Table	of	Contents

Index	to	Financial	Statements

# UNITED	STATES

# SECURITIES	AND	EXCHANGE	COMMISSION

# (Mark	One)

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

For	the	fiscal	year	ended	December	31,	2018

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

# DEVON	ENERGY	CORPORATION

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	or	other	jurisdiction	of	incorporation	or	organization)

333	West	Sheridan	Avenue,	Oklahoma	City,	Oklahoma

(Address	of	principal	executive	offices)

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

(Zip	code)

Registrant's	telephone	number,	including	area	code:

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

Title	of	each	class

Name	of	each	exchange	on	which	registered

Common	stock,	par	value	$0.10	per	share The	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		 ☒					No		☐

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

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		☒				No		☐

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		☒				No		☐

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 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.				☒

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 	 ☑ Accelerated	filer 	 ☐ Non-accelerated	filer 	 ☐

Smaller	reporting	company 	 ☐ Emerging	growth	company 	 ☐

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.			☐

Indicate	by	check	mark	whether	the	registrant	is	a	shell	company	(as	defined	in	Rule	12b-2	of	the	Act).				Yes		 ☐				No		☒

The	aggregate	market	value	of	the	voting	common	stock	held	by	non-affiliates	of	the	registrant	as	of	June	29,	2018	was	approximately	$ 22.5	billion,	based	upon	the	closing	price	of	$43.96 per	share	as	reported	by	the	New	York	Stock	Exchange	on	such	date.	On	February	6,	2019,	438.3	million	shares	of	common	stock	were	outstanding.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

Portions	of	Registrant's	definitive	Proxy	Statement	relating	to	Registrant's	2019	annual	meeting	of	stockholders	have	been	incorporated	by	reference	in	Part	III	of	this	Annual	Report	on	Form	10-K.

| Table	of	Contents<br>Index	to	Financial	Statements |  |
| :--- | :--- |
| DEVON\tENERGY\tCORPORATION |  |
| FORM\t10-K |  |
| TABLE\tOF\tCONTENTS |  |
| PART\tI | 6 |
| Items\t1\tand\t2.\tBusiness\tand\tProperties | 6 |
| Item\t1A.\t\tRisk\tFactors | 14 |
| Item\t1B.\t\tUnresolved\tStaff\tComments | 21 |
| Item\t3.\t\t\t\t\tLegal\tProceedings | 21 |
| Item\t4.\t\t\t\t\tMine\tSafety\tDisclosures | 21 |
| PART\tII | 22 |
| Item\t5.\t\t\t\t\tMarket\tfor\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 22 |
| Item\t6.\t\t\t\t\tSelected\tFinancial\tData | 24 |
| Item\t7.\t\t\t\t\tManagement's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 25 |
| Item\t7A.\t\tQuantitative\tand\tQualitative\tDisclosures\tabout\tMarket\tRisk | 49 |
| Item\t8.\t\t\t\t\tFinancial\tStatements\tand\tSupplementary\tData | 50 |
| Item\t9.\t\t\t\t\tChanges\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | 109 |
| Item\t9A.\t\tControls\tand\tProcedures | 109 |
| Item\t9B.\t\tOther\tInformation | 109 |
| PART\tIII | 110 |
| Item\t10.\t\t\tDirectors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | 110 |
| Item\t11.\t\t\tExecutive\tCompensation | 110 |
| Item\t12.\t\t\tSecurity\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | 110 |
| Item\t13.\t\t\tCertain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | 110 |
| Item\t14.\t\t\tPrincipal\tAccountant\tFees\tand\tServices | 110 |
| PART\tIV | 111 |
| Item\t15.\t\t\tExhibits\tand\tFinancial\tStatement\tSchedules | 111 |
| Item\t16.\t\t\tForm\t10-K\tSummary | 116 |
| Signatures | 117 |

# DEFINITIONS

Unless	the	context	otherwise	indicates,	references	to	"us,"	"we,"	"our,"	"ours,"	"Devon,"	the	"Company"	and	"Registrant"	refer	to	Devon	Energy	Corporation and	its	consolidated	subsidiaries.	All	monetary	values,	other	than	per	unit	and	per	share	amounts,	are	stated	in	millions	of	U.S.	dollars	unless	otherwise	specified.	In addition,	the	following	are	other	abbreviations	and	definitions	of	certain	terms	used	within	this	Annual	Report	on	Form	10-K:

"2009	Plan"	means	the	Devon	Energy	Corporation	2009	Long-Term	Incentive	Plan,	as	amended	and	restated.

"2015	Plan"	means	the	Devon	Energy	Corporation	2015	Long-Term	Incentive	Plan.

"2012	Senior	Credit	Facility"	means	Devon's	syndicated	unsecured	revolving	line	of	credit,	effective	as	of	October	24,	2012.

"ASC"	means	Accounting	Standards	Codification.

"ASR"	means	an	accelerated	share-repurchase	transaction	with	a	financial	institution	to	repurchase	Devon's	common	stock.

"ASU"	means	Accounting	Standards	Update.

"Bbl"	or	"Bbls"	means	barrel	or	barrels.

"Bcf"	means	billion	cubic	feet.

"BLM"	means	the	United	States	Bureau	of	Land	Management.

"Boe"	means	barrel	of	oil	equivalent.	Gas	proved	reserves	and	production	are	converted	to	Boe,	at	the	pressure	and	temperature	base	standard	of	each	respective state	in	which	the	gas	is	produced,	at	the	rate	of	six	Mcf	of	gas	per	Bbl	of	oil,	based	upon	the	approximate	relative	energy	content	of	gas	and	oil.	Bitumen	and NGL	proved	reserves	and	production	are	converted	to	Boe	on	a	one-to-one	basis	with	oil.

"Btu"	means	British	thermal	units,	a	measure	of	heating	value.

"Canada"	means	the	division	of	Devon	encompassing	oil	and	gas	properties	located	in	Canada.	All	dollar	amounts	associated	with	Canada	are	in	U.S.	dollars, unless	stated	otherwise.

"Canadian	Plan"	means	Devon	Canada	Corporation	Incentive	Savings	Plan.

"DD&A"	means	depreciation,	depletion	and	amortization	expenses.

"Devon	Financing"	means	Devon	Financing	Company,	L.L.C.

"Devon	Plan"	means	Devon	Energy	Corporation	Incentive	Savings	Plan.

"EnLink"	means	EnLink	Midstream	Partners,	LP,	a	master	limited	partnership.

"EPA"	means	the	United	States	Environmental	Protection	Agency.

"FASB"	means	Financial	Accounting	Standards	Board.

"Federal	Funds	Rate"	means	the	interest	rate	at	which	depository	institutions	lend	balances	at	the	Federal	Reserve	to	other	depository	institutions	overnight.

"G&A"	means	general	and	administrative	expenses.

"GAAP"	means	U.S.	generally	accepted	accounting	principles.

"General	Partner"	means	EnLink	Midstream,	LLC,	the	indirect	general	partner	entity	of	EnLink,	and,	unless	the	context	otherwise	indicates,	EnLink	Midstream Manager,	LLC,	the	managing	member	of	EnLink	Midstream,	LLC.

"Inside	FERC"	refers	to	the	publication	Inside	F.E.R.C.'s	Gas	Market	Report.

"LIBOR"	means	London	Interbank	Offered	Rate.

"LOE"	means	lease	operating	expenses.

"MBbls"	means	thousand	barrels.

"MBoe"	means	thousand	Boe.

"Mcf"	means	thousand	cubic	feet.

"MMBbls"	means	million	barrels.

"MMBoe"	means	million	Boe.

"MMBtu"	means	million	Btu.

"MMcf"	means	million	cubic	feet.

"N/M"	means	not	meaningful.

"NGL"	or	"NGLs"	means	natural	gas	liquids.

"NYMEX"	means	New	York	Mercantile	Exchange.

"NYSE"	means	New	York	Stock	Exchange.

"OPEC"	means	Organization	of	the	Petroleum	Exporting	Countries.

"OPIS"	means	Oil	Price	Information	Service.

"PHMSA"	means	United	States	Department	of	Transportation	Pipeline	and	Hazardous	Materials	Safety	Administration.

"SEC"	means	United	States	Securities	and	Exchange	Commission.

"Standardized	measure"	means	the	present	value	of	after-tax	future	net	revenues	discounted	at	10%	per	annum.

"Tax	Reform	Legislation"	means	Tax	Cuts	and	Jobs	Act.

"TSR"	means	total	shareholder	return.

"Upstream	operations"	means	upstream	revenues	minus	production	expenses.

"U.S."	means	United	States	of	America.

"WTI"	means	West	Texas	Intermediate.

"/Bbl"	means	per	barrel.

"/MMBtu"	means	per	MMBtu.

# INFORMATION	REGARDING	FORWARD-LOOKING	STATEMENTS

This	report	includes	"forward-looking	statements"	as	defined	by	the	SEC.	Such	statements	include	those	concerning	strategic	plans,	our	expectations	and objectives	for	future	operations,	as	well	as	other	future	events	or	conditions,	and	are	often	identified	by	use	of	the	words	and	phrases	"expects,"	"believes,"	"will," "would,"	"could,"	"continue,"	"may,"	"aims,"	"likely	to	be,"	"intends,"	"forecasts,"	"projections,"	"estimates,"	"plans,"	"expectations,"	"targets,"	"opportunities," "potential,"	"anticipates,"	"outlook"	and	other	similar	terminology.	All	statements,	other	than	statements	of	historical	facts,	included	in	this	report	that	address	activities, events	or	developments	that	Devon	expects,	believes	or	anticipates	will	or	may	occur	in	the	future	are	forward-looking	statements.	Such	statements	are	subject	to	a number	of	assumptions,	risks	and	uncertainties,	many	of	which	are	beyond	our	control.	Consequently,	actual	future	results	could	differ	materially	from	our	expectations due	to	a	number	of	factors,	including,	but	not	limited	to:

•the	volatility	of	oil,	gas	and	NGL	prices;

•uncertainties	inherent	in	estimating	oil,	gas	and	NGL	reserves;

•the	extent	to	which	we	are	successful	in	acquiring	and	discovering	additional	reserves;

•the	uncertainties,	costs	and	risks	involved	in	our	operations,	including	as	a	result	of	employee	misconduct;

•regulatory	restrictions,	compliance	costs	and	other	risks	relating	to	governmental	regulation,	including	with	respect	to	environmental	matters;

•risks	related	to	regulatory,	social	and	market	efforts	to	address	climate	change;

•risks	related	to	our	hedging	activities;

•counterparty	credit	risks;

•risks	relating	to	our	indebtedness;

•cyberattack	risks;

•our	limited	control	over	third	parties	who	operate	some	of	our	oil	and	gas	properties;

•midstream	capacity	constraints	and	potential	interruptions	in	production;

•the	extent	to	which	insurance	covers	any	losses	we	may	experience;

•competition	for	assets,	materials,	people	and	capital;

•our	ability	to	successfully	complete	mergers,	acquisitions	and	divestitures;	and

•any	of	the	other	risks	and	uncertainties	discussed	in	this	report.

All	subsequent	written	and	oral	forward-looking	statements	attributable	to	Devon,	or	persons	acting	on	its	behalf,	are	expressly	qualified	in	their	entirety	by	the cautionary	statements	above.	We	assume	no	duty	to	update	or	revise	our	forward-looking	statements	based	on	new	information,	future	events	or	otherwise.

# PART	I

# Items	1	and	2.	Business	and	Properties

# General

A	Delaware	corporation	formed	in	1971	and	publicly	held	since	1988,	Devon	(NYSE:	DVN)	is	an	independent	energy	company	engaged	primarily	in	the exploration,	development	and	production	of	oil,	natural	gas	and	NGLs.	Our	operations	are	concentrated	in	various	North	American	onshore	areas	in	the	U.S.	and	Canada. In	July	2018,	we	exited	the	midstream	business	by	divesting	our	aggregate	ownership	interests	in	EnLink	and	the	General	Partner.

Our	principal	and	administrative	offices	are	located	at	333	West	Sheridan,	Oklahoma	City,	OK	73102-5015	(telephone	405-235-3611).	As	of	December	31, 2018,	Devon	and	its	consolidated	subsidiaries	had	approximately	2,900	employees.

