# UNITED	STATES

# SECURITIES	AND	EXCHANGE	COMMISSION

# (Mark	One)

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

# For	the	fiscal	year	ended	December	31,	2018

o TRANSITION	REPORT	PURSUANT	TO	SECTION	13	OR	15(d)	OF	THE	SECURITIES	EXCHANGE	ACT	OF	1934

Commission	file	number:	1-9743

# EOG	RESOURCES,	INC.

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	or	other	jurisdiction	of incorporation	or	organization)

(I.R.S.	Employer Identification	No.)

(Address	of	principal	executive	offices)					(Zip	Code)

# Registrant's	telephone	number,	including	area	code:		713-651-7000

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

Title	of	each	class

Common	Stock,	par	value	$0.01	per	share

Name	of	each	exchange	on	which	registered

New	York	Stock	Exchange

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

# None.

Indicate	by	check	mark	if	the	registrant	is	a	well-known	seasoned	issuer,	as	defined	in	Rule	405	of	the	Securities	Act.		Yes	ý		No	o

Indicate	by	check	mark	if	the	registrant	is	not	required	to	file	reports	pursuant	to	Section	13	or	Section	15(d)	of	the	Exchange	Act.		Yes	o		No	ý

Indicate	by	check	mark	whether	the	registrant	(1)	has	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	registrant	was	required	to	file	such	reports),	and	(2)	has	been	subject	to	such	filing	requirements	for	the	past	90	days.		Yes	ý		No	o

Indicate	by	check	mark	whether	the	registrant	has	submitted	electronically	every	Interactive	Data	File	required	to	be	submitted	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	such	files).		Yes	ý		No	o

Indicate	by	check	mark	if	disclosure	of	delinquent	filers	pursuant	to	Item	405	of	Regulation	S-K	(§	229.405	of	this	chapter)	is	not	contained	herein,	and	will	not	be	contained,	to the	best	of	the	registrant's	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.		o

Indicate	by	check	mark	whether	the	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	Exchange	Act.

Large	accelerated	filer	ý				Accelerated	filer	o				Non-accelerated	filer	o

Smaller	reporting	company	o				Emerging	growth	company	o

If	an	emerging	growth	company,	indicate	by	check	mark	if	the	registrant	has	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	registrant	is	a	shell	company	(as	defined	in	Rule	12b-2	of	the	Exchange	Act).		Yes	o		No	ý

State	the	aggregate	market	value	of	the	voting	and	non-voting	common	equity	held	by	non-affiliates	computed	by	reference	to	the	price	at	which	the	common	equity	was	last sold,	or	the	average	bid	and	asked	price	of	such	common	equity,	as	of	the	last	business	day	of	the	registrant's	most	recently	completed	second	fiscal	quarter.		Common	Stock	aggregate market	value	held	by	non-affiliates	as	of	June	30,	2018:	$71,861	million.

Indicate	the	number	of	shares	outstanding	of	each	of	the	registrant's	classes	of	common	stock,	as	of	the	latest	practicable	date.		Class:	Common	Stock,	par	value	$0.01	per	share, 580,053,225	shares	outstanding	as	of	February	15,	2019.

Documents	incorporated	by	reference.		Portions	of	the	Definitive	Proxy	Statement	for	the	registrant's	2019	Annual	Meeting	of	Stockholders,	to	be	filed	within	120	days	after December	31,	2018,	are	incorporated	by	reference	into	Part	III	of	this	report.

# TABLE	OF	CONTENTS

# PART	I

| ITEM	1. | Business | 1 |
| :--- | :--- | :--- |
|  | General | 1 |
|  | Exploration\tand\tProduction | 1 |
|  | Marketing | 5 |
|  | Wellhead\tVolumes\tand\tPrices | 6 |
|  | Competition | 7 |
|  | Regulation | 7 |
|  | Other\tMatters | 11 |
|  | Executive\tOfficers\tof\tthe\tRegistrant | 12 |
| ITEM\t1A. | Risk\tFactors | 13 |
| ITEM\t1B. | Unresolved\tStaff\tComments | 22 |
| ITEM\t2. | Properties | 22 |
|  | Oil\tand\tGas\tExploration\tand\tProduction\t-\tProperties\tand\tReserves | 22 |
| ITEM\t3. | Legal\tProceedings | 26 |
| ITEM\t4. | Mine\tSafety\tDisclosures | 26 |
|  | PART\tII |  |
| ITEM\t5. | Market\tfor\tRegistrant's\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 26 |
| ITEM\t6. | Selected\tFinancial\tData | 28 |
| ITEM\t7. | Management's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 29 |
| ITEM\t7A. | Quantitative\tand\tQualitative\tDisclosures\tAbout\tMarket\tRisk | 47 |
| ITEM\t8. | Financial\tStatements\tand\tSupplementary\tData | 47 |
| ITEM\t9. | Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | 47 |
| ITEM\t9A. | Controls\tand\tProcedures | 47 |
| ITEM\t9B. | Other\tInformation | 48 |
|  | PART\tIII |  |
| ITEM\t10. | Directors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | 48 |
| ITEM\t11. | Executive\tCompensation | 48 |
| ITEM\t12. | Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | 49 |
| ITEM\t13. | Certain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | 50 |
| ITEM\t14. | Principal\tAccounting\tFees\tand\tServices | 50 |
|  | PART\tIV |  |
| ITEM\t15. | Exhibits,\tFinancial\tStatement\tSchedules | 51 |
| ITEM\t16. | Form\t10-K\tSummary | 51 |

# SIGNATURES

# ITEM	1.		Business

# General

EOG	Resources,	Inc.,	a	Delaware	corporation	organized	in	1985,	together	with	its	subsidiaries	(collectively,	EOG),	explores	for,	develops,	produces	and markets	crude	oil	and	natural	gas	primarily	in	major	producing	basins	in	the	United	States	of	America	(United	States	or	U.S.),	The	Republic	of	Trinidad	and	Tobago (Trinidad),	The	People's	Republic	of	China	(China),	Canada	and,	from	time	to	time,	select	other	international	areas.		EOG's	principal	producing	areas	are	further described	in	"Exploration	and	Production"	below.		EOG's	Annual	Reports	on	Form	10-K,	Quarterly	Reports	on	Form	10-Q,	Current	Reports	on	Form	8-K	and	any amendments	to	those	reports	(including	related	exhibits	and	supplemental	schedules,	filed	or	furnished	pursuant	to	Section	13(a)	or	15(d)	of	the	Exchange	Act)	are	made available,	free	of	charge,	through	EOG's	website,	as	soon	as	reasonably	practicable	after	such	reports	have	been	filed	with,	or	furnished	to,	the	United	States	Securities and	Exchange	Commission	(SEC).		EOG's	website	address	is	www.eogresources.com.	Information	on	our	website	is	not	incorporated	by	reference	into,	and	does	not constitute	a	part	of,	this	report.

At	December	31,	2018,	EOG's	total	estimated	net	proved	reserves	were	2,928	million	barrels	of	oil	equivalent	(MMBoe),	of	which	1,532	million	barrels (MMBbl)	were	crude	oil	and	condensate	reserves,	614	MMBbl	were	natural	gas	liquids	(NGLs)	reserves	and	4,687	billion	cubic	feet	(Bcf),	or	782	MMBoe,	were	natural gas	reserves	(see	"Supplemental	Information	to	Consolidated	Financial	Statements").		At	such	date,	approximately	98%	of	EOG's	net	proved	reserves,	on	a	crude	oil equivalent	basis,	were	located	in	the	United	States,	1%	in	Trinidad	and	1%	in	other	international	areas.		Crude	oil	equivalent	volumes	are	determined	using	a	ratio	of	1.0 barrel	of	crude	oil	and	condensate	or	NGLs	to	6.0	thousand	cubic	feet	(Mcf)	of	natural	gas.

As	of	December	31,	2018,	EOG	employed	approximately	2,800	persons,	including	foreign	national	employees.

EOG's	operations	are	all	crude	oil	and	natural	gas	exploration	and	production	related.	For	information	regarding	the	risks	associated	with	EOG's	domestic	and foreign	operations,	see	ITEM	1A,	Risk	Factors.

EOG's	business	strategy	is	to	maximize	the	rate	of	return	on	investment	of	capital	by	controlling	operating	and	capital	costs	and	maximizing	reserve	recoveries. Pursuant	to	this	strategy,	each	prospective	drilling	location	is	evaluated	by	its	estimated	rate	of	return.	This	strategy	is	intended	to	enhance	the	generation	of	cash	flow and	earnings	from	each	unit	of	production	on	a	cost-effective	basis,	allowing	EOG	to	deliver	long-term	production	growth	while	maintaining	a	strong	balance	sheet. EOG	is	focused	on	cost-effective	utilization	of	advanced	technology	associated	with	three-dimensional	seismic	and	microseismic	data,	the	development	of	reservoir simulation	models,	the	use	of	improved	drilling	equipment,	completion	technologies	for	horizontal	drilling	and	formation	evaluation.		These	advanced	technologies	are used,	as	appropriate,	 throughout	EOG	 to	reduce	 the	risks	and	costs	associated	with	all	aspects	of	oil	and	gas	exploration,	development	and	exploitation.	 	EOG implements	its	strategy	primarily	by	emphasizing	the	drilling	of	internally	generated	prospects	in	order	to	find	and	develop	low-cost	reserves.		Maintaining	the	lowest possible	operating	cost	structure	that	is	consistent	with	efficient,	safe	and	environmentally	responsible	operations	is	also	an	important	goal	in	the	implementation	of EOG's	strategy.

With	respect	to	information	on	EOG's	working	interest	in	wells	or	acreage,	"net"	oil	and	gas	wells	or	acreage	are	determined	by	multiplying	"gross"	oil	and	gas wells	or	acreage	by	EOG's	working	interest	in	the	wells	or	acreage.

# Exploration	and	Production

# United	States	Operations

EOG's	operations	are	located	in	most	of	the	productive	basins	in	the	United	States	with	a	focus	on	crude	oil	and,	to	a	lesser	extent,	liquids-rich	natural	gas	plays.

At	December	31,	2018,	on	a	crude	oil	equivalent	basis,	53%	of	EOG's	net	proved	reserves	in	the	United	States	were	crude	oil	and	condensate,	21%	were	NGLs and	26%	were	natural	gas.	The	majority	of	these	reserves	are	in	long-lived	fields	with	well-established	production	characteristics.	EOG	believes	that	opportunities	exist to	increase	production	through	continued	development	in	and	around	many	of	these	fields	and	through	the	utilization	of	applicable	technologies.	EOG	also	maintains	an active	exploration	program	designed	to	extend	fields	and	add	new	trends	and	resource	plays	to	its	already	broad	portfolio.

The	following	is	a	summary	of	significant	developments	during	2018	and	certain	2019	plans	for	EOG's	United	States	operations.

|  |  | 2018 |  |  |  |  | 2019 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Crude\tOil\t& |  |  |  |  |  |  |
|  | Condensate | Natural\tGas | Natural\tGas |  |  |  | Expected\tNet |
|  | Volumes | Liquids\tVolumes | Volumes | Total\tNet\tAcres |  | Net\tWell | Well |
| Area\tof\tOperation | (MBbld)\t(1) | (MBbld)\t(1) | (MMcfd)\t(1) | (2) |  | Completions | Completions |
| Eagle\tFord | 171 | 31 | 159 | 579,000 |  | 304 | 300 |
| Austin\tChalk | 20 | 7 | 42 | — | (3) | 27 | 15 |
| Permian\tBasin | 132 | 46 | 338 | 913,000 |  | 265 | 275 |
| Rocky\tMountain\tArea | 62 | 15 | 207 | 1,232,000 |  | 109 | 95 |
| Upper\tGulf\tCoast | 1 | — | 4 | 441,000 |  | 1 | 5 |
| Mid-Continent | 6 | 2 | 12 | 125,000 |  | 31 | 35 |
| Fort\tWorth\tBasin | 2 | 14 | 78 | 152,000 |  | — | — |
| South\tTexas | 1 | 1 | 24 | 391,000 |  | 8 | 5 |
| Marcellus\tShale | — | — | 59 | 172,000 |  | 15 | — |

(1) Thousand	barrels	per	day	or	million	cubic	feet	per	day,	as	applicable.

(2) Total	net	acres	excludes	approximately	0.3	million	net	acres	related	to	other	areas.

(3) The	Austin	Chalk	play	encompasses	the	same	net	acres	as	the	Eagle	Ford.

The	Eagle	Ford	continues	to	prove	itself	as	a	world-class	crude	oil	field	having	produced	in	excess	of	2.9	billion	barrels	of	crude	oil	and	condensate.	With approximately	516,000	of	its	579,000	total	net	acres	in	the	prolific	oil	window,	EOG	continues	to	be	the	largest	crude	oil	producer	in	the	Eagle	Ford	with	cumulative gross	production	in	excess	of	490	MMBbl	of	crude	oil	and	condensate.	In	2018,	EOG	completed	304	net	Eagle	Ford	wells	and	continued	to	test	the	Austin	Chalk	play concept	with	the	completion	of	27	net	Austin	Chalk	wells.	EOG	is	still	evaluating	the	extent	of	prospectivity	of	the	Austin	Chalk,	which	overlays	the	Eagle	Ford.	EOG also	continued	its	enhanced	oil	recovery	(EOR)	gas	injection	program	in	2018,	adding	54	wells	to	the	program.	EOG	does	not	expect	to	add	wells	to	the	EOR	program in	2019	while	it	evaluates	additional	primary	development	opportunities.	EOG	expects	to	complete	approximately	300	net	Eagle	Ford	wells	and	15	net	Austin	Chalk wells	 in	 2019	 while	 continuing	 to	 improve	 well	 productivity	 and	 operational	 efficiencies.	The	 combination	 of	 exceptional	 execution	 and	 continuous	 operational improvements	have	made	this	play	one	of	the	foundations	of	EOG's	portfolio.

In	the	Permian	Basin,	EOG	completed	265	net	wells	during	2018,	primarily	in	the	Delaware	Basin	Wolfcamp	Shale,	Bone	Spring	and	Leonard	plays.	EOG continued	to	consolidate	its	acreage	position	in	each	of	these	world-class	assets	through	small	leasing	transactions	and	the	exchange	of	acreage	with	other	nearby operators.	EOG	has	approximately	346,000	net	acres	in	the	Delaware	Basin	Wolfcamp	Shale	play	where	it	completed	219	net	wells	in	2018.	The	success	of	the	2018 Wolfcamp	program	was	due	to	precision	targeting,	high-density	stimulations	and	continued	cost	reductions.	The	program	shifted	toward	the	development	of	larger packages	of	wells	during	2018,	which	also	contributed	to	cost	reductions.	The	high-return	Delaware	Basin	Wolfcamp	Shale	play	will	continue	to	be	a	primary	area	of focus	in	2019.	In	the	Second	Bone	Spring	play,	EOG	holds	approximately	289,000	net	acres	and	completed	18	net	wells	in	2018.	The	Second	Bone	Spring	play	is another	integral	part	of	EOG's	Permian	Basin	portfolio.	In	the	Leonard	Shale	play,	EOG	has	approximately	160,000	net	acres	and	continued	development	with	17	net wells	completed	in	2018.	EOG	also	had	strong	results	in	the	First	Bone	Spring	where	it	holds	approximately	100,000	net	acres	and	completed	eight	net	wells	in	2018. Activity	in	2019	will	continue	to	be	focused	in	the	Delaware	Basin	Wolfcamp	Shale,	Second	Bone	Spring,	First	Bone	Spring	and	Leonard	plays,	where	EOG	expects	to complete	approximately	270	net	wells.

Activity	in	the	Rocky	Mountain	area	increased	in	2018	with	a	focus	on	the	Wyoming	Powder	River	and	DJ	Basins.	In	the	Powder	River	Basin,	EOG	operated	a two-rig	program,	completing	41	net	wells,	and	identified	future	drilling	locations,	mostly	in	the	Mowry	and	Niobrara	formations.	The	focus	in	2019	will	be	to	add infrastructure	and	operate	a	drilling	program	to	further	delineate	the	basin	and	test	additional	targets,	to	better	position	the	company	for	a	more	robust	development program	in	2020	and	beyond.	In	the	Wyoming	DJ	Basin,	drilling,	completion,	and	operating	costs	continued	to	decline	and	there	is	a	significant	high-return	development program	scheduled	for	2019.	Drilling	activity	increased	in	the	Williston	Basin	in	2018	after	pausing	for	several	years	while	the	company	reduced	its	inventory	of	drilled uncompleted	wells	(DUCs).	The	20	net	wells	completed	in	2018	targeted	the	Bakken	and	Three	Forks	formations	and	benefited	from	the	application	of	precision targeting.	Activity	in	2019	will	be	similar,	as	will	the	seasonal	program	of	completing	wells	mostly	in	the	summer	while	drilling	operations	are	conducted	throughout	the year.	EOG	currently	holds	approximately	1.2	million	net	acres	in	the	Rocky	Mountain	area.

In	the	Mid-Continent	area,	EOG	continued	its	development	of	the	Woodford	Oil	Window	play	with	26	net	wells	completed	during	2018.	EOG	holds	47,000	net acres	in	the	play	and	plans	to	build	on	its	initial	success	in	the	Woodford	Oil	Window	with	30	net	well	completions	in	2019.	In	2018,	EOG	completed	22	gross	(four	net) wells	in	the	Western	Anadarko	Basin	Marmaton	Sand.

Total	net	production	in	2018	from	the	Fort	Worth	Basin	Barnett	Shale	and	Marcellus	Shale	averaged	2	MBbld	of	crude	oil	and	condensate,	14	MBbld	of	NGLs and	137	MMcfd	of	natural	gas.	Development	activity	in	these	areas	was	concentrated	in	the	Marcellus	Shale	in	2018,	where	EOG	completed	15	net	DUCs.	Net production	in	the	Marcellus	Shale	for	2018	averaged	59	MMcfd	of	natural	gas,	with	a	peak	net	rate	of	102	MMcfd.	EOG	currently	holds	approximately	172,000	net	acres with	Marcellus	potential.	At	year-end	2018,	EOG	held	approximately	152,000	net	acres	in	the	Fort	Worth	Basin.

At	year-end	2018,	EOG	held	approximately	441,000	net	acres	in	the	Upper	Gulf	Coast	region.	EOG	remained	focused	on	exploration	and	evaluation	efforts last	year	with	minimal	activity	and	expects	these	efforts	will	continue	in	2019.

In	the	South	Texas	area,	EOG	completed	eight	net	liquids-rich	natural	gas	wells	in	2018,	including	three	net	DUCs	from	prior	years.	EOG	has	deferred completion	 of	 five	 additional	 net	 wells,	 and	 expects	 to	 complete	 these	 liquids-rich	 natural	 gas	 wells	 in	 2019	 in	 the	 Frio	 and	Vicksburg	 trends,	 where	 it	 holds approximately	391,000	net	acres.	In	addition,	exploration	and	evaluation	efforts	will	continue	in	this	region	in	2019.

At	December	31,	2018,	EOG	held	approximately	2.4	million	net	undeveloped	acres	in	the	United	States.

During	2018,	EOG	continued	to	operate	its	gathering	and	processing	facilities	in	the	Eagle	Ford	in	South	Texas,	the	Williston	Basin	Bakken	and	Three	Forks plays	in	North	Dakota,	the	Fort	Worth	Basin	Barnett	Shale	and	the	Permian	Basin	in	West	Texas	and	New	Mexico.	 At	December	31,	2018,	EOG-owned	natural	gas processing	capacity	in	the	Eagle	Ford	and	the	Fort	Worth	Basin	Barnett	Shale	totaled	325	MMcfd	and	180	MMcfd,	respectively.

# Operations	Outside	the	United	States

EOG	has	operations	offshore	Trinidad,	in	the	China	Sichuan	Basin	and	in	Canada	and	is	evaluating	additional	exploration,	development	and	exploitation opportunities	in	these	and	other	select	international	areas.	EOG	sold	its	operations	in	the	United	Kingdom	(U.K.)	East	Irish	Sea	in	the	fourth	quarter	of	2018.

Trinidad.	EOG,	through	several	of	its	subsidiaries,	including	EOG	Resources	Trinidad	Limited,

•holds	an	80%	working	interest	in	the	exploration	and	production	license	covering	the	South	East	Coast	Consortium	(SECC)	Block	offshore	Trinidad, except	in	the	Deep	Ibis	area	in	which	EOG's	working	interest	decreased	as	a	result	of	a	third-party	farm-out	agreement;

•holds	 an	 80%	 working interest in the	 exploration	 and	 production license	 covering the	 Pelican	 Field	 and its	 related facilities;

•holds	 a	 50%	 working interest in the	 exploration	 and	 production licenses	 covering the	 Sercan	Area	 offshore Trinidad;

•holds	a	100%	working	interest	in	a	production	sharing	contract	with	the	Government	of	Trinidad	and	Tobago	for	each	of	the	Modified	U(a)	Block, Modified	U(b)	Block	and	Block	4(a);

•holds	a	50%	working	interest	in	the	exploration	and	production	license	covering	the	Banyan

Field;

•holds	a	50%	working	interest	in	the	exploration	and	production	license	covering	the	Ska,	Mento,	Reggae	Area	deep	Teak,	deep	Saaman	and	deep	Poui offshore	Trinidad	(collectively	SMR	Area);

•owns	a	12%	equity	interest	in	an	anhydrous	ammonia	plant	in	Point	Lisas,	Trinidad,	that	is	owned	and	operated	by	Caribbean	Nitrogen	Company	Limited; and

•owns	a	10%	equity interest in	an	anhydrous	ammonia	plant in	Point	Lisas,	Trinidad, that is	owned	and	operated	by	Nitrogen	(2000) Unlimited.

Several	fields	in	the	SECC	Block,	Modified	U(a)	Block,	Modified	U(b)	Block,	Block	4(a),	the	Banyan	Field	and	the	Sercan	Area	have	been	developed	and	are producing	natural	gas	and	crude	oil	and	condensate.	Natural	gas	from	EOG's	Trinidad	operations	currently	is	sold	under	various	contracts	with	the	National	Gas Company	of	Trinidad	and	Tobago	Limited	and	its	subsidiary	(NGC).	Crude	oil	and	condensate	from	EOG's	Trinidad	operations	currently	is	sold	to	the	Petroleum Company	 of	 Trinidad	 and	 Tobago	 Limited	 and	 its	 successor,	 Heritage	 Petroleum	 Company	 Limited.	 In	 2018,	 EOG's	 net	 production	 from	 Trinidad	 averaged approximately	266	MMcfd	of	natural	gas	and	approximately	0.8	MBbld	of	crude	oil	and	condensate.

In	2018,	EOG	conducted	an	ocean	bottom	nodal	seismic	survey	in	the	SECC	Block	and	the	Pelican	Field	and	continues	to	process	and	review	the	initial	data.

In	2019,	EOG	expects	to	drill	five	wells	of	which	two	of	these	wells	are	expected	to	be	completed	during	the	second	quarter	of	2019	and	one	well	is	expected	to be	completed	in	the	fourth	quarter	of	2019.	All	of	the	natural	gas	produced	from	EOG's	Trinidad	operations	in	2019	is	expected	to	be	supplied	to	NGC	under	various contracts	with	NGC.	All	crude	oil	and	condensate	produced	from	EOG's	Trinidad	operations	in	2019	is	expected	to	be	supplied	to	Heritage	Petroleum	Company	Limited under	various	contracts	with	Heritage	Petroleum	Company	Limited.

At	December	31,	2018,	EOG	held	approximately	115,000	net	undeveloped	acres	in	Trinidad.

United	Kingdom.	EOG	completed	the	sale	of	all	of	its	interest	in	EOG	Resources	United	Kingdom	Limited	during	the	fourth	quarter	of	2018.	EOG	no	longer has	any	presence	in	the	U.K.

In	2018,	production	averaged	approximately	4.2	MBbld	of	crude	oil,	net,	in	the	U.K.

China.	In	July	2008,	EOG	acquired	rights	from	ConocoPhillips	in	a	Petroleum	Contract	covering	the	Chuan	Zhong	Block	exploration	area	in	the	Sichuan Basin,	 Sichuan	 Province,	 China.	In	October	2008,	EOG	obtained	 the	rights	 to	shallower	zones	on	 the	acquired	acreage.	EOG	entered	2018	with	 two	DUCs	and completed	both	wells.	In	addition,	EOG	drilled	five	natural	gas	wells	and	completed	one	of	those	wells	in	2018	as	part	of	the	continuing	development	of	the	Bajiaochang Field,	which	natural	gas	is	sold	under	a	long-term	contract	to	PetroChina.	EOG	plans	to	drill	two	additional	wells	in	2019	and	complete	the	remaining	2018	wells	in progress	as	pipeline	capacity	allows.

In	2018,	production	averaged	approximately	23	MMcfd	of	natural	gas,	net,	in	China.

Canada.	EOG	maintains	approximately	134,000	net	acres	with	23	net	producing	wells	in	the	Horn	River	area	in	Northeast	British	Columbia.

In	2018,	net	production	in	Canada	averaged	approximately	8	MMcfd	of	natural	gas.

EOG	continues	to	evaluate	other	select	crude	oil	and	natural	gas	opportunities	outside	the	United	States,	primarily	by	pursuing	exploitation	opportunities	in countries	where	indigenous	crude	oil	and	natural	gas	reserves	have	been	identified.

# Marketing

In	2018,	EOG's	wellhead	crude	oil	and	condensate	production	was	transported	either	by	pipeline	or	truck	to	downstream	markets	or	sold	into	local	markets.	In each	case,	the	price	received	was	based	on	market	prices	at	that	specific	sales	point	or	based	on	the	price	index	applicable	for	that	location.	Major	U.S.	sales	areas included	the	Midwest;	the	Permian	Basin;	Cushing,	Oklahoma;	Houston	and	Corpus	Christi,	Texas;	and	Louisiana;	and	other	points	along	the	U.S.	Gulf	Coast.	In	2019, the	pricing	mechanism	for	such	production	is	expected	to	remain	the	same.	At	December	31,	2018,	EOG	is	committed	to	deliver	fixed	quantities	of	crude	oil	of	69.9 MMBbls	in	2019,	13.7	MMBbls	in	2020	and	1.4	MMBbls	in	2021,	all	of	which	is	expected	to	be	delivered	from	future	production	of	available	reserves.

In	2018,	EOG	processed	certain	of	its	natural	gas	production,	either	at	EOG-owned	facilities	or	at	third-party	facilities,	extracting	NGLs.	NGLs	were	sold	at prevailing	market	prices.	In	2019,	the	pricing	mechanism	for	such	production	is	expected	to	remain	the	same.

In	2018,	EOG's	United	States	wellhead	natural	gas	production	was	sold	into	local	markets	or	transported	by	pipeline	to	Katy,	Texas;	East	Texas;	the	Cheyenne Hub;	Southern	California;	or	Chicago,	Illinois.	Pricing	was	based	on	the	spot	market	price	at	the	ultimate	sales	point.	In	2019,	the	pricing	mechanism	for	such	production is	expected	to	remain	the	same.	At	December	31,	2018,	EOG	is	committed	to	deliver	fixed	quantities	of	natural	gas	of	64	Bcf	in	2019,	15	Bcf	in	2020,	10	Bcf	in	2021,	2 Bcf	in	2022	and	11	Bcf	thereafter,	all	of	which	is	expected	to	be	delivered	from	future	production	of	available	reserves.

In	2018,	a	large	majority	of	the	wellhead	natural	gas	volumes	from	Trinidad	were	sold	under	contracts	with	prices	which	were	either	wholly	or	partially dependent	on	Caribbean	ammonia	index	prices	and/or	methanol	prices.	The	remaining	volumes	were	sold	under	a	contract	at	prices	partially	dependent	on	United	States Henry	Hub	market	prices	and	a	fixed	price	contract.	The	pricing	mechanisms	for	these	contracts	in	Trinidad	are	expected	to	remain	the	same	in	2019.

In	2018,	all	wellhead	natural	gas	volumes	from	China	were	sold	at	regulated	prices	based	on	the	purchaser's	pipeline	sales	volumes	to	various	local	market segments.	The	pricing	mechanism	for	production	in	China	is	expected	to	remain	the	same	in	2019.

Through	November	2018,	EOG	marketed	and	sold	its	U.K.	wellhead	crude	oil	production	from	the	Conwy	field.	The	crude	oil	sales	were	based	on	a	Dated Brent	price	or	other	market	prices,	as	applicable.

In	certain	instances,	EOG	purchases	and	sells	third-party	crude	oil	and	natural	gas	in	order	to	balance	firm	transportation	capacity	with	production	in	certain areas	and	to	utilize	excess	capacity	at	EOG-owned	facilities.

During	2018,	two	purchasers	each	accounted	for	more	than	10%	of	EOG's	total	wellhead	crude	oil	and	condensate,	NGL	and	natural	gas	revenues	and gathering,	processing	and	marketing	revenues.	The	two	purchasers	are	in	the	crude	oil	refining	industry.	EOG	does	not	believe	that	the	loss	of	any	single	purchaser would	have	a	material	adverse	effect	on	its	financial	condition	or	results	of	operations.

# Wellhead	Volumes	and	Prices

The	following	table	sets	forth	certain	information	regarding	EOG's	wellhead	volumes	of,	and	average	prices	for,	crude	oil	and	condensate,	NGLs	and	natural gas.	The	table	also	presents	crude	oil	equivalent	volumes	which	are	determined	using	a	ratio	of	1.0	barrel	of	crude	oil	and	condensate	or	NGLs	to	6.0	Mcf	of	natural	gas for	each	of	the	years	ended	December	31,	2018,	2017	and	2016.	See	ITEM	7,	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	- Results	of	Operations,	for	wellhead	volumes	on	a	per-day	basis.

| Year	Ended	December	31 | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Crude\tOil\tand\tCondensate\tVolumes\t(MMBbl)\t(1) |  |  |  |
| United\tStates: |  |  |  |
| Eagle\tFord | 62.4 | 57.4 | 60.7 |
| Delaware\tBasin | 46.3 | 31.6 | 17.0 |
| Other | 35.4 | 33.2 | 24.2 |
| United\tStates | 144.1 | 122.2 | 101.9 |
| Trinidad | 0.3 | 0.3 | 0.3 |
| Other\tInternational\t(2) | 1.6 | 0.2 | 1.2 |
| Total | 146.0 | 122.7 | 103.4 |
| Natural\tGas\tLiquids\tVolumes\t(MMBbl)\t(1) |  |  |  |
| United\tStates: |  |  |  |
| Eagle\tFord | 11.4 | 9.4 | 10.0 |
| Delaware\tBasin | 15.8 | 8.8 | 5.8 |
| Other | 15.3 | 14.1 | 14.1 |
| United\tStates | 42.5 | 32.3 | 29.9 |
| Other\tInternational\t(2) | — | — | — |
| Total | 42.5 | 32.3 | 29.9 |
| Natural\tGas\tVolumes\t(Bcf)\t(1) |  |  |  |
| United\tStates: |  |  |  |
| Eagle\tFord | 58 | 55 | 59 |
| Delaware\tBasin | 110 | 81 | 50 |
| Other | 169 | 143 | 187 |
| United\tStates | 337 | 279 | 296 |
| Trinidad | 97 | 114 | 125 |
| Other\tInternational\t(2) | 11 | 9 | 9 |
| Total | 445 | 402 | 430 |
| Crude\tOil\tEquivalent\tVolumes\t(MMBoe)\t(3) |  |  |  |
| United\tStates: |  |  |  |
| Eagle\tFord | 83.5 | 76.0 | 80.6 |
| Delaware\tBasin | 80.3 | 53.9 | 31.2 |
| Other | 78.8 | 71.2 | 69.3 |
| United\tStates | 242.6 | 201.1 | 181.1 |
| Trinidad | 16.5 | 19.4 | 21.1 |
| Other\tInternational\t(2) | 3.4 | 1.8 | 2.8 |
| Total | 262.5 | 222.3 | 205.0 |

| Year	Ended	December	31 | 2018 |  | 2017 | 2016 |
| :--- | :--- | :--- | :--- | :--- |
| Average\tCrude\tOil\tand\tCondensate\tPrices\t($/Bbl)\t(4) |  |  |  |  |
| United\tStates | $65.16 |  | $50.91 | $41.84 |
| Trinidad | 57.26 |  | 42.30 | 33.76 |
| Other\tInternational\t(2) | 71.45 |  | 57.20 | 36.72 |
| Composite | 65.21 |  | 50.91 | 41.76 |
| Average\tNatural\tGas\tLiquids\tPrices\t($/Bbl)\t(4) |  |  |  |  |
| United\tStates | $26.60 |  | $22.61 | $14.63 |
| Other\tInternational\t(2) | — |  | — | — |
| Composite | 26.60 |  | 22.61 | 14.63 |
| Average\tNatural\tGas\tPrices\t($/Mcf)\t(4) |  |  |  |  |
| United\tStates | $2.88 |  | $2.20 | $1.60 |
| Trinidad | 2.94 |  | 2.38 | 1.88 |
| Other\tInternational\t(2) | 4.08 |  | 3.89 | 3.64 |
| Composite | 2.92 | (5) | 2.29 | 1.73 |

(1) Million	barrels	or	billion	cubic	feet,	as	applicable.

(2) Other	International	includes	EOG's	United	Kingdom,	China,	Canada	and	Argentina	operations.	The	United	Kingdom	operations	were	sold	in	the	fourth	quarter	of	2018.	The Argentina	operations	were	sold	in	the	third	quarter	of	2016.

(3) Million	barrels	of	oil	equivalent;	includes	crude	oil	and	condensate,	NGLs	and	natural	gas.

(4) Dollars	per	barrel	or	per	 thousand	cubic	feet,	as	applicable.	 	Excludes	 the	 impact	of	financial	commodity	derivative instruments	(see	Note	12 to	Consolidated	Financial Statements).

(5) Includes	a	positive	revenue	adjustment	of	$0.44	per	Mcf	related	to	the	adoption	of	ASU	2014-09,	"Revenue	From	Contracts	with	Customers"	(ASU	2014-09)	(see	Note	1	to	the Consolidated	Financial	Statements).	In	connection	with	the	adoption	of	ASU	2014-09,	EOG	presents	natural	gas	processing	fees	related	to	certain	processing	and	marketing agreements	as	Gathering	and	Processing	Costs,	instead	of	as	a	deduction	to	Natural	Gas	revenues.

# Competition

EOG	competes	with	major	integrated	oil	and	gas	companies,	government-affiliated	oil	and	gas	companies	and	other	independent	oil	and	gas	companies	for	the acquisition	of	licenses	and	leases,	properties	and	reserves	and	access	to	the	facilities,	equipment,	materials,	services,	and	employees	and	other	contract	personnel (including	geologists,	geophysicists,	engineers	and	other	specialists)	required	to	explore	for,	develop,	produce,	market	and	transport	crude	oil	and	natural	gas.	In addition,	certain	of	EOG's	competitors	have	financial	and	other	resources	substantially	greater	than	those	EOG	possesses	and	have	established	strategic	long-term positions	or	strong	governmental	relationships	in	countries	or	areas	in	which	EOG	may	seek	new	or	expanded	entry.	As	a	consequence,	EOG	may	be	at	a	competitive disadvantage	in	certain	respects,	such	as	in	bidding	for	drilling	rights	or	in	accessing	necessary	services,	facilities,	equipment,	materials	and	personnel.	In	addition, EOG's	larger	competitors	may	have	a	competitive	advantage	when	responding	to	factors	that	affect	demand	for	crude	oil	and	natural	gas,	such	as	changing	worldwide prices	and	levels	of	production	and	the	cost	and	availability	of	alternative	fuels.	EOG	also	faces	competition,	to	a	lesser	extent,	from	competing	energy	sources,	such	as alternative	energy	sources.

# Regulation

United	States	Regulation	of	Crude	Oil	and	Natural	Gas	Production.	Crude	oil	and	natural	gas	production	operations	are	subject	to	various	types	of	regulation, including	regulation	by	federal	and	state	agencies.

United	States	legislation	affecting	the	oil	and	gas	industry	is	under	constant	review	for	amendment	or	expansion.	In	addition,	numerous	departments	and agencies,	both	federal	and	state,	are	authorized	by	statute	 to	 issue,	and	have	 issued,	rules	and	regulations	applicable	 to	 the	oil	and	gas	 industry.	Such	rules	and regulations,	among	other	things,	require	permits	for	the	drilling	of	wells,	regulate	the	spacing	of	wells,	prevent	the	waste	of	natural	gas	through	restrictions	on	flaring, require	surety	bonds	for	various	exploration	and	production	operations	and	regulate	the	calculation	and	disbursement	of	royalty	payments	(for	federal	and	state	leases), production	taxes	and	ad	valorem	taxes.

A	portion	of	EOG's	oil	and	gas	leases	in	New	Mexico,	North	Dakota,	Utah,	Wyoming	and	the	Gulf	of	Mexico,	as	well	as	in	other	areas,	are	granted	by	the federal	government	and	administered	by	the	Bureau	of	Land	Management	(BLM)	and/or	the	Bureau	of	Indian	Affairs	(BIA)	or,	in	the	case	of	offshore	leases	(which,	for EOG,	are	de	minimis),	by	the	Bureau	of	Ocean	Energy	Management	(BOEM)	and	the	Bureau	of	Safety	and	Environmental	Enforcement	(BSEE),	all	federal	agencies. Operations	conducted	by	EOG	on	federal	oil	and	gas	leases	must	comply	with	numerous	additional	statutory	and	regulatory	restrictions	and,	in	the	case	of	leases	relating to	tribal	lands,	certain	tribal	environmental	and	permitting	requirements	and	employment	rights	regulations.	In	addition,	the	U.S.	Department	of	the	Interior	(via	various of	its	agencies,	including	the	BLM,	the	BIA	and	the	Office	of	Natural	Resources	Revenue)	has	certain	authority	over	our	calculation	and	payment	of	royalties,	bonuses, fines,	penalties,	assessments	and	other	revenues	related	to	our	federal	and	tribal	oil	and	gas	leases.

BLM,	BIA	and	BOEM	leases	contain	relatively	standardized	terms	requiring	compliance	with	detailed	regulations	and,	in	the	case	of	offshore	leases,	orders pursuant	to	the	Outer	Continental	Shelf	Lands	Act	(which	are	subject	to	change	by	the	BOEM	or	BSEE).	Under	certain	circumstances,	the	BLM,	BIA,	BOEM	or	BSEE (as	applicable)	may	require	operations	on	federal	leases	to	be	suspended	or	terminated.	Any	such	suspension	or	termination	could	materially	and	adversely	affect	EOG's interests.

The	transportation	and	sale	for	resale	of	natural	gas	in	interstate	commerce	are	regulated	pursuant	to	the	Natural	Gas	Act	of	1938,	as	amended	(NGA),	and	the Natural	Gas	Policy	Act	of	1978.	These	statutes	are	administered	by	the	Federal	Energy	Regulatory	Commission	(FERC).	Effective	January	1993,	the	Natural	Gas Wellhead	Decontrol	Act	of	1989	deregulated	natural	gas	prices	for	all	"first	sales"	of	natural	gas,	which	includes	all	sales	by	EOG	of	its	own	production.	All	other	sales of	natural	gas	by	EOG,	such	as	those	of	natural	gas	purchased	from	third	parties,	remain	jurisdictional	sales	subject	to	a	blanket	sales	certificate	under	the	NGA,	which has	flexible	terms	and	conditions.	Consequently,	all	of	EOG's	sales	of	natural	gas	currently	may	be	made	at	market	prices,	subject	to	applicable	contract	provisions. EOG's	jurisdictional	sales,	however,	may	be	subject	in	the	future	to	greater	federal	oversight,	including	the	possibility	that	the	FERC	might	prospectively	impose	more restrictive	conditions	on	such	sales.	Conversely,	sales	of	crude	oil	and	condensate	and	NGLs	by	EOG	are	made	at	unregulated	market	prices.

EOG	owns	certain	gathering	and/or	processing	facilities	in	the	Permian	Basin	in	West	Texas	and	New	Mexico,	the	Barnett	Shale	in	North	Texas,	the	Bakken and	Three	Forks	plays	in	North	Dakota,	and	the	Eagle	Ford	in	South	Texas.	State	regulation	of	gathering	and	processing	facilities	generally	includes	various	safety, environmental	and,	in	some	circumstances,	nondiscrimination	requirements	with	respect	to	the	provision	of	gathering	and	processing	services,	but	does	not	generally entail	rate	regulation.	EOG's	gathering	and	processing	operations	could	be	materially	and	adversely	affected	should	they	be	subject	in	the	future	to	the	application	of state	or	federal	regulation	of	rates	and	services.

EOG's	gathering	and	processing	operations	also	may	be,	or	become,	subject	to	safety	and	operational	regulations	relating	to	the	design,	installation,	testing, construction,	operation,	replacement	and	management	of	such	facilities.	Additional	rules	and	legislation	pertaining	to	these	matters	are	considered	and/or	adopted	from time	to	time.	Although	EOG	cannot	predict	what	effect,	if	any,	such	legislation	might	have	on	its	operations	and	financial	condition,	EOG	could	be	required	to	incur additional	capital	expenditures	and	increased	compliance	and	operating	costs	depending	on	the	nature	and	extent	of	such	future	legislative	and	regulatory	changes.

EOG	also	owns	crude	oil	rail	loading	facilities	in	North	Dakota	and	crude	oil	truck	unloading	facilities	in	certain	of	its	U.S.	plays.	Regulation	of	such	facilities is	conducted	at	the	state	and	federal	levels	and	generally	includes	various	safety,	environmental,	permitting	and	packaging/labeling	requirements.	Additional	regulation pertaining	to	these	matters	is	considered	and/or	adopted	from	time	to	time.	Although	EOG	cannot	predict	what	effect,	if	any,	any	such	new	regulations	might	have	on	its crude-by-rail	assets	and	the	transportation	of	its	crude	oil	production	by	truck,	EOG	could	be	required	to	incur	additional	capital	expenditures	and	increased	compliance and	operating	costs	depending	on	the	nature	and	extent	of	such	future	regulatory	changes.	EOG	did	not	transport	any	crude	oil	by	rail	during	2018.

Proposals	and	proceedings	that	might	affect	the	oil	and	gas	industry	are	considered	from	time	to	time	by	Congress,	the	state	legislatures,	the	FERC	and	federal, state	and	local	regulatory	commissions,	agencies,	councils	and	courts.	EOG	cannot	predict	when	or	whether	any	such	proposals	or	proceedings	may	become	effective.	It should	also	be	noted	that	the	oil	and	gas	industry	historically	has	been	very	heavily	regulated;	therefore,	there	is	no	assurance	that	the	approach	currently	being	followed by	such	legislative	bodies	and	regulatory	commissions,	agencies,	councils	and	courts	will	remain	unchanged.

Environmental	Regulation	-	United	States.	EOG	is	subject	to	various	federal,	state	and	local	laws	and	regulations	covering	the	discharge	of	materials	into	the environment	or	otherwise	relating	to	the	protection	of	the	environment.	These	laws	and	regulations	affect	EOG's	operations	and	costs	as	a	result	of	their	effect	on	crude oil	 and	 natural	 gas	 exploration,	 development	 and	 production	 operations.	Failure	 to	 comply	 with	 these	 laws	 and	 regulations	 may	 result	 in	 the	 assessment	 of administrative,	civil	and	criminal	penalties,	including	the	assessment	of	monetary	penalties,	the	imposition	of	investigatory	and	remedial	obligations,	the	suspension	or revocation	of	necessary	permits,	licenses	and	authorizations,	the	requirement	that	additional	pollution	controls	be	installed	and	the	issuance	of	orders	enjoining	future operations	or	imposing	additional	compliance	requirements.

In	addition,	EOG	has	acquired	certain	oil	and	gas	properties	from	third	parties	whose	actions	with	respect	to	the	management	and	disposal	or	release	of hydrocarbons	or	other	wastes	were	not	under	EOG's	control.	Under	environmental	laws	and	regulations,	EOG	could	be	required	to	remove	or	remediate	wastes	disposed of	or	released	by	prior	owners	or	operators.	EOG	also	could	incur	costs	related	to	the	clean-up	of	third-party	sites	to	which	it	sent	regulated	substances	for	disposal	or	to which	it	sent	equipment	for	cleaning,	and	for	damages	to	natural	resources	or	other	claims	related	to	releases	of	regulated	substances	at	such	third-party	sites.	In	addition, EOG	could	be	responsible	under	environmental	laws	and	regulations	for	oil	and	gas	properties	in	which	EOG	previously	owned	or	currently	owns	an	interest,	but	was	or is	not	the	operator.	Moreover,	EOG	is	subject	to	the	United	States	(U.S.)	Environmental	Protection	Agency's	(U.S.	EPA)	rule	requiring	annual	reporting	of	greenhouse gas	(GHG)	emissions	and,	as	discussed	further	below,	is	also	subject	to	federal,	state	and	local	laws	and	regulations	regarding	hydraulic	fracturing.

Compliance	with	environmental	laws	and	regulations	increases	EOG's	overall	cost	of	business,	but	has	not	had,	to	date,	a	material	adverse	effect	on	EOG's operations,	financial	condition	or	results	of	operations.	In	addition,	it	is	not	anticipated,	based	on	current	laws	and	regulations,	that	EOG	will	be	required	in	the	near future	to	expend	amounts	(whether	for	environmental	control	facilities	or	otherwise)	that	are	material	in	relation	to	its	total	exploration	and	development	expenditure program	in	order	to	comply	with	such	laws	and	regulations.	However,	given	that	such	laws	and	regulations	are	subject	to	change,	EOG	is	unable	to	predict	the	ultimate cost	of	compliance	or	the	ultimate	effect	on	EOG's	operations,	financial	condition	and	results	of	operations.

Climate	Change	-	United	States.	Local,	state,	federal	and	international	regulatory	bodies	have	been	increasingly	focused	on	GHG	emissions	and	climate	change issues	in	recent	years.	In	addition	to	the	U.S.	EPA's	rule	requiring	annual	reporting	of	GHG	emissions,	the	U.S.	EPA	has	adopted	regulations	for	certain	large	sources regulating	GHG	emissions	as	pollutants	under	the	federal	Clean	Air	Act.	In	May	2016,	the	U.S.	EPA	issued	regulations	that	require	operators	to	reduce	methane emissions	and	emissions	of	volatile	organic	compounds	(VOC)	from	new,	modified	and	reconstructed	crude	oil	and	natural	gas	wells	and	equipment	located	at	natural gas	production	gathering	and	booster	stations,	gas	processing	plants	and	natural	gas	transmission	compressor	stations.

At	the	international	level,	in	December	2015,	the	U.S.	participated	in	the	21st	Conference	of	the	Parties	of	the	United	Nations	Framework	Convention	on Climate	Change	in	Paris,	France.	The	Paris	Agreement	(adopted	at	the	conference)	calls	for	nations	to	undertake	efforts	with	respect	to	global	temperatures	and	GHG emissions.	The	Paris	Agreement	went	into	effect	on	November	4,	2016.	However,	the	U.S.	has	announced	its	intention	to	withdraw	from	the	Paris	Agreement.	In response,	many	state	and	local	officials	have	stated	their	intent	to	intensify	efforts	to	uphold	the	commitments	set	forth	in	the	international	accord.

EOG	believes	that	its	strategy	to	reduce	GHG	emissions	throughout	its	operations	is	both	in	the	best	interest	of	the	environment	and	a	prudent	business	practice. EOG	has	developed	a	system	that	is	utilized	in	calculating	GHG	emissions	from	its	operating	facilities.	This	emissions	management	system	calculates	emissions	based on	recognized	regulatory	methodologies,	where	applicable,	and	on	commonly	accepted	engineering	practices.	EOG	reports	GHG	emissions	for	facilities	covered	under the	U.S.	EPA's	Mandatory	Reporting	of	Greenhouse	Gases	Rule	published	in	2009,	as	amended.

EOG	is	unable	to	predict	the	timing,	scope	and	effect	of	any	currently	proposed	or	future	investigations,	laws,	regulations	or	treaties	regarding	climate	change and	GHG	emissions,	but	the	direct	and	indirect	costs	of	such	investigations,	laws,	regulations	and	treaties	(if	enacted)	could	materially	and	adversely	affect	EOG's operations,	financial	condition	and	results	of	operations.

Hydraulic	Fracturing	-	United	States.	Most	onshore	crude	oil	and	natural	gas	wells	drilled	by	EOG	are	completed	and	stimulated	through	the	use	of	hydraulic fracturing.	Hydraulic	fracturing	technology,	which	has	been	used	by	the	oil	and	gas	industry	for	more	than	60	years	and	is	constantly	being	enhanced,	enables	EOG	to produce	crude	oil	and	natural	gas	from	formations	that	otherwise	would	not	be	recovered.	Specifically,	hydraulic	fracturing	is	a	process	in	which	pressurized	fluid	is pumped	into	underground	formations	to	create	tiny	fractures	or	spaces	that	allow	crude	oil	and	natural	gas	to	flow	from	the	reservoir	into	the	well	so	that	it	can	be brought	to	the	surface.	Hydraulic	fracturing	generally	takes	place	thousands	of	feet	underground,	a	considerable	distance	below	any	drinking	water	aquifers,	and	there are	impermeable	layers	of	rock	between	the	area	fractured	and	the	water	aquifers.	The	makeup	of	the	fluid	used	in	the	hydraulic	fracturing	process	typically	includes water	and	sand,	and	less	than	1%	of	highly	diluted	chemical	additives;	lists	of	the	chemical	additives	used	in	fracturing	fluids	are	available	to	the	public	via	internet websites	and	in	other	publications	sponsored	by	industry	trade	associations	and	through	state	agencies	in	those	states	that	require	the	reporting	of	the	components	of fracturing	fluids.	While	the	majority	of	the	sand	remains	underground	to	hold	open	the	fractures,	a	significant	amount	of	the	water	and	chemical	additives	flow	back	and are	then	either	reused	or	safely	disposed	of	at	sites	that	are	approved	and	permitted	by	the	appropriate	regulatory	authorities.	EOG	periodically	conducts	regulatory assessments	of	these	disposal	facilities	to	monitor	compliance	with	applicable	regulations.

The	regulation	of	hydraulic	fracturing	is	primarily	conducted	at	the	state	and	local	level	through	permitting	and	other	compliance	requirements.	In	April	2012, however,	the	U.S.	EPA	issued	regulations	specifically	applicable	to	the	oil	and	gas	industry	that	require	operators	to	significantly	reduce	VOC	emissions	from	natural gas	wells	that	are	hydraulically	fractured	through	the	use	of	"green	completions"	to	capture	natural	gas	that	would	otherwise	escape	into	the	air.	The	U.S.	EPA	also issued	regulations	that	establish	standards	for	VOC	emissions	from	several	types	of	equipment,	including	storage	tanks,	compressors,	dehydrators,	and	valves	and sweetening	units	at	gas	processing	plants.	In	addition,	in	May	2016,	the	U.S.	EPA	issued	regulations	that	require	operators	to	reduce	methane	and	VOC	emissions	from new,	modified	and	reconstructed	crude	oil	and	natural	gas	wells	and	equipment	located	at	natural	gas	production	gathering	and	booster	stations,	gas	processing	plants and	natural	gas	transmission	compressor	stations.

In	November	2016,	the	BLM	issued	a	final	rule	that	limits	venting,	flaring	and	leaking	of	natural	gas	from	oil	and	gas	wells	and	equipment	on	federal	and Indian	lands,	though,	in	September	2018,	the	BLM	issued	a	final	rule	rescinding	certain	requirements	of	that	rule.	There	have	been	various	other	proposals	to	regulate hydraulic	fracturing	at	the	federal	level.	Any	new	federal	regulations	that	may	be	imposed	on	hydraulic	fracturing	could	result	in	additional	permitting	and	disclosure requirements,	additional	operating	and	compliance	costs	and	additional	operating	restrictions.

In	addition	to	these	federal	regulations,	some	state	and	local	governments	have	imposed	or	have	considered	imposing	various	conditions	and	restrictions	on drilling	and	completion	operations,	including	requirements	regarding	casing	and	cementing	of	wells;	testing	of	nearby	water	wells;	restrictions	on	access	to,	and	usage of,	water;	disclosure	of	the	chemical	additives	used	in	hydraulic	fracturing	operations;	restrictions	on	the	type	of	chemical	additives	that	may	be	used	in	hydraulic fracturing	operations;	and	restrictions	on	drilling	or	injection	activities	on	certain	lands	lying	within	wilderness	wetlands,	ecologically	or	seismically	sensitive	areas,	and other	protected	areas.	Such	federal,	state	and	local	permitting	and	disclosure	requirements	and	operating	restrictions	and	conditions	could	lead	to	operational	delays	and increased	operating	and	compliance	costs	and,	moreover,	could	delay	or	effectively	prevent	the	development	of	crude	oil	and	natural	gas	from	formations	which	would not	be	economically	viable	without	the	use	of	hydraulic	fracturing.

EOG	is	unable	to	predict	the	timing,	scope	and	effect	of	any	currently	proposed	or	future	laws	or	regulations	regarding	hydraulic	fracturing	in	the	United	States, but	the	direct	and	indirect	costs	of	such	laws	and	regulations	(if	enacted)	could	materially	and	adversely	affect	EOG's	operations,	financial	condition	and	results	of operations.

