisites were	provided	to	the	Named	Executive	Officers	in	2017.

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	Personnel

Committee	reviews	the	level	of	usage	throughout	the	year.	Entergy	Corporation	believes	that	its	officers'	ability	to	use	its	plane	for	limited personal	use	saves	time	and	provides	additional	security	for	them,	thereby	benefiting	Entergy	Corporation.	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.	In	addition,	Entergy	Corporation	offers	its	executives	comprehensive	annual physical	exams	at	Entergy	Corporation's	expense.	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	his	employment,	and	in	accordance	with	its	relocation policies	and	pursuant	to	certain	additional	relocation	benefits	including	the	purchase	of	his	home,	Entergy	Corporation	paid	$77,897	in	relocation expenses	 for	 Mr.	 Bakken	 in	 2017.	The	 relocation	 assistance	 amounts	 reported	 above	 represent	 the	 amounts	 paid	 to	 Entergy	 Corporation's relocation	service	provider	or	Mr.	Bakken,	as	applicable.

None	of	the	other	perquisites	referenced	above	exceeded	$25,000	for	any	of	the	other	Named	Executive	Officers.

# 2017	Grants	of	Plan-Based	Awards

The	following	table	summarizes	award	grants	during	2017	to	the	Named	Executive	Officers.

|  |  | Estimated	Future	Payouts	Under	Non- | Equity	Incentive	Plan	Awards	(1) | Equity	Incentive	Plan	Awards	(1) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) |
| Name | Grant\tDate | Thresh-\nold | Target | Maximum | Thresh-\nold | Target | Maximum | All\tOther\nStock\nAwards:\nNumber\tof\nShares\tof\nStock\tor\nUnits | All\tOther\nOption\nAwards:\nNumber\tof\nSecurities\nUnder-lying\nOptions | Exercise\tor\nBase\tPrice\nof\tOption\nAwards | Grant\tDate\tFair\nValue\tof\tStock\nand\tOption\nAwards |
|  |  | ($) | ($) | ($) | (#) | (#) | (#) | (#) | (#) | ($/Sh) | ($) |
|  |  |  |  |  |  |  |  | (3) | (4) |  | (5) |
| A.\nChristopher | 1/26/17 | $- | $434,088 | $868,175 |  |  |  |  |  |  |  |
| Bakken,\tIII | 1/26/17 |  |  |  | 2,075 | 8,300 | 16,600 |  |  |  | $592,620 |
|  | 1/26/17 |  |  |  |  |  |  | 5,200 |  |  | $366,756 |
|  | 1/26/17 |  |  |  |  |  |  |  | 37,600 | $70.53 | $245,904 |
| Marcus\tV. | 1/26/17 | $- | $441,000 | $882,000 |  |  |  |  |  |  |  |
| Brown | 1/26/17 |  |  |  | 2,075 | 8,300 | 16,600 |  |  |  | $592,620 |
|  | 1/26/17 |  |  |  |  |  |  | 6,100 |  |  | $430,233 |
|  | 1/26/17 |  |  |  |  |  |  |  | 44,000 | $70.53 | $287,760 |
| Leo\tP. | 1/26/17 | $- | $1,660,500 | $3,321,000 |  |  |  |  |  |  |  |
| Denault | 1/26/17 |  |  |  | 12,175 | 48,700 | 97,400 |  |  |  | $3,477,180 |
|  | 1/26/17 |  |  |  |  |  |  | 17,000 |  |  | $1,199,010 |
|  | 1/26/17 |  |  |  |  |  |  |  | 179,400 | $70.53 | $1,173,276 |

# Estimated	Future	Payouts	Under	Non- Estimated	Future	Payouts	under

|  |  | Estimated	Future	Payouts	Under	Non- | Equity	Incentive	Plan	Awards	(1) | Equity	Incentive	Plan	Awards	(1) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) | Estimated	Future	Payouts	under<br>Equity	Incentive	Plan	Awards	(2) |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) |
| Name | Grant\tDate | Thresh-\nold | Target | Maximum | Thresh-\nold | Target | Maximum | All\tOther\nStock\nAwards:\nNumber\tof\nShares\tof\nStock\tor\nUnits | All\tOther\nOption\nAwards:\nNumber\tof\nSecurities\nUnder-lying\nOptions | Exercise\tor\nBase\tPrice\nof\tOption\nAwards | Grant\tDate\nFair\tValue\tof\nStock\tand\nOption\tAwards |
|  |  | ($) | ($) | ($) | (#) | (#) | (#) | (#) | (#) | ($/Sh) | ($) |
|  |  |  |  |  |  |  |  | (3) | (4) |  | (5) |
| Haley\tR. | 1/26/17 | $- | $142,120 | $284,240 |  |  |  |  |  |  |  |
| Fisackerly | 1/26/17 |  |  |  | 463 | 1,850 | 3,700 |  |  |  | $132,090 |
|  | 1/26/17 |  |  |  |  |  |  | 850 |  |  | $59,951 |
|  | 1/26/17 |  |  |  |  |  |  |  | 7,600 | $70.53 | $49,704 |
| Andrew\tS. | 1/26/17 | $- | $420,000 | $840,000 |  |  |  |  |  |  |  |
| Marsh | 1/26/17 |  |  |  | 2,075 | 8,300 | 16,600 |  |  |  | $592,620 |
|  | 1/26/17 |  |  |  |  |  |  | 6,100 |  |  | $430,233 |
|  | 1/26/17 |  |  |  |  |  |  |  | 44,000 | $70.53 | $287,760 |
| Phillip\tR. | 1/26/17 | $- | $219,690 | $439,380 |  |  |  |  |  |  |  |
| May,\tJr. | 1/26/17 |  |  |  | 788 | 3,150 | 6,300 |  |  |  | $224,910 |
|  | 1/26/17 |  |  |  |  |  |  | 1,100 |  |  | $77,583 |
|  | 1/26/17 |  |  |  |  |  |  |  | 10,500 | $70.53 | $68,670 |
| Sallie\tT. | 1/26/17 | $- | $131,310 | $262,620 |  |  |  |  |  |  |  |
| Rainer | 1/26/17 |  |  |  | 463 | 1,850 | 3,700 |  |  |  | $132,090 |
|  | 1/26/17 |  |  |  |  |  |  | 900 |  |  | $63,477 |
|  | 1/26/17 |  |  |  |  |  |  |  | 7,800 | $70.53 | $51,012 |
| Charles\tL. | 1/26/17 | $- | $114,570 | $229,140 |  |  |  |  |  |  |  |
| Rice,\tJr. | 1/26/17 |  |  |  | 463 | 1,850 | 3,700 |  |  |  | $132,090 |
|  | 1/26/17 |  |  |  |  |  |  | 550 |  |  | $38,792 |
|  | 1/26/17 |  |  |  |  |  |  |  | 3,900 | $70.53 | $25,506 |
| Richard\tC. | 1/26/17 | $- | $137,680 | $275,360 |  |  |  |  |  |  |  |
| Riley | 1/26/17 |  |  |  | 463 | 1,850 | 3,700 |  |  |  | $132,090 |
|  | 1/26/17 |  |  |  |  |  |  | 1,000 |  |  | $70,530 |
|  | 1/26/17 |  |  |  |  |  |  |  | 8,000 | $70.53 | $52,320 |
| Roderick\tK. | 1/26/17 | $- | $472,919 | $945,837 |  |  |  |  |  |  |  |
| West | 1/26/17 |  |  |  | 2,075 | 8,300 | 16,600 |  |  |  | $592,620 |
|  | 1/26/17 |  |  |  |  |  |  | 3,200 |  |  | $225,696 |
|  | 1/26/17 |  |  |  |  |  |  |  | 29,200 | $70.53 | $190,968 |

(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) 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.	 	There	 is	no	payout	under	 the	program	 if	Entergy Corporation's	total	shareholder	return	falls	within	the	lowest	quartile	of	the	peer	companies	in	the	Philadelphia	Utility	Index.		Subject	to the	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,	2019.)	 	Accrued	dividends	on	the	shares	earned	will	also	be	paid	in	Entergy	Corporation common	stock.

(3) The	amounts	in	column	(i)	represent	shares	of	restricted	stock	granted	under	the	2015	Equity	Ownership	Plan.		Shares	of	restricted	stock vest	one-third	on	each	of	the	first	through	third	anniversaries	of	the	grant	date,	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	2015	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	4	and	5	to	the	2017	Summary	Compensation	Table	for	a	discussion	of	the	relevant	assumptions	used	in	calculating	the	grant	date fair	value.

# 2017	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	December	31,	2017.

| Name | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity	Incentive<br>Plan	Awards:<br>Number	of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number	of<br>Shares	or<br>Units	of<br>Stock	That<br>Have	Not<br>Vested | Market	Value<br>of	Shares	or<br>Units	of	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	That<br>Have	Not<br>Vested | Equity<br>Incentive	Plan<br>Awards:<br>Market	or<br>Payout	Value<br>of	Unearned<br>Shares,	Units<br>or	Other<br>Rights	That<br>Have	Not<br>Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| A.\tChristopher\nBakken,\tIII | — | 37,600(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  |  |  |  |  |  |  |  | 8,300(4) | $675,537 |
|  |  |  |  |  |  |  |  | 7,289(5) | $593,252 |
|  |  |  |  |  |  | 5,200(6) | $423,228 |  |  |
|  |  |  |  |  |  | 30,000(9) | $2,441,700 |  |  |
| Marcus\tV.\nBrown | — | 44,000(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 15,000 | 30,000(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 16,000 | 8,000(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 30,500 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 16,000 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 4,600 | — |  | $71.30 | 1/26/2022 |  |  |  |  |

| Name | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive	Plan<br>Awards:<br>Number	of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number	of<br>Shares	or<br>Units	of<br>Stock	That<br>Have	Not<br>Vested | Market	Value<br>of	Shares	or<br>Units	of	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	That<br>Have	Not<br>Vested | Equity<br>Incentive	Plan<br>Awards:<br>Market	or<br>Payout	Value<br>of	Unearned<br>Shares,	Units<br>or	Other<br>Rights	That<br>Have	Not<br>Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
|  | 2,800 | — |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 7,500 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 4,300 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  |  |  | 8,300(4) | $675,537 |
|  |  |  |  |  |  |  |  | 8,200(5) | $667,398 |
|  |  |  |  |  |  | 6,100(6) | $496,479 |  |  |
|  |  |  |  |  |  | 4,267(7) | $347,291 |  |  |
|  |  |  |  |  |  | 1,667(8) | $135,677 |  |  |
| Leo\tP.\tDenault | — | 179,400(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 55,666 | 111,334(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 58,666 | 29,334(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 106,000 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 50,000 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 30,000 | — |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 25,000 | — |  | $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 |  |  |  |  |
|  |  |  |  |  |  |  |  | 48,700(4) | $3,963,693 |
|  |  |  |  |  |  |  |  | 41,700(5) | $3,393,963 |
|  |  |  |  |  |  | 17,000(6) | $1,383,630 |  |  |
|  |  |  |  |  |  | 10,467(7) | $851,909 |  |  |
|  |  |  |  |  |  | 4,000(8) | $325,560 |  |  |
| Haley\tR.\nFisackerly | — | 7,600(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 2,233 | 4,467(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 3,000 | 1,500(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 1,534 | — |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 2,900 | — |  | $72.79 | 1/27/2021 |  |  |  |  |
|  | 6,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 5,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,850(4) | $150,572 |
|  |  |  |  |  |  |  |  | 1,800(5) | $146,502 |

| Name | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive	Plan<br>Awards:<br>Number	of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number	of<br>Shares	or<br>Units	of<br>Stock	That<br>Have	Not<br>Vested | Market	Value<br>of	Shares	or<br>Units	of	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	That<br>Have	Not<br>Vested | Equity<br>Incentive	Plan<br>Awards:<br>Market	or<br>Payout	Value	of<br>Unearned<br>Shares,	Units	or<br>Other	Rights<br>That	Have	Not<br>Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
|  |  |  |  |  |  | 850(6) | $69,182 |  |  |
|  |  |  |  |  |  | 734(7) | $59,740 |  |  |
|  |  |  |  |  |  | 284(8) | $23,115 |  |  |
| Andrew\tS.\nMarsh | — | 44,000(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 15,000 | 30,000(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 16,000 | 8,000(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 35,000 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 32,000 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 10,000 | — |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 4,000 | — |  | $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 |  |  |  |  |
|  |  |  |  |  |  |  |  | 8,300(4) | $675,537 |
|  |  |  |  |  |  |  |  | 8,200(5) | $667,398 |
|  |  |  |  |  |  | 6,100(6) | $496,479 |  |  |
|  |  |  |  |  |  | 4,267(7) | $347,291 |  |  |
|  |  |  |  |  |  | 1,667(8) | $135,677 |  |  |
|  |  |  |  |  |  | 21,100(10) | $1,717,329 |  |  |
| Phillip\tR.\nMay,\tJr. | — | 10,500(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 3,200 | 6,400(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 3,333 | 1,667(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 8,000 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 6,000 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 4,600 | — |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 2,900 | — |  | $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 |  |  |  |  |
|  |  |  |  |  |  |  |  | 3,150(4) | $256,379 |
|  |  |  |  |  |  |  |  | 2,700(5) | $219,753 |
|  |  |  |  |  |  | 1,100(6) | $89,529 |  |  |
|  |  |  |  |  |  | 934(7) | $76,018 |  |  |
|  |  |  |  |  |  | 284(8) | $23,115 |  |  |