Devon	files	or	furnishes	annual	reports	on	Form	10-K,	quarterly	reports	on	Form	10-Q	and	current	reports	on	Form	8-K,	as	well	as	any	amendments	to	these reports,	with	the	SEC.	Through	our	website,	www.devonenergy.com,	we	make	available	electronic	copies	of	the	documents	we	file	or	furnish	to	the	SEC,	the	charters	of the	committees	of	our	Board	of	Directors	and	other	documents	related	to	our	corporate	governance.	The	corporate	governance	documents	available	on	our	website include	our	Code	of	Ethics	for	Chief	Executive	Officer,	Chief	Financial	Officer	and	Chief	Accounting	Officer,	and	any	amendments	to	and	waivers	from	any	provision of	that	Code	will	also	be	posted	on	our	website.	Access	to	these	electronic	filings	is	available	free	of	charge	as	soon	as	reasonably	practicable	after	filing	or	furnishing them	to	the	SEC.	Printed	copies	of	our	committee	charters	or	other	governance	documents	and	filings	can	be	requested	by	writing	to	our	corporate	secretary	at	the address	on	the	cover	of	this	report.	Reports	filed	with	the	SEC	are	also	made	available	on	its	website	at	www.sec.gov.

# Our	Strategy

Our	business	strategy	is	focused	on	delivering	a	consistently	competitive	shareholder	return	among	our	peer	group.	Because	the	business	of	exploring	for, developing	and	producing	oil	and	natural	gas	is	capital	intensive,	delivering	sustainable	capital	efficient	cash	flow	growth	is	a	key	tenant	to	our	success.	While	our	cash flow	is	highly	dependent	on	volatile	and	uncertain	commodity	prices,	we	pursue	our	strategy	throughout	all	commodity	price	cycles	with	three	fundamental	principles.

A	premier,	sustainable	portfolio	of	assets	–	As	discussed	in	the	next	section	of	this	Annual	Report,	we	own	a	portfolio	of	assets	located	in	the	United	States	and Alberta,	Canada.	We	strive	to	own	premier	assets	capable	of	generating	cash	flows	in	excess	of	our	capital	and	operating	requirements,	as	well	as	competitive	rates	of return.	We	also	desire	to	own	a	portfolio	of	assets	that	can	provide	a	production	growth	platform	extending	many	years	into	the	future.	Because	of	the	strength	of	oil prices	relative	to	natural	gas,	we	have	been	positioning	our	portfolio	to	be	more	heavily	weighted	to	U.S.	oil	assets	in	recent	years.

During	2018,	we	made	significant	progress	in	our	transition	to	a	U.S.	oil	company.	We	sold	our	midstream	business	and	certain	non-core	upstream	assets, generating	nearly	$5	billion	in	proceeds.	In	February	2019,	we	announced	our	intent	to	separate	our	Canadian	business	and	our	Barnett	Shale	assets	from	the	Company. After	these	separations,	we	expect	our	oil	production	growth,	price	realizations	and	field-level	margins	will	all	improve,	as	we	sharpen	our	focus	on	four	core	U.S.	oil plays	located	in	the	Delaware	Basin,	STACK,	Eagle	Ford	and	Rockies.

Superior	execution	–	As	we	pursue	cash	flow	growth,	we	continually	work	to	optimize	the	efficiency	of	our	capital	programs	and	production	operations,	with	an underlying	objective	of	reducing	absolute	and	per	unit	costs	and	enhancing	our	returns.	We	also	strive	to	leverage	our	culture	of	health,	safety	and	environmental stewardship	in	all	aspects	of	our	business.

Throughout	2018,	we	continued	to	achieve	efficiency	gains	in	various	aspects	of	our	business.	Our	initial	production	rates	from	new	wells	continued	to	improve in	our	four	core	U.S.	oil	plays	and	have	exceeded	the	average	of	the	top	40	U.S.	producers	since	2015	by	more	than	40%.	We	continued	to	improve	cycle	times, incorporate	production	optimization	strategies	and	other	cost	reduction	initiatives,	driving	down	breakeven	costs	across	our	portfolio	of	assets.

As	we	focus	on	a	more	streamlined	portfolio	of	U.S.	oil	assets,	we	are	aggressively	pursuing	an	improved	cost	structure	with	$780	million	of	annual	costs	savings expected	by	2021.	We	expect	to	realize	about	70%	of	the	annualized	savings	by	the	end	of	2019.	Our	retained	U.S.	oil	business	is	expected	to	realize	$300	million	of annual	well	cost	savings	by	2021,	as	we	increase	our	focus	on	development	drilling,	reduce	our	facility	costs	and	optimize	well	spacing	in	the	STACK.	Additionally,	we will	streamline	and	align	our	workforce	with	our	go-forward	business,	which	should	result	in	$300	million	of	annual	cost	savings	by	the	end	of	the	three-year	period.	As we	continue	deleveraging,	we	expect	to	reduce	annual	interest	costs	by	$130	million.	Finally,	we	have	plans	to	reduce	our	annual	production	expenses	by	$50	million over	the	next	three	years.

Financial	strength	and	flexibility	–	Commodity	prices	are	uncertain	and	volatile,	so	we	strive	to	maintain	a	strong	balance	sheet,	as	well	as	adequate	liquidity	and financial	flexibility,	in	order	to	operate	competitively	in	all	commodity	price	cycles.	Our	capital	allocation	decisions	are	made	with	attention	to	these	financial stewardship	principles,	as	well	as	the	priorities	of	funding	our	core	operations,	protecting	our	investment-grade	credit	ratings,	and	paying	and	growing	our	shareholder dividend.

During	2018,	we	reduced	our	consolidated	debt	by	40%,	primarily	from	our	divestitures.	We	also	raised	our	quarterly	dividend	33%	and	began	a	$4	billion	share repurchase	program.	As	we	dispose	of	our	Canadian	and	Barnett	Shale	assets	in	2019,	we	expect	to	use	the	proceeds	to	reduce	debt	further	and	repurchase	additional common	shares.	As	a	result	of	our	planned	dispositions,	our	Board	of	Directors	has	increased	our	share	repurchase	program	to	$5	billion	in	February	2019	and	raised	our quarterly	dividend	12.5%	to	$0.09	per	share.

# Oil	and	Gas	Properties

# Property	Profiles

Key	summary	data	from	each	of	our	areas	of	operation	as	of	and	for	the	year	ended	December	31,	2018	are	detailed	in	the	map	below.	Notes	22	and	23	to	the financial	statements	included	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report	contain	additional	information	on	our	segments	and	geographical areas.

Delaware	Basin	–	The	Delaware	Basin	is	one	of	Devon's	top	assets	and	continues	to	offer	exploration	and	low-risk	development	opportunities	from	many geologic	reservoirs	and	play	types,	including	the	oil-rich	Bone	Spring,	Wolfcamp	and	Leonard	formations.	We	expect	these	oil	and	liquids-rich	opportunities	across	our acreage	in	the	Delaware	Basin	to	deliver	high-margin	growth	for	many	years	to	come.	During	2018,	our	continued	appraisal	and	development	work	enabled	us	to increase	our	proved	reserves	in	this	area	by	approximately	24%.	At	December	31,	2018,	we	had	10	operated	rigs	developing	this	asset.	In	2019,	we	plan	to	invest approximately	$900	million	of	capital	in	the	Delaware	Basin,	making	it	the	top-funded	asset	in	the	portfolio.

STACK	–	The	STACK	development,	located	primarily	in	Oklahoma's	Canadian,	Kingfisher	and	Blaine	counties,	is	one	of	Devon's	top	assets.	Our	STACK position	is	one	of	the	largest	in	the	industry,	providing	visible	long-term	stable	production.	At	December	31,	2018,	we	had	five	operated	rigs	with	drilling	focused	in	the Meramec	formation.	In	2019,	we	plan	approximately	$400	million	of	capital	investment.	The	STACK	is	Devon's	second	highest	funded	asset	in	the	portfolio	for	2019.

Eagle	Ford	–	We	acquired	our	position	in	the	Eagle	Ford	in	2014.	Since	acquiring	these	assets,	we	have	delivered	tremendous	results	by	producing	173	million oil-equivalent	barrels.	Our	excellent	results	are	driven	by	our	development	in	DeWitt	County,	located	in	the	economic	core	of	the	play.	Our	Eagle	Ford	assets	generated significant	cash	flow	in	2018.	In	2019,	we	plan	approximately	$300	million	of	capital	investment.

Rockies	Oil	–	Our	acreage	in	the	Rockies	is	focused	on	emerging	oil	opportunities	in	the	Powder	River	Basin.	Recent	drilling	success	in	this	basin	has	expanded our	drilling	inventory,	and	we	expect	further	growth	as	we	accelerate	activity	and	continue	to	de-risk	this	emerging	light-oil	opportunity.	As	of	December	31,	2018,	we had	two	operated	rigs	targeting	the	Turner,	Parkman,	Teapot	and	Niobrara	formations	in	northern	Converse	County	of	the	Powder	River	Basin.	In	2019,	we	plan approximately	$300	million	of	capital	investment	and	adding	two	additional	operated	rigs.

Heavy	Oil	–	Our	operations	in	Canada	are	focused	on	our	heavy	oil	assets	in	Alberta,	Canada.	Our	most	significant	Canadian	operation	is	our	Jackfish	complex, an	industry-leading	thermal	heavy	oil	operation	in	the	non-conventional	oil	sands	of	east	central	Alberta.	We	employ	a	recovery	method	known	as	steam-assisted	gravity drainage	at	Jackfish.	The	Jackfish	operation	consists	of	three	facilities.	We	expect	Jackfish	to	maintain	a	reasonably	flat	production	profile	for	greater	than	15	years requiring	approximately	$200	million	of	annual	maintenance	capital	based	on	current	economic	conditions.

Our	Pike	oil	sands	acreage	is	situated	directly	to	the	southeast	of	our	Jackfish	acreage	in	east	central	Alberta	and	has	similar	reservoir	characteristics	to	Jackfish. The	Pike	leasehold	is	currently	undeveloped	and	has	no	proved	reserves	or	production	as	of	December	31,	2018.	Currently,	we	have	minimal	planned	capital	outlays	for Pike	in	the	near	future.	The	majority	of	our	Pike	leasehold	does	not	expire	until	2025	and	2026.

In	addition	to	Jackfish	and	Pike,	we	hold	acreage	and	own	producing	assets	in	the	Bonnyville	region,	located	to	the	south	and	east	of	Jackfish	in	eastern	Alberta. Bonnyville	is	a	low-risk	oil	development	play	that	produces	heavy	oil	by	conventional	means,	without	the	need	for	steam	injection.

# In	2019,	we	plan	to	separate	our	operations	in	Canada.

Barnett	Shale	–	This	is	our	largest	property	in	terms	of	proved	reserves.	Our	leases	are	located	primarily	in	Denton,	Parker,	Tarrant	and	Wise	counties	in	north Texas.	Since	acquiring	a	substantial	position	in	this	field	in	2002,	we	continue	to	introduce	technology	and	new	innovations	to	optimize	production	operations	and	have transformed	this	asset	into	one	of	the	top	producing	gas	fields	in	North	America.	In	2019,	we	plan	to	separate	our	Barnett	Shale	assets.

# Proved	Reserves

For	estimates	of	our	proved	developed	and	proved	undeveloped	reserves	and	the	discussion	of	the	contribution	by	each	property,	see	Note	23	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report.

Proved	oil	and	gas	reserves	are	those	quantities	of	oil,	gas	and	NGLs	which,	by	analysis	of	geoscience	and	engineering	data,	can	be	estimated	with	reasonable certainty	to	be	economically	producible	from	known	reservoirs	under	existing	economic	conditions,	operating	methods	and	government	regulations.	To	be	considered proved,	oil	and	gas	reserves	must	be	economically	producible	before	contracts	providing	the	right	to	operate	expire,	unless	evidence	indicates	that	renewal	is	reasonably certain.	Also,	the	project	to	extract	the	hydrocarbons	must	have	commenced	or	the	operator	must	be	reasonably	certain	that	it	will	commence	the	project	within	a reasonable	time.

The	process	of	estimating	oil,	gas	and	NGL	reserves	is	complex	and	requires	significant	judgment,	as	discussed	in	"Item	1A.	Risk	Factors"	of	this	report.	As	a result,	we	have	developed	internal	policies	for	estimating	and	recording	reserves.	Such	policies	require	proved	reserves	to	be	in	compliance	with	the	SEC	definitions	and guidance.	Our	policies	assign	responsibilities	for	compliance	in	reserves	bookings	to	our	Reserve	Evaluation	Group	(the	"Group").	These	same	policies	also	require	that reserve	estimates	be	made	by	professionally	qualified	reserves	estimators,	as	defined	by	the	Society	of	Petroleum	Engineers'	standards.