Other	International	Regulation.	EOG's	exploration	and	production	operations	outside	the	United	States	are	subject	to	various	types	of	regulations,	including environmental	regulations,	imposed	by	the	respective	governments	of	the	countries	in	which	EOG's	operations	are	conducted,	and	may	affect	EOG's	operations	and	costs of	compliance	within	those	countries.	EOG	currently	has	operations	in	Trinidad,	China	and	Canada	(as	earlier	discussed,	EOG	sold	its	United	Kingdom	operations	in	the fourth	quarter	of	2018).	EOG	is	unable	to	predict	the	timing,	scope	and	effect	of	any	currently	proposed	or	future	laws,	regulations	or	treaties,	including	those	regarding climate	change	and	hydraulic	fracturing,	but	the	direct	and	indirect	costs	of	such	laws,	regulations	and	treaties	(if	enacted)	could	materially	and	adversely	affect	EOG's operations,	financial	condition	and	results	of	operations.	EOG	will	continue	to	review	the	risks	to	its	business	and	operations	associated	with	all	environmental	matters, including	climate	change	and	hydraulic	fracturing	regulation.	In	addition,	EOG	will	continue	to	monitor	and	assess	any	new	policies,	legislation,	regulations	and	treaties in	the	areas	where	it	operates	to	determine	the	impact	on	its	operations	and	take	appropriate	actions,	where	necessary.

Other	Regulation.	EOG	has	sand	mining	and	processing	operations	in	Texas	and	Wisconsin,	which	support	EOG's	exploration	and	development	operations. EOG's	sand	mining	operations	are	subject	to	regulation	by	the	federal	Mine	Safety	and	Health	Administration	(in	respect	of	safety	and	health	matters)	and	by	state agencies	(in	respect	of	air	permitting	and	other	environmental	matters).	The	information	concerning	mine	safety	violations	and	other	regulatory	matters	required	by Section	1503(a)	of	the	Dodd-Frank	Wall	Street	Reform	and	Consumer	Protection	Act	and	Item	104	of	Regulation	S-K	(17	CFR	229.104)	is	included	in	Exhibit	95	to	this report.

# Other	Matters

Energy	Prices.	EOG	is	a	crude	oil	and	natural	gas	producer	and	is	impacted	by	changes	in	prices	of	crude	oil	and	condensate,	NGLs	and	natural	gas.	Average crude	oil	and	condensate	prices	received	by	EOG	for	production	in	the	United	States	increased	28%	in	2018	and	22%	in	2017	and	decreased	12%	in	2016,	each	as compared	to	the	immediately	preceding	year.	Average	NGL	prices	received	by	EOG	for	production	in	the	United	States	increased	18%	in	2018,	55%	in	2017,	and	1%	in 2016,	each	as	compared	to	the	immediately	preceding	year.	During	the	last	three	years,	average	United	States	wellhead	natural	gas	prices	have	fluctuated,	at	times	rather dramatically.	These	fluctuations	resulted	in	a	31%	increase	in	the	average	wellhead	natural	gas	price	received	by	EOG	for	production	in	the	United	States	in	2018 (inclusive	of	a	positive	revenue	adjustment	of	$0.44	per	Mcf	related	to	the	adoption	of	ASU	2014-09),	a	38%	increase	in	2017	and	a	19%	decrease	in	2016,	each	as compared	to	the	immediately	preceding	year.

Due	to	the	many	uncertainties	associated	with	the	world	political	and	economic	environment	(for	example,	the	actions	of	other	crude	oil	exporting	nations, including	the	Organization	of	Petroleum	Exporting	Countries),	the	global	supply	of,	and	demand	for,	crude	oil,	NGLs	and	natural	gas	and	the	availability	of	other	energy supplies,	the	relative	competitive	relationships	of	the	various	energy	sources	in	the	view	of	consumers	and	other	factors,	EOG	is	unable	to	predict	what	changes	may occur	in	prices	of	crude	oil	and	condensate,	NGLs	and	natural	gas	in	the	future.	For	additional	discussion	regarding	changes	in	crude	oil	and	condensate,	NGLs	and natural	gas	prices	and	the	risks	that	such	changes	may	present	to	EOG,	see	ITEM	1A,	Risk	Factors.

Based	on	EOG's	tax	position,	EOG's	price	sensitivity	(exclusive	of	basis	swaps)	in	2019	for	each	$1.00	per	barrel	increase	or	decrease	in	wellhead	crude	oil	and condensate	price,	combined	with	the	estimated	change	in	NGL	price,	is	approximately	$133	million	for	net	income	and	$173	million	for	pretax	cash	flows	from operating	activities.	Based	on	EOG's	tax	position	and	the	portion	of	EOG's	anticipated	natural	gas	volumes	for	2019	for	which	prices	have	not	been	determined	under long-term	marketing	contracts,	EOG's	price	sensitivity	for	each	$0.10	per	Mcf	increase	or	decrease	in	wellhead	natural	gas	price	is	approximately	$29	million	for	net income	and	$37	million	for	pretax	cash	flows	from	operating	activities.	For	a	summary	of	EOG's	financial	commodity	derivative	contracts	through	February	19,	2019, see	ITEM	7,	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	-	Capital	Resources	and	Liquidity	-	Derivative	Transactions.	For a	summary	of	EOG's	financial	commodity	derivative	contracts	for	the	twelve	months	ended	December	31,	2018,	see	Note	12	to	Consolidated	Financial	Statements.

Risk	Management.	EOG	engages	in	price	risk	management	activities	from	time	to	time.	These	activities	are	intended	to	manage	EOG's	exposure	to	fluctuations in	prices	of	crude	oil	and	natural	gas.	EOG	utilizes	financial	commodity	derivative	instruments,	primarily	price	swap,	option,	swaption,	collar	and	basis	swap	contracts, as	a	means	to	manage	this	price	risk.	See	Note	12	to	Consolidated	Financial	Statements.	For	a	summary	of	EOG's	financial	commodity	derivative	contracts	through February	 19,	 2019,	 see	 ITEM	 7,	Management's	 Discussion	 and	Analysis	 of	 Financial	 Condition	 and	 Results	 of	 Operations	 -	 Capital	 Resources	 and	 Liquidity	 - Derivative	Transactions.

All	of	EOG's	crude	oil	and	natural	gas	activities	are	subject	to	the	risks	normally	incident	to	the	exploration	for,	and	development,	production	and	transportation of,	crude	oil	and	natural	gas,	including	rig	and	well	explosions,	cratering,	fires,	loss	of	well	control	and	leaks	and	spills,	each	of	which	could	result	in	damage	to	life, property	and/or	the	environment.	EOG's	operations	are	also	subject	to	certain	perils,	including	hurricanes,	flooding	and	other	adverse	weather	events.	Moreover,	EOG's activities	are	subject	to	governmental	regulations	as	well	as	interruption	or	termination	by	governmental	authorities	based	on	environmental	and	other	considerations. Losses	and	liabilities	arising	from	such	events	could	reduce	revenues	and	increase	costs	to	EOG	to	the	extent	not	covered	by	insurance.

Insurance	is	maintained	by	EOG	against	some,	but	not	all,	of	these	risks	in	accordance	with	what	EOG	believes	are	customary	industry	practices	and	in amounts	and	at	costs	that	EOG	believes	to	be	prudent	and	commercially	practicable.	Specifically,	EOG	maintains	commercial	general	liability	and	excess	liability coverage	 provided	 by	 third-party	 insurers	 for	 bodily	 injury	 or	 death	 claims	 resulting	 from	 an	 incident	 involving	 EOG's	 operations	 (subject	 to	 policy	 terms	 and conditions).	Moreover,	in	the	event	an	incident	involving	EOG's	operations	results	in	negative	environmental	effects,	EOG	maintains	operators	extra	expense	coverage provided	by	third-party	insurers	for	obligations,	expenses	or	claims	that	EOG	may	incur	from	such	an	incident,	including	obligations,	expenses	or	claims	in	respect	of seepage	and	pollution,	cleanup	and	containment,	evacuation	expenses	and	control	of	the	well	(subject	to	policy	terms	and	conditions).	In	the	event	of	a	well	control incident	resulting	in	negative	environmental	effects,	such	operators	extra	expense	coverage	would	be	EOG's	primary	coverage,	with	the	commercial	general	liability	and excess	liability	coverage	referenced	above	also	providing	certain	coverage	to	EOG.	All	of	EOG's	drilling	activities	are	conducted	on	a	contractual	basis	with	independent drilling	contractors	and	other	third-party	service	contractors.	The	indemnification	and	other	risk	allocation	provisions	included	in	such	contracts	are	negotiated	on	a contract-by-contract	basis	and	are	each	based	on	the	particular	circumstances	of	the	services	being	provided	and	the	anticipated	operations.

In	addition	to	the	above-described	risks,	EOG's	operations	outside	the	United	States	are	subject	to	certain	risks,	including	the	risk	of	increases	in	taxes	and governmental	royalties,	changes	in	laws	and	policies	governing	the	operations	of	foreign-based	companies,	expropriation	of	assets,	unilateral	or	forced	renegotiation	or modification	of	existing	contracts	with	governmental	entities,	currency	restrictions	and	exchange	rate	fluctuations.	Please	refer	to	ITEM	1A,	Risk	Factors,	for	further discussion	of	the	risks	to	which	EOG	is	subject	with	respect	to	its	operations	outside	the	United	States.

# Executive	Officers	of	the	Registrant

The	current	executive	officers	of	EOG	and	their	names	and	ages	(as	of	February	26,	2019)	are	as	follows:

William	R.	Thomas	was	elected	Chairman	of	the	Board	and	Chief	Executive	Officer	effective	January	2014.	He	was	elected	Senior	Vice	President	and	General Manager	of	EOG's	Fort	Worth,	Texas,	office	in	June	2004,	Executive	Vice	President	and	General	Manager	of	EOG's	Fort	Worth,	Texas,	office	in	February	2007	and Senior	Executive	Vice	President,	Exploitation	in	February	2011.	He	subsequently	served	as	Senior	Executive	Vice	President,	Exploration	from	July	2011	to	September 2011,	as	President	from	September	2011	to	July	2013	and	as	President	and	Chief	Executive	Officer	from	July	2013	to	December	2013.	Mr.	Thomas	joined	a	predecessor of	EOG	in	January	1979.	Mr.	Thomas	is	EOG's	principal	executive	officer.

Lloyd	W.	Helms,	Jr.	was	elected	Chief	Operating	Officer	in	December	2017.	Prior	to	that,	he	served	as	Executive	Vice	President,	Exploration	and	Production from	August	2013	to	December	2017.	He	was	elected	Vice	President,	Engineering	and	Acquisitions	in	September	2006,	Vice	President	and	General	Manager	of	EOG's Calgary,	Alberta,	 Canada	 office	 in	 March	 2008,	 and	 served	 as	 Executive	Vice	 President,	 Operations	 from	 February	 2012	 to	August	 2013.	 Mr.	 Helms	 joined	 a predecessor	of	EOG	in	February	1981.

Kenneth	W.	Boedeker	was	elected	Executive	Vice	President,	Exploration	and	Production	in	December	2018.	 	He	served	as	Vice	President	and	General Manager	of	EOG's	Denver,	Colorado,	office	from	October	2016	to	December	2018,	and	as	Vice	President,	Engineering	and	Acquisitions	from	July	2015	to	October 2016.		Prior	to	that,	Mr.	Boedeker	held	technical	and	managerial	positions	of	increasing	responsibility	across	multiple	offices	and	functional	areas	within	EOG.		Mr. Boedeker	joined	EOG	in	July	1994.

Ezra	Y.	Yacob	was	elected	Executive	Vice	President,	Exploration	and	Production	in	December	2017.	 He	served	as	Vice	President	and	General	Manager	of EOG's	Midland,	Texas,	office	from	May	2014	to	December	2017.	Prior	to	that,	he	served	as	Manager,	Division	Exploration	in	EOG's	Fort	Worth,	Texas,	and	Midland, Texas,	offices	from	March	2012	to	May	2014	as	well	as	in	various	geoscience	and	leadership	positions.	Mr.	Yacob	joined	EOG	in	August	2005.

Timothy	K.	Driggers	was	elected	Executive	Vice	President	and	Chief	Financial	Officer	in	April	2016.	 Previously,	Mr.	Driggers	served	as	Vice	President	and Chief	Financial	Officer	from	July	2007	to	April	2016.	He	was	elected	Vice	President	and	Controller	of	EOG	in	October	1999,	was	subsequently	named	Vice	President, Accounting	and	Land	Administration	in	October	2000	and	Vice	President	and	Chief	Accounting	Officer	in	August	2003.	 Mr.	Driggers	is	EOG's	principal	financial officer.	Mr.	Driggers	joined	a	predecessor	of	EOG	in	August	1995.

Michael	P.	Donaldson	was	elected	Executive	Vice	President,	General	Counsel	and	Corporate	Secretary	in	April	2016.	 Previously,	Mr.	Donaldson	served	as Vice	President,	General	Counsel	and	Corporate	Secretary	from	May	2012	to	April	2016.	He	was	elected	Corporate	Secretary	in	May	2008,	and	was	appointed	Deputy General	Counsel	and	Corporate	Secretary	in	July	2010.	Mr.	Donaldson	joined	EOG	in	September	2007.

# ITEM	1A.	Risk	Factors

Our	business	and	operations	are	subject	to	many	risks.	The	risks	described	below	may	not	be	the	only	risks	we	face,	as	our	business	and	operations	may	also	be subject	to	risks	that	we	do	not	yet	know	of,	or	that	we	currently	believe	are	immaterial.	If	any	of	the	events	or	circumstances	described	below	actually	occurs,	our business,	financial	condition,	results	of	operations	or	cash	flows	could	be	materially	and	adversely	affected	and	the	trading	price	of	our	common	stock	could	decline.	The following	risk	factors	should	be	read	in	conjunction	with	the	other	information	contained	herein,	including	the	consolidated	financial	statements	and	the	related	notes. Unless	the	context	requires	otherwise,	"we,"	"us,"	"our"	and	"EOG"	refer	to	EOG	Resources,	Inc.	and	its	subsidiaries.

Crude	oil,	natural	gas	and	NGL	prices	are	volatile,	and	a	substantial	and	extended	decline	in	commodity	prices	can	have	a	material	and	adverse	effect	on	us.

Prices	for	crude	oil	and	natural	gas	(including	prices	for	natural	gas	liquids	(NGLs)	and	condensate)	fluctuate	widely.	Among	the	interrelated	factors	that	can	or could	cause	these	price	fluctuations	are:

•domestic	and	worldwide	supplies	of	crude	oil,	NGLs	and	natural	gas;

•domestic	and	international	drilling

activity;

•the	actions	of	other	crude	oil	producing	and	exporting	nations,	including	the	Organization	of	Petroleum	Exporting Countries;

•consumer	and	industrial/commercial	demand	for	crude	oil,	natural	gas	and

NGLs;

•worldwide	economic	conditions,	geopolitical	factors	and	political	conditions,	including,	but	not	limited	to,	the	imposition	of	tariffs	or	trade	or	other economic	sanctions,	political	instability	or	armed	conflict	in	oil	and	gas	producing	regions;

•the	 availability,	 proximity	 and	 capacity	 of	 appropriate	 transportation,	 gathering,	 processing, compression, storage and refining facilities;

•the	price	and	availability	of,	and	demand	for,	competing	energy	sources,	including	alternative	energy

sources;

•the	effect	of	worldwide	energy	conservation	measures,	alternative	fuel	requirements	and	climate	change-related initiatives;

•the	 nature	 and	 extent	 of	 governmental	 regulation,	 including	 environmental	 and	 other	 climate	 change-related	 regulation,	 regulation	 of	 derivatives transactions	and	hedging	activities,	tax	laws	and	regulations	and	laws	and	regulations	with	respect	to	the	import	and	export	of	crude	oil,	natural	gas	and related	commodities;

•the	level	and	effect	of	trading	in	commodity	futures	markets,	including	trading	by	commodity	price	speculators	and	others; and

•weather conditions and changes in weather patterns.

Beginning	in	the	fourth	quarter	of	2014	and	continuing	through	2016,	crude	oil	prices	substantially	declined.	In	addition,	natural	gas	and	NGL	prices	began	to decline	substantially	in	the	second	quarter	of	2014	and	such	lower	prices	continued	through	2016.	While	crude	oil,	natural	gas	and	NGL	prices	improved	significantly during	2017	and	2018,	the	above-described	factors	and	the	volatility	of	commodity	prices	make	it	difficult	to	predict	future	crude	oil,	natural	gas	and	NGL	prices.	For example,	during	the	fourth	quarter	of	2018,	there	was	a	substantial	decline	in	the	prices	for	crude	oil	and	NGLs,	whereas	natural	gas	prices	increased	significantly	during such	period.	As	a	result,	there	can	be	no	assurance	that	the	prices	for	crude	oil,	natural	gas	and/or	NGLs	will	sustain,	or	increase	from,	their	current	levels	and	not decline.

Our	cash	flows	and	results	of	operations	depend	to	a	great	extent	on	prevailing	commodity	prices.	Accordingly,	substantial	and	extended	declines	in	commodity prices	can	materially	and	adversely	affect	the	amount	of	cash	flows	we	have	available	for	our	capital	expenditures	and	other	operating	expenses,	the	terms	on	which	we can	access	the	credit	and	capital	markets	and	our	results	of	operations.

Lower	commodity	prices	can	also	reduce	the	amount	of	crude	oil,	natural	gas	and	NGLs	that	we	can	produce	economically.	Substantial	and	extended	declines in	 the	prices	of	 these	commodities	can	render	uneconomic	a	portion	of	our	exploration,	development	and	exploitation	projects,	resulting	 in	our	having	 to	make downward	adjustments	to	our	estimated	proved	reserves.	In	addition,	significant	prolonged	decreases	in	commodity	prices	may	cause	the	expected	future	cash	flows from	our	properties	to	fall	below	their	respective	net	book	values,	which	will	require	us	to	write	down	the	value	of	our	properties.	Such	reserve	write-downs	and	asset impairments	could	materially	and	adversely	affect	our	results	of	operations	and	financial	position	and,	in	turn,	the	trading	price	of	our	common	stock.

In	fact,	the	substantial	declines	in	crude	oil,	natural	gas,	and	NGL	prices	that	began	in	2014	and	continued	in	2015	and	through	2016	materially	and	adversely affected	the	amount	of	cash	flows	we	had	available	for	our	capital	expenditures	and	other	operating	expenses	and	our	results	of	operations	during	fiscal	years	2015	and 2016.	Such	declines	also	adversely	affected	the	trading	price	of	our	common	stock.

If	commodity	prices	decline	from	current	levels	for	an	extended	period	of	time,	our	financial	condition,	cash	flows	and	results	of	operations	will	be	adversely affected	and	we	may	be	limited	in	our	ability	to	maintain	our	current	level	of	dividends	on	our	common	stock.	In	addition,	we	may	be	required	to	incur	impairment charges	and/or	make	downward	adjustments	to	our	proved	reserve	estimates.	As	a	result,	our	financial	condition	and	results	of	operations	and	the	trading	price	of	our common	stock	may	be	adversely	affected.

Drilling	crude	oil	and	natural	gas	wells	is	a	high-risk	activity	and	subjects	us	to	a	variety	of	risks	that	we	cannot	control.

Drilling	crude	oil	and	natural	gas	wells,	including	development	wells,	involves	numerous	risks,	including	the	risk	that	we	may	not	encounter	commercially productive	crude	oil	and	natural	gas	reserves	(including	"dry	holes").	As	a	result,	we	may	not	recover	all	or	any	portion	of	our	investment	in	new	wells.

Specifically,	we	often	are	uncertain	as	to	the	future	cost	or	timing	of	drilling,	completing	and	operating	wells,	and	our	drilling	operations	and	those	of	our	third- party	operators	may	be	curtailed,	delayed	or	canceled,	the	cost	of	such	operations	may	increase	and/or	our	results	of	operations	and	cash	flows	from	such	operations	may be	impacted,	as	a	result	of	a	variety	of	factors,	including:

•unexpected	drilling

conditions;

•title	problems;

•pressure	or	irregularities	in

formations;

•equipment	failures	or	accidents;

•adverse	 weather	 conditions,	 such	 as	 winter	 storms, flooding, tropical	 storms	 and	 hurricanes,	 and	 changes in	 weather patterns;

•compliance	with,	or	changes	in,	environmental,	health	and	safety	laws	and	regulations	relating	to	air	emissions,	hydraulic	fracturing,	access	to	and	use	of water,	disposal	or	other	discharge	(e.g.,	into	injection	wells)	of	produced	water,	drilling	fluids	and	other	wastes,	laws	and	regulations	imposing	conditions or	restrictions	on	drilling	and	completion	operations	and	on	the	transportation	of	crude	oil	and	natural	gas,	and	other	laws	and	regulations,	such	as	tax	laws and	regulations;

•the	availability	and	timely	issuance	of	required	federal,	state,	tribal	and	other	permits	and	licenses,	which	may	be	affected	by	(among	other	things) government	shutdowns	or	other	suspensions	of,	or	delays	in,	government	services;

•the	availability	of,	costs	associated	with	and	terms	of	contractual	arrangements	for	properties,	including	mineral	licenses	and	leases,	pipelines,	crude	oil hauling	trucks	and	qualified	drivers	and	facilities	and	equipment	to	gather,	process,	compress,	store,	transport	and	market	crude	oil,	natural	gas	and	related commodities;	and

•the	costs	of,	or	shortages	or	delays	in	the	availability	of,	drilling	rigs,	hydraulic	fracturing	services,	pressure	pumping	equipment	and	supplies,	tubular materials,	water,	sand,	disposal	facilities,	qualified	personnel	and	other	necessary	facilities,	equipment,	materials,	supplies	and	services.

Our	failure	to	recover	our	investment	in	wells,	increases	in	the	costs	of	our	drilling	operations	or	those	of	our	third-party	operators,	and/or	curtailments,	delays or	cancellations	of	our	drilling	operations	or	those	of	our	third-party	operators,	in	each	case,	due	to	any	of	the	above	factors	or	other	factors,	may	materially	and adversely	affect	our	business,	financial	condition	and	results	of	operations.	For	related	discussion	of	the	risks	and	potential	losses	and	liabilities	inherent	in	our	crude	oil and	natural	gas	operations	generally,	see	the	immediately	following	risk	factor.

Our	crude	oil	and	natural	gas	operations	and	supporting	activities	and	operations	involve	many	risks	and	expose	us	to	potential	losses	and	liabilities,	and	insurance may	not	fully	protect	us	against	these	risks	and	potential	losses	and	liabilities.

Our	crude	oil	and	natural	gas	operations	and	supporting	activities	and	operations	are	subject	to	all	of	the	risks	associated	with	exploring	and	drilling	for,	and producing,	gathering,	processing,	compressing,	storing	and	transporting,	crude	oil	and	natural	gas,	including	the	risks	of:

•well	blowouts	and	cratering;

•loss	of	well

control;

•crude	oil	spills,	natural	gas	leaks,	formation	water	(i.e.,	produced	water)	spills	and	pipeline

ruptures;

•pipe	failures	and	casing	collapses;

•uncontrollable	flows	of	crude	oil,	natural	gas,	formation	water	or	drilling fluids;

•releases	of	chemicals,	wastes	or	pollutants;

•adverse	 weather	 events,	 such	 as	 winter storms, flooding, tropical storms	 and	 hurricanes,	 and	 other	 natural disasters;

•fires	and	explosions;

•terrorism,	vandalism	and	physical,	electronic	and	cybersecurity

breaches;

•formations	with	abnormal	or	unexpected	pressures;

•leaks	or	spills	in	connection	with,	or	associated	with,	the	gathering,	processing,	compression,	storage	and	transportation	of	crude	oil	and	natural	gas;

•malfunctions	of,	or	damage	to,	gathering,	processing,	compression	and	transportation	facilities	and	equipment	and	other	facilities	and	equipment	utilized	in support	of	our	crude	oil	and	natural	gas	operations.

If	any	of	these	events	occur,	we	could	incur	losses,	liabilities	and	other	additional	costs	as	a	result	of:

•injury	or	loss	of	life;

•damage	to,	or	destruction	of,	property,	facilities,	equipment	and	crude	oil	and	natural	gas

reservoirs;

•pollution	or	other	environmental	damage;

•regulatory	investigations	and	penalties	as	well	as	cleanup	and	remediation	responsibilities	and

costs;

•suspension	or	interruption	of	our	operations,	including	due	to injunction;

•repairs	necessary	to	resume	operations;

•compliance	with	laws	and	regulations	enacted	as	a	result	of	such

events.

We	maintain	insurance	against	many,	but	not	all,	such	losses	and	liabilities	in	accordance	with	what	we	believe	are	customary	industry	practices	and	in	amounts and	at	costs	that	we	believe	to	be	prudent	and	commercially	practicable.	However,	the	occurrence	of	any	of	these	events	and	any	losses	or	liabilities	incurred	as	a	result of	such	events,	if	uninsured	or	in	excess	of	our	insurance	coverage,	would	reduce	the	funds	available	to	us	for	our	operations	and	could,	in	turn,	have	a	material	adverse effect	on	our	business,	financial	condition	and	results	of	operations.

Our	ability	to	sell	and	deliver	our	crude	oil	and	natural	gas	production	could	be	materially	and	adversely	affected	if	adequate	gathering,	processing,	compression, storage	and	transportation	facilities	and	equipment	are	unavailable.

The	sale	of	our	crude	oil	and	natural	gas	production	depends	on	a	number	of	factors	beyond	our	control,	including	the	availability,	proximity	and	capacity	of, and	costs	associated	with,	gathering,	processing,	compression,	storage	and	transportation	facilities	and	equipment	owned	by	third	parties.	These	facilities	may	be temporarily	unavailable	to	us	due	to	market	conditions,	regulatory	reasons,	mechanical	reasons	or	other	factors	or	conditions,	and	may	not	be	available	to	us	in	the	future on	terms	we	consider	acceptable,	if	at	all.	In	particular,	in	certain	newer	plays,	the	capacity	of	gathering,	processing,	compression,	storage	and	transportation	facilities and	equipment	may	not	be	sufficient	to	accommodate	potential	production	from	existing	and	new	wells.	In	addition,	lack	of	financing,	construction	and	permitting delays,	permitting	costs	and	regulatory	or	other	constraints	could	 limit	or	delay	 the	construction,	manufacture	or	other	acquisition	of	new	gathering,	processing, compression,	storage	and	transportation	facilities	and	equipment	by	third	parties	or	us,	and	we	may	experience	delays	or	increased	costs	in	accessing	the	pipelines, gathering	systems	or	rail	systems	necessary	to	transport	our	production	to	points	of	sale	or	delivery.

Any	significant	change	in	market	or	other	conditions	affecting	gathering,	processing,	compression,	storage	or	transportation	facilities	and	equipment	or	the availability	of	these	facilities,	including	due	to	our	failure	or	inability	to	obtain	access	to	these	facilities	and	equipment	on	terms	acceptable	to	us	or	at	all,	could materially	and	adversely	affect	our	business	and,	in	turn,	our	financial	condition	and	results	of	operations.

If	we	fail	to	acquire	or	find	sufficient	additional	reserves	over	time,	our	reserves	and	production	will	decline	from	their	current	levels.

The	rate	of	production	from	crude	oil	and	natural	gas	properties	generally	declines	as	reserves	are	produced.	Except	to	the	extent	that	we	conduct	successful exploration,	exploitation	and	development	activities	resulting	in	additional	reserves,	acquire	additional	properties	containing	reserves	or,	through	engineering	studies, identify	additional	behind-pipe	zones	or	secondary	recovery	reserves,	our	reserves	will	decline	as	they	are	produced.	Maintaining	our	production	of	crude	oil	and	natural gas	at,	or	increasing	our	production	from,	current	levels,	is,	therefore,	highly	dependent	upon	our	level	of	success	in	acquiring	or	finding	additional	reserves.	To	the extent	we	are	unsuccessful	in	acquiring	or	finding	additional	reserves,	our	future	cash	flows	and	results	of	operations	and,	in	turn,	the	trading	price	of	our	common	stock could	be	materially	and	adversely	affected.

We	incur	certain	costs	to	comply	with	government	regulations,	particularly	regulations	relating	to	environmental	protection	and	safety,	and	could	incur	even	greater costs	in	the	future.

Our	crude	oil	and	natural	gas	operations	and	supporting	activities	are	regulated	extensively	by	federal,	state,	tribal	and	local	governments	and	regulatory agencies,	both	domestically	and	in	the	foreign	countries	in	which	we	do	business,	and	are	subject	to	interruption	or	termination	by	governmental	and	regulatory authorities	based	on	environmental,	health,	safety	or	other	considerations.	Moreover,	we	have	incurred	and	will	continue	to	incur	costs	in	our	efforts	to	comply	with	the requirements	of	environmental,	health,	safety	and	other	regulations.	Further,	the	regulatory	environment	could	change	in	ways	that	we	cannot	predict	and	that	might substantially	increase	our	costs	of	compliance	and,	in	turn,	materially	and	adversely	affect	our	business,	results	of	operations	and	financial	condition.

Specifically,	as	a	current	or	past	owner	or	lessee	and	operator	of	crude	oil	and	natural	gas	properties,	we	are	subject	to	various	federal,	state,	tribal,	local	and foreign	regulations	relating	to	the	discharge	of	materials	into,	and	the	protection	of,	the	environment.	These	regulations	may,	among	other	things,	impose	liability	on	us for	the	cost	of	pollution	cleanup	resulting	from	current	or	past	operations,	subject	us	to	liability	for	pollution	damages	and	require	suspension	or	cessation	of	operations in	affected	areas.	Changes	in,	or	additions	to,	these	regulations	could	lead	to	increased	operating	and	compliance	costs	and,	in	turn,	materially	and	adversely	affect	our business,	results	of	operations	and	financial	condition.

Local,	state,	federal	and	international	regulatory	bodies	have	been	increasingly	focused	on	greenhouse	gas	(GHG)	emissions	and	climate	change	issues	in	recent years.	For	example,	we	are	subject	to	the	United	States	(U.S.)	Environmental	Protection	Agency's	(U.S.	EPA)	rule	requiring	annual	reporting	of	GHG	emissions.	In addition,	in	May	2016,	the	U.S.	EPA	issued	regulations	that	require	operators	to	reduce	methane	emissions	and	emissions	of	volatile	organic	compounds	from	new, modified	and	reconstructed	crude	oil	and	natural	gas	wells	and	equipment	located	at	natural	gas	production	gathering	and	booster	stations,	gas	processing	plants	and natural	gas	transmission	compressor	stations.

It	is	possible	that	the	Paris	Agreement	and	subsequent	domestic	and	international	regulations	will	have	adverse	effects	on	the	market	for	crude	oil,	natural	gas and	other	fossil	fuel	products	as	well	as	adverse	effects	on	the	business	and	operations	of	companies	engaged	in	the	exploration	for,	and	production	of,	crude	oil,	natural gas	and	other	fossil	fuel	products.	EOG	is	unable	to	predict	the	timing,	scope	and	effect	of	any	currently	proposed	or	future	investigations,	laws,	regulations	or	treaties regarding	climate	change	and	GHG	emissions,	but	the	direct	and	indirect	costs	of	such	investigations,	laws,	regulations	and	treaties	(if	enacted)	could	materially	and adversely	affect	EOG's	operations,	financial	condition	and	results	of	operations.

The	regulation	of	hydraulic	fracturing	is	primarily	conducted	at	the	state	and	local	level	through	permitting	and	other	compliance	requirements.	In	November 2016,	however,	the	U.S.	Bureau	of	Land	Management	(BLM)	issued	a	final	rule	that	limits	venting,	flaring	and	leaking	of	natural	gas	from	oil	and	gas	wells	and equipment	on	federal	and	Indian	lands	(in	September	2018,	the	BLM	issued	a	final	rule	rescinding	certain	requirements	of	the	rule).	In	addition,	the	U.S.	EPA	has	issued regulations	relating	to	hydraulic	fracturing	and	there	have	been	various	other	proposals	to	regulate	hydraulic	fracturing	at	the	federal	level.	Any	new	federal	regulations that	may	be	imposed	on	hydraulic	fracturing	could	result	in	additional	permitting	and	disclosure	requirements,	additional	operating	and	compliance	costs	and	additional operating	 restrictions.	Moreover,	some	state	and	local	governments	have	imposed	or	have	considered	imposing	various	conditions	and	restrictions	on	drilling	and completion	operations.	Any	such	federal	or	state	requirements,	restrictions	or	conditions	could	lead	to	operational	delays	and	increased	operating	and	compliance	costs and,	moreover,	could	delay	or	effectively	prevent	the	development	of	crude	oil	and	natural	gas	from	formations	which	would	not	be	economically	viable	without	the	use of	hydraulic	fracturing.	Accordingly,	our	production	of	crude	oil	and	natural	gas	could	be	materially	and	adversely	affected.	For	additional	discussion	regarding	climate change	 regulation	 and	 hydraulic	 fracturing	 regulation,	 see	 Climate	 Change	 -	 United	 States	 and	 Hydraulic	 Fracturing	 -	 United	 States	 under	 ITEM	 1,	 Business	 - Regulation.

We	will	continue	to	monitor	and	assess	any	proposed	or	new	policies,	legislation,	regulations	and	treaties	in	the	areas	where	we	operate	to	determine	the	impact on	our	operations	and	take	appropriate	actions,	where	necessary.	We	are	unable	to	predict	the	timing,	scope	and	effect	of	any	currently	proposed	or	future	laws, regulations	or	treaties,	but	the	direct	and	indirect	costs	of	such	laws,	regulations	and	treaties	(if	enacted)	could	materially	and	adversely	affect	our	business,	results	of operations	and	financial	condition.	For	related	discussion,	see	the	risk	factor	below	regarding	the	provisions	of	the	Dodd-Frank	Wall	Street	Reform	and	Consumer Protection	Act	with	respect	to	regulation	of	derivatives	transactions	and	entities	(such	as	EOG)	that	participate	in	such	transactions.

Tax	laws	and	regulations	applicable	to	crude	oil	and	natural	gas	exploration	and	production	companies	may	change	over	time,	and	such	changes	could	materially	and adversely	affect	our	cash	flows,	results	of	operations	and	financial	condition.

From	time	to	time,	legislation	has	been	proposed	that,	if	enacted	into	law,	would	make	significant	changes	to	U.S.	federal	income	tax	laws	applicable	to	crude oil	and	natural	gas	exploration	and	production	companies,	such	as	with	respect	to	the	intangible	drilling	and	development	costs	deduction	and	bonus	tax	depreciation. While	these	specific	changes	were	not	included	in	the	Tax	Cuts	and	Jobs	Act	signed	into	law	in	December	2017,	no	accurate	prediction	can	be	made	as	to	whether	any such	legislative	changes	or	similar	or	other	tax	law	changes	will	be	proposed	in	the	future	and,	if	enacted,	what	the	specific	provisions	or	the	effective	date	of	any	such legislation	would	be.	The	elimination	of	certain	U.S.	federal	income	tax	deductions,	as	well	as	any	other	changes	to,	or	the	imposition	of	new,	federal,	state,	local	or non-U.S.	taxes	(including	the	imposition	of,	or	increases	in,	production,	severance	or	similar	taxes),	could	materially	and	adversely	affect	our	cash	flows,	results	of operations	and	financial	condition.

A	portion	of	our	crude	oil	and	natural	gas	production	may	be	subject	to	interruptions	that	could	have	a	material	and	adverse	effect	on	us.

A	portion	of	our	crude	oil	and	natural	gas	production	may	be	interrupted,	or	shut	in,	from	time	to	time	for	various	reasons,	including,	but	not	limited	to,	as	a result	of	accidents,	weather	conditions,	the	unavailability	of	gathering,	processing,	compression,	storage,	transportation	or	refining	facilities	or	equipment	or	field	labor issues,	or	intentionally	as	a	result	of	market	conditions	such	as	crude	oil	or	natural	gas	prices	that	we	deem	uneconomic.	If	a	substantial	amount	of	our	production	is interrupted	or	shut	in,	our	cash	flows	and,	in	turn,	our	financial	condition	and	results	of	operations	could	be	materially	and	adversely	affected.

# We	have	limited	control	over	the	activities	on	properties	we	do	not	operate.

Some	of	the	properties	in	which	we	have	an	interest	are	operated	by	other	companies	and	involve	third-party	working	interest	owners.	As	a	result,	we	have limited	ability	to	influence	or	control	the	operation	or	future	development	of	such	properties,	including	compliance	with	environmental,	safety	and	other	regulations,	or the	amount	of	capital	expenditures	that	we	will	be	required	to	fund	with	respect	to	such	properties.	Moreover,	we	are	dependent	on	the	other	working	interest	owners	of such	projects	to	fund	their	contractual	share	of	the	capital	expenditures	of	such	projects.	In	addition,	a	third-party	operator	could	also	decide	to	shut-in	or	curtail production	from	wells,	or	plug	and	abandon	marginal	wells,	on	properties	owned	by	that	operator	during	periods	of	lower	crude	oil	or	natural	gas	prices.	These limitations	and	our	dependence	on	the	operator	and	third-party	working	interest	owners	for	these	projects	could	cause	us	to	incur	unexpected	future	costs,	lower production	and	materially	and	adversely	affect	our	financial	condition	and	results	of	operations.

If	we	acquire	crude	oil	and	natural	gas	properties,	our	failure	to	fully	identify	existing	and	potential	problems,	to	accurately	estimate	reserves,	production	rates	or	costs, or	to	effectively	integrate	the	acquired	properties	into	our	operations	could	materially	and	adversely	affect	our	business,	financial	condition	and	results	of	operations.

From	time	to	time,	we	seek	to	acquire	crude	oil	and	natural	gas	properties	-	for	example,	our	October	2016	mergers	and	related	asset	purchase	transactions	with Yates	Petroleum	Corporation	and	certain	of	its	affiliated	entities.	Although	we	perform	reviews	of	properties	to	be	acquired	in	a	manner	that	we	believe	is	duly	diligent and	consistent	with	industry	practices,	reviews	of	records	and	properties	may	not	necessarily	reveal	existing	or	potential	problems	(such	as	title	or	environmental	issues), nor	may	they	permit	us	to	become	sufficiently	familiar	with	the	properties	in	order	to	assess	fully	their	deficiencies	and	potential.	Even	when	problems	with	a	property are	identified,	we	often	may	assume	environmental	and	other	risks	and	liabilities	in	connection	with	acquired	properties	pursuant	to	the	acquisition	agreements.

In	addition,	there	are	numerous	uncertainties	inherent	in	estimating	quantities	of	crude	oil	and	natural	gas	reserves	(as	discussed	further	below),	actual	future production	rates	and	associated	costs	with	respect	to	acquired	properties.	Actual	reserves,	production	rates	and	costs	may	vary	substantially	from	those	assumed	in	our estimates.	In	addition,	an	acquisition	may	have	a	material	and	adverse	effect	on	our	business	and	results	of	operations,	particularly	during	the	periods	in	which	the operations	of	the	acquired	properties	are	being	integrated	into	our	ongoing	operations	or	if	we	are	unable	to	effectively	integrate	the	acquired	properties	into	our	ongoing operations.

We	have	substantial	capital	requirements,	and	we	may	be	unable	to	obtain	needed	financing	on	satisfactory	terms,	if	at	all.

We	make,	and	will	continue	to	make,	substantial	capital	expenditures	for	the	acquisition,	exploration,	development,	production	and	transportation	of	crude	oil and	natural	gas	reserves.	We	intend	to	finance	our	capital	expenditures	primarily	through	our	cash	flows	from	operations,	commercial	paper	borrowings,	sales	of	non- core	assets	and	borrowings	under	other	uncommitted	credit	facilities	and,	to	a	lesser	extent	and	if	and	as	necessary,	bank	borrowings,	borrowings	under	our	revolving credit	facility	and	public	and	private	equity	and	debt	offerings.

Lower	crude	oil	and	natural	gas	prices,	however,	reduce	our	cash	flows	and	could	also	delay	or	impair	our	ability	to	consummate	certain	planned	non-core	asset sales	and	divestitures.	Further,	if	the	condition	of	the	credit	and	capital	markets	materially	declines,	we	might	not	be	able	to	obtain	financing	on	terms	we	consider acceptable,	if	at	all.	In	addition,	weakness	and/or	volatility	in	domestic	and	global	financial	markets	or	economic	conditions	or	a	depressed	commodity	price	environment may	increase	the	interest	rates	that	lenders	and	commercial	paper	investors	require	us	to	pay	or	adversely	affect	our	ability	to	finance	our	capital	expenditures	through equity	or	debt	offerings	or	other	borrowings.

Similarly,	a	reduction	in	our	cash	flows	(for	example,	as	a	result	of	lower	crude	oil	and	natural	gas	prices	or	unanticipated	well	shut-ins)	and	the	corresponding adverse	effect	on	our	financial	condition	and	results	of	operations	may	also	increase	the	interest	rates	that	lenders	and	commercial	paper	investors	require	us	to	pay.	A substantial	increase	in	interest	rates	would	decrease	our	net	cash	flows	available	for	reinvestment.	Any	of	these	factors	could	have	a	material	and	adverse	effect	on	our business,	financial	condition	and	results	of	operations.

Further,	our	ability	to	obtain	financings,	our	borrowing	costs	and	the	terms	of	any	financings	are,	in	part,	dependent	on	the	credit	ratings	assigned	to	our	debt	by independent	credit	rating	agencies.	The	interrelated	factors	that	may	impact	our	credit	ratings	include	our	debt	levels;	planned	asset	purchases	or	sales;	near-term	and long-term	production	growth	opportunities;	liquidity;	asset	quality;	cost	structure;	product	mix;	and	commodity	pricing	levels	(including,	but	not	limited	to,	the	estimates and	assumptions	of	credit	rating	agencies	with	respect	to	future	commodity	prices).	We	cannot	provide	any	assurance	that	our	current	credit	ratings	will	remain	in	effect for	any	given	period	of	time	or	that	our	credit	ratings	will	be	raised	in	the	future,	nor	can	we	provide	any	assurance	that	any	of	our	credit	ratings	will	not	be	lowered.

The	inability	of	our	customers	and	other	contractual	counterparties	to	satisfy	their	obligations	to	us	may	have	a	material	and	adverse	effect	on	us.

We	have	various	customers	for	the	crude	oil,	natural	gas	and	related	commodities	that	we	produce	as	well	as	various	other	contractual	counterparties,	including several	financial	institutions	and	affiliates	of	financial	institutions.	Domestic	and	global	economic	conditions,	including	the	financial	condition	of	financial	institutions generally,	may	adversely	affect	the	ability	of	our	customers	and	other	contractual	counterparties	to	pay	amounts	owed	to	us	from	time	to	time	and	to	otherwise	satisfy their	contractual	obligations	to	us,	as	well	as	their	ability	to	access	the	credit	and	capital	markets	for	such	purposes.

Moreover,	our	customers	and	other	contractual	counterparties	may	be	unable	 to	satisfy	 their	contractual	obligations	 to	us	for	reasons	unrelated	 to	 these conditions	and	factors,	such	as	the	unavailability	of	required	facilities	or	equipment	due	to	mechanical	failure	or	market	conditions.	Furthermore,	if	a	customer	is	unable to	satisfy	its	contractual	obligation	to	purchase	crude	oil,	natural	gas	or	related	commodities	from	us,	we	may	be	unable	to	sell	such	production	to	another	customer	on terms	we	consider	acceptable,	if	at	all,	due	to	the	geographic	location	of	such	production;	the	availability,	proximity	and	capacity	of	appropriate	gathering,	processing, compression,	storage,	transportation	and	refining	facilities;	or	market	or	other	factors	and	conditions.

The	inability	of	our	customers	and	other	contractual	counterparties	to	pay	amounts	owed	to	us	and	to	otherwise	satisfy	their	contractual	obligations	to	us	may materially	and	adversely	affect	our	business,	financial	condition,	results	of	operations	and	cash	flows.

Competition	in	the	oil	and	gas	exploration	and	production	industry	is	intense,	and	many	of	our	competitors	have	greater	resources	than	we	have.

We	compete	with	major	integrated	oil	and	gas	companies,	government-affiliated	oil	and	gas	companies	and	other	independent	oil	and	gas	companies	for	the acquisition	of	licenses	and	leases,	properties	and	reserves	and	access	to	the	facilities,	equipment,	materials,	services	and	employees	and	other	contract	personnel (including	geologists,	geophysicists,	engineers	and	other	specialists)	necessary	to	explore	for,	develop,	produce,	market	and	transport	crude	oil	and	natural	gas.	In addition,	certain	of	our	competitors	have	financial	and	other	resources	substantially	greater	than	those	we	possess	and	have	established	strategic	long-term	positions	or strong	governmental	relationships	in	countries	or	areas	in	which	we	may	seek	new	or	expanded	entry.	As	a	consequence,	we	may	be	at	a	competitive	disadvantage	in certain	respects,	such	as	in	bidding	for	drilling	rights	or	in	accessing	necessary	services,	facilities,	equipment,	materials	and	personnel.	In	addition,	our	larger	competitors may	have	a	competitive	advantage	when	responding	to	factors	that	affect	demand	for	crude	oil	and	natural	gas,	such	as	changing	worldwide	prices	and	levels	of production	and	the	cost	and	availability	of	alternative	fuels.	We	also	face	competition,	to	a	lesser	extent,	from	competing	energy	sources,	such	as	alternative	energy sources.

Reserve	estimates	depend	on	many	 interpretations	and	assumptions	 that	may	 turn	out to	be inaccurate.	Any	significant inaccuracies in these interpretations	and assumptions	could	cause	the	reported	quantities	of	our	reserves	to	be	materially	misstated.

Estimating	quantities	of	crude	oil,	NGL	and	natural	gas	reserves	and	future	net	cash	flows	from	such	reserves	is	a	complex,	inexact	process.	It	requires interpretations	of	available	technical	data	and	various	assumptions,	including	assumptions	relating	to	economic	factors,	made	by	our	management	and	our	independent petroleum	consultants.	Any	significant	inaccuracies	in	these	interpretations	or	assumptions	could	cause	the	reported	quantities	of	our	reserves	and	future	net	cash	flows from	such	reserves	to	be	overstated	or	understated.	Also,	the	data	for	a	given	reservoir	may	also	change	substantially	over	time	as	a	result	of	numerous	factors	including, but	not	limited	to,	additional	development	activity,	evolving	production	history,	continual	reassessment	of	the	viability	of	production	under	varying	economic	conditions and	improvements	and	other	changes	in	geological,	geophysical	and	engineering	evaluation	methods.

To	prepare	estimates	of	our	economically	recoverable	crude	oil,	NGL	and	natural	gas	reserves	and	future	net	cash	flows	from	our	reserves,	we	analyze	many variable	 factors,	 such	 as	 historical	 production	 from	 the	 area	 compared	 with	 production	 rates	 from	 other	 producing	 areas.	We	 also	 analyze	 available	 geological, geophysical,	production	and	engineering	data,	and	the	extent,	quality	and	reliability	of	this	data	can	vary.	The	process	also	involves	economic	assumptions	relating	to commodity	prices,	production	costs,	gathering,	processing,	compression,	storage	and	transportation	costs,	severance,	ad	valorem	and	other	applicable	taxes,	capital expenditures	and	workover	and	remedial	costs,	many	of	which	factors	are	or	may	be	beyond	our	control.	Our	actual	reserves	and	future	net	cash	flows	from	such reserves	most	likely	will	vary	from	our	estimates.	Any	significant	variance,	including	any	significant	revisions	or	"write-downs"	to	our	existing	reserve	estimates,	could materially	and	adversely	affect	our	business,	financial	condition	and	results	of	operations	and,	in	turn,	the	trading	price	of	our	common	stock.	For	related	discussion,	see ITEM	2,	Properties	-	Oil	and	Gas	Exploration	and	Production	-	Properties	and	Reserves	and	Supplemental	Information	to	Consolidated	Financial	Statements.

# Weather	and	climate	may	have	a	significant	and	adverse	impact	on	us.

Demand	for	crude	oil	and	natural	gas	is,	to	a	degree,	dependent	on	weather	and	climate,	which	impacts,	among	other	things,	the	price	we	receive	for	the commodities	we	produce	and,	in	turn,	our	cash	flows	and	results	of	operations.	For	example,	relatively	warm	temperatures	during	a	winter	season	generally	result	in relatively	lower	demand	for	natural	gas	(as	less	natural	gas	is	used	to	heat	residences	and	businesses)	and,	as	a	result,	lower	prices	for	natural	gas	production.

In	 addition,	 there	 has	 been	 public	 discussion	 that	 climate	 change	 may	 be	 associated	 with	 more	 frequent	 or	 more	 extreme	 weather	 events,	 changes	 in temperature	and	precipitation	patterns,	changes	to	ground	and	surface	water	availability,	and	other	related	phenomena,	which	could	affect	some,	or	all,	of	our	operations. Our	exploration,	exploitation	and	development	activities	and	equipment	could	be	adversely	affected	by	extreme	weather	events,	such	as	winter	storms,	flooding	and tropical	storms	and	hurricanes	in	the	Gulf	of	Mexico,	which	may	cause	a	loss	of	production	from	temporary	cessation	of	activity	or	damaged	facilities	and	equipment. Such	 extreme	 weather	 events	 could	 also	 impact	 other	 areas	 of	 our	 operations,	 including	 access	 to	 our	 drilling	 and	 production	 facilities	 for	 routine	 operations, maintenance	and	repairs,	the	installation	and	operation	of	gathering,	processing,	compression,	storage	and	transportation	facilities	and	the	availability	of,	and	our	access to,	necessary	third-party	services,	such	as	gathering,	processing,	compression,	storage	and	transportation	services.	Such	extreme	weather	events	and	changes	in	weather patterns	may	materially	and	adversely	affect	our	business	and,	in	turn,	our	financial	condition	and	results	of	operations.

Our	hedging	activities	may	prevent	us	from	benefiting	fully	from	increases	in	crude	oil	and	natural	gas	prices	and	may	expose	us	to	other	risks,	including	counterparty risk.

We	use	derivative	instruments	(primarily	financial	basis	swap,	price	swap,	option,	swaption	and	collar	contracts)	to	hedge	the	impact	of	fluctuations	in	crude	oil and	natural	gas	prices	on	our	results	of	operations	and	cash	flows.	To	the	extent	that	we	engage	in	hedging	activities	to	protect	ourselves	against	commodity	price declines,	we	may	be	prevented	from	fully	realizing	the	benefits	of	increases	in	crude	oil	and	natural	gas	prices	above	the	prices	established	by	our	hedging	contracts.	At February	19,	2019,	our	forecasted	crude	oil	production	(excluding	basis	swap	contracts)	for	2019	and	our	forecasted	natural	gas	production	for	2019	were	not	hedged. As	a	result,	our	forecasted	production	for	2019	is	subject	to	fluctuating	market	prices.	If	we	do	not	hedge	additional	production	volumes	for	2019	and	beyond,	we	will	be impacted	by	commodity	price	declines,	which	may	result	in	lower	net	cash	provided	by	operating	activities.	In	addition,	our	hedging	activities	may	expose	us	to	the	risk of	financial	loss	in	certain	circumstances,	including	instances	in	which	the	counterparties	to	our	hedging	contracts	fail	to	perform	under	the	contracts.

Federal	legislation	and	related	regulations	regarding	derivatives	transactions	could	have	a	material	and	adverse	impact	on	our	hedging	activities.

As	discussed	in	the	risk	factor	immediately	above,	we	use	derivative	instruments	to	hedge	the	impact	of	fluctuations	in	crude	oil	and	natural	gas	prices	on	our results	of	operations	and	cash	flows.	In	2010,	Congress	adopted	the	Dodd-Frank	Wall	Street	Reform	and	Consumer	Protection	Act	(Dodd-Frank	Act),	which,	among other	matters,	provides	for	federal	oversight	of	the	over-the-counter	derivatives	market	and	entities	that	participate	in	that	market	and	mandates	that	the	Commodity Futures	Trading	Commission	(CFTC),	the	U.S.	Securities	and	Exchange	Commission	(SEC)	and	certain	federal	agencies	that	regulate	the	banking	and	insurance	sectors (the	Prudential	Regulators)	adopt	rules	or	regulations	implementing	the	Dodd-Frank	Act	and	providing	definitions	of	terms	used	in	the	Dodd-Frank	Act.	The	Dodd-Frank Act	establishes	margin	requirements	and	requires	clearing	and	trade	execution	practices	for	certain	categories	of	swaps	and	may	result	in	certain	market	participants needing	to	curtail	their	derivatives	activities.	Although	some	of	the	rules	necessary	to	implement	the	Dodd-Frank	Act	are	yet	to	be	adopted,	the	CFTC,	the	SEC	and	the Prudential	Regulators	have	issued	numerous	rules,	including	a	rule	establishing	an	"end-user"	exception	to	mandatory	clearing	(End-User	Exception),	a	rule	regarding margin	for	uncleared	swaps	(Margin	Rule)	and	a	proposed	rule	imposing	position	limits	(Position	Limits	Rule).

We	qualify	as	a	"non-financial	entity"	for	purposes	of	the	End-User	Exception	and,	as	such,	we	are	eligible	for,	and	expect	to	utilize,	such	exception.	As	a	result, our	hedging	activities	will	not	be	subject	to	mandatory	clearing	or	the	margin	requirements	imposed	in	connection	with	mandatory	clearing.	We	also	qualify	as	a	"non- financial	end	user"	for	purposes	of	the	Margin	Rule;	therefore,	our	uncleared	swaps	are	not	subject	to	regulatory	margin	requirements.	Finally,	we	believe	our	hedging activities	would	constitute	bona	fide	hedging	under	the	Position	Limits	Rule	and	would	not	be	subject	to	limitation	under	such	rule	if	it	is	enacted.	However,	many	of our	hedge	counterparties	and	many	other	market	participants	may	not	be	eligible	for	the	End-User	Exception,	may	be	subject	to	mandatory	clearing	or	the	Margin	Rule for	swaps	with	some	or	all	of	their	other	swap	counterparties,	and/or	may	be	subject	to	the	Position	Limits	Rule.	In	addition,	the	European	Union	and	other	non-U.S. jurisdictions	have	enacted	laws	and	regulations	related	to	derivatives	(collectively,	Foreign	Regulations)	which	may	apply	to	our	transactions	with	counterparties	subject to	such	Foreign	Regulations.