| Name | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive	Plan<br>Awards:<br>Number	of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number	of<br>Shares	or<br>Units	of<br>Stock	That<br>Have	Not<br>Vested | Market	Value<br>of	Shares	or<br>Units	of	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	That<br>Have	Not<br>Vested | Equity<br>Incentive	Plan<br>Awards:<br>Market	or<br>Payout	Value<br>of	Unearned<br>Shares,	Units<br>or	Other<br>Rights	That<br>Have	Not<br>Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Sallie\tT.\tRainer | — | 7,800(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 2,233 | 4,467(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 2,533 | 1,267(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 2,000 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 2,000 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 2,300 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,850(4) | $150,572 |
|  |  |  |  |  |  |  |  | 1,800(5) | $146,502 |
|  |  |  |  |  |  | 900(6) | $73,251 |  |  |
|  |  |  |  |  |  | 734(7) | $59,740 |  |  |
|  |  |  |  |  |  | 250(8) | $20,348 |  |  |
| Charles\tL.\nRice,\tJr. | — | 3,900(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 2,233 | 4,467(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 3,000 | 1,500(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,850(4) | $150,572 |
|  |  |  |  |  |  |  |  | 1,800(5) | $146,502 |
|  |  |  |  |  |  | 550(6) | $44,765 |  |  |
|  |  |  |  |  |  | 734(7) | $59,740 |  |  |
|  |  |  |  |  |  | 250(8) | $20,348 |  |  |
| Richard\tC.\nRiley | — | 8,000(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 1,566 | 3,134(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 3,000 | 1,500(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 5,334 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 1,334 | — |  | $64.60 | 1/31/2023 |  |  |  |  |
|  | 4,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  |  |  | 1,850(4) | $150,572 |
|  |  |  |  |  |  |  |  | 1,800(5) | $146,502 |
|  |  |  |  |  |  | 1,000(6) | $81,390 |  |  |
|  |  |  |  |  |  | 700(7) | $56,973 |  |  |
|  |  |  |  |  |  | 367(8) | $29,870 |  |  |

| Name | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Exercisable | Number	of<br>Securities<br>Underlying<br>Unexercised<br>Options<br>Unexercisable | Equity<br>Incentive	Plan<br>Awards:<br>Number	of<br>Securities<br>Underlying<br>Unexercised<br>Unearned<br>Options | Option<br>Exercise<br>Price | Option<br>Expiration<br>Date | Number	of<br>Shares	or<br>Units	of<br>Stock	That<br>Have	Not<br>Vested | Market	Value<br>of	Shares	or<br>Units	of	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	That<br>Have	Not<br>Vested | Equity<br>Incentive	Plan<br>Awards:<br>Market	or<br>Payout	Value	of<br>Unearned<br>Shares,	Units	or<br>Other	Rights<br>That	Have	Not<br>Vested |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | (#) | (#) | (#) | ($) |  | (#) | ($) | (#) | ($) |
| Roderick\tK.\nWest | — | 29,200(1) |  | $70.53 | 1/26/2027 |  |  |  |  |
|  | 13,666 | 27,334(2) |  | $70.56 | 1/28/2026 |  |  |  |  |
|  | 15,333 | 7,667(3) |  | $89.90 | 1/29/2025 |  |  |  |  |
|  | 12,000 | — |  | $63.17 | 1/30/2024 |  |  |  |  |
|  | 30,000 | — |  | $71.30 | 1/26/2022 |  |  |  |  |
|  | 7,000 | — |  | $77.10 | 1/28/2020 |  |  |  |  |
|  | 5,000 | — |  | $77.53 | 1/29/2019 |  |  |  |  |
|  | 8,000 | — |  | $108.20 | 1/24/2018 |  |  |  |  |
|  |  |  |  |  |  |  |  | 8,300(4) | $675,537 |
|  |  |  |  |  |  |  |  | 8,200(5) | $667,398 |
|  |  |  |  |  |  | 3,200(6) | $260,448 |  |  |
|  |  |  |  |  |  | 4,000(7) | $325,560 |  |  |
|  |  |  |  |  |  | 1,567(8) | $127,538 |  |  |
|  |  |  |  |  |  | 21,000(11) | $1,709,190 |  |  |

(1) Consists	of	options	that	vested	or	will	vest	as	follows:	1/3	of	the	remaining	unexercisable	options	vest	on	each	of	January	26,	2018, January	26,	2019,	and	January	26,	2020.

(2) Consists	of	options	that	vested	or	will	vest	as	follows:	1/2	of	the	remaining	unexercisable	options	vest	on	each	of	January	28,	2018	and January	28,	2019.

(3) The	remaining	unexercisable	options	vested	on	January	29,	2018.

(4) Consists	of	performance	units	that	will	vest	on	December	31,	2019	based	on	Entergy	Corporation's	total	shareholder	return	performance over	 the	 2017-2019	 performance	 period,	 as	 described	 under	 "What	 Entergy	 Corporation	 Pays	 and	 Why-	 Executive	 Compensation Elements	-	Variable	-	Long-Term	Incentive	Compensation	-	Performance	Unit	Program"	in	Compensation	Discussion	and	Analysis.

(5) Consists	of	performance	units	that	will	vest	on	December	31,	2018	based	on	Entergy	Corporation's	total	shareholder	return	performance over	the	2016-2018	performance	period.

(6) Consists	of	shares	of	restricted	stock	that	vested	or	will	vest	as	follows:		1/3	of	the	shares	of	restricted	stock	granted	vest	on	each	of January	26,	2018,	January	26,	2019,	and	January	26,	2020.

(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 January	28,	2018	and	January	28,	2019.

(8) Consists	of	shares	of	restricted	stock	that	vested	on	January	29,	2018.

(9) Consists	of	restricted	stock	units	granted	under	the	2015	Equity	Ownership	Plan	which	will	vest	one	third	on	April	6,	2019,	April	6,	2022, and	April	6,	2025.

(10) Consists	of	restricted	stock	units	granted	under	the	2015	Equity	Ownership	Plan	which	will	vest	on	August	3,	2020.

(11) Consists	of	restricted	stock	units	granted	under	the	2011	Equity	Ownership	Plan	which	will	vest	on	May	1,	2018.

# 2017	Option	Exercises	and	Stock	Vested

The	following	table	provides	information	concerning	each	exercise	of	stock	options	and	each	vesting	of	stock	during	2017	for	the	Named Executive	Officers.

|  | Options	Awards |  | Stock	Awards |  |
| :--- | :--- | :--- | :--- | :--- |
| (a) | (b) | (c) | (d) | (e) |
| Name | Number\tof\tShares\nAcquired\ton\nExercise | Value\tRealized\non\tExercise | Number\tof\tShares\nAcquired\ton\nVesting | Value\tRealized\non\tVesting\t(1) |
|  | (#) | ($) | (#) | ($) |
| A.\tChristopher\tBakken,\tIII | — | $— | 1,212 | $95,154 |
| Marcus\tV.\tBrown | 5,000 | $35,850 | 8,224 | $598,764 |
| Leo\tP.\tDenault | — | $— | 26,741 | $1,979,459 |
| Haley\tR.\tFisackerly | 10,734 | $134,837 | 1,734 | $126,435 |
| Andrew\tS.\tMarsh | — | $— | 8,224 | $598,764 |
| Phillip\tR.\tMay,\tJr. | — | $— | 2,202 | $161,139 |
| Sallie\tT.\tRainer | 11,300 | $169,289 | 1,698 | $123,893 |
| Charles\tL.\tRice,\tJr. | 9,234 | $147,762 | 1,603 | $117,185 |
| Richard\tC.\tRiley | 4,500 | $67,559 | 1,847 | $134,414 |
| Roderick\tK.\tWest | — | $— | 8,396 | $610,908 |

(1) Represents	the	value	of	performance	units	for	the	2015-2017	performance	period	(payable	solely	in	shares	based	on	the	closing	stock	price of	Entergy	Corporation	on	the	date	of	vesting)	under	the	Performance	Unit	Program	and	the	vesting	of	shares	of	restricted	stock	in	2017.

# 2017	Pension	Benefits

The	following	table	shows	the	present	value	as	of	December	31,	2017,	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.		Additional	information regarding	these	retirement	plans	follows	this	table.

| Name | Plan	Name | Number	of<br>Years<br>Credited<br>Service | Present	Value	of<br>Accumulated<br>Benefit | Payments<br>During	2017 |
| :--- | :--- | :--- | :--- | :--- |
| A.\tChristopher\tBakken,\tIII | \t Cash\tBalance\tEqualization\tPlan | 1.74 | $30,600 | $— |
|  | \t Cash\tBalance\tPlan | 1.74 | $30,300 | $— |
| Marcus\tV.\tBrown(1) | System\tExecutive\tRetirement\tPlan | 22.74 | $4,793,900 | $— |
|  | \t Entergy\tRetirement\tPlan | 22.74 | $907,400 | $— |
| Leo\tP.\tDenault\t(1)(2) | System\tExecutive\tRetirement\tPlan | 33.83 | $22,072,300 | $— |
|  | \t Entergy\tRetirement\tPlan | 18.83 | $802,000 | $— |
| Haley\tR.\tFisackerly | System\tExecutive\tRetirement\tPlan | 22.08 | $1,370,100 | $— |
|  | \t Entergy\tRetirement\tPlan | 22.08 | $789,100 | $— |
| Andrew\tS.\tMarsh | System\tExecutive\tRetirement\tPlan | 19.37 | $3,493,700 | $— |
|  | \t Entergy\tRetirement\tPlan | 19.37 | $548,400 | $— |
| Phillip\tR.\tMay,\tJr.\t(1) | System\tExecutive\tRetirement\tPlan | 31.56 | $2,398,400 | $— |
|  | \t Entergy\tRetirement\tPlan | 31.56 | $1,227,800 | $— |
| Sallie\tT.\tRainer\t(1)(3) | System\tExecutive\tRetirement\tPlan | 33.38 | $1,356,000 | $— |
|  | \t Entergy\tRetirement\tPlan | 33.00 | $1,415,200 | $— |
| Charles\tL.\tRice,\tJr. | System\tExecutive\tRetirement\tPlan | 8.47 | $609,100 | $— |
|  | \t Entergy\tRetirement\tPlan | 8.47 | $307,800 | $— |
| Richard\tC.\tRiley\t(1)(4) | System\tExecutive\tRetirement\tPlan | 28.01 | $1,688,200 | $— |
|  | \t Entergy\tRetirement\tPlan | 22.55 | $866,000 | $— |
| Roderick\tK.\tWest | System\tExecutive\tRetirement\tPlan | 18.75 | $4,636,200 | $— |
|  | \t Entergy\tRetirement\tPlan | 18.75 | $594,100 | $— |

(2) In	2006,	Mr.	Denault	entered	into	a	retention	agreement	granting	him	an	additional	15	years	of	service	and	permission	to	retire	under	the non-qualified	System	Executive	Retirement	Plan	in	the	event	his	employment	is	terminated	by	his	Entergy	employer	other	than	for	cause (as	defined	in	the	retention	agreement),	by	Mr.	Denault	for	good	reason	(as	defined	in	the	retention	agreement),	or	on	account	of	his	death or	 disability.	His	retention	agreement	also	provides	that	if	he	terminates	employment	for	any	other	reason,	he	shall	be	entitled	to	the additional	 15	 years	 of	 service	 under	 the	 non-qualified	 System	 Executive	 Retirement	 Plan	 only	 if	 his	 Entergy	 employer	 grants	 him permission	to	retire.	The	additional	15	years	of	service	increases	the	present	value	of	his	benefit	by	$3,967,700.

(3) Service	under	the	non-qualified	System	Executive	Retirement	Plan	is	granted	from	the	date	of	hire.	Qualified	plan	benefit	service	is granted	from	the	later	of	the	date	of	hire	or	the	plan	participation	date.

(4) Mr.	Riley	separated	from	Entergy	Corporation	and	was	subsequently	rehired	in	June	1995.	The	Entergy	Retirement	Plan	does	not	include any	credit	service	prior	to	his	rehire	date,	however,	the	System	Executive	Retirement	Plan	reflects	a	net	credited	service	date	of	December 28,	1989.

The tables	 below	 contain	 summaries	 of	 the	 pension	 benefit	 plans	 sponsored	 by	 Entergy	 Corporation	 that	 the	 Named	 Executive	 Officers participated	in	during	2017.	Benefits	for	the	Named	Executive	Officers	who	participate	in	these	plans	are	determined	using	the	same	formulas	as for	other	eligible	employees.

# Qualified	Retirement	Benefits

# Benefit	Timing

# Normal	retirement	age	under	the	plan	is	65.

A	reduced	vested	benefit	may	be	commenced	as	early	as age	55.	The	amount	of	this	benefit	is	determined	by reducing	the	normal	retirement	benefit	by	7%	per	year	for from	service.	The	amount	of	the	benefit	is	determined	in the	first	5	years	commencement	precedes	age	65,	and	6% per	year	for	each	additional	year	commencement	precedes described	above	in	the	"Retirement	Benefit	Formula" age	65. A	vested	cash	balance	benefit	can	be	commenced	as early	as	the	first	day	of	the	month	following	separation the	same	manner	as	the	normal	retirement	benefit section.