The	Group,	which	is	led	by	Devon's	Director	of	Reserves	and	Economics,	is	responsible	for	the	internal	review	and	certification	of	reserves	estimates.	We	ensure the	Director	and	key	members	of	the	Group	have	appropriate	technical	qualifications	to	oversee	the	preparation	of	reserves	estimates.	The	Group	reports	to	and	is managed	through	our	finance	department.	No	portion	of	the	Group's	compensation	is	directly	dependent	on	the	quantity	of	reserves	booked.

The	Director	of	the	Group	has	over	30	years	of	industry	experience	with	positions	of	increasing	responsibility	for	the	estimation	and	evaluation	of	reserves.	He has	been	employed	by	Devon	for	the	past	18	years,	including	the	past	11	in	his	current	position.	His	further	professional	qualifications	include	a	degree	in	petroleum engineering,	registered	professional	engineer,	member	of	the	Society	of	Petroleum	Engineers	and	experience	in	reserves	estimation	for	projects	in	the	U.S.	(both	onshore and	offshore),	as	well	as	in	Canada,	Asia,	the	Middle	East	and	South	America.

Throughout	the	year,	the	Group	performs	internal	reserves	reviews	of	each	operating	country's	reserves.	The	Group	also	oversees	audits	and	reserves	estimates performed	by	qualified	third-party	petroleum	consulting	firms.	During	2018,	we	engaged	two	such	firms	to	audit	approximately	89%	of	our	proved	reserves	in accordance	with	generally	accepted	petroleum	engineering	and	evaluation	methods	and	procedures.	LaRoche	Petroleum	Consultants,	Ltd.	audited	approximately	87%	of our	U.S.	reserves,	and	Deloitte	LLP	audited	approximately	97%	of	our	Canadian	reserves.

In	addition	to	conducting	these	internal	reviews	and	external	reserves	audits,	we	also	have	a	Reserves	Committee	that	consists	of	three	independent	members	of our	Board	of	Directors.	This	committee	provides	additional	oversight	of	our	reserves	estimation	and	certification	process.	The	members	of	our	Reserves	Committee	have educational	backgrounds	in	geology	or	petroleum	engineering,	as	well	as	experience	relevant	to	the	reserves	estimation	process.	The	Reserves	Committee	meets	a minimum	of	twice	a	year	to	discuss	reserves	issues	and	policies	and	meets	at	least	once	a	year	separately	with	our	senior	reserves	engineering	personnel	and	separately with	our	third-party	petroleum	consultants.

The	following	tables	present	production,	price	and	cost	information	for	each	significant	field,	country	and	continent.

|  |  |  | Production |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31, | Oil\t(MMBbls) | Bitumen\t(MMBbls) | Gas\t(Bcf) | NGLs\t(MMBbls) | Total\t(MMBoe) |
| 2018 |  |  |  |  |  |
| Barnett\tShale | — | — | 186 | 12 | 43 |
| STACK | 12 | — | 121 | 14 | 45 |
| Jackfish | — | 35 | — | — | 35 |
| U.S. | 47 | — | 397 | 39 | 153 |
| Canada | 7 | 35 | 4 | — | 42 |
| Total\tNorth\tAmerica | 54 | 35 | 401 | 39 | 195 |
| 2017 |  |  |  |  |  |
| Barnett\tShale | — | — | 237 | 14 | 54 |
| STACK | 9 | — | 107 | 11 | 38 |
| Jackfish | — | 40 | — | — | 40 |
| U.S. | 42 | — | 433 | 36 | 150 |
| Canada | 7 | 40 | 6 | — | 48 |
| Total\tNorth\tAmerica | 49 | 40 | 439 | 36 | 198 |
| 2016 |  |  |  |  |  |
| Barnett\tShale | — | — | 265 | 15 | 60 |
| STACK | 7 | — | 103 | 9 | 33 |
| Jackfish | — | 40 | — | — | 40 |
| U.S. | 47 | — | 510 | 42 | 174 |
| Canada | 8 | 40 | 7 | — | 49 |
| Total\tNorth\tAmerica | 55 | 40 | 517 | 42 | 223 |

| Year	Ended	December	31, | Oil	(Per	Bbl) | Bitumen	(Per	Bbl) | Gas	(Per	Mcf) | NGLs	(Per	Bbl) | Boe)	(1)(2) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2018\t(1) |  |  |  |  |  |
| Barnett\tShale | $62.89 | $— | $2.45 | $22.72 | $9.42 |
| STACK | $63.81 | $— | $2.29 | $25.53 | $7.16 |
| Jackfish | $— | $17.88 | $— | $— | $12.85 |
| U.S. | $61.97 | $— | $2.37 | $24.74 | $8.61 |
| Canada | $27.36 | $17.88 | N/M | $— | $13.43 |
| Total\tNorth\tAmerica | $57.76 | $17.88 | $2.37 | $24.74 | $9.66 |
| 2017 |  |  |  |  |  |
| Barnett\tShale | $49.72 | $— | $2.47 | $13.67 | $6.86 |
| STACK | $48.43 | $— | $2.40 | $17.78 | $4.72 |
| Jackfish | $— | $29.38 | $— | $— | $11.02 |
| U.S. | $49.41 | $— | $2.48 | $15.66 | $6.74 |
| Canada | $33.73 | $29.38 | N/M | $— | $11.70 |
| Total\tNorth\tAmerica | $47.31 | $29.38 | $2.48 | $15.66 | $7.94 |
| 2016 |  |  |  |  |  |
| Barnett\tShale | $41.03 | $— | $1.76 | $10.31 | $5.75 |
| STACK | $39.81 | $— | $1.91 | $10.86 | $4.34 |
| Jackfish | $— | $19.82 | $— | $— | $8.70 |
| U.S. | $38.92 | $— | $1.84 | $9.81 | $6.44 |
| Canada | $23.96 | $19.82 | N/M | $— | $9.36 |
| Total\tNorth\tAmerica | $36.72 | $19.82 | $1.84 | $9.81 | $7.08 |

(1) As	further	discussed	in	Note	1	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report,	in	2018	the	presentation	of	certain	processing arrangements	changed	from	a	net	to	a	gross	presentation.	The	change	resulted	in	an	increase	to	our	upstream	revenues	and	production	expenses	by	$254 million	during	2018	with	no	impact	to	net	earnings.	These	changes	primarily	related	to	our	Barnett	Shale	and	STACK	properties.

(2) Represents	production	expense	per	BOE	excluding	production	and	property	taxes.	Jackfish	and	Canada	include	purchases	of	natural	gas	used	to	heat	the heavy	oil	reservoirs.	The	gas	is	purchased	at	prevailing	market	prices,	which	vary	from	year	to	year.

# Drilling	Statistics

The	following	table	summarizes	our	development	and	exploratory	drilling	results.

|  | Development	Wells	(1) |  | Exploratory	Wells	(1) |  |  | Total	Wells	(1) |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31, | Productive | Dry | Productive | Dry | Productive | Dry | Total |
| 2018 |  |  |  |  |  |  |  |
| U.S. | 165.6 | 3.1 | 69.4 | — | 235.0 | 3.1 | 238.1 |
| Canada | 70.5 | — | — | — | 70.5 | — | 70.5 |
| Total\tNorth\tAmerica | 236.1 | 3.1 | 69.4 | — | 305.5 | 3.1 | 308.6 |
| 2017 |  |  |  |  |  |  |  |
| U.S. | 149.8 | — | 44.0 | — | 193.8 | — | 193.8 |
| Canada | 100.5 | — | — | — | 100.5 | — | 100.5 |
| Total\tNorth\tAmerica | 250.3 | — | 44.0 | — | 294.3 | — | 294.3 |
| 2016 |  |  |  |  |  |  |  |
| U.S. | 88.5 | — | 36.4 | 2.0 | 124.9 | 2.0 | 126.9 |
| Canada | 21.5 | — | — | — | 21.5 | — | 21.5 |
| Total\tNorth\tAmerica | 110.0 | — | 36.4 | 2.0 | 146.4 | 2.0 | 148.4 |

(1) Well	counts	represent	net	wells	completed	during	each	year.	Net	wells	are	gross	wells	multiplied	by	our	fractional	working	interests.

The	following	table	presents	the	wells	that	were	in	progress	on	December	31,	2018.	As	of	February	1,	2019,	these	wells	were	still	in	progress.

|  | Gross	(1) | Net	(2) |
| :--- | :--- | :--- |
| U.S. | 184.0 | 105.2 |
| Canada | 1.0 | 1.0 |
| Total\tNorth\tAmerica | 185.0 | 106.2 |

(1) Gross	wells	are	the	sum	of	all	wells	in	which	we	own	a	working	interest.

(2) Net	wells	are	gross	wells	multiplied	by	our	fractional	working	interests	in	each	well.

# Productive	Wells

The	following	table	sets	forth	our	producing	wells	as	of	December	31,	2018.

|  | Oil	Wells	(1) |  | Natural	Gas	Wells | Natural	Gas	Wells | Total	Wells	(1) |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross\t(2)(4) | Net\t(3) | Gross\t(2)(4) | Net\t(3) | Gross\t(2)(4) | Net\t(3) |
| U.S. | 9,284 | 3,445 | 8,235 | 5,703 | 17,519 | 9,148 |
| Canada | 3,183 | 3,071 | 544 | 380 | 3,727 | 3,451 |
| Total\tNorth\tAmerica | 12,467 | 6,516 | 8,779 | 6,083 | 21,246 | 12,599 |

(1) Includes	bitumen	wells.

(4) Includes	902	and	350	gross	oil	and	gas	wells,	respectively,	which	had	multiple	completions.

The	day-to-day	operations	of	oil	and	gas	properties	are	the	responsibility	of	an	operator	designated	under	pooling	or	operating	agreements.	The	operator supervises	production,	maintains	production	records,	employs	field	personnel	and	performs	other	functions.	We	are	the	operator	of	approximately	12,900	gross	wells. As	operator,	we	receive	reimbursement	for	direct	expenses	incurred	to	perform	our	duties,	as	well	as	monthly	per-well	producing,	drilling,	and	construction	overhead reimbursement	at	rates	customarily	charged	in	the	respective	areas.	In	presenting	our	financial	data,	we	record	the	monthly	overhead	reimbursements	as	a	reduction	of G&A,	which	is	a	common	industry	practice.

# Acreage	Statistics

The	following	table	sets	forth	our	developed	and	undeveloped	lease	and	mineral	acreage	as	of	December	31,	2018.	Of	our	3.8	million	net	acres,	approximately 1.9	million	acres	are	held	by	production.	The	acreage	in	the	table	includes	0.2	million,	0.1	million	and	0.1	million	net	acres	subject	to	leases	that	are	scheduled	to	expire during	2019,	2020	and	2021,	respectively.	As	of	December	31,	2018,	there	were	no	proved	undeveloped	reserves	associated	with	our	expiring	acreage.	Of	the 0.3	million	net	acres	set	to	expire	by	December	31,	2021,	we	anticipate	performing	operational	and	administrative	actions	to	continue	the	lease	terms	for	portions	of	the acreage	that	we	intend	to	further	assess.	However,	we	do	expect	to	allow	a	portion	of	the	acreage	to	expire	in	the	normal	course	of	business.	In	2018,	we	allowed approximately	0.1	million	acres	to	expire.

|  | Developed |  | Undeveloped |  |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross\t(1) | Net\t(2) | Gross\t(1) | Net\t(2) | Gross\t(1) | Net\t(2) |
|  |  |  | (Thousands) |  |  |  |
| U.S. | 1,449 | 909 | 3,373 | 1,463 | 4,822 | 2,372 |
| Canada | 674 | 495 | 2,086 | 967 | 2,760 | 1,462 |
| Total\tNorth\tAmerica | 2,123 | 1,404 | 5,459 | 2,430 | 7,582 | 3,834 |

(1) Gross	acres	are	the	sum	of	all	acres	in	which	we	own	a	working	interest.

(2) Net	acres	are	gross	acres	multiplied	by	our	fractional	working	interests	in	the	acreage.

# Title	to	Properties

Title	to	properties	is	subject	to	contractual	arrangements	customary	in	the	oil	and	gas	industry,	liens	for	taxes	not	yet	due	and,	in	some	instances,	other encumbrances.	We	believe	that	such	burdens	do	not	materially	detract	from	the	value	of	properties	or	from	the	respective	interests	therein	or	materially	interfere	with their	use	in	the	operation	of	the	business.