The	Dodd-Frank	Act,	the	rules	adopted	thereunder	and	the	Foreign	Regulations	could	increase	the	cost	of	derivative	contracts,	alter	the	terms	of	derivative contracts,	reduce	the	availability	of	derivatives	to	protect	against	the	price	risks	we	encounter,	reduce	our	ability	to	monetize	or	restructure	our	existing	derivative contracts,	and	increase	our	exposure	to	less	creditworthy	counterparties.	If	our	use	of	derivatives	is	reduced	as	a	result	of	the	Dodd-Frank	Act,	related	regulations	or	the Foreign	Regulations,	our	results	of	operations	may	become	more	volatile,	and	our	cash	flows	may	be	less	predictable,	which	could	adversely	affect	our	ability	to	plan for,	and	fund,	our	capital	expenditure	requirements.	Any	of	these	consequences	could	have	a	material	and	adverse	effect	on	our	business,	financial	condition	and	results of	operations.

Our	business	and	prospects	for	future	success	depend	to	a	significant	extent	upon	the	continued	service	and	performance	of	our	management	team.

Our	business	and	prospects	for	future	success,	including	the	successful	implementation	of	our	strategies	and	handling	of	issues	integral	to	our	future	success, depend	to	a	significant	extent	upon	the	continued	service	and	performance	of	our	management	team.	The	loss	of	any	member	of	our	management	team,	and	our	inability to	attract,	motivate	and	retain	substitute	management	personnel	with	comparable	experience	and	skills,	could	materially	and	adversely	affect	our	business,	financial condition	and	results	of	operations.

We	operate	in	other	countries	and,	as	a	result,	are	subject	to	certain	political,	economic	and	other	risks.

Our	operations	in	jurisdictions	outside	the	U.S.	are	subject	to	various	risks	inherent	in	foreign	operations.	These	risks	include,	among	other	risks:

•increases	in	taxes	and	governmental

royalties;

•changes	in	laws	and	policies	governing	operations	of	foreign-based

companies;

•loss	of	revenue,	loss	of	or	damage	to	equipment,	property	and	other	assets	and	interruption	of	operations	as	a	result	of	expropriation,	nationalization,	acts of	terrorism,	war,	civil	unrest	and	other	political	risks;

•unilateral	or	forced	renegotiation,	modification	or	nullification	of	existing	contracts	with	governmental

entities;

•difficulties	enforcing	our	rights	against	a	governmental	agency	because	of	the	doctrine	of	sovereign	immunity	and	foreign	sovereignty	over	international operations;	and

•currency restrictions or exchange rate fluctuations.

Our	international	operations	may	also	be	adversely	affected	by	U.S.	laws	and	policies	affecting	foreign	trade	and	taxation,	including	tariffs	or	trade	or	other economic	sanctions	and	modifications	to,	or	withdrawal	from,	international	trade	treaties.	The	realization	of	any	of	these	factors	could	materially	and	adversely	affect our	business,	financial	condition	and	results	of	operations.

# Unfavorable	currency	exchange	rate	fluctuations	could	adversely	affect	our	results	of	operations.

The	reporting	currency	for	our	financial	statements	is	the	U.S.	dollar.	However,	certain	of	our	subsidiaries	are	located	in	countries	other	than	the	U.S.	and	have functional	currencies	other	than	the	U.S.	dollar.	The	assets,	liabilities,	revenues	and	expenses	of	certain	of	these	foreign	subsidiaries	are	denominated	in	currencies	other than	 the	 U.S.	 dollar.	To	prepare	our	consolidated	financial	statements,	we	must	translate	those	assets,	liabilities,	revenues	and	expenses	into	U.S.	dollars	at	then- applicable	exchange	rates.	Consequently,	increases	and	decreases	in	the	value	of	the	U.S.	dollar	versus	other	currencies	will	affect	the	amount	of	these	items	in	our consolidated	financial	statements,	even	if	the	amount	has	not	changed	in	the	original	currency.	These	translations	could	result	in	changes	to	our	results	of	operations from	period	to	period.	For	the	fiscal	year	ended	December	31,	2018,	less	than	1%	of	our	net	operating	revenues	related	to	operations	of	our	foreign	subsidiaries	whose functional	currency	was	not	the	U.S.	dollar.

# Our	business	could	be	adversely	affected	by	security	threats,	including	cybersecurity	threats.

We	face	various	security	threats,	including	cybersecurity	threats	to	gain	unauthorized	access	to	our	sensitive	information	or	to	render	our	information	or systems	unusable,	and	threats	to	the	security	of	our	facilities	and	infrastructure	or	third-party	facilities	and	infrastructure,	such	as	gathering	and	processing	facilities, refineries,	rail	facilities	and	pipelines.	The	potential	for	such	security	threats	subjects	our	operations	to	increased	risks	that	could	have	a	material	adverse	effect	on	our business,	financial	condition	and	results	of	operations.	For	example,	unauthorized	access	to	our	seismic	data,	reserves	information	or	other	proprietary	information	could lead	to	data	corruption,	communication	interruptions,	or	other	disruptions	to	our	operations.

Our	implementation	of	various	procedures	and	controls	to	monitor	and	mitigate	such	security	threats	and	to	increase	security	for	our	information,	systems, facilities	and	infrastructure	may	result	in	increased	capital	and	operating	costs.	Moreover,	there	can	be	no	assurance	that	such	procedures	and	controls	will	be	sufficient to	prevent	security	breaches	from	occurring.	If	any	of	these	security	breaches	were	to	occur,	they	could	lead	to	losses	of,	or	damage	to,	sensitive	information	or	facilities, infrastructure	and	systems	essential	to	our	business	and	operations,	as	well	as	data	corruption,	reputational	damage,communication	interruptions	or	other	disruptions	to our	operations,	which,	in	turn,	could	have	a	material	adverse	effect	on	our	business,	financial	position	and	results	of	operations.

# Terrorist	activities	and	military	and	other	actions	could	materially	and	adversely	affect	us.

Terrorist	attacks	and	the	threat	of	terrorist	attacks,	whether	domestic	or	foreign,	as	well	as	military	or	other	actions	taken	in	response	to	these	acts,	could	cause instability	in	the	global	financial	and	energy	markets.	The	U.S.	government	has	at	times	issued	public	warnings	that	indicate	that	energy	assets	might	be	specific	targets of	terrorist	organizations.	Any	such	actions	and	the	threat	of	such	actions	could	materially	and	adversely	affect	us	in	unpredictable	ways,	including	the	disruption	of energy	supplies	and	markets,	increased	volatility	in	crude	oil	and	natural	gas	prices	or	the	possibility	that	the	infrastructure	on	which	we	rely	could	be	a	direct	target	or an	indirect	casualty	of	an	act	of	terrorism,	and,	in	turn,	could	materially	and	adversely	affect	our	business,	financial	condition	and	results	of	operations.

# ITEM	1B.		Unresolved	Staff	Comments

Not	applicable.

# ITEM	2.		Properties

# Oil	and	Gas	Exploration	and	Production	-	Properties	and	Reserves

Reserve	Information.		For	estimates	and	discussions	of	EOG's	net	proved	reserves	of	crude	oil	and	condensate,	natural	gas	liquids	(NGLs)	and	natural	gas,	the qualifications	of	the	preparers	of	EOG's	reserve	estimates,	EOG's	independent	petroleum	consultants	and	EOG's	processes	and	controls	with	respect	to	its	reserve estimates,	see	"Supplemental	Information	to	Consolidated	Financial	Statements."

There	are	numerous	uncertainties	inherent	in	estimating	quantities	of	proved	reserves	and	in	projecting	future	rates	of	production	and	timing	of	development expenditures,	including	many	factors	beyond	the	control	of	the	producer.	The	reserve	data	set	forth	in	"Supplemental	Information	to	Consolidated	Financial	Statements" represent	only	estimates.	Reserve	engineering	is	a	complex	subjective	process	of	estimating	underground	accumulations	of	crude	oil	and	condensate,	NGLs	and	natural gas	that	cannot	be	measured	in	an	exact	manner.		The	accuracy	of	any	reserve	estimate	is	a	function	of	the	amount	and	quality	of	available	data	and	of	engineering	and geological	interpretation	and	judgment.		As	a	result,	estimates	by	different	engineers	normally	vary.		In	addition,	results	of	drilling,	testing	and	production	or	fluctuations in	commodity	prices	subsequent	to	the	date	of	an	estimate	may	justify	revision	of	such	estimate	(upward	or	downward).		Accordingly,	reserve	estimates	are	often different	from	the	quantities	ultimately	recovered.		Further,	the	meaningfulness	of	such	estimates	is	highly	dependent	upon	the	accuracy	of	the	assumptions	upon	which they	were	based.		For	related	discussion,	see	ITEM	1A,	Risk	Factors,	and	"Supplemental	Information	to	Consolidated	Financial	Statements."

In	general,	the	rate	of	production	from	crude	oil	and	natural	gas	properties	declines	as	reserves	are	produced.		Except	to	the	extent	EOG	acquires	additional properties	containing	proved	reserves,	conducts	successful	exploration,	exploitation	and	development	activities	or,	through	engineering	studies,	identifies	additional behind-pipe	zones	or	secondary	recovery	reserves,	the	proved	reserves	of	EOG	will	decline	as	reserves	are	produced.		The	volumes	to	be	generated	from	future	activities of	EOG	are	therefore	highly	dependent	upon	the	level	of	success	in	finding	or	acquiring	additional	reserves.		For	related	discussion,	see	ITEM	1A,	Risk	Factors.	EOG's estimates	of	reserves	filed	with	other	federal	agencies	are	consistent	with	the	information	set	forth	in	"Supplemental	Information	to	Consolidated	Financial	Statements."

Acreage.	The	following	table	summarizes	EOG's	gross	and	net	developed	and	undeveloped	acreage	at	December	31,	2018.	Excluded	is	acreage	in	which EOG's	interest	is	limited	to	owned	royalty,	overriding	royalty	and	other	similar	interests.

|  | Developed<br>Gross | Net | Undeveloped<br>Gross | Net | Total<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 2,618,624 | 1,884,489 | 3,280,867 | 2,409,792 | 5,899,491 | 4,294,281 |
| Trinidad | 79,277 | 67,474 | 201,435 | 115,274 | 280,712 | 182,748 |
| China | 130,548 | 130,548 | — | — | 130,548 | 130,548 |
| Canada | 40,000 | 35,771 | 105,560 | 98,436 | 145,560 | 134,207 |
| Total | 2,868,449 | 2,118,282 | 3,587,862 | 2,623,502 | 6,456,311 | 4,741,784 |

Most	of	our	undeveloped	oil	and	gas	leases,	particularly	in	the	United	States,	are	subject	to	lease	expiration	if	initial	wells	are	not	drilled	within	a	specified period,	generally	between	three	and	five	years.	Approximately	0.3	million	net	acres	will	expire	in	2019,	0.5	million	net	acres	will	expire	in	2020	and	0.3	million	net acres	will	expire	in	2021	if	production	is	not	established	or	we	take	no	other	action	to	extend	the	terms	of	the	leases	or	obtain	concessions.	In	the	ordinary	course	of business,	based	on	our	evaluations	of	certain	geologic	trends	and	prospective	economics,	we	have	allowed	certain	lease	acreage	to	expire	and	may	allow	additional acreage	to	expire	in	the	future.	As	of	December	31,	2018,	there	were	no	proved	undeveloped	reserves	associated	with	such	undeveloped	acreage.

Productive	Well	Summary.	The	following	table	represents	EOG's	gross	and	net	productive	wells,	including	2,107	wells	in	which	we	hold	a	royalty	interest.

|  | Crude	Oil<br>Gross | Net | Natural	Gas<br>Gross | Net | Total<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 9,023 | 6,422 | 6,360 | 3,658 | 15,383 | 10,080 |
| Trinidad | 2 | 2 | 33 | 27 | 35 | 29 |
| China | — | — | 36 | 36 | 36 | 36 |
| Canada | — | — | 24 | 23 | 24 | 23 |
| Total\t(1) | 9,025 | 6,424 | 6,453 | 3,744 | 15,478 | 10,168 |

(1) EOG	operated	11,366	gross	and	9,744	net	producing	crude	oil	and	natural	gas	wells	at	December	31,	2018.	Gross	crude	oil	and	natural	gas	wells	include	316	wells	with	multiple completions.

Drilling	and	Acquisition	Activities.		During	the	years	ended	December	31,	2018,	2017	 and	2016,	EOG	expended	$6.4	billion,	$4.4	billion	and	$6.4	billion, respectively,	for	exploratory	and	development	drilling,	facilities	and	acquisition	of	leases	and	producing	properties,	including	asset	retirement	obligations	of	$70	million, $56	million	and	$(20)	million,	respectively.		Included	in	the	2016	expenditures	was	$3.9	billion	of	acquisitions	of	producing	properties	and	leases	in	connection	with	the 2016	merger	and	related	asset	purchase	transactions	with	Yates	Petroleum	Corporation	and	other	affiliated	entities.	The	following	tables	set	forth	the	results	of	the	gross crude	oil	and	natural	gas	wells	completed	for	the	years	ended	December	31,	2018,	2017	and	2016:

|  |  | Gross	Development	Wells	Completed | Gross	Development	Wells	Completed |  |  | Gross	Exploratory	Wells	Completed | Gross	Exploratory	Wells	Completed |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Crude\tOil | Natural\tGas | Dry\tHole | Total | Crude\tOil | Natural\tGas | Dry\tHole | Total |
| 2018 |  |  |  |  |  |  |  |  |
| United\tStates | 834 | 39 | 22 | 895 | — | — | 1 | 1 |
| Trinidad | — | — | — | — | — | — | — | — |
| China | — | 1 | — | 1 | — | 2 | — | 2 |
| Total | 834 | 40 | 22 | 896 | — | 2 | 1 | 3 |
| 2017 |  |  |  |  |  |  |  |  |
| United\tStates | 568 | 22 | 13 | 603 | — | — | 1 | 1 |
| Trinidad | — | 8 | — | 8 | — | 1 | — | 1 |
| China | — | 3 | — | 3 | — | — | 1 | 1 |
| Total | 568 | 33 | 13 | 614 | — | 1 | 2 | 3 |
| 2016 |  |  |  |  |  |  |  |  |
| United\tStates | 524 | 39 | 6 | 569 | 1 | — | — | 1 |
| Trinidad | — | 1 | — | 1 | — | — | — | — |
| Total | 524 | 40 | 6 | 570 | 1 | — | — | 1 |

The	following	tables	set	forth	the	results	of	the	net	crude	oil	and	natural	gas	wells	completed	for	the	years	ended	December	31,	2018,	2017	and	2016:

|  |  | Net	Development	Wells	Completed | Net	Development	Wells	Completed |  |  | Net	Exploratory	Wells	Completed | Net	Exploratory	Wells	Completed |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Crude\tOil | Natural\tGas | Dry\tHole | Total | Crude\tOil | Natural\tGas | Dry\tHole | Total |
| 2018 |  |  |  |  |  |  |  |  |
| United\tStates | 704 | 37 | 18 | 759 | — | — | 1 | 1 |
| Trinidad | — | — | — | — | — | — | — | — |
| China | — | 1 | — | 1 | — | 2 | — | 2 |
| Total | 704 | 38 | 18 | 760 | — | 2 | 1 | 3 |
| 2017 |  |  |  |  |  |  |  |  |
| United\tStates | 490 | 21 | 13 | 524 | — | — | 1 | 1 |
| Trinidad | — | 6 | — | 6 | — | 1 | — | 1 |
| China | — | 3 | — | 3 | — | — | 1 | 1 |
| Total | 490 | 30 | 13 | 533 | — | 1 | 2 | 3 |
| 2016 |  |  |  |  |  |  |  |  |
| United\tStates | 420 | 17 | 6 | 443 | 1 | — | — | 1 |
| Trinidad | — | 1 | — | 1 | — | — | — | — |
| Total | 420 | 18 | 6 | 444 | 1 | — | — | 1 |

EOG	participated	in	the	drilling	of	wells	that	were	in	the	process	of	being	drilled	or	completed	at	the	end	of	the	period	as	set	out	in	the	table	below	for	the	years ended	December	31,	2018,	2017	and	2016:

|  | 2018<br>Gross | Net | 2017<br>Gross | Net | 2016<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 297 | 238 | 247 | 208 | 237 | 194 |
| Trinidad | — | — | — | — | 1 | 1 |
| China | 4 | 4 | 1 | 1 | — | — |
| Total | 301 | 242 | 248 | 209 | 238 | 195 |

Included	in	the	previous	table	of	wells	in	progress	at	the	end	of	the	period	were	wells	which	had	been	drilled,	but	were	not	completed	(DUCs).	In	order	to effectively	manage	its	capital	expenditures	and	to	provide	flexibility	in	managing	its	drilling	rig	and	well	completion	schedules,	EOG,	from	time	to	time,	will	have	an inventory	of	DUCs.	At	December	31,	2018,	there	were	approximately	78	MMBoe	of	net	proved	undeveloped	reserves	(PUDs)	associated	with	EOG's	inventory	of DUCs.	Under	EOG's	current	drilling	plan,	all	such	DUCs	are	expected	to	be	completed	within	five	years	from	the	original	booking	date	of	such	reserves.	The	following table	sets	forth	EOG's	DUCs,	for	which	PUDs	had	been	booked,	as	of	the	end	of	each	period.

|  |  |  | Drilled	Uncompleted	Wells	at	End	of	Period | Drilled	Uncompleted	Wells	at	End	of	Period |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2018\nGross | Net | 2017\nGross | Net | 2016\nGross | Net |
| United\tStates | 168 | 137 | 147 | 121 | 173 | 137 |
| China | 3 | 3 | 1 | 1 | — | — |
| Total | 171 | 140 | 148 | 122 | 173 | 137 |

EOG	acquired	wells	as	set	forth	in	the	following	tables	as	of	the	end	of	each	period	(excluding	the	acquisition	of	additional	interests	in	114,	29	and	63	net	wells in	which	EOG	previously	owned	an	interest	for	the	years	ended	December	31,	2018,	2017	and	2016,	respectively):

|  | Crude<br>Oil | Gross	Acquired	Wells<br>Natural	Gas | Total | Crude<br>Oil | Net	Acquired	Wells<br>Natural	Gas | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |  |  |
| United\tStates | 15 | 13 | 28 | 10 | 6 | 16 |
| Total | 15 | 13 | 28 | 10 | 6 | 16 |
| 2017 |  |  |  |  |  |  |
| United\tStates | 12 | 3 | 15 | 6 | 2 | 8 |
| Total | 12 | 3 | 15 | 6 | 2 | 8 |
| 2016 |  |  |  |  |  |  |
| United\tStates | 4,112 | 4,144 | 8,256 | 1,228 | 2,297 | 3,525 |
| Total | 4,112 | 4,144 | 8,256 | 1,228 | 2,297 | 3,525 |

All	of	EOG's	drilling	and	completion	activities	are	conducted	on	a	contractual	basis	with	 independent	drilling	contractors	and	other	 third-party	service contractors.		EOG's	other	property,	plant	and	equipment	primarily	includes	gathering,	transportation	and	processing	infrastructure	assets,	buildings,	crude-by-rail	assets, and	sand	mine	and	sand	processing	assets	which	support	EOG's	exploration	and	production	activities.	EOG	does	not	own	drilling	rigs,	hydraulic	fracturing	equipment	or rail	cars.

# ITEM	3.		Legal	Proceedings

See	 the information	set	forth	under the	"Contingencies"	caption in	Note	8	of the	Notes to	Consolidated	Financial	Statements,	which is incorporated	by reference	herein.

# ITEM	4.		Mine	Safety	Disclosures

The	information	concerning	mine	safety	violations	and	other	regulatory	matters	required	by	Section	1503(a)	of	the	Dodd-Frank	Wall	Street	Reform	and Consumer	Protection	Act	and	Item	104	of	Regulation	S-K	(17	CFR	229.104)	is	included	in	Exhibit	95	to	this	report.

# PART	II

# ITEM	5.	Market	for	Registrant's	Common	Equity,	Related	Stockholder	Matters	and	Issuer	Purchases	of	Equity		Securities

EOG's	common	stock	is	traded	on	the	New	York	Stock	Exchange	(NYSE)	under	the	ticker	symbol	"EOG."

As	of	February	14,	2019,	there	were	approximately	2,100	record	holders	and	approximately	454,000	beneficial	owners	of	EOG's	common	stock.

The	following	table	sets	forth,	for	the	periods	indicated,	EOG's	share	repurchase	activity:

(1) The	39,242	total	shares	for	the	quarter	ended	December	31,	2018,	and	the	538,892	total	shares	for	the	full	year	2018,	consist	solely	of	shares	that	were	withheld	by	or	returned	to EOG	(i)	in	satisfaction	of	tax	withholding	obligations	that	arose	upon	the	exercise	of	employee	stock	options	or	stock-settled	stock	appreciation	rights	or	the	vesting	of	restricted stock,	restricted	stock	unit	or	performance	unit	grants	or	(ii)	in	payment	of	the	exercise	price	of	employee	stock	options.		These	shares	do	not	count	against	the	10	million aggregate	share	repurchase	authorization	of	EOG's	Board	discussed	below.

(2) In	September	2001,	the	Board	authorized	the	repurchase	of	up	to	10,000,000	shares	of	EOG's	common	stock.		During	2018,	EOG	did	not	repurchase	any	shares	under	the	Board- authorized	repurchase	program.

# Comparative	Stock	Performance

The	following	performance	graph	and	related	information	shall	not	be	deemed	"soliciting	material"	or	to	be	"filed"	with	the	United	States	Securities	and Exchange	Commission,	nor	shall	such	information	be	incorporated	by	reference	into	any	future	filing	under	the	Securities	Act	of	1933,	as	amended,	or	Securities Exchange	Act	of	1934,	as	amended,	except	 to	 the	extent that	EOG	specifically	requests that	such information	be treated	as	 "soliciting	 material"	 or	 specifically incorporates	such	information	by	reference	into	such	a	filing.

The	performance	graph	shown	below	compares	the	cumulative	five-year	total	return	to	stockholders	on	EOG's	common	stock	as	compared	to	the	cumulative five-year	total	returns	on	the	Standard	and	Poor's	500	Index	(S&P	500)	and	the	Standard	and	Poor's	500	Oil	&	Gas	Exploration	&	Production	Index	(S&P	O&G	E&P). The	comparison	was	prepared	based	upon	the	following	assumptions:

2. Dividends	are	reinvested.

# Comparison	of	Five-Year	Cumulative	Total	Returns

(Performance	Results	Through	December	31,	2018)

# stockgrapha08.jpg

|  | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| EOG | $100.00 | $110.30 | $85.45 | $123.08 | $132.28 | $107.59 |
| S&amp;P\t500 | $100.00 | $113.69 | $115.27 | $129.06 | $157.23 | $150.34 |
| S&amp;P\tO&amp;G\tE&amp;P | $100.00 | $89.41 | $58.88 | $78.21 | $73.28 | $58.99 |

# ITEM	6.		Selected	Financial	Data

(In	Thousands,	Except	Per	Share	Data)

The	following	selected	consolidated	financial	information	should	be	read	in	conjunction	with	ITEM	7,	Management's	Discussion	and	Analysis	of	Financial Condition	and	Results	of	Operations	and	ITEM	8,	Financial	Statements	and	Supplementary	Data.

(1) Effective	January	1,	2018,	EOG	adopted	the	provisions	of	Accounting	Standards	Update	(ASU)	2014-09,	"Revenue	From	Contracts	With	Customers"	(ASU	2014-09).	In connection	with	the	adoption	of	ASU	2014-09,	EOG	presents	natural	gas	processing	fees	relating	to	certain	processing	and	marketing	agreements	within	its	United	States segment	as	Gathering	and	Processing	Costs	instead	of	as	a	deduction	to	Natural	Gas	Revenues.	There	was	no	impact	to	operating	income,	net	income	or	cash	flows	resulting	from changes	to	the	presentation	of	natural	gas	processing	fees.	EOG	elected	to	adopt	ASU	2014-09	using	the	modified	retrospective	approach	with	no	reclassification	of	amounts	for the	years	ended	December	31,	2017,	2016,	2015	and	2014	(see	Note	1	to	Consolidated	Financial	Statements).

(2) Effective	January	1,	2017,	EOG	adopted	the	provisions	of	ASU	2015-17,	"Income	Taxes	(Topic	740):	Balance	Sheet	Classification	of	Deferred	Taxes"	(ASU	2015-17),	which simplifies	the	presentation	of	deferred	taxes	in	a	classified	balance	sheet	by	eliminating	the	requirement	to	separate	deferred	income	tax	liabilities	and	assets	into	current	and noncurrent	 amounts.	Instead,	ASU	2015-17	requires	that	all	deferred	tax	liabilities	and	assets	be	shown	as	noncurrent	in	a	classified	balance	sheet.	In	connection	with	the adoption	of	ASU	2015-17,	EOG	restated	its	Consolidated	Balance	Sheets	at	December	31,	2016	and	2015	by	$160	million	and	$136	million,	respectively,	from	deferred	tax liabilities	to	deferred	tax	assets.

(3) Effective	January	1,	2016,	EOG	adopted	the	provisions	of	ASU	2015-03,	"Interest	-	Computation	of	Interest	(Subtopic	835-30):	Simplifying	the	Presentation	of	Debt	Issuance Costs"	(ASU	2015-03).	ASU	2015-03	requires	that	debt	issuance	costs	be	presented	in	the	balance	sheet	as	a	direct	reduction	from	the	related	debt	liability	rather	than	as	an	asset. In	connection	with	the	adoption	of	ASU	2015-03,	EOG	restated	its	Consolidated	Balance	Sheets	at	December	31,	2015	and	2014	by	$4.8	million	and	$4.1	million,	respectively, of	unamortized	debt	issuance	costs	from	Other	Assets	to	Long-Term	Debt.

# ITEM	7.		Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations

# Overview

EOG	Resources,	Inc.,	together	with	its	subsidiaries	(collectively,	EOG),	is	one	of	the	largest	independent	(non-integrated)	crude	oil	and	natural	gas	companies in	the	United	States	with	proved	reserves	in	the	United	States,	Trinidad	and	China.		EOG	operates	under	a	consistent	business	and	operational	strategy	that	focuses predominantly	on	maximizing	the	rate	of	return	on	investment	of	capital	by	controlling	operating	and	capital	costs	and	maximizing	reserve	recoveries.		Each	prospective drilling	location	is	evaluated	by	its	estimated	rate	of	return.	This	strategy	is	intended	to	enhance	the	generation	of	cash	flow	and	earnings	from	each	unit	of	production	on a	cost-effective	basis,	allowing	EOG	to	deliver	long-term	production	growth	while	maintaining	a	strong	balance	sheet.		EOG	implements	its	strategy	primarily	by emphasizing	the	drilling	of	internally	generated	prospects	in	order	to	find	and	develop	low-cost	reserves.		Maintaining	the	lowest	possible	operating	cost	structure	that	is consistent	with	efficient,	safe	and	environmentally	responsible	operations	is	also	an	important	goal	in	the	implementation	of	EOG's	strategy.

EOG	realized	net	income	of	$3,419	million	during	2018	as	compared	to	net	income	of	$2,583	million	for	2017.	At	December	31,	2018,	EOG's	total	estimated net	proved	reserves	were	2,928	million	barrels	of	oil	equivalent	(MMBoe),	an	increase	of	401	MMBoe	from	December	31,	2017.		During	2018,	net	proved	crude	oil	and condensate	and	natural	gas	liquids	(NGLs)	reserves	increased	by	330	million	barrels	(MMBbl),	and	net	proved	natural	gas	reserves	increased	by	424	billion	cubic	feet	or 71	MMBoe,	in	each	case	from	December	31,	2017.

# Operations

Several	important	developments	have	occurred	since	January	1,	2018.

United	States.	EOG's	efforts	to	identify	plays	with	large	reserve	potential	have	proven	to	be	successful.	EOG	continues	to	drill	numerous	wells	in	large	acreage plays,	which	in	the	aggregate	have	contributed	substantially	to,	and	are	expected	to	continue	to	contribute	substantially	to,	EOG's	crude	oil	and	liquids-rich	natural	gas production.	EOG	has	placed	an	emphasis	on	applying	its	horizontal	drilling	and	completion	expertise	to	unconventional	crude	oil	and	liquids-rich	reservoirs.

During	2018,	EOG	continued	to	focus	on	increasing	drilling,	completion	and	operating	efficiencies	gained	in	prior	years.	In	addition,	EOG	continued	to evaluate	certain	potential	crude	oil	and	liquids-rich	natural	gas	exploration	and	development	prospects	and	to	look	for	opportunities	to	add	drilling	inventory	through leasehold	acquisitions,	farm-ins,	exchanges	or	tactical	acquisitions.	On	a	volumetric	basis,	as	calculated	using	a	ratio	of	1.0	barrel	of	crude	oil	and	condensate	or	NGLs to	6.0	thousand	cubic	feet	of	natural	gas,	crude	oil	and	condensate	and	NGL	production	accounted	for	approximately	77%	of	United	States	production	during	2018	and 2017.	During	 2018,	 drilling	 and	 completion	 activities	 occurred	 primarily	 in	 the	 Eagle	 Ford	 play,	 Delaware	 Basin	 play	 and	 Rocky	 Mountain	 area.	EOG's	 major producing	areas	in	the	United	States	are	in	New	Mexico,	North	Dakota,	Texas,	Utah	and	Wyoming.

Trinidad.	In	Trinidad,	EOG	continued	to	deliver	natural	gas	under	existing	supply	contracts.	Several	fields	in	the	South	East	Coast	Consortium	(SECC)	Block, Modified	U(a)	Block,	Block	4(a),	Modified	U(b)	Block,	the	Banyan	Field	and	the	Sercan	Area	have	been	developed	and	are	producing	natural	gas	which	is	sold	to	the National	Gas	Company	of	Trinidad	and	Tobago	Limited	and	its	subsidiary	and	crude	oil	and	condensate	which	is	sold	to	the	Petroleum	Company	of	Trinidad	and Tobago	Limited	and	its	successor,	Heritage	Petroleum	Company	Limited.	In	2018,	EOG	conducted	an	ocean	bottom	nodal	seismic	survey	in	the	SECC	Block	and	the Pelican	Field	and	continued	to	process	and	review	the	initial	data.

Other International.	In	the	Sichuan	Basin,	Sichuan	Province,	China,	EOG	entered	2018	with	two	drilled	uncompleted	wells	and	completed	both	wells.	In addition,	EOG	drilled	five	natural	gas	wells	and	completed	one	of	those	wells	in	2018	as	part	of	the	continuing	development	of	the	Bajiaochang	Field,	which	natural	gas is	sold	under	a	long-term	contract	to	PetroChina.

In	the	U.K.,	EOG	produced	crude	oil	from	its	100%	working	interest	East	Irish	Sea	Conwy	development	project.	EOG	completed	the	sale	of	all	of	its	interest	in EOG	Resources	United	Kingdom	Limited	during	the	fourth	quarter	of	2018.	EOG	no	longer	has	any	presence	in	the	U.K.

# Capital	Structure

One	of	management's	key	strategies	is	to	maintain	a	strong	balance	sheet	with	a	consistently	below	average	debt-to-total	capitalization	ratio	as	compared	to those	in	EOG's	peer	group.		EOG's	debt-to-total	capitalization	ratio	was	24%	at	December	31,	2018	and	28%	at	December	31,	2017.		As	used	in	this	calculation,	total capitalization	represents	the	sum	of	total	current	and	long-term	debt	and	total	stockholders'	equity.

On	October	1,	2018,	EOG	repaid	upon	maturity	the	$350	million	aggregate	principal	amount	of	its	6.875%	Senior	Notes	due	2018.

During	2018,	EOG	funded	$6.6	billion	($411	million	of	which	was	non-cash)	 in	exploration	and	development	and	other	property,	plant	and	equipment expenditures	(excluding	asset	retirement	obligations),	repaid	$350	million	aggregate	principal	amount	of	long-term	debt,	paid	$438	million	in	dividends	to	common stockholders	and	purchased	$63	million	of	treasury	stock	in	connection	with	stock	compensation	plans,	primarily	by	utilizing	net	cash	provided	from	its	operating activities	and	net	proceeds	of	$227	million	from	the	sale	of	assets.

Total	anticipated	2019	capital	expenditures	are	estimated	 to	range	from	approximately	$6.1	billion	 to	$6.5	billion,	excluding	acquisitions	and	non-cash exchanges.	The	majority	of	2019	expenditures	will	be	focused	on	United	States	crude	oil	drilling	activities.	EOG	has	significant	flexibility	with	respect	to	financing alternatives,	including	borrowings	under	its	commercial	paper	program	and	other	uncommitted	credit	facilities,	bank	borrowings,	borrowings	under	its	$2.0	billion senior	unsecured	revolving	credit	facility,	joint	development	agreements	and	similar	agreements	and	equity	and	debt	offerings.

Management	continues	to	believe	EOG	has	one	of	the	strongest	prospect	inventories	in	EOG's	history.	When	it	fits	EOG's	strategy,	EOG	will	make	acquisitions that	bolster	existing	drilling	programs	or	offer	incremental	exploration	and/or	production	opportunities.

# Results	of	Operations

The	following	review	of	operations	for	each	of	the	three	years	in	the	period	ended	December	31,	2018,	should	be	read	in	conjunction	with	the	consolidated financial	statements	of	EOG	and	notes	thereto	beginning	on	page	F-1.

# Operating	Revenues	and	Other

During	2018,	operating	revenues	increased	$6,067	million,	or	54%,	to	$17,275	million	from	$11,208	million	in	2017.	Total	wellhead	revenues,	which	are revenues	generated	from	sales	of	EOG's	production	of	crude	oil	and	condensate,	NGLs	and	natural	gas,	increased	$4,039	million,	or	51%,	to	$11,946	million	in	2018 from	$7,907	million	in	2017.	Revenues	from	the	sales	of	crude	oil	and	condensate	and	NGLs	in	2018	were	approximately	89%	of	total	wellhead	revenues	compared	to 88%	in	2017.	During	2018,	EOG	recognized	net	losses	on	the	mark-to-market	of	financial	commodity	derivative	contracts	of	$166	million	compared	to	net	gains	of	$20 million	in	2017.	Gathering,	processing	and	marketing	revenues	increased	$1,932	million	during	2018,	to	$5,230	million	from	$3,298	million	in	2017.	Net	gains	on	asset dispositions	of	$175	million	in	2018	were	primarily	as	a	result	of	exchanges	of	producing	properties	and	acreage	in	Texas	and	sales	of	producing	properties	and	acreage in	the	United	Kingdom,	Texas	and	the	Rocky	Mountain	area	compared	to	net	losses	on	asset	dispositions	of	$99	million	in	2017.

Wellhead	volume	and	price	statistics	for	the	years	ended	December	31,	2018,	2017	and	2016	were	as	follows:

| Year	Ended	December	31 | 2018 |  | 2017 | 2016 |
| :--- | :--- | :--- | :--- | :--- |
| Crude\tOil\tand\tCondensate\tVolumes\t(MBbld)\t(1) |  |  |  |  |
| United\tStates | 394.8 |  | 335.0 | 278.3 |
| Trinidad | 0.8 |  | 0.9 | 0.8 |
| Other\tInternational\t(2) | 4.3 |  | 0.8 | 3.4 |
| Total | 399.9 |  | 336.7 | 282.5 |
| Average\tCrude\tOil\tand\tCondensate\tPrices\t($/Bbl)\t(3) |  |  |  |  |
| United\tStates | $65.16 |  | $50.91 | $41.84 |
| Trinidad | 57.26 |  | 42.30 | 33.76 |
| Other\tInternational\t(2) | 71.45 |  | 57.20 | 36.72 |
| Composite | 65.21 |  | 50.91 | 41.76 |
| Natural\tGas\tLiquids\tVolumes\t(MBbld)\t(1) |  |  |  |  |
| United\tStates | 116.1 |  | 88.4 | 81.6 |
| Other\tInternational\t(2) | — |  | — | — |
| Total | 116.1 |  | 88.4 | 81.6 |
| Average\tNatural\tGas\tLiquids\tPrices\t($/Bbl)\t(3) |  |  |  |  |
| United\tStates | $26.60 |  | $22.61 | $14.63 |
| Other\tInternational\t(2) | — |  | — | — |
| Composite | 26.60 |  | 22.61 | 14.63 |
| Natural\tGas\tVolumes\t(MMcfd)\t(1) |  |  |  |  |
| United\tStates | 923 |  | 765 | 810 |
| Trinidad | 266 |  | 313 | 340 |
| Other\tInternational\t(2) | 30 |  | 25 | 25 |
| Total | 1,219 |  | 1,103 | 1,175 |
| Average\tNatural\tGas\tPrices\t($/Mcf)\t(3) |  |  |  |  |
| United\tStates | $2.88 |  | $2.20 | $1.60 |
| Trinidad | 2.94 |  | 2.38 | 1.88 |
| Other\tInternational\t(2) | 4.08 |  | 3.89 | 3.64 |
| Composite | 2.92 | (4) | 2.29 | 1.73 |
| Crude\tOil\tEquivalent\tVolumes\t(MBoed)\t(5) |  |  |  |  |
| United\tStates | 664.7 |  | 551.0 | 494.9 |
| Trinidad | 45.1 |  | 53.0 | 57.5 |
| Other\tInternational\t(2) | 9.4 |  | 4.9 | 7.6 |
| Total | 719.2 |  | 608.9 | 560.0 |
| Total\tMMBoe\t(5) | 262.5 |  | 222.3 | 205.0 |

(5) Thousand	barrels	of	oil	equivalent	per	day	or	million	barrels	of	oil	equivalent,	as	applicable;	includes	crude	oil	and	condensate,	NGLs	and	natural	gas.		Crude	oil	equivalent volumes	are	determined	using	a	ratio	of	1.0	barrel	of	crude	oil	and	condensate	or	NGLs	to	6.0	thousand	cubic	feet	of	natural	gas.		MMBoe	is	calculated	by	multiplying	the MBoed	amount	by	the	number	of	days	in	the	period	and	then	dividing	that	amount	by	one	thousand.

2018	compared	to	2017.	Wellhead	crude	oil	and	condensate	revenues	in	2018	increased	$3,261	million,	or	52%,	to	$9,517	million	from	$6,256	million	in	2017, due	primarily	to	a	higher	composite	average	wellhead	crude	oil	and	condensate	price	($2,088	million)	and	an	increase	in	production	($1,173	million).	EOG's	composite wellhead	crude	oil	and	condensate	price	for	2018	increased	28%	to	$65.21	per	barrel	compared	to	$50.91	per	barrel	in	2017.	Wellhead	crude	oil	and	condensate production	in	2018	increased	19%	to	400	MBbld	as	compared	to	337	MBbld	in	2017.	The	increased	production	was	primarily	in	the	Permian	Basin	and	the	Eagle	Ford.

NGL	revenues	in	2018	increased	$398	million,	or	55%,	to	$1,127	million	from	$729	million	in	2017	primarily	due	to	an	increase	in	production	($229	million) and	a	higher	composite	average	wellhead	NGL	price	($169	million).	EOG's	composite	average	wellhead	NGL	price	increased	18%	to	$26.60	per	barrel	in	2018 compared	to	$22.61	per	barrel	in	2017.	NGL	production	in	2018	increased	31%	to	116	MBbld	as	compared	to	88	MBbld	in	2017.	The	increased	production	was primarily	in	the	Permian	Basin	and	the	Eagle	Ford.

Wellhead	natural	gas	revenues	in	2018	increased	$380	million,	or	41%,	to	$1,302	million	from	$922	million	in	2017,	primarily	due	to	a	higher	composite wellhead	natural	gas	price	($282	million)	and	an	increase	in	wellhead	natural	gas	deliveries	($98	million).	EOG's	composite	average	wellhead	natural	gas	price	increased 28%	to	$2.92	per	Mcf	in	2018	compared	to	$2.29	per	Mcf	in	2017.	This	increase	in	composite	wellhead	natural	gas	prices	includes	a	positive	revenue	adjustment	of $0.44	per	Mcf	related	to	the	adoption	of	ASU	2014-09.	Natural	gas	deliveries	in	2018	increased	11%	to	1,219	MMcfd	as	compared	to	1,103	MMcfd	in	2017.	The increase	in	production	was	primarily	due	to	increased	production	in	the	United	States	(158	MMcfd),	partially	offset	by	decreased	production	in	Trinidad	(47	MMcfd). The	increased	production	in	the	United	States	was	due	primarily	to	increased	production	of	associated	gas	in	the	Permian	Basin	and	Rocky	Mountain	area	and	higher volumes	in	the	Marcellus	Shale.	The	decrease	in	Trinidad	was	primarily	attributable	to	higher	contractual	deliveries	in	2017.

During	2018,	EOG	recognized	net	losses	on	the	mark-to-market	of	financial	commodity	derivative	contracts	of	$166	million,	which	included	net	cash	paid	for settlements	of	crude	oil	and	natural	gas	financial	derivative	contracts	of	$259	million.	During	2017,	EOG	recognized	net	gains	on	the	mark-to-market	of	financial commodity	derivative	contracts	of	$20	million,	which	included	net	cash	received	from	settlements	of	crude	oil	and	natural	gas	financial	derivative	contracts	of	$7 million.

Gathering,	processing	and	marketing	revenues	are	revenues	generated	from	sales	of	third-party	crude	oil,	NGLs	and	natural	gas,	as	well	as	gathering	fees associated	with	gathering	third-party	natural	gas	and	revenues	from	sales	of	EOG-owned	sand.	Purchases	and	sales	of	third-party	crude	oil	and	natural	gas	may	be utilized	in	order	to	balance	firm	transportation	capacity	with	production	in	certain	areas	and	to	utilize	excess	capacity	at	EOG-owned	facilities.	EOG	sells	sand	in	order to	balance	the	timing	of	firm	purchase	agreements	with	completion	operations	and	to	utilize	excess	capacity	at	EOG-owned	facilities.	Marketing	costs	represent	the	costs to	purchase	third-party	crude	oil,	natural	gas	and	sand	and	the	associated	transportation	costs,	as	well	as	costs	associated	with	EOG-owned	sand	sold	to	third	parties.

Gathering,	processing	and	marketing	revenues	less	marketing	costs	in	2018	increased	$59	million	compared	to	2017,	primarily	due	to	higher	margins	on	crude oil	and	condensate	marketing	activities.

2017	compared	to	2016.	Wellhead	crude	oil	and	condensate	revenues	in	2017	increased	$1,939	million,	or	45%,	to	$6,256	million	from	$4,317	million	in	2016, due	primarily	to	a	higher	composite	average	wellhead	crude	oil	and	condensate	price	($1,124	million)	and	an	increase	in	production	($815	million).	EOG's	composite wellhead	crude	oil	and	condensate	price	for	2017	increased	22%	to	$50.91	per	barrel	compared	to	$41.76	per	barrel	in	2016.	Wellhead	crude	oil	and	condensate deliveries	in	2017	increased	19%	to	337	MBbld	as	compared	to	283	MBbld	in	2016.	The	increased	production	was	primarily	due	to	higher	production	in	the	Permian Basin	and	Rocky	Mountain	area.

NGL	revenues	in	2017	increased	$292	million,	or	67%,	to	$729	million	from	$437	million	in	2016	primarily	due	to	a	higher	composite	wellhead	NGL	price ($257	million)	and	an	increase	in	production	($35	million).	EOG's	composite	average	wellhead	NGL	price	increased	55%	to	$22.61	per	barrel	in	2017	compared	to $14.63	per	barrel	in	2016.	The	increased	production	was	primarily	due	to	higher	production	in	the	Permian	Basin	and	Rocky	Mountain	area,	partially	offset	by	decreased production	in	the	Fort	Worth	Barnett	Shale,	largely	resulting	from	2016	asset	sales	in	this	region.

Wellhead	natural	gas	revenues	in	2017	increased	$180	million,	or	24%,	to	$922	million	from	$742	million	in	2016,	primarily	due	to	a	higher	composite wellhead	natural	gas	price	($227	million),	partially	offset	by	a	decrease	in	wellhead	natural	gas	deliveries	($47	million).	EOG's	composite	average	wellhead	natural	gas price	increased	32%	to	$2.29	per	Mcf	in	2017	compared	to	$1.73	per	Mcf	in	2016.	Natural	gas	deliveries	in	2017	decreased	6%	to	1,103	MMcfd	as	compared	to	1,175 MMcfd	in	2016.	The	decrease	in	production	was	primarily	due	to	decreased	production	in	the	United	States	(45	MMcfd)	and	Trinidad	(27	MMcfd).	The	decreased production	in	the	United	States	was	due	primarily	to	lower	volumes	in	the	Fort	Worth	Barnett	Shale,	Upper	Gulf	Coast	and	South	Texas	areas,	largely	resulting	from 2016	asset	sales	in	these	regions,	partially	offset	by	increased	production	of	associated	gas	in	the	Permian	Basin	and	Rocky	Mountain	area	and	from	the	2016	mergers and	related	asset	purchase	transactions	with	Yates	Petroleum	Corporation	and	other	affiliated	entities	(collectively,	the	Yates	Entities).	 The	decrease	in	Trinidad	was primarily	attributable	to	higher	contractual	deliveries	in	2016.

During	2017,	EOG	recognized	net	gains	on	the	mark-to-market	of	financial	commodity	derivative	contracts	of	$20	million,	which	included	net	cash	received from	settlements	of	crude	oil	and	natural	gas	financial	derivative	contracts	of	$7	million.	During	2016,	EOG	recognized	net	losses	on	the	mark-to-market	of	financial commodity	derivative	contracts	of	$100	million,	which	included	net	cash	paid	for	settlements	of	crude	oil	and	natural	gas	financial	derivative	contracts	of	$22	million.

Gathering,	processing	and	marketing	revenues	less	marketing	costs	in	2017	increased	$9	million	compared	to	2016,	primarily	due	to	higher	margins	on	natural gas	and	NGL	marketing	activities	($16	million),	partially	offset	by	lower	margins	on	sand	sales	($9	million).

# Operating	and	Other	Expenses

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Lease\tand\tWell | $4.89 | $4.70 |
| Transportation\tCosts | 2.85 | 3.33 |
| Depreciation,\tDepletion\tand\tAmortization\t(DD&amp;A)\t- |  |  |
| Oil\tand\tGas\tProperties | 12.65 | 14.83 |
| Other\tProperty,\tPlant\tand\tEquipment | 0.44 | 0.51 |
| General\tand\tAdministrative\t(G&amp;A) | 1.63 | 1.95 |
| Net\tInterest\tExpense | 0.93 | 1.23 |
| Total\t(1) | $23.39 | $26.55 |

(1) Total	excludes	gathering	and	processing	costs,	exploration	costs,	dry	hole	costs,	impairments,	marketing	costs	and	taxes	other	than	income.

The	primary	factors	impacting	the	cost	components	of	per-unit	rates	of	lease	and	well,	transportation	costs,	DD&A,	G&A	and	net	interest	expense	for	2018 compared	to	2017	are	set	forth	below.		See	"Operating	Revenues	and	Other"	above	for	a	discussion	of	production	volumes.

Lease	and	well	expenses	include	expenses	for	EOG-operated	properties,	as	well	as	expenses	billed	to	EOG	from	other	operators	where	EOG	is	not	the	operator of	a	property.		Lease	and	well	expenses	can	be	divided	into	the	following	categories:	costs	to	operate	and	maintain	crude	oil	and	natural	gas	wells,	the	cost	of	workovers and	lease	and	well	administrative	expenses.		Operating	and	maintenance	costs	include,	among	other	things,	pumping	services,	salt	water	disposal,	equipment	repair	and maintenance,	compression	expense,	lease	upkeep	and	fuel	and	power.		Workovers	are	operations	to	restore	or	maintain	production	from	existing	wells.

Each	of	these	categories	of	costs	individually	fluctuates	from	time	to	time	as	EOG	attempts	to	maintain	and	increase	production	while	maintaining	efficient, safe	and	environmentally	responsible	operations.		EOG	continues	to	increase	its	operating	activities	by	drilling	new	wells	in	existing	and	new	areas.		Operating	and maintenance	costs	within	these	existing	and	new	areas,	as	well	as	the	costs	of	services	charged	to	EOG	by	vendors,	fluctuate	over	time.

Lease	and	well	expenses	of	$1,283	million	in	2018	increased	$238	million	from	$1,045	million	in	2017	primarily	due	to	higher	operating	and	maintenance	costs ($171	million),	higher	workover	expenditures	($44	million)	and	higher	lease	and	well	administrative	expenses	($41	million),	all	in	the	United	States,	partially	offset	by lower	operating	and	maintenance	costs	in	the	United	Kingdom	($18	million).	Lease	and	well	expenses	increased	in	the	United	States	primarily	due	to	increased	operating activities	resulting	in	increased	production.

Transportation	costs	represent	costs	associated	with	the	delivery	of	hydrocarbon	products	from	the	lease	to	a	downstream	point	of	sale.		Transportation	costs include	transportation	fees,	the	cost	of	compression	(the	cost	of	compressing	natural	gas	to	meet	pipeline	pressure	requirements),	dehydration	(the	cost	associated	with removing	water	from	natural	gas	to	meet	pipeline	requirements),	gathering	fees	and	fuel	costs.

Transportation	costs	of	$747	million	in	2018	increased	$7	million	from	$740	million	in	2017	primarily	due	to	increased	transportation	costs	in	the	Permian Basin	($116	million),	partially	offset	by	decreased	transportation	costs	in	the	Barnett	Shale	($52	million),	the	Eagle	Ford	($31	million)	and	the	Rocky	Mountain	area ($25	million).

DD&A	of	the	cost	of	proved	oil	and	gas	properties	is	calculated	using	the	unit-of-production	method.		EOG's	DD&A	rate	and	expense	are	the	composite	of numerous	individual	DD&A	group	calculations.		There	are	several	factors	that	can	impact	EOG's	composite	DD&A	rate	and	expense,	such	as	field	production	profiles, drilling	or	acquisition	of	new	wells,	disposition	of	existing	wells	and	reserve	revisions	(upward	or	downward)	primarily	related	to	well	performance,	economic	factors and	impairments.		Changes	to	these	factors	may	cause	EOG's	composite	DD&A	rate	and	expense	to	fluctuate	from	period	to	period.		DD&A	of	the	cost	of	other property,	plant	and	equipment	is	generally	calculated	using	the	straight-line	depreciation	method	over	the	useful	lives	of	the	assets.

DD&A	expenses	in	2018	increased	$26	million	to	$3,435	million	from	$3,409	million	in	2017.		DD&A	expenses	associated	with	oil	and	gas	properties	in	2018 were	$24	million	higher	than	in	2017	primarily	due	to	an	increase	in	production	in	the	United	States	($647	million)	and	the	United	Kingdom	($21	million),	partially offset	by	lower	unit	rates	in	the	United	States	($625	million)	and	a	decrease	in	production	in	Trinidad	($16	million).	Unit	rates	in	the	United	States	decreased	primarily due	to	upward	reserve	revisions	and	reserves	added	at	lower	costs	as	a	result	of	increased	efficiencies.

G&A	expenses	of	$427	million	in	2018	decreased	$7	million	from	$434	million	in	2017	primarily	due	to	decreased	professional,	legal	and	other	services	($24 million);	partially	offset	by	 increased	employee-related	expenses	resulting	from	expanded	operations	($15	million)	and	 increased	 information	systems	costs	($10 million).

Net	interest	expense	of	$245	million	in	2018	was	$29	million	lower	than	2017	primarily	due	to	repayment	of	the	$600	million	aggregate	principal	amount	of 5.875%	Senior	Notes	due	2017	in	September	2017	($25	million)	and	the	$350	million	aggregate	principal	amount	of	6.875%	Senior	Notes	due	2018	in	October	2018	($6 million),	partially	offset	by	a	decrease	in	capitalized	interest	($3	million).

Gathering	and	processing	costs	represent	operating	and	maintenance	expenses	and	administrative	expenses	associated	with	operating	EOG's	gathering	and processing	assets	and	beginning	January	1,	2018,	natural	gas	processing	fees	from	third	parties.	EOG	pays	third	parties	to	process	a	portion	of	its	natural	gas	production to	extract	NGLs.	See	Note	1	to	the	Consolidated	Financial	Statements	for	discussion	related	to	EOG's	adoption	of	ASU	2014-09.

Gathering	and	processing	costs	increased	$288	million	to	$437	million	in	2018	compared	to	$149	million	in	2017	primarily	due	to	the	adoption	of	ASU	2014- 09	($204	million)	and	increased	operating	costs	in	the	Permian	Basin	($32	million),	the	United	Kingdom	($28	million)	and	the	Eagle	Ford	($25	million).

Exploration	costs	of	$149	million	in	2018	increased	$4	million	from	$145	million	in	2017	primarily	due	to	increased	general	and	administrative	expenses	in	the United	States	($7	million),	partially	offset	by	decreased	geological	and	geophysical	expenditures	in	Trinidad	($5	million).

Impairments	include	amortization	of	unproved	oil	and	gas	property	costs	as	well	as	impairments	of	proved	oil	and	gas	properties;	other	property,	plant	and equipment;	and	other	assets.		Unproved	properties	with	acquisition	costs	that	are	not	individually	significant	are	aggregated,	and	the	portion	of	such	costs	estimated	to	be nonproductive	is	amortized	over	the	remaining	lease	term.		Unproved	properties	with	individually	significant	acquisition	costs	are	reviewed	individually	for	impairment. When	 circumstances	 indicate	 that	 a	 proved	 property	 may	 be	 impaired,	 EOG	 compares	 expected	 undiscounted	 future	 cash	 flows	 at	 a	 DD&A	 group	 level	 to	 the unamortized	capitalized	cost	of	the	asset.		If	the	expected	undiscounted	future	cash	flows	are	lower	than	the	unamortized	capitalized	cost,	the	capitalized	cost	is	reduced to	fair	value.		Fair	value	is	generally	calculated	by	using	the	Income	Approach	described	in	the	Fair	Value	Measurement	Topic	of	the	Financial	Accounting	Standards Board's	Accounting	Standards	Codification	(ASC).		In	certain	instances,	EOG	utilizes	accepted	offers	from	third-party	purchasers	as	the	basis	for	determining	fair	value.