# 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,	the	Cash	Balance	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	non-qualified	plans,	but	is	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,	separation	from	service	due	to	disability,	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.

# Cash	Balance	Equalization

# Pension	Equalization	Plan

Executive	Annual	Incentive	Awards	are	taken payable	as	a	lump	sum	under into	account	as	eligible	earnings	under	this plan. the	Cash	Balance	Plan.

# System	Executive	Retirement	Plan

value	of	the	participant's	Entergy	Retirement Plan	benefit.

Benefit	timing Payable	at	age	65

Benefits	payable	prior	to	age	65	are	subject	to the	same	reduced	terminated	vested	or	early retirement	reduction	factors	as	benefits payable	under	the	Entergy	Retirement	Plan	as described	above.

An	employee	with	supplemental	credited service	who	terminates	employment	prior	to age	65	must	receive	prior	written	consent	of the	Entergy	employer	in	order	to	receive	the portion	of	their	benefit	attributable	to	their supplemental	credited	service	agreement.

Payable	upon	separation	from service	subject	to	6	month delay	required	under	Code Section	409A. Payable	at	age	65 Prior	to	age	65,	vesting	is	conditioned	on	the prior	written	consent	of	the	officer's	Entergy employer.

Benefits	payable	prior	to	age	65	are	subject	to the	same	reduced	terminated	vested	or subsidized	early	retirement	reduction	factors as	benefits	payable	under	the	Entergy Retirement	Plan	as	described	above.

Benefits	payable	upon	separation	from service	subject	to	the	6	month	delay	required under	Code	Section	409A.

# Additional	Information

(1) Effective	July	1,	2014,	(a)	no	new	grants	of	supplemental	service	may	be	provided	to	participants	in	the	Pension	Equalization	Plan;	(b) supplemental	credited	service	granted	prior	to	July	1,	2014	was	grandfathered;	and	(c)	participants	in	Entergy	Corporation's	Cash	Balance Plan	 are	 not	 eligible	 to	 participate	 in	 the	 Pension	 Equalization	 Plan	 and	 instead	 may	 be	 eligible	 to	 participate	 in	 the	 Cash	 Balance Equalization	Plan.

(2) Benefits	already	accrued	under	the	System	Executive	Retirement	Plan,	Pension	Equalization	Plan,	and	Cash	Balance	Equalization	Plan,	if any,	will	become	fully	vested	if	a	participant	is	involuntarily	terminated	without	cause	or	terminates	his	or	her	employment	for	good	reason in	connection	with	a	change	in	control	with	payment	generally	made	in	a	lump-sum	payment	as	soon	as	reasonably	practicable	following the	first	day	of	the	month	after	the	termination	of	employment,	unless	delayed	6	months	under	Code	Section	409A.

(3) The	System	Executive	Retirement	Plan	was	closed	to	new	executive	officers	effective	July	1,	2014.

# 2017	Non-qualified	Deferred	Compensation

As	of	December	31,	2017,	Mr.	May	had	a	deferred	account	balance	under	a	frozen	Defined	Contribution	Restoration	Plan.		The	amount	is deemed	invested,	as	chosen	by	the	participant,	in	certain	T.	Rowe	Price	investment	funds	that	are	also	available	to	the	participant	under	the Savings	Plan.		Mr.	May	has	elected	to	receive	the	deferred	account	balance	after	he	retires.	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	Code.

# Defined	Contribution	Restoration	Plan

|  |  | Defined	Contribution	Restoration	Plan | Defined	Contribution	Restoration	Plan |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Name\n(a) | Executive\nContributions\tin\n2017\n(b) | Registrant\nContributions\tin\n2017\n(c) | Aggregate\nEarnings\tin\n2017(1)\n(d) | Aggregate\nWithdrawals/Distributions\n(e) | Aggregate\nBalance\tat\nDecember\t31,\n2017\n(f) |
| Phillip\tR.\tMay,\tJr. | $— | $— | $362 | $— | $2,113 |

(1) Amounts	in	this	column	are	not	included	in	the	Summary	Compensation	Table.

# 2017	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 terminates	under	specified	conditions,	including	following	a	change	in	control	of	Entergy	Corporation	or	its	subsidiaries.	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	employer	had been	terminated	under	various	scenarios	as	of	December	31,	2017.	For	purposes	of	these	tables,	a	stock	price	of	$81.39	was	used,	which	was	the closing	market	price	on	December	29,	2017,	the	last	trading	day	of	the	year.

| Benefits	and	Payments	Upon	Termination | Voluntary<br>Resignation | For	Cause | Termination	for	Good<br>Reason	or	Not	for<br>Cause | Retirement | Disability | Death | Termination<br>Related	to	a<br>Change	in	Control |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| A.\tChristopher\tBakken,\tIII(1) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $2,511,506 |
| Performance\tUnits(7) | — | — | — | — | $620,680 | $620,680 | $1,530,132 |
| Stock\tOptions(8) | — | — | — | — | $408,336 | $408,336 | $408,336 |
| Restricted\tStock(9) | — | — | — | — | $442,029 | $442,029 | $442,029 |
| Welfare\tBenefits(10) | — | — | — | — | — | — | $20,358 |
| Unvested\tRestricted\tStock\tUnits(12) | — | — | $813,900 | — | $813,900 | $813,900 | $2,441,700 |
| Marcus\tV.\tBrown(2) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $3,213,000 |
| Performance\tUnits(7) | — | — | — | $670,165 | $670,165 | $670,165 | $1,530,132 |
| Stock\tOptions(8) | — | — | — | $802,740 | $802,740 | $802,740 | $802,740 |
| Restricted\tStock(9) | — | — | — | — | $1,041,711 | $1,041,711 | $1,054,082 |
| Welfare\tBenefits(11) | — | — | — | — | — | — | — |
| Leo\tP.\tDenault(3) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $10,119,954 |
| Performance\tUnits(6)(7) | — | — | $3,174,210 | $3,583,846 | $3,583,846 | $3,583,846 | $6,511,200 |
| Stock\tOptions(8) | — | — | $3,154,024 | $3,154,024 | $3,154,024 | $3,154,024 | $3,154,024 |
| Restricted\tStock(9) | — | — | $2,750,413 | — | $2,750,413 | $2,750,413 | $2,750,413 |
| Welfare\tBenefits(11) | — | — | — | — | — | — | — |
| Haley\tR.\tFisackerly(4) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $497,420 |
| Performance\tUnits(7) | — | — | — | — | $147,886 | $147,886 | $358,116 |
| Stock\tOptions(8) | — | — | — | — | $130,910 | $130,910 | $130,910 |
| Restricted\tStock(9) | — | — | — | — | $161,966 | $161,966 | $164,163 |
| Welfare\tBenefits(10) | — | — | — | — | — | — | $18,252 |
| Andrew\tS.\tMarsh(4) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $3,060,000 |
| Performance\tUnits(7) | — | — | — | — | $670,165 | $670,165 | $1,530,132 |
| Stock\tOptions(8) | — | — | — | — | $802,740 | $802,740 | $802,740 |
| Restricted\tStock(9) | — | — | — | — | $1,041,711 | $1,041,711 | $1,054,082 |
| Welfare\tBenefits(10) | — | — | — | — | — | — | $27,378 |
| Unvested\tRestricted\tStock\tUnits(13) | — | — | — | — | $1,717,329 | $1,717,329 | $1,717,329 |

| Benefits	and	Payments	Upon	Termination | Voluntary<br>Resignation | For	Cause | Termination	for	Good<br>Reason	or	Not	for<br>Cause | Retirement | Disability | Death | Termination<br>Related	to	a<br>Change	in	Control |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Phillip\tR.\tMay,\tJr.(2) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $1,171,680 |
| Performance\tUnits(7) | — | — | — | $231,962 | $231,962 | $231,962 | $504,618 |
| Stock\tOptions(8) | — | — | — | $183,342 | $183,342 | $183,342 | $183,342 |
| Restricted\tStock(9) | — | — | — | — | $201,034 | $201,034 | $203,231 |
| Welfare\tBenefits(11) | — | — | — | — | — | — | — |
| Sallie\tT.\tRainer(2) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $459,585 |
| Performance\tUnits(7) | — | — | — | $147,886 | $147,886 | $147,886 | $358,116 |
| Stock\tOptions(8) | — | — | — | $133,082 | $133,082 | $133,082 | $133,082 |
| Restricted\tStock(9) | — | — | — | — | $163,269 | $163,269 | $165,222 |
| Welfare\tBenefits(11) | — | — | — | — | — | — | — |
| Charles\tR.\tRice,\tJr(4) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $400,993 |
| Performance\tUnits(7) | — | — | — | — | $147,886 | $147,886 | $358,116 |
| Stock\tOptions(8) | — | — | — | — | $90,728 | $90,728 | $90,728 |
| Restricted\tStock(9) | — | — | — | — | $133,480 | $133,480 | $135,433 |
| Welfare\tBenefits(10) | — | — | — | — | — | — | $18,252 |
| Richard\tC.\tRiley(2) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $481,880 |
| Performance\tUnits(7) | — | — | — | $147,886 | $147,886 | $147,886 | $358,116 |
| Stock\tOptions(8) | — | — | — | $120,814 | $120,814 | $120,814 | $120,814 |
| Restricted\tStock(9) | — | — | — | — | $178,896 | $178,896 | $181,663 |
| Welfare\tBenefits(11) | — | — | — | — | — | — | — |
| Roderick\tK.\tWest(4) |  |  |  |  |  |  |  |
| Severance\tPayment(5) | — | — | — | — | — | — | $3,434,065 |
| Performance\tUnits(7) | — | — | — | — | $670,165 | $670,165 | $1,530,132 |
| Stock\tOptions(8) | — | — | — | — | $613,132 | $613,132 | $613,132 |
| Restricted\tStock(9) | — | — | — | — | $762,624 | $762,624 | $774,344 |
| Welfare\tBenefits(10) | — | — | — | — | — | — | $27,378 |
| Unvested\tRestricted\tStock\tUnits(14) | — | — | $1,709,190 | — | — | — | $1,709,190 |

# Pension	Benefits

1) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Bakken's	employment	were	terminated	under	certain	conditions	relating	to	a change	in	control,	on	the	first	day	of	the	month	following	the	Qualifying	Event	(as	defined	in	the	Cash	Balance	Equalization	Plan)	he would	have	become	vested	in	and	would	have	been	entitled	to	receive	his	vested	pension	benefits	accumulated	in	the	Cash	Balance Equalization	Plan	as	of	the	date	of	the	Qualifying	Event	so	long	as	a	forfeiture	event	does	not	occur	as	described	in	the	plan.	For	 a description	of	the	pension	benefits	under	the	Cash	Balance	Equalization	Plan,	see	"2017	Pension	Benefits."

2) As	of	December	31,	2017,	Messrs.	Brown,	May,	and	Riley	and	Ms.	Rainer	are	retirement	eligible	and	would	retire	rather	than	voluntarily resign,	and	in	addition	to	the	payments	and	benefits	in	the	table,	each	also	would	be	entitled	to	receive	his	or	her	vested	pension	benefits under	the	Entergy	Retirement	Plan.	For	a	description	of	the	pension

benefits	available,	see	"2017	Pension	Benefits."	In	the	event	their	termination	by	their	Entergy	employer	without	cause	or	by	Mr.	Brown, Mr.	May,	Ms.	Rainer,	or	Mr.	Riley	for	good	reason	in	connection	with	a	change	in	control,	each	would	be	eligible	for	subsidized	early retirement	 benefits	 under	 the	 System	 Executive	 Retirement	 Plan	 even	 if	 they	 do	 not	 have	 company	 permission	 to	 separate	 from employment.	If	Mr.	Brown's,	Mr.	May's,	Ms.	Rainer's,	or	Mr.	Riley's	employment	were	terminated	for	cause	in	connection	with	a	change in	 control,	 they	 would	 not	 be	 entitled	 to	 receive	 a	 benefit	 under	 the	 System	 Executive	 Retirement	 Plan.	If	 their	 employment	 were terminated	for	any	reason	not	in	connection	with	a	change	in	control,	or	they	were	to	retire	from	their	Entergy	employer	before	age	65 without	the	permission	of	their	Entergy	employer,	they	would	not	be	entitled	to	receive	a	benefit	under	the	System	Executive	Retirement Plan.

3) As	of	December	31,	2017,	Mr.	Denault	is	retirement	eligible	and	would	retire	rather	than	voluntarily	resign,	and	in	addition	to	the	payments and	benefits	in	the	table,	Mr.	Denault	also	would	be	entitled	to	receive	his	vested	pension	benefits	under	the	Entergy	Retirement	Plan.	For	a description	of	the	pension	benefits	available,	see	"2017	Pension	Benefits."	If	Mr.	Denault's	employment	was	terminated	by	his	Entergy employer	other	than	for	cause,	by	Mr.	Denault	for	good	reason	or	on	account	of	his	death	or	disability,	he	would	also	be	eligible	for	certain additional	retirement	benefits.	For	a	description	of	these	benefits,	see	"2017	Pension	Benefits."	Otherwise,	if	Mr.	Denault's	employment was	terminated	for	cause	or	he	was	to	retire	from	his	Entergy	employer	before	age	65	without	the	permission	of	his	Entergy	employer,	he would	not	receive	a	benefit	under	the	System	Executive	Retirement	Plan.