As	is	customary	in	the	industry,	a	preliminary	title	investigation,	typically	consisting	of	a	review	of	local	title	records,	is	made	at	the	time	of	acquisitions	of undeveloped	properties.	More	thorough	title	investigations,	which	generally	include	a	review	of	title	records	and	the	preparation	of	title	opinions	by	outside	legal counsel,	are	made	prior	to	the	consummation	of	an	acquisition	of	producing	properties	and	before	commencement	of	drilling	operations	on	undeveloped	properties.

# Marketing	Activities

# Oil,	Gas	and	NGL	Marketing

The	spot	markets	for	oil,	gas	and	NGLs	are	subject	to	volatility	as	supply	and	demand	factors	fluctuate.	As	detailed	below,	we	sell	our	production	under	both long-term	(one	year	or	more)	and	short-term	(less	than	one	year)	agreements	at	prices	negotiated	with	third	parties.	Regardless	of	the	term	of	the	contract,	the	vast majority	of	our	production	is	sold	at	variable,	or	market-sensitive,	prices.

Additionally,	we	may	enter	into	financial	hedging	arrangements	or	fixed-price	contracts	associated	with	a	portion	of	our	oil,	gas	and	NGL	production.	These activities	are	intended	to	support	targeted	price	levels	and	to	manage	our	exposure	to	price	fluctuations.	See	Note	3	in	"Item	8.	Financial	Statements	and	Supplementary Data"	of	this	report	for	further	information.

As	of	January	2019,	our	production	was	sold	under	the	following	contract	terms.

|  | Short-Term |  | Long-Term |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Variable | Fixed | Variable | Fixed |
| Oil\tand\tbitumen | 75% | — | 25% | — |
| Natural\tgas | 67% | 4% | 29% | — |
| NGLs | 41% | 20% | 39% | — |

# Delivery	Commitments

A	portion	of	our	production	is	sold	under	certain	contractual	arrangements	that	specify	the	delivery	of	a	fixed	and	determinable	quantity.	As	of	December	31, 2018,	we	were	committed	to	deliver	the	following	fixed	quantities	of	production.

|  | Total | Less	Than	1	Year | 1-3	Years | 3-5	Years |
| :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(MMBbls) | 53 | 25 | 28 | — |
| Natural\tgas\t(Bcf) | 360 | 220 | 125 | 15 |
| NGLs\t(MMBbls) | 10 | 10 | — | — |
| Total\t(MMBoe) | 123 | 72 | 49 | 2 |

We	expect	to	fulfill	our	delivery	commitments	primarily	with	production	from	our	proved	developed	reserves.	Moreover,	our	proved	reserves	have	generally been	sufficient	to	satisfy	our	delivery	commitments	during	the	three	most	recent	years,	and	we	expect	such	reserves	will	continue	to	be	the	primary	means	of	fulfilling our	future	commitments.	However,	where	our	proved	reserves	are	not	sufficient	to	satisfy	our	delivery	commitments,	we	can	and	may	use	spot	market	purchases	to satisfy	the	commitments.

# Customers

During	2018,	we	had	one	purchaser	that	accounted	for	approximately	11%	of	our	consolidated	sales	revenue.

During	2017	and	2016,	no	purchaser	accounted	for	over	10%	of	our	consolidated	sales	revenue.

# Competition

See	"Item	1A.	Risk	Factors."

# Public	Policy	and	Government	Regulation

Our	industry	is	subject	to	a	wide	range	of	regulations.	Laws,	rules,	regulations,	taxes,	fees	and	other	policy	implementation	actions	affecting	our	industry	have been	pervasive	and	are	under	constant	review	for	amendment	or	expansion.	Numerous	government	agencies	have	issued	extensive	regulations	which	are	binding	on	our industry	and	its	individual	members,	some	of	which	carry	substantial	penalties	for	failure	to	comply.	These	laws	and	regulations	increase	the	cost	of	doing	business	and consequently	affect	profitability.	Because	public	policy	changes	are	commonplace,	and	existing	laws	and	regulations	are	frequently	amended,	we	are	unable	to	predict the	future	cost	or	impact	of	compliance.	However,	we	do	not	expect	that	any	of	these	laws	and	regulations	will	affect	our	operations	materially	differently	than	they would	affect	other	companies	with	similar	operations,	size	and	financial	strength.	The	following	are	significant	areas	of	government	control	and	regulation	affecting	our operations.

# Exploration	and	Production	Regulation

Our	operations	are	subject	to	federal,	tribal,	state,	provincial	and	local	laws	and	regulations.	These	laws	and	regulations	relate	to	matters	that	include:

•acquisition	of	seismic	data;

•location,	drilling	and	casing	of	wells;

•well	design;

•hydraulic	fracturing;

•well	production;

•spill	prevention	plans;

•emissions	and	discharge	permitting;

•use,	transportation,	storage	and	disposal	of	fluids	and	materials	incidental	to	oil	and	gas	operations;

•surface	usage	and	the	restoration	of	properties	upon	which	wells	have	been	drilled;

•calculation	and	disbursement	of	royalty	payments	and	production	taxes;

•plugging	and	abandoning	of	wells;

•transportation	of	production;	and

•endangered	species	and	habitat.

Our	operations	also	are	subject	to	conservation	regulations,	including	the	regulation	of	the	size	of	drilling	and	spacing	units	or	proration	units;	the	number	of wells	that	may	be	drilled	in	a	unit;	the	rate	of	production	allowable	from	oil	and	gas	wells;	and	the	unitization	or	pooling	of	oil	and	gas	properties.	In	the	U.S.,	some states	allow	the	forced	pooling	or	unitization	of	tracts	to	facilitate	exploration,	while	other	states	rely	on	voluntary	pooling	of	lands	and	leases,	which	may	make	it	more difficult	to	develop	oil	and	gas	properties.	In	addition,	federal	and	state	conservation	laws	generally	limit	the	venting	or	flaring	of	natural	gas,	and	state	conservation laws	impose	certain	requirements	regarding	the	ratable	purchase	of	production.	These	regulations	limit	the	amounts	of	oil	and	gas	we	can	produce	from	our	wells	and the	number	of	wells	or	the	locations	at	which	we	can	drill.

Certain	of	our	U.S.	natural	gas	and	oil	leases	are	granted	or	approved	by	the	federal	government	and	administered	by	the	BLM	or	Bureau	of	Indian	Affairs	of	the Department	of	the	Interior.	Such	leases	require	compliance	with	detailed	federal	regulations	and	orders	that	regulate,	among	other	matters,	drilling	and	operations	on lands	covered	by	these	leases	and	calculation	and	disbursement	of	royalty	payments	to	the	federal	government,	tribes	or	tribal	members.	The	federal	government	has, from	time	to	time,	evaluated	and,	in	some	cases,	promulgated	new	rules	and	regulations	regarding	competitive	lease	bidding,	venting	and	flaring,	oil	and	gas measurement	and	royalty	payment	obligations	for	production	from	federal	lands.	In	addition,	permitting	activities	on	federal	lands	can	sometimes	be	subject	to	delays.

# Royalties	and	Incentives	in	Canada

The	royalty	calculation	in	Canada	is	a	significant	factor	in	the	profitability	of	Canadian	oil	and	gas	production.	Oil	sands	crown	royalties	are	determined	by government	regulations	and	are	generally	calculated	as	a	percentage	of	the	value	of	the	gross	production,	net	of	allowed	deductions.	The	royalty	percentage	is determined	on	a	sliding-scale	based	on	crown	posted	prices.	For	pre-payout	oil	sands	projects,	the	regulations	prescribe	lower	royalty	rates	for	oil	sands	projects	until allowable	capital	costs	have	been	recovered.	In

early	2016,	the	Alberta	government	adopted	the	recommendation	of	its	Royalty	Review	Panel.	The	new	royalty	framework	preserves	the	existing	royalty	structure	and rates	for	oil	sands.	For	conventional	oil	and	gas	royalty	calculations,	wells	drilled	after	January	1,	2017	would	use	the	Modernized	Royalty	Framework	(MRF)	which prescribes	a	lower	royalty	rate	until	allowable	costs	have	been	recovered.	The	calculation	for	wells	post	payout	is	based	on	a	percentage	of	production	net	of	allowed deductions	and	varies	with	commodity	price.

# Marketing	in	Canada

Any	oil	or	gas	export	requires	an	exporter	to	obtain	export	authorizations	from	Canada's	National	Energy	Board.

In	December	2018,	Alberta	enacted	the	Curtailment	Rules	(Rules)	in	an	effort	to	reduce	Alberta's	oversupply	of	oil	which	resulted	from	pipeline	and	rail constraints.	Pursuant	to	the	Rules,	operators	that	produce	either	or	both	crude	oil	or	crude	bitumen	in	amounts	in	excess	of	10	MBbls/d	are	required	to	curtail	their production.	As	of	January	1,	2019,	the	production	curtailment	amount	was	set	at	325	MBbls/d.	The	curtailment	amounts	are	expected	to	reduce	over	2019	to	an	average of	approximately	95	MBbls/d	as	storage	levels	ease	and	price	differential	improve,	and	the	Rules	terminate	on	December	31,	2019.	Devon's	curtailments	in	the	first quarter	of	2019	as	a	result	of	the	Rules	are	anticipated	to	total	approximately	10	MBbls/d	of	bitumen,	or	approximately	2%	of	our	total	production.

# Environmental,	Pipeline	Safety	and	Occupational	Regulations

We	strive	to	conduct	our	operations	in	a	socially	and	environmentally	responsible	manner,	which	includes	compliance	with	applicable	law.	We	are	subject	to many	federal,	state,	provincial,	tribal	and	local	laws	and	regulations	concerning	occupational	safety	and	health	as	well	as	the	discharge	of	materials	into,	and	the protection	of,	the	environment	and	natural	resources.	Environmental	laws	and	regulations	relate	to:

•the	discharge	of	pollutants	into	federal,	provincial	and	state	waters;

•assessing	the	environmental	impact	of	seismic	acquisition,	drilling	or	construction	activities;

•the	generation,	storage,	transportation	and	disposal	of	waste	materials,	including	hazardous	substances;

•the	emission	of	certain	gases	into	the	atmosphere;

•the	monitoring,	abandonment,	reclamation	and	remediation	of	well	and	other	sites,	including	sites	of	former	operations;

•the	development	of	emergency	response	and	spill	contingency	plans;

•the	monitoring,	repair	and	design	of	pipelines	used	for	the	transportation	of	oil	and	natural	gas;

•the	protection	of	threatened	and	endangered	species;	and

# •worker	protection.

Failure	to	comply	with	these	laws	and	regulations	can	lead	to	the	imposition	of	remedial	liabilities,	administrative,	civil	or	criminal	fines	or	penalties	or injunctions	limiting	our	operations	in	affected	areas.	Moreover,	multiple	environmental	laws	provide	for	citizen	suits,	which	allow	environmental	organizations	to	act	in the	place	of	the	government	and	sue	operators	for	alleged	violations	of	environmental	law.	Environmental	protection	and	health	and	safety	compliance	are	necessary, manageable	parts	of	our	business.	We	have	been	able	to	plan	for	and	comply	with	environmental,	safety	and	health	initiatives	without	materially	altering	our	operating strategy	or	incurring	significant	unreimbursed	expenditures.	However,	based	on	regulatory	trends	and	increasingly	stringent	laws,	our	capital	expenditures	and	operating expenses	related	to	the	protection	of	the	environment	and	safety	and	health	compliance	have	increased	over	the	years	and	may	continue	to	increase.	We	cannot	predict with	any	reasonable	degree	of	certainty	our	future	exposure	concerning	such	matters.

# Item	1A.	Risk	Factors

Our	business	and	operations,	and	our	industry	in	general,	are	subject	to	a	variety	of	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	following	risks	should	occur, our	business,	financial	condition,	results	of	operations	and	liquidity	could	be	materially	and	adversely	impacted.	As	a	result,	holders	of	our	securities	could	lose	part	or all	of	their	investment	in	Devon.