The	following	table	represents	impairments	for	the	years	ended	December	31,	2018	and	2017	(in	millions):

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Proved\tproperties | $121 | $224 |
| Unproved\tproperties | 173 | 211 |
| Other\tassets | 49 | 28 |
| Other\tproperty,\tplant\tand\tequipment | — | 16 |
| Inventories | 4 | — |
| Total | $347 | $479 |

Impairments	of	proved	properties	were	primarily	due	to	the	write-down	to	fair	value	of	legacy	natural	gas	assets	in	2018	and	2017.

Taxes	 other	 than	 income	 include	 severance/production	 taxes,	 ad	 valorem/property	 taxes,	 payroll	 taxes,	 franchise	 taxes	 and	 other	 miscellaneous	 taxes. Severance/production	taxes	are	generally	determined	based	on	wellhead	revenues,	and	ad	valorem/property	taxes	are	generally	determined	based	on	the	valuation	of	the underlying	assets.

Taxes	other	than	income	in	2018	increased	$227	million	to	$772	million	(6.5%	of	wellhead	revenues)	from	$545	million	(6.9%	of	wellhead	revenues)	in	2017. The	increase	in	taxes	other	than	income	was	primarily	due	to	increases	in	severance/production	taxes	($190	million)	primarily	as	a	result	of	increased	wellhead	revenues and	an	increase	in	ad	valorem/property	taxes	($33	million),	both	in	the	United	States.

Other	income,	net,	was	$17	million	in	2018	compared	to	other	income,	net,	of	$9	million	in	2017.	The	increase	of	$8	million	in	2018	was	primarily	due	to	a decrease	in	deferred	compensation	expense	($12	million)	and	an	increase	in	interest	income	($4	million);	partially	offset	by	an	increase	in	foreign	currency	transaction losses	($15	million).

EOG	recognized	an	income	tax	provision	of	$822	million	in	2018	compared	to	an	income	tax	benefit	of	$1,921	million	in	2017,	primarily	due	to	the	absence	of certain	2017	tax	benefits	related	to	the	Tax	Cuts	and	Jobs	Act	(TCJA)	and	higher	pretax	income.	The	most	significant	impact	of	the	TCJA	on	EOG	was	the	reduction	in the	statutory	income	tax	rate	from	35%	to	21%	which	required	the	existing	net	United	States	federal	deferred	income	tax	liability	to	be	remeasured	resulting	in	the recognition	of	an	income	tax	benefit	in	2017	of	approximately	$2.2	billion.	The	net	effective	tax	rate	for	2018	increased	to	19%	from	(291%)	in	the	prior	year,	primarily due	to	the	absence	of	the	TCJA	tax	benefits.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Lease\tand\tWell | $4.70 | $4.53 |
| Transportation\tCosts | 3.33 | 3.73 |
| Depreciation,\tDepletion\tand\tAmortization\t(DD&amp;A)\t- |  |  |
| Oil\tand\tGas\tProperties | 14.83 | 16.77 |
| Other\tProperty,\tPlant\tand\tEquipment | 0.51 | 0.57 |
| General\tand\tAdministrative\t(G&amp;A) | 1.95 | 1.93 |
| Net\tInterest\tExpense | 1.23 | 1.37 |
| Total\t(1) | $26.55 | $28.90 |

Lease	and	well	expenses	of	$1,045	million	in	2017	increased	$118	million	from	$927	million	in	2016	primarily	due	to	higher	operating	and	maintenance	costs in	the	United	States	($71	million)	and	the	United	Kingdom	($30	million)	and	higher	workover	expenditures	in	the	United	States	($21	million).	Lease	and	well	expenses increased	in	the	United	States	primarily	due	to	increased	operating	activities	resulting	in	increased	production.

Transportation	costs	of	$740	million	in	2017	decreased	$24	million	from	$764	million	in	2016	primarily	due	to	divestitures	in	the	Barnett	Shale	and	Upper	Gulf Coast	($85	million)	and	decreased	transportation	costs	in	the	Eagle	Ford	($8	million)	and	the	United	Kingdom	($8	million),	partially	offset	by	increased	transportation costs	related	to	higher	production	in	the	Permian	Basin	($47	million)	and	the	Rocky	Mountain	area	($20	million)	and	from	the	2016	transactions	with	the	Yates	Entities ($13	million).

DD&A	expenses	in	2017	decreased	$144	million	to	$3,409	million	from	$3,553	million	in	2016.		DD&A	expenses	associated	with	oil	and	gas	properties	in 2017	were	$141	million	lower	than	in	2016	primarily	due	to	lower	unit	rates	in	the	United	States	($449	million)	and	Trinidad	($19	million)	and	a	decrease	in	production in	the	United	Kingdom	($16	million)	and	Trinidad	($11	million),	partially	offset	by	an	increase	in	production	in	the	United	States	($354	million).	Unit	rates	in	the	United States	decreased	primarily	due	to	upward	reserve	revisions	and	reserves	added	at	lower	costs	as	a	result	of	increased	efficiencies.

G&A	expenses	of	$434	million	in	2017	increased	$39	million	from	$395	million	in	2016	primarily	due	to	increased	employee-related	expenses	resulting	from expanded	operations	and	from	the	2016	transactions	with	the	Yates	Entities	($45	million)	and	increased	professional,	legal	and	other	services	($30	million),	partially offset	by	2016	employee	related	expenses	in	connection	with	certain	voluntary	retirements	($42	million).

Net	interest	expense	of	$274	million	in	2017	was	$8	million	lower	than	2016	primarily	due	to	repayment	of	the	$600	million	aggregate	principal	amount	of 5.875%	Senior	Notes	due	2017	in	September	2017	($11	million),	partially	offset	by	a	decrease	in	capitalized	interest	($4	million).

Gathering	and	processing	costs	increased	$26	million	to	$149	million	in	2017	compared	to	$123	million	in	2016	due	to	increased	activities	in	the	Permian	Basin ($12	million)	and	the	Rocky	Mountain	area	($8	million).

Exploration	costs	of	$145	million	in	2017	increased	$20	million	from	$125	million	in	2016	primarily	due	to	increased	geological	and	geophysical	expenditures in	Trinidad.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Proved\tproperties | $224 | $116 |
| Unproved\tproperties | 211 | 291 |
| Other\tassets | 28 | — |
| Other\tproperty,\tplant\tand\tequipment | 16 | 14 |
| Inventories | — | 61 |
| Firm\tcommitment\tcontracts | — | 138 |
| Total | $479 | $620 |

Impairments	of	proved	properties	were	primarily	due	to	the	write-down	to	fair	value	of	divested	legacy	natural	gas	assets	in	2017	and	2016.	EOG	recognized additional	 impairment	 charges	 in	 2016	 of	 $61	 million	 related	 to	 obsolete	 inventory	 and	 $138	 million	 related	 to	 firm	 commitment	 contracts	 related	 to	 divested Haynesville	natural	gas	assets.

Taxes	other	than	income	in	2017	increased	$195	million	to	$545	million	(6.9%	of	wellhead	revenues)	from	$350	million	(6.4%	of	wellhead	revenues)	in	2016. The	increase	in	taxes	other	than	income	was	primarily	due	to	increases	in	severance/production	taxes	($171	million)	and	in	ad	valorem/property	taxes	($18	million),	both primarily	as	a	result	of	increased	wellhead	revenues	in	the	United	States.

Other	income,	net,	was	$9	million	in	2017	compared	to	other	expense,	net,	of	$51	million	in	2016.	The	increase	of	$60	million	was	primarily	due	to	an	increase in	foreign	currency	transaction	gains	in	2017	($49	million)	and	interest	income	($5	million).

EOG	recognized	an	income	tax	benefit	of	$1,921	million	in	2017	compared	to	an	income	tax	benefit	of	$461	million	in	2016,	primarily	due	to	the	enactment	of the	TCJA	in	December	2017.	The	most	significant	impact	of	the	TCJA	on	EOG	was	the	reduction	in	the	statutory	income	tax	rate	from	35%	to	21%,	which	required	the existing	net	United	States	federal	deferred	income	tax	liability	to	be	remeasured,	resulting	in	the	recognition	of	an	income	tax	benefit	of	approximately	$2.2	billion.		Due largely	to	this	tax	rate	reduction,	the	net	effective	tax	rate	for	2017	decreased	to	(291)%	from	30%	in	the	prior	year.

# Capital	Resources	and	Liquidity

# Cash	Flow

The	primary	sources	of	cash	for	EOG	during	the	three-year	period	ended	December	31,	2018,	were	funds	generated	from	operations	and	proceeds	from	asset sales.		The	primary	uses	of	cash	were	funds	used	in	operations;	exploration	and	development	expenditures;	other	property,	plant	and	equipment	expenditures;	dividend payments	to	stockholders;	repayments	of	debt;	and	purchases	of	treasury	stock	in	connection	with	stock	compensation	plans.

2018	compared	to	2017.		Net	cash	provided	by	operating	activities	of	$7,769	million	in	2018	increased	$3,504	million	from	$4,265	million	in	2017	primarily reflecting	an	increase	in	wellhead	revenues	($4,039	million),	favorable	changes	in	working	capital	and	other	assets	and	liabilities	($758	million)	and	a	favorable	change in	the	cash	paid	for	income	taxes	($113	million),	partially	offset	by	an	increase	in	cash	operating	expenses	($746	million)	and	an	unfavorable	change	in	the	net	cash	paid for	the	settlement	of	financial	commodity	derivative	contracts	($266	million).

Net	cash	used	in	investing	activities	of	$6,170	million	in	2018	increased	by	$2,183	million	from	$3,987	million	in	2017	primarily	due	to	an	increase	in additions	to	oil	and	gas	properties	($1,888	million);	unfavorable	changes	in	working	capital	associated	with	investing	activities	($211	million);	and	an	increase	in additions	to	other	property,	plant	and	equipment	($64	million).

Net	cash	used	in	financing	activities	of	$839	million	in	2018	included	cash	dividend	payments	($438	million),	repayments	of	long-term	debt	($350	million)	and purchases	of	treasury	stock	in	connection	with	stock	compensation	plans	($63	million).	Cash	provided	by	financing	activities	in	2018	included	proceeds	from	stock options	exercised	and	employee	stock	purchase	plan	activity	($21	million).

2017	compared	to	2016.		Net	cash	provided	by	operating	activities	of	$4,265	million	in	2017	increased	$1,906	million	from	$2,359	million	in	2016	primarily reflecting	an	increase	in	wellhead	revenues	($2,411	million)	and	a	favorable	change	in	the	net	cash	received	from	the	settlement	of	financial	commodity	derivative contracts	($30	million),	partially	offset	by	an	increase	in	cash	operating	expenses	($362	million),	an	increase	in	net	cash	paid	for	income	taxes	($228	million),	an increase	in	net	cash	paid	for	interest	expense	($23	million)	and	unfavorable	changes	in	working	capital	and	other	assets	and	liabilities	($10	million).

Net	cash	used	in	investing	activities	of	$3,987	million	in	2017	increased	by	$2,734	million	from	$1,253	million	in	2016	primarily	due	to	an	increase	in additions	to	oil	and	gas	properties	($1,461	million);	a	decrease	in	proceeds	from	asset	sales	($892	million);	unfavorable	changes	in	working	capital	associated	with investing	activities	($246	million);	and	an	increase	in	additions	to	other	property,	plant	and	equipment	($80	million).

Net	cash	used	in	financing	activities	of	$1,036	million	in	2017	included	repayments	of	long-term	debt	($600	million),	cash	dividend	payments	($387	million) and	purchases	of	treasury	stock	in	connection	with	stock	compensation	plans	($63	million).	Cash	provided	by	financing	activities	in	2017	included	proceeds	from	stock options	exercised	and	employee	stock	purchase	plan	activity	($21	million).

# Total	Expenditures

The	table	below	sets	out	components	of	total	expenditures	for	the	years	ended	December	31,	2018,	2017	and	2016	(in	millions):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Expenditure\tCategory |  |  |  |
| Capital |  |  |  |
| Exploration\tand\tDevelopment\tDrilling | $4,935 | $3,132 | $1,957 |
| Facilities | 625 | 575 | 375 |
| Leasehold\tAcquisitions\t(1) | 488 | 427 | 3,217 |
| Property\tAcquisitions\t(2) | 124 | 73 | 749 |
| Capitalized\tInterest | 24 | 27 | 31 |
| Subtotal | 6,196 | 4,234 | 6,329 |
| Exploration\tCosts | 149 | 145 | 125 |
| Dry\tHole\tCosts | 5 | 5 | 11 |
| Exploration\tand\tDevelopment\tExpenditures | 6,350 | 4,384 | 6,465 |
| Asset\tRetirement\tCosts | 70 | 56 | (20) |
| Total\tExploration\tand\tDevelopment\tExpenditures | 6,420 | 4,440 | 6,445 |
| Other\tProperty,\tPlant\tand\tEquipment\t(3) | 286 | 173 | 109 |
| Total\tExpenditures | $6,706 | $4,613 | $6,554 |

(1) Leasehold	acquisitions	included	$291	million	and	$256	million	related	to	non-cash	property	exchanges	in	2018	and	2017,	respectively,	and	$3,115	million	in	2016	related	to	the Yates	transaction.

(2) Property	acquisitions	included	$71	million	and	$26	million	related	to	non-cash	property	exchanges	in	2018	and	2017,	respectively,	and	$735	million	in	2016	related	to	the	Yates transaction.

(3) Other	property,	plant	and	equipment	included	$49	million	of	non-cash	additions	in	2018	primarily	related	to	a	capital	lease	transaction	in	the	Permian	Basin	and	$17	million	in 2016	related	to	the	Yates	transaction.

Exploration	and	development	expenditures	of	$6,350	million	for	2018	were	$1,966	million	higher	than	the	prior	year.	The	increase	was	primarily	due	to increased	exploration	and	development	drilling	expenditures	in	the	United	States	($1,932	million)	and	Other	International	($11	million),	increased	leasehold	acquisitions ($61	million),	increased	property	acquisitions	($51	million)	and	increased	facility	expenditures	($50	million),	partially	offset	by	decreased	exploration	and	development drilling	expenditures	in	Trinidad	($140	million).	The	2018	exploration	and	development	expenditures	of	$6,350	million	included	$5,546	million	in	development	drilling and	 facilities,	 $656	 million	 in	 exploration,	 $124	 million	 in	 property	 acquisitions	 and	 $24	 million	 in	 capitalized	 interest.	The	 2017	 exploration	 and	 development expenditures	of	$4,384	million	included	$3,661	million	in	development	drilling	and	facilities,	$623	million	in	exploration,	$73	million	in	property	acquisitions	and	$27 million	 in	 capitalized	 interest.	The	 2016	 exploration	 and	 development	 expenditures	 of	 $6,465	 million	 included	 $3,351	 million	 in	 exploration,	 $2,334	 million	 in development	drilling	and	facilities,	$749	million	in	property	acquisitions	and	$31	million	in	capitalized	interest.

The	level	of	exploration	and	development	expenditures,	including	acquisitions,	will	vary	in	future	periods	depending	on	energy	market	conditions	and	other related	economic	factors.		EOG	has	significant	flexibility	with	respect	to	financing	alternatives	and	the	ability	to	adjust	its	exploration	and	development	expenditure budget	as	circumstances	warrant.		While	EOG	has	certain	continuing	commitments	associated	with	expenditure	plans	related	to	its	operations,	such	commitments	are not	expected	to	be	material	when	considered	in	relation	to	the	total	financial	capacity	of	EOG.

# Derivative	Transactions

Commodity	Derivative	Contracts.		Prices	received	by	EOG	for	its	crude	oil	production	generally	vary	from	U.S.	New	York	Mercantile	Exchange	(NYMEX) West	Texas	Intermediate	prices	due	to	adjustments	for	delivery	location	(basis)	and	other	factors.	EOG	has	entered	into	crude	oil	basis	swap	contracts	in	order	to	fix	the differential	between	pricing	in	Midland,	Texas,	and	Cushing,	Oklahoma	(Midland	Differential).	Presented	below	is	a	comprehensive	summary	of	EOG's	Midland Differential	basis	swap	contracts	through	February	19,	2019.	The	weighted	average	price	differential	expressed	in	dollars	per	barrel	($/Bbl)	represents	the	amount	of reduction	to	Cushing,	Oklahoma,	prices	for	the	notional	volumes	expressed	in	barrels	per	day	(Bbld)	covered	by	the	basis	swap	contracts.

# Midland	Differential	Basis	Swap	Contracts

|  | Volume	(Bbld) | Weighted	Average<br>Price	Differential<br>($/Bbl) |
| :--- | :--- | :--- |
| \t2018\n\tJanuary\t1,\t2018\tthrough\tDecember\t31,\t2018\t(closed) | 15,000 | $1.063 |
| \t2019 |  |  |
| \tJanuary\t1,\t2019\tthrough\tFebruary\t28,\t2019\t(closed) | 20,000 | $1.075 |
| \tMarch\t1,\t2019\tthrough\tDecember\t31,\t2019 | 20,000 | 1.075 |

EOG	has	also	entered	into	crude	oil	basis	swap	contracts	in	order	to	fix	the	differential	between	pricing	in	the	U.S.	Gulf	Coast	and	Cushing,	Oklahoma	(Gulf Coast	 Differential).	Presented	below	is	a	comprehensive	summary	of	EOG's	Gulf	Coast	Differential	basis	swap	contracts	through	February	19,	2019.	The	weighted average	price	differential	expressed	in	$/Bbl	represents	the	amount	of	addition	to	Cushing,	Oklahoma,	prices	for	the	notional	volumes	expressed	in	Bbld	covered	by	the basis	swap	contracts.

# Gulf	Coast	Differential	Basis	Swap	Contracts

|  | Volume	(Bbld) | Weighted	Average<br>Price	Differential<br>($/Bbl) |
| :--- | :--- | :--- |
| \t2018 |  |  |
| \tJanuary\t1,\t2018\tthrough\tSeptember\t30,\t2018\t(closed) | 37,000 | $3.818 |
| \tOctober\t1,\t2018\tthrough\tDecember\t31,\t2018\t(closed) | 52,000 | 3.911 |
| \t2019 |  |  |
| \tJanuary\t1,\t2019\tthrough\tFebruary\t28,\t2019\t(closed) | 13,000 | $5.572 |
| \tMarch\t1,\t2019\tthrough\tDecember\t31,\t2019 | 13,000 | 5.572 |

Presented	below	is	a	comprehensive	summary	of	EOG's	crude	oil	price	swap	contracts	through	February	19,	2019,	with	notional	volumes	expressed	in	Bbld and	prices	expressed	in	$/Bbl.

# Crude	Oil	Price	Swap	Contracts

On	November	20,	2018,	EOG	entered	into	crude	oil	price	swap	contracts	for	the	period	December	1,	2018	through	December	31,	2018,	with	notional	volumes of	134,000	Bbld	at	an	average	price	of	$53.75	per	Bbl.	These	contracts	offset	the	crude	oil	price	swap	contracts	for	the	same	time	period	with	notional	volumes	of 134,000	Bbld	at	an	average	price	of	$60.04	per	Bbl.	The	net	cash	EOG	received	for	settling	these	contracts	was	$26.1	million.	The	offsetting	contracts	are	excluded	from the	above	table.

Presented	below	is	a	comprehensive	summary	of	EOG's	natural	gas	price	swap	contracts	through	February	19,	2019,	with	notional	volumes	expressed	in million	British	thermal	units	(MMBtu)	per	day	(MMBtud)	and	prices	expressed	in	dollars	per	MMBtu	($/MMBtu).

# Natural	Gas	Price	Swap	Contracts

EOG	has	sold	call	options	which	establish	a	ceiling	price	for	the	sale	of	notional	volumes	of	natural	gas	as	specified	in	the	call	option	contracts.	The	call options	require	that	EOG	pay	the	difference	between	the	call	option	strike	price	and	either	the	average	or	last	business	day	NYMEX	Henry	Hub	natural	gas	price	for	the contract	month	(Henry	Hub	Index	Price)	in	the	event	the	Henry	Hub	Index	Price	is	above	the	call	option	strike	price.

In	addition,	EOG	has	purchased	put	options	which	establish	a	floor	price	for	the	sale	of	notional	volumes	of	natural	gas	as	specified	in	the	put	option	contracts. The	put	options	grant	EOG	the	right	to	receive	the	difference	between	the	put	option	strike	price	and	the	Henry	Hub	Index	Price	in	the	event	the	Henry	Hub	Index	Price is	below	the	put	option	strike	price.	Presented	below	is	a	comprehensive	summary	of	EOG's	natural	gas	call	and	put	option	contracts	through	February	19,	2019,	with notional	volumes	expressed	in	MMBtud	and	prices	expressed	in	$/MMBtu.

|  | Natural	Gas	Option	Contracts<br>Call	Options	Sold<br>Volume<br>(MMBtud) | Weighted<br>Average	Price<br>($/MMBtu) | Put	Options	Purchased<br>Volume<br>(MMBtud) | Weighted<br>Average	Price<br>($/MMBtu) |
| :--- | :--- | :--- | :--- | :--- |
| 2018\nMarch\t1,\t2018\tthrough\tNovember\t30,\t2018\t(closed) | 120,000 | $3.38 | 96,000 | $2.94 |

# Financing

EOG's	 debt-to-total	 capitalization	 ratio	 was	 24%	 at	 December	 31,	 2018,	 compared to	 28%	 at	 December	 31,	 2017. 	As	 used in this	 calculation, total capitalization	represents	the	sum	of	total	current	and	long-term	debt	and	total	stockholders'	equity.

At	December	31,	2018	and	2017,	respectively,	EOG	had	outstanding	$6,040	million	and	$6,390	million	aggregate	principal	amount	of	senior	notes	which	had estimated	fair	values	of	$6,027	million	and	$6,602	million,	respectively.		The	estimated	fair	value	was	based	upon	quoted	market	prices	and,	where	such	prices	were	not available,	other	observable	inputs	regarding	interest	rates	available	to	EOG	at	year-end.		EOG's	debt	is	at	fixed	interest	rates.		While	changes	in	interest	rates	affect	the fair	value	of	EOG's	senior	notes,	such	changes	do	not	expose	EOG	to	material	fluctuations	in	earnings	or	cash	flow.

During	2018,	EOG	funded	its	capital	program	primarily	by	utilizing	cash	provided	by	operating	activities,	proceeds	from	asset	sales	and	cash	provided	by borrowings	from	its	commercial	paper	program.		While	EOG	maintains	a	$2.0	billion	commercial	paper	program,	the	maximum	outstanding	at	any	time	during	2018 was	$208	million,	and	the	amount	outstanding	at	year-end	was	zero.		There	were	no	amounts	outstanding	under	uncommitted	credit	facilities	during	2018.	The	average borrowings	outstanding	under	the	commercial	paper	program	were	$8	million	during	the	year	2018.		EOG	considers	this	excess	availability,	which	is	backed	by	its	$2.0 billion	senior	unsecured	revolving	credit	facility	described	in	Note	2	to	Consolidated	Financial	Statements,	to	be	sufficient	to	meet	its	ongoing	operating	needs.

# Contractual	Obligations

The	following	table	summarizes	EOG's	contractual	obligations	at	December	31,	2018,	(in	thousands):

| Contractual	Obligations	(1)	(2) | Total | 2019 | 2020-2021 | 2022-2023 | 2024	&amp;	Beyond |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Current\tand\tLong-Term\tDebt | $6,040,000 | $900,000 | $1,750,000 | $1,250,000 | $2,140,000 |
| Capital\tLease | 71,571 | 13,384 | 27,560 | 17,529 | 13,098 |
| Non-Cancelable\tOperating\tLeases | 555,692 | 175,787 | 218,995 | 90,608 | 70,302 |
| Interest\tPayments\ton\tLong-Term\tDebt\tand\tCapital\tLease | 1,276,530 | 213,776 | 308,379 | 227,185 | 527,190 |
| Transportation\tand\tStorage\tService\tCommitments\t(3) | 3,781,178 | 898,491 | 1,370,060 | 880,057 | 632,570 |
| Drilling\tRig\tCommitments\t(4) | 391,459 | 262,404 | 126,398 | 2,657 | — |
| Seismic\tPurchase\tObligations | 6,898 | 6,898 | — | — | — |
| Fracturing\tServices\tObligations | 1,048,517 | 421,873 | 460,088 | 164,041 | 2,515 |
| Other\tPurchase\tObligations | 1,024,301 | 385,525 | 237,771 | 175,250 | 225,755 |
| Total\tContractual\tObligations | $14,196,146 | $3,278,138 | $4,499,251 | $2,807,327 | $3,611,430 |

(1) This	table	does	not	include	the	liability	for	unrecognized	tax	benefits,	EOG's	pension	or	postretirement	benefit	obligations	or	liability	for	dismantlement,	abandonment	and	asset retirement	obligations	(see	Notes	6,	7	and	15,	respectively,	to	Consolidated	Financial	Statements).	These	amounts	are	excluded	because	they	are	subject	to	estimates	and	the timing	of	settlement	is	unknown.

(2) This	table	does	not	include	the	liability	for	commitments	to	purchase	fixed	quantities	of	crude	oil	and	natural	gas.	The	amounts	are	excluded	because	they	are	variable	and	based on	future	commodity	prices.	At	December	31,	2018,	EOG	is	committed	to	purchase	3.6	MMBbls	of	crude	oil	and	15	Bcf	of	natural	gas	in	2019.

(3) Amounts	shown	are	based	on	current	transportation	and	storage	rates	and	the	foreign	currency	exchange	rates	used	to	convert	Canadian	dollars	into	United	States	dollars	at December	31,	2018.		Management	does	not	believe	that	any	future	changes	in	these	rates	before	the	expiration	dates	of	these	commitments	will	have	a	material	adverse	effect	on the	financial	condition	or	results	of	operations	of	EOG.

(4) Amounts	shown	represent	minimum	future	expenditures	for	drilling	rig	services.		EOG's	expenditures	for	drilling	rig	services	will	exceed	such	minimum	amounts	to	the	extent EOG	utilizes	the	drilling	rigs	subject	to	a	particular	contractual	commitment	for	a	period	greater	than	the	period	set	forth	in	the	governing	contract	or	if	EOG	utilizes	drilling	rigs in	addition	to	the	drilling	rigs	subject	to	the	particular	contractual	commitment	(for	example,	pursuant	to	the	exercise	of	an	option	to	utilize	additional	drilling	rigs	provided	for	in the	governing	contract).

# Off-Balance	Sheet	Arrangements

EOG	 does	 not	 participate	 in	 financial	 transactions	 that	 generate	 relationships	 with	 unconsolidated	 entities	 or	 financial	 partnerships.	 	 Such	 entities	 or partnerships,	often	referred	to	as	variable	interest	entities	(VIE)	or	special	purpose	entities	(SPE),	are	generally	established	for	the	purpose	of	facilitating	off-balance sheet	 arrangements	 or	 other	 limited	 purposes.	 EOG	 was	 not	 involved	 in	 any	 unconsolidated	VIE	 or	 SPE	 financial	 transactions	 or	 any	 other	 "off-balance	 sheet arrangement"	(as	defined	in	Item	303(a)(4)(ii)	of	Regulation	S-K)	during	any	of	the	periods	covered	by	this	report	and	currently	has	no	intention	of	participating	in	any such	transaction	or	arrangement	in	the	foreseeable	future.

# Foreign	Currency	Exchange	Rate	Risk

During	2018,	EOG	was	exposed	to	foreign	currency	exchange	rate	risk	inherent	in	its	operations	in	foreign	countries,	including	Trinidad,	China	and	Canada and,	through	November	2018,	the	U.K.		The	foreign	currency	most	significant	to	EOG's	operations	during	2018	was	the	British	pound.		EOG	continues	to	monitor	the foreign	currency	exchange	rates	of	countries	in	which	it	is	currently	conducting	business	and	may	implement	measures	to	protect	against	foreign	currency	exchange	rate risk.

# Outlook

Pricing.		Crude	oil	and	natural	gas	prices	have	been	volatile,	and	this	volatility	is	expected	to	continue.		As	a	result	of	the	many	uncertainties	associated	with the	world	political	environment,	worldwide	supplies	of,	and	demand	for,	crude	oil	and	condensate,	NGL	and	natural	gas,	the	availabilities	of	other	worldwide	energy supplies	and	the	relative	competitive	relationships	of	the	various	energy	sources	in	the	view	of	consumers,	EOG	is	unable	to	predict	what	changes	may	occur	in	crude	oil and	condensate,	NGLs,	natural	gas,	ammonia	and	methanol	prices	in	the	future.		The	market	price	of	crude	oil	and	condensate,	NGLs	and	natural	gas	in	2019	will	impact the	amount	of	cash	generated	from	EOG's	operating	activities,	which	will	in	turn	impact	EOG's	financial	position.	As	of	February	19,	2019,	the	average	2019	NYMEX crude	oil	and	natural	gas	prices	were	$57.15	per	barrel	and	$2.89	per	MMBtu,	respectively,	representing	a	decrease	of	12%	for	crude	oil	and	a	decrease	of	6%	for	natural gas	from	the	average	NYMEX	prices	in	2018.	See	ITEM	1A,	Risk	Factors.

Based	on	EOG's	tax	position,	EOG's	price	sensitivity	(exclusive	of	basis	swaps)	in	2019	for	each	$1.00	per	barrel	increase	or	decrease	in	wellhead	crude	oil	and condensate	price,	combined	with	the	estimated	change	in	NGL	price,	is	approximately	$133	million	for	net	income	and	$173	million	for	pretax	cash	flows	from operating	activities.		Based	on	EOG's	tax	position	and	the	portion	of	EOG's	anticipated	natural	gas	volumes	for	2019	for	which	prices	have	not	been	determined	under long-term	marketing	contracts,	EOG's	price	sensitivity	for	each	$0.10	per	Mcf	increase	or	decrease	in	wellhead	natural	gas	price	is	approximately	$29	million	for	net income	and	$37	million	for	pretax	cash	flows	from	operating	activities.		For	information	regarding	EOG's	crude	oil	and	natural	gas	financial	commodity	derivative contracts	through	February	19,	2019,	see	"Derivative	Transactions"	above.

Capital.	EOG	plans	to	continue	to	focus	a	substantial	portion	of	its	exploration	and	development	expenditures	in	its	major	producing	areas	in	the	United	States. In	particular,	EOG	will	be	focused	on	United	States	crude	oil	drilling	activity	in	its	Eagle	Ford,	Delaware	Basin	and	Rocky	Mountain	area	where	it	generates	its	highest rates-of-return.	To	further	enhance	the	economics	of	these	plays,	EOG	expects	to	continue	to	improve	well	performance	and	lower	drilling	and	completion	costs	through efficiency	gains	and	lower	service	costs.

The	total	anticipated	2019	capital	expenditures	of	approximately	$6.1	billion	to	$6.5	billion,	excluding	acquisitions	and	non-cash	exchanges,	is	structured	to maintain	EOG's	strategy	of	capital	discipline	by	funding	its	exploration,	development	and	exploitation	activities	primarily	from	available	internally	generated	cash	flows and	 cash	 on	 hand.	EOG	 has	 significant	 flexibility	 with	 respect	 to	 financing	 alternatives,	 including	 borrowings	 under	 its	 commercial	 paper	 program	 and	 other uncommitted	credit	facilities,	bank	borrowings,	borrowings	under	its	$2.0	billion	senior	unsecured	revolving	credit	facility	and	equity	and	debt	offerings.

Operations.	In	2019,	both	total	production	and	total	crude	oil	production	are	expected	to	increase	from	2018	levels.	In	2019,	EOG	expects	to	continue	to	focus on	reducing	operating	costs	through	efficiency	improvements.

# Summary	of	Critical	Accounting	Policies

EOG	prepares	its	financial	statements	and	the	accompanying	notes	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States,	which require	management	to	make	estimates	and	assumptions	about	future	events	that	affect	the	reported	amounts	in	the	financial	statements	and	the	accompanying	notes. EOG	identifies	certain	accounting	policies	as	critical	based	on,	among	other	things,	their	impact	on	the	portrayal	of	EOG's	financial	condition,	results	of	operations	or liquidity,	and	the	degree	of	difficulty,	subjectivity	and	complexity	in	their	application.		Critical	accounting	policies	cover	accounting	matters	that	are	inherently	uncertain because	the	future	resolution	of	such	matters	is	unknown.		Management	routinely	discusses	the	development,	selection	and	disclosure	of	each	of	the	critical	accounting policies.		Following	is	a	discussion	of	EOG's	most	critical	accounting	policies:

# Proved	Oil	and	Gas	Reserves

EOG's	engineers	estimate	proved	oil	and	gas	reserves	in	accordance	with	United	States	Securities	and	Exchange	Commission	(SEC)	regulations,	which	directly impact	financial	accounting	estimates,	including	depreciation,	depletion	and	amortization	and	impairments	of	proved	properties	and	related	assets.		Proved	reserves represent	estimated	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas	that	geological	and	engineering	data	demonstrate,	with	reasonable	certainty,	to	be recoverable	in	future	years	from	known	reservoirs	under	economic	and	operating	conditions	existing	at	the	time	the	estimates	were	made.		The	process	of	estimating quantities	of	proved	oil	and	gas	reserves	is	complex,	requiring	significant	subjective	decisions	in	the	evaluation	of	available	geological,	engineering	and	economic	data for	each	reservoir.		The	data	for	a	given	reservoir	may	also	change	substantially	over	time	as	a	result	of	numerous	factors	including,	but	not	limited	to,	additional development	activity,	evolving	production	history	and	continual	reassessment	of	the	viability	of	production	under	varying	economic	conditions.		Consequently,	material revisions	(upward	or	downward)	to	existing	reserve	estimates	may	occur	from	time	to	time.		For	related	discussion,	see	ITEM	1A,	Risk	Factors,	and	"Supplemental Information	to	Consolidated	Financial	Statements."

# Oil	and	Gas	Exploration	Costs

EOG	accounts	for	its	crude	oil	and	natural	gas	exploration	and	production	activities	under	the	successful	efforts	method	of	accounting.		Oil	and	gas	exploration costs,	other	than	the	costs	of	drilling	exploratory	wells,	are	expensed	as	incurred.		The	costs	of	drilling	exploratory	wells	are	capitalized	pending	determination	of whether	EOG	has	discovered	proved	commercial	reserves.		If	proved	commercial	reserves	are	not	discovered,	such	drilling	costs	are	expensed.		In	some	circumstances, it	may	be	uncertain	whether	proved	commercial	reserves	have	been	discovered	when	drilling	has	been	completed.		Such	exploratory	well	drilling	costs	may	continue	to be	capitalized	if	the	reserve	quantity	is	sufficient	to	justify	its	completion	as	a	producing	well	and	sufficient	progress	in	assessing	the	reserves	and	the	economic	and operating	viability	of	the	project	is	being	made.		Costs	to	develop	proved	reserves,	including	the	costs	of	all	development	wells	and	related	equipment	used	in	the production	of	crude	oil	and	natural	gas,	are	capitalized.

# Depreciation,	Depletion	and	Amortization	for	Oil	and	Gas	Properties

The	quantities	of	estimated	proved	oil	and	gas	reserves	are	a	significant	component	of	EOG's	calculation	of	depreciation,	depletion	and	amortization	expense, and	revisions	in	such	estimates	may	alter	the	rate	of	future	expense.	Holding	all	other	factors	constant,	if	reserves	were	revised	upward	or	downward,	earnings	would increase	or	decrease,	respectively.

Depreciation,	depletion	and	amortization	of	the	cost	of	proved	oil	and	gas	properties	is	calculated	using	the	unit-of-production	method.		The	reserve	base	used to	calculate	depreciation,	depletion	and	amortization	for	leasehold	acquisition	costs	and	the	cost	to	acquire	proved	properties	is	the	sum	of	proved	developed	reserves	and proved	undeveloped	reserves.		With	respect	to	lease	and	well	equipment	costs,	which	include	development	costs	and	successful	exploration	drilling	costs,	the	reserve base	includes	only	proved	developed	reserves.		Estimated	future	dismantlement,	restoration	and	abandonment	costs,	net	of	salvage	values,	are	taken	into	account.

Oil	and	gas	properties	are	grouped	in	accordance	with	the	provisions	of	the	Extractive	Industries	-	Oil	and	Gas	Topic	of	the	ASC.		The	basis	for	grouping	is	a reasonable	aggregation	of	properties	with	a	common	geological	structural	feature	or	stratigraphic	condition,	such	as	a	reservoir	or	field.

Depreciation,	depletion	and	amortization	rates	are	updated	quarterly	to	reflect	the	addition	of	capital	costs,	reserve	revisions	(upwards	or	downwards)	and additions,	property	acquisitions	and/or	property	dispositions	and	impairments.

Depreciation	and	amortization	of	other	property,	plant	and	equipment	is	calculated	on	a	straight-line	basis	over	the	estimated	useful	life	of	the	asset.

# Impairments

Oil	 and	 gas	 lease	 acquisition	 costs	 are	 capitalized	 when	 incurred.	 	 Unproved	 properties	 with	 acquisition	 costs	 that	 are	 not	 individually	 significant	 are aggregated,	and	the	portion	of	such	costs	estimated	to	be	nonproductive	is	amortized	over	the	remaining	lease	term.		Unproved	properties	with	individually	significant acquisition	costs	are	reviewed	individually	for	impairment.	If	the	unproved	properties	are	determined	to	be	productive,	the	appropriate	related	costs	are	transferred	to proved	oil	and	gas	properties.		Lease	rentals	are	expensed	as	incurred.

When	circumstances	indicate	that	proved	oil	and	gas	properties	may	be	impaired,	EOG	compares	expected	undiscounted	future	cash	flows	at	a	depreciation, depletion	and	amortization	group	level	to	the	unamortized	capitalized	cost	of	the	asset.		If	the	expected	undiscounted	future	cash	flows,	based	on	EOG's	estimates	of	(and assumptions	regarding)	future	crude	oil	and	natural	gas	prices,	operating	costs,	development	expenditures,	anticipated	production	from	proved	reserves	and	other relevant	data,	are	lower	than	the	unamortized	capitalized	cost,	the	capitalized	cost	is	reduced	to	fair	value.		Fair	value	is	generally	calculated	using	the	Income	Approach described	in	the	Fair	Value	Measurement	Topic	of	the	ASC.		In	certain	instances,	EOG	utilizes	accepted	offers	from	third-party	purchasers	as	the	basis	for	determining fair	value.		Estimates	of	undiscounted	future	cash	flows	require	significant	judgment,	and	the	assumptions	used	in	preparing	such	estimates	are	inherently	uncertain.	In addition,	such	assumptions	and	estimates	are	reasonably	likely	to	change	in	the	future.

Crude	oil	and	natural	gas	prices	have	exhibited	significant	volatility	in	the	past,	and	EOG	expects	that	volatility	to	continue	in	the	future.		During	the	five	years ended	December	31,	2018,	West	Texas	Intermediate	crude	oil	spot	prices	have	fluctuated	from	approximately	$26.19	per	barrel	to	$107.95	per	barrel,	and	Henry	Hub natural	gas	spot	prices	have	ranged	from	approximately	$1.49	per	MMBtu	to	$8.15	per	MMBtu.	 	EOG	uses	the	five-year	NYMEX	futures	strip	for	West	Texas Intermediate	crude	oil	and	Henry	Hub	natural	gas	(in	each	case	as	of	the	applicable	balance	sheet	date)	as	a	basis	to	estimate	future	crude	oil	and	natural	gas	prices. EOG's	proved	reserves	estimates,	including	the	timing	of	future	production,	are	also	subject	to	significant	assumptions	and	judgment,	and	are	frequently	revised (upwards	and	downwards)	as	more	information	becomes	available.		Proved	reserves	are	estimated	using	a	trailing	12-month	average	price,	in	accordance	with	SEC rules.	In	the	future,	if	any	combination	of	crude	oil	prices,	natural	gas	prices,	actual	production	or	operating	costs	diverge	negatively	from	EOG's	current	estimates, impairment	charges	and	downward	adjustments	to	our	estimated	proved	reserves	may	be	necessary.

# Income	Taxes

Income	 taxes	are	accounted	for	using	 the	asset	and	 liability	approach.	 	Under	 this	approach,	deferred	 tax	assets	and	 liabilities	are	recognized	based	on anticipated	future	tax	consequences	attributable	to	differences	between	financial	statement	carrying	amounts	of	assets	and	liabilities	and	their	respective	tax	basis.		EOG assesses	the	realizability	of	deferred	tax	assets	and	recognizes	valuation	allowances	as	appropriate.		Significant	assumptions	used	in	estimating	future	taxable	income include	future	oil	and	gas	prices	and	levels	of	capital	reinvestment.		Changes	in	such	assumptions	or	changes	in	tax	laws	and	regulations	could	materially	affect	the recognized	amounts	of	valuation	allowances.

# Stock-Based	Compensation

In	accounting	for	stock-based	compensation,	judgments	and	estimates	are	made	regarding,	among	other	things,	the	appropriate	valuation	methodology	to	follow in	valuing	stock	compensation	awards	and	the	related	inputs	required	by	those	valuation	methodologies.	Assumptions	regarding	expected	volatility	of	EOG's	common stock,	the	level	of	risk-free	interest	rates,	expected	dividend	yields	on	EOG's	common	stock,	the	expected	term	of	the	awards,	expected	volatility	in	the	price	of	shares	of EOG's	peer	companies	and	other	valuation	inputs	are	subject	to	change.	Any	such	changes	could	result	in	different	valuations	and	thus	impact	the	amount	of	stock-based compensation	expense	recognized	on	the	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss).

# Information	Regarding	Forward-Looking	Statements

This	Annual	Report	on	Form	10-K	includes	forward-looking	statements	within	the	meaning	of	Section	27A	of	the	Securities	Act	of	1933,	as	amended,	and Section	21E	of	the	Securities	Exchange	Act	of	1934,	as	amended.	All	statements,	other	than	statements	of	historical	facts,	including,	among	others,	statements	and projections	regarding	EOG's	future	financial	position,	operations,	performance,	business	strategy,	returns,	budgets,	reserves,	levels	of	production,	capital	expenditures, costs	and	asset	sales,	statements	regarding	future	commodity	prices	and	statements	regarding	the	plans	and	objectives	of	EOG's	management	for	future	operations,	are forward-looking	statements.	EOG	typically	uses	words	such	as	"expect,"	"anticipate,"	"estimate,"	"project,"	"strategy,"	"intend,"	"plan,"	"target,"	"aims,"	"goal,"	"may," "will,"	"should"	and	"believe"	or	the	negative	of	those	terms	or	other	variations	or	comparable	terminology	to	identify	its	forward-looking	statements.	In	particular, statements,	express	or	implied,	concerning	EOG's	future	operating	results	and	returns	or	EOG's	ability	to	replace	or	increase	reserves,	increase	production,	generate returns,	 replace	 or	 increase	 drilling	 locations,	 reduce	 or	 otherwise	 control	 operating	 costs	 and	 capital	 expenditures,	 generate	 cash	 flows,	 pay	 down	 or	 refinance indebtedness	or	pay	and/or	increase	dividends	are	forward-looking	statements.	Forward-looking	statements	are	not	guarantees	of	performance.	Although	EOG	believes the	expectations	reflected	in	its	forward-looking	statements	are	reasonable	and	are	based	on	reasonable	assumptions,	no	assurance	can	be	given	that	these	assumptions are	accurate	or	that	any	of	these	expectations	will	be	achieved	(in	full	or	at	all)	or	will	prove	to	have	been	correct.	Moreover,	EOG's	forward-looking	statements	may	be affected	by	known,	unknown	or	currently	unforeseen	risks,	events	or	circumstances	that	may	be	outside	EOG's	control.	Important	factors	that	could	cause	EOG's	actual results	to	differ	materially	from	the	expectations	reflected	in	EOG's	forward-looking	statements	include,	among	others:

•the	timing,	extent	and	duration	of	changes	in	prices	for,	supplies	of,	and	demand	for,	crude	oil	and	condensate,	natural	gas	liquids,	natural	gas	and	related commodities;

•the	extent	to	which	EOG	is	successful	in	its	efforts	to	acquire	or	discover	additional

reserves;

•the	extent	to	which	EOG	is	successful	in	its	efforts	to	economically	develop	its	acreage	in,	produce	reserves	and	achieve	anticipated	production	levels from,	and	maximize	reserve	recovery	from,	its	existing	and	future	crude	oil	and	natural	gas	exploration	and	development	projects;

•the	extent	 to	which	EOG	 is	successful	 in	 its	efforts	 to	market	 its	crude	oil	and	condensate,	natural	gas	 liquids,	natural	gas	and	related	commodity production;

•the	availability,	proximity	and	capacity	of,	and	costs	associated	with,	appropriate	gathering,	processing,	compression,	storage,	transportation	and	refining facilities;

•the	availability,	cost,	terms	and	timing	of	issuance	or	execution	of,	and	competition	for,	mineral	licenses	and	leases	and	governmental	and	other	permits and	rights-of-way,	and	EOG's	ability	to	retain	mineral	licenses	and	leases;

•the	impact	of,	and	changes	in,	government	policies,	laws	and	regulations,	including	tax	laws	and	regulations;	climate	change	and	other	environmental,

health	and	safety	laws	and	regulations	relating	to	air	emissions,	disposal	of	produced	water,	drilling	fluids	and	other	wastes,	hydraulic	fracturing	and	access to	and	use	of	water;	laws	and	regulations	imposing	conditions	or	restrictions	on	drilling	and	completion	operations	and	on	the	transportation	of	crude	oil and	natural	gas;	laws	and	regulations	with	respect	to	derivatives	and	hedging	activities;	and	laws	and	regulations	with	respect	to	the	import	and	export	of crude	oil,	natural	gas	and	related	commodities;

•EOG's	ability	to	effectively	integrate	acquired	crude	oil	and	natural	gas	properties	into	its	operations,	fully	identify	existing	and	potential	problems	with respect	to	such	properties	and	accurately	estimate	reserves,	production	and	costs	with	respect	to	such	properties;

•the	 extent	 to	 which	 EOG's	 third-party-operated	 crude	 oil	 and	 natural	 gas	 properties	 are	 operated successfully and economically;

•competition	in	the	oil	and	gas	exploration	and	production	industry	for	the	acquisition	of	licenses,	leases	and	properties,	employees	and	other	personnel, facilities,	equipment,	materials	and	services;

•the	 availability	 and	 cost	 of	 employees	 and	 other	 personnel,	 facilities,	 equipment,	 materials	 (such	 as	 water	 and tubulars)	 and services;

•the	 accuracy	 of reserve	 estimates,	 which	 by their	 nature involve the	 exercise	 of	 professional judgment	 and	 may therefore	 be imprecise;

•weather,	including	its	impact	on	crude	oil	and	natural	gas	demand,	and	weather-related	delays	in	drilling	and	in	the	installation	and	operation	(by	EOG	or third	parties)	of	production,	gathering,	processing,	refining,	compression,	storage	and	transportation	facilities;

•the	ability	of	EOG's	customers	and	other	contractual	counterparties	to	satisfy	their	obligations	to	EOG	and,	related	thereto,	to	access	the	credit	and	capital markets	to	obtain	financing	needed	to	satisfy	their	obligations	to	EOG;

•EOG's	ability	to	access	the	commercial	paper	market	and	other	credit	and	capital	markets	to	obtain	financing	on	terms	it	deems	acceptable,	if	at	all,	and	to otherwise	satisfy	its	capital	expenditure	requirements;

•the	extent	to	which	EOG	is	successful	in	its	completion	of	planned	asset dispositions;

•the	extent	and	effect	of	any	hedging	activities	engaged	in	by

•the	timing	and	extent	of	changes	in	foreign	currency	exchange	rates,	interest	rates,	inflation	rates,	global	and	domestic	financial	market	conditions	and global	and	domestic	general	economic	conditions;

•geopolitical	factors	and	political	conditions	and	developments	around	the	world	(such	as	the	imposition	of	tariffs	or	trade	or	other	economic	sanctions,

political	instability	and	armed	conflict),	including	in	the	areas	in	which	EOG	operates;

•the	use	of	competing	energy	sources	and	the	development	of	alternative	energy sources;

•the	 extent to	 which	 EOG incurs	 uninsured losses	 and liabilities	 or losses	 and liabilities in	 excess	 of its insurance coverage;

•acts	of	war	and	terrorism	and	responses	to	these

acts;

•physical,	electronic	and	cybersecurity	breaches;	and

•the	other	factors	described	under	ITEM	1A,	Risk	Factors,	on	pages	13	through	22	of	this	Annual	Report	on	Form	10-K	and	any	updates	to	those	factors	set forth	in	EOG's	subsequent	Quarterly	Reports	on	Form	10-Q	or	Current	Reports	on	Form	8-K.

In	light	of	these	risks,	uncertainties	and	assumptions,	the	events	anticipated	by	EOG's	forward-looking	statements	may	not	occur,	and,	if	any	of	such	events	do, we	may	not	have	anticipated	the	timing	of	their	occurrence	or	the	duration	or	extent	of	their	impact	on	our	actual	results.	Accordingly,	you	should	not	place	any	undue reliance	on	any	of	EOG's	forward-looking	statements.	EOG's	forward-looking	statements	speak	only	as	of	the	date	made,	and	EOG	undertakes	no	obligation,	other	than as	required	by	applicable	law,	to	update	or	revise	its	forward-looking	statements,	whether	as	a	result	of	new	information,	subsequent	events,	anticipated	or	unanticipated circumstances	or	otherwise.

# ITEM	7A.		Quantitative	and	Qualitative	Disclosures	About	Market	Risk

The	 information	required	by	 this	Item	 is	 incorporated	by	reference	from	Item	7	of	 this	report,	specifically	 the	 information	set	forth	under	 the	captions "Derivative	Transactions,"	"Financing,"	"Foreign	Currency	Exchange	Rate	Risk"	and	"Outlook"	in	"Management's	Discussion	and	Analysis	of	Financial	Condition	and Results	of	Operations	-	Capital	Resources	and	Liquidity."

# ITEM	8.		Financial	Statements	and	Supplementary	Data

The	information	required	by	this	Item	is	included	in	this	report	as	set	forth	in	the	"Index	to	Financial	Statements"	on	page	F-1	and	is	incorporated	by	reference herein.

# ITEM	9.		Changes	in	and	Disagreements	with	Accountants	on	Accounting	and	Financial	Disclosure

# ITEM	9A.		Controls	and	Procedures

Disclosure	Controls	and	Procedures.	EOG's	management,	with	the	participation	of	EOG's	principal	executive	officer	and	principal	financial	officer,	evaluated the	effectiveness	of	EOG's	disclosure	controls	and	procedures	(as	defined	in	Rules	13a-15(e)	and	15d-15(e)	promulgated	under	the	Securities	Exchange	Act	of	1934,	as amended	(Exchange	Act))	as	of	December	31,	2018.	EOG's	disclosure	controls	and	procedures	are	designed	to	provide	reasonable	assurance	that	information	that	is required	to	be	disclosed	in	the	reports	EOG	files	or	submits	under	the	Exchange	Act	is	accumulated	and	communicated	to	EOG's	management,	as	appropriate,	to	allow timely	decisions	regarding	required	disclosure	and	is	recorded,	processed,	summarized	and	reported	within	the	time	periods	specified	in	the	rules	and	forms	of	the United	States	Securities	and	Exchange	Commission.	Based	on	that	evaluation,	EOG's	principal	executive	officer	and	principal	financial	officer	have	concluded	that EOG's	disclosure	controls	and	procedures	were	effective	as	of	December	31,	2018.

Management's	Annual	Report	on	Internal	Control	over	Financial	Reporting.	EOG's	management	is	responsible	for	establishing	and	maintaining	adequate internal	control	over	financial	reporting	(as	defined	in	Rules	13a-15(f)	and	15d-15(f)	promulgated	under	the	Exchange	Act).	Even	an	effective	system	of	internal	control over	financial	reporting,	no	matter	how	well	designed,	has	inherent	limitations,	including	the	possibility	of	human	error,	circumvention	of	controls	or	overriding	of controls	and,	therefore,	can	provide	only	reasonable	assurance	with	respect	to	reliable	financial	reporting.	Furthermore,	the	effectiveness	of	a	system	of	internal	control over	financial	reporting	in	future	periods	can	change	as	conditions	change.

EOG's	management	assessed	the	effectiveness	of	EOG's	internal	control	over	financial	reporting	as	of	December	31,	2018.	In	making	this	assessment,	it	used the	criteria	set	forth	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(COSO)	in	Internal	Control	-	Integrated	Framework	(2013).	Based	on this	assessment	and	such	criteria,	EOG's	management	believes	that	EOG's	internal	control	over	financial	reporting	was	effective	as	of	December	31,	2018.	See	also "Management's	Responsibility	for	Financial	Reporting"	appearing	on	page	F-2	of	this	report,	which	is	incorporated	herein	by	reference.

The	report	of	EOG's	independent	registered	public	accounting	firm	relating	to	the	consolidated	financial	statements	and	effectiveness	of	internal	control	over financial	reporting	is	set	forth	on	page	F-3	of	this	report.

There	were	no	changes	in	EOG's	internal	control	over	financial	reporting	that	occurred	during	the	quarter	ended	December	31,	2018,	that	have	materially affected,	or	are	reasonably	likely	to	materially	affect,	EOG's	internal	control	over	financial	reporting.

# ITEM	9B.		Other	Information

# PART	III

# ITEM	10.		Directors,	Executive	Officers	and	Corporate	Governance

The	information	required	by	this	Item	is	incorporated	by	reference	from	(i)	EOG's	Definitive	Proxy	Statement	with	respect	to	its	2019	Annual	Meeting	of Stockholders	to	be	filed	not	later	than	April	30,	2019	and	(ii)	Item	1	of	this	report,	specifically	the	information	therein	set	forth	under	the	caption	"Executive	Officers	of the	Registrant."