4) In	addition	to	the	payments	and	benefits	in	the	table,	if	Mr.	Fisackerly's,	Mr.	Marsh's,	Mr.	Rice's,	or	Mr.	West's	employment	were terminated	under	certain	conditions	relating	to	a	change	in	control,	each	also	would	have	been	entitled	to	receive	his	vested	pension	benefits upon	attainment	of	age	55	under	the	Entergy	Retirement	Plan	and	would	have	been	eligible	for	early	retirement	benefits	under	the	System Executive	Retirement	Plan	calculated	using	early	retirement	reduction	factors.	For	a	description	of	the	pension	benefits,	see	"2017	Pension Benefits."	Mr.	Fisackerly's,	Mr.	Marsh's,	Mr.	Rice's,	or	Mr.	West's	employment	were	terminated	for	cause	in	connection	with	a	change	in control,	he	would	not	be	entitled	to	receive	a	benefit	under	the	System	Executive	Retirement	Plan.	If	his	employment	were	terminated	for any	reason	not	in	connection	with	a	change	in	control,	or	each	were	to	resign	from	his	Entergy	employer	before	age	65	without	the permission	of	his	Entergy	employer,	each	would	not	be	entitled	to	receive	a	benefit	under	the	System	Executive	Retirement	Plan.

# Severance	Payments:

5) In	the	event	of	a	termination	by	the	executive	for	good	reason	or	by	his	or	her	Entergy	system	employer	not	for	cause	during	the	period beginning	upon	the	occurrence	of	a	"potential	change	in	control"	(as	defined	in	the	System	Executive	Continuity	Plan)	and	ending	on	the 2nd	anniversary	of	a	change	in	control,	each	Named	Executive	Officer	would	be	entitled	to	receive	pursuant	to	the	System	Executive Continuity	Plan	a	lump	sum	severance	payment	equal	to	a	multiple	of	the	sum	of	(1)	his	or	her	annual	base	salary	as	in	effect	at	any	time within	one	year	prior	to	the	commencement	of	a	change	of	control	period	or,	if	higher,	immediately	prior	to	a	circumstance	constituting good	reason	plus	(2)	his	or	her	annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under	the	Annual	Incentive Plan	for	2015	and	2016	(the	two	calendar	years	immediately	preceding	the	calendar	year	in	which	termination	occurs),	but	in	no	event	shall the	severance	payment	exceed	the	product	of	2.99	times	the	sum	of	(a)	his	or	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)	the	higher	of	his	or	her	actual	annual	incentive	payment	under	the	Annual	Incentive	Plan	for	the	2016	performance	year	or	his	or	her annual	incentive,	calculated	using	the	average	annual	target	opportunity	derived	under	the	Annual	Incentive	Plan	for	2015	and	2016	(the two	calendar	years	immediately	preceding	the	calendar	year	in	which	termination	occurs).	For	purposes	of	this	table,	the	following	target opportunity	and	base	salary	were	assumed:

| Named	Executive	Officer | Target<br>Opportunity | Base	Salary |
| :--- | :--- | :--- |
| A.\tChristopher\tBakken\tIII | 35% | $620,125 |
| Marcus\tV.\tBrown | 70% | $630,000 |
| Leo\tP.\tDenault | 130% | $1,230,000 |
| Haley\tR.\tFisackerly | 40% | $355,300 |
| Andrew\tS.\tMarsh | 70% | $600,000 |
| Phillip\tR.\tMay\tJr, | 60% | $366,150 |
| Sallie\tT.\tRainer | 40% | $328,275 |
| Charles\tL.\tRice,\tJr. | 40% | $286,424 |
| Richard\tC.\tRiley | 40% | $344,200 |
| Roderick\tK.\tWest | 70% | $675,598 |

# Performance	Units:

6) With	respect	to	Mr.	Denault,	in	the	event	of	a	Termination	Event	(as	defined	in	Mr.	Denault's	2006	retention	agreement),	he	is	entitled	to	a Target	LTIP	Award,	as	defined	in	his	2006	retention	agreement,	calculated	by	using	the	average	annual	number	of	performance	units	with respect	to	the	two	most	recent	performance	periods	preceding	the	calendar	year	in	which	his	employment	termination	occurs,	assuming	all performance	goals	were	achieved	at	target.	For	purposes	of	the	table,	the	value	of	Mr.	Denault's	retention	payment	was	calculated	by	taking an	average	of	the	target	performance	units	from	the	2013-2015	Performance	Unit	Program	(38,000)	and	from	the	2014-2016	Performance Unit	Program	(40,000).	This	average	number	of	units	(39,000)	multiplied	by	the	closing	price	of	Entergy	Corporation's	common	stock	on December	29,	2017	($81.39)	would	equal	a	payment	of	$3,174,210.	In	the	event	of	death	or	disability,	Mr.	Denault	receives	the	greater	of	the Target	LTIP	Award	calculated	as	described	above	or	the	sum	of	the	amount	that	would	be	payable	under	the	provisions	of	each	open Performance	Unit	Program	as	described	in	Note	7	below.

7) In	the	event	of	a	qualifying	termination	related	to	a	change	in	control,	each	Named	Executive	Officer	would	have	forfeited	his	or	her performance	units	for	the	2016-2018	and	2017-2019	performance	periods	and	would	have	been	entitled	to	receive,	pursuant	to	the	2015 Equity	Ownership	Plan,	a	single-lump	sum	payment	in	lieu	of	any	payment	for	each	performance	award	that	would	not	be	based	on	any outstanding	performance	period.	The	payments	for	the	2016-2018	and	the	2017-2019	performance	periods	would	have	been	calculated	using the	most	recent	performance	period	preceding	(but	not	including)	the	calendar	year	in	which	his	or	her	termination	occurs.	For	purposes	of the	table,	the	value	of	Mr.	Denault's	payments	was	calculated	by	multiplying	the	target	performance	units	for	the	2014-2016	Performance Unit	Program	(40,000)	by	the	closing	price	of	Entergy	Corporation's	common	stock	on	December	29,	2017	($81.39),	which	would	equal	a payment	of	$3,255,600	for	the	forfeited	performance	units	for	each	performance	period.	The	value	of	the	payments	for	the	other	Named Executive	Officers	was	calculated	by	multiplying	the	target	performance	units	for	the	2014-2016	Performance	Unit	Program	(9,400)	by	the closing	price	of	Entergy	Corporation's	common	stock	on	December	29,	2017	($81.39),	which	would	equal	a	payment	of	$765,066	for	the forfeited	performance	units	for	each	performance	period.	In	the	event	his	death	or	disability,	Mr.	Denault	would	receive	the	greater	of	the target	Long-Term	Performance	Incentive	award	as	described	 in	note	6	above	or	a	pro-rated	number	of	performance	units	for	all	open performance	periods,	based	on	the	number	of	months	of	his	participation	in	each	open	performance	period.

In	the	event	of	retirement	in	the	case	of	Mr.	Brown,	Mr.	Denault,	Mr.	May,	Ms.	Rainer,	or	Mr.	Riley,	or	upon	death	or	disability,	other	than Mr.	Denault,	each	Named	Executive	Officer	would	not	have	forfeited	his	or	her	performance	units	for	all	open	performance	periods,	but rather	such	performance	unit	awards	would	have	been	pro-rated	based	on	his	or	her	number	of	months	of	participation	 in	each	open Performance	Unit	Program	performance	period,	in	accordance	with	his	grant	agreement	under	the	Performance	Unit	Program.	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	values	of	the	awards	were	calculated	as	follows:

# Mr.	Denault's:

Messrs.	Brown's,	Marsh's,	and	West's:

Messrs.	Fisackerly's,	Rice's,	Riley's,	and	Ms.	Rainer's:

8) In	 the	event	of	death	or	disability	or	qualifying	 termination	related	 to	a	change	 in	control,	or	retirement	 in	 the	case	of	Mr.	Brown, Mr.	Denault,	Mr.	May,	Ms.	Rainer,	or	Mr.	Riley,	all	of	the	unvested	stock	options	of	each	Named	Executive	Officer	would	immediately vest	pursuant	to	the	Equity	Ownership	Plans.	In	addition,	with	respect	to	grants	under	the	2011	Equity	Ownership	Plan,	each	Named Executive	Officer	would	be	entitled	to	exercise	his	or	her	stock	options	for	the	remainder	of	the	ten-year	period	extending	from	the	grant date	of	the	options,	and	with	respect	to	grants	under	the	2015	Equity	Ownership	Plan,	within	the	lesser	of	five	years	or	the	remaining	term of	the	option	grant.	For	purposes	of	this	table,	it	is	assumed	that	the	Named	Executive	Officers	exercised	their	options	immediately	upon vesting	and	received	proceeds	equal	to	the	difference	between	the	closing	price	of	common	stock	on	December	29,	2017,	and	the	applicable exercise	price	of	each	option	share.

In	the	event	of	a	Termination	Event	as	defined	in	his	2006	retention	agreement,	Mr.	Denault	will	immediately	vest	in	all	unvested	stock options.

# Restricted	Stock:

9) In	the	event	of	death	or	disability	pursuant	to	the	2011	Equity	Ownership	Plan,	each	Named	Executive	Officer	would	immediately	vest	in	a pro-rated	portion	of	his	or	her	unvested	restricted	stock	that	was	otherwise	scheduled	to	become	vested	on	the	immediately	following	12- month	grant	date	anniversary	date,	as	well	as	dividends	declared	on	the	pro-rated	portion	of	such	restricted	stock	pursuant	to	the	2011 Equity	Ownership	Plan.	The	pro-rated	vested	portion	would	be	determined	based	on	the	number	of	days	between	the	most	recent	preceding 12-month	grant	date	anniversary	date	and	the	date	of	his	or	her	death	or	disability.	In	the	event	of	his	or	her	qualifying	termination	related to	a	change	in	control,	a	Named	Executive	Officer	would	immediately	vest	in	all	of	their	unvested	restricted	stock,	as	well	as	dividends declared	 on	 such	 restricted	 stock	 granted	 pursuant	 the	 2011	 Equity	 Ownership	 Plan.	In	 the	 event	 of	 death,	 disability,	 or	 qualifying termination	related	to	a	change	in	control,	each	Named	Executive	Officer	would	vest	in	all	of	their	unvested	restricted	stock	as	well	as dividends	declared	pursuant	to	the	2015	Equity	Ownership	Plan.

In	the	event	of	a	Termination	Event	as	defined	in	his	2006	retention	agreement,	Mr.	Denault	will	immediately	vest	in	all	unvested	restricted stock.

# Welfare	Benefits:

10) Pursuant	to	the	System	Executive	Continuity	Plan,	in	the	event	of	a	termination	related	to	a	change	in	control,	Mr.	Bakken,	Mr.	Marsh,	and Mr.	West	would	be	eligible	to	receive	Entergy-sponsored	COBRA	benefits	for	18	months	and	Mr.	Fisackerly	and	Mr.	Rice	would	be eligible	to	receive	Entergy-sponsored	COBRA	benefits	for	12	months.

11) Upon	retirement,	Mr.	Brown,	Mr.	Denault,	Mr.	May,	Ms.	Rainer,	and	Mr.	Riley	would	be	eligible	for	retiree	medical	and	dental	benefits, the	same	as	all	other	retirees.

# Unvested	Restricted	Stock	Units:

12) Mr.Bakken's	30,000	restricted	stock	units	vest	1/3 rd	on	each	of	April	6,	2019,	April	6,	2022,	and	April	6,	2025.	Pursuant	to	his	restricted stock	unit	agreement,	if	Mr.	Bakken's	employment	terminates	due	to	total	disability	or	death	or,	prior	to	April	6,	2019,	Mr.	Bakken's employment	is	terminated	by	his	Entergy	employer	other	than	for	cause,	then	he	will	vest	in	and	be	paid	the	10,000	restricted	stock	units that	otherwise	would	have	vested	had	he	satisfied	the	vesting	conditions	of	the	restricted	stock	unit	agreement	through	the	next	vesting	date to	occur	following	his	date	of	total	disability,	death,	or	termination	other	than	for	cause	prior	to	April	6,	2019	subject,	in	the	case	of	a termination	without	cause,	to	Mr.	Bakken	timely	executing	and	not	revoking	a	release	of	claims	against	Entergy	Corporation	and	its affiliates.	In	 the	 event	 of	 a	 change	 in	 control,	 the	 unvested	 restricted	 stock	 units	 will	 fully	 vest	 upon	 Mr.	 Bakken's	 termination	 of employment	by	his	Entergy	employer	without	cause	or	by	Mr.	Bakken	with	good	reason	during	a	change	in	control	period	(as	defined	in	the 2015	Equity	Ownership	Plan).	Otherwise,	if	Mr.	Bakken	voluntarily	resigns	or	is	terminated,	he	would	forfeit	these	units.	Pursuant	to	his restricted	stock	unit	agreement,	Mr.	Bakken	is	subject	to	certain	restrictions	on	his	ability	to	compete	with	Entergy	Corporation	and	its affiliates	or	solicit	its	employees	or	customers	during	and	for	12	months	after	his	employment	with	his	Entergy	employer.	In	addition,	the restricted	stock	unit	agreement	limits	Mr.	Bakken's	ability	to	disparage	Entergy	Corporation	and	its	affiliates.	In	the	event	of	a	breach	of these	restrictions,	other	than	following	certain	constructive	terminations	of	his	employment,	Mr.	Bakken	will	forfeit	any	restricted	stock units	that	are	not	yet	vested	and	paid,	and	must	repay	to	Entergy	Corporation	any	shares	of	Entergy	Corporation's	common	stock	paid	to him	in	respect	of	the	restricted	stock	units	and	any	amounts	he	received	upon	the	sale	or	transfer	of	any	such	shares.