# Volatile	Oil,	Gas	and	NGL	Prices	Significantly	Impact	our	Business

Our	financial	condition,	results	of	operations	and	the	value	of	our	properties	are	highly	dependent	on	the	general	supply	and	demand	for	oil,	gas	and	NGLs,	which impact	the	prices	we	ultimately	realize	on	our	sales	of	these	commodities.	Historically,	market	prices	and	our	realized	prices	have	been	volatile.	For	example,	over	the last	five	years,	NYMEX	WTI	oil	and	NYMEX	Henry	Hub	prices	ranged	from	a	high	of	over	$100	per	Bbl	and	$6	per	MMBtu,	respectively,	to	a	low	of	under	$27	per Bbl	and	$1.70	per	MMBtu,	respectively.	Such	volatility	is	likely	to	continue	in	the	future	due	to	numerous	factors	beyond	our	control,	including,	but	not	limited	to:

•the	domestic	and	worldwide	supply	of	and	demand	for	oil,	gas	and	NGLs;

•volatility	and	trading	patterns	in	the	commodity-futures	markets;

•conservation	and	environmental	protection	efforts;

•production	levels	of	members	of	OPEC,	Russia	or	other	producing	countries;

•geopolitical	risks,	including	political	and	civil	unrest	in	the	Middle	East,	Africa	and	South	America;

•adverse	weather	conditions	and	natural	disasters,	such	as	tornadoes,	earthquakes	and	hurricanes;

•regional	pricing	differentials,	including	in	Canada,	the	Delaware	Basin	and	other	areas	of	our	operations;

•differing	quality	of	production,	including	NGL	content	of	gas	produced;

•the	level	of	imports	and	exports	of	oil,	gas	and	NGLs	and	the	level	of	global	oil,	gas	and	NGL	inventories;

•the	price	and	availability	of	alternative	fuels;

•technological	advances	affecting	energy	consumption	and	production;

•the	overall	economic	environment;

•changes	in	trade	relations	and	policies,	including	the	imposition	of	tariffs	by	the	U.S.	or	China;	and

•other	governmental	regulations	and	taxes.

The	differential	between	WTI	and	Western	Canadian	Select,	a	benchmark	for	the	Canadian	oil	market,	recently	expanded,	widening	to	nearly	$46	per	barrel	in November	2018.	As	a	result,	our	Canadian	heavy	oil	unhedged	realized	price	for	the	fourth	quarter	was	near	zero.	This	negatively	affected	our	results	of	operations	in 2018,	and	a	sustained	weakness	or	further	deterioration	in	differentials	or	commodity	prices	could	materially	and	adversely	impact	our	business	by	resulting	in,	or exacerbating,	the	following	effects:

•reducing	the	amount	of	oil,	bitumen,	gas	and	NGLs	that	we	can	produce	economically;

•limiting	our	financial	flexibility,	liquidity	and	access	to	sources	of	capital,	such	as	equity	and	debt;

•reducing	our	revenues,	operating	cash	flows	and	profitability;

•causing	us	to	decrease	our	capital	expenditures	or	maintain	reduced	capital	spending	for	an	extended	period,	resulting	in	lower	future	production	of	oil, gas	and	NGLs;	and

•reducing	the	carrying	value	of	our	properties,	resulting	in	noncash	write-downs.

# Estimates	of	Oil,	Gas	and	NGL	Reserves	Are	Uncertain	and	May	Be	Subject	to	Revision

The	process	of	estimating	oil,	gas	and	NGL	reserves	is	complex	and	requires	significant	judgment	in	the	evaluation	of	available	geological,	engineering	and economic	data	for	each	reservoir,	particularly	for	new	discoveries.	Because	of	the	high	degree	of	judgment	involved,	different	reserve	engineers	may	develop	different estimates	of	reserve	quantities	and	related	revenue	based	on	the	same	data.	In	addition,	the	reserve	estimates	for	a	given	reservoir	may	change	substantially	over	time	as a	result	of	several	factors,	including	additional	development	and	appraisal	activity,	the	viability	of	production	under	varying	economic	conditions,	including	commodity price	declines,	and	variations	in	production	levels	and	associated	costs.	Consequently,	material	revisions	to	existing	reserve	estimates	may	occur	as	a	result	of	changes	in any	of	these	factors.	Such	revisions	to	proved	reserves	could	have	a	material	adverse	effect	on	our	financial	condition	and	the	value	of	our	properties,	as	well	as	the estimates	of	our	future	net	revenue	and	profitability.	Our	policies	and	internal	controls	related	to	estimating	and	recording	reserves	are	included	in	"Items	1	and	2. Business	and	Properties"	of	this	report.

# Discoveries	or	Acquisitions	of	Reserves	Are	Needed	to	Avoid	a	Material	Decline	in	Reserves	and	Production

The	production	rates	from	oil	and	gas	properties	generally	decline	as	reserves	are	depleted,	while	related	per	unit	production	costs	generally	increase	due	to decreasing	reservoir	pressures	and	other	factors.	Therefore,	our	estimated	proved	reserves	and	future	oil,	gas	and	NGL	production	will	decline	materially	as	reserves	are produced	unless	we	conduct	successful	exploration	and	development	activities,	such	as	identifying	additional	producing	zones	in	existing	wells,	utilizing	secondary	or tertiary	recovery	techniques	or	acquiring	additional	properties	containing	proved	reserves.	Consequently,	our	future	oil,	gas	and	NGL	production	and	related	per	unit production	costs	are	highly	dependent	upon	our	level	of	success	in	finding	or	acquiring	additional	reserves.

# Our	Operations	Are	Uncertain	and	Involve	Substantial	Costs	and	Risks

Our	operating	activities	are	subject	to	numerous	costs	and	risks,	including	the	risk	that	we	will	not	encounter	commercially	productive	oil	or	gas	reservoirs. Drilling	for	oil,	gas	and	NGLs	can	be	unprofitable,	not	only	from	dry	holes,	but	from	productive	wells	that	do	not	return	a	profit	because	of	insufficient	revenue	from production	or	high	costs.	Substantial	costs	are	required	to	locate,	acquire	and	develop	oil	and	gas	properties,	and	we	are	often	uncertain	as	to	the	amount	and	timing	of those	costs.	Our	cost	of	drilling,	completing,	equipping	and	operating	wells	is	often	uncertain	before	drilling	commences.	Declines	in	commodity	prices	and	overruns	in budgeted	expenditures	are	common	risks	that	can	make	a	particular	project	uneconomic	or	less	economic	than	forecasted.	While	both	exploratory	and	developmental drilling	activities	involve	these	risks,	exploratory	drilling	involves	greater	risks	of	dry	holes	or	failure	to	find	commercial	quantities	of	hydrocarbons.	In	addition,	our	oil and	gas	properties	can	become	damaged,	our	operations	may	be	curtailed,	delayed	or	canceled	and	the	costs	of	such	operations	may	increase	as	a	result	of	a	variety	of factors,	including,	but	not	limited	to:

•unexpected	drilling	conditions,	pressure	conditions	or	irregularities	in	reservoir	formations;

•equipment	failures	or	accidents;

•fires,	explosions,	blowouts,	cratering	or	loss	of	well	control,	as	well	as	the	mishandling	or	underground	migration	of	fluids	and	chemicals;

•adverse	weather	conditions	and	natural	disasters,	such	as	tornadoes,	earthquakes,	hurricanes	and	extreme	temperatures;

•issues	with	title	or	in	receiving	governmental	permits	or	approvals;

•restricted	takeaway	capacity	for	our	production,	including	due	to	inadequate	midstream	infrastructure	or	constrained	downstream	markets;

•environmental	hazards	or	liabilities;

•restrictions	in	access	to,	or	disposal	of,	water	used	or	produced	in	drilling	and	completion	operations;	and

•shortages	or	delays	in	the	availability	of	services	or	delivery	of	equipment.

The	occurrence	of	one	or	more	of	these	factors	could	result	in	a	partial	or	total	loss	of	our	investment	in	a	particular	property,	as	well	as	significant	liabilities. Moreover,	certain	of	these	events	could	result	in	environmental	pollution	and	impact	to	third	parties,	including	persons	living	in	proximity	to	our	operations,	our employees	and	employees	of	our	contractors,	leading	to	possible	injuries,	death	or	significant	damage	to	property	and	natural	resources.

In	addition,	we	rely	on	our	employees,	consultants	and	sub-contractors	to	conduct	our	operations	in	compliance	with	applicable	laws	and	standards.	Any	violation of	such	laws	or	standards	by	these	individuals,	whether	through	negligence,	harassment,	discrimination	or	other	misconduct,	could	result	in	significant	liability	for	us	and adversely	affect	our	business.	For	example,	negligent	operations	by	employees	could	result	in	serious	injury,	death	or	property	damage,	and	sexual	harassment	or	racial and	gender	discrimination	could	result	in	legal	claims	and	reputational	harm.

# We	Are	Subject	to	Extensive	Governmental	Regulation,	Which	Can	Change	and	Could	Adversely	Impact	Our	Business

Our	operations	are	subject	to	extensive	federal,	state,	provincial,	tribal,	local	and	other	laws,	rules	and	regulations,	including	with	respect	to	environmental matters,	worker	health	and	safety,	wildlife	conservation,	the	gathering	and	transportation	of	oil,	gas	and	NGLs,	conservation	policies,	reporting	obligations,	royalty payments,	unclaimed	property	and	the	imposition	of	taxes.	Such

regulations	include	requirements	for	permits	to	drill	and	to	conduct	other	operations	and	for	provision	of	financial	assurances	(such	as	bonds)	covering	drilling, completion	and	well	operations	and	decommissioning	obligations.	If	permits	are	not	issued,	or	if	unfavorable	restrictions	or	conditions	are	imposed	on	our	drilling	or completion	activities,	we	may	not	be	able	to	conduct	our	operations	as	planned.	In	addition,	we	may	be	required	to	make	large	expenditures	to	comply	with	applicable governmental	laws,	rules,	regulations,	permits	or	orders.	For	example,	certain	regulations	require	the	plugging	and	abandonment	of	wells	and	removal	of	production facilities	by	current	and	former	operators,	which	may	result	in	significant	costs	associated	with	the	removal	of	tangible	equipment	and	other	restorative	actions	at	the	end of	operations.

In	addition,	changes	in	public	policy	have	affected,	and	in	the	future	could	further	affect,	our	operations.	Regulatory	and	public	policy	developments	could, among	other	things,	restrict	production	levels,	impose	price	controls,	change	environmental	protection	requirements	and	increase	taxes,	royalties	and	other	amounts payable	to	governments	or	governmental	agencies.	Our	operating	and	other	compliance	costs	could	increase	further	if	existing	laws	and	regulations	are	revised	or reinterpreted	or	if	new	laws	and	regulations	become	applicable	to	our	operations.	In	addition,	changes	in	public	policy	may	indirectly	impact	our	operations	by,	among other	things,	increasing	the	cost	of	supplies	and	equipment	and	fostering	general	economic	uncertainty.	For	example,	changes	in	U.S.	trade	relations,	particularly	the imposition	of	tariffs	by	the	U.S.	and	China,	may	increase	the	cost	of	materials	we	or	our	vendors	use,	thereby	increasing	our	operating	expense.	Although	we	are	unable to	predict	changes	to	existing	laws	and	regulations,	such	changes	could	significantly	impact	our	profitability,	financial	condition	and	liquidity,	particularly	changes related	to	hydraulic	fracturing,	pipeline	safety,	seismic	activity	and	income	taxes,	as	discussed	below.

Hydraulic	Fracturing	–	In	recent	years,	the	EPA	has	made	proposals	that	subject	hydraulic	fracturing	to	further	regulation	and	that	could	potentially	restrict	the practice	of	hydraulic	fracturing.	For	example,	the	EPA	has	issued	final	regulations	under	the	federal	Clean	Air	Act	establishing	performance	standards	for	oil	and	gas activities,	including	standards	for	the	capture	of	air	emissions	released	during	hydraulic	fracturing,	and	finalized	in	2016	regulations	that	prohibit	the	discharge	of wastewater	from	hydraulic	fracturing	operations	to	publicly	owned	wastewater	treatment	plants.	The	EPA	also	released	a	study	in	2016	finding	that	certain	aspects	of hydraulic	fracturing,	such	as	water	withdrawals	and	wastewater	management	practices,	could	result	in	impacts	to	water	resources,	although	the	report	did	not	identify	a direct	link	between	hydraulic	fracturing	and	impacts	to	groundwater	resources.	The	BLM	previously	finalized	regulations	to	regulate	hydraulic	fracturing	on	federal lands,	but	subsequently	issued	a	repeal	of	those	regulations	in	2017.	Several	states	in	which	we	operate	have	already	adopted	and	more	states	are	considering	adopting laws	or	regulations	that	require	disclosure	of	chemicals	used	in	hydraulic	fracturing	and	impose	more	stringent	permitting,	disclosure	and	well-construction	requirements on	hydraulic	fracturing	operations.	In	addition,	some	states	and	municipalities	have	significantly	limited	drilling	activities	or	hydraulic	fracturing	or	are	considering doing	so	or	banning	the	practice	altogether.	Although	it	is	not	possible	at	this	time	to	predict	the	final	outcome	of	these	proposals,	any	new	federal,	state	or	local restrictions	on	hydraulic	fracturing	that	may	be	imposed	in	areas	in	which	we	conduct	business	could	potentially	result	in	increased	compliance	costs,	delays	in development	or	restrictions	on	our	operations.