Pursuant	to	Rule	303A.10	of	the	New	York	Stock	Exchange	and	Item	406	of	Regulation	S-K	promulgated	under	the	Securities	Exchange	Act	of	1934,	as amended,	EOG	has	adopted	a	Code	of	Business	Conduct	and	Ethics	for	Directors,	Officers	and	Employees	(Code	of	Conduct)	that	applies	to	all	EOG	directors,	officers and	employees,	including	EOG's	principal	executive	officer,	principal	financial	officer	and	principal	accounting	officer.	EOG	has	also	adopted	a	Code	of	Ethics	for Senior	Financial	Officers	(Code	of	Ethics)	that,	along	with	EOG's	Code	of	Conduct,	applies	to	EOG's	principal	executive	officer,	principal	financial	officer,	principal accounting	officer	and	controllers.

You	can	access	the	Code	of	Conduct	and	Code	of	Ethics	on	the	"Governance"	page	under	"Investors"	on	EOG's	website	at	www.eogresources.com,	and	any EOG	stockholder	who	so	requests	may	obtain	a	printed	copy	of	the	Code	of	Conduct	and	Code	of	Ethics	by	submitting	a	written	request	to	EOG's	Corporate	Secretary.

EOG	intends	to	disclose	any	amendments	to	the	Code	of	Conduct	or	Code	of	Ethics,	and	any	waivers	with	respect	to	the	Code	of	Conduct	or	Code	of	Ethics granted	to	EOG's	principal	executive	officer,	principal	financial	officer,	principal	accounting	officer,	any	of	our	controllers	or	any	of	our	other	employees	performing similar	functions,	on	its	website	at	www.eogresources.com	within	four	business	days	of	the	amendment	or	waiver.	In	such	case,	the	disclosure	regarding	the	amendment or	waiver	will	remain	available	on	EOG's	website	for	at	least	12	months	after	the	initial	disclosure.	There	have	been	no	waivers	granted	with	respect	to	EOG's	Code	of Conduct	or	Code	of	Ethics.

# ITEM	11.		Executive	Compensation

The	information	required	by	this	Item	is	incorporated	by	reference	from	EOG's	Definitive	Proxy	Statement	with	respect	to	its	2019	Annual	Meeting	of Stockholders	to	be	filed	not	later	than	April	30,	2019.	The	Compensation	Committee	Report	and	related	information	incorporated	by	reference	herein	shall	not	be deemed	"soliciting	material"	or	to	be	"filed"	with	the	United	States	Securities	and	Exchange	Commission,	nor	shall	such	information	be	incorporated	by	reference	into any	future	filing	under	the	Securities	Act	of	1933,	as	amended,	or	Securities	Exchange	Act	of	1934,	as	amended,	except	to	the	extent	that	EOG	specifically	incorporates such	information	by	reference	into	such	a	filing.

# ITEM	12.		Security	Ownership	of	Certain	Beneficial	Owners	and	Management	and	Related	Stockholder	Matters

The	information	required	by	this	Item	with	respect	to	security	ownership	of	certain	beneficial	owners	and	management	is	incorporated	by	reference	from	EOG's Definitive	Proxy	Statement	with	respect	to	its	2019	Annual	Meeting	of	Stockholders	to	be	filed	not	later	than	April	30,	2019.

In	February	2014,	EOG's	Board	of	Directors	(Board)	approved	a	two-for-one	stock	split	in	the	form	of	a	stock	dividend	(payable	to	stockholders	of	record	as	of March	17,	2014,	and	paid	on	March	31,	2014)	and	corresponding	adjustments	to	EOG's	equity	compensation	plans.	All	share	amounts	set	forth	below	have	been restated	to	reflect	the	two-for-one	stock	split	and	such	adjustments.

# Equity	Compensation	Plan	Information

Stock	Plans	Approved	by	EOG	Stockholders.		EOG's	stockholders	approved	the	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(2008	Plan)	at the	2008	Annual	Meeting	of	Stockholders	in	May	2008.		At	the	2010	Annual	Meeting	of	Stockholders	in	April	2010	(2010	Annual	Meeting),	an	amendment	to	the	2008 Plan	was	approved,	pursuant	to	which	the	number	of	shares	of	common	stock	available	for	future	grants	of	stock	options,	stock-settled	stock	appreciation	rights	(SARs), restricted	stock,	restricted	stock	units,	performance	stock,	performance	units	and	other	stock-based	awards	under	the	2008	Plan	was	increased	by	an	additional	13.8 million	shares,	to	an	aggregate	maximum	of	25.8	million	shares	plus	shares	underlying	forfeited	or	canceled	grants	under	the	prior	stock	plans	referenced	in	the	2008 Plan	document.		At	the	2013	Annual	Meeting	of	Stockholders	in	May	2013,	EOG's	stockholders	approved	the	Amended	and	Restated	EOG	Resources,	Inc.	2008 Omnibus	Equity	Compensation	Plan	(Amended	and	Restated	2008	Plan).		As	more	fully	discussed	in	the	Amended	and	Restated	2008	Plan	document,	the	Amended	and Restated	2008	Plan,	among	other	things,	authorizes	an	additional	31.0	million	shares	of	EOG	common	stock	for	grant	under	the	plan	and	extends	the	expiration	date	of the	plan	to	May	2023.		Under	the	Amended	and	Restated	2008	Plan,	grants	may	be	made	to	employees	and	non-employee	members	of	EOG's	Board.

Also	at	the	2010	Annual	Meeting,	an	amendment	to	the	EOG	Resources,	Inc.	Employee	Stock	Purchase	Plan	(ESPP)	was	approved	to	increase	the	shares available	for	grant	by	2.0	million	shares.		The	ESPP	was	originally	approved	by	EOG's	stockholders	in	2001,	and	would	have	expired	on	July	1,	2011.		The	amendment also	extended	the	term	of	the	ESPP	to	December	31,	2019,	unless	terminated	earlier	by	its	terms	or	by	EOG.	At	the	2018	Annual	Meeting	of	Stockholders,	stockholders approved	an	amendment	and	restatement	of	the	ESPP	to	(among	other	changes)	increase	the	number	of	shares	available	for	grant	by	2.5	million	shares	and	further extend	the	term	of	the	ESPP	to	December	31,	2027,	unless	terminated	earlier	by	its	terms	or	by	EOG.

Stock	Plans	Not	Approved	by	EOG	Stockholders.		In	December	2008,	the	Board	approved	the	amendment	and	continuation	of	the	1996	Deferral	Plan	as	the "EOG	Resources,	Inc.	409A	Deferred	Compensation	Plan"	(Deferral	Plan).		Under	the	Deferral	Plan	(as	subsequently	amended),	payment	of	up	to	50%	of	base	salary and	100%	of	annual	cash	bonus,	director's	fees,	vestings	of	restricted	stock	units	granted	to	non-employee	directors	(and	dividends	credited	thereon)	under	the	2008	Plan and	401(k)	refunds	(as	defined	in	the	Deferral	Plan)	may	be	deferred	into	a	phantom	stock	account.	In	the	phantom	stock	account,	deferrals	are	treated	as	if	shares	of EOG	common	stock	were	purchased	at	the	closing	stock	price	on	the	date	of	deferral.		Dividends	are	credited	quarterly	and	treated	as	if	reinvested	in	EOG	common stock.		Payment	of	the	phantom	stock	account	is	made	in	actual	shares	of	EOG	common	stock	in	accordance	with	the	Deferral	Plan	and	the	individual's	deferral election.		A	total	of	540,000	shares	of	EOG	common	stock	have	been	authorized	by	the	Board	and	registered	for	issuance	under	the	Deferral	Plan.		As	of	December	31, 2018,	327,362	phantom	shares	had	been	issued.	The	Deferral	Plan	is	currently	EOG's	only	stock	plan	that	has	not	been	approved	by	EOG's	stockholders.

			The	following	table	sets	forth	data	for	EOG's	equity	compensation	plans	aggregated	by	the	various	plans	approved	by	EOG's	stockholders	and	those	plans	not

approved	by	EOG's	stockholders,	in	each	case	as	of	December	31,	2018.

| Plan	Category | (a)<br>Number	of	Securities	to	be<br>Issued	Upon	Exercise	of<br>Outstanding	Options,<br>Warrants	and	Rights |  | (b)<br>Weighted-Average<br>Exercise	Price	of<br>Outstanding	Options,<br>Warrants	and	Rights	(1) | (c)<br>Number	of	Securities<br>Remaining	Available<br>for	Future	Issuance	Under<br>Equity	Compensation<br>Plans	(Excluding	Securities<br>Reflected	in	Column	(a)) |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Equity\tCompensation\tPlans\tApproved\tby\nEOG\tStockholders | 9,759,247 | (2) | $96.90 | 16,243,789 | (3) |
| Equity\tCompensation\tPlans\tNot\tApproved\tby\nEOG\tStockholders | 273,296 | (4) | N/A | 212,638 | (5) |
| Total | 10,032,543 |  | $96.90 | 16,456,427 |  |

(1) The	weighted-average	exercise	price	is	calculated	based	solely	on	the	exercise	prices	of	the	outstanding	stock	option	and	SAR	grants	and	does	not	reflect	shares	that	will	be issued	upon	the	vesting	of	outstanding	restricted	stock	unit	and	performance	unit	grants,	or	Deferral	Plan	phantom	shares,	all	of	which	have	no	exercise	price.

(2) Amount	includes	910,880	outstanding	restricted	stock	units,	for	which	shares	of	EOG	common	stock	will	be	issued,	on	a	one-for-one	basis,	upon	the	vesting	of	such	grants. Amount	also	includes	539,029	outstanding	performance	units	and	assumes,	for	purposes	of	this	table,	(i)	the	application	of	a	100%	performance	multiple	upon	the	completion	of each	of	the	remaining	performance	periods	in	respect	of	such	performance	unit	grants	and	(ii)	accordingly,	the	issuance,	on	a	one-for-one	basis,	of	an	aggregate	539,029	shares	of EOG	common	stock	upon	the	vesting	of	such	grants.	As	more	fully	discussed	in	Note	7	to	Consolidated	Financial	Statements,	upon	the	application	of	the	relevant	performance multiple	at	the	completion	of	each	of	the	remaining	performance	periods	in	respect	of	such	grants,	(A)	a	minimum	of	143,610	and	a	maximum	of	934,448	performance	units could	be	outstanding	and	(B)	accordingly,	a	minimum	of	143,610	and	a	maximum	of	934,448	shares	of	EOG	common	stock	could	be	issued	upon	the	vesting	of	such	grants.

(3) Consists	of	(i)	13,748,078	shares	remaining	available	for	issuance	under	the	Amended	and	Restated	2008	Plan	and	(ii)	2,495,711	shares	remaining	available	for	purchase	under the	ESPP.		Pursuant	to	the	fungible	share	design	of	the	Amended	and	Restated	2008	Plan,	each	share	issued	as	a	SAR	or	stock	option	under	the	Amended	and	Restated	2008	Plan counts	as	1.0	share	against	the	aggregate	plan	share	limit,	and	each	share	issued	as	a	"full	value	award"	(i.e.,	as	restricted	stock,	restricted	stock	units,	performance	stock	or performance	units)	counts	as	2.45	shares	against	the	aggregate	plan	share	limit.		Thus,	from	the	13,748,078	shares	remaining	available	for	issuance	under	the	Amended	and Restated	2008	Plan,	(i)	the	maximum	number	of	shares	we	could	issue	as	SAR	and	stock	option	awards	is	13,748,078	(i.e.,	if	all	shares	remaining	available	for	issuance	under	the Amended	and	Restated	2008	Plan	are	issued	as	SAR	and	stock	option	awards)	and	(ii)	the	maximum	number	of	shares	we	could	issue	as	full	value	awards	is	5,611,460	(i.e.,	if	all shares	remaining	available	for	issuance	under	the	Amended	and	Restated	2008	Plan	are	issued	as	full	value	awards).

(4) Consists	of	shares	of	EOG	common	stock	to	be	issued	in	accordance	with	the	Deferral	Plan	and	participant	deferral	elections	(i.e.,	in	respect	of	the	273,296	phantom	shares	issued and	outstanding	under	the	Deferral	Plan	as	of	December	31,	2018).

(5) Represents	phantom	shares	that	remain	available	for	issuance	under	the	Deferral	Plan.

# ITEM	13.		Certain	Relationships	and	Related	Transactions,	and	Director	Independence

The	information	required	by	this	Item	is	incorporated	by	reference	from	EOG's	Definitive	Proxy	Statement	with	respect	to	its	2019	Annual	Meeting	of Stockholders	to	be	filed	not	later	than	April	30,	2019.

# ITEM	14.		Principal	Accounting	Fees	and	Services

# PART	IV

# ITEM	15.		Exhibits,	Financial	Statement	Schedules

# (a)(1)	and	(a)(2)	Financial	Statements	and	Financial	Statement	Schedule

See	"Index	to	Financial	Statements"	set	forth	on	page	F-1.

See	pages	E-1	through	E-6	for	a	listing	of	the	exhibits.

# INDEX	TO	FINANCIAL	STATEMENTS

# Consolidated	Financial	Statements:

# MANAGEMENT'S	RESPONSIBILITY	FOR	FINANCIAL	REPORTING

The	following	consolidated	financial	statements	of	EOG	Resources,	Inc.,	together	with	its	subsidiaries	(collectively,	EOG),	were	prepared	by	management, which	is	responsible	for	the	integrity,	objectivity	and	fair	presentation	of	such	financial	statements.		The	statements	have	been	prepared	in	conformity	with	generally accepted	 accounting	 principles	 in	 the	 United	 States	 of	America	 and,	 accordingly,	 include	 some	 amounts	 that	 are	 based	 on	 the	 best	 estimates	 and	 judgments	 of management.

EOG's	 management	 is	 also	 responsible	 for	 establishing	 and	 maintaining	 adequate	 internal	 control	 over	 financial	 reporting	 as	 well	 as	 designing	 and implementing	programs	and	controls	to	prevent	and	detect	fraud.		The	system	of	internal	control	of	EOG	is	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	in	the United	States	of	America.		This	system	consists	of	1)	entity	level	controls,	including	written	policies	and	guidelines	relating	to	the	ethical	conduct	of	business	affairs,	2) general	computer	controls	and	3)	process	controls	over	initiating,	authorizing,	recording,	processing	and	reporting	transactions.		Even	an	effective	internal	control system,	no	matter	how	well	designed,	has	inherent	limitations,	including	the	possibility	of	human	error,	circumvention	of	controls	or	overriding	of	controls	and, therefore,	can	provide	only	reasonable	assurance	with	respect	to	reliable	financial	reporting.		Furthermore,	the	effectiveness	of	a	system	of	internal	control	over	financial reporting	in	future	periods	can	change	as	conditions	change.

The	adequacy	of	EOG's	financial	controls	and	the	accounting	principles	employed	by	EOG	in	its	financial	reporting	are	under	the	general	oversight	of	the	Audit Committee	of	the	Board	of	Directors.		No	member	of	this	committee	is	an	officer	or	employee	of	EOG.		Moreover,	EOG's	independent	registered	public	accounting	firm and	internal	auditors	have	full,	free,	separate	and	direct	access	to	the	Audit	Committee	and	meet	with	the	committee	periodically	to	discuss	accounting,	auditing	and financial	reporting	matters.

EOG's	management	assessed	the	effectiveness	of	EOG's	internal	control	over	financial	reporting	as	of	December	31,	2018.		In	making	this	assessment,	EOG used	the	criteria	set	forth	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(COSO)	in	Internal	Control	-	Integrated	Framework	(2013). These	criteria	cover	the	control	environment,	risk	assessment	process,	control	activities,	information	and	communication	systems,	and	monitoring	activities.		Based	on this	assessment	and	those	criteria,	management	believes	that	EOG	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2018.

Deloitte	&	Touche	LLP,	independent	registered	public	accounting	firm,	was	engaged	to	audit	the	consolidated	financial	statements	of	EOG	and	audit	EOG's internal	control	over	financial	reporting	and	issue	a	report	thereon.		In	the	conduct	of	the	audits,	Deloitte	&	Touche	LLP	was	given	unrestricted	access	to	all	financial records	and	related	data,	including	all	minutes	of	meetings	of	stockholders,	the	Board	of	Directors	and	committees	of	the	Board	of	Directors.		Management	believes	that all	representations	made	to	Deloitte	&	Touche	LLP	during	the	audits	were	valid	and	appropriate.		Their	audits	were	made	in	accordance	with	the	standards	of	the	Public Company	Accounting	Oversight	Board	(United	States).	Their	report	appears	on	page	F-3.

WILLIAM	R.	THOMAS

Chairman	of	the	Board	and

Chief	Executive	Officer

TIMOTHY	K.	DRIGGERS Executive	Vice	President	and	Chief Financial	Officer

Houston,	Texas

# REPORT	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

To	the	stockholders	and	the	Board	of	Directors	of

# Opinions	on	the	Financial	Statements	and	Internal	Control	over	Financial	Reporting

We	have	audited	the	accompanying	consolidated	balance	sheets	of	EOG	Resources,	Inc.	and	subsidiaries	(the	"Company")	as	of	December	31,	2018	and	2017,	and	the related	consolidated	statements	of	income	(loss)	and	comprehensive	income	(loss),	stockholders'	equity,	and	cash	flows	for	each	of	the	three	years	in	the	period	ended December	31,	2018,	and	the	related	notes	(collectively	referred	to	as	the	"financial	statements").	We	also	have	audited	the	Company's	internal	control	over	financial reporting	 as	 of	 December	 31,	 2018,	 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	financial	statements	referred	to	above	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company	as	of	December	31,	2018	and 2017,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2018,	in	conformity	with	accounting	principles generally	accepted	in	the	United	States	of	America.	Also,	in	our	opinion,	the	Company	maintained,	in	all	material	respects,	effective	internal	control	over	financial reporting	as	of	December	31,	2018,	based	on	the	criteria	established	in	Internal	Control	-	Integrated	Framework	(2013)	issued	by	COSO.

# Basis	for	Opinions

The	Company's	management	is	responsible	for	these	financial	statements,	for	maintaining	effective	internal	control	over	financial	reporting,	and	for	its	assessment	of	the effectiveness	of	internal	control	over	financial	reporting,	included	in	the	accompanying	Management's	Annual	Report	on	Internal	Control	over	Financial	Reporting.	Our responsibility	is	to	express	an	opinion	on	these	financial	statements	and	an	opinion	on	the	Company's	internal	control	over	financial	reporting	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	audits	to	obtain	reasonable	assurance about	whether	the	financial	statements	are	free	of	material	misstatement,	whether	due	to	error	or	fraud,	and	whether	effective	internal	control	over	financial	reporting was	maintained	in	all	material	respects.

Our	audits	of	the	financial	statements	included	performing	procedures	to	assess	the	risks	of	material	misstatement	of	the	financial	statements,	whether	due	to	error	or fraud,	and	performing	procedures	to	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.

Our	audit	of	internal	control	over	financial	reporting	included	obtaining	an	understanding	of	internal	control	over	financial	reporting,	assessing	the	risk	that	a	material weakness	exists,	and	testing	and	evaluating	the	design	and	operating	effectiveness	of	internal	control	based	on	the	assessed	risk.	Our	audits	also	included	performing such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We	believe	that	our	audits	provide	a	reasonable	basis	for	our	opinions.

# 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.

/s/	DELOITTE	&	TOUCHE	LLP

We	have	served	as	the	Company's	auditor	since	2002.

# CONSOLIDATED	STATEMENTS	OF	INCOME	(LOSS)	AND	COMPREHENSIVE	INCOME	(LOSS)

| Year	Ended	December	31 | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Operating\tRevenues\tand\tOther |  |  |  |
| Crude\tOil\tand\tCondensate | $9,517,440 | $6,256,396 | $4,317,341 |
| Natural\tGas\tLiquids | 1,127,510 | 729,561 | 437,250 |
| Natural\tGas | 1,301,537 | 921,934 | 742,152 |
| Gains\t(Losses)\ton\tMark-to-Market\tCommodity\tDerivative\tContracts | (165,640) | 19,828 | (99,608) |
| Gathering,\tProcessing\tand\tMarketing | 5,230,355 | 3,298,087 | 1,966,259 |
| Gains\t(Losses)\ton\tAsset\tDispositions,\tNet | 174,562 | (99,096) | 205,835 |
| Other,\tNet | 89,635 | 81,610 | 81,403 |
| Total | 17,275,399 | 11,208,320 | 7,650,632 |
| Operating\tExpenses |  |  |  |
| Lease\tand\tWell | 1,282,678 | 1,044,847 | 927,452 |
| Transportation\tCosts | 746,876 | 740,352 | 764,106 |
| Gathering\tand\tProcessing\tCosts | 436,973 | 148,775 | 122,901 |
| Exploration\tCosts | 148,999 | 145,342 | 124,953 |
| Dry\tHole\tCosts | 5,405 | 4,609 | 10,657 |
| Impairments | 347,021 | 479,240 | 620,267 |
| Marketing\tCosts | 5,203,243 | 3,330,237 | 2,007,635 |
| Depreciation,\tDepletion\tand\tAmortization | 3,435,408 | 3,409,387 | 3,553,417 |
| General\tand\tAdministrative | 426,969 | 434,467 | 394,815 |
| Taxes\tOther\tThan\tIncome | 772,481 | 544,662 | 349,710 |
| Total | 12,806,053 | 10,281,918 | 8,875,913 |
| Operating\tIncome\t(Loss) | 4,469,346 | 926,402 | (1,225,281) |
| Other\tIncome\t(Expense),\tNet | 16,704 | 9,152 | (50,543) |
| Income\t(Loss)\tBefore\tInterest\tExpense\tand\tIncome\tTaxes | 4,486,050 | 935,554 | (1,275,824) |
| Interest\tExpense |  |  |  |
| Incurred | 269,549 | 301,801 | 313,341 |
| Capitalized | (24,497) | (27,429) | (31,660) |
| Net\tInterest\tExpense | 245,052 | 274,372 | 281,681 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | 4,240,998 | 661,182 | (1,557,505) |
| Income\tTax\tProvision\t(Benefit) | 821,958 | (1,921,397) | (460,819) |
| Net\tIncome\t(Loss) | $3,419,040 | $2,582,579 | $(1,096,686) |
| Net\tIncome\t(Loss)\tPer\tShare |  |  |  |
| Basic | $5.93 | $4.49 | $(1.98) |
| Diluted | $5.89 | $4.46 | $(1.98) |
| Average\tNumber\tof\tCommon\tShares |  |  |  |
| Basic | 576,578 | 574,620 | 553,384 |
| Diluted | 580,441 | 578,693 | 553,384 |
| Comprehensive\tIncome\t(Loss) |  |  |  |
| Net\tIncome\t(Loss) | $3,419,040 | $2,582,579 | $(1,096,686) |
| Other\tComprehensive\tIncome\t(Loss) |  |  |  |
| Foreign\tCurrency\tTranslation\tAdjustments | 16,816 | 2,799 | 12,097 |
| Other,\tNet\tof\tTax | 1,123 | (3,086) | 2,231 |
| Other\tComprehensive\tIncome\t(Loss) | 17,939 | (287) | 14,328 |
| Comprehensive\tIncome\t(Loss) | $3,436,979 | $2,582,292 | $(1,082,358) |

The	accompanying	notes	are	an	integral	part	of	these	consolidated	financial	statements.

# CONSOLIDATED	BALANCE	SHEETS

# (In	Thousands,	Except	Share	Data)

| At	December	31 | 2018 | 2017 |
| :--- | :--- | :--- |
| ASSETS |  |  |
| Current\tAssets |  |  |
| Cash\tand\tCash\tEquivalents | $1,555,634 | $834,228 |
| Accounts\tReceivable,\tNet | 1,915,215 | 1,597,494 |
| Inventories | 859,359 | 483,865 |
| Assets\tfrom\tPrice\tRisk\tManagement\tActivities | 23,806 | 7,699 |
| Income\tTaxes\tReceivable | 427,909 | 113,357 |
| Other | 275,467 | 242,465 |
| Total | 5,057,390 | 3,279,108 |
| Property,\tPlant\tand\tEquipment |  |  |
| Oil\tand\tGas\tProperties\t(Successful\tEfforts\tMethod) | 57,330,016 | 52,555,741 |
| Other\tProperty,\tPlant\tand\tEquipment | 4,220,665 | 3,960,759 |
| Total\tProperty,\tPlant\tand\tEquipment | 61,550,681 | 56,516,500 |
| Less:\tAccumulated\tDepreciation,\tDepletion\tand\tAmortization | (33,475,162) | (30,851,463) |
| Total\tProperty,\tPlant\tand\tEquipment,\tNet | 28,075,519 | 25,665,037 |
| Deferred\tIncome\tTaxes | 777 | 17,506 |
| Other\tAssets | 800,788 | 871,427 |
| Total\tAssets | $33,934,474 | $29,833,078 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tLiabilities |  |  |
| Accounts\tPayable | $2,239,850 | $1,847,131 |
| Accrued\tTaxes\tPayable | 214,726 | 148,874 |
| Dividends\tPayable | 126,971 | 96,410 |
| Liabilities\tfrom\tPrice\tRisk\tManagement\tActivities | — | 50,429 |
| Current\tPortion\tof\tLong-Term\tDebt | 913,093 | 356,235 |
| Other | 233,724 | 226,463 |
| Total | 3,728,364 | 2,725,542 |
| Long-Term\tDebt | 5,170,169 | 6,030,836 |
| Other\tLiabilities | 1,258,355 | 1,275,213 |
| Deferred\tIncome\tTaxes | 4,413,398 | 3,518,214 |
| Commitments\tand\tContingencies\t(Note\t8) |  |  |
| Stockholders'\tEquity |  |  |
| December\t31,\t2018\tand\t2017,\trespectively | 205,804 | 205,788 |
| Additional\tPaid\tin\tCapital | 5,658,794 | 5,536,547 |
| Accumulated\tOther\tComprehensive\tLoss | (1,358) | (19,297) |
| Retained\tEarnings | 13,543,130 | 10,593,533 |
| Common\tStock\tHeld\tin\tTreasury,\t385,042\tShares\tand\t350,961\tShares\tat\tDecember\t31,\t2018\tand\t2017,\trespectively | (42,182) | (33,298) |
| Total\tStockholders'\tEquity | 19,364,188 | 16,283,273 |
| Total\tLiabilities\tand\tStockholders'\tEquity | $33,934,474 | $29,833,078 |

# CONSOLIDATED	STATEMENTS	OF	STOCKHOLDERS'	EQUITY

|  | Common<br>Stock | Additional<br>Paid	In<br>Capital | Accumulated<br>Other<br>Comprehensive<br>Income	(Loss) | Retained<br>Earnings | Common<br>Stock<br>Held	In<br>Treasury | Total<br>Stockholders'<br>Equity |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Balance\tat\tDecember\t31,\t2015 | $205,502 | $2,923,461 | $(33,338) | $9,870,816 | $(23,406) | $12,943,035 |
| Net\tLoss | — | — | — | (1,096,686) | — | (1,096,686) |
| Common\tStock\tIssued\tfor\tthe\tYates\tTransaction | 252 | 2,397,635 | — | — | — | 2,397,887 |
| Common\tStock\tIssued\tUnder\tStock\tPlans | 9 | 16,388 | — | — | — | 16,397 |
| Common\tStock\tDividends\tDeclared,\t$0.67\tPer\nShare | — | — | — | (376,012) | — | (376,012) |
| Other\tComprehensive\tIncome | — | — | 14,328 | — | — | 14,328 |
| Change\tin\tTreasury\tStock\t-\tStock\tCompensation\nPlans,\tNet | — | (27,018) | — | — | (48,208) | (75,226) |
| Excess\tTax\tBenefit\tfrom\tStock-Based\nCompensation | — | 29,357 | — | — | — | 29,357 |
| Restricted\tStock\tand\tRestricted\tStock\tUnits,\tNet | 7 | (47,509) | — | — | 47,502 | — |
| Stock-Based\tCompensation\tExpenses | — | 128,090 | — | — | — | 128,090 |
| Treasury\tStock\tIssued\tas\tCompensation | — | (19) | — | — | 430 | 411 |
| Balance\tat\tDecember\t31,\t2016 | 205,770 | 5,420,385 | (19,010) | 8,398,118 | (23,682) | 13,981,581 |
| Net\tIncome | — | — | — | 2,582,579 | — | 2,582,579 |
| Common\tStock\tIssued\tUnder\tStock\tPlans | 7 | 7,082 | — | — | — | 7,089 |
| Common\tStock\tDividends\tDeclared,\t$0.67\tPer\nShare | — | — | — | (387,164) | — | (387,164) |
| Other\tComprehensive\tLoss | — | — | (287) | — | — | (287) |
| Change\tin\tTreasury\tStock\t-\tStock\tCompensation\nPlans,\tNet | — | (27,348) | — | — | (9,395) | (36,743) |
| Restricted\tStock\tand\tRestricted\tStock\tUnits,\tNet | 11 | 2,552 | — | — | (2,563) | — |
| Stock-Based\tCompensation\tExpenses | — | 133,849 | — | — | — | 133,849 |
| Treasury\tStock\tIssued\tas\tCompensation | — | 27 | — | — | 2,342 | 2,369 |
| Balance\tat\tDecember\t31,\t2017 | 205,788 | 5,536,547 | (19,297) | 10,593,533 | (33,298) | 16,283,273 |
| Net\tIncome | — | — | — | 3,419,040 | — | 3,419,040 |
| Common\tStock\tIssued\tUnder\tStock\tPlans | 8 | 5,612 | — | — | — | 5,620 |
| Common\tStock\tDividends\tDeclared,\t$0.81\tPer\nShare |  |  |  |  |  |  |
|  | — | — | — | (469,443) | — | (469,443) |
| Other\tComprehensive\tIncome | — | — | 17,939 | — | — | 17,939 |
| Change\tin\tTreasury\tStock\t-\tStock\tCompensation\nPlans,\tNet | — | (35,118) | — | — | (13,336) | (48,454) |
| Restricted\tStock\tand\tRestricted\tStock\tUnits,\tNet | 8 | (3,891) | — | — | 3,883 | — |
| Stock-Based\tCompensation\tExpenses | — | 155,337 | — | — | — | 155,337 |
| Treasury\tStock\tIssued\tas\tCompensation | — | 307 | — | — | 569 | 876 |
| Balance\tat\tDecember\t31,\t2018 | $205,804 | $5,658,794 | $(1,358) | $13,543,130 | $(42,182) | $19,364,188 |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

# (In	Thousands)

| Year	Ended	December	31 | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Cash\tFlows\tfrom\tOperating\tActivities |  |  |  |
| Reconciliation\tof\tNet\tIncome\t(Loss)\tto\tNet\tCash\tProvided\tby\tOperating\tActivities: |  |  |  |
| Net\tIncome\t(Loss) | $3,419,040 | $2,582,579 | $(1,096,686) |
| Items\tNot\tRequiring\t(Providing)\tCash |  |  |  |
| Depreciation,\tDepletion\tand\tAmortization | 3,435,408 | 3,409,387 | 3,553,417 |
| Impairments | 347,021 | 479,240 | 620,267 |
| Stock-Based\tCompensation\tExpenses | 155,337 | 133,849 | 128,090 |
| Deferred\tIncome\tTaxes | 894,156 | (1,473,872) | (515,206) |
| (Gains)\tLosses\ton\tAsset\tDispositions,\tNet | (174,562) | 99,096 | (205,835) |
| Other,\tNet | 7,066 | 6,546 | 61,690 |
| Dry\tHole\tCosts | 5,405 | 4,609 | 10,657 |
| Mark-to-Market\tCommodity\tDerivative\tContracts |  |  |  |
| Total\t(Gains)\tLosses | 165,640 | (19,828) | 99,608 |
| Net\tCash\tReceived\tfrom\t(Payments\tfor)\tSettlements\tof\tCommodity\tDerivative\tContracts | (258,906) | 7,438 | (22,219) |
| Excess\tTax\tBenefits\tfrom\tStock-Based\tCompensation | — | — | (29,357) |
| Other,\tNet | 3,108 | 1,204 | 10,971 |
| Changes\tin\tComponents\tof\tWorking\tCapital\tand\tOther\tAssets\tand\tLiabilities |  |  |  |
| Accounts\tReceivable | (368,180) | (392,131) | (232,799) |
| Inventories | (395,408) | (174,548) | 170,694 |
| Accounts\tPayable | 439,347 | 324,192 | (74,048) |
| Accrued\tTaxes\tPayable | (92,461) | (63,937) | 92,782 |
| Other\tAssets | (125,435) | (658,609) | (40,636) |
| Other\tLiabilities | 10,949 | (89,871) | (16,225) |
| Changes\tin\tComponents\tof\tWorking\tCapital\tAssociated\twith\tInvesting\tand\tFinancing\tActivities | 301,083 | 89,992 | (156,102) |
| Net\tCash\tProvided\tby\tOperating\tActivities | 7,768,608 | 4,265,336 | 2,359,063 |
| Investing\tCash\tFlows |  |  |  |
| Additions\tto\tOil\tand\tGas\tProperties | (5,839,294) | (3,950,918) | (2,489,756) |
| Additions\tto\tOther\tProperty,\tPlant\tand\tEquipment | (237,181) | (173,324) | (93,039) |
| Proceeds\tfrom\tSales\tof\tAssets | 227,446 | 226,768 | 1,119,215 |
| Net\tCash\tReceived\tfrom\tYates\tTransaction | — | — | 54,534 |
| Other\tInvesting\tActivities | (19,993) | — | — |
| Changes\tin\tComponents\tof\tWorking\tCapital\tAssociated\twith\tInvesting\tActivities | (301,140) | (89,935) | 156,102 |
| Net\tCash\tUsed\tin\tInvesting\tActivities | (6,170,162) | (3,987,409) | (1,252,944) |
| Financing\tCash\tFlows |  |  |  |
| Net\tCommercial\tPaper\tRepayments | — | — | (259,718) |
| Long-Term\tDebt\tBorrowings | — | — | 991,097 |
| Long-Term\tDebt\tRepayments | (350,000) | (600,000) | (563,829) |
| Dividends\tPaid | (438,045) | (386,531) | (372,845) |
| Excess\tTax\tBenefits\tfrom\tStock-Based\tCompensation | — | — | 29,357 |
| Treasury\tStock\tPurchased | (63,456) | (63,408) | (82,125) |
| Proceeds\tfrom\tStock\tOptions\tExercised\tand\tEmployee\tStock\tPurchase\tPlan | 20,560 | 20,840 | 23,296 |
| Debt\tIssuance\tCosts | — | — | (1,602) |
| Repayment\tof\tCapital\tLease\tObligation | (8,219) | (6,555) | (6,353) |
| Changes\tin\tComponents\tof\tWorking\tCapital\tAssociated\twith\tFinancing\tActivities | 57 | (57) | — |
| Net\tCash\tUsed\tin\tFinancing\tActivities | (839,103) | (1,035,711) | (242,722) |
| Effect\tof\tExchange\tRate\tChanges\ton\tCash | (37,937) | (7,883) | 17,992 |
| Increase\t(Decrease)\tin\tCash\tand\tCash\tEquivalents | 721,406 | (765,667) | 881,389 |
| Cash\tand\tCash\tEquivalents\tat\tBeginning\tof\tYear | 834,228 | 1,599,895 | 718,506 |
| Cash\tand\tCash\tEquivalents\tat\tEnd\tof\tYear | $1,555,634 | $834,228 | $1,599,895 |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# 1.		Summary	of	Significant	Accounting	Policies

Principles of	 Consolidation.		 The	 consolidated	 financial	 statements	 of	 EOG	 Resources,	 Inc.	 (EOG)	 include	 the	 accounts	 of	 all	 domestic	 and	 foreign subsidiaries.	 	 Investments	 in	 unconsolidated	 affiliates,	 in	 which	 EOG	 is	 able	 to	 exercise	 significant	 influence,	 are	 accounted	 for	 using	 the	 equity	 method.	 	All intercompany	accounts	and	transactions	have	been	eliminated.

The	preparation	of	financial	statements	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America	(U.S.	GAAP)	requires management	to	make	estimates	and	assumptions	that	affect	the	reported	amounts	of	assets	and	liabilities	and	disclosure	of	contingent	assets	and	liabilities	at	the	date	of the	financial	statements	and	the	reported	amounts	of	revenues	and	expenses	during	the	reporting	period.		Actual	results	could	differ	from	those	estimates.

Financial	Instruments. 	EOG's	financial	instruments	consist	of	cash	and	cash	equivalents,	commodity	derivative	contracts,	accounts	receivable,	accounts payable	and	current	and	long-term	debt.		The	carrying	values	of	cash	and	cash	equivalents,	commodity	derivative	contracts,	accounts	receivable	and	accounts	payable approximate	fair	value	(see	Notes	2	and	12).

Cash	and	Cash	Equivalents.		EOG	records	as	cash	equivalents	all	highly	liquid	short-term	investments	with	original	maturities	of	three	months	or	less.

Oil	 and	 Gas	 Operations.		 EOG	 accounts	 for its	 crude	 oil	 and	 natural	 gas	 exploration	 and	 production	 activities	 under the	 successful	 efforts	 method	 of accounting.

Oil	and	gas	exploration	costs,	other	than	the	costs	of	drilling	exploratory	wells,	are	expensed	as	incurred.		The	costs	of	drilling	exploratory	wells	are	capitalized pending	determination	of	whether	EOG	has	discovered	commercial	quantities	of	proved	reserves.		If	commercial	quantities	of	proved	reserves	are	not	discovered,	such drilling	costs	are	expensed.		In	some	circumstances,	it	may	be	uncertain	whether	commercial	quantities	of	proved	reserves	have	been	discovered	when	drilling	has	been completed.		Such	exploratory	well	drilling	costs	may	continue	to	be	capitalized	if	the	reserve	quantity	is	sufficient	to	justify	its	completion	as	a	producing	well	and sufficient	progress	in	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project	is	being	made	(see	Note	16).		Costs	to	develop	proved	reserves, including	the	costs	of	all	development	wells	and	related	equipment	used	in	the	production	of	crude	oil	and	natural	gas,	are	capitalized.

Oil	and	gas	properties	are	grouped	in	accordance	with	the	provisions	of	the	Extractive	Industries	-	Oil	and	Gas	Topic	of	the	Financial	Accounting	Standards Board	(FASB)	Accounting	Standards	Codification	(ASC).		The	basis	for	grouping	is	a	reasonable	aggregation	of	properties	with	a	common	geological	structural	feature or	stratigraphic	condition,	such	as	a	reservoir	or	field.

Amortization	rates	are	updated	quarterly	to	reflect:	1)	the	addition	of	capital	costs,	2)	reserve	revisions	(upwards	or	downwards)	and	additions,	3)	property acquisitions	and/or	property	dispositions	and	4)	impairments.

When	circumstances	indicate	that	proved	oil	and	gas	properties	may	be	impaired,	EOG	compares	expected	undiscounted	future	cash	flows	at	a	depreciation, depletion	and	amortization	group	level	to	the	unamortized	capitalized	cost	of	the	asset.		If	the	expected	undiscounted	future	cash	flows,	based	on	EOG's	estimate	of	(and assumptions	regarding)	future	crude	oil	and	natural	gas	prices,	operating	costs,	development	expenditures,	anticipated	production	from	proved	reserves	and	other relevant	data,	are	lower	than	the	unamortized	capitalized	cost,	the	capitalized	cost	is	reduced	to	fair	value.		Fair	value	is	generally	calculated	using	the	Income	Approach described	in	the	Fair	Value	Measurement	Topic	of	the	ASC.		In	certain	instances,	EOG	utilizes	accepted	offers	from	third-party	purchasers	as	the	basis	for	determining fair	value.

Inventories,	consisting	primarily	of	tubular	goods,	materials	for	completion	operations	and	well	equipment	held	for	use	in	the	exploration	for,	and	development and	production	of,	crude	oil	and	natural	gas	reserves,	are	carried	at	the	lower	of	cost	and	net	realizable	value	with	adjustments	made,	as	appropriate,	to	recognize	any reductions	in	value.

Revenue	Recognition.	Effective	January	1,	2018,	EOG	adopted	the	provisions	of	Accounting	Standards	Update	(ASU)	2014-09,	"Revenue	From	Contracts	With Customers"	 (ASU	 2014-09).	ASU	2014-09	and	other	related	ASUs	require	entities	 to	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.	EOG	elected	to	adopt	ASU 2014-09	using	the	modified	retrospective	approach,	which	required	EOG	to	recognize	in	retained	earnings	the	cumulative	effect	at	the	date	of	adoption	for	all	existing contracts	with	customers	which	were	not	substantially	complete	as	of	January	1,	2018.	There	was	no	impact	to	retained	earnings	upon	adoption	of	ASU	2014-09.

EOG	presents	disaggregated	revenues	by	type	of	commodity	within	its	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss)	and	by geographic	areas	defined	as	operating	segments.	See	Note	11.

In	connection	with	the	adoption	of	ASU	2014-09,	EOG	presents	natural	gas	processing	fees	relating	to	certain	processing	and	marketing	agreements	within	its United	 States	 segment	 as	 Gathering	 and	 Processing	 Costs,	 instead	 of	 as	 a	 deduction	 to	 Revenues	 within	 its	 Consolidated	 Statements	 of	 Income	 (Loss)	 and Comprehensive	Income	(Loss).	There	was	no	impact	to	operating	income,	net	income	or	cash	flows	resulting	from	changes	to	the	presentation	of	natural	gas	processing fees.	The	impacts	of	the	adoption	of	ASU	2014-09	for	the	year	ended	December	31,	2018,	were	as	follows	(in	thousands):

|  | As	Reported | Amounts	Without<br>Adoption	of	ASU	2014-09 | Effect	of	Change |
| :--- | :--- | :--- | :--- |
| Operating\tRevenues\tand\tOther |  |  |  |
| Crude\tOil\tand\tCondensate | $9,517,440 | $9,517,440 | $— |
| Natural\tGas\tLiquids | 1,127,510 | 1,121,237 | 6,273 |
| Natural\tGas | 1,301,537 | 1,104,095 | 197,442 |
| Gathering,\tProcessing\tand\tMarketing | 5,230,355 | 5,211,136 | 19,219 |
| Total\tOperating\tRevenues\tand\tOther | 17,275,399 | 17,052,465 | 222,934 |
| Operating\tExpenses |  |  |  |
| Gathering\tand\tProcessing\tCosts | 436,973 | 233,258 | 203,715 |
| Marketing\tCosts | 5,203,243 | 5,184,024 | 19,219 |
| Total\tOperating\tExpenses | 12,806,053 | 12,583,119 | 222,934 |
| Operating\tIncome | 4,469,346 | 4,469,346 | — |

Revenues	are	recognized	for	the	sale	of	crude	oil	and	condensate,	natural	gas	liquids	(NGLs)	and	natural	gas	at	the	point	control	of	the	product	is	transferred	to the	customer,	typically	when	production	is	delivered	and	title	or	risk	of	loss	transfers	to	the	customer.	Arrangements	for	such	sales	are	evidenced	by	signed	contracts with	prices	typically	based	on	stated	market	indices,	with	certain	adjustments	for	product	quality	and	geographic	location.	As	EOG	typically	invoices	customers	shortly after	performance	obligations	have	been	fulfilled,	contract	assets	and	contract	liabilities	are	not	recognized.	The	balances	of	accounts	receivable	from	contracts	with customers	on	January	1,	2018	and	December	31,	2018,	were	$1,343	million	 and	$1,460	million,	respectively,	and	are	included	in	Accounts	Receivable,	Net	on	the Consolidated	Balance	Sheets.	Losses	incurred	on	receivables	from	contracts	with	customers	are	infrequent	and	have	been	immaterial.

Crude	Oil	and	Condensate.	EOG	sells	its	crude	oil	and	condensate	production	at	the	wellhead	or	further	downstream	at	a	contractually-specified	delivery	point. Revenue	is	recognized	when	control	transfers	to	the	customer	based	on	contract	terms	which	reflect	prevailing	market	prices.	Any	costs	incurred	prior	to	the	transfer	of control,	such	as	gathering	and	transportation,	are	recognized	as	Operating	Expenses.

Natural	Gas	Liquids.	EOG	delivers	certain	of	its	natural	gas	production	to	either	EOG-owned	processing	facilities	or	third-party	processing	facilities,	where extraction	of	NGLs	occurs.	For	EOG-owned	facilities,	revenue	is	recognized	after	processing	upon	transfer	of	NGLs	to	a	customer.	For	third-party	facilities,	extracted NGLs	are	sold	to	the	owner	of	the	processing	facility	at	the	tailgate,	or	EOG	takes	possession	and	sells	the	extracted	NGLs	at	the	tailgate	or	exercises	its	option	to	sell further	downstream	to	various	customers.	Under	typical	arrangements	for	third-party	facilities,	revenue	is	recognized	after	processing	upon	the	transfer	of	control	of	the NGLs,	either	at	the	tailgate	of	the	processing	plant	or	further	downstream.	EOG	recognizes	revenues	based	on	contract	terms	which	reflect	prevailing	market	prices,	with processing	fees	recognized	as	Gathering	and	Processing	Costs.

Natural	Gas.	EOG	sells	its	natural	gas	production	either	at	the	wellhead	or	further	downstream	at	a	contractually-specified	delivery	point.	In	connection	with the	extraction	of	NGLs,	EOG	sells	residue	gas	under	separate	agreements.	Typically,	EOG	takes	possession	of	the	natural	gas	at	the	tailgate	of	the	processing	facility and	sells	it	at	the	tailgate	or	further	downstream.	In	each	case,	EOG	recognizes	revenues	when	control	transfers	to	the	customer,	based	on	contract	terms	which	reflect prevailing	market	prices.

Gathering,	Processing	and	Marketing.	Gathering,	processing	and	marketing	revenues	represent	sales	of	third-party	crude	oil	and	condensate,	NGLs	and	natural gas,	as	well	as	fees	associated	with	gathering	and	processing	third-party	natural	gas	and	revenues	from	sales	of	EOG-owned	sand.	EOG	evaluates	whether	it	is	the principal	or	agent	under	these	transactions.	As	control	of	the	underlying	commodity	is	transferred	to	EOG	prior	to	the	gathering,	processing	and	marketing	activities, EOG	considers	itself	the	principal	of	these	arrangements.	Accordingly,	EOG	recognizes	these	transactions	on	a	gross	basis.	Purchases	of	third-party	commodities	are recorded	as	Marketing	Costs,	with	sales	of	third-party	commodities	and	fees	received	for	gathering	and	processing	recorded	as	Gathering,	Processing	and	Marketing revenues.

Other	Property,	Plant	and	Equipment.		Other	property,	plant	and	equipment	consists	of	gathering	and	processing	assets,	compressors,	buildings	and	leasehold improvements,	crude-by-rail	assets,	sand	mine	and	sand	processing	assets,	computer	hardware	and	software,	vehicles,	and	furniture	and	fixtures.		Other	property,	plant and	equipment	is	generally	depreciated	on	a	straight-line	basis	over	the	estimated	useful	lives	of	the	property,	plant	and	equipment,	which	range	from	3	years	to	45 years.

Capitalized	Interest	Costs.		Interest	costs	have	been	capitalized	as	a	part	of	the	historical	cost	of	unproved	oil	and	gas	properties.		The	amount	capitalized	is	an allocation	of	the	interest	cost	incurred	during	the	reporting	period.		Capitalized	interest	is	computed	only	during	the	exploration	and	development	phases	and	ceases	once production	begins.		The	interest	rate	used	for	capitalization	purposes	is	based	on	the	interest	rates	on	EOG's	outstanding	borrowings.	The	capitalization	of	interest	is excluded	on	significant	acquisitions	of	unproved	oil	and	gas	properties	financed	through	non-interest-bearing	instruments,	such	as	the	issuance	of	shares	of	Common Stock,	or	through	non-cash	property	exchanges.

Accounting	for	Risk	Management	Activities.		Derivative	instruments	are	recorded	on	the	balance	sheet	as	either	an	asset	or	liability	measured	at	fair	value,	and changes	in	the	derivative's	fair	value	are	recognized	currently	in	earnings	unless	specific	hedge	accounting	criteria	are	met.	 	During	the	three-year	period	ended December	31,	2018,	EOG	elected	not	to	designate	any	of	its	financial	commodity	derivative	instruments	as	accounting	hedges	and,	accordingly,	changes	in	the	fair	value of	these	outstanding	derivative	instruments	are	recognized	as	gains	or	losses	in	the	period	of	change.		The	gains	or	losses	are	recorded	as	Gains	(Losses)	on	Mark-to- Market	Commodity	Derivative	Contracts	on	the	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss).		The	related	cash	flow	impact	of	settled contracts	is	reflected	as	cash	flows	from	operating	activities.		EOG	employs	net	presentation	of	derivative	assets	and	liabilities	for	financial	reporting	purposes	when such	assets	and	liabilities	are	with	the	same	counterparty	and	subject	to	a	master	netting	arrangement.		See	Note	12.

Income	Taxes.		Income	taxes	are	accounted	for	using	the	asset	and	liability	approach.		Under	this	approach,	deferred	tax	assets	and	liabilities	are	recognized based	on	anticipated	future	tax	consequences	attributable	to	differences	between	financial	statement	carrying	amounts	of	assets	and	liabilities	and	their	respective	tax basis.		EOG	assesses	the	realizability	of	deferred	tax	assets	and	recognizes	valuation	allowances	as	appropriate.

In	March	2018,	the	FASB	issued	ASU	2018-05,	"Income	Taxes	(Topic	740)	-	Amendments	to	SEC	Paragraphs	Pursuant	to	SEC	Staff	Accounting	Bulletin	No. 118"	(ASU	2018-05).	In	December	2017,	the	United	States	(U.S.)	enacted	the	Tax	Cuts	and	Jobs	Act	(TCJA),	which	made	significant	changes	to	U.S.	federal	income tax	law.	Shortly	after	enactment	of	the	TCJA,	the	United	States	Securities	and	Exchange	Commission	staff	issued	Staff	Accounting	Bulletin	No.	118	(SAB	118),	which provides	guidance	on	accounting	for	the	impact	of	the	TCJA.	ASU	2018-05	codified	various	paragraphs	of	SAB	118	and	was	effective	upon	issuance.	Under	ASU	2018- 05,	an	entity	will	use	a	similar	approach	as	the	measurement	period	provided	in	the	Business	Combinations	Topic	of	the	ASC.	An	entity	will	recognize	those	matters	for which	the	accounting	can	be	completed.	For	matters	that	have	not	been	completed,	the	entity	will	either	(1)	recognize	provisional	amounts	to	the	extent	that	they	are reasonably	able	to	be	estimated	and	adjust	them	over	time	as	more	information	becomes	available	or	(2)	for	any	specific	income	tax	effects	of	the	TCJA	for	which	a reasonable	estimate	cannot	be	determined,	continue	to	apply	the	Income	Taxes	Topic	of	the	ASC	on	the	basis	of	the	provisions	of	the	tax	laws	that	were	in	effect immediately	before	the	TCJA	was	signed	into	law.	EOG	has	prepared	its	Consolidated	Financial	Statements	for	the	year	ended	December	31,	2018	in	accordance	with ASU	2018-05.	As	discussed	in	EOG's	2017	Annual	Report,	provisional	amounts	were	recorded	for	tax	accruals	as	of	December	31,	2017	for	certain	aspects	of	the TCJA.	EOG	has	updated	and	finalized	the	2017	U.S.	federal	and	state	provisional	amounts.	See	Note	6.

Foreign	 Currency	 Translation.		 The	 United	 States	 dollar is	 the	 functional	 currency	 for	 all	 of	 EOG's	 consolidated	 subsidiaries	 except	 for	 its	 Canadian subsidiaries,	for	which	the	functional	currency	is	the	Canadian	dollar,	and	its	United	Kingdom	subsidiary	(which	was	sold	in	the	fourth	quarter	of	2018),	for	which	the functional	currency	was	the	British	pound.		For	subsidiaries	whose	functional	currency	is	deemed	to	be	other	than	the	United	States	dollar,	asset	and	liability	accounts are	translated	at	year-end	exchange	rates	and	revenues	and	expenses	are	translated	at	average	exchange	rates	prevailing	during	the	year.		Translation	adjustments	are included	in	Accumulated	Other	Comprehensive	Loss	on	the	Consolidated	Balance	Sheets.		Any	gains	or	losses	on	transactions	or	monetary	assets	or	liabilities	in currencies	other	than	the	functional	currency	are	included	in	net	income	in	the	current	period.	See	Notes	4	and	17.

Net	Income	(Loss)	Per	Share.		Basic	net	income	(loss)	per	share	is	computed	on	the	basis	of	the	weighted-average	number	of	common	shares	outstanding during	the	period.		Diluted	net	income	(loss)	per	share	is	computed	based	upon	the	weighted-average	number	of	common	shares	outstanding	during	the	period	plus	the assumed	issuance	of	common	shares	for	all	potentially	dilutive	securities.	See	Note	9.

Stock-Based	Compensation.	EOG	measures	the	cost	of	employee	services	received	in	exchange	for	an	award	of	equity	instruments	based	on	the	grant-date	fair value	of	the	award.	See	Note	7.