13) Mr.	Marsh's	21,100	restricted	stock	units	vest	100%	in	2020.	Pursuant	to	his	restricted	stock	unit	agreement,	any	unvested	restricted	stock units	will	vest	immediately	in	the	event	of	his	termination	of	employment	due	to	Mr.	Marsh's	total	disability	or	death.	In	the	event	of	a change	in	control,	the	units	will	vest	upon	termination	of	Mr.	Marsh's	employment	by	his	Entergy	employer	without	cause	or	by	Mr.	Marsh with	good	reason	during	a	change	in	control	period	(as	defined	in	the	2015	Equity	Ownership	Plan).	Otherwise,	if	Mr.	Marsh	voluntarily resigns	or	is	terminated,	he	would	forfeit	these	units.	Pursuant	to	his	restricted	stock	unit	agreement,	Mr.	Marsh	is	subject	to	certain restrictions	on	his	ability	to	compete	with	Entergy	Corporation	and	its	affiliates	during	and	for	12	months	after	his	employment	with Entergy	Corporation,	or	to	solicit	its	employees	or	customers	during	and	for	24	months	after	his	employment	with	it.	In	addition,	the restricted	stock	unit	agreement	limits	Mr.	Marsh's	ability	to	disparage	Entergy	Corporation	and	its	affiliates.	In	the	event	of	a	breach	of these	restrictions,	Mr.	Marsh	will	forfeit	any	restricted	stock	units	that	are	not	yet	vested	and	paid,	and	must	repay	to	Entergy	Corporation any	shares	of	Entergy	Corporation's	common	stock	paid	to	him	in	respect	of	the	restricted	stock	units	and	any	amounts	he	received	upon the	sale	or	transfer	of	any	such	shares.

14) Mr.	West's	21,000	restricted	stock	units	vest	100%	in	2018.	Pursuant	to	his	restricted	stock	unit	agreement,	any	unvested	restricted	stock units	will	vest	immediately	in	the	event	of	a	termination	other	than	for	cause.	In	the	event	of	a	change	in	control,	the	units	will	vest	upon termination	of	Mr.	West's	employment	by	his	Entergy	employer	without	cause	or	by	Mr.	West	with	good	reason	during	a	change	in	control period	(as	defined	 in	 the	2011	Equity	Ownership	Plan).	Otherwise,	 if	Mr.	West	voluntarily	resigns,	 is	 terminated	for	cause,	dies,	or becomes	disabled,	he	would	forfeit	these	units.

# Mr.	Denault's	2006	Retention	Agreement

Under	the	terms	of	his	2006	retention	agreement,	Mr.	Denault's	employment	may	be	terminated	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	Corporation;

•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	Corporation's	reputation;

•material	violation	of	any	agreement	that	he	has	entered	into	with	Entergy	Corporation;	or

•unauthorized	disclosure	of	Entergy	Corporation'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	from	those	in	effect	immediately	prior	to	the	date	of the	retention	agreement,	other	than	de	minimis	acts	that	are	remedied	after	notice	from	Mr.	Denault;

•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	Entergy	Corporation's	pension,	savings,	life	insurance,	medical,	health	and	accident, disability,	or	vacation	plans	or	policies	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.

# System	Executive	Continuity	Plan

# Termination	Related	to	a	Change	in	Control

Entergy	 Corporation's	 Named	 Executive	 Officers	 will	 be	 entitled	 to	 the	 benefits	 described	 in	 the	 tables	 above	 under	 the	 System Executive	Continuity	Plan	in	the	event	of	a	termination	related	to	a	change	in	control	if	a	change	in	control	occurs	and	their	employment	is terminated	by	their	Entergy	employer	other	than	for	cause	or	if	they	terminate	their	employment	for	good	reason,	in	each	case	within	a	period beginning	on	the	occurrence	of	a	potential	change	in	control	and	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	 Entergy	 Corporation's common stock	 or the combined	 voting	 power	 of	 Entergy Corporation's	voting	securities;

•the	merger	or	consolidation	of	Entergy	Corporation	(unless	its	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.

A	potential	change	in	control	includes	the	following	events:

•Entergy	Corporation	or	an	affiliate	enters	into	an	agreement	the	consummation	of	which	would	constitute	a	change	in	control; •the	Entergy	Corporation	Board	adopts	resolutions	determining	 that,	for	purposes	of	 the	System	Executive	Continuity	Plan,	a potential	change	in	control	has	occurred;

•a	System	Company	or	other	person	or	entity	publicly	announces	an	intention	to	take	actions	that	would	constitute	a	change	in control;	or

•any	person	or	entity	becomes	the	beneficial	owner	(directly	or	indirectly)	of	outstanding	shares	of	Entergy	Corporation's	common stock	constituting	20%	or	more	of	the	voting	power	or	value	of	Entergy	Corporation's	outstanding	common	stock.

A	Named	Executive	Officer's	employment	may	be	terminated	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	Entergy	Corporation's	Board;

•engages	in	conduct	that	is	materially	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	his	or	her	employment	with	his	or	her	Entergy	employer	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	his	or	her	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	Entergy	employer	purports	to	terminate	his	or	her	employment	other	than	in	accordance	with	the	System	Executive Continuity	Plan.

In	addition	to	participation	in	the	System	Executive	Continuity	Plan,	benefits	already	accrued	under	the	System	Executive	Retirement Plan,	Pension	Equalization	Plan,	and	Cash	Balance	Equalization	Plan,	if	any,	will	become	fully	vested	if	the	executive	is	involuntarily	terminated without	cause	or	the	executive	terminates	his	or	her	employment	for	good	reason	within	two	years	after	the	occurrence	of	a	change	in	control.	Any awards	granted	under	the	Equity	Ownership	Plans	will	become	fully	vested	if	the	executive	is	involuntarily	terminated	without	cause	or	terminates employment	for	good	reason	within	two	years	after	the	occurrence	of	a	change	in	control.

Under	certain	circumstances	described	below,	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	his	or	her	non-compete	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	his	or	her	non-compete	provision,	he	or	she	will	be	required	to	repay	any	benefits	previously	received	under	the	System	Executive Continuity	Plan.

# Voluntary	Resignation

If	a	Named	Executive	Officer	voluntarily	resigns	from	his	or	her	Entergy	employer:

•all	unvested	stock	options,	shares	of	restricted	stock	and	restricted	stock	units	as	well	as	any	perquisites	to	which	he	or	she	is	entitled as	an	officer	are	forfeited;

•incentive	payments	under	any	outstanding	performance	periods	under	 the	Long-Term	Performance	Unit	Program	or	 the	Annual Incentive	Plan	are	forfeited;	provided	however,	if	an	officer	resigns	after	the	completion	of	an	Annual	Incentive	Plan	or	Long-Term Performance	Unit	Program	performance	period,	he	or	she	could	receive	a	payout	under	the	Long-Term	Performance	Unit	Program based	on	the	outcome	of	the	performance	period	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;	and

•he	or	she	is	entitled	to	all	vested	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.

# Termination	for	Cause

If	a	Named	Executive	Officer's	employment	is	terminated	for	"cause"	(as	defined	in	the	System	Executive	Continuity	Plan	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	above	under	"Voluntary	Resignation,"	except	that	all	options	are	no	longer	exercisable.

# Retirement

# Upon	a	Named	Executive	Officer's	retirement:

•the	annual	incentive	payment	under	the	Annual	Incentive	Plan	is	generally	pro-rated	based	on	the	actual	number	of	days	employed during	the	performance	year	in	which	the	retirement	date	occurs,	subject	to	negative	discretion	that	may	be	applied	to	reduce	or disallow	the	payment;	payments	are	delivered	at	the	conclusion	of	the	annual	period,	consistent	with	the	timing	of	payments	to	active participants	in	the	Annual	Incentive	Plan;

•payments	under	the	Long-Term	Performance	Unit	Program	for	those	retiring	with	a	minimum	of	12	months	of	participation	are	pro- rated	based	on	the	actual	full	months	of	participation	in	each	outstanding	performance	period	in	which	the	retirement	date	occurs,	and payments	are	delivered	at	the	conclusion	of	each	performance	period,	consistent	with	the	timing	of	payments	to	active	participants	in the	Long-Term	Performance	Unit	Program;

•unvested	stock	options	issued	under	the	2011	Equity	Ownership	Plan	vest	on	the	retirement	date	and	expire	ten	years	from	the	grant date	of	the	options;

•unvested	stock	options	issued	under	the	2015	Equity	Ownership	Plan	vest	on	the	retirement	date	and	expire	the	earlier	of	five	years from	the	grant	date	of	the	options	or	the	original	term	of	ten	years;

•any	unvested	restricted	stock	and	restricted	stock	units	held	by	the	executive	upon	his	retirement	are	forfeited;	and •he	or	she	is	generally	entitled	to	all	vested	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.

# 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	unvested	restricted	stock	and	restricted	stock	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	 employer,	 he	 or	 she	 generally	 is	 entitled	 to	 the	 same compensation	and	separation	benefits	described	above	under	"Retirement,"	except	that	unvested	restricted	stock	and	restricted	stock	units	may	be subject	to	specific	death	benefits	as	noted,	where	applicable,	in	the	tables	above.

# Pay	Ratio

As	required	by	Section	953(b)	of	the	Dodd-Frank	Wall	Street	Reform	and	Consumer	Protection	Act,	the	following	disclosure	is	being provided	about	the	relationship	of	the	annual	total	compensation	of	the	employees	of	each	of	the	Utility	operating	companies	to	the	annual	total compensation	of	their	respective	Presidents	and	Chief	Executive	Officers.

# Identification	of	Median	Employee

For	each	of	the	Utility	operating	companies,	October	6,	2017	was	selected	as	the	date	on	which	to	determine	the	median	employee.	To identify	the	median	employee	from	each	of	the	Utility	operating	companies'	employee	population	base,	all	compensation	included	in	Box	5	of Form	W-2	was	considered	with	all	before-tax	deductions	added	back	to	this	compensation	(Box	5	Compensation).	For	purposes	of	determining the	 median	 employee	 of	 each	 Utility	 operating	 company,	 Box	 5	 Compensation	 was	 selected	 as	 it	 is	 believed	 it	 is	 representative	 of	 the compensation	received	by	the	employees	of	each	respective	Utility	operating	company	and	is	readily	available.	The	calculation	of	annual	total compensation	of	the	median	employee	for	each	Utility	operating	company	is	the	same	calculation	used	to	determine	total	compensation	for purposes	of	the	2017	Summary	Compensation	Table	with	respect	to	each	of	the	Named	Executive	Officers.

# Entergy	Arkansas	Ratio

•Mr.	Riley's	annual	total	compensation,	as	reported	in	the	Total	column	of	the	2017	Summary	Compensation	Table,	was	$1,353,719.

•The	annual	total	compensation	of	the	median	employee	was	$127,560.

•Based	on	this	information,	the	ratio	of	the	annual	total	compensation	of	Mr.	Riley	to	the	median	employee	is	estimated	to	be	11:1.

# Entergy	Louisiana	Ratio

•Mr.	May's	annual	total	compensation,	as	reported	in	the	Total	column	of	the	2017	Summary	Compensation	Table,	was	$1,564,954. •The	annual	total	compensation	of	the	median	employee	was	$144,954.

•Based	on	this	information,	the	ratio	of	the	annual	total	compensation	of	Mr.	May	to	the	median	employee	is	estimated	to	be	11:1.

# Entergy	Mississippi	Ratio

•Mr.	Fisackerly's	annual	total	compensation,	as	reported	in	the	Total	column	of	the	2017	Summary	Compensation	Table,	was	$1,207,343. •The	annual	total	compensation	of	the	median	employee	was	$112,110.

•Based	on	this	information,	the	ratio	of	the	annual	total	compensation	of	Mr.	Fisackerly	to	the	median	employee	is	estimated	to	be	11:1.

# Entergy	New	Orleans	Ratio

•Mr.	Rice's	annual	total	compensation,	as	reported	in	the	Total	column	of	the	2017	Summary	Compensation	Table,	was	$824,111.

•The	annual	total	compensation	of	the	median	employee	was	$91,346.

•Based	on	this	information,	the	ratio	of	the	annual	total	compensation	of	Mr.	Rice	to	the	median	employee	is	estimated	to	be	9:1.