Pipeline	Safety	–	The	pipeline	assets	in	which	we	own	interests,	are	subject	to	stringent	and	complex	regulations	related	to	pipeline	safety	and	integrity management.	The	PHMSA	has	established	a	series	of	rules	that	require	pipeline	operators	to	develop	and	implement	integrity	management	programs	for	gas,	NGL	and condensate	transmission	pipelines	as	well	as	certain	low	stress	pipelines	and	gathering	lines	transporting	hazardous	liquids,	such	as	oil,	that,	in	the	event	of	a	failure, could	affect	"high	consequence	areas."	Additional	action	by	PHMSA	with	respect	to	pipeline	integrity	management	requirements	may	occur	in	the	future.	For	example, in	2016	PHMSA	proposed	new	rules	for	gas	pipelines	that	extend	pipeline	safety	programs	beyond	high	consequence	areas	to	newly	proposed	"moderate	consequence areas"	and	would	also	impose	more	rigorous	testing	and	reporting	requirements	on	such	pipelines.	To	date,	no	further	action	has	been	taken.	PHMSA	has	announced	its intent	to	address	the	2016	proposed	rules	for	gas	pipelines	through	three	separate	final	rulemakings	in	2019.	More	recently,	in	January	2017,	PHMSA	finalized regulations	for	hazardous	liquid	pipelines	that	significantly	extend	and	expand	the	reach	of	certain	PHMSA	integrity	management	requirements	(i.e.,	periodic assessments,	leak	detection	and	repairs),	regardless	of	the	pipeline's	proximity	to	a	high	consequence	area.	The	final	rule	also	imposes	new	reporting	requirements	for certain	unregulated	pipelines,	including	all	hazardous	liquid	gathering	lines.	Following	the	change	in	presidential	administrations,	implementation	of	this	rule	was delayed,	but	the	final	rule	is	expected	to	be	published	in	the	Federal	Register	and	become	effective	during	the	first	half	of	2019.	At	this	time,	we	cannot	predict	the	cost of	such	requirements,	but	they	could	be	significant.	Moreover,	violations	of	pipeline	safety	regulations	can	result	in	the	imposition	of	significant	penalties.

Seismic	Activity	–	Earthquakes	in	northern	and	central	Oklahoma	and	elsewhere	have	prompted	concerns	about	seismic	activity	and	possible	relationships	with the	energy	industry.	Legislative	and	regulatory	initiatives	intended	to	address	these	concerns	may	result	in	additional	levels	of	regulation	or	other	requirements	that	could lead	to	operational	delays,	increase	our	operating	and	compliance	costs	or	otherwise	adversely	affect	our	operations.	In	addition,	we	are	currently	defending	against certain	third-party	lawsuits	and	could	be	subject	to	additional	claims,	seeking	alleged	property	damages	or	other	remedies	as	a	result	of	alleged	induced	seismic	activity in	our	areas	of	operation.

Changes	to	Tax	Laws	–	We	are	subject	to	U.S.	federal	income	tax	as	well	as	income	or	capital	taxes	in	various	state	and	foreign	jurisdictions,	and	our	operating cash	flow	is	sensitive	to	the	amount	of	income	taxes	we	must	pay.	In	the	jurisdictions	in	which	we	operate,	income	taxes	are	assessed	on	our	earnings	after	consideration of	all	allowable	deductions	and	credits.	Changes	in	the	types	of	earnings	that	are	subject	to	income	tax,	the	types	of	costs	that	are	considered	allowable	deductions	or	the rates	assessed	on	our	taxable	earnings	would	all	impact	our	income	taxes	and	resulting	operating	cash	flow.

# Concerns	About	Climate	Change	and	Related	Regulatory,	Social	and	Market	Actions	May	Adversely	Affect	Our	Business

Continuing	and	increasing	political	and	social	attention	to	the	issue	of	climate	change	has	resulted	in	legislative,	regulatory	and	other	initiatives,	including international	agreements,	to	reduce	greenhouse	gas	emissions,	such	as	carbon	dioxide	and	methane.	Policy	makers	at	both	the	U.S.	federal	and	state	levels	have introduced	legislation	and	proposed	new	regulations	designed	to	quantify	and	limit	the	emission	of	greenhouse	gases.	For	example,	both	the	EPA	and	the	BLM	have issued	regulations	for	the	control	of	methane	emissions,	which	also	include	leak	detection	and	repair	requirements,	for	the	oil	and	gas	industry.	Following	the	change	in presidential	administrations,	however,	the	agencies	have	attempted	to	revise	or	rescind	their	previously	issued	methane	standards.	Litigation	concerning	these	methane regulations	and	subsequent	attempts	to	revise	or	rescind	them	is	ongoing.	Nevertheless,	several	states	where	we	operate,	including	Wyoming,	have	already	imposed venting	and	flaring	limitations	designed	to	reduce	methane	emissions	from	oil	and	gas	exploration	and	production	activities.	With	respect	to	more	comprehensive regulation,	federal	and	state	initiatives	to	date	have	generally	focused	on	the	development	of	cap-and-trade	or	carbon	tax	programs.	As	generally	proposed,	a	cap-and- trade	program	would	cap	overall	greenhouse	gas	emissions	on	an	economy-wide	basis	and	require	major	sources	of	greenhouse	gas	emissions	or	major	fuel	producers	to acquire	and	surrender	emission	allowances,	while	a	carbon	tax	could	impose	taxes	based	on	emissions	from	our	operations	and	downstream	uses	of	our	products.

In	Canada,	greenhouse	gas	emissions	are	also	being	addressed	at	both	the	federal	and	provincial	level.	Devon	will	continue	to	be	subject	to	Alberta's	climate change	laws	and	regulations	until	at	least	2021.	Those	laws	and	regulations	include	a	legislated	oil	sands	emission	limit,	with	forthcoming	regulations	involving	methane emissions	reduction	targets.	Beginning	January	2019,	the	Greenhouse	Gas	Pollution	Pricing	Act	subjects	all	of	Canada	to	a	federal	price	on	greenhouse	gas	emissions unless	a	province	or	territory	has	implemented	a	compliant	carbon	pricing	regime.	Litigation	concerning	the	act	is	ongoing,	and	it	is	unclear	how	the	act	will	ultimately treat	provincial	plans.	In	Alberta,	large	industrial	emitters	are	subject	to	the	Carbon	Competitiveness	Incentive	Regulation	(CCIR).	The	CCIR	prices	carbon,	but	provides cost	protection	to	emission-intensive	/	trade-exposed	industries,	including	Devon's	oil	sands	operations.	The	impact	to	our	operations	from	these	laws	and	regulations	is expected	to	be	minimal	in	the	near	term.	Oil	and	gas	facilities	that	are	not	subject	to	the	CCIR	are	exempt	from	its	economy-wide	carbon	levy	until	2023.

In	addition	to	regulatory	risk,	other	market	and	social	initiatives	resulting	from	the	changing	perception	of	climate	change	present	risks	for	our	business.	For example,	in	an	effort	to	promote	a	lower-carbon	economy,	there	are	various	public	and	private	initiatives	subsidizing	the	development	of	alternative	energy	sources, including	by	mandating	the	use	of	specific	fuels	or	technologies.	These	initiatives	may	reduce	the	competitiveness	of	carbon-based	fuels,	such	as	oil	and	gas.	Moreover, certain	financial	institutions,	funds	and	other	sources	of	capital	have	begun	restricting	or	eliminating	their	investment	in	oil	and	natural	gas	activities	due	to	their	concern regarding	climate	change.	Such	restrictions	in	capital	could	make	it	more	difficult	to	secure	funding	to	operate	our	business.	Finally,	governmental	entities	and	other plaintiffs	have	brought,	and	may	continue	to	bring,	claims	against	us	and	other	oil	and	gas	companies	for	purported	damages	caused	by	the	alleged	effects	of	climate change.	These	and	the	other	regulatory,	social	and	market	risks	relating	to	climate	change	described	above	could	result	in	unexpected	costs,	increase	our	operating expense	and	reduce	the	demand	for	our	products,	which	in	turn	could	lower	the	value	of	our	reserves	and	have	a	material	adverse	effect	on	our	profitability,	financial condition	and	liquidity.

# Our	Hedging	Activities	Limit	Participation	in	Commodity	Price	Increases	and	Involve	Other	Risks

We	enter	into	financial	derivative	instruments	with	respect	to	a	portion	of	our	production	to	manage	our	exposure	to	oil,	gas	and	NGL	price	volatility.	To	the extent	that	we	engage	in	price	risk	management	activities	to	protect	ourselves	from	commodity	price	declines,	we	will	be	prevented	from	fully	realizing	the	benefits	of commodity	price	increases	above	the	prices	established	by	our	hedging	contracts.	In	addition,	our	hedging	arrangements	may	expose	us	to	the	risk	of	financial	loss	in certain	circumstances,	including	instances	in	which	the	contract	counterparties	fail	to	perform	under	the	contracts.	Moreover,	as	a	result	of	the	Dodd-Frank	Wall	Street Reform	and	Consumer	Protection	Act	and	other	legislation,	hedging	transactions	and	many	of	our	contract	counterparties	have	become	subject	to	increased governmental	oversight	and	regulations	in	recent	years.	Although	we	cannot	predict	the	ultimate	impact	of	these	laws	and	the	related	rulemaking,	some	of	which	is ongoing,	existing	or	future	regulations	may	adversely	affect	the	cost

and	availability	of	our	hedging	arrangements,	including	by	causing	our	contract	counterparties,	which	are	generally	financial	institutions	and	other	market	participants, to	curtail	or	cease	their	derivatives	activities.

# The	Credit	Risk	of	Our	Counterparties	Could	Adversely	Affect	Us

We	enter	into	a	variety	of	transactions	that	expose	us	to	counterparty	credit	risk.	For	example,	we	have	exposure	to	financial	institutions	and	insurance	companies through	our	hedging	arrangements,	our	syndicated	revolving	credit	facility	and	our	insurance	policies.	Disruptions	in	the	financial	markets	or	otherwise	may	impact these	counterparties	and	affect	their	ability	to	fulfill	their	existing	obligations	and	their	willingness	to	enter	into	future	transactions	with	us.

In	addition,	we	are	exposed	to	the	risk	of	financial	loss	from	trade,	joint	interest	billing	and	other	receivables.	We	sell	our	oil,	gas	and	NGLs	to	a	variety	of purchasers,	and,	as	an	operator,	we	pay	expenses	and	bill	our	non-operating	partners	for	their	respective	share	of	costs.	We	also	frequently	look	to	buyers	of	oil	and	gas properties	from	us	to	perform	certain	obligations	associated	with	the	disposed	assets,	including	the	removal	of	production	facilities	and	plugging	and	abandonment	of wells.	Certain	of	these	counterparties	may	experience	insolvency,	liquidity	problems	or	other	issues	and	may	not	be	able	to	meet	their	obligations	and	liabilities (including	contingent	liabilities)	owed	to,	and	assumed	from,	us,	particularly	during	a	depressed	or	volatile	commodity	price	environment.	Any	such	default	by	these counterparties	may	result	in	us	being	forced	to	cover	the	costs	of	those	obligations	and	liabilities,	which	could	adversely	impact	our	financial	results	and	condition.

# Our	Debt	May	Limit	Our	Liquidity	and	Financial	Flexibility,	and	Any	Downgrade	of	Our	Credit	Rating	Could	Adversely	Impact	Us

As	of	December	31,	2018,	we	had	total	indebtedness	of	$5.9	billion.	Our	indebtedness	and	other	financial	commitments	have	important	consequences	to	our business,	including,	but	not	limited	to:

•requiring	us	to	dedicate	a	portion	of	our	cash	flows	from	operations	to	debt	service	payments,	thereby	limiting	our	ability	to	fund	working	capital,	capital expenditures,	investments	or	acquisitions	and	other	general	corporate	purposes;

•increasing	our	vulnerability	to	general	adverse	economic	and	industry	conditions,	including	low	commodity	price	environments;	and

•limiting	our	ability	to	obtain	additional	financing	due	to	higher	costs	and	more	restrictive	covenants.