Recently	Issued	Accounting	Standards.	In	February	2016,	the	FASB	issued	ASU	2016-02,	"Leases	(Topic	842)"	(ASU	2016-02),	which	significantly	changes accounting	for	leases	by	requiring	that	lessees	recognize	a	right-of-use	asset	and	a	related	lease	liability	representing	the	obligation	to	make	lease	payments,	for	certain lease	transactions.	Additional	disclosures	about	an	entity's	lease	transactions	will	also	be	required.	ASU	2016-02	defines	a	lease	as	"a	contract,	or	part	of	a	contract,	that conveys	the	right	to	control	the	use	of	identified	property,	plant	or	equipment	(an	identified	asset)	for	a	period	of	time	in	exchange	for	consideration."	In	January	2018, the	FASB	issued	ASU	2018-01,	"Leases	(Topic	842)	-	Land	Easement	Practical	Expedient	for	Transition	to	Topic	842"	(ASU	2018-01),	which	permits	an	entity	an optional	election	to	not	evaluate	under	ASU	2016-02	those	existing	or	expired	land	easements	that	were	not	previously	accounted	for	as	leases	prior	to	the	adoption	of ASU	2016-02.	Additionally,	in	July	2018,	the	FASB	issued	ASU	2018-11,	"Leases	(Topic	842)	-	Targeted	Improvements"	(ASU	2018-11),	which	permits	an	entity	(i) to	apply	the	provisions	of	ASU	2016-02	at	the	adoption	date	instead	of	the	earliest	period	presented	in	the	financial	statements,	and,	as	a	lessor,	(ii)	to	account	for	lease and	nonlease	components	as	a	single	component	as	the	nonlease	components	would	otherwise	be	accounted	for	under	the	provisions	of	ASU	2014-09.	ASU	2016-02	and other	related	ASUs	are	effective	for	interim	and	annual	periods	beginning	after	December	31,	2018,	and	early	application	is	permitted.	Based	on	the	provisions	of	ASU 2018-11	and	other	related	ASUs,	lessees	and	lessors	may	recognize	and	measure	leases	at	the	beginning	of	the	earliest	period	presented	in	the	financial	statements, defined	as	the	effective	date,	using	a	modified	retrospective	approach,	or	at	the	adoption	date	by	recognizing	a	cumulative-effect	adjustment	to	the	opening	balance	of retained	earnings.

EOG	is	continuing	to	progress	towards	the	adoption	of	ASU	2016-02	by	implementing	its	project	plan,	including	a	lease	accounting	software	solution.	EOG	has assessed	the	scope	of	its	current	contractual	arrangements,	reviewed	its	existing	contracts	and	is	continuing	to	evaluate	certain	operational	and	corporate	policies	and processes	in	light	of	these	findings.	EOG	enters	into	contracts	for	drilling	services,	fracturing	services,	compression,	real	estate	and	other	contracts	which	contain equipment	and	other	assets	used	in	its	exploration,	development	and	production	activities	and	corporate	functions.	Certain	of	these	contracts	will	require	recognition	of	a right-of-use	asset	and	related	lease	liability	on	the	Consolidated	Balance	Sheet,	while	others	will	require	disclosure	within	the	Notes	to	the	Consolidated	Financial Statements.

The	impact	upon	adoption	of	ASU	2016-02	and	other	related	ASUs	is	not	quantifiable	due	to	the	pending	determination	by	EOG	of	certain	accounting	policies, including	the	separation	of	lease	and	non-lease	components	for	certain	classes	of	underlying	assets,	among	others.	The	adoption	of	ASU	2016-02	and	other	related	ASUs will	 significantly	 increase	 assets	 and	 liabilities	 related	 to	 operating	 leases	 on	 the	 Consolidated	 Balance	 Sheets.	Non-cancelable	 operating	 leases,	 which	 will	 be considered	for	recognition	or	disclosure	upon	adoption	of	ASU	2016-02	and	other	related	ASUs,	totaled	$2.0	billion	on	an	undiscounted	basis	at	December	31,	2018, and	are	included	within	total	minimum	commitments	in	Note	8.

EOG	will	elect	the	practical	expedient	under	ASU	2018-11	and	apply	the	provisions	of	ASU	2016-02	on	the	adoption	date,	January	1,	2019.	Additionally,	EOG will	elect	the	package	of	practical	expedients	within	ASU	2016-02	that	allows	an	entity	to	not	reassess	prior	to	the	effective	date	(i)	whether	any	expired	or	existing contracts	are	or	contain	leases,	(ii)	the	lease	classification	for	any	expired	or	existing	leases,	or	(iii)	initial	direct	costs	for	any	existing	leases,	but	will	not	elect	the practical	expedient	of	hindsight	when	determining	the	lease	term	of	existing	contracts	at	the	effective	date.	EOG	also	will	elect	the	practical	expedient	under	ASU	2018- 01	and	not	evaluate	existing	or	expired	land	easements	not	previously	accounted	for	as	leases	prior	to	the	effective	date.

# 2.		Long-Term	Debt

Long-Term	Debt	at	December	31,	2018	and	2017	consisted	of	the	following	(in	thousands):

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| 6.875%\tSenior\tNotes\tdue\t2018 | $— | $350,000 |
| 5.625%\tSenior\tNotes\tdue\t2019 | 900,000 | 900,000 |
| 4.40%\tSenior\tNotes\tdue\t2020 | 500,000 | 500,000 |
| 2.45%\tSenior\tNotes\tdue\t2020 | 500,000 | 500,000 |
| 4.100%\tSenior\tNotes\tdue\t2021 | 750,000 | 750,000 |
| 2.625%\tSenior\tNotes\tdue\t2023 | 1,250,000 | 1,250,000 |
| 3.15%\tSenior\tNotes\tdue\t2025 | 500,000 | 500,000 |
| 4.15%\tSenior\tNotes\tdue\t2026 | 750,000 | 750,000 |
| 6.65%\tSenior\tNotes\tdue\t2028 | 140,000 | 140,000 |
| 3.90%\tSenior\tNotes\tdue\t2035 | 500,000 | 500,000 |
| 5.10%\tSenior\tNotes\tdue\t2036 | 250,000 | 250,000 |
| Long-Term\tDebt | 6,040,000 | 6,390,000 |
| Capital\tLease\tObligation | 71,571 | 32,155 |
| Less:\tCurrent\tPortion\tof\tLong-Term\tDebt | 913,093 | 356,235 |
| Unamortized\tDebt\tDiscount | 24,640 | 30,564 |
| Debt\tIssuance\tCosts | 3,669 | 4,520 |
| Total\tLong-Term\tDebt | $5,170,169 | $6,030,836 |

At	December	31,	2018,	the	aggregate	annual	maturities	of	long-term	debt	(excluding	capital	lease	obligations)	were	$900	million	in	2019,	$1	billion	in	2020, $750	million	in	2021,	zero	in	2022	and	$1.25	billion	in	2023.		At	December	31,	2018	and	2017,	EOG	had	no	outstanding	short-term	borrowings	under	its	commercial paper	program	and	no	outstanding	borrowings	under	uncommitted	credit	facilities.

During	2018	 and	2017,	EOG	utilized	commercial	paper	bearing	market	 interest	rates,	for	various	corporate	financing	purposes.	The	average	borrowings outstanding	under	the	commercial	paper	program	were	$8	million	and	$84	million	during	the	years	ended	December	31,	2018	and	2017,	respectively.	The	weighted average	interest	rates	for	commercial	paper	borrowings	were	1.97%	and	1.44%	for	the	years	2018	and	2017,	respectively.

On	September	15,	2017,	EOG	repaid	upon	maturity	the	$600	million	aggregate	principal	amount	of	its	5.875%	Senior	Notes	due	2017.

EOG	 currently	 has	 a	$2.0	billion	 senior	 unsecured	 Revolving	 Credit	Agreement	 (Agreement)	 with	 domestic	 and	 foreign	 lenders.	The	Agreement	 has	 a scheduled	maturity	date	of	July	21,	2020,	and	includes	an	option	for	EOG	to	extend,	on	up	to	two	occasions,	the	term	for	successive	one-year	periods	subject	to	certain terms	and	conditions.	Advances	under	the	Agreement	will	accrue	interest	based,	at	EOG's	option,	on	either	the	London	InterBank	Offered	Rate	plus	an	applicable margin	(Eurodollar	rate)	or	the	base	rate	(as	defined	in	the	Agreement)	plus	an	applicable	margin.	The	Agreement	contains	representations,	warranties,	covenants	and events	of	default	that	are	customary	for	investment-grade,	senior	unsecured	commercial	bank	credit	agreements,	including	a	financial	covenant	for	the	maintenance	of	a debt-to-total	capitalization	ratio	of	no	greater	than	65%.	At	December	31,	2018,	EOG	was	in	compliance	with	this	financial	covenant.	At	December	31,	2018	and	2017, there	were	no	borrowings	or	letters	of	credit	outstanding	under	the	Agreement.	The	Eurodollar	rate	and	applicable	base	rate,	had	there	been	any	amounts	borrowed	under the	Agreement	at	December	31,	2018,	would	have	been	3.50%	and	5.50%,	respectively.

# 3.		Stockholders'	Equity

Common	Stock.		In	September	2001,	EOG's	Board	of	Directors	(Board)	authorized	the	purchase	of	an	aggregate	maximum	of	10	million	shares	of	Common Stock	 that	superseded	all	 previous	 authorizations.	 	At	December	31,	2018,	6,386,200	shares	remained	available	for	purchase	under	 this	authorization.	 	EOG	 last purchased	shares	of	its	Common	Stock	under	this	authorization	in	March	2003.		In	addition,	shares	of	Common	Stock	are	from	time	to	time	withheld	by,	or	returned	to, EOG	in	satisfaction	of	tax	withholding	obligations	arising	upon	the	exercise	of	employee	stock	options	or	stock-settled	stock	appreciation	rights	(SARs),	the	vesting	of restricted	stock,	restricted	stock	unit,	performance	stock	or	performance	unit	grants	or	in	payment	of	the	exercise	price	of	employee	stock	options.		Such	shares	withheld or	returned	do	not	count	against	the	Board	authorization	discussed	above.		Shares	purchased,	withheld	and	returned	are	held	in	treasury	for,	among	other	purposes, fulfilling	any	obligations	arising	under	EOG's	stock-based	compensation	plans	and	any	other	approved	transactions	or	activities	for	which	such	shares	of	Common	Stock may	be	required.

On	August	2,	2018,	EOG's	Board	of	Directors	increased	the	quarterly	cash	dividend	on	the	common	stock	by	19%	from	the	previous	$0.1850	per	share	to	$0.22 per	share,	effective	beginning	with	the	dividend	paid	on	October	31,	2018,	to	stockholders	of	record	as	of	October	17,	2018.	On	February	27,	2018,	EOG's	Board increased	the	quarterly	cash	dividend	on	the	common	stock	by	10%	from	the	previous	$0.1675	per	share	to	$0.1850	per	share,	effective	beginning	with	the	dividend	paid on	April	30,	2018,	to	stockholders	of	record	as	of	April	16,	2018.	EOG	declared	and	paid	quarterly	cash	dividends	of	$0.1675	per	share	in	2017	and	2016.

On	February	15,	2017,	the	Board	approved	an	amendment	to	EOG's	Restated	Certificate	of	Incorporation	to	increase	the	number	of	EOG's	authorized	shares	of common	 stock	 from	640	million	 to	1,280	million.	EOG's	stockholders	approved	 the	 increase	at	 the	Annual	Meeting	of	Stockholders	on	April	27,	2017,	and	 the amendment	was	filed	with	the	Delaware	Secretary	of	State	on	April	28,	2017.

On	October	4,	2016,	EOG	issued	approximately	25	million	shares	of	EOG	common	stock	in	connection	with	the	Yates	transaction.	See	Note	17.

The	following	summarizes	Common	Stock	activity	for	each	of	the	years	ended	December	31,	2016,	2017	and	2018	(in	thousands):

|  | Issued | Treasury | Outstanding |
| :--- | :--- | :--- | :--- |
| Balance\tat\tDecember\t31,\t2015 | 550,151 | (292) | 549,859 |
| Common\tStock\tIssued | 25,204 | — | 25,204 |
| Common\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | 1,500 | — | 1,500 |
| Treasury\tStock\tPurchased\t(1) | — | (922) | (922) |
| Common\tStock\tIssued\tUnder\tEmployee\tStock\tPurchase\tPlan | 95 | 117 | 212 |
| Treasury\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | — | 847 | 847 |
| Balance\tat\tDecember\t31,\t2016 | 576,950 | (250) | 576,700 |
| Common\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | 1,878 | — | 1,878 |
| Treasury\tStock\tPurchased\t(1) | — | (686) | (686) |
| Common\tStock\tIssued\tUnder\tEmployee\tStock\tPurchase\tPlan | — | 180 | 180 |
| Treasury\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | — | 405 | 405 |
| Balance\tat\tDecember\t31,\t2017 | 578,828 | (351) | 578,477 |
| Common\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | 1,580 | — | 1,580 |
| Treasury\tStock\tPurchased\t(1) | — | (539) | (539) |
| Common\tStock\tIssued\tUnder\tEmployee\tStock\tPurchase\tPlan | — | 180 | 180 |
| Treasury\tStock\tIssued\tUnder\tStock-Based\tCompensation\tPlans | — | 325 | 325 |
| Balance\tat\tDecember\t31,\t2018 | 580,408 | (385) | 580,023 |

(1) Represents	shares	that	were	withheld	by	or	returned	to	EOG	(i)	in	satisfaction	of	tax	withholding	obligations	that	arose	upon	the	exercise	of	employee	stock	options	or	SARs	or the	vesting	of	restricted	stock,	restricted	stock	unit,	performance	stock	or	performance	unit	grants	or	(ii)	in	payment	of	the	exercise	price	of	employee	stock	options.

Preferred	Stock.		EOG	currently	has	one	authorized	series	of	preferred	stock.		As	of	December	31,	2018,	there	were	no	shares	of	preferred	stock	outstanding.

# 4.		Accumulated	Other	Comprehensive	Income	(Loss)

Accumulated	 other	 comprehensive	 income	 (loss)	 includes	 certain	 transactions	 that	 have	 generally	 been	 reported	 in	 the	 Consolidated	 Statements	 of Stockholders'	Equity.	The	components	of	Accumulated	Other	Comprehensive	Income	(Loss)	at	December	31,	2018	and	2017	consisted	of	the	following	(in	thousands):

|  | Foreign	Currency<br>Translation	Adjustment | Other | Total |
| :--- | :--- | :--- | :--- |
| December\t31,\t2016 | $(19,441) | $431 | $(19,010) |
| Other\tcomprehensive\tincome\t(loss)\tbefore\treclassifications | 2,799 | (3,728) | (929) |
| Tax\teffects | — | 642 | 642 |
| Other\tcomprehensive\tincome\t(loss) | 2,799 | (3,086) | (287) |
| December\t31,\t2017 | (16,642) | (2,655) | (19,297) |
| Other\tcomprehensive\tincome\tbefore\treclassifications | 2,451 | 1,131 | 3,582 |
| Amounts\treclassified\tout\tof\tother\tcomprehensive\tincome\t(loss)\t(1) | 14,365 | — | 14,365 |
| Tax\teffects | — | (8) | (8) |
| Other\tcomprehensive\tincome | 16,816 | 1,123 | 17,939 |
| December\t31,\t2018 | $174 | $(1,532) | $(1,358) |

(1) Reclassified	to	Net	Income	(Loss)	-	Gains	(Losses)	on	Asset	Dispositions,	Net.	See	Note	17.

No	significant	amount	was	reclassified	out	of	Accumulated	Other	Comprehensive	Income	(Loss)	during	the	year	ended	December	31,	2017.

# 5.		Other	Income	(Expense),	Net

Other	income,	net	for	2018	included	interest	income	($12	million),	a	downward	adjustment	to	deferred	compensation	expense	($6	million)	and	equity	income from	investments	in	ammonia	plants	in	Trinidad	($2	million),	partially	offset	by	net	foreign	currency	transaction	losses	($(7)	million).	Other	income,	net	for	2017 included	net	foreign	currency	transaction	gains	($8	million),	interest	income	($8	million)	and	equity	 income	from	 investments	 in	ammonia	plants	 in	Trinidad	($3 million),	 partially	 offset	 by	 an	 upward	 adjustment	 to	 deferred	 compensation	 expense ($(6)	 million) .	Other	 expense,	 net	 for	 2016	 included	 net	 foreign	 currency transaction	losses	($(41)	million)	and	an	upward	adjustment	to	deferred	compensation	expense	($(11)	million),	partially	offset	by	equity	income	from	investments	in ammonia	plants	in	Trinidad	($4	million).

As	described	in	Note	1,	EOG	finalized	the	accounting	impact	of	the	TCJA	on	its	provisional	income	tax	accruals	during	2018	in	accordance	with	ASU	2018- 05.	Following	is	a	description	of	each	provisional	tax	accrual	and	the	reason	it	was	adjusted.

During	the	third	quarter	of	2018,	EOG	filed	its	consolidated	2017	U.S.	federal	income	tax	return,	along	with	certain	tax	elections,	and	finalized	its	foreign earnings	and	profits	study.	The	deemed	repatriation	tax	decreased	from	the	provisional	amount	of	$179	million	 to	$40	million	mostly	as	a	result	of	reducing	the repatriation	taxable	income	by	net	operating	losses	(NOLs).	EOG	previously	expected	to	pay	the	repatriation	tax	in	installments	over	eight	years	and	preserve	NOLs	for utilization	in	future	years,	as	allowed	by	the	TCJA.	However,	the	Internal	Revenue	Service	(IRS)	stated	in	recent	guidance	that	no	tax	refunds	would	be	issued	until	the entire	repatriation	tax	liability	is	satisfied,	regardless	of	the	installment	election.	As	a	result,	EOG	did	not	make	the	installment	election	and	instead	utilized	NOLs	to reduce	the	repatriation	taxable	income.	EOG	has	reviewed	the	tax	consequences	of	the	repatriation	tax	on	its	outside	basis	differences	in	its	investment	in	non-U.S. subsidiaries	and	no	U.S.	federal	deferred	tax	liability	is	currently	required.

EOG	recorded	a	provisional	amount	in	2017	for	its	refundable	alternative	minimum	tax	(AMT)	credits	due	to	the	lack	of	guidance,	at	that	time,	on	whether	any portion	of	these	credits	would	be	sequestered	due	to	a	federal	budgetary	provision.	In	the	first	quarter	of	2018,	the	IRS	affirmed	that	any	refundable	AMT	credits resulting	from	the	TCJA	would	be	subject	to	sequestration.	However,	in	the	fourth	quarter	of	2018,	the	IRS	reversed	their	decision.	Accordingly,	EOG	eliminated	the provisional	sequestration	accrual	and	recognized	a	$42	million	tax	benefit	for	the	year.

The	 remeasurement	 of	 U.S.	 deferred	 tax	 assets	 and	 liabilities	 resulted	 in	 a	 provisional	 net	 tax	 benefit	 of	$2.2	billion	 in	 2017,	 which	 was	 increased	 by approximately	$52	million	in	the	third	quarter	of	2018	due	to	the	utilization	of	the	aforementioned	NOLs	at	the	2017	U.S.	federal	corporate	income	tax	rate	of	35% instead	of	the	future	tax	rate	of	21%.	This	tax	benefit,	along	with	the	sequestration	benefit	and	other	less	significant	tax	reform	adjustments,	lowered	the	2018	full	year effective	tax	rate	approximately	three	percentage	points.

The	principal	components	of	EOG's	total	net	deferred	income	tax	liabilities	at	December	31,	2018	and	2017	were	as	follows	(in	thousands):

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Deferred\tIncome\tTax\tAssets\t(Liabilities) |  |  |
| Foreign\tOil\tand\tGas\tExploration\tand\tDevelopment\tCosts\tDeducted\tfor\tTax\tUnder\tBook\tDepreciation,\tDepletion\tand\nAmortization | $4,359 | $(40,851) |
| Foreign\tNet\tOperating\tLoss | 55,175 | 423,258 |
| Foreign\tValuation\tAllowances | (58,932) | (365,379) |
| Foreign\tOther | 175 | 478 |
| Total\tNet\tDeferred\tIncome\tTax\tAssets | $777 | $17,506 |
| Deferred\tIncome\tTax\t(Assets)\tLiabilities |  |  |
| Oil\tand\tGas\tExploration\tand\tDevelopment\tCosts\tDeducted\tfor\tTax\tOver\tBook\tDepreciation,\tDepletion\tand\nAmortization | $4,819,222 | $3,894,739 |
| Commodity\tHedging\tContracts | 4,883 | (12,008) |
| Deferred\tCompensation\tPlans | (39,086) | (35,832) |
| Accrued\tExpenses\tand\tLiabilities | (19,097) | 12,094 |
| Net\tOperating\tLoss\t-\tFederal | — | (69,262) |
| Non-Producing\tLeasehold\tCosts | (88,594) | (47,981) |
| Seismic\tCosts\tCapitalized\tfor\tTax | (164,932) | (109,423) |
| Equity\tAwards | (93,977) | (92,696) |
| Capitalized\tInterest | 17,821 | 51,345 |
| Alternative\tMinimum\tTax\tCredit\tCarryforward | — | (77,114) |
| Undistributed\tForeign\tEarnings | 22,945 | 19,684 |
| Other | (45,787) | (15,332) |
| Total\tNet\tDeferred\tIncome\tTax\tLiabilities | $4,413,398 | $3,518,214 |
| Total\tNet\tDeferred\tIncome\tTax\tLiabilities | $4,412,621 | $3,500,708 |

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| United\tStates | $4,084,156 | $621,610 | $(1,520,573) |
| Foreign | 156,842 | 39,572 | (36,932) |
| Total | $4,240,998 | $661,182 | $(1,557,505) |

The	principal	components	of	EOG's	Income	Tax	Provision	(Benefit)	for	the	years	indicated	below	were	as	follows	(in	thousands):

|  | 2018 |  | 2017 |  | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Current: |  |  |  |  |  |
| Federal | $(303,853) |  | $33,058 |  | $11,567 |
| State | 17,048 |  | (2,502) |  | (8,369) |
| Foreign | 65,615 |  | 35,323 |  | 51,189 |
| Total | (221,190) |  | 65,879 |  | 54,387 |
| Deferred: |  |  |  |  |  |
| Federal | 862,075 |  | (1,504,288) |  | (532,979) |
| State | 43,293 |  | 26,942 |  | 4,876 |
| Foreign | (11,212) |  | 3,474 |  | 12,897 |
| Total | 894,156 |  | (1,473,872) |  | (515,206) |
| Other\tNon-Current: |  |  |  |  |  |
| Federal | 148,992 | (1) | (513,404) | (2) | — |
| Income\tTax\tProvision\t(Benefit) | $821,958 |  | $(1,921,397) |  | $(460,819) |

(1) Includes	change	in	refundable	AMT	credits	and	the	reversal	of	the	repatriation	tax	accrued	in	2017.	See	previous	discussion	regarding	the	filing	of	EOG's	2017	U.S.	federal income	tax	return	for	details.

(2) Includes	refundable	AMT	credits	net	of	the	repatriation	tax	that	was	expected	to	be	paid	post-2017.

The	differences	between	taxes	computed	at	the	U.S.	federal	statutory	tax	rate	and	EOG's	effective	rate	for	the	years	indicated	below	were	as	follows:

|  | 2018 |  | 2017 |  | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statutory\tFederal\tIncome\tTax\tRate | 21.00\t% |  | 35.00\t% |  | 35.00\t% |
| State\tIncome\tTax,\tNet\tof\tFederal\tBenefit | 1.12 |  | 3.38 |  | 0.15 |
| Income\tTax\tProvision\tRelated\tto\tForeign\tOperations | 0.51 |  | (0.30) |  | (1.23) |
| Income\tTax\tProvision\tRelated\tto\tTrinidad\tOperations | — |  | — |  | (3.71) |
| Income\tTax\tProvision\tRelated\tto\tUnited\tKingdom\tOperations | — |  | 1.78 |  | — |
| Income\tTax\tProvision\tRelated\tto\tCanadian\tOperations | — |  | 2.30 |  | — |
| TCJA | (2.60) | (1) | (328.10) | (2) | — |
| Share-Based\tCompensation\t(3) | (0.47) |  | (4.63) |  | — |
| Other | (0.18) |  | (0.03) |  | (0.62) |
| Effective\tIncome\tTax\tRate | 19.38\t% |  | (290.60)% |  | 29.59\t% |

(1) Includes	impact	of	utilizing	certain	tax	NOLs	((1.2)%),	the	IRS's	reversal	of	its	sequestration	decision	((1.0)%)	and	other	tax	reform	impacts	((0.4)%).

(3) Effective	January	1,	2017,	EOG	adopted	the	provisions	of	ASU	2016-09,	"Improvements	to	Employee	Share-Based	Payment	Accounting"	(ASU	2016-09),	which	provides	that share-based	compensation	tax	benefits	and	deficiencies	are	recognized	in	the	income	tax	provision.

Deferred	tax	assets	are	recorded	for	certain	tax	benefits,	including	tax	NOLs	and	tax	credit	carryforwards,	provided	that	management	assesses	the	utilization	of such	assets	to	be	"more	likely	than	not."	Management	assesses	the	available	positive	and	negative	evidence	to	estimate	if	sufficient	future	taxable	income	will	be generated	to	use	the	existing	deferred	tax	assets.	On	the	basis	of	this	evaluation,	EOG	has	recorded	valuation	allowances	for	the	portion	of	certain	foreign	and	state deferred	tax	assets	that	management	does	not	believe	are	more	likely	than	not	to	be	realized.

The	principal	components	of	EOG's	rollforward	of	valuation	allowances	for	deferred	income	tax	assets	for	the	years	indicated	below	were	as	follows	(in

# thousands):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Beginning\tBalance | $466,421 | $383,221 | $506,127 |
| Increase\t(1) | 23,062 | 67,333 | 37,221 |
| Decrease\t(2) | (26,219) | (13,687) | (12,667) |
| Other\t(3) | (296,122) | 29,554 | (147,460) |
| Ending\tBalance | $167,142 | $466,421 | $383,221 |

(1) Increase	in	valuation	allowance	related	to	the	generation	of	tax	NOLs	and	other	deferred	tax	assets.

(2) Decrease	in	valuation	allowance	associated	with	adjustments	to	certain	deferred	tax	assets	and	their	related	allowance.

(3) Represents	dispositions,	revisions	and/or	foreign	exchange	rate	variances	and	the	effect	of	statutory	income	tax	rate	changes.	The	United	Kingdom	operations	were	sold	in	the fourth	quarter	of	2018.	The	Argentina	operations	were	sold	in	the	third	quarter	of	2016.

As	of	December	31,	2018,	EOG	had	state	income	tax	NOLs	being	carried	forward	of	approximately	$1.8	billion,	which,	if	unused,	expire	between	2019	and 2037.	EOG	also	has	Canadian	NOLs	of	$183	million	which	can	be	carried	forward	20	years.	As	described	above,	these	NOLs	as	well	as	other	less	significant	future	tax benefits,	have	been	evaluated	for	the	likelihood	of	utilization,	and	valuation	allowances	have	been	established	for	the	portion	of	these	deferred	income	tax	assets	that	do not	meet	the	"more	likely	than	not"	threshold.

The	 balance	 of	 unrecognized	 tax	 benefits	 at	 December	 31,	 2018,	 was	$29	 million,	 resulting	 from	 the	 tax	 treatment	 of	 its	 research	 and	 experimental expenditures	related	to	certain	innovations	in	its	horizontal	drilling	and	completion	projects,	of	which	$12	million	may	potentially	have	an	earnings	 impact.	EOG records	interest	and	penalties	related	to	unrecognized	tax	benefits	to	its	income	tax	provision.	Currently	$2	million	of	interest	has	been	recognized	in	the	Consolidated Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss).	EOG	does	not	anticipate	that	the	amount	of	the	unrecognized	tax	benefits	will	change	materially	during the	next	twelve	months.	EOG	and	its	subsidiaries	file	income	tax	returns	and	are	subject	to	tax	audits	in	the	U.S.	and	various	state,	local	and	foreign	jurisdictions.	EOG's earliest	open	tax	years	in	its	principal	jurisdictions	are	as	follows:	U.S.	federal	(2016),	Canada	(2014),	Trinidad	(2013)	and	China	(2008).

EOG's	foreign	subsidiaries'	undistributed	earnings	are	not	considered	to	be	permanently	reinvested	outside	of	the	U.S.	Accordingly,	EOG	may	be	required	to accrue	certain	U.S.	federal,	state,	and	foreign	deferred	income	taxes	on	these	undistributed	earnings	as	well	as	on	any	other	outside	basis	differences	related	to	its investments	in	these	subsidiaries.	As	of	December	31,	2018,	EOG	has	cumulatively	recorded	$23	million	of	deferred	foreign	income	taxes	for	withholdings	on	its undistributed	foreign	earnings.	Additionally,	for	tax	years	beginning	in	2018	and	later,	EOG's	foreign	earnings	may	be	subject	to	the	U.S.	federal	"global	intangible	low- taxed	income"	(GILTI)	inclusion.	EOG	records	any	GILTI	tax	as	a	period	expense.

# 7.		Employee	Benefit	Plans

During	2018,	EOG	maintained	various	stock-based	compensation	plans	as	discussed	below.		EOG	recognizes	compensation	expense	on	grants	of	stock	options, SARs,	restricted	stock	and	restricted	stock	units,	performance	units	and	grants	made	under	the	EOG	Resources,	Inc.	Employee	Stock	Purchase	Plan	(ESPP).		Stock- based	compensation	expense	is	calculated	based	upon	the	grant	date	estimated	fair	value	of	the	awards,	net	of	forfeitures,	based	upon	EOG's	historical	employee turnover	rate.		Compensation	expense	is	amortized	over	the	shorter	of	the	vesting	period	or	the	period	from	date	of	grant	until	the	date	the	employee	becomes	eligible	to retire	without	company	approval.

Stock-based	compensation	expense	is	included	on	the	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss)	based	upon	the	job functions	of	the	employees	receiving	the	grants.		Compensation	expense	related	to	EOG's	stock-based	compensation	plans	for	the	years	ended	December	31,	2018,	2017 and	2016	was	as	follows	(in	millions):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Lease\tand\tWell | $51 | $41 | $38 |
| Gathering\tand\tProcessing\tCosts | 1 | 1 | 1 |
| Exploration\tCosts | 25 | 23 | 21 |
| General\tand\tAdministrative | 78 | 69 | 68 |
| Total | $155 | $134 | $128 |

The	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(2008	Plan)	provides	for	grants	of	stock	options,	SARs,	restricted stock	and	restricted	stock	units,	performance	stock	and	performance	units,	and	other	stock-based	awards.

Beginning	with	the	grants	made	effective	September	25,	2017,	the	Compensation	Committee	of	the	Board	of	Directors	of	EOG	(Committee)	approved	revised vesting	schedules	for	grants	of	stock	options,	SARs,	restricted	stock	and	restricted	stock	units,	and	performance	units.	These	revised	vesting	schedules	will	apply	to	all future	grants	as	well,	until	revised,	amended	or	otherwise	determined	by	the	Committee.

At	December	31,	2018,	approximately	13.7	million	common	shares	remained	available	for	grant	under	the	2008	Plan.		EOG's	policy	is	to	issue	shares	related	to the	2008	Plan	from	previously	authorized	unissued	shares	or	treasury	shares	to	the	extent	treasury	shares	are	available.

During	2018,	2017	and	2016,	EOG	issued	shares	in	connection	with	stock	option/SAR	exercises,	restricted	stock	and	performance	stock	grants,	restricted	stock unit	and	performance	unit	releases	and	ESPP	purchases.		Effective	January	1,	2017,	with	the	adoption	of	ASU	2016-09,	EOG	began	recognizing	income	tax	associated with	excess	tax	benefits	and	tax	deficiencies	as	discrete	benefits	and	expenses,	respectively,	in	the	income	tax	provision.	Net	excess	tax	benefits	recognized	within	the income	tax	provision	were	$20	million	and	$32	million	for	the	twelve	months	ended	December	31,	2018	and	2017,	respectively.	Prior	to	the	adoption	of	ASU	2016-09, EOG	recognized,	as	an	adjustment	to	Additional	Paid	in	Capital,	federal	income	tax	benefits	of	$29	million	for	2016	related	to	the	exercise	of	stock	options/SARs	and the	release	of	restricted	stock,	restricted	stock	units,	performance	stock	and	performance	units.

Stock	 Options	 and	 Stock-Settled	 Stock	 Appreciation	 Rights	 and	 Employee	 Stock	 Purchase	 Plan.		 Participants in	 EOG's	 stock-based	 compensation	 plans (including	the	2008	Plan)	have	been	or	may	be	granted	options	to	purchase	shares	of	Common	Stock.		In	addition,	participants	in	EOG's	stock	plans	(including	the	2008 Plan)	have	been	or	may	be	granted	SARs,	representing	the	right	to	receive	shares	of	Common	Stock	based	on	the	appreciation	in	the	stock	price	from	the	date	of	grant on	the	number	of	SARs	granted.		Stock	options	and	SARs	are	granted	at	a	price	not	less	than	the	market	price	of	the	Common	Stock	on	the	date	of	grant.		Terms	for stock	options	and	SARs	granted	have	generally	not	exceeded	a	maximum	term	of	seven	years.		EOG's	ESPP	allows	eligible	employees	to	semi-annually	purchase, through	payroll	deductions,	shares	of	Common	Stock	at	85	percent	of	the	fair	market	value	at	specified	dates.		Contributions	to	the	ESPP	are	limited	to	10	percent	of	the employee's	pay	(subject	to	certain	ESPP	limits)	during	each	of	the	two	six-month	offering	periods	each	year.

The	fair	value	of	stock	option	grants	and	SAR	grants	is	estimated	using	the	Hull-White	II	binomial	option	pricing	model.		The	fair	value	of	ESPP	grants	is estimated	using	the	Black-Scholes-Merton	model.		Stock-based	compensation	expense	related	to	stock	option,	SAR	and	ESPP	grants	totaled	$60	million,	$56	million and	$57	million	for	the	years	ended	December	31,	2018,	2017	and	2016,	respectively.

Weighted	average	fair	values	and	valuation	assumptions	used	to	value	stock	option,	SAR	and	ESPP	grants	for	the	years	ended	December	31,	2018,	2017	and 2016	were	as	follows:

|  | 2018 | Stock	Options/SARs<br>2017 | 2016 | 2018 | ESPP<br>2017 | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Weighted\tAverage\tFair\tValue\tof\tGrants | $33.46 | $23.95 | $25.78 | $25.75 | $22.20 | $19.21 |
| Expected\tVolatility | 28.23% | 28.28% | 31.54% | 24.59% | 27.12% | 36.55% |
| Risk-Free\tInterest\tRate | 2.68% | 1.52% | 0.78% | 1.89% | 0.88% | 0.44% |
| Dividend\tYield | 0.72% | 0.75% | 0.76% | 0.64% | 0.71% | 0.82% |
| Expected\tLife | 5.0\tyears | 5.1\tyears | 5.4\tyears | 0.5\tyears | 0.5\tyears | 0.5\tyears |

Expected	volatility	is	based	on	an	equal	weighting	of	historical	volatility	and	implied	volatility	from	traded	options	in	EOG's	Common	Stock.		The	risk-free interest	rate	is	based	upon	United	States	Treasury	yields	in	effect	at	the	time	of	grant.		The	expected	life	is	based	upon	historical	experience	and	contractual	terms	of stock	option,	SAR	and	ESPP	grants.

The	following	table	sets	forth	the	stock	option	and	SAR	transactions	for	the	years	ended	December	31,	2018,	2017 and	2016	(stock	options	and	SARs	in thousands):

|  | Number<br>of	Stock<br>Options/<br>SARs | Weighted<br>Average<br>Grant<br>Price | Number<br>of	Stock<br>Options/<br>SARs | Weighted<br>Average<br>Grant<br>Price | Number<br>of	Stock<br>Options/<br>SARs | Weighted<br>Average<br>Grant<br>Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Outstanding\tat\tJanuary\t1 | 9,103 | $83.89 | 9,850 | $75.53 | 10,744 | $67.98 |
| Granted | 1,906 | 126.49 | 2,274 | 96.27 | 1,855 | 94.82 |
| Exercised\t(1) | (2,493) | 72.21 | (2,574) | 61.12 | (2,376) | 54.56 |
| Forfeited | (206) | 94.43 | (447) | 93.84 | (373) | 87.38 |
| Outstanding\tat\tDecember\t31 | 8,310 | 96.90 | 9,103 | 83.89 | 9,850 | 75.53 |
| Stock\tOptions/SARs\tExercisable\tat\tDecember |  |  |  |  |  |  |
| 31 | 3,969 | 85.82 | 4,510 | 75.76 | 5,613 | 66.48 |

(1) The	total	intrinsic	value	of	stock	options/SARs	exercised	during	the	years	2018,	2017	and	2016	was	$118	million,	$95	million	and	$84	million,	respectively.		The	intrinsic	value is	based	upon	the	difference	between	the	market	price	of	the	Common	Stock	on	the	date	of	exercise	and	the	grant	price	of	the	stock	options/SARs.

At	December	31,	2018,	 there	were	8.0	million	stock	options/SARs	vested	or	expected	to	vest	with	a	weighted	average	grant	price	of	$96.43	per	share,	an intrinsic	value	of	$34.6	million	and	a	weighted	average	remaining	contractual	life	of	4.4	years.

The	following	table	summarizes	certain	information	for	the	stock	options	and	SARs	outstanding	and	exercisable	at	December	31,	2018	(stock	options	and SARs	in	thousands):

|  | Stock	Options/SARs	Outstanding | Stock	Options/SARs	Outstanding |  |  |  | Stock	Options/SARs	Exercisable | Stock	Options/SARs	Exercisable |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Range\tof\nGrant\nPrices | Stock\nOptions/\nSARs | Weighted\nAverage\nRemaining\nLife\n(Years) | Weighted\nAverage\nGrant\nPrice | Aggregate\nIntrinsic\nValue(1) | Stock\nOptions/\nSARs | Weighted\nAverage\nRemaining\nLife\n(Years) | Weighted\nAverage\nGrant\nPrice | Aggregate\nIntrinsic\nValue\t(1) |
| $\t50.00\tto\t$\t\t82.99 | 1,528 | 3 | $65.46 |  | 1,183 | 2 | $64.27 |  |
| \t83.00\tto\t\t\t\t95.99 | 2,046 | 4 | 91.48 |  | 1,290 | 3 | 89.50 |  |
| \t\t\t96.00\tto\t\t\t\t\t96.99 | 1,961 | 6 | 96.29 |  | 618 | 5 | 96.29 |  |
| \t\t\t97.00\tto\t\t\t125.99 | 957 | 3 | 102.77 |  | 872 | 3 | 101.91 |  |
| \t126.00\tto\t\t\t129.99 | 1,818 | 7 | 127.01 |  | 6 | 1 | 127.00 |  |
|  | 8,310 | 5 | 96.90 | $35,083 | 3,969 | 3 | 85.82 | $28,993 |

(1) Based	upon	the	difference	between	the	closing	market	price	of	the	Common	Stock	on	the	last	trading	day	of	the	year	and	the	grant	price	of	in-the-money	stock	options	and	SARs.

At	December	31,	2018,	unrecognized	compensation	expense	related	to	non-vested	stock	option	and	SAR	grants	totaled	$106	million. 	This	unrecognized expense	will	be	amortized	on	a	straight-line	basis	over	a	weighted	average	period	of	1.7	years.

At	the	2018	Annual	Meeting	of	Stockholders,	EOG	stockholders	approved	an	amendment	and	restatement	of	the	ESPP	to	(among	other	changes)	increase	the number	of	shares	available	for	grant.	At	December	31,	2018,	approximately	2.5	million	shares	of	Common	Stock	remained	available	for	grant	under	the	ESPP.		The following	table	summarizes	ESPP	activity	for	the	years	ended	December	31,	2018,	2017	and	2016	(in	thousands,	except	number	of	participants):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Approximate\tNumber\tof\tParticipants | 1,934 | 1,870 | 1,746 |
| Shares\tPurchased | 180 | 180 | 212 |
| Aggregate\tPurchase\tPrice | $14,887 | $13,997 | $13,787 |

Restricted	Stock	and	Restricted	Stock	Units.		Employees	may	be	granted	restricted	(non-vested)	stock	and/or	restricted	stock	units	without	cost	to	them.		Upon vesting	of	restricted	stock,	shares	of	Common	Stock	are	released	to	the	employee.		Upon	vesting,	restricted	stock	units	are	converted	into	shares	of	Common	Stock	and released	to	the	employee.		Stock-based	compensation	expense	related	to	restricted	stock	and	restricted	stock	units	totaled	$81	million,	$68	million	and	$60	million	for the	years	ended	December	31,	2018,	2017	and	2016,	respectively.

The	following	table	sets	forth	the	restricted	stock	and	restricted	stock	unit	transactions	for	the	years	ended	December	31,	2018,	2017	and	2016	(shares	and	units in	thousands):

|  | Number	of<br>Shares	and<br>Units | Weighted<br>Average	Grant<br>Date	Fair	Value | Number	of<br>Shares	and<br>Units | Weighted<br>Average	Grant<br>Date	Fair	Value | Number	of<br>Shares	and<br>Units | Weighted<br>Average	Grant<br>Date	Fair	Value |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Outstanding\tat\tJanuary\t1 | 3,905 | $88.57 | 3,962 | $79.63 | 4,908 | $70.35 |
| Granted | 812 | 117.55 | 1,095 | 97.34 | 853 | 88.01 |
| Released\t(1) | (740) | 78.16 | (929) | 61.51 | (1,465) | 53.95 |
| Forfeited | (185) | 92.12 | (223) | 85.45 | (334) | 77.29 |
| Outstanding\tat\tDecember\t31\t(2) | 3,792 | 96.64 | 3,905 | 88.57 | 3,962 | 79.63 |

(1) The	total	intrinsic	value	of	restricted	stock	and	restricted	stock	units	released	during	the	years	ended	December	31,	2018,	2017	and	2016	was	$84	million,	$91	million	and	$124 million,	respectively.	The	intrinsic	value	is	based	upon	the	closing	price	of	EOG's	common	stock	on	the	date	restricted	stock	and	restricted	stock	units	are	released.

(2) The	total	intrinsic	value	of	restricted	stock	and	restricted	stock	units	outstanding	at	December	31,	2018,	2017	and	2016	was	$331	million,	$421	million and	$401	million, respectively.

At	December	31,	2018,	unrecognized	compensation	expense	related	 to	restricted	stock	and	restricted	stock	units totaled	$172	million.	Such	 unrecognized expense	will	be	recognized	on	a	straight-line	basis	over	a	weighted	average	period	of	1.9	years.

Performance	Units	and	Performance	Stock.		EOG	has	granted	performance	units	and/or	performance	stock	(Performance	Awards)	to	its	executive	officers annually	since	2012.	As	more	fully	discussed	in	the	grant	agreements,	the	performance	metric	applicable	to	these	performance-based	grants	is	EOG's	total	shareholder return	over	a	three-year	performance	period	relative	to	the	total	shareholder	return	of	a	designated	group	of	peer	companies	(Performance	Period).	Upon	the	application of	the	performance	multiple	at	the	completion	of	the	Performance	Period,	a	minimum	of	0%	and	a	maximum	of	200%	of	the	Performance	Awards	granted	could	be outstanding.	The	fair	value	of	the	Performance	Awards	is	estimated	using	a	Monte	Carlo	simulation.	Stock-based	compensation	expense	related	to	the	Performance Award	grants	totaled	$14	million,	$10	million	and	$11	million	for	the	years	ended	December	31,	2018,	2017	and	2016,	respectively.

						Weighted	average	fair	values	and	valuation	assumptions	used	to	value	Performance	Awards	during	the	years	ended	December	31,	2018,	2017	and	2016	were	as follows:

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Weighted\tAverage\tFair\tValue\tof\tGrants | $136.74 | $113.81 | $119.10 |
| Expected\tVolatility | 29.92% | 32.19% | 32.48% |
| Risk-Free\tInterest\tRate | 2.85% | 1.60% | 1.15% |

Expected	volatility	is	based	on	the	term-matched	historical	volatility	over	the	simulated	term,	which	is	calculated	as	the	time	between	the	grant	date	and	the	end of	the	Performance	Period.	The	risk-free	interest	rate	is	derived	from	the	Treasury	Constant	Maturities	yield	curve	on	the	grant	date.

The	following	table	sets	forth	the	Performance	Award	transactions	for	the	years	ended	December	31,	2018,	2017	and	2016	(shares	and	units	in	thousands):

|  | Number	of	Units<br>and	Shares |  | Weighted<br>Average	Price<br>per	Grant	Date | Number	of	Units<br>and	Shares | Weighted<br>Average	Price<br>per	Grant	Date | Number	of	Units<br>and	Shares | Weighted<br>Average	Price<br>per	Grant	Date |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Outstanding\tat\tJanuary\t1 | 502 |  | $90.96 | 545 | $80.92 | 405 | $74.93 |
| Granted | 113 |  | 125.73 | 78 | 96.29 | 132 | 100.95 |
| Granted\tfor\tPerformance\tMultiple\t(1) | 72 |  | 101.87 | 119 | 84.43 | 142 | 56.21 |
| Released\t(2) | (148) |  | 84.43 | (240) | 66.69 | (134) | 56.21 |
| Forfeited | — |  | — | — | — | — | — |
| Outstanding\tat\tDecember\t31\t(3) | 539 | (4) | 101.53 | 502 | 90.96 | 545 | 80.92 |

(1) Upon	completion	of	the	Performance	Period	for	the	Performance	Awards	granted	in	2014,	2013	and	2012,	a	performance	multiple	of	200%	was	applied	to	each	of	the	grants resulting	in	additional	grants	of	Performance	Awards	in	February	2018,	2017	and	2016.

(2) The	total	intrinsic	value	of	Performance	Awards	released	during	the	years	ended	December	31,	2018,	2017	and	2016	was	$18	million,	$24	million	and	$10	million,	respectively.

(3) The	total	intrinsic	value	of	Performance	Awards	outstanding	at	December	31,	2018,	2017	and	2016	was	$47	million,	$54	million	and	$55	million,	respectively.

(4) Upon	 the	application	of	 the	relevant	performance	multiple	at	 the	completion	of	each	of	 the	remaining	Performance	Periods,	a	minimum	of	 144	 and	 a	 maximum	 of	934 Performance	Awards	could	be	outstanding.	The	intrinsic	value	is	based	upon	the	closing	price	of	EOG's	common	stock	on	the	date	Performance	Awards	are	released.

At	December	31,	2018,	unrecognized	compensation	expense	related	to	Performance	Awards	totaled	$10	million.	Such	unrecognized	expense	will	be	amortized on	a	straight-line	basis	over	a	weighted	average	period	of	1.7	years.

Upon	completion	of	the	Performance	Period	for	the	Performance	Awards	granted	in	2015,	a	performance	multiple	of	200%	was	applied	to	the	2015	grants resulting	in	an	additional	grant	of	71,805	Performance	Awards	in	February	2019.

Pension	Plans.		EOG	has	a	defined	contribution	pension	plan	in	place	for	most	of	its	employees	in	the	United	States.		EOG's	contributions	to	the	pension	plan are	based	on	various	percentages	of	compensation	and,	in	some	instances,	are	based	upon	the	amount	of	the	employees'	contributions.		EOG's	total	costs	recognized	for the	plan	were	$43	million,	$37	million	and	$34	million	for	2018,	2017	and	2016,	respectively.

In	 addition,	 EOG's	Trinidadian	 subsidiary	 maintains	 a	 contributory	 defined	 benefit	 pension	 plan	 and	 a	 matched	 savings	 plan.	 	 EOG's	 United	 Kingdom subsidiary	maintained	a	pension	plan	which	included	a	non-contributory	defined	contribution	pension	plan	and	a	matched	defined	contribution	savings	plan.		These pension	plans	are	available	to	most	employees	of	the	Trinidadian	subsidiary	and	were	available	to	most	employees	of	the	United	Kingdom	subsidiary.		EOG's	combined contributions	to	these	plans	were	$1	million,	for	each	of	2018,	2017	and	2016,	respectively.	The	United	Kingdom	operations	were	sold	in	the	fourth	quarter	of	2018.

For	the	Trinidadian	defined	benefit	pension	plan,	the	benefit	obligation,	fair	value	of	plan	assets	and	accrued	benefit	cost	totaled	$11	million,	$9	million	and $0.2	million,	respectively,	at	December	31,	2018,	and	$10	million,	$8	million	and	$0.2	million,	respectively,	at	December	31,	2017.

Postretirement	Health	Care.		EOG	has	postretirement	medical	and	dental	benefits	in	place	for	eligible	United	States	and	Trinidad	employees	and	their	eligible dependents,	the	costs	of	which	are	not	material.

# 8.		Commitments	and	Contingencies

Letters	of	Credit	and	Guarantees.		At	December	31,	2018	and	2017,	respectively,	EOG	had	standby	letters	of	credit	and	guarantees	outstanding	totaling	$294 million	 and	$174	million,	primarily	representing	guarantees	of	payment	or	performance	obligations	on	behalf	of	subsidiaries.	As	of	February	19,	2019,	EOG	had received	no	demands	for	payment	under	these	guarantees.

Minimum	Commitments. 	At	December	31,	2018,	total	minimum	commitments	from	long-term	non-cancelable	operating	leases,	drilling	rig	commitments, seismic	 purchase	 obligations,	 fracturing	 services	 obligations,	 other	 purchase	 obligations	 and	 transportation	 and	 storage	 service	 commitments,	 based	 on	 current transportation	and	storage	rates	and	the	foreign	currency	exchange	rates	used	to	convert	Canadian	dollars	into	United	States	dollars	at	December	31,	2018,	were	as follows	(in	thousands):

| 2019 | $2,150,978 |
| :--- | :--- |
| 2020 | 1,416,968 |
| 2021 | 996,344 |
| 2022 | 803,240 |
| 2023 | 509,373 |
| 2024\tand\tbeyond | 931,142 |

Included	in	the	table	above	are	leases	for	buildings,	facilities	and	equipment	with	varying	expiration	dates	through	2042.		Rental	expenses	associated	with existing	leases	amounted	to	$233	million,	$200	million,	and	$204	million	for	2018,	2017	and	2016,	respectively.

Contingencies.		There	are	currently	various	suits	and	claims	pending	against	EOG	that	have	arisen	in	the	ordinary	course	of	EOG's	business,	including	contract disputes,	personal	injury	and	property	damage	claims	and	title	disputes.		While	the	ultimate	outcome	and	impact	on	EOG	cannot	be	predicted,	management	believes	that the	resolution	of	these	suits	and	claims	will	not,	individually	or	in	the	aggregate,	have	a	material	adverse	effect	on	EOG's	consolidated	financial	position,	results	of operations	or	cash	flow.		EOG	records	reserves	for	contingencies	when	information	available	indicates	that	a	loss	is	probable	and	the	amount	of	the	loss	can	be reasonably	estimated.

# 9.		Net	Income	(Loss)	Per	Share

The	following	table	sets	forth	the	computation	of	Net	Income	(Loss)	Per	Share	for	the	years	ended	December	31,	2018,	2017	and	2016	(in	thousands,	except per	share	data):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Numerator\tfor\tBasic\tand\tDiluted\tEarnings\tper\tShare\t- |  |  |  |
| Net\tIncome\t(Loss) | $3,419,040 | $2,582,579 | $(1,096,686) |
| Denominator\tfor\tBasic\tEarnings\tper\tShare\t- |  |  |  |
| Weighted\tAverage\tShares | 576,578 | 574,620 | 553,384 |
| Potential\tDilutive\tCommon\tShares\t- |  |  |  |
| Stock\tOptions/SARs | 1,137 | 1,466 | — |
| Restricted\tStock/Units\tand\tPerformance\tUnits/Stock | 2,726 | 2,607 | — |
| Denominator\tfor\tDiluted\tEarnings\tper\tShare\t- |  |  |  |
| Adjusted\tDiluted\tWeighted\tAverage\tShares | 580,441 | 578,693 | 553,384 |
| Net\tIncome\t(Loss)\tPer\tShare |  |  |  |
| Basic | $5.93 | $4.49 | $(1.98) |
| Diluted | $5.89 | $4.46 | $(1.98) |

The	diluted	earnings	per	share	calculation	excludes	stock	options,	SARs,	restricted	stock	and	units	and	performance	units	and	stock	that	were	anti-dilutive. Shares	underlying	the	excluded	stock	options	and	SARs	totaled	0.6	million,	2.6	million	 and	10.3	million	for	 the	years	ended	December	31,	2018,	2017	 and	2016, respectively.	For	the	year	ended	December	31,	2016,	4.5	million	shares	of	restricted	stock	and	restricted	stock	units	and	performance	units	and	performance	stock	were excluded.

# 10.		Supplemental	Cash	Flow	Information

Net	cash	paid	for	interest	and	income	taxes	was	as	follows	for	the	years	ended	December	31,	2018,	2017	and	2016	(in	thousands):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Interest,\tNet\tof\tCapitalized\tInterest | $243,279 | $275,305 | $252,030 |
| Income\tTaxes,\tNet\tof\tRefunds\tReceived | $75,634 | $188,946 | $(39,293) |

Non-cash	investing	activities	for	the	year	ended	December	31,	2018,	included	additions	of	$362	million	to	EOG's	oil	and	gas	properties	as	a	result	of	property exchanges	and	an	addition	of	$49	million	to	EOG's	other	property,	plant	and	equipment	primarily	in	connection	with	a	capital	lease	transaction	in	the	Permian	Basin.

Non-cash	investing	activities	for	the	year	ended	December	31,	2017,	included	non-cash	additions	of	$282	million	to	EOG's	oil	and	gas	properties	as	a	result	of property	exchanges.

Non-cash	investing	activities	for	the	year	ended	December	31,	2016,	included	$3,834	million	in	non-cash	additions	to	EOG's	oil	and	gas	properties	related	to the	Yates	transaction	(see	Note	17).