# Entergy	Texas	Ratio

•Ms.	Rainer's	annual	total	compensation,	as	reported	in	the	Total	column	of	the	2017	Summary	Compensation	Table,	was	$1,200,260. •The	annual	total	compensation	of	the	median	employee	was	$129,877.

•Based	on	this	information,	the	ratio	of	the	annual	total	compensation	of	Ms.	Rainer	to	the	median	employee	is	estimated	to	be	9:1.

# Item	12.		Security	Ownership	of	Certain	Beneficial	Owners	and	Management

Entergy	Corporation	owns	100%	of	the	outstanding	common	stock	of	registrants	Entergy	Arkansas,	Entergy	Mississippi,	Entergy	Texas, and	indirectly	100%	of	the	outstanding	common	membership	interests	of	registrant	Entergy	Louisiana	and	Entergy	New	Orleans.		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	"Entergy	Share	Ownership	-	Beneficial	Owners	of	More	Than	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, 2018	for	all	non-employee	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.

# Options	Exercisable	Within	60

# Stock	Units	(3)

| Name | Shares	(1)(2) | Options	Exercisable	Within	60<br>Days | Stock	Units	(3) |
| :--- | :--- | :--- | :--- |
| Entergy\tCorporation |  |  |  |
| A.\tChristopher\tBakken,\tIII** | 10,710 | 12,533 | — |
| Maureen\tS.\tBateman* | 22,716 | — | — |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Patrick\tJ.\tCondon* | 4,460 | — | — |
| Leo\tP.\tDenault*** | 133,457 | 565,133 | — |
| Kirkland\tH.\tDonald* | 5,736 | — | 1,389 |
| Philip\tL.\tFrederickson* | 2,775 | — | 805 |
| Alexis\tM.\tHerman* | 12,581 | — | — |
| Donald\tC.\tHintz* | 15,096 | — | 3,942 |
| Stuart\tL.\tLevenick* | 18,047 | — | — |
| Blanche\tL.\tLincoln* | 11,004 | — | — |
| Andrew\tS.\tMarsh** | 60,425 | 166,766 | — |
| Karen\tA.\tPuckett* | 4,460 | — | — |
| W.\tJ.\tTauzin* | 17,809 | — | — |
| Roderick\tK.\tWest** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(19\tpersons) | 444,591 | 1,112,495 | 6,136 |
| Entergy\tArkansas |  |  |  |
| A.\tChristopher\tBakken,\tIII** | 10,710 | 12,533 | — |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Leo\tP.\tDenault** | 133,457 | 565,133 | — |
| Andrew\tS.\tMarsh*** | 60,425 | 166,766 | — |
| Richard\tC.\tRiley*** | 11,169 | 16,967 | — |
| Roderick\tK.\tWest*** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(10\tpersons) | 341,076 | 1,129,462 | — |
| Entergy\tLouisiana |  |  |  |
| A.\tChristopher\tBakken,\tIII** | 10,710 | 12,533 | — |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Leo\tP.\tDenault** | 133,457 | 565,133 | — |
| Andrew\tS.\tMarsh*** | 60,425 | 166,766 | — |
| Phillip\tR.\tMay,\tJr.*** | 18,203 | 47,100 | 12 |
| Roderick\tK.\tWest*** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(10\tpersons) | 348,110 | 1,159,595 | 12 |

| Name | Shares	(1)(2) | Options	Exercisable	Within	60<br>Days | Stock	Units	(3) |
| :--- | :--- | :--- | :--- |
| Entergy\tMississippi |  |  |  |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Leo\tP.\tDenault** | 133,457 | 565,133 | — |
| Haley\tR.\tFisackerly*** | 6,605 | 21,933 | — |
| Andrew\tS.\tMarsh*** | 60,425 | 166,766 | — |
| Roderick\tK.\tWest*** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(9\tpersons) | 325,802 | 1,121,895 | — |
| Entergy\tNew\tOrleans |  |  |  |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Leo\tP.\tDenault** | 133,457 | 565,133 | — |
| Andrew\tS.\tMarsh*** | 60,425 | 166,766 | — |
| Charles\tL.\tRice,\tJr.*** | 5,855 | 10,266 | — |
| Roderick\tK.\tWest*** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(9\tpersons) | 325,052 | 1,110,228 | — |
| Entergy\tTexas |  |  |  |
| Marcus\tV.\tBrown** | 27,803 | 130,066 | — |
| Leo\tP.\tDenault** | 133,457 | 565,133 | — |
| Andrew\tS.\tMarsh*** | 60,425 | 166,766 | — |
| Sallie\tT.\tRainer*** | 7,884 | 14,866 | — |
| Roderick\tK.\tWest*** | 42,475 | 114,066 | — |
| All\tdirectors\tand\texecutive\tofficers\tas\ta\ngroup\t(9\tpersons) | 327,081 | 1,114,828 | — |

* Director	of	the	respective	Company

** 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	non-employee	directors	and	executive officers	as	a	group	does	not	exceed	one	percent	of	the	outstanding	shares	of	Entergy	Corporation	common	stock.

(2) For	 the	non-employee	directors,	 the	balances	 include	phantom	units	 that	are	 issued	under	 the	Service	Recognition	Program.	All	 non- employee	directors	are	credited	with	phantom	units	for	each	year	of	service	on	the	Entergy	Corporation	Board.	These	phantom	units	do	not have	voting	rights,	accrue	dividends,	and	will	be	settled	in	shares	of	Entergy	Corporation	common	stock	following	the	non-employee director's	separation	from	the	Board.

(3) 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.		Messrs.	Donald,	Hintz,	and	Frederickson	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,	2017.	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	be<br>Issued	Upon	Exercise	of<br>Outstanding	Options	(a) | Weighted<br>Average<br>Exercise	Price<br>(b) | Number	of	Securities<br>Remaining	Available	for<br>Future	Issuance	(excluding<br>securities	reflected	in	column<br>(a))(c) |
| :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans\tapproved\tby\nsecurity\tholders\t(1) | 5,164,854 | $83.26 | 3,498,788 |
| Equity\tcompensation\tplans\tnot\tapproved\tby\nsecurity\tholders(2) | — | — | — |
| Total | 5,164,854 | $83.26 | 3,498,788 |

(1) Includes	the	2007	Equity	Ownership	Plan,	the	2011	Equity	Ownership	Plan,	and	the	2015	Equity	Ownership	Plan.	 	The	2007	Equity Ownership	Plan	was	approved	by	Entergy	Corporation	shareholders	on	May	12,	2006,	and	only	applied	to	awards	granted	between	January 1,	2007	and	May	5,	2011.	The	2011	Equity	Ownership	Plan	was	approved	by	Entergy	Corporation	shareholders	on	May	6,	2011,	and	only applied	to	awards	granted	between	May	6,	2011	and	May	7,	2015.		The	2015	Equity	Ownership	Plan	was	approved	by	Entergy	Corporation shareholders	on	May	8,	2015,	and	6,900,000	shares	of	Entergy	Corporation	common	stock	can	be	issued	from	the	2015	Equity	Ownership Plan,	with	no	more	than	1,500,000	shares	available	for	incentive	stock	option	grants.		The	2015	Plan	applies	to	awards	granted	on	or	after May	8,	2015.	The	2007	Equity	Ownership	Plan,	the	2011	Equity	Ownership	Plan,	and	the	2015	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	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	stock,	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),	restricted	stock	unit	awards,	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,	2017,	all	options	outstanding	under	the	plan	were	either	exercised	or	expired.

# Item	13.		Certain	Relationships	and	Related	Party	Transactions	and	Director	Independence

For	information	regarding	certain	relationship,	related	transactions	and	director	independence	of	Entergy	Corporation,	see	the	Proxy Statement	under	the	headings	"Corporate	Governance	at	Entergy	-	Director	Independence"	and	"Corporate	Governance	at	Entergy	-	Governance Policies	-	Our	Transactions	with	Related	Party	Persons	Policy."

Entergy	Corporation's	Board	of	Directors	has	adopted	written	policies	and	procedures	for	the	review,	approval	or	ratification	of	any transaction	involving	an	amount	in	excess	of	$120,000	in	which	any	director	or	executive	officer	of	Entergy	Corporation,	any	nominee	for director,	or	any	immediate	family	member	of	the	foregoing	has	or	will	have	a	material	interest	as	contemplated	by	Item	404(a)	of	Regulation	S-K ("Related	 Person	 Transactions").	Under	 these	 policies	 and	 procedures,	 Entergy	 Corporation's	 Corporate	 Governance	 Committee	 or	 a subcommittee	of	its	Board	of	Directors	consisting	entirely	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	that	are	at	least	as	favorable	to	Entergy	Corporation	as	those	achievable	with	an unaffiliated	third	party;

•Size	of	the	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;	and

•Any	other	factors	that	the	Corporate	Governance	Committee	or	subcommittee	deems	relevant.

The	policy	does	not	apply	to	(a)	compensation	and	related	person	transactions	involving	a	director	or	an	executive	officer	solely	resulting from	that	person's	service	as	a	director	or	employment	with	Entergy	Corporation	so	long	as	the	compensation	is	approved	by	the	Board	of Directors	(or	an	appropriate	committee),	(b)	transactions	involving	public	utility	services	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	S-K.

# Related	Party	Transactions

Since	January	1,	2017,	neither	Entergy	Corporation	nor	any	of	its	affiliates	has	participated	in	any	Related	Person	Transaction.

# Item	14.		Principal	Accountant	Fees	and	Services	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,

# Entergy	New	Orleans,	Entergy	Texas,	and	System	Energy)

Aggregate	fees	billed	to	Entergy	Corporation	(consolidated),	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New Orleans,	Entergy	Texas,	and	System	Energy	for	the	years	ended	December	31,	2017	and	2016	by	Deloitte	&	Touche	LLP	were	as	follows:

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Entergy\tCorporation\t(consolidated) |  |  |
| Audit\tFees | $8,401,895 | $8,932,000 |
| Audit-Related\tFees\t(a) | 875,000 | 865,000 |
| Total\taudit\tand\taudit-related\tfees | 9,276,895 | 9,797,000 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $9,276,895 | $9,797,000 |
| Entergy\tArkansas |  |  |
| Audit\tFees | $1,018,860 | $1,056,881 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 1,018,860 | 1,056,881 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $1,018,860 | $1,056,881 |
| Entergy\tLouisiana |  |  |
| Audit\tFees | $1,887,719 | $2,138,762 |
| Audit-Related\tFees\t(a) | 500,000 | 450,000 |
| Total\taudit\tand\taudit-related\tfees | 2,387,719 | 2,588,762 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $2,387,719 | $2,588,762 |
| Entergy\tMississippi |  |  |
| Audit\tFees | $933,860 | $971,881 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 933,860 | 971,881 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $933,860 | $971,881 |

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Entergy\tNew\tOrleans |  |  |
| Audit\tFees | $953,860 | $1,056,881 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 953,860 | 1,056,881 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $953,860 | $1,056,881 |
| Entergy\tTexas |  |  |
| Audit\tFees | $1,093,860 | $1,076,881 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 1,093,860 | 1,076,881 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $1,093,860 | $1,076,881 |
| System\tEnergy |  |  |
| Audit\tFees | $868,860 | $861,881 |
| Audit-Related\tFees\t(a) | — | — |
| Total\taudit\tand\taudit-related\tfees | 868,860 | 861,881 |
| Tax\tFees | — | — |
| All\tOther\tFees | — | — |
| Total\tFees\t(b) | $868,860 | $861,881 |

(a) Includes	fees	for	employee	benefit	plan	audits,	consultation	on	financial	accounting	and	reporting,	and	other	attestation	services.

(b) 100%	of	fees	paid	in	2017	and	2016	were	pre-approved	by	the	Entergy	Corporation	Audit	Committee.

# Entergy	Audit	Committee	Guidelines	for	Pre-approval	of	Independent	Auditor	Services

The	Audit	 Committee	 has	 adopted the	 following	 guidelines	 regarding the	 engagement	 of	 Entergy's independent	 auditor to	 perform services	for	Entergy:

1. The	independent	auditor	will	provide	the	Audit	Committee,	for	approval,	an	annual	engagement	letter	outlining	the	scope	of	services proposed	to	be	performed	during	the	fiscal	year,	including	audit	services	and	other	permissible	non-audit	services	(e.g.	audit-related services,	tax	services,	and	all	other	services).

2. For	other	permissible	services	not	included	in	the	engagement	letter,	Entergy	management	will	submit	a	description	of	the	proposed service,	including	a	budget	estimate,	to	the	Audit	Committee	for	pre-approval.		Management	and	the	independent	auditor	must	agree that	the	requested	service	is	consistent	with	the	SEC's	rules	on	auditor	independence	prior	to	submission	to	the	Audit	Committee.		The Audit	Committee,	at	its	discretion,	will	pre-approve	permissible	services	and	has	established	the	following	additional	guidelines	for permissible	non-audit	services	provided	by	the	independent	auditor:

•Aggregate	non-audit	service	fees	are	targeted	at	fifty	percent	or	less	of	the	approved	audit	service	fee.