In	addition,	we	receive	credit	ratings	from	rating	agencies	in	the	U.S.	with	respect	to	our	debt.	Factors	that	may	impact	our	credit	ratings	include,	among	others, debt	levels,	planned	asset	sales	and	purchases,	liquidity,	forecasted	production	growth	and	commodity	prices.	We	are	currently	required	to	provide	letters	of	credit	or other	assurances	under	certain	of	our	contractual	arrangements.	Any	credit	downgrades	could	adversely	impact	our	ability	to	access	financing	and	trade	credit,	require	us to	provide	additional	letters	of	credit	or	other	assurances	under	contractual	arrangements	and	increase	our	interest	rate	under	any	credit	facility	borrowing	as	well	as	the cost	of	any	other	future	debt.

# Environmental	Matters	and	Related	Costs	Can	Be	Significant

As	an	owner,	lessee	or	operator	of	oil	and	gas	properties,	we	are	subject	to	various	federal,	state,	provincial,	tribal	and	local	laws	and	regulations	relating	to discharge	of	materials	into,	and	protection	of,	the	environment.	These	laws	and	regulations	may,	among	other	things,	impose	liability	on	us	for	the	cost	of	remediating pollution	that	results	from	our	operations.	Environmental	laws	may	impose	strict,	joint	and	several	liability,	and	failure	to	comply	with	environmental	laws	and regulations	can	result	in	the	imposition	of	administrative,	civil	or	criminal	fines	and	penalties,	as	well	as	injunctions	limiting	operations	in	affected	areas.	Any	future environmental	costs	of	fulfilling	our	commitments	to	the	environment	are	uncertain	and	will	be	governed	by	several	factors,	including	future	changes	to	regulatory requirements.	Changes	in	or	additions	to	public	policy	regarding	the	protection	of	the	environment	could	have	a	significant	impact	on	our	operations	and	profitability.

# Cyber	Attacks	May	Adversely	Impact	Our	Operations

Our	business	has	become	increasingly	dependent	on	digital	technologies,	and	we	anticipate	expanding	our	use	of	technology	in	our	operations,	including	through process	automation	and	data	analytics.	Concurrent	with	this	growing	dependence	on	technology	is	greater	sensitivity	to	cyberattack	activities,	which	have	been increasing	against	our	industry.	Cyber	attackers	often	attempt	to	gain	unauthorized	access	to	digital	systems	for	purposes	of	misappropriating	sensitive	information, intellectual	property	or	financial	assets,

corrupting	data	or	causing	operational	disruptions.	These	attacks	may	be	perpetrated	by	third	parties	or	insiders.	Techniques	used	in	these	attacks	range	from	highly sophisticated	efforts	to	electronically	circumvent	network	security	to	more	traditional	intelligence	gathering	and	social	engineering	aimed	at	obtaining	information necessary	to	gain	access.	Cyber	attacks	may	also	be	carried	out	in	a	manner	that	does	not	require	gaining	unauthorized	access,	such	as	by	causing	denial-of-service attacks.	In	addition,	our	vendors,	midstream	providers	and	other	business	partners	may	separately	suffer	disruptions	or	breaches	from	cyber	attacks,	which,	in	turn,	could adversely	impact	our	operations	and	compromise	our	information.	Although	we	have	not	suffered	material	losses	related	to	cyber	attacks	to	date,	if	we	were	successfully attacked,	we	could	incur	substantial	remediation	and	other	costs	or	suffer	other	negative	consequences,	including	litigation	risks.	Moreover,	as	the	sophistication	of	cyber attacks	continues	to	evolve,	we	may	be	required	to	expend	significant	additional	resources	to	further	enhance	our	digital	security	or	to	remediate	vulnerabilities.

# Limited	Control	on	Properties	Operated	by	Others

Certain	of	the	properties	in	which	we	have	an	interest	are	operated	by	other	companies	and	involve	third-party	working	interest	owners.	We	have	limited influence	and	control	over	the	operation	or	future	development	of	such	properties,	including	compliance	with	environmental,	health	and	safety	regulations	or	the	amount and	timing	of	required	future	capital	expenditures.	These	limitations	and	our	dependence	on	the	operator	and	other	working	interest	owners	for	these	properties	could result	in	unexpected	future	costs	and	delays,	curtailments	or	cancellations	of	operations	or	future	development,	which	could	adversely	affect	our	financial	condition	and results	of	operations.

# Midstream	Capacity	Constraints	and	Interruptions	Impact	Commodity	Sales

We	rely	on	midstream	facilities	and	systems	to	process	our	gas	production	and	to	transport	our	oil,	gas	and	NGL	production	to	downstream	markets.	All	or	a portion	of	our	production	in	one	or	more	regions	may	be	interrupted	or	shut	in	from	time	to	time	due	to	losing	access	to	plants,	pipelines	or	gathering	systems.	Such access	could	be	lost	due	to	a	number	of	factors,	including,	but	not	limited	to,	weather	conditions	and	natural	disasters,	accidents,	field	labor	issues	or	strikes. Additionally,	the	midstream	operators	may	be	subject	to	constraints	that	limit	their	ability	to	construct,	maintain	or	repair	midstream	facilities	needed	to	process	and transport	our	production.	Such	interruptions	or	constraints	could	negatively	impact	our	production	and	associated	profitability.

# Insurance	Does	Not	Cover	All	Risks

As	discussed	above,	our	business	is	hazardous	and	is	subject	to	all	of	the	operating	risks	normally	associated	with	the	exploration,	development	and	production	of oil,	gas	and	NGLs.	To	mitigate	financial	losses	resulting	from	these	operational	hazards,	we	maintain	comprehensive	general	liability	insurance,	as	well	as	insurance coverage	against	certain	losses	resulting	from	physical	damages,	loss	of	well	control,	business	interruption	and	pollution	events	that	are	considered	sudden	and accidental.	We	also	maintain	workers'	compensation	and	employer's	liability	insurance.	However,	our	insurance	coverage	does	not	provide	100%	reimbursement	of potential	losses	resulting	from	these	operational	hazards.	Additionally,	we	have	limited	or	no	insurance	coverage	for	a	variety	of	other	risks,	including	pollution	events that	are	considered	gradual,	war	and	political	risks	and	fines	or	penalties	assessed	by	governmental	authorities.	The	occurrence	of	a	significant	event	against	which	we are	not	fully	insured	could	have	a	material	adverse	effect	on	our	profitability,	financial	condition	and	liquidity.

# Competition	for	Assets,	Materials,	People	and	Capital	Can	Be	Significant

Strong	competition	exists	in	all	sectors	of	the	oil	and	gas	industry.	We	compete	with	major	integrated	and	independent	oil	and	gas	companies	for	the	acquisition of	oil	and	gas	leases	and	properties.	We	also	compete	for	the	equipment	and	personnel	required	to	explore,	develop	and	operate	properties.	Typically,	during	times	of rising	commodity	prices,	drilling	and	operating	costs	will	also	increase.	During	these	periods,	there	is	often	a	shortage	of	drilling	rigs	and	other	oilfield	services,	which could	adversely	affect	our	ability	to	execute	our	development	plans	on	a	timely	basis	and	within	budget.	Competition	is	also	prevalent	in	the	marketing	of	oil,	gas	and NGLs.	Certain	of	our	competitors	have	financial	and	other	resources	substantially	greater	than	ours	and	may	have	established	superior	strategic	long-term	positions	and relationships,	including	with	respect	to	midstream	take-away	capacity.	As	a	consequence,	we	may	be	at	a	competitive	disadvantage	in	bidding	for	assets	or	services	and accessing	capital	and	downstream	markets.	In	addition,	many	of	our	larger	competitors	may	have	a	competitive	advantage	when	responding	to	factors	that	affect demand	for	oil	and	gas	production,	such	as	changing	worldwide	price	and	production	levels,	the	cost	and	availability	of	alternative	fuels	and	the	application	of government	regulations.

# Our	Business	Could	Be	Adversely	Impacted	by	Investors	Attempting	to	Effect	Change

Stockholder	activism	has	been	increasing	in	our	industry,	and	investors	may	from	time	to	time	attempt	to	effect	changes	to	our	business	or	governance,	whether by	stockholder	proposals,	public	campaigns,	proxy	solicitations	or	otherwise.	Such	actions	could	adversely	impact	our	business	by	distracting	our	board	of	directors	and employees	from	core	business	operations,	requiring	us	to	incur	increased	advisory	fees	and	related	costs,	interfering	with	our	ability	to	successfully	execute	on	strategic transactions	and	plans	and	provoking	perceived	uncertainty	about	the	future	direction	of	our	business.		Such	perceived	uncertainty	may,	in	turn,	make	it	more	difficult	to retain	employees	and	could	result	in	significant	fluctuation	in	the	market	price	of	our	common	stock.

# Our	Acquisition	and	Divestiture	Activities	Involve	Substantial	Risks

Our	business	depends,	in	part,	on	making	acquisitions	that	complement	or	expand	our	current	business	and	successfully	integrating	any	acquired	assets	or businesses.	If	we	are	unable	to	make	attractive	acquisitions,	our	future	growth	could	be	limited.	Furthermore,	even	if	we	do	make	acquisitions,	they	may	not	result	in	an increase	in	our	cash	flow	from	operations	or	otherwise	result	in	the	benefits	anticipated	due	to	various	risks,	including,	but	not	limited	to:

•mistaken	estimates	or	assumptions	about	reserves,	potential	drilling	locations,	revenues	and	costs,	including	synergies	and	the	overall	costs	of	equity	or debt;

•difficulties	in	integrating	the	operations,	technologies,	products	and	personnel	of	the	acquired	assets	or	business;	and

•unknown	and	unforeseen	liabilities	or	other	issues	related	to	any	acquisition	for	which	contractual	protections	prove	inadequate,	including	environmental liabilities	and	title	defects.

In	addition,	from	time	to	time,	we	may	sell	or	otherwise	dispose	of	certain	of	our	properties	or	businesses	as	a	result	of	an	evaluation	of	our	asset	portfolio	and	to help	enhance	our	liquidity.	These	transactions	also	have	inherent	risks,	including	possible	delays	in	closing,	the	risk	of	lower-than-expected	sales	proceeds	for	the disposed	assets	or	business	and	potential	post-closing	claims	for	indemnification.	Moreover,	volatility	in	commodity	prices	may	result	in	fewer	potential	bidders, unsuccessful	sales	efforts	and	a	higher	risk	that	buyers	may	seek	to	terminate	a	transaction	prior	to	closing.

# Item	1B.	Unresolved	Staff	Comments

Not	applicable.

# Item	3.	Legal	Proceedings

We	are	involved	in	various	legal	proceedings	incidental	to	our	business.	However,	to	our	knowledge	as	of	the	date	of	this	report,	there	were	no	material	pending legal	proceedings	to	which	we	are	a	party	or	to	which	any	of	our	property	is	subject.

Devon	Energy	Production	Company,	L.P.,	a	wholly-owned	subsidiary	of	the	Company,	is	currently	in	negotiations	with	the	EPA	with	respect	to	alleged noncompliance	with	the	leak	detection	and	repair	requirements	of	EPA	regulations	promulgated	under	the	Clean	Air	Act	at	its	Beaver	Creek	Gas	Plant	located	near Riverton,	Wyoming.	Although	management	cannot	predict	the	outcome	of	settlement	negotiations,	the	resolution	of	this	matter	may	result	in	a	fine	or	penalty	in	excess of	$100,000.

# Item	4.	Mine	Safety	Disclosures

# PART	II

# Item	5.	Market	for	Common	Equity,	Related	Stockholder	Matters	and	Issuer	Purchases	of	Equity	Securities

Our	common	stock	is	traded	on	the	NYSE	under	the	"DVN"	ticker	symbol.	On	February	6,	2019,	there	were	7,094	holders	of	record	of	our	common	stock.	We began	paying	regular	quarterly	cash	dividends	in	the	second	quarter	of	1993.	The	declaration	of	future	dividends	is	a	business	decision	made	by	our	Board	of	Directors, and	will	depend	on	Devon's	financial	condition	and	other	relevant	factors.	Additional	information	on	our	dividends	can	be	found	in	Note	18	in	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

# Performance	Graph

The	following	graph	compares	the	cumulative	TSR	over	a	five-year	period	on	Devon's	common	stock	with	the	cumulative	total	returns	of	the	S&P	500	Index	and a	peer	group	of	companies	to	which	we	compare	our	performance.	The	peer	group	includes	Anadarko	Petroleum	Corporation,	Apache	Corporation,	Chesapeake	Energy Corporation,	Concho	Resources,	Inc.,	ConocoPhillips,	Continental	Resources,	Inc.,	Encana	Corporation,	EOG	Resources,	Inc.,	Hess	Corporation,	Marathon	Oil Corporation,	Murphy	Oil	Corporation,	Noble	Energy,	Inc.,	Occidental	Petroleum	Corporation	and	Pioneer	Natural	Resources	Company.	The	graph	was	prepared assuming	$100	was	invested	on	December	31,	2013	in	Devon's	common	stock,	the	S&P	500	Index	and	the	peer	group,	and	dividends	have	been	reinvested	subsequent to	the	initial	investment.