# 11.		Business	Segment	Information

EOG's	operations	are	all	crude	oil	and	natural	gas	exploration	and	production	related.	The	Segment	Reporting	Topic	of	the	ASC	establishes	standards	for reporting	information	about	operating	segments	in	annual	financial	statements.		Operating	segments	are	defined	as	components	of	an	enterprise	about	which	separate financial	information	is	available	and	evaluated	regularly	by	the	chief	operating	decision	maker,	or	decision-making	group,	in	deciding	how	to	allocate	resources	and	in assessing	performance.		EOG's	chief	operating	decision-making	process	is	informal	and	involves	the	Chairman	of	the	Board	and	Chief	Executive	Officer	and	other	key officers.		This	group	routinely	reviews	and	makes	operating	decisions	related	to	significant	issues	associated	with	each	of	EOG's	major	producing	areas	in	the	United States,	Trinidad,	China	and	the	United	Kingdom	(EOG	sold	its	United	Kingdom	operations	in	the	fourth	quarter	of	2018).		For	segment	reporting	purposes,	the	chief operating	decision	maker	considers	the	major	United	States	producing	areas	to	be	one	operating	segment.

Financial	information	by	reportable	segment	is	presented	below	as	of	and	for	the	years	ended	December	31,	2018,	2017	and	2016	(in	thousands):

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Crude\tOil\tand\tCondensate | $9,390,244 | $17,059 | $110,137 | $9,517,440 |
| Natural\tGas\tLiquids | 1,127,510 | — | — | 1,127,510 |
| Natural\tGas | 970,866 | 285,053 | 45,618 | 1,301,537 |
| Losses\ton\tMark-to-Market\tCommodity\tDerivative\tContracts | (165,640) | — | — | (165,640) |
| Gathering,\tProcessing\tand\tMarketing | 5,227,051 | 3,304 | — | 5,230,355 |
| Gains\ton\tAsset\tDispositions,\tNet | 154,852 | 4,493 | 15,217 | 174,562 |
| Other,\tNet | 89,708 | (49) | (24) | 89,635 |
| Operating\tRevenues\tand\tOther\t(2) | 16,794,591 | 309,860 | 170,948 | 17,275,399 |
| Depreciation,\tDepletion\tand\tAmortization | 3,296,499 | 91,971 | 46,938 | 3,435,408 |
| Operating\tIncome\t(Loss) | 4,334,364 | 147,240 | (12,258) | 4,469,346 |
| Interest\tIncome | 9,326 | 1,612 | 608 | 11,546 |
| Other\tIncome\t(Expense) | 9,580 | 2,436 | (6,858) | 5,158 |
| Net\tInterest\tExpense | 253,352 | — | (8,300) | 245,052 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | 4,099,918 | 151,288 | (10,208) | 4,240,998 |
| Income\tTax\tProvision | 765,986 | 54,272 | 1,700 | 821,958 |
| Additions\tto\tOil\tand\tGas\tProperties,\tExcluding\tDry\tHole\tCosts | 6,155,874 | 1,618 | 37,838 | 6,195,330 |
| Total\tProperty,\tPlant\tand\tEquipment,\tNet | 27,786,086 | 210,183 | 79,250 | 28,075,519 |
| Total\tAssets | 33,178,733 | 629,633 | 126,108 | 33,934,474 |

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2017 |  |  |  |  |
| Crude\tOil\tand\tCondensate | $6,225,711 | $13,572 | $17,113 | $6,256,396 |
| Natural\tGas\tLiquids | 729,545 | — | 16 | 729,561 |
| Natural\tGas | 615,512 | 271,101 | 35,321 | 921,934 |
| Gains\ton\tMark-to-Market\tCommodity\tDerivative\tContracts | 19,828 | — | — | 19,828 |
| Gathering,\tProcessing\tand\tMarketing | 3,298,098 | (11) | — | 3,298,087 |
| Losses\ton\tAsset\tDispositions,\tNet | (98,233) | (8) | (855) | (99,096) |
| Other,\tNet | 81,610 | 59 | (59) | 81,610 |
| Operating\tRevenues\tand\tOther\t(3) | 10,872,071 | 284,713 | 51,536 | 11,208,320 |
| Depreciation,\tDepletion\tand\tAmortization | 3,269,196 | 115,321 | 24,870 | 3,409,387 |
| Operating\tIncome\t(Loss) | 933,571 | 101,010 | (108,179) | 926,402 |
| Interest\tIncome | 3,223 | 2,201 | 2,289 | 7,713 |
| Other\tIncome\t(Expense) | (9,659) | 3,337 | 7,761 | 1,439 |
| Net\tInterest\tExpense | 303,941 | — | (29,569) | 274,372 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | 623,194 | 106,548 | (68,560) | 661,182 |
| Income\tTax\tProvision\t(Benefit) | (1,964,343) | 38,798 | 4,148 | (1,921,397) |
| Additions\tto\tOil\tand\tGas\tProperties,\tExcluding\tDry\tHole\tCosts | 4,067,359 | 145,937 | 14,932 | 4,228,228 |
| Total\tProperty,\tPlant\tand\tEquipment,\tNet | 25,125,427 | 313,357 | 226,253 | 25,665,037 |
| Total\tAssets | 28,312,599 | 974,477 | 546,002 | 29,833,078 |
| 2016 |  |  |  |  |
| Crude\tOil\tand\tCondensate | $4,265,036 | $9,600 | $42,705 | $4,317,341 |
| Natural\tGas\tLiquids | 437,238 | — | 12 | 437,250 |
| Natural\tGas | 475,715 | 234,108 | 32,329 | 742,152 |
| Losses\ton\tMark-to-Market\tCommodity\tDerivative\tContracts | (99,608) | — | — | (99,608) |
| Gathering,\tProcessing\tand\tMarketing | 1,967,390 | (1,131) | — | 1,966,259 |
| Gains\t(Losses)\ton\tAsset\tDispositions,\tNet | 196,043 | (145) | 9,937 | 205,835 |
| Other,\tNet | 81,386 | (8) | 25 | 81,403 |
| Operating\tRevenues\tand\tOther\t(4) | 7,323,200 | 242,424 | 85,008 | 7,650,632 |
| Depreciation,\tDepletion\tand\tAmortization | 3,365,390 | 145,591 | 42,436 | 3,553,417 |
| Operating\tIncome\t(Loss) | (1,192,338) | 46,473 | (79,416) | (1,225,281) |
| Interest\tIncome | 358 | 932 | 1,329 | 2,619 |
| Other\tIncome\t(Expense) | (15,703) | 2,667 | (40,126) | (53,162) |
| Net\tInterest\tExpense | 298,125 | — | (16,444) | 281,681 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | (1,505,808) | 50,072 | (101,769) | (1,557,505) |
| Income\tTax\tProvision\t(Benefit) | (516,180) | 64,281 | (8,920) | (460,819) |
| Additions\tto\tOil\tand\tGas\tProperties,\tExcluding\tDry\tHole\tCosts | 6,223,228 | 75,407 | 30,734 | 6,329,369 |
| Total\tProperty,\tPlant\tand\tEquipment,\tNet | 25,221,517 | 274,850 | 210,711 | 25,707,078 |
| Total\tAssets\t(5) | 27,746,851 | 889,253 | 663,097 | 29,299,201 |

(1) Other	International	primarily	consists	of	EOG's	United	Kingdom,	China,	Canada	and	Argentina	operations.	The	United	Kingdom	operations	were	sold	in	the	fourth	quarter	of 2018.	The	Argentina	operations	were	sold	in	the	third	quarter	of	2016.

(2) EOG	had	sales	activity	with	two	significant	purchasers	in	2018,	one	totaling	$2.6	billion	and	the	other	totaling	$2.3	billion	of	consolidated	Operating	Revenues	and	Other	in	the United	States	segment.

(4) EOG	had	sales	activity	with	three	significant	purchasers	in	2016,	one	totaling	$1.2	billion,	 one totaling	$1.1	billion	and	one totaling	$1.0	billion	of	consolidated	Operating Revenues	and	Other	in	the	United	States	segment.

(5) EOG	made	a	reclassification	of	$160	million	from	deferred	tax	liabilities	to	deferred	tax	assets	for	the	year	ended	December	31,	2016,	for	the	United	States	segment	and	in	total.

# 12.		Risk	Management	Activities

Commodity	Price	Risks.		EOG	engages	in	price	risk	management	activities	from	time	to	time.		These	activities	are	intended	to	manage	EOG's	exposure	to fluctuations	in	commodity	prices	for	crude	oil	and	natural	gas.		EOG	utilizes	financial	commodity	derivative	instruments,	primarily	price	swap,	option,	swaption,	collar and	basis	swap	contracts,	as	a	means	to	manage	this	price	risk.

During	2018,	2017	 and	2016,	EOG	elected	not	 to	designate	any	of	 its	financial	commodity	derivative	contracts	as	accounting	hedges	and,	accordingly, accounted	for	these	financial	commodity	derivative	contracts	using	the	mark-to-market	accounting	method.		Under	this	accounting	method,	changes	in	the	fair	value	of outstanding	financial	instruments	are	recognized	as	gains	or	losses	in	the	period	of	change	and	are	recorded	as	Gains	(Losses)	on	Mark-to-Market	Commodity	Derivative Contracts	on	the	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss).		The	related	cash	flow	impact	is	reflected	in	Cash	Flows	from	Operating Activities.		During	2018,	2017	and	2016,	EOG	recognized	net	gains	(losses)	on	the	mark-to-market	of	financial	commodity	derivative	contracts	of	$(166)	million,	$20 million	 and	$(100)	million,	respectively,	which	included	cash	received	from	(payments	for)	settlements	of	crude	oil	and	natural	gas	derivative	contracts	of	$(259) million,	$7	million	and	$(22)	million,	respectively.

Commodity	Derivative	Contracts.	Prices	received	by	EOG	for	its	crude	oil	production	generally	vary	from	U.S.	New	York	Mercantile	Exchange	(NYMEX) West	Texas	Intermediate	prices	due	to	adjustments	for	delivery	location	(basis)	and	other	factors.	EOG	has	entered	into	crude	oil	basis	swap	contracts	in	order	to	fix	the differential	between	pricing	in	Midland,	Texas,	and	Cushing,	Oklahoma	(Midland	Differential).	Presented	below	is	a	comprehensive	summary	of	EOG's	Midland Differential	basis	swap	contracts	for	the	year	ended	December	31,	2018.	The	weighted	average	price	differential	expressed	in	dollars	per	barrel	($/Bbl)	represents	the amount	of	reduction	to	Cushing,	Oklahoma,	prices	for	the	notional	volumes	expressed	in	barrels	per	day	(Bbld)	covered	by	the	basis	swap	contracts.

|  | Volume	(Bbld) | Weighted	Average<br>Price	Differential<br>($/Bbl) |
| :--- | :--- | :--- |
| \t2018\n\tJanuary\t1,\t2018\tthrough\tDecember\t31,\t2018\t(closed) | 15,000 | $1.063 |
| \t2019 |  |  |
| \tJanuary\t2019\t(closed) | 20,000 | $1.075 |
| \tFebruary\t1,\t2019\tthrough\tDecember\t31,\t2019 | 20,000 | 1.075 |

EOG	has	also	entered	into	crude	oil	basis	swap	contracts	in	order	to	fix	the	differential	between	pricing	in	the	U.S.	Gulf	Coast	and	Cushing,	Oklahoma	(Gulf Coast	Differential).	Presented	below	is	a	comprehensive	summary	of	EOG's	Gulf	Coast	Differential	basis	swap	contracts	for	the	year	ended	December	31,	2018.	The weighted	average	price	differential	expressed	in	$/Bbl	represents	the	amount	of	addition	to	Cushing,	Oklahoma,	prices	for	the	notional	volumes	expressed	in	Bbld covered	by	the	basis	swap	contracts.

|  | Volume	(Bbld) | Weighted	Average<br>Price	Differential<br>($/Bbl) |
| :--- | :--- | :--- |
| \t2018 |  |  |
| \tJanuary\t1,\t2018\tthrough\tSeptember\t30,\t2018\t(closed) | 37,000 | $3.818 |
| \tOctober\t1,\t2018\tthrough\tDecember\t31,\t2018\t(closed) | 52,000 | 3.911 |
| \t2019 |  |  |
| \tJanuary\t2019\t(closed) | 13,000 | $5.572 |
| \tFebruary\t1,\t2019\tthrough\tDecember\t31,\t2019 | 13,000 | 5.572 |

Presented	below	is	a	comprehensive	summary	of	EOG's	crude	oil	price	swap	contracts	for	the	year	ended	December	31,	2018,	with	notional	volumes	expressed in	Bbld	and	prices	expressed	in	$/Bbl.

|  | Volume	(Bbld) | Weighted	Average<br>Price	($/Bbl) |
| :--- | :--- | :--- |
| \t2018\n\tJanuary\t1,\t2018\tthrough\tNovember\t30,\t2018\t(closed) | 134,000 | $60.04 |

On	November	20,	2018,	EOG	entered	into	crude	oil	price	swap	contracts	for	the	period	December	1,	2018	through	December	31,	2018,	with	notional	volumes of	134,000	Bbld	at	an	average	price	of	$53.75	per	Bbl.	These	contracts	offset	the	crude	oil	price	swap	contracts	for	the	same	time	period	with	notional	volumes	of 134,000	Bbld	at	an	average	price	of	$60.04	per	Bbl.	The	net	cash	EOG	received	for	settling	these	contracts	is	$26.1	million.	The	offsetting	contracts	are	excluded	from the	above	table.

Presented	below	is	a	comprehensive	summary	of	EOG's	natural	gas	price	swap	contracts	for	the	year	ended	December	31,	2018,	with	notional	volumes expressed	in	million	British	thermal	units	(MMBtu)	per	day	(MMBtud)	and	prices	expressed	in	dollars	per	MMBtu	($/MMBtu).

|  | Volume<br>(MMBtud) | Weighted	Average<br>Price	($/MMBtu) |
| :--- | :--- | :--- |
| \t2018\n\tMarch\t1,\t2018\tthrough\tNovember\t30,\t2018\t(closed) | 35,000 | $3.00 |

In	addition,	EOG	has	purchased	put	options	which	establish	a	floor	price	for	the	sale	of	notional	volumes	of	natural	gas	as	specified	in	the	put	option	contracts. The	put	options	grant	EOG	the	right	to	receive	the	difference	between	the	put	option	strike	price	and	the	Henry	Hub	Index	Price	in	the	event	the	Henry	Hub	Index	Price is	below	the	put	option	strike	price.	Presented	below	is	a	comprehensive	summary	of	EOG's	natural	gas	call	and	put	option	contracts	for	the	year	ended	December	31, 2018,	with	notional	volumes	expressed	in	MMBtud	and	prices	expressed	in	$/MMBtu.

|  | Natural	Gas	Option	Contracts<br>Call	Options	Sold<br>Volume<br>(MMBtud) | Weighted<br>Average	Price<br>($/MMBtu) | Put	Options	Purchased<br>Volume<br>(MMBtud) | Weighted<br>Average	Price<br>($/MMBtu) |
| :--- | :--- | :--- | :--- | :--- |
| 2018\nMarch\t1,\t2018\tthrough\tNovember\t30,\t2018\t(closed) | 120,000 | $3.38 | 96,000 | $2.94 |

The	 following	 table	 sets	 forth	 the	 amounts	 and	 classification	 of	 EOG's	 outstanding	 derivative	 financial	 instruments	 at	December	 31,	 2018	 and	2017, respectively.		Certain	amounts	may	be	presented	on	a	net	basis	on	the	consolidated	financial	statements	when	such	amounts	are	with	the	same	counterparty	and	subject	to a	master	netting	arrangement	(in	millions):

|  |  | Fair	Value	at	December	31, | Fair	Value	at	December	31, |
| :--- | :--- | :--- | :--- |
| Description | Location\ton\tBalance\tSheet | 2018 | 2017 |
| Asset\tDerivatives |  |  |  |
| Crude\toil\tand\tnatural\tgas\tderivative\tcontracts\t- |  |  |  |
| Current\tportion | \t Assets\tfrom\tPrice\tRisk\tManagement\tActivities | $24 | $8 |
| Noncurrent\tportion | \t Other\tAssets | — | — |
| Liability\tDerivatives |  |  |  |
| Crude\toil\tand\tnatural\tgas\tderivative\tcontracts\t- |  |  |  |
| Current\tportion | \t Liabilities\tfrom\tPrice\tRisk\tManagement\tActivities\t(1) | $— | $50 |
| Noncurrent\tportion | \t Other\tLiabilities | — | 7 |

(1) The	current	portion	of	Liabilities	from	Price	Risk	Management	Activities	consists	of	gross	liabilities	of	 $55	million,	partially	offset	by	gross	assets	of	$5	million,	at	December 31,	2017.

Credit	Risk.		Notional	contract	amounts	are	used	to	express	the	magnitude	of	a	financial	derivative.		The	amounts	potentially	subject	to	credit	risk,	in	the	event of	nonperformance	by	the	counterparties,	are	equal	to	the	fair	value	of	such	contracts	(see	Note	13).		EOG	evaluates	its	exposure	to	significant	counterparties	on	an ongoing	basis,	including	those	arising	from	physical	and	financial	transactions.		In	some	instances,	EOG	renegotiates	payment	terms	and/or	requires	collateral,	parent guarantees	or	letters	of	credit	to	minimize	credit	risk.		At	December	31,	2018,	EOG's	net	accounts	receivable	balance	related	to	United	States	hydrocarbon	sales	included three	receivable	balances,	each	of	which	accounted	for	more	than	10%	of	the	total	balance.		The	receivables	were	due	from	three	petroleum	refinery	companies.		The related	amounts	were	collected	during	early	2019.		At	December	31,	2017,	EOG's	net	accounts	receivable	balance	related	to	United	States,	Canada	and	United	Kingdom hydrocarbon	sales	included	two	receivable	balances,	each	of	which	accounted	for	more	than	10%	of	the	total	balance.		The	receivables	were	due	from	two	petroleum refinery	companies.		The	related	amounts	were	collected	during	early	2018.	In	2018	and	2017,	all	natural	gas	from	EOG's	Trinidad	operations	was	sold	to	the	National Gas	Company	of	Trinidad	and	Tobago	Limited	and	its	subsidiary.	 In	2018,	all	crude	oil	and	condensate	from	EOG's	Trinidad	operations	was	sold	to	the	Petroleum Company	of	Trinidad	and	Tobago	Limited	and	 its	successor,	Heritage	Petroleum	Company	Limited.	In	2017,	all	crude	oil	and	condensate	from	EOG's	Trinidad operations	was	sold	to	the	Petroleum	Company	of	Trinidad	and	Tobago	Limited;	and	in	2018	and	2017,	all	natural	gas	from	EOG's	China	operations	was	sold	to Petrochina	Company	Limited.

All	of	EOG's	derivative	instruments	are	covered	by	International	Swap	Dealers	Association	Master	Agreements	(ISDAs)	with	counterparties.		The	ISDAs	may contain	provisions	that	require	EOG,	if	it	is	the	party	in	a	net	liability	position,	to	post	collateral	when	the	amount	of	the	net	liability	exceeds	the	threshold	level	specified for	EOG's	then-current	credit	ratings.		In	addition,	the	ISDAs	may	also	provide	that	as	a	result	of	certain	circumstances,	including	certain	events	that	cause	EOG's	credit ratings	to	become	materially	weaker	than	its	then-current	ratings,	the	counterparty	may	require	all	outstanding	derivatives	under	the	ISDA	to	be	settled	immediately. See	Note	13	for	the	aggregate	fair	value	of	all	derivative	instruments	that	were	in	a	net	liability	position	at	December	31,	2017.		EOG	had	no	collateral	posted	and	held no	collateral	at	December	31,	2018	and	2017.

Substantially	all	of	EOG's	accounts	receivable	at	December	31,	2018	 and	2017	resulted	from	hydrocarbon	sales	and/or	joint	interest	billings	to	third-party companies,	including	foreign	state-owned	entities	in	the	oil	and	gas	industry.		This	concentration	of	customers	and	joint	interest	owners	may	impact	EOG's	overall	credit risk,	either	positively	or	negatively,	in	that	these	entities	may	be	similarly	affected	by	changes	in	economic	or	other	conditions.		In	determining	whether	or	not	to	require collateral	or	other	credit	enhancements	from	a	customer	or	joint	interest	owner,	EOG	typically	analyzes	the	entity's	net	worth,	cash	flows,	earnings	and	credit	ratings. Receivables	 are	 generally	 not	 collateralized.	 	 During	 the	 three-year	 period	 ended	December	31,	2018,	 credit	 losses	 incurred	 on	 receivables	 by	 EOG	 have	 been immaterial.

# 13.		Fair	Value	Measurements

Certain	of	EOG's	financial	and	nonfinancial	assets	and	liabilities	are	reported	at	fair	value	on	the	Consolidated	Balance	Sheets.		An	established	fair	value hierarchy	prioritizes	the	relative	reliability	of	inputs	used	in	fair	value	measurements.		The	hierarchy	gives	highest	priority	to	Level	1	inputs	that	represent	unadjusted quoted	market	prices	in	active	markets	for	identical	assets	and	liabilities	that	the	reporting	entity	has	the	ability	to	access	at	the	measurement	date.		Level	2	inputs	are directly	or	indirectly	observable	inputs	other	than	quoted	prices	included	within	Level	1.		Level	3	inputs	are	unobservable	inputs	and	have	the	lowest	priority	in	the hierarchy.		EOG	gives	consideration	to	the	credit	risk	of	its	counterparties,	as	well	as	its	own	credit	risk,	when	measuring	financial	assets	and	liabilities	at	fair	value.

The	following	table	provides	fair	value	measurement	information	within	the	fair	value	hierarchy	for	certain	of	EOG's	financial	assets	and	liabilities	carried	at fair	value	on	a	recurring	basis	at	December	31,	2018	and	2017.	Amounts	shown	in	millions.

|  | Quoted<br>Prices	in<br>Active<br>Markets<br>(Level	1) | Significant<br>Other<br>Observable<br>Inputs<br>(Level	2) | Fair	Value	Measurements	Using:<br>Significant<br>Unobservable<br>Inputs<br>(Level	3) | Total |
| :--- | :--- | :--- | :--- | :--- |
| At\tDecember\t31,\t2018 |  |  |  |  |
| Financial\tAssets:\t(1) |  |  |  |  |
| Crude\tOil\tBasis\tSwaps | $— | $24 | $— | $24 |
| At\tDecember\t31,\t2017 |  |  |  |  |
| Financial\tAssets:\t(1) |  |  |  |  |
| Natural\tGas\tSwaps | $— | $2 | $— | $2 |
| Natural\tGas\tOptions/Collars | — | 6 | — | 6 |
| Financial\tLiabilities:\t(2) |  |  |  |  |
| Crude\tOil\tSwaps | $— | $38 | $— | $38 |
| Crude\tOil\tBasis\tSwaps | — | 19 | — | 19 |

(1) $24	million	and	$8	million	is	included	in	"Assets	from	Price	Risk	Management	Activities"	at	December	31,	2018	and	2017,	respectively,	on	the	Consolidated	Balance	Sheets.

(2) $50	million	is	included	in	"Current	Liabilities	-	Liabilities	from	Price	Risk	Management	Activities"	at	December	31,	2017	and	$7	million	is	included	in	"Other	Liabilities"	at December	31,	2017,	on	the	Consolidated	Balance	Sheets.

The	estimated	fair	value	of	crude	oil	and	natural	gas	derivative	contracts	(including	options/collars)	was	based	upon	forward	commodity	price	curves	based	on quoted	market	prices.		Commodity	derivative	contracts	were	valued	by	utilizing	an	independent	third-party	derivative	valuation	provider	who	uses	various	types	of valuation	models,	as	applicable.

The	initial	measurement	of	asset	retirement	obligations	at	fair	value	is	calculated	using	discounted	cash	flow	techniques	and	based	on	internal	estimates	of future	retirement	costs	associated	with	property,	plant	and	equipment.		Significant	Level	3	inputs	used	in	the	calculation	of	asset	retirement	obligations	include	plugging costs	and	reserve	lives.		A	reconciliation	of	EOG's	asset	retirement	obligations	is	presented	in	Note	15.

During	2018,	proved	oil	and	gas	properties;	other	property,	plant	and	equipment;	and	other	assets	with	a	carrying	amount	of	$482	million	were	written	down	to their	fair	value	of	$308	million,	resulting	in	pretax	impairment	charges	of	$174	million.	Included	in	the	$174	million	pretax	impairment	charges	are	$104	million	of impairments	of	proved	oil	and	gas	properties	for	which	EOG	utilized	an	accepted	offer	from	a	third-party	purchaser	as	the	basis	for	determining	fair	value.	In	addition, EOG	recorded	pretax	impairment	charges	in	2018	of	$49	million	for	a	commodity	price-related	write-down	of	other	assets.	During	2017,	proved	oil	and	gas	properties; other	property,	plant	and	equipment;	and	other	assets	with	a	carrying	amount	of	$640	million	were	written	down	to	their	fair	value	of	$372	million,	resulting	in	pretax impairment	charges	of	$268	million.	Included	in	the	$268	million	pretax	impairment	charges	are	$217	million	of	impairments	of	proved	oil	and	gas	properties	for	which EOG	utilized	an	accepted	offer	from	a	third-party	purchaser	as	the	basis	for	determining	fair	value.	In	addition,	EOG	recorded	pretax	impairment	charges	in	2017	of	$28 million	for	a	commodity	price-related	write-down	of	other	assets.	Significant	Level	3	inputs	associated	with	the	calculation	of	discounted	cash	flows	used	in	the impairment	analysis	include	EOG's	estimate	of	future	crude	oil	and	natural	gas	prices,	production	costs,	development	expenditures,	anticipated	production	of	proved reserves,	appropriate	risk-adjusted	discount	rates	and	other	relevant	data.

EOG	utilized	average	prices	per	acre	from	comparable	market	transactions	and	estimated	discounted	cash	flows	as	the	basis	for	determining	the	fair	value	of unproved	and	proved	properties,	respectively,	received	in	non-cash	property	exchanges.	See	Note	10.

Fair	Value	of	Debt.		At	December	31,	2018	and	2017,	respectively,	EOG	had	outstanding	$6,040	million	and	$6,390	million	aggregate	principal	amount	of senior	notes,	which	had	estimated	fair	values	of	approximately	$6,027	million	and	$6,602	million,	respectively.		The	estimated	fair	value	of	debt	was	based	upon	quoted market	prices	and,	where	such	prices	were	not	available,	other	observable	(Level	2)	inputs	regarding	interest	rates	available	to	EOG	at	year-end.

# 14.		Accounting	for	Certain	Long-Lived	Assets

EOG	reviews	its	proved	oil	and	gas	properties	for	impairment	purposes	by	comparing	the	expected	undiscounted	future	cash	flows	at	a	depreciation,	depletion and	amortization	group	level	to	the	unamortized	capitalized	cost	of	the	asset.		The	carrying	values	for	assets	determined	to	be	impaired	were	adjusted	to	estimated	fair value	using	the	Income	Approach	described	in	the	Fair	Value	Measurement	Topic	of	the	ASC.	 In	certain	instances,	EOG	utilizes	accepted	offers	from	third-party purchasers	as	the	basis	for	determining	fair	value.

During	2018,	proved	oil	and	gas	properties	with	a	carrying	amount	of	$139	million	were	written	down	to	their	fair	value	of	$18	million,	resulting	in	pretax impairment	charges	of	$121	million.	During	2017,	proved	oil	and	gas	properties	with	a	carrying	amount	of	$370	million	were	written	down	to	their	fair	value	of	$146 million,	resulting	in	pretax	impairment	charges	of	$224	million.	Impairments	in	2018,	2017	and	2016	included	domestic	legacy	natural	gas	assets.	Amortization	and impairments	of	unproved	oil	and	gas	property	costs,	including	amortization	of	capitalized	interest,	were	$173	million,	$211	million	and	$291	million	during	2018,	2017 and	2016,	respectively.

# 15.		Asset	Retirement	Obligations

The	 following	 table	 presents	 the	 reconciliation	 of	 the	 beginning	 and	 ending	 aggregate	 carrying	 amounts	 of	 short-term	 and long-term legal	 obligations associated	with	the	retirement	of	property,	plant	and	equipment	for	the	years	ended	December	31,	2018	and	2017	(in	thousands):

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Carrying\tAmount\tat\tBeginning\tof\tPeriod | $946,848 | $912,926 |
| Liabilities\tIncurred | 79,057 | 54,764 |
| Liabilities\tSettled\t(1) | (70,829) | (61,871) |
| Accretion | 36,622 | 34,708 |
| Revisions | (38,932) | (9,818) |
| Foreign\tCurrency\tTranslations | 1,611 | 16,139 |
| Carrying\tAmount\tat\tEnd\tof\tPeriod | $954,377 | $946,848 |
| Current\tPortion | $26,214 | $19,259 |
| Noncurrent\tPortion | $928,163 | $927,589 |

# (1) Includes	settlements	related	to	asset	sales.

The	current	and	noncurrent	portions	of	EOG's	asset	retirement	obligations	are	included	in	Current	Liabilities	-	Other	and	Other	Liabilities,	respectively,	on	the Consolidated	Balance	Sheets.

# 16.		Exploratory	Well	Costs

EOG's	net	changes	in	capitalized	exploratory	well	costs	for	the	years	ended	December	31,	2018,	2017	and	2016	are	presented	below	(in	thousands):

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Balance\tat\tJanuary\t1 | $2,167 | $— | $8,955 |
| Additions\tPending\tthe\tDetermination\tof\tProved\tReserves | 10,304 | 27,487 | 6,688 |
| Reclassifications\tto\tProved\tProperties | (7,917) | (20,802) | (5,274) |
| Costs\tCharged\tto\tExpense\t(1) | (433) | (4,518) | (10,369) |
| Balance\tat\tDecember\t31 | $4,121 | $2,167 | $— |

(1) Includes	capitalized	exploratory	well	costs	charged	to	either	dry	hole	costs	or	impairments.

At	December	31,	2018,	2017	and	2016,	all	exploratory	well	costs	had	been	capitalized	for	periods	of	less	than	one	year.

# 17.		Acquisitions	and	Divestitures

During	2018,	EOG	recognized	a	net	gain	on	asset	dispositions	of	$175	million	primarily	due	to	non-cash	property	exchanges	in	Texas,	New	Mexico	and Wyoming.	Additionally,	EOG	received	proceeds	in	2018	of	approximately	$227	million	primarily	due	to	the	sale	of	its	United	Kingdom	operations	in	the	fourth	quarter of	2018.

During	2017,	EOG	recognized	a	net	loss	on	asset	dispositions	of	$(99)	million	and	received	proceeds	of	approximately	$227	million	primarily	from	sales	of producing	properties,	other	assets	and	acreage	in	Texas	and	Oklahoma.	Additionally,	in	the	fourth	quarter	of	2017,	EOG	signed	a	purchase	and	sale	agreement	and	an exchange	agreement	for	the	sale	and	exchange,	respectively,	of	primarily	producing	properties	in	the	Rocky	Mountain	area.	At	December	31,	2017,	the	book	value	of	the assets	classified	as	held	for	sale	and	the	related	asset	retirement	obligations	were	$188	million	and	$41	million,	respectively.

During	2017,	EOG	completed	acquisitions	of	approximately	$73	million	to	acquire	producing	properties	in	various	areas	in	the	United	States.

During	2016,	EOG	recognized	a	net	gain	on	asset	dispositions	of	$206	million	and	received	proceeds	of	approximately	$1,119	million	primarily	from	sales	of producing	properties	and	acreage	in	Texas,	Louisiana,	the	Rocky	Mountain	area	and	Oklahoma.	Additionally,	during	the	third	quarter	of	2016,	EOG	completed	the	sale of	all	its	Argentina	assets.

Yates Entities.	On	 October	 4,	 2016,	 EOG	 completed	 its	 previously	 announced	 mergers	 and	 related	 asset	 purchase	 transactions	 with	 Yates	 Petroleum Corporation	(YPC),	Abo	Petroleum	Corporation	(ABO),	MYCO	Industries,	Inc.	(MYCO)	and	certain	affiliated	entities	(collectively	with	YPC,	ABO	and	MYCO,	the Yates	Entities).	Pursuant	to	these	transactions,	EOG	issued	to	the	shareholders	of	YPC,	ABO	and	MYCO	and	to	certain	of	the	sellers	under	the	related	asset	purchase transactions	an	aggregate	of	approximately	25	million	shares	of	EOG	common	stock	and	paid	to	certain	of	the	sellers	under	the	asset	purchase	transactions	an	aggregate of	approximately	$16	million	in	cash	for	total	consideration	transferred	of	approximately	$2.4	billion.	In	addition,	under	the	terms	of	the	transactions,	EOG	assumed	and repaid	approximately	$164	million	of	debt	owed	by	the	Yates	Entities,	which	was	offset	by	approximately	$70	million	of	cash	of	the	Yates	Entities.

The	assets	of	the	Yates	Entities	include	producing	wells	in	addition	to	acreage	in	the	Delaware	Basin	Core,	the	Powder	River	Basin,	the	Permian	Basin Northwest	Shelf	and	other	Western	basins.

In	connection	with	these	mergers	and	related	asset	purchase	transactions,	EOG	incurred	acquisition-related	costs	in	2016	of	approximately	$5	million,	all	of which	were	expensed	and	recorded	as	General	and	Administrative	on	the	Consolidated	Statements	of	Income	(Loss)	and	Comprehensive	Income	(Loss).

EOG	accounted	for	the	mergers	with	YPC,	ABO	and	MYCO	and	the	related	asset	purchase	transactions	as	a	business	combination	under	the	acquisition	method with	EOG	as	the	acquirer.	Under	the	acquisition	method,	the	consideration	transferred	is	allocated	to	the	assets	acquired	and	liabilities	assumed	based	on	their	estimated fair	values,	with	any	excess	of	the	consideration	transferred	over	the	estimated	fair	value	of	the	identifiable	net	assets	acquired	recorded	as	goodwill.	EOG	did	not	record goodwill	in	connection	with	these	transactions.

The	following	table	represents	the	final	allocation	of	the	total	purchase	price	of	the	Yates	Entities	(in	thousands).

| Current	Assets |  |
| :--- | :--- |
| Cash\tand\tCash\tEquivalents | $70,411 |
| Accounts\tReceivable,\tNet | 77,073 |
| Inventories | 10,955 |
| Other | 10,640 |
| Total | 169,079 |
| Property,\tPlant\tand\tEquipment |  |
| Oil\tand\tGas\tProperties\t(Successful\tEfforts\tMethod) | 3,815,207 |
| Other\tProperty,\tPlant\tand\tEquipment | 21,824 |
| Total\tProperty,\tPlant\tand\tEquipment,\tNet | 3,837,031 |
| Other\tAssets | 22,706 |
| Total\tAssets | $4,028,816 |
| Current\tLiabilities |  |
| Accounts\tPayable | $124,145 |
| Accrued\tTaxes\tPayable | 22,417 |
| Other | 743 |
| Total | 147,305 |
| Long-Term\tDebt | 163,829 |
| Asset\tRetirement\tObligations | 163,144 |
| Off-Market\tTransportation\tContracts | 39,720 |
| Other\tLiabilities | 28,645 |
| Deferred\tIncome\tTaxes | 1,072,405 |
| Total\tLiabilities | $1,615,048 |
| Total\tConsideration\tTransferred | $2,413,768 |

The	fair	value	measurements	of	Oil	and	Gas	Properties	and	Asset	Retirement	Obligations	are	based	on	inputs	that	are	not	observable	in	the	market	and	therefore represent	Level	3	inputs.	The	fair	values	of	Proved	Oil	and	Gas	Properties	were	measured	using	the	income	approach.	Significant	inputs	to	the	valuation	of	Proved	Oil and	Gas	Properties	included	EOG's	estimate	of	future	crude	oil	and	natural	gas	prices,	production	costs,	development	expenditures,	anticipated	production	of	proved reserves,	appropriate	risk-adjusted	discount	rates	and	other	relevant	data.	Significant	inputs	to	the	valuation	of	Unproved	Oil	and	Gas	Properties	included	average	prices per	acre	of	comparable	market	transactions.

# SUPPLEMENTAL	INFORMATION	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# (In	Thousands,	Except	Per	Share	Data	Unless	Otherwise	Indicated)

# (Unaudited)

# Oil	and	Gas	Producing	Activities

The	following	disclosures	are	made	in	accordance	with	Financial	Accounting	Standards	Board	Accounting	Standards	Update	No.	2010-03	"Oil	and	Gas Reserve	Estimates	and	Disclosures"	and	the	United	States	Securities	and	Exchange	Commission's	(SEC)	final	rule	on	"Modernization	of	Oil	and	Gas	Reporting."

Oil	and	Gas	Reserves.		Users	of	this	information	should	be	aware	that	the	process	of	estimating	quantities	of	"proved,"	"proved	developed"	and	"proved undeveloped"	crude	oil,	natural	gas	 liquids	(NGLs)	and	natural	gas	reserves	 is	complex,	requiring	significant	subjective	decisions	 in	 the	evaluation	of	available geological,	engineering	and	economic	data	for	each	reservoir.		The	data	for	a	given	reservoir	may	also	change	substantially	over	time	as	a	result	of	numerous	factors, including,	but	not	 limited	 to,	additional	development	activity;	evolving	production	history;	crude	oil	and	condensate,	NGL	and	natural	gas	prices;	and	continual reassessment	of	the	viability	of	production	under	varying	economic	conditions.		Consequently,	material	revisions	(upward	or	downward)	to	existing	reserve	estimates may	occur	from	time	to	time.		Although	reasonable	effort	is	made	to	ensure	that	reserve	estimates	reported	represent	the	most	accurate	assessments	possible,	the significance	of	the	subjective	decisions	required	and	variances	in	available	data	for	various	reservoirs	make	these	estimates	generally	less	precise	than	other	estimates presented	in	connection	with	financial	statement	disclosures.		For	related	discussion,	see	ITEM	1A,	Risk	Factors.

Proved	reserves	represent	estimated	quantities	of	crude	oil,	NGLs	and	natural	gas,	which,	by	analysis	of	geoscience	and	engineering	data,	can	be	estimated, with	reasonable	certainty,	to	be	economically	producible	from	a	given	date	forward	from	known	reservoirs	under	then-existing	economic	conditions,	operating	methods and	government	regulations	before	the	time	at	which	contracts	providing	the	right	to	operate	expire,	unless	evidence	indicates	that	renewal	is	reasonably	certain, regardless	of	whether	deterministic	or	probabilistic	methods	are	used	for	the	estimation.

Proved	developed	reserves	are	proved	reserves	expected	to	be	recovered	under	operating	methods	being	utilized	at	the	time	the	estimates	were	made,	through wells	and	equipment	in	place	or	if	the	cost	of	any	required	equipment	is	relatively	minor	compared	to	the	cost	of	a	new	well.

Proved	undeveloped	reserves	(PUDs)	are	reserves	that	are	expected	to	be	recovered	from	new	wells	on	undrilled	acreage,	or	from	existing	wells	where	a relatively	major	expenditure	is	required	for	recompletion.	Reserves	on	undrilled	acreage	are	limited	to	those	directly	offsetting	development	spacing	areas	that	are reasonably	certain	of	production	when	drilled,	unless	evidence	using	reliable	technology	exists	that	establishes	reasonable	certainty	of	economic	producibility	at	greater distances.	PUDs	can	be	recorded	in	respect	of	a	particular	undrilled	location	only	if	the	location	is	scheduled,	under	the	then-current	drilling	and	development	plan,	to	be drilled	within	five	years	from	the	date	that	the	PUDs	were	recorded,	unless	specific	factors	(such	as	those	described	in	interpretative	guidance	issued	by	the	Staff	of	the SEC)	justify	a	longer	timeframe.		Likewise,	absent	any	such	specific	factors,	PUDs	associated	with	a	particular	undeveloped	drilling	location	shall	be	removed	from	the estimates	of	proved	reserves	if	the	location	is	scheduled,	under	the	then-current	drilling	and	development	plan,	to	be	drilled	on	a	date	that	is	beyond	five	years	from	the date	that	the	PUDs	were	recorded.		EOG	has	formulated	development	plans	for	all	drilling	locations	associated	with	its	PUDs	at	December	31,	2018.		Under	these	plans, each	PUD	location	will	be	drilled	within	five	years	from	the	date	it	was	recorded.		Estimates	for	PUDs	are	not	attributed	to	any	acreage	for	which	an	application	of	fluid injection	or	other	improved	recovery	technique	is	contemplated,	unless	such	techniques	have	been	proved	effective	by	actual	projects	in	the	same	reservoir	or	an analogous	reservoir,	or	by	other	evidence	using	reliable	technology	establishing	reasonable	certainty.

In	making	estimates	of	PUDs,	EOG's	technical	staff,	including	engineers	and	geoscientists,	perform	detailed	technical	analysis	of	each	potential	drilling location	within	its	inventory	of	prospects.		In	making	a	determination	as	to	which	of	these	locations	would	penetrate	undrilled	portions	of	the	formation	that	can	be judged,	with	reasonable	certainty,	to	be	continuous	and	contain	economically	producible	crude	oil	and	natural	gas,	studies	are	conducted	using	numerous	data	elements and	analysis	techniques.		EOG's	technical	staff	estimates	the	hydrocarbons	in	place,	by	mapping	the	entirety	of	the	play	in	question	using	seismic	techniques,	typically employing	two-dimensional	and	three-dimensional	data.		This	analysis	is	integrated	with	other	static	data,	including,	but	not	limited	to,	core	analysis,	mechanical properties	of	the	formation,	thermal	maturity	indicators,	and	well	logs	of	existing	penetrations.		Highly	specialized	equipment	is	utilized	to	prepare	rock	samples	in assessing	microstructures	which	contribute	to	porosity	and	permeability.

Analysis	of	dynamic	data	is	then	incorporated	to	arrive	at	the	estimated	fractional	recovery	of	hydrocarbons	in	place.		Data	analysis	techniques	employed include,	but	are	not	limited	to,	well	testing	analysis,	static	bottom	hole	pressure	analysis,	flowing	bottom	hole	pressure	analysis,	analysis	of	historical	production	trends, pressure	transient	analysis	and	rate	transient	analysis.		Application	of	proprietary	rate	transient	analysis	techniques	in	low	permeability	rocks	allow	for	quantification	of estimates	of	contribution	to	production	from	both	fractures	and	rock	matrix.

# SUPPLEMENTAL	INFORMATION	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	(Continued)

The	impact	of	optimal	completion	techniques	is	a	key	factor	in	determining	if	the	PUDs	reflected	in	prospective	locations	are	reasonably	certain	of	being economically	producible.		EOG's	technical	staff	estimates	the	recovery	improvement	that	might	be	achieved	when	completing	horizontal	wells	with	multi-stage	fracture stimulation.		In	the	early	stages	of	development	of	a	play,	EOG	determines	the	optimal	length	of	the	horizontal	lateral	and	multi-stage	fracture	stimulation	using	the aforementioned	analysis	techniques	along	with	pilot	drilling	programs	and	gathering	of	microseismic	data.

The	process	of	analyzing	static	and	dynamic	data,	well	completion	optimization	and	the	results	of	early	development	activities	provides	the	appropriate	level	of certainty	as	well	as	support	for	the	economic	producibility	of	the	plays	in	which	PUDs	are	reflected.		EOG	has	found	this	approach	to	be	effective	based	on	successful application	in	analogous	reservoirs	in	low	permeability	resource	plays.

Certain	of	EOG's	Trinidad	reserves	are	held	under	production	sharing	contracts	where	EOG's	interest	varies	with	prices	and	production	volumes.		Trinidad reserves,	as	presented	on	a	net	basis,	assume	prices	in	existence	at	the	time	the	estimates	were	made	and	EOG's	estimate	of	future	production	volumes.	 	Future fluctuations	in	prices,	production	rates	or	changes	in	political	or	regulatory	environments	could	cause	EOG's	share	of	future	production	from	Trinidadian	reserves	to	be materially	different	from	that	presented.

Estimates	of	proved	reserves	at	December	31,	2018,	2017	and	2016	were	based	on	studies	performed	by	the	engineering	staff	of	EOG.		The	Engineering	and Acquisitions	Department	is	directly	responsible	for	EOG's	reserve	evaluation	process	and	consists	of	16	professionals,	all	of	whom	hold,	at	a	minimum,	bachelor's degrees	in	engineering,	and	four	of	whom	are	Registered	Professional	Engineers.		The	Vice	President,	Engineering	and	Acquisitions	is	the	manager	of	this	department and	is	the	primary	technical	person	responsible	for	this	process.		The	Vice	President,	Engineering	and	Acquisitions	holds	a	Bachelor	of	Science	degree	in	Petroleum Engineering,	has	32	years	of	experience	in	reserve	evaluations	and	is	a	Registered	Professional	Engineer.

EOG's	reserves	estimation	process	is	a	collaborative	effort	coordinated	by	the	Engineering	and	Acquisitions	Department	in	compliance	with	EOG's	internal controls	for	such	process.		Reserve	information	as	well	as	models	used	to	estimate	such	reserves	are	stored	on	secured	databases.		Non-technical	inputs	used	in	reserve estimation	models,	 including	crude	oil,	NGL	and	natural	gas	prices,	production	costs,	 transportation	costs,	future	capital	expenditures	and	EOG's	net	ownership percentages,	 are	 obtained	 from	 other	 departments	 within	 EOG.	 	 EOG's	 Internal	Audit	 Department	 conducts	 testing	 with	 respect	 to	 such	 non-technical	 inputs. Additionally,	EOG	engages	DeGolyer	and	MacNaughton	(D&M),	 independent	petroleum	consultants,	 to	perform	 independent	reserves	evaluation	of	select	EOG properties	comprising	not	less	than	75%	of	EOG's	estimates	of	proved	reserves.		EOG's	Board	of	Directors	requires	that	D&M's	and	EOG's	reserve	quantities	for	the properties	evaluated	by	D&M	vary	by	no	more	than	5%	in	the	aggregate.		Once	completed,	EOG's	year-end	reserves	are	presented	to	senior	management,	including	the Chairman	of	the	Board	and	Chief	Executive	Officer;	the	Chief	Operating	Officer;	the	Executive	Vice	Presidents,	Exploration	and	Production;	and	the	Executive	Vice President	and	Chief	Financial	Officer,	for	approval.

Opinions	by	D&M	for	the	years	ended	December	31,	2018,	2017	and	2016	covered	producing	areas	containing	79%,	79%	and	83%,	respectively,	of	proved reserves	of	EOG	on	a	net-equivalent-barrel-of-oil	basis.		D&M's	opinions	indicate	that	the	estimates	of	proved	reserves	prepared	by	EOG's	Engineering	and	Acquisitions Department	for	the	properties	reviewed	by	D&M,	when	compared	in	total	on	a	net-equivalent-barrel-of-oil	basis,	do	not	differ	materially	from	the	estimates	prepared	by D&M.		Specifically,	such	estimates	by	D&M	in	the	aggregate	varied	by	not	more	than	5%	from	those	prepared	by	the	Engineering	and	Acquisitions	Department	of EOG.		All	reports	by	D&M	were	developed	utilizing	geological	and	engineering	data	provided	by	EOG.		The	report	of	D&M	dated	January	25,	2019,	which	contains further	discussion	of	 the	reserve	estimates	and	evaluations	prepared	by	D&M,	as	well	as	 the	qualifications	of	D&M's	 technical	person	primarily	responsible	for overseeing	such	estimates	and	evaluations,	is	attached	as	Exhibit	99.1	to	this	Annual	Report	on	Form	10-K	and	incorporated	herein	by	reference.

No	major	discovery	or	other	favorable	or	adverse	event	subsequent	to	December	31,	2018,	is	believed	to	have	caused	a	material	change	in	the	estimates	of	net proved	reserves	as	of	that	date.

The	following	tables	set	forth	EOG's	net	proved	reserves	at	December	31	for	each	of	the	four	years	in	the	period	ended	December	31,	2018,	and	the	changes	in the	net	proved	reserves	for	each	of	the	three	years	in	the	period	ended	December	31,	2018,	as	estimated	by	the	Engineering	and	Acquisitions	Department	of	EOG:

# NET	PROVED	RESERVE	SUMMARY

| NET	PROVED	RESERVES | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| Crude\tOil\t(MBbl)\t(2) |  |  |  |  |
| Net\tproved\treserves\tat\tDecember\t31,\t2015 | 1,087,860 | 1,069 | 8,667 | 1,097,596 |
| Revisions\tof\tprevious\testimates | 42,040 | 54 | 861 | 42,955 |
| Purchases\tin\tplace | 25,795 | — | — | 25,795 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 123,441 | — | — | 123,441 |
| Sales\tin\tplace | (8,791) | — | — | (8,791) |
| Production | (101,854) | (284) | (1,273) | (103,411) |
| Net\tproved\treserves\tat\tDecember\t31,\t2016 | 1,168,491 | 839 | 8,255 | 1,177,585 |
| Revisions\tof\tprevious\testimates | 57,935 | 80 | (179) | 57,836 |
| Purchases\tin\tplace | 1,111 | — | — | 1,111 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 207,137 | 301 | 119 | 207,557 |
| Sales\tin\tplace | (8,393) | — | — | (8,393) |
| Production | (122,210) | (322) | (191) | (122,723) |
| Net\tproved\treserves\tat\tDecember\t31,\t2017 | 1,304,071 | 898 | 8,004 | 1,312,973 |
| Revisions\tof\tprevious\testimates | (13,237) | (183) | 44 | (13,376) |
| Purchases\tin\tplace | 2,743 | — | — | 2,743 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 383,003 | — | 15 | 383,018 |
| Sales\tin\tplace | (768) | — | (6,310) | (7,078) |
| Production | (144,128) | (298) | (1,542) | (145,968) |
| Net\tproved\treserves\tat\tDecember\t31,\t2018 | 1,531,684 | 417 | 211 | 1,532,312 |
| Natural\tGas\tLiquids\t(MBbl)\t(2) |  |  |  |  |
| Net\tproved\treserves\tat\tDecember\t31,\t2015 | 382,875 | — | — | 382,875 |
| Revisions\tof\tprevious\testimates | 53,771 | — | — | 53,771 |
| Purchases\tin\tplace | 1,284 | — | — | 1,284 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 41,862 | — | — | 41,862 |
| Sales\tin\tplace | (33,548) | — | — | (33,548) |
| Production | (29,878) | — | — | (29,878) |
| Net\tproved\treserves\tat\tDecember\t31,\t2016 | 416,366 | — | — | 416,366 |
| Revisions\tof\tprevious\testimates | 46,843 | — | — | 46,843 |
| Purchases\tin\tplace | 421 | — | — | 421 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 75,003 | — | — | 75,003 |
| Sales\tin\tplace | (2,887) | — | — | (2,887) |
| Production | (32,273) | — | — | (32,273) |
| Net\tproved\treserves\tat\tDecember\t31,\t2017 | 503,473 | — | — | 503,473 |
| Revisions\tof\tprevious\testimates | 23,942 | — | — | 23,942 |
| Purchases\tin\tplace | 2,006 | — | — | 2,006 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 127,409 | — | — | 127,409 |
| Sales\tin\tplace | (41) | — | — | (41) |
| Production | (42,460) | — | — | (42,460) |
| Net\tproved\treserves\tat\tDecember\t31,\t2018 | 614,329 | — | — | 614,329 |

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| Natural\tGas\t(Bcf)\t(3) |  |  |  |  |
| Net\tproved\treserves\tat\tDecember\t31,\t2015 | 3,489.8 | 316.6 | 19.5 | 3,825.9 |
| Revisions\tof\tprevious\testimates | 298.4 | 29.5 | 5.2 | 333.1 |
| Purchases\tin\tplace | 91.5 | — | — | 91.5 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 202.1 | 59.9 | — | 262.0 |
| Sales\tin\tplace | (752.0) | — | — | (752.0) |
| Production | (308.6) | (125.1) | (8.9) | (442.6) |
| Net\tproved\treserves\tat\tDecember\t31,\t2016 | 3,021.2 | 280.9 | 15.8 | 3,317.9 |
| Revisions\tof\tprevious\testimates | 602.8 | (27.4) | 8.6 | 584.0 |
| Purchases\tin\tplace | 4.8 | — | — | 4.8 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 619.3 | 174.2 | 35.9 | 829.4 |
| Sales\tin\tplace | (56.4) | — | — | (56.4) |
| Production | (293.2) | (114.3) | (9.1) | (416.6) |
| Net\tproved\treserves\tat\tDecember\t31,\t2017 | 3,898.5 | 313.4 | 51.2 | 4,263.1 |
| Revisions\tof\tprevious\testimates | (127.2) | 20.7 | 15.0 | (91.5) |
| Purchases\tin\tplace | 41.3 | — | — | 41.3 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 951.4 | — | 4.6 | 956.0 |
| Sales\tin\tplace | (22.2) | — | — | (22.2) |
| Production | (351.2) | (97.1) | (11.2) | (459.5) |
| Net\tproved\treserves\tat\tDecember\t31,\t2018 | 4,390.6 | 237.0 | 59.6 | 4,687.2 |
| Oil\tEquivalents\t(MBoe)\t(2) |  |  |  |  |
| Net\tproved\treserves\tat\tDecember\t31,\t2015 | 2,052,361 | 53,843 | 11,913 | 2,118,117 |
| Revisions\tof\tprevious\testimates | 145,542 | 4,978 | 1,722 | 152,242 |
| Purchases\tin\tplace | 42,330 | — | — | 42,330 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 198,973 | 9,990 | — | 208,963 |
| Sales\tin\tplace | (167,669) | — | — | (167,669) |
| Production | (183,145) | (21,150) | (2,755) | (207,050) |
| Net\tproved\treserves\tat\tDecember\t31,\t2016 | 2,088,392 | 47,661 | 10,880 | 2,146,933 |
| Revisions\tof\tprevious\testimates | 205,262 | (4,493) | 1,249 | 202,018 |
| Purchases\tin\tplace | 2,332 | — | — | 2,332 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 385,354 | 29,340 | 6,104 | 420,798 |
| Sales\tin\tplace | (20,687) | — | — | (20,687) |
| Production | (203,351) | (19,366) | (1,707) | (224,424) |
| Net\tproved\treserves\tat\tDecember\t31,\t2017 | 2,457,302 | 53,142 | 16,526 | 2,526,970 |
| Revisions\tof\tprevious\testimates | (10,500) | 3,272 | 2,544 | (4,684) |
| Purchases\tin\tplace | 11,640 | — | — | 11,640 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 668,972 | — | 778 | 669,750 |
| Sales\tin\tplace | (4,509) | — | (6,310) | (10,819) |
| Production | (245,127) | (16,478) | (3,406) | (265,011) |
| Net\tproved\treserves\tat\tDecember\t31,\t2018 | 2,877,778 | 39,936 | 10,132 | 2,927,846 |

(2) Thousand	barrels	or	thousand	barrels	of	oil	equivalent,	as	applicable;	oil	equivalents	include	crude	oil	and	condensate,	NGLs	and	natural	gas.	Oil	equivalents	are	determined using	a	ratio	of	1.0	barrel	of	crude	oil	and	condensate	or	NGLs	to	6.0	thousand	cubic	feet	of	natural	gas.