•All	other	services	should	only	be	provided	by	the	independent	auditor	if	it	is	a	highly	qualified	provider	of	that	service	or	if the	Audit	Committee	pre-approves	the	independent	audit	firm	to	provide	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	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	530)

Financial	Statement	Schedules	are	listed	in	the	Index	to	Financial	Statement	Schedules	(see	page	S-1)

Exhibits	for	Entergy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	Entergy	Texas,	and	System Energy	are	listed	in	the	Exhibit	Index	(see	page	507).		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.

# Item	16.		Form	10-K	Summary	(Entergy	Corporation,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans, Entergy	Texas,	and	System	Energy)

None.

# 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.

(c)	1	-- Articles	of	Amendment	and	Restatement	for	the	Second	Amended	and	Restated	Articles	of	Incorporation	of	Entergy	Arkansas effective	August	19,	2009	(3	to	Form	8-K	filed	August	24,	2009	in	1-10764).

(d)	1	-- Certificate	of	Formation	of	Entergy	Louisiana	Power,	LLC	(including	Certificate	of	Amendment	to	Certificate	of	Formation	to change	the	company	name	to	Entergy	Louisiana,	LLC)	effective	July	7,	2015	(3.3	to	Form	8-K12B	filed	October	1,	2015	in	1- 32718).

(d)	2	-- Company	Agreement	of	Entergy	Louisiana	Power,	LLC	(including	First	Amendment	to	Company	Agreement	to	change	the company	name	to	Entergy	Louisiana,	LLC)	effective	July	7,	2015	(3.4	to	Form	8-K12B	filed	October	1,	2015	in	1-32718).

# (4) Instruments	Defining	Rights	of	Security	Holders,	Including	Indentures

(a)	1	-- See	(4)(b)	through	(4)(g)	below	for	instruments	defining	the	rights	of	security	holders	of	System	Energy,	Entergy	Arkansas, Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	Entergy	Texas.

(a)	2	-- 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	-- Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among	Entergy	Corporation,	as	the	Borrower,	the	banks and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank, and	the	other	LC	Issuing	Banks	party	thereto	(4(g)	to	Form	10-Q	for	the	quarter	ended	September	30,	2015	in	1-11299).

(a)	8	-- Amendment	dated	as	of	August	28,	2015,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(h)	to	Form	10-Q	for	the quarter	ended	September	30,	2015	in	1-11299).

(a)	9	-- Extension	Agreement,	dated	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(l)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-11299).

(a)	10	-- Amendment	dated	as	of	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(m)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-11299).

(a)	11	-- Extension	Agreement,	dated	August	7,	2017,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(a)	to Form	10-Q	for	the	quarter	ended	September	30,	2017).

(a)	12	-- Amendment,	 dated	 as	 of	 October	 17,	 2017,	 to	Amended	 and	 Restated	 Credit	Agreement	 dated	 as	 of	August	 14,	 2015,	 as amended,	among	Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(b)	to Form	10-Q	for	the	quarter	ended	September	30,	2017).

(a)	13	-- Agreement,	dated	as	of	October	17,	2017,	pursuant	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Corporation,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(c)	to Form	10-Q	for	the	quarter	ended	September	30,	2017).

(b)	2	-- Loan	Agreement,	dated	as	of	October	15,	1998,	between	System	Energy	and	Mississippi	Business	Finance	Corporation	(B-6(b) to	Rule	24	Certificate	filed	November	12,	1998	in	70-8511).

*(b)	3	-- Fuel	Lease,	dated	as	of	February	24,	1989,	between	River	Fuel	Funding	Company	#3,	Inc.	and	System	Energy.

(c)	2	-- Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among	Entergy	Arkansas,	as	the	Borrower,	the	banks	and other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and the	other	LC	Issuing	Banks	party	thereto	(4(i)	to	Form	10-Q	for	the	quarter	ended	September	30,	2015	in	1-10764).

(c)	3	-- Amendment	dated	as	of	August	28,	2015,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Arkansas,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(j)	to	Form	10-Q	for	the quarter	ended	September	30,	2015	in	1-10764).

(c)	4	-- Extension	Agreement,	dated	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Arkansas,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(n)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-10764).

(c)	5	-- Amendment	dated	as	of	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Arkansas,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(o)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-10764).

(c)	6	-- Extension	Agreement,	dated	August	7,	2017,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Arkansas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(d)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-10764).

(c)	7	-- Amendment,	 dated	 as	 of	 October	 17,	 2017,	 to	Amended	 and	 Restated	 Credit	Agreement	 dated	 as	 of	August	 14,	 2015,	 as amended,	among	Entergy	Arkansas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(e)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-10764).

(c)	8-- Agreement,	dated	as	of	October	17,	2017,	pursuant	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Arkansas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(f)	to	Form 10-Q	for	the	quarter	ended	September	30,	2017	in	1-10764).

(d)	2	-- Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among	Entergy	Louisiana	[Old	Entergy	Louisiana]	and Entergy	Gulf	States	Louisiana,	as	the	Borrowers,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank, N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4.4	to	Form	8-K12B filed	October	1,	2015	in	1-32718).

(d)	3	-- Amendment	dated	as	of	August	28,	2015,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Louisiana	[Old	Entergy	Louisiana]	and	Entergy	Gulf	States	Louisiana,	as	the	Borrowers,	the	banks	and	other	financial institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC Issuing	Banks	party	thereto	(4.5	to	Form	8-K12B	filed	October	1,	2015	in	1-32718).

(d)	4	-- Borrower	Assumption	Agreement	dated	as	of	October	1,	2015	of	Entergy	Louisiana	[New	Entergy	Louisiana]	under	Amended and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among	Entergy	Louisiana	[Old	Entergy	Louisiana]	and	Entergy Gulf	States	Louisiana,	as	the	Borrowers,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto,	as	amended	(4.6	to	Form	8- K12B	filed	October	1,	2015	in	1-32718).

(d)	5	-- Extension	Agreement,	dated	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Louisiana,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(p)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-32718).

(d)	6	-- Amendment	dated	as	of	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	Louisiana,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(q)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-32718).

(d)	7	-- Extension	Agreement,	dated	August	7,	2017,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Louisiana,	LLC,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(g)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-32718).

(d)	8	-- Amendment,	 dated	 as	 of	 October	 17,	 2017,	 to	Amended	 and	 Restated	 Credit	Agreement	 dated	 as	 of	August	 14,	 2015,	 as amended,	among	Entergy	Louisiana,	LLC,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(h)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-32718).

(d)	9	-- Agreement,	dated	as	of	October	17,	2017,	pursuant	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Louisiana,	LLC,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(i)	to	Form 10-Q	for	the	quarter	ended	September	30,	2017	in	1-32718).

*(d)	11	-- Nuclear	Fuel	Lease	Agreement	between	Entergy	Gulf	States,	Inc.	and	River	Bend	Fuel	Services,	Inc.	to	lease	the	fuel	for	River Bend	Unit	1,	dated	February	7,	1989.

*(d)	12	-- Exhibit	A	to	Trust	Indenture	dated	as	of	February	7,	1989	between	River	Bend	Fuel	Services,	Inc.	and	U.S.	Bank	National Association	(as	successor	Trustee).

(d)	13	-- Loan	Agreement,	dated	as	of	March	1,	2016,	between	the	Louisiana	Public	Facilities	Authority	and	Entergy	Louisiana	relating	to Refunding	Revenue	Bonds	(Entergy	Louisiana,	LLC	Project)	Series	2016A	(4(b)	to	Form	8-K	filed	March	18,	2016	in	1- 32718).

(d)	14	-- Loan	Agreement,	dated	as	of	March	1,	2016,	between	Louisiana	Public	Facilities	Authority	and	Entergy	Louisiana	relating	to Refunding	Revenue	Bonds	(Entergy	Louisiana,	LLC	Project)	Series	2016B	(4(d)	to	Form	8-K	filed	March	18,	2016	in	1- 32718).

(d)	16	-- 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).

(f)	2	-- Amended	and	Restated	Credit	Agreement	($25,000,000),	dated	as	of	November	20,	2015,	among	Entergy	New	Orleans,	as	the Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	and	Bank	of	America,	N.A.,	as	Administrative Agent	(4(f)2	to	Form	10-K	for	the	year	ended	December	31,	2015	in	1-35747).

(f)	3	-- Amendment,	dated	as	of	June	30,	2016,	to	Amended	and	Restated	Credit	Agreement,	dated	as	of	November	20,	2015,	among Entergy	New	Orleans,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	and	Bank	of	America, N.A.,	as	Administrative	Agent	(4(f)	to	Form	10-Q	for	the	quarter	ended	June	30,	2016	in	1-35747).

(f)	4	-- Amendment,	dated	as	of	September	26,	2017,	to	Amended	and	Restated	Credit	Agreement,	dated	as	of	November	20,	2015,	as amended,	among	Entergy	New	Orleans,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders,	and Bank	of	America,	N.A.,	as	Administrative	Agent	(4(j)	to	Form	10-Q	for	the	quarter	ending	September	30,	2017	in	1-35747).

(f)	5	-- Borrower	Assumption	Agreement,	dated	as	of	November	30,	2017,	of	Entergy	New	Orleans	Power,	LLC	under	the	Amended	and Restated	Credit	Agreement	dated	as	of	November,	2015,	as	amended,	among	Entergy	New	Orleans,	Inc.,	as	the	Borrower,	the banks	and	other	financial	institutions	party	thereto	as	Lenders,	Bank	of	America,	N.A.,	as	Administrative	Agent	(4.2	to	Form	8- K12B	filed	December	1,	2017	in	1-35747).

(g)	2	-- Officer's	Certificate	No.	1-B-1	dated	January	27,	2009,	supplemental	to	Indenture,	Deed	of	Trust	and	Security	Agreement	dated as	of	October	1,	2008,	between	Entergy	Texas	and	The	Bank	of	New	York	Mellon,	as	trustee	(4(h)3	to	Form	10-K	for	the	year ended	December	31,	2008	in	0-53134).

(g)	3	-- 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	and	The	Bank	of	New	York	Mellon,	as	trustee	(4.40	to	Form	8-K	filed September	13,	2011	in	1-34360).

*(g)	4	-- Officer's	Certificate	No.	7-B-5	dated	May	13,	2014,	supplemental	to	Indenture,	Deed	of	Trust	and	Security	Agreement	dated	as of	October	1,	2008,	between	Entergy	Texas	and	The	Bank	of	New	York	Mellon,	as	trustee.

Officer's	Certificate	No.	10-B-8	dated	November	14,	2017,	supplemental	to	Indenture,	Deed	of	Trust	and	Security	Agreement dated	as	of	October	1,	2008,	between	Entergy	Texas	and	The	Bank	of	New	York	Mellon,	as	trustee	(4.48	to	Form	8-K	filed November	17,	2017	in	1-34360).

(g)	8	-- Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among	Entergy	Texas,	as	the	Borrower,	the	banks	and other	financial	institutions	party	thereto	as	Lenders,	Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and the	other	LC	Issuing	Banks	party	thereto	(4(k)	to	Form	10-Q	for	the	quarter	ended	September	30,	2015	in	1-34360).

(g)	9	-- Amendment	dated	as	of	August	28,	2015,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	 Texas,	 as	 the	 Borrower,	 the	 banks	 and	 other	 financial	 institutions	 party	 thereto	 as	 Lenders,	 Citibank,	 N.A.,	 as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(l)	to	Form	10-Q	for	the quarter	ended	September	30,	2015	in	1-34360).

Extension	Agreement,	dated	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	 Texas,	 as	 the	 Borrower,	 the	 banks	 and	 other	 financial	 institutions	 party	 thereto	 as	 Lenders,	 Citibank,	 N.A.,	 as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(r)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-34360).

(g)	11	-- Amendment	dated	as	of	August	8,	2016,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	among Entergy	 Texas,	 as	 the	 Borrower,	 the	 banks	 and	 other	 financial	 institutions	 party	 thereto	 as	 Lenders,	 Citibank,	 N.A.,	 as Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(s)	to	Form	10-Q	for	the quarter	ended	September	30,	2016	in	1-34360).

(g)	12	-- Extension	Agreement,	dated	August	7,	2017,	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Texas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(k)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-34360).

(g)	13	-- Amendment,	 dated	 as	 of	 October	 17,	 2017,	 to	Amended	 and	 Restated	 Credit	Agreement	 dated	 as	 of	August	 14,	 2015,	 as amended,	among	Entergy	Texas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(l)	to	Form 10-Q	for	the	quarter	ended	September	30,	2017	in	1-34360).

(g)	14	-- Amendment,	dated	as	of	October	17,	2017,	pursuant	to	Amended	and	Restated	Credit	Agreement	dated	as	of	August	14,	2015,	as amended,	among	Entergy	Texas,	Inc.,	as	the	Borrower,	the	banks	and	other	financial	institutions	party	thereto	as	Lenders, Citibank,	N.A.,	as	Administrative	Agent	and	as	an	LC	Issuing	Bank,	and	the	other	LC	Issuing	Banks	party	thereto	(4(m)	to Form	10-Q	for	the	quarter	ended	September	30,	2017	in	1-34360).