(3) Billion	cubic	feet.

During	2018,	EOG	added	670	million	barrels	of	oil	equivalent	(MMBoe)	of	proved	reserves	from	drilling	activities	and	technical	evaluation	of	major	proved areas,	primarily	in	the	Permian	Basin,	the	Eagle	Ford,	the	Rocky	Mountain	area	and	the	Mid-Continent	area.		Approximately	76%	of	the	2018	reserve	additions	were crude	oil	and	condensate	and	NGLs,	and	substantially	all	were	in	the	United	States.		Sales	in	place	of	11	MMBoe	were	primarily	related	to	the	sale	of	the	United Kingdom	operations	and	the	sale	or	exchange	of	other	producing	assets.	Revisions	of	previous	estimates	of	negative	5	MMBoe	for	2018	included	an	upward	revision	of 35	MMBoe	primarily	due	to	increases	in	the	average	crude	oil	and	natural	gas	prices	used	in	the	December	31,	2018,	reserves	estimation	as	compared	to	the	prices	used in	the	prior	year	estimate.	The	primary	areas	affected	were	in	the	Rocky	Mountain	area,	the	Eagle	Ford	and	the	Permian	Basin.	Downward	revisions	other	than	price	of 40	MMBoe	resulted	primarily	from	changes	in	production	forecasts	and	higher	production	costs.	Purchases	in	place	of	12	MMBoe	were	primarily	related	to	the	South Texas	Area.

During	2017,	EOG	added	421	MMBoe	of	proved	reserves	from	drilling	activities	and	technical	evaluation	of	major	proved	areas,	primarily	in	the	Permian Basin,	the	Eagle	Ford,	the	Rocky	Mountain	area	and	Trinidad.		Approximately	67%	of	the	2017	reserve	additions	were	crude	oil	and	condensate	and	NGLs,	and	92% were	in	the	United	States.		Sales	in	place	of	21	MMBoe	were	primarily	related	to	the	sale	or	exchange	of	certain	producing	assets.	Revisions	of	previous	estimates	of	202 MMBoe	for	2017	included	an	upward	revision	of	154	MMBoe	primarily	due	to	increases	in	the	average	crude	oil	and	natural	gas	prices	used	in	the	December	31,	2017, reserves	estimation	as	compared	to	the	prices	used	in	the	prior	year	estimate.	The	primary	plays	affected	were	in	the	Rocky	Mountain	area,	the	Eagle	Ford	and	the Permian	Basin.	Positive	revisions	other	than	price	of	48	MMBoe	resulted	primarily	from	improved	well	performance	in	the	Permian	Basin	and	lower	production	costs. Purchases	in	place	of	2	MMBoe	were	primarily	related	to	the	Permian	Basin.

During	2016,	EOG	added	209	MMBoe	of	proved	reserves	from	drilling	activities	and	technical	evaluation	of	major	proved	areas,	primarily	in	the	Permian Basin,	the	Rocky	Mountain	area	and	the	Eagle	Ford.		Approximately	79%	of	the	2016	reserve	additions	were	crude	oil	and	condensate	and	NGLs,	and	95%	were	in	the United	States.		Sales	in	place	of	168	MMBoe	were	primarily	related	to	the	disposition	of	certain	producing	natural	gas	assets	in	the	Barnett	Shale	and	Haynesville	plays and	marginal	liquids	plays	in	the	Permian	Basin	and	Rocky	Mountain	area.	Revisions	of	previous	estimates	of	152	MMBoe	for	2016	included	a	downward	revision	of 101	MMBoe	primarily	due	to	decreases	in	the	average	crude	oil	and	natural	gas	prices	used	in	the	December	31,	2016,	reserves	estimation	as	compared	to	the	prices used	in	the	prior	year	estimate.	The	primary	plays	affected	were	the	Eagle	Ford,	the	Uinta	basin	in	the	Rocky	Mountain	area,	the	Permian	Basin	and	the	Barnett	Shale. Positive	revisions	other	than	price	of	253	MMBoe	resulted	primarily	from	lower	production	costs	and	improved	performance	in	the	Delaware	Basin.	Purchases	in	place of	42	MMBoe	were	primarily	related	to	the	Yates	transaction.

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| NET\tPROVED\tDEVELOPED\tRESERVES |  |  |  |  |
| Crude\tOil\t(MBbl) |  |  |  |  |
| December\t31,\t2015 | 444,070 | 1,069 | 63 | 445,202 |
| December\t31,\t2016 | 507,531 | 839 | 8,255 | 516,625 |
| December\t31,\t2017 | 605,405 | 898 | 7,933 | 614,236 |
| December\t31,\t2018 | 712,218 | 417 | 150 | 712,785 |
| Natural\tGas\tLiquids\t(MBbl) |  |  |  |  |
| December\t31,\t2015 | 205,898 | — | — | 205,898 |
| December\t31,\t2016 | 230,219 | — | — | 230,219 |
| December\t31,\t2017 | 286,872 | — | — | 286,872 |
| December\t31,\t2018 | 341,386 | — | — | 341,386 |
| Natural\tGas\t(Bcf) |  |  |  |  |
| December\t31,\t2015 | 2,211.2 | 297.6 | 19.5 | 2,528.3 |
| December\t31,\t2016 | 1,804.4 | 262.2 | 15.8 | 2,082.4 |
| December\t31,\t2017 | 2,450.8 | 299.2 | 29.3 | 2,779.3 |
| December\t31,\t2018 | 2,699.0 | 223.9 | 40.9 | 2,963.8 |
| Oil\tEquivalents\t(MBoe) |  |  |  |  |
| December\t31,\t2015 | 1,018,491 | 50,677 | 3,309 | 1,072,477 |
| December\t31,\t2016 | 1,038,483 | 44,543 | 10,880 | 1,093,906 |
| December\t31,\t2017 | 1,300,758 | 50,779 | 12,798 | 1,364,335 |
| December\t31,\t2018 | 1,503,441 | 37,746 | 6,950 | 1,548,137 |
| NET\tPROVED\tUNDEVELOPED\tRESERVES |  |  |  |  |
| Crude\tOil\t(MBbl) |  |  |  |  |
| December\t31,\t2015 | 643,790 | — | 8,604 | 652,394 |
| December\t31,\t2016 | 660,690 | — | — | 660,690 |
| December\t31,\t2017 | 698,666 | — | 71 | 698,737 |
| December\t31,\t2018 | 819,466 | — | 61 | 819,527 |
| Natural\tGas\tLiquids\t(MBbl) |  |  |  |  |
| December\t31,\t2015 | 176,977 | — | — | 176,977 |
| December\t31,\t2016 | 186,147 | — | — | 186,147 |
| December\t31,\t2017 | 216,601 | — | — | 216,601 |
| December\t31,\t2018 | 272,943 | — | — | 272,943 |
| Natural\tGas\t(Bcf) |  |  |  |  |
| December\t31,\t2015 | 1,278.6 | 19.0 | — | 1,297.6 |
| December\t31,\t2016 | 1,216.8 | 18.7 | — | 1,235.5 |
| December\t31,\t2017 | 1,447.7 | 14.2 | 21.9 | 1,483.8 |
| December\t31,\t2018 | 1,691.6 | 13.1 | 18.7 | 1,723.4 |
| Oil\tEquivalents\t(MBoe) |  |  |  |  |
| December\t31,\t2015 | 1,033,870 | 3,166 | 8,604 | 1,045,640 |
| December\t31,\t2016 | 1,049,909 | 3,118 | — | 1,053,027 |
| December\t31,\t2017 | 1,156,544 | 2,363 | 3,728 | 1,162,635 |
| December\t31,\t2018 | 1,374,337 | 2,190 | 3,182 | 1,379,709 |

|  | 2018 | 2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Balance\tat\tJanuary\t1 | 1,162,635 | 1,053,027 | 1,045,640 |
| Extensions\tand\tDiscoveries | 490,725 | 237,378 | 138,101 |
| Revisions | (8,244) | 33,127 | 64,413 |
| Acquisition\tof\tReserves | 311 | — | — |
| Sale\tof\tReserves | — | (8,253) | (45,917) |
| Conversion\tto\tProved\tDeveloped\tReserves | (265,718) | (152,644) | (149,210) |
| Balance\tat\tDecember\t31 | 1,379,709 | 1,162,635 | 1,053,027 |

For	the	twelve-month	period	ended	December	31,	2018,	total	PUDs	increased	by	217	MMBoe	to	1,380	MMBoe.		EOG	added	approximately	31	MMBoe	of PUDs	through	drilling	activities	where	the	wells	were	drilled	but	significant	expenditures	remained	for	completion.		Based	on	the	technology	employed	by	EOG	to identify	and	record	PUDs	(see	discussion	of	technology	employed	on	pages	F-36	and	F-37	of	this	Annual	Report	on	Form	10-K),	EOG	added	460	MMBoe.		The	PUD additions	were	primarily	in	the	Permian	Basin,	Anadarko	Basin,	the	Eagle	Ford	and,	to	a	lesser	extent,	the	Rocky	Mountain	area,	and	80%	of	the	additions	were	crude	oil and	condensate	and	NGLs.		During	2018,	EOG	drilled	and	transferred	266	MMBoe	of	PUDs	to	proved	developed	reserves	at	a	total	capital	cost	of	$2,745	million.		All PUDs,	including	drilled	but	uncompleted	wells	(DUCs),	are	scheduled	for	completion	within	five	years	of	the	original	reserve	booking.

For	the	twelve-month	period	ended	December	31,	2017,	total	PUDs	increased	by	110	MMBoe	to	1,163	MMBoe.		EOG	added	approximately	38	MMBoe	of PUDs	through	drilling	activities	where	the	wells	were	drilled	but	significant	expenditures	remained	for	completion.		Based	on	the	technology	employed	by	EOG	to identify	and	record	PUDs,	EOG	added	199	MMBoe.		The	PUD	additions	were	primarily	in	the	Permian	Basin	and,	to	a	lesser	extent,	the	Eagle	Ford	and	the	Rocky Mountain	area,	and	74%	of	the	additions	were	crude	oil	and	condensate	and	NGLs.		During	2017,	EOG	drilled	and	transferred	153	MMBoe	of	PUDs	to	proved developed	reserves	at	a	total	capital	cost	of	$1,440	million.		Revisions	of	PUDs	totaled	positive	33	MMBoe,	primarily	due	to	updated	type	curves	resulting	from improved	performance	of	offsetting	wells	in	the	Permian	Basin,	the	impact	of	increases	in	the	average	crude	oil	and	natural	gas	prices	used	in	the	December	31,	2017, reserves	estimation	as	compared	to	the	prices	used	in	the	prior	year	estimate,	and	lower	costs.		During	2017,	EOG	sold	or	exchanged	8	MMBoe	of	PUDs	primarily	in	the Permian	Basin.

For	the	twelve-month	period	ended	December	31,	2016,	total	PUDs	increased	by	7	MMBoe	to	1,053	MMBoe.		EOG	added	approximately	21	MMBoe	of	PUDs through	drilling	activities	where	the	wells	were	drilled	but	significant	expenditures	remained	for	completion.		Based	on	the	technology	employed	by	EOG	to	identify	and record	PUDs,	EOG	added	117	MMBoe.		The	PUD	additions	were	primarily	in	the	Permian	Basin	and,	to	a	lesser	extent,	the	Rocky	Mountain	area,	and	82%	of	the additions	were	crude	oil	and	condensate	and	NGLs.		During	2016,	EOG	drilled	and	transferred	149	MMBoe	of	PUDs	to	proved	developed	reserves	at	a	total	capital	cost of	$1,230	million.		Revisions	of	PUDs	totaled	positive	64	MMBoe,	primarily	due	to	improved	well	performance,	primarily	in	the	Delaware	Basin,	and	lower	production costs,	partially	offset	by	the	impact	of	decreases	in	the	average	crude	oil	and	natural	gas	prices	used	in	the	December	31,	2016,	reserves	estimation	as	compared	to	the prices	used	in	the	prior	year	estimate.		During	2016,	EOG	sold	46	MMBoe	of	PUDs	primarily	in	the	Haynesville	play.

Capitalized	Costs	Relating	to	Oil	and	Gas	Producing	Activities.		The	following	table	sets	forth	the	capitalized	costs	relating	to	EOG's	crude	oil	and	natural	gas producing	activities	at	December	31,	2018	and	2017:

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Proved\tproperties | $53,624,809 | $48,845,672 |
| Unproved\tproperties | 3,705,207 | 3,710,069 |
| Total | 57,330,016 | 52,555,741 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization | (31,674,085) | (29,191,247) |
| Net\tcapitalized\tcosts | $25,655,931 | $23,364,494 |

Costs	Incurred	in	Oil	and	Gas	Property	Acquisition,	Exploration	and	Development	Activities.		The	acquisition,	exploration	and	development	costs	disclosed	in the	following	tables	are	in	accordance	with	definitions	in	the	Extractive	Industries	-	Oil	and	Gas	Topic	of	the	Accounting	Standards	Codification	(ASC).

Acquisition	costs	include	costs	incurred	to	purchase,	lease	or	otherwise	acquire	property.

Exploration	costs	include	additions	to	exploratory	wells,	including	those	in	progress,	and	exploration	expenses.

Development	costs	include	additions	to	production	facilities	and	equipment	and	additions	to	development	wells,	including	those	in	progress.

The	following	table	sets	forth	costs	incurred	related	to	EOG's	oil	and	gas	activities	for	the	years	ended	December	31,	2018,	2017	and	2016:

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Acquisition\tCosts\tof\tProperties |  |  |  |  |
| Unproved\t(2) | $486,081 | $1,258 | $— | $487,339 |
| Proved\t(3) | 123,684 | — | — | 123,684 |
| Subtotal | 609,765 | 1,258 | — | 611,023 |
| Exploration\tCosts | 157,222 | 22,511 | 13,895 | 193,628 |
| Development\tCosts\t(4) | 5,605,264 | (12,863) | 22,628 | 5,615,029 |
| Total | $6,372,251 | $10,906 | $36,523 | $6,419,680 |
| 2017 |  |  |  |  |
| Acquisition\tCosts\tof\tProperties |  |  |  |  |
| Unproved\t(5) | $424,118 | $2,422 | $— | $426,540 |
| Proved\t(6) | 72,584 | — | — | 72,584 |
| Subtotal | 496,702 | 2,422 | — | 499,124 |
| Exploration\tCosts | 144,499 | 62,547 | 16,553 | 223,599 |
| Development\tCosts\t(7) | 3,590,899 | 109,491 | 16,297 | 3,716,687 |
| Total | $4,232,100 | $174,460 | $32,850 | $4,439,410 |
| 2016 |  |  |  |  |
| Acquisition\tCosts\tof\tProperties |  |  |  |  |
| Unproved\t(8) | $3,216,598 | $— | $36 | $3,216,634 |
| Proved\t(9) | 749,023 | — | — | 749,023 |
| Subtotal | 3,965,621 | — | 36 | 3,965,657 |
| Exploration\tCosts | 156,295 | 2,695 | 6,761 | 165,751 |
| Development\tCosts\t(10) | 2,252,713 | 72,147 | (10,984) | 2,313,876 |
| Total | $6,374,629 | $74,842 | $(4,187) | $6,445,284 |

(2) Includes	non-cash	unproved	leasehold	acquisition	costs	of	$291	million	related	to	property	exchanges.

(3) Includes	non-cash	proved	property	acquisition	costs	of	$71	million	related	to	property	exchanges.

(4) Includes	Asset	Retirement	Costs	of	$90	million,	$(12)	million	and	$(8)	million	for	the	United	States,	Trinidad	and	Other	International,	respectively.	Excludes	other	property, plant	and	equipment.

(8) Includes	non-cash	unproved	leasehold	acquisition	costs	of	$3,102	million	related	to	the	Yates	transaction.

(9) Includes	non-cash	proved	property	acquisition	costs	of	$732	million	related	to	the	Yates	transaction.

(10) Includes	Asset	Retirement	Costs	of	$25	million,	$(3)	million	and	$(42)	million	for	the	United	States,	Trinidad	and	Other	International,	respectively.		Excludes	other	property, plant	and	equipment.

Results	of	Operations	for	Oil	and	Gas	Producing	Activities	(1).	The	following	table	sets	forth	results	of	operations	for	oil	and	gas	producing	activities	for	the years	ended	December	31,	2018,	2017	and	2016:

|  | United<br>States | Trinidad | Other<br>International	(2) | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Crude\tOil\tand\tCondensate,\tNatural\tGas\tLiquids\tand\tNatural\tGas\tRevenues | $11,488,620 | $302,112 | $155,755 | $11,946,487 |
| Other | 89,708 | (49) | (24) | 89,635 |
| Total | 11,578,328 | 302,063 | 155,731 | 12,036,122 |
| Exploration\tCosts | 121,572 | 21,402 | 6,025 | 148,999 |
| Dry\tHole\tCosts | 4,983 | — | 422 | 5,405 |
| Transportation\tCosts | 742,792 | 3,236 | 848 | 746,876 |
| Gathering\tand\tProcessing\tCosts\t(3) | 404,471 | — | 32,502 | 436,973 |
| Production\tCosts | 1,924,504 | 33,506 | 70,073 | 2,028,083 |
| Impairments | 344,595 | — | 2,426 | 347,021 |
| Depreciation,\tDepletion\tand\tAmortization | 3,181,801 | 91,788 | 46,687 | 3,320,276 |
| Income\tBefore\tIncome\tTaxes | 4,853,610 | 152,131 | (3,252) | 5,002,489 |
| Income\tTax\tProvision | 1,086,077 | 12,170 | 1,898 | 1,100,145 |
| Results\tof\tOperations | $3,767,533 | $139,961 | $(5,150) | $3,902,344 |
| 2017 |  |  |  |  |
| Crude\tOil\tand\tCondensate,\tNatural\tGas\tLiquids\tand\tNatural\tGas\tRevenues | $7,570,768 | $284,673 | $52,450 | $7,907,891 |
| Other | 81,610 | 59 | (59) | 81,610 |
| Total | 7,652,378 | 284,732 | 52,391 | 7,989,501 |
| Exploration\tCosts | 113,334 | 26,245 | 5,763 | 145,342 |
| Dry\tHole\tCosts | 91 | — | 4,518 | 4,609 |
| Transportation\tCosts | 737,403 | 1,885 | 1,064 | 740,352 |
| Production\tCosts | 1,446,333 | 27,839 | 88,038 | 1,562,210 |
| Impairments | 477,223 | — | 2,017 | 479,240 |
| Depreciation,\tDepletion\tand\tAmortization | 3,157,056 | 115,174 | 24,536 | 3,296,766 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | 1,720,938 | 113,589 | (73,545) | 1,760,982 |
| Income\tTax\tProvision\t(Benefit) | 625,562 | 24,882 | (1,342) | 649,102 |
| Results\tof\tOperations | $1,095,376 | $88,707 | $(72,203) | $1,111,880 |
| 2016 |  |  |  |  |
| Crude\tOil\tand\tCondensate,\tNatural\tGas\tLiquids\tand\tNatural\tGas\tRevenues | $5,177,989 | $243,708 | $75,046 | $5,496,743 |
| Other | 81,386 | (8) | 25 | 81,403 |
| Total | 5,259,375 | 243,700 | 75,071 | 5,578,146 |
| Exploration\tCosts | 115,990 | 2,647 | 6,316 | 124,953 |
| Dry\tHole\tCosts | 10,529 | — | 128 | 10,657 |
| Transportation\tCosts | 753,791 | 1,181 | 9,134 | 764,106 |
| Production\tCosts | 1,163,827 | 27,113 | 63,073 | 1,254,013 |
| Impairments | 611,297 | 7,773 | 1,197 | 620,267 |
| Depreciation,\tDepletion\tand\tAmortization | 3,249,792 | 145,440 | 42,052 | 3,437,284 |
| Income\t(Loss)\tBefore\tIncome\tTaxes | (645,851) | 59,546 | (46,829) | (633,134) |
| Income\tTax\tProvision\t(Benefit) | (230,377) | 5,526 | (1,562) | (226,413) |
| Results\tof\tOperations | $(415,474) | $54,020 | $(45,267) | $(406,721) |

(1) Excludes	gains	or	losses	on	the	mark-to-market	of	financial	commodity	derivative	contracts,	gains	or	losses	on	sales	of	reserves	and	related	assets,	interest	charges	and	general corporate	expenses	for	each	of	the	three	years	in	the	period	ended	December	31,	2018.

(3) Effective	January	1,	2018,	EOG	adopted	the	provisions	of	Accounting	Standards	Update	(ASU)	2014-09,	"Revenue	From	Contracts	With	Customers"	(ASU	2014-09).	In connection	with	the	adoption	of	ASU	2014-09,	EOG	presents	natural	gas	processing	fees	relating	to	certain	processing	and	marketing	agreements	within	its	United	States segment	as	Gathering	and	Processing	Costs	instead	of	as	a	deduction	to	Natural	Gas	Revenues.	There	was	no	impact	to	operating	income	or	net	income	resulting	from	changes	to the	presentation	of	natural	gas	processing	fees	(see	Note	1	to	Consolidated	Financial	Statements).

The	 following	 table	 sets	 forth	 production	 costs	 per	 barrel	 of	 oil	 equivalent,	 excluding	 severance/production	 and	 ad	 valorem taxes,	 for the	 years	 ended December	31,	2018,	2017	and	2016:

|  | United<br>States | Trinidad | Other<br>International	(1) | Composite |
| :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2018 | $4.84 | $1.67 | $20.19 | $4.84 |
| Year\tEnded\tDecember\t31,\t2017 | $4.58 | $1.39 | $50.86 | $4.66 |
| Year\tEnded\tDecember\t31,\t2016 | $4.58 | $1.23 | $22.43 | $4.48 |

Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	Relating	to	Proved	Oil	and	Gas	Reserves. 	The	following	information	has	been	developed utilizing	procedures	prescribed	by	the	Extractive	Industries	-	Oil	and	Gas	Topic	of	the	ASC	and	based	on	crude	oil,	NGL	and	natural	gas	reserves	and	production volumes	estimated	by	the	Engineering	and	Acquisitions	Department	of	EOG.		The	estimates	were	based	on	a	12-month	average	for	commodity	prices	for	the	years	2018, 2017	and	2016.		The	following	information	may	be	useful	for	certain	comparative	purposes,	but	should	not	be	solely	relied	upon	in	evaluating	EOG	or	its	performance. Further,	 information	 contained	 in	 the	 following	 table	 should	 not	 be	 considered	 as	 representative	 of	 realistic	 assessments	 of	 future	 cash	 flows,	 nor	 should	 the Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	be	viewed	as	representative	of	the	current	value	of	EOG.

The	future	cash	flows	presented	below	are	based	on	sales	prices,	cost	rates	and	statutory	income	tax	rates	in	existence	as	of	the	date	of	the	projections.		It	is expected	that	material	revisions	to	some	estimates	of	crude	oil,	NGL	and	natural	gas	reserves	may	occur	in	the	future,	development	and	production	of	the	reserves	may occur	in	periods	other	than	those	assumed,	and	actual	prices	realized	and	costs	incurred	may	vary	significantly	from	those	used.

Management	does	not	rely	upon	the	following	information	in	making	investment	and	operating	decisions.		Such	decisions	are	based	upon	a	wide	range	of factors,	including	estimates	of	probable	and	possible	reserves	as	well	as	proved	reserves,	and	varying	price	and	cost	assumptions	considered	more	representative	of	a range	of	possible	economic	conditions	that	may	be	anticipated.

The	following	table	sets	forth	the	standardized	measure	of	discounted	future	net	cash	flows	from	projected	production	of	EOG's	oil	and	gas	reserves	for	the years	ended	December	31,	2018,	2017	and	2016:

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Future\tcash\tinflows\t(2) | $133,066,375 | $749,695 | $303,620 | $134,119,690 |
| Future\tproduction\tcosts | (42,351,174) | (204,444) | (99,024) | (42,654,642) |
| Future\tdevelopment\tcosts | (16,577,794) | (78,199) | (11,900) | (16,667,893) |
| Future\tincome\ttaxes | (14,756,011) | (174,382) | (31,748) | (14,962,141) |
| Future\tnet\tcash\tflows | 59,381,396 | 292,670 | 160,948 | 59,835,014 |
| Discount\tto\tpresent\tvalue\tat\t10%\tannual\trate | (27,348,744) | (26,832) | (33,483) | (27,409,059) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\noil\tand\tgas\treserves | $32,032,652 | $265,838 | $127,465 | $32,425,955 |
| 2017 |  |  |  |  |
| Future\tcash\tinflows\t(3) | $83,652,363 | $904,141 | $664,560 | $85,221,064 |
| Future\tproduction\tcosts | (32,018,812) | (239,213) | (311,383) | (32,569,408) |
| Future\tdevelopment\tcosts | (13,395,873) | (84,379) | (58,543) | (13,538,795) |
| Future\tincome\ttaxes | (5,948,453) | (195,855) | (16,233) | (6,160,541) |
| Future\tnet\tcash\tflows | 32,289,225 | 384,694 | 278,401 | 32,952,320 |
| Discount\tto\tpresent\tvalue\tat\t10%\tannual\trate | (14,532,290) | (52,267) | (40,103) | (14,624,660) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\noil\tand\tgas\treserves | $17,756,935 | $332,427 | $238,298 | $18,327,660 |
| 2016 |  |  |  |  |
| Future\tcash\tinflows\t(4) | $57,913,314 | $524,523 | $402,587 | $58,840,424 |
| Future\tproduction\tcosts | (27,625,833) | (165,757) | (227,293) | (28,018,883) |
| Future\tdevelopment\tcosts | (12,602,699) | (103,631) | (35,602) | (12,741,932) |
| Future\tincome\ttaxes | (3,151,319) | (60,001) | — | (3,211,320) |
| Future\tnet\tcash\tflows | 14,533,463 | 195,134 | 139,692 | 14,868,289 |
| Discount\tto\tpresent\tvalue\tat\t10%\tannual\trate | (6,039,736) | (9,384) | (7,012) | (6,056,132) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\noil\tand\tgas\treserves |  |  |  |  |
|  | $8,493,727 | $185,750 | $132,680 | $8,812,157 |

(2) Estimated	crude	oil	prices	used	to	calculate	2018	future	cash	inflows	for	the	United	States,	Trinidad	and	Other	International	were	$68.54,	$55.66	 and	$61.66,	respectively. Estimated	NGL	price	used	to	calculate	2018	future	cash	inflows	for	the	United	States	was	$27.83.	Estimated	natural	gas	prices	used	to	calculate	2018	future	cash	inflows	for	the United	States,	Trinidad	and	Other	International	were	$2.50,	$3.06	and	$4.88,	respectively.

(3) Estimated	crude	oil	prices	used	to	calculate	2017	future	cash	inflows	for	the	United	States,	Trinidad	and	Other	International	were	$49.21,	$41.87	 and	$50.06,	respectively. Estimated	NGL	price	used	to	calculate	2017	future	cash	inflows	for	the	United	States	was	$23.51.	Estimated	natural	gas	prices	used	to	calculate	2017	future	cash	inflows	for	the United	States,	Trinidad	and	Other	International	were	$1.96,	$2.76	and	$5.16,	respectively.

(4) Estimated	crude	oil	prices	used	to	calculate	2016	future	cash	inflows	for	the	United	States,	Trinidad	and	Other	International	were	$40.70,	$34.79	 and	$39.55,	respectively. Estimated	NGL	price	used	to	calculate	2016	future	cash	inflows	for	the	United	States	was	$14.69.	Estimated	natural	gas	prices	used	to	calculate	2016	future	cash	inflows	for	the United	States,	Trinidad	and	Other	International	were	$1.40,	$1.76	and	$4.84,	respectively.

Changes	in	Standardized	Measure	of	Discounted	Future	Net	Cash	Flows.		The	following	table	sets	forth	the	changes	in	the	standardized	measure	of	discounted future	net	cash	flows	at	December	31,	for	each	of	the	three	years	in	the	period	ended	December	31,	2018:

|  | United<br>States | Trinidad | Other<br>International	(1) | Total |
| :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2015 | $8,965,467 | $381,124 | $274,805 | $9,621,396 |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tcosts | (3,260,372) | (215,414) | (2,839) | (3,478,625) |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | (3,352,802) | (182,876) | (143,924) | (3,679,602) |
| Extensions,\tdiscoveries,\tadditions\tand\timproved\trecovery,\tnet\tof\trelated\tcosts | 865,066 | 42,201 | — | 907,267 |
| Development\tcosts\tincurred | 1,207,000 | 3,900 | 19,100 | 1,230,000 |
| Revisions\tof\testimated\tdevelopment\tcost | 2,092,769 | 22,596 | 6,343 | 2,121,708 |
| Revisions\tof\tprevious\tquantity\testimates | 1,013,753 | 36,648 | 2,619 | 1,053,020 |
| Accretion\tof\tdiscount | 970,388 | 56,566 | 27,481 | 1,054,435 |
| Net\tchange\tin\tincome\ttaxes | 738,416 | 129,622 | — | 868,038 |
| Purchases\tof\treserves\tin\tplace | 377,872 | — | — | 377,872 |
| Sales\tof\treserves\tin\tplace | (375,793) | — | — | (375,793) |
| Changes\tin\ttiming\tand\tother | (748,037) | (88,617) | (50,905) | (887,559) |
| December\t31,\t2016 | 8,493,727 | 185,750 | 132,680 | 8,812,157 |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tcosts | (5,387,031) | (254,948) | 36,649 | (5,605,330) |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | 6,606,908 | 436,969 | 77,668 | 7,121,545 |
| Extensions,\tdiscoveries,\tadditions\tand\timproved\trecovery,\tnet\tof\trelated\tcosts | 3,644,041 | 270,255 | 43,952 | 3,958,248 |
| Development\tcosts\tincurred | 1,435,600 | 4,700 | — | 1,440,300 |
| Revisions\tof\testimated\tdevelopment\tcost | (114,464) | 9,683 | (20,096) | (124,877) |
| Revisions\tof\tprevious\tquantity\testimates | 2,460,498 | (58,373) | 36,146 | 2,438,271 |
| Accretion\tof\tdiscount | 849,373 | 24,066 | 13,268 | 886,707 |
| Net\tchange\tin\tincome\ttaxes | (1,918,989) | (114,575) | (10,099) | (2,043,663) |
| Purchases\tof\treserves\tin\tplace | 30,362 | — | — | 30,362 |
| Sales\tof\treserves\tin\tplace | (76,527) | — | — | (76,527) |
| Changes\tin\ttiming\tand\tother | 1,733,437 | (171,100) | (71,870) | 1,490,467 |
| December\t31,\t2017 | 17,756,935 | 332,427 | 238,298 | 18,327,660 |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tcosts | (8,416,853) | (265,370) | (52,399) | (8,734,622) |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | 12,750,466 | 84,353 | 21,610 | 12,856,429 |
| Extensions,\tdiscoveries,\tadditions\tand\timproved\trecovery,\tnet\tof\trelated\tcosts | 8,418,666 | — | 12,287 | 8,430,953 |
| Development\tcosts\tincurred | 2,732,560 | — | 12,600 | 2,745,160 |
| Revisions\tof\testimated\tdevelopment\tcost | (410,741) | 4,030 | (3,814) | (410,525) |
| Revisions\tof\tprevious\tquantity\testimates | (173,084) | 39,608 | 31,750 | (101,726) |
| Accretion\tof\tdiscount | 1,967,592 | 50,191 | 24,839 | 2,042,622 |
| Net\tchange\tin\tincome\ttaxes | (4,965,373) | 3,844 | (11,529) | (4,973,058) |
| Purchases\tof\treserves\tin\tplace | 116,887 | — | — | 116,887 |
| Sales\tof\treserves\tin\tplace | (35,874) | — | (82,058) | (117,932) |
| Changes\tin\ttiming\tand\tother | 2,291,471 | 16,755 | (64,119) | 2,244,107 |
| December\t31,\t2018 | $32,032,652 | $265,838 | $127,465 | $32,425,955 |

# SUPPLEMENTAL	INFORMATION	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	(Concluded)

# Unaudited	Quarterly	Financial	Information

| Quarter	Ended | Mar	31 | Jun	30 | Sep	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Operating\tRevenues\tand\tOther | $3,681,162 | $4,238,077 | $4,781,624 | $4,574,536 |
| Operating\tIncome | $874,588 | $964,931 | $1,506,687 | $1,123,140 |
| Income\tBefore\tIncome\tTaxes | $813,359 | $892,936 | $1,446,363 | $1,088,340 |
| Income\tTax\tProvision | 174,770 | 196,205 | 255,411 | 195,572 |
| Net\tIncome | $638,589 | $696,731 | $1,190,952 | $892,768 |
| Net\tIncome\tPer\tShare\t(1) |  |  |  |  |
| Basic | $1.11 | $1.21 | $2.06 | $1.55 |
| Diluted | $1.10 | $1.20 | $2.05 | $1.54 |
| Average\tNumber\tof\tCommon\tShares |  |  |  |  |
| Basic | 575,775 | 576,135 | 577,254 | 577,035 |
| Diluted | 579,726 | 580,375 | 581,559 | 580,288 |
| 2017 |  |  |  |  |
| Operating\tRevenues\tand\tOther | $2,610,565 | $2,612,472 | $2,644,844 | $3,340,439 |
| Operating\tIncome | $107,746 | $127,908 | $214,836 | $475,912 |
| Income\tBefore\tIncome\tTaxes | $39,382 | $62,467 | $145,980 | $413,353 |
| Income\tTax\tProvision\t(Benefit)\t(2) | 10,865 | 39,414 | 45,439 | (2,017,115) |
| Net\tIncome | $28,517 | $23,053 | $100,541 | $2,430,468 |
| Net\tIncome\tPer\tShare\t(1) |  |  |  |  |
| Basic | $0.05 | $0.04 | $0.17 | $4.22 |
| Diluted | $0.05 | $0.04 | $0.17 | $4.20 |
| Average\tNumber\tof\tCommon\tShares |  |  |  |  |
| Basic | 573,935 | 574,439 | 574,783 | 575,394 |
| Diluted | 578,593 | 578,483 | 578,736 | 579,203 |

(1) The	sum	of	quarterly	net	income	per	share	may	not	agree	with	total	year	net	income	per	share	as	each	quarterly	computation	is	based	on	the	weighted	average	of	common	shares outstanding.

(2) Includes	an	income	tax	benefit	of	approximately	$2.2	billion	for	the	quarter	ended	December	31,	2017,	primarily	due	to	the	enactment	of	the	Tax	Cuts	and	Jobs	Act	in	December 2017.	See	Note	6	to	the	Consolidated	Financial	Statements.

# EXHIBITS

Exhibits	not	incorporated	herein	by	reference	to	a	prior	filing	are	designated	by	(i)	an	asterisk	(*)	and	are	filed	herewith;	or	(ii)	a	pound	sign	(#)	and	are	not filed	herewith,	and,	pursuant	to	Item	601(b)(4)(iii)(A)	of	Regulation	S-K,	the	registrant	hereby	agrees	to	furnish	a	copy	of	such	exhibit	to	the	United	States	Securities	and Exchange	Commission	(SEC)	upon	request.

- Certificate	of	Amendment	of	Restated	Certificate	of	Incorporation,	dated	May	5,	1993	(Exhibit	4.1(b)	to	EOG's	Registration	Statement	on Form	S-8,	SEC	File	No.	33-52201,	filed	February	8,	1994).

- Certificate	of	Amendment	of	Restated	Certificate	of	Incorporation,	dated	June	14,	1994	(Exhibit	4.1(c)	to	EOG's	Registration	Statement	on Form	S-8,	SEC	File	No.	33-58103,	filed	March	15,	1995).

- Certificate	of	Amendment	of	Restated	Certificate	of	Incorporation,	dated	June	11,	1996	(Exhibit	3(d)	to	EOG's	Registration	Statement	on Form	S-3,	SEC	File	No.	333-09919,	filed	August	9,	1996).

- Certificate	of	Amendment	of	Restated	Certificate	of	Incorporation,	dated	May	7,	1997	(Exhibit	3(e)	to	EOG's	Registration	Statement	on Form	S-3,	SEC	File	No.	333-44785,	filed	January	23,	1998).

- Certificate	of	Designations	of	Series	E	Junior	Participating	Preferred	Stock,	dated	February	14,	2000	(Exhibit	2	to	EOG's	Registration Statement	on	Form	8-A,	SEC	File	No.	001-09743,	filed	February	18,	2000).

- Certificate	of	Elimination	of	the	Fixed	Rate	Cumulative	Perpetual	Senior	Preferred	Stock,	Series	A,	dated	September	13,	2000	(Exhibit 3.1(j)	to	EOG's	Registration	Statement	on	Form	S-3,	SEC	File	No.	333-46858,	filed	September	28,	2000).

- Certificate	of	Elimination	of	the	Flexible	Money	Market	Cumulative	Preferred	Stock,	Series	C,	dated	September	13,	2000	(Exhibit	3.1(k)	to EOG's	Registration	Statement	on	Form	S-3,	SEC	File	No.	333-46858,	filed	September	28,	2000).

- Certificate	of	Elimination	of	the	Flexible	Money	Market	Cumulative	Preferred	Stock,	Series	D,	dated	February	24,	2005	(Exhibit	3.1(k)	to EOG's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2004)	(SEC	File	No.	001-09743).

- Amended	Certificate	of	Designations	of	Series	E	Junior	Participating	Preferred	Stock,	dated	March	7,	2005	(Exhibit	3.1(m)	to	EOG's	Annual Report	on	Form	10-K	for	the	year	ended	December	31,	2007)	(SEC	File	No.	001-09743).

- Certificate	of	Elimination	of	Fixed	Rate	Cumulative	Perpetual	Senior	Preferred	Stock,	Series	B,	dated	March	6,	2008	(Exhibit	3.1	to	EOG's Current	Report	on	Form	8-K,	filed	March	6,	2008)	(SEC	File	No.	001-09743).

- Specimen	of	Certificate	evidencing	EOG's	Common	Stock	(Exhibit	3.3	to	EOG's	Annual	Report	on	Form	10-K	for	the	year	ended	December 31,	1999)	(SEC	File	No.	001-09743).

- Indenture,	dated	as	of	September	1,	1991,	between	Enron	Oil	&	Gas	Company	(predecessor	to	EOG)	and	The	Bank	of	New	York	Mellon Trust	Company,	N.A.	(as	successor	in	interest	to	JPMorgan	Chase	Bank,	N.A.	(formerly,	Texas	Commerce	Bank	National	Association)),	as Trustee	(Exhibit	4(a)	to	EOG's	Registration	Statement	on	Form	S-3,	SEC	File	No.	33-42640,	filed	in	paper	format	on	September	6,	1991).

- First	Amendment	to	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan,	dated	effective	as	of	September	4,	2008	(Exhibit	10.1 to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2008)	(SEC	File	No.	001-09743).

- Second	Amendment	to	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan,	dated	effective	as	of	January	1,	2010	(Exhibit	10.1 to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2010)	(SEC	File	No.	001-09743).

- Third	Amendment	to	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan,	dated	effective	as	of	September	26,	2012	(Exhibit 10.1	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2012)	(SEC	File	No.	001-09743).

- Form	of	Stock	Option	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(applicable	to	grants	made	prior	to February	23,	2011)	(Exhibit	10.2	to	EOG's	Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001-09743).

- Form	of	Stock	Option	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(applicable	to	grants	made	on	or	after February	23,	2011)	(Exhibit	10.3	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2011)	(SEC	File	No.	001- 09743).

- Form	of	Stock-Settled	Stock	Appreciation	Right	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(applicable to	grants	made	prior	to	February	23,	2011)	(Exhibit	10.3	to	EOG's	Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001- 09743).

- Form	of	Stock-Settled	Stock	Appreciation	Right	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(applicable to	grants	made	on	or	after	February	23,	2011)	(Exhibit	10.4	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2011) (SEC	File	No.	001-09743).

- Form	 of	 Nonemployee	 Director	 Stock-Settled	 Stock	 Appreciation	 Right	 Agreement	 for	 EOG	 Resources,	 Inc.	 2008	 Omnibus	 Equity Compensation	Plan	(Exhibit	10.4	to	EOG's	Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Award	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(Exhibit	10.5	to	EOG's Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Unit	Award	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(Exhibit	10.6	to	EOG's Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001-09743).

- Form	of	Nonemployee	Director	Restricted	Stock	Award	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (Exhibit	10.7	to	EOG's	Current	Report	on	Form	8-K,	filed	May	14,	2008)	(SEC	File	No.	001-09743).

- Form	of	Nonemployee	Director	Restricted	Stock	Unit	Award	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (Exhibit	10.3	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	June	30,	2012)	(SEC	File	No.	001-09743).

- Form	of	Performance	Unit	Award	Agreement	for	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan	(Exhibit	10.4	to	EOG's Current	Report	on	Form	8-K,	filed	October	1,	2012)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	prior	to	September	25,	2017)	(Exhibit	4.5	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No.	333- 188352,	filed	May	3,	2013).

- Form	of	Restricted	Stock	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	on	or	after	September	25,	2017	and	prior	to	September	27,	2018)	(Exhibit	10.1	to	EOG's	Current	Report	on	Form 8-K,	filed	September	29,	2017)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	effective	September	27,	2018	and	subsequent	grants)	(Exhibit	10.1	to	EOG's	Quarterly	Report	on	Form	10-Q	for the	quarter	ended	September	30,	2018)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	prior	to	September	25,	2017)	(Exhibit	4.6	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No.	333- 188352,	filed	May	3,	2013).

- Form	of	Restricted	Stock	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	on	or	after	September	25,	2017	and	prior	to	September	27,	2018)	(Exhibit	10.2	to	EOG's	Current	Report	on	Form 8-K,	filed	September	29,	2017)	(SEC	File	No.	001-09743).

- Form	of	Restricted	Stock	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	effective	September	27,	2018	and	subsequent	grants)	(Exhibit	10.2	to	EOG's	Quarterly	Report	on	Form	10-Q	for the	quarter	ended	September	30,	2018)	(SEC	File	No.	001-09743).

- Form	 of	 Stock-Settled	 Stock	Appreciation	 Right	Agreement	 for	Amended	 and	 Restated	 EOG	 Resources,	 Inc.	 2008	 Omnibus	 Equity Compensation	Plan	(applicable	to	grants	made	prior	to	September	25,	2017)	(Exhibit	4.7	to	EOG's	Registration	Statement	on	Form	S-8,	SEC File	No.	333-188352,	filed	May	3,	2013).

- Form	 of	 Stock	 Settled	 Stock	Appreciation	 Right	Agreement	 for	Amended	 and	 Restated	 EOG	 Resources,	 Inc.	 2008	 Omnibus	 Equity Compensation	Plan	(applicable	to	grants	made	effective	September	25,	2017	and	subsequent	grants)	(Exhibit	10.4	to	EOG's	Current	Report on	Form	8-K,	filed	September	29,	2017)	(SEC	File	No.	001-09743).

- Form	of	Performance	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	annual	grants	made	prior	to	September	22,	2014)	(Exhibit	4.8	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No. 333-188352,	filed	May	3,	2013).

- Form	of	Performance	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	annual	grants	made	on	or	after	September	22,	2014	and	prior	to	September	27,	2016)	(Exhibit	10.1	to	EOG's	Quarterly	Report on	Form	10-Q	for	the	quarter	ended	September	30,	2014)	(SEC	File	No.	001-09743).

- Form	of	Performance	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	specific	grants	made	effective	December	13,	2016)	(Exhibit	10.1	to	EOG's	Current	Report	on	Form	8-K,	filed	December	19, 2016)	(SEC	File	No.	001-09743).

- Form	of	Performance	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	annual	grants	made	on	or	after	September	25,	2017	and	prior	to	September	27,	2018)	(Exhibit	10.3	to	EOG's	Current	Report on	Form	8-K,	filed	September	29,	2017)	(SEC	File	No.	001-09743).

- Form	of	Performance	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (applicable	to	grants	made	effective	September	27,	2018	and	subsequent	grants)	(Exhibit	10.3	to	EOG's	Quarterly	Report	on	Form	10-Q	for the	quarter	ended	September	30,	2018)	(SEC	File	No.	001-09743).

- Form	of	Performance	Stock	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus	Equity	Compensation	Plan (Exhibit	4.9	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No.	333-188352,	filed	May	3,	2013).

- Form	of	Non-Employee	Director	Restricted	Stock	Unit	Award	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008	Omnibus Equity	Compensation	Plan	(Exhibit	4.10	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No.	333-188352,	filed	May	3,	2013).

- Form	of	Non-Employee	Director	Stock-Settled	Stock	Appreciation	Right	Agreement	for	Amended	and	Restated	EOG	Resources,	Inc.	2008 Omnibus	Equity	Compensation	Plan	(Exhibit	4.11	to	EOG's	Registration	Statement	on	Form	S-8,	SEC	File	No.	333-188352,	filed	May	3, 2013).

- EOG	Resources,	Inc.	409A	Deferred	Compensation	Plan	-	Nonqualified	Supplemental	Deferred	Compensation	Plan	-	Plan	Document, effective	as	of	December	16,	2008	(Exhibit	10.2(a)	to	EOG's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2008)	(SEC	File No.	001-09743).

- EOG	Resources,	Inc.	409A	Deferred	Compensation	Plan	-	Nonqualified	Supplemental	Deferred	Compensation	Plan	-	Adoption	Agreement, originally	dated	as	of	December	16,	2008	(and	as	amended	through	February	24,	2012	(including	an	amendment	to	Item	7	thereof,	effective January	1,	2012,	with	respect	to	the	deferral	of	restricted	stock	units))	(Exhibit	10.2(b)	to	EOG's	Annual	Report	on	Form	10-K	for	the	year ended	December	31,	2011)	(originally	filed	as	Exhibit	10.2(b)	to	EOG's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31, 2008)	(SEC	File	No.	001-09743).

- First	Amendment	to	the	EOG	Resources,	Inc.	409A	Deferred	Compensation	Plan,	effective	as	of	January	1,	2013	(Exhibit	10.8	to	EOG's Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- Amendment	2	to	the	EOG	Resources,	Inc.	409A	Deferred	Compensation	Plan,	effective	as	of	January	1,	2018.

- First	Amendment	to	Change	of	Control	Agreement	between	EOG	and	William	R.	Thomas,	effective	as	of	September	13,	2011	(Exhibit	10.2 to	EOG's	Current	Report	on	Form	8-K,	filed	September	13,	2011)	(SEC	File	No.	001-09743).

- Second	Amendment	to	Change	of	Control	Agreement	between	EOG	and	William	R.	Thomas,	effective	as	of	September	4,	2013	(Exhibit 10.2	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- First	Amendment	to	Amended	and	Restated	Change	of	Control	Agreement	between	EOG	and	Gary	L.	Thomas,	effective	as	of	April	30, 2009	(Exhibit	10.3(b)	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2009)	(SEC	File	No.	001-09743).

- Second	Amendment	to	Amended	and	Restated	Change	of	Control	Agreement	between	EOG	and	Gary	L.	Thomas,	effective	as	of	September 13,	2011	(Exhibit	10.3	to	EOG's	Current	Report	on	Form	8-K,	filed	September	13,	2011)	(SEC	File	No.	001-09743).

- Third	Amendment	to	Amended	and	Restated	Change	of	Control	Agreement	between	EOG	and	Gary	L.	Thomas,	effective	as	of	September	4, 2013	(Exhibit	10.3	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- First	Amendment	to	Amended	and	Restated	Change	of	Control	Agreement	between	EOG	and	Timothy	K.	Driggers,	effective	as	of	April	30, 2009	(Exhibit	10.5	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2009)	(SEC	File	No.	001-09743).

- Second	Amendment	to	Amended	and	Restated	Change	of	Control	Agreement	between	EOG	and	Timothy	K.	Driggers,	effective	as	of September	13,	2011	(Exhibit	10.4	to	EOG's	Current	Report	on	Form	8-K,	filed	September	13,	2011)	(SEC	File	No.	001-09743).

- First	Amendment	to	Change	of	Control	Agreement	between	EOG	and	Michael	P.	Donaldson,	effective	as	of	September	4,	2013	(Exhibit 10.7	to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- First	Amendment	to	Change	of	Control	Agreement	between	EOG	and	Lloyd	W.	Helms,	Jr.,	effective	as	of	September	4,	2013	(Exhibit	10.4 to	EOG's	Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- Change	of	Control	Agreement	by	and	between	EOG	and	David	W.	Trice,	effective	as	of	September	4,	2013	(Exhibit	10.5 to	EOG's Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	September	30,	2013)	(SEC	File	No.	001-09743).

- Agreement,	dated	as	of	December	12,	2018,	by	and	between	EOG	and	David	W.	Trice	(terminating	the	Change	of	Control	Agreement, effective	as	of	December	12,	2018).

- Change	of	Control	Agreement	by	and	between	EOG	and	Kenneth	W.	Boedeker,	effective	as	of	December	19,	2018.

- First	Amendment	to	the	EOG	Resources,	Inc.	Change	of	Control	Severance	Plan,	effective	as	of	April	30,	2009	(Exhibit	10.6	to	EOG's Quarterly	Report	on	Form	10-Q	for	the	quarter	ended	March	31,	2009)	(SEC	File	No.	001-09743).

- EOG	Resources,	Inc.	Amended	and	Restated	Executive	Officer	Annual	Bonus	Plan	(Exhibit	10.4	to	EOG's	Quarterly	Report	on	Form	10-Q for	the	quarter	ended	March	31,	2010)	(SEC	File	No.	001-09743).

										10.15 - Revolving	Credit	Agreement,	dated	as	of	July	21,	2015,	among	EOG,	JPMorgan	Chase	Bank,	N.A.,	as	Administrative	Agent,	the	financial institutions	as	bank	parties	thereto,	and	the	other	parties	thereto	(Exhibit	10.1	to	EOG's	Current	Report	on	Form	8-K,	filed	July	24,	2015) (SEC	File	No.	001-09743).

*								32.2 - Section	906	Certification	of	Annual	Report	of	Principal	Financial	Officer.

# *Exhibits	filed	herewith

**Annexes,	exhibit	and	disclosure	schedules	have	been	omitted	pursuant	to	Item	601(b)(2)	of	Regulation	S-K.	A	list	of	the	annexes	and	exhibit	is	included	after	the	table	of	contents in	the	Agreement	and	Plan	of	Merger.	The	disclosure	schedules	set	forth	various	matters	in	respect	of	the	representations,	warranties,	covenants	and	other	provisions	of	the	Agreement and	Plan	of	Merger.	The	registrant	agrees	to	furnish	a	supplemental	copy	of	any	such	omitted	annexes,	exhibit	or	disclosure	schedules	to	the	SEC	upon	request.

***Attached	as	Exhibit	101	to	this	report	are	the	following	documents	formatted	in	XBRL	(Extensible	Business	Reporting	Language):	(i)	the	Consolidated	Statements	of	Income (Loss)	and	Comprehensive	Income	(Loss)	for	Each	of	the	Three	Years	in	the	Period	Ended	December	31,	2018,	(ii)	the	Consolidated	Balance	Sheets	-	December	31,	2018	and	2017, (iii)	the	Consolidated	Statements	of	Stockholders'	Equity	for	Each	of	the	Three	Years	in	the	Period	Ended	December	31,	2018,	(iv)	the	Consolidated	Statements	of	Cash	Flows	for Each	of	the	Three	Years	in	the	Period	Ended	December	31,	2018	and	(v)	the	Notes	to	Consolidated	Financial	Statements.

+	Management	contract,	compensatory	plan	or	arrangement

Pursuant	to	the	requirements	of	Section	13	or	15(d)	of	the	Securities	Exchange	Act	of	1934,	as	amended,	the	registrant	has	duly	caused	this	report	to	be	signed on	its	behalf	by	the	undersigned,	thereunto	duly	authorized.

(Registrant)

Timothy	K.	Driggers

Executive	Vice	President	and	Chief	Financial	Officer

(Principal	Financial	Officer	and	Duly	Authorized	Officer)

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	as	amended,	this	report	has	been	signed	below	by	the	following	persons	on	behalf	of	the registrant	and	in	the	capacities	with	EOG	Resources,	Inc.	indicated	and	on	the	26th	day	of	February,	2019.

/s/	ANN	D.	JANSSEN

(Ann	D.	Janssen)

(Janet	F.	Clark)

(Charles	R.	Crisp)

Senior	Vice	President	and	Chief	Accounting	Officer (Principal	Accounting	Officer)

# Director

* Director (Robert	P.	Daniels) * Director (James	C.	Day) * Director (C.	Christopher	Gaut) * Director (Julie	J.	Robertson) * Director (Donald	F.	Textor)

(Frank	G.	Wisner)

/s/	MICHAEL	P.	DONALDSON

(Michael	P.	Donaldson)

(Attorney-in-fact	for	persons	indicated)



Question: considering the year 2018 , what is the percentage of unrecognized tax benefits that may have an earnings impact?
Calculation: unrecognized_tax_benefits = 12
total_tax_benefits = 29
percent_unrecognized = unrecognized_tax_benefits / total_tax_benefits
answer = percent_unrecognized * 100
Answer: 41.38%