# (10)		Material	Contracts

+(a)	1	-- 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)	3	-- Second	Amendment	of	the	2007	Equity	Ownership	and	Long	Term	Cash	Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries effective	January	1,	2009	(10(a)51	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	5	-- 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)	6	-- 2015	Equity	Ownership	Plan	of	Entergy	Corporation	and	Subsidiaries	(Appendix	C	to	2015	Entergy	Corporation's	Definitive Proxy	Statement	filed	on	March	20,	2015	in	1-11299).

+(a)	7	-- First	Amendment	to	The	2015	Entergy	Corporation	Non-Employee	Director	Stock	Program	Established	under	the	2015	Equity Ownership	Plan	of	Entergy	Corporation	and	Subsidiaries	(10(a)	to	Form	10-Q	for	the	quarter	ended	June	30,	2017	in	1-11299).

+(a)	8	-- Supplemental	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	as	amended	and	restated	effective	January	1,	2009 (10(a)57	to	Form	10-K	for	the	year	ended	December	31,	2010	in	1-11299).

+(a)	11	-- Third	Amendment	of	the	Supplemental	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	July	25,	2013	(10(b) to	Form	10-Q	for	the	quarter	ended	September	30,	2014	in	1-11299).

+(a)	12	-- Fourth	Amendment	of	the	Supplemental	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	July	1,	2014	(10(c) to	Form	10-Q	for	the	quarter	ended	September	30,	2014	in	1-11299).

+(a)	13	-- 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)	14	-- 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)	15	-- 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)	17	-- 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)	18	-- 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)	19	-- 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)	38	-- Fifth	Amendment	of	the	System	Executive	Retirement	Plan	of	Entergy	Corporation	and	Subsidiaries,	effective	July	1,	2014 (10(d)	to	Form	10-Q	for	the	quarter	ended	September	30,	2014	in	1-11299).

*+(a)	46	-- Form	of	Stock	Option	Grant	Agreement.

*+(a)	47	-- Form	of	Long	Term	Incentive	Program	Performance	Unit	Agreement.

*+(a)	48	-- Form	of	Restricted	Stock	Grant	Agreement.

*+(a)	49	-- Form	of	Restricted	Stock	Units	Grant	Agreement.

+(a)	52	-- Executive	Annual	Incentive	Plan	of	Entergy	Corporation	and	Subsidiaries	as	amended	and	restated	effective	January	1,	2016 (Appendix	B	to	2015	Entergy	Corporation's	Definitive	Proxy	Statement	filed	on	March	20,	2015	in	1-11299).

+(a)	53	-- Entergy	Corporation	Service	Recognition	Program	for	Non-Employee	Directors,	as	amended	and	restated	effective	June	1,	2015 (10(d)	to	Form	10-Q	for	the	quarter	ended	June	30,	2015	in	1-11299).

*(b)	1	-- Availability	Agreement,	dated	June	21,	1974,	among	System	Energy	and	certain	other	System	companies.

*(b)	3	-- Second	Amendment	to	Availability	Agreement,	dated	as	of	June	15,	1981.

*(b)	5	-- Fourth	Amendment	to	Availability	Agreement,	dated	as	of	June	1,	1989.

(b)	6	-- 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).

(b)	7	-- Amendment	to	the	Thirty-seventh	Assignment	of	Availability	Agreement,	Consent	and	Agreement,	dated	as	of	September	18, 2015,	among	System	Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	Entergy	New	Orleans,	and	The	Bank of	New	York	Mellon,	as	successor	trustee	(4.25	to	Form	S-3	filed	October	2,	2015).

*(b)	8	-- Capital	Funds	Agreement,	dated	June	21,	1974,	between	Entergy	Corporation	and	System	Energy.

(b)	10	-- 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).

*(b)	11	-- Facility	Lease	No.	1,	dated	as	of	December	1,	1988,	between	Meridian	Trust	Company	and	Stephen	M.	Carta	(Stephen	J.	Kaba, successor),	as	Owner	Trustees,	and	System	Energy.

*(b)	15	-- Reallocation	Agreement,	dated	as	of	July	28,	1981,	among	System	Energy	and	certain	other	System	companies.

(b)	16	-- Unit	Power	Sales	Agreement	among	System	Energy,	Entergy	Arkansas,	Entergy	Louisiana,	Entergy	Mississippi,	and	Entergy New	Orleans	dated	as	of	June	10,	1982,	as	amended	and	revised	(10(b)16	to	Form	10-K	for	the	year	ended	December	31,	2016 in	1-11299).

*(c)	1	-- Amendment	to	Limited	Liability	Company	Agreement,	effective	as	of	May	26,	2017,	and	amends	the	Fourth	Amended	and Restated	Limited	Liability	Company	Agreement	of	Entergy	Holdings	Company	LLC	effective	as	of	September	19,	2015.

# (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	Louisiana's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Distributions, as	defined.

*(c) Entergy	Mississippi's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Dividends,	as defined.

*(d) Entergy	New	Orleans's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges	and	of	Earnings	to	Fixed	Charges	and	Preferred	Dividends, as	defined.

*(e) Entergy	Texas's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges,	as	defined.

*(f) System	Energy's	Computation	of	Ratios	of	Earnings	to	Fixed	Charges,	as	defined.

# *(21)		Subsidiaries	of	the	Registrants

# (23)		Consents	of	Experts	and	Counsel

*(a) The	consent	of	Deloitte	&	Touche	LLP	is	contained	herein	at	page	529.

*(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	Louisiana.

*(f) Section	1350	Certification	for	Entergy	Louisiana.

*(g) Section	1350	Certification	for	Entergy	Mississippi.

*(h) Section	1350	Certification	for	Entergy	Mississippi.

*(i) Section	1350	Certification	for	Entergy	New	Orleans.

*(j) Section	1350	Certification	for	Entergy	New	Orleans.

*(k) Section	1350	Certification	for	Entergy	Texas.

*(l) Section	1350	Certification	for	Entergy	Texas.

*(m) Section	1350	Certification	for	System	Energy.

*(n) 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.

# 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

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,	Patrick	J.	Condon,	Kirkland	H.	Donald,	Philip	L. Frederickson,	Alexis	M.	Herman,	Donald	C.	Hintz,	Stuart	L.	Levenick,	Blanche	L.	Lincoln,	Karen	A.	Puckett,	and	W.	J.	Tauzin	(Directors).

(Alyson	M.	Mount,	Attorney-in-fact)

# ENTERGY	ARKANSAS,	INC.

Richard	C.	Riley	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S. Marsh	(Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	Paul	D.	Hinnenkamp	and	Roderick	K.	West (Directors).

Phillip	R.	May,	Jr.	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S. Marsh	(Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	Paul	D.	Hinnenkamp	and	Roderick	K.	West (Directors).

Haley	R.	Fisackerly	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S. Marsh	(Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	Paul	D.	Hinnenkamp	and	Roderick	K.	West (Directors).

Charles	L.	Rice,	Jr.	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S. Marsh	(Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	Paul	D.	Hinnenkamp	and	Roderick	K.	West (Directors).

Sallie	T.	Rainer	(Chair	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S.	Marsh (Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	Paul	D.	Hinnenkamp	and	Roderick	K.	West (Directors).

Roderick	K.	West	(Chairman	of	the	Board,	President,	Chief	Executive	Officer,	and	Director;	Principal	Executive	Officer);	Andrew	S. Marsh	(Executive	Vice	President,	Chief	Financial	Officer,	and	Director;	Principal	Financial	Officer);	A.	Christopher	Bakken,	III	and	Steven	C. McNeal	(Directors).

# CONSENTS	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-213335	on	Form	S-3	and	in	Registration	Statements	Nos.	333- 140183,	333-174148,	333-204546,	and	333-206556	on	Form	S-8	of	our	reports	dated	February	26,	2018,	relating	to	the	consolidated	financial statements	 and	 financial	 statement	 schedule	 of	 Entergy	 Corporation	 and	 Subsidiaries,	 and	 the	 effectiveness	 of	 Entergy	 Corporation	 and Subsidiaries'	internal	control	over	financial	reporting,	appearing	in	this	Annual	Report	on	Form	10-K	of	Entergy	Corporation	for	the	year	ended December	31,	2017.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-213335-06	on	Form	S-3	of	our	reports	dated	February	26,	2018, relating	to	the	consolidated	financial	statements	and	financial	statement	schedule	of	Entergy	Arkansas,	Inc.	and	Subsidiaries	appearing	in	this Annual	Report	on	Form	10-K	of	Entergy	Arkansas,	Inc.	for	the	year	ended	December	31,	2017.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-213335-03	on	Form	S-3	of	our	reports	dated	February	26,	2018, relating	to	the	consolidated	financial	statements	and	financial	statement	schedule	of	Entergy	Louisiana,	LLC	and	Subsidiaries	appearing	in	this Annual	Report	on	Form	10-K	of	Entergy	Louisiana,	LLC	for	the	year	ended	December	31,	2017.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-213335-05	on	Form	S-3	of	our	reports	dated	February	26,	2018, relating	to	the	consolidated	financial	statements	and	financial	statement	schedule	of	Entergy	Texas,	Inc.	and	Subsidiaries	appearing	in	this	Annual Report	on	Form	10-K	of	Entergy	Texas,	Inc.	for	the	year	ended	December	31,	2017.

We	consent	to	the	incorporation	by	reference	in	Registration	Statement	No.	333-213335-04	on	Form	S-3	of	our	report	dated	February	26,	2018, relating	to	the	financial	statements	of	System	Energy	Resources,	Inc.	appearing	in	this	Annual	Report	on	Form	10-K	of	System	Energy	Resources, Inc.	for	the	year	ended	December	31,	2017.

# Opinion	on	the	Financial	Statement	Schedule

We	have	audited	the	consolidated	financial	statements	of	Entergy	Corporation	and	Subsidiaries	(the	"Corporation")	as	of	December	31,	2017	and 2016,	and	for	each	of	the	three	years	in	the	period	ended	December	31,	2017,	and	the	Corporation's	internal	control	over	financial	reporting	as	of December	31,	2017,	and	have	issued	our	reports	thereon	dated	February	26,	2018.	Our	audits	also	included	the	consolidated	financial	statement schedule	 of	 the	 Corporation	 listed	 in	 Item	 15.	 This	 consolidated	 financial	 statement	 schedule	 is	 the	 responsibility	 of	 the	 Corporation's management.	Our	responsibility	is	to	express	an	opinion	on	the	Corporation's	consolidated	financial	statement	schedule	based	on	our	audits.	In our	opinion,	such	consolidated	financial	statement	schedule,	when	considered	in	relation	to	the	consolidated	financial	statements	taken	as	a	whole, presents	fairly,	in	all	material	respects,	the	information	set	forth	therein.

# Opinion	on	the	Financial	Statement	Schedules

We	have	audited	the	consolidated	financial	statements	of	Entergy	Arkansas,	Inc.	and	Subsidiaries,	Entergy	Louisiana,	LLC	and	Subsidiaries, Entergy	New	Orleans,	LLC	and	Subsidiaries,	and	Entergy	Texas,	Inc.	and	Subsidiaries,	and	we	have	also	audited	the	financial	statements	of Entergy	Mississippi,	Inc.	(collectively	the	"Companies")	as	of	December	31,	2017	and	2016,	and	for	each	of	the	three	years	in	the	period	ended December	31,	2017,	and	have	issued	our	reports	thereon	dated	February	26,	2018.	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'	management. Our	responsibility	is	to	express	an	opinion	on	the	Companies'	financial	statement	schedules	based	on	our	audits.	In	our	opinion,	such	financial statement	 schedules,	 when	 considered	 in	 relation	 to	 the	 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,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $11,924 | $4,211 | $2,548 | $13,587 |
| 2016 | $39,895 | $7,505 | $35,476 | $11,924 |
| 2015 | $35,663 | $6,926 | $2,694 | $39,895 |

(1)	Deductions	represent	write-offs	of	accounts	receivable	balances	and	are	reduced	by	recoveries	of	amounts	previously	written	off.

| For	the	Years	Ended	December	31,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $1,211 | $503 | $651 | $1,063 |
| 2016 | $34,226 | $902 | $33,917 | $1,211 |
| 2015 | $32,247 | $2,759 | $780 | $34,226 |

| For	the	Years	Ended	December	31,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $6,277 | $3,108 | $955 | $8,430 |
| 2016 | $4,209 | $2,942 | $874 | $6,277 |
| 2015 | $1,609 | $3,464 | $864 | $4,209 |

| For	the	Years	Ended	December	31,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $549 | $255 | $230 | $574 |
| 2016 | $718 | $259 | $428 | $549 |
| 2015 | $873 | $247 | $402 | $718 |

| For	the	Years	Ended	December	31,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $3,059 | $152 | $154 | $3,057 |
| 2016 | $268 | $2,872 | $81 | $3,059 |
| 2015 | $262 | $217 | $211 | $268 |

| For	the	Years	Ended	December	31,	2017,	2016,	and	2015 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (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\tof\nPeriod |
| Allowance\tfor\tdoubtful\taccounts |  |  |  |  |
| 2017 | $828 | $192 | $557 | $463 |
| 2016 | $474 | $531 | $177 | $828 |
| 2015 | $672 | $239 | $437 | $474 |



Question: what percent did net revenue decrease between 2016 and 2017?
Answer: .33%