The	graph	and	related	information	should	not	be	deemed	"soliciting	material"	or	to	be	"filed"	with	the	SEC,	nor	should	such	information	be	incorporated	by reference	into	any	future	filing	under	the	Securities	Act	of	1933,	as	amended,	or	the	Securities	Exchange	Act	of	1934,	as	amended,	except	to	the	extent	that	we specifically	incorporate	such	information	by	reference	into	such	a	filing.	The	graph	and	information	is	included	for	historical	comparative	purposes	only	and	should	not be	considered	indicative	of	future	stock	performance.

# Issuer	Purchases	of	Equity	Securities

The	following	table	provides	information	regarding	purchases	of	our	common	stock	that	were	made	by	us	during	the	fourth	quarter	of	2018	(shares	in	thousands).

| Period | Total	Number	of<br>Shares	Purchased	(1) | Average	Price<br>Paid	per	Share | Total	Number	of	Shares	Purchased	As<br>Part	of	Publicly	Announced	Plans	or<br>Programs	(2) | Maximum	Dollar	Value	of	Shares	that<br>May	Yet	Be	Purchased	Under	the	Plans	or<br>Programs	(2) |
| :--- | :--- | :--- | :--- | :--- |
| October\t1\t-\tOctober\t31 | 10,532 | $36.01 | 10,529 | $2,388 |
| November\t1\t-\tNovember\t30 | 7,079 | $31.55 | 7,068 | $2,165 |
| December\t1\t-\tDecember\t31 | 6,020 | $23.82 | 6,015 | $2,022 |
| Total | 23,631 | $31.57 | 23,612 |  |

(1) In	addition	to	shares	purchased	under	the	share	repurchase	program	described	below,	these	amounts	also	included	approximately	19,000	shares	received	by	us from	employees	for	the	payment	of	personal	income	tax	withholding	on	vesting	transactions.

(2) On	March	7,	2018,	we	announced	a	$1.0	billion	share	repurchase	program.	On	June	6,	2018,	we	announced	the	expansion	of	this	program	to	$4.0	billion.	On February	19,	2019,	we	announced	a	further	expansion	to	$5.0	billion	with	a	December	31,	2019	expiration	date.	During	2018,	we	repurchased	78.1	million shares	of	common	stock	for	$3.0	billion,	or	$38.11	per	share.	Future	purchases	under	the	program	will	be	made	in	the	open	market,	private	transactions	or through	the	use	of	ASR	programs.

Under	the	Devon	Plan,	eligible	employees	may	purchase	shares	of	our	common	stock	through	an	investment	in	the	Devon	Stock	Fund,	which	is	administered	by an	independent	trustee.	Eligible	employees	purchased	approximately	39,000	shares	of	our	common	stock	in	2018,	at	then-prevailing	stock	prices,	that	they	held	through their	ownership	in	the	Devon	Stock	Fund.	We	acquired	the	shares	of	our	common	stock	sold	under	this	plan	through	open-market	purchases.

Similarly,	eligible	Canadian	employees	may	purchase	shares	of	our	common	stock	through	an	investment	in	the	Canadian	Plan,	which	is	administered	by	an independent	trustee.	Shares	sold	under	the	Canadian	Plan	were	acquired	through	open-market	purchases.	These	shares	and	any	interest	in	the	Canadian	Plan	were	offered and	sold	in	reliance	on	the	exemptions	for	offers	and	sales	of	securities	made	outside	of	the	U.S.,	including	under	Regulation	S	for	offers	and	sales	of	securities	to employees	pursuant	to	an	employee	benefit	plan	established	and	administered	in	accordance	with	the	law	of	a	country	other	than	the	U.S.	In	2018,	there	were	no	shares purchased	by	Canadian	employees	under	the	plan.

# Item	6.	Selected	Financial	Data

The	financial	information	below	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"	of	this	report.

|  | 2018 | 2017 | 2016 | 2015 | 2014 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statement\tof\tEarnings\tdata: |  |  |  |  |  |
| Upstream\trevenues\t(1) | $6,285 | $5,307 | $3,981 | $5,885 | $11,619 |
| Total\trevenues\t(1) | $10,734 | $8,878 | $6,753 | $9,372 | $16,636 |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations\t(2) | $764 | $758 | $(574) | $(12,231) | $(1,004) |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare: |  |  |  |  |  |
| Basic\t(2) | $1.53 | $1.44 | $(1.14) | $(30.09) | $(2.49) |
| Diluted\t(2) | $1.52 | $1.43 | $(1.14) | $(30.09) | $(2.49) |
| Cash\tdividends\tper\tcommon\tshare | $0.30 | $0.24 | $0.42 | $0.96 | $0.94 |
| Balance\tSheet\tdata: |  |  |  |  |  |
| Total\tassets\t(2)(3) | $19,566 | $30,241 | $28,675 | $29,673 | $49,253 |
| Long-term\tdebt | $5,785 | $6,749 | $6,859 | $8,990 | $7,738 |
| Stockholders'\tequity | $9,186 | $14,104 | $12,722 | $11,111 | $24,789 |
| Common\tshares\toutstanding | 450 | 525 | 523 | 418 | 409 |

	(1) In	January	2018,	Devon	adopted	ASC	606	–	Revenue	from	Contracts	with	Customers	using	the	modified	retrospective	method	and	has	applied	the	standard	to	all existing	contracts.	The	impact	of	adoption	for	2018	is	further	discussed	in	Note	1	of	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.	Prior periods	have	not	been	restated.

	(2) Material	asset	impairments	and	acquisition	and	divestiture	activity	had	significant	impacts	on	operating	results	and	the	carrying	value	of	our	oil	and	gas	assets. Specifically,	there	were	asset	impairments	of	$0.4	billion,	$16.1	billion	and	$3.4	billion	in	2016,	2015	and	2014,	respectively.	More	discussion	on	these	items	can be	found	in	"Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations"	and	in	Note	2	and	Note	5	of	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

	(3) Amounts	in	2014	through	2017	include	assets	related	to	our	aggregate	ownership	interest	in	EnLink	and	the	General	Partner.	As	discussed	further	in	Note	19	of "Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report,	the	2018	divestment	of	our	aggregate	ownership	interests	in	EnLink	and	the	General Partner	resulted	in	the	reclassification	of	EnLink	and	the	General	Partners'	assets	to	assets	held	for	sale,	which	are	included	within	this	amount.

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

# Introduction

The	following	discussion	and	analysis	presents	management's	perspective	of	our	business,	financial	condition	and	overall	performance.	This	information	is intended	to	provide	investors	with	an	understanding	of	our	past	performance,	current	financial	condition	and	outlook	for	the	future	and	should	be	read	in	conjunction with	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Overview	of	2018	Results

2018	was	a	pivotal	year	for	Devon	as	we	took	several	significant	steps	toward	achieving	our	long-term	strategic	goals.	Operationally,	we	successfully transitioned	our	U.S.	oil	business	into	full-field	development,	which	resulted	in	high-return,	light-oil	production	advancing	14	percent	in	2018.	In	addition	to	this	strong operating	performance,	we	made	substantial	progress	high-grading	our	asset	portfolio,	building	per-share	value	through	our	share-repurchase	program	and	reducing	our financial	leverage	by	more	than	40	percent.

•Increased	STACK	and	Delaware	Basin	production	27%	in	2018	compared	to	2017.

•Maintained	our	2018	capital	expenditure	forecast.

•Substantially	achieved	$5.0	billion	in	asset	sales,	including	the	monetization	of	EnLink	and	the	General	Partner.

•Repurchased	$3.0	billion	of	common	stock,	representing	a	14%	share	count	reduction	since	December	31,	2017.

•Reduced	long-term	debt	by	$922	million,	which	is	expected	to	reduce	annualized	financing	costs	by	$66	million.

•Completed	workforce	reduction	and	cost	reduction	initiatives	expected	to	generate	$150	million	of	annualized	savings.

•Increased	our	quarterly	common	stock	dividend	33%	to	$0.08	per	share	beginning	in	the	second	quarter	of	2018.

•Exited	2018	with	$2.4	billion	of	cash	and	$2.9	billion	of	available	credit	under	our	Senior	Credit	Facility	and	have	no	significant	debt	maturities	until 2021.

As	presented	in	the	graph	at	the	left,	our	operating achievements	are	subject	to	the	volatility	of	commodity	prices. Over	the	last	four	years,	NYMEX	WTI	oil	and	NYMEX	Henry Hub	prices	ranged	from	an	average	high	of	$64.79	per	Bbl	and $3.11	per	MMBtu,	respectively,	to	an	average	low	of	$43.36 per	Bbl	and	$2.46	per	MMBtu,	respectively.	Widening Western	Canadian	Select	differentials	negatively	impacted	the prices	we	realized	on	our	heavy	oil	production	in	the	fourth quarter	of	2018.	In	the	first	two	months	of	2019,	Western Canadian	Select	differentials	have	improved	significantly.

Key	measures	of	our	financial	performance	in	2018	are summarized	in	the	following	table.	Increased	oil	and	natural gas	liquids	prices	as	well	as	continued	focus	cost	management improved	our	2018	financial	performance	as	compared	to 2017,	as	seen	in	the	table	below.	Additionally,	we	recognized	a gain	of	approximately	$2.6	billion	($2.2	billion	after-tax) related	to	the	sale	of	EnLink	and	the	General	Partner	during 2018.	More	details	for	these	metrics	are	found	within	the "Results	of	Operations	–	2018	vs.	2017"	below.

|  | 2018 | Change | 2017 | Change | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Total: |  |  |  |  |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $3,064 | +241% | $898 | +185% | $(1,056) |
| Net\tearnings\t(loss)\tper\tdiluted\tshare\tattributable\tto\tDevon | $6.10 | +259% | $1.70 | +181% | $(2.09) |
| Core\tearnings\t(loss)\tattributable\tto\tDevon\t(1) | $655 | +53% | $427 | +216% | $(367) |
| Core\tearnings\t(loss)\tattributable\tto\tDevon\tper\tdiluted\tshare\t(1) | $1.30 | +60% | $0.81 | +212% | $(0.73) |
| Continuing\tOperations: |  |  |  |  |  |
| Net\tearnings\t(loss) | $764 | +1% | $758 | +232% | $(574) |
| Net\tearnings\t(loss)\tper\tdiluted\tshare | $1.52 | +6% | $1.43 | +225% | $(1.14) |
| Core\tearnings\t(loss)\t(1) | $587 | +48% | $397 | +207% | $(371) |
| Core\tearnings\t(loss)\tper\tdiluted\tshare\t(1) | $1.17 | +57% | $0.75 | +202% | $(0.73) |
| Discontinued\tOperations: |  |  |  |  |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $2,300 | +1543% | $140 | +129% | $(481) |
| Net\tearnings\t(loss)\tper\tdiluted\tshare\tattributable\tto\tDevon | $4.58 | +1596% | $0.27 | +128% | $(0.95) |
| Core\tearnings\tattributable\tto\tDevon\t(1) | $68 | +127% | $30 | +580% | $4 |
| Core\tearnings\tattributable\tto\tDevon\tper\tdiluted\tshare\t(1) | $0.13 | +120% | $0.06 | +1628% | $0.00 |
| Other\tMetrics: |  |  |  |  |  |
| Retained\tproduction\t(MBoe/d) | 500 | +4% | 481 | -\t3% | 497 |
| Total\tproduction\t(MBoe/d) | 535 | -\t2% | 543 | -\t11% | 611 |
| Realized\tprice\tper\tBoe\t(2) | $29.08 | +12% | $25.96 | +39% | $18.72 |
| Operating\tcash\tflow\tfrom\tcontinuing\toperations | $2,228 | +1% | $2,209 | +165% | $834 |
| Capitalized\texpenditures,\tincluding\tacquisitions | $2,576 | +19% | $2,169 | -\t23% | $2,826 |
| Cash\tand\tcash\tequivalents | $2,414 | -\t9% | $2,642 | +36% | $1,947 |
| Total\tdebt | $5,947 | -\t13% | $6,864 | +0% | $6,859 |
| Reserves\t(MMBoe) | 1,927 | -\t10% | 2,152 | +5% | 2,058 |

(1) Core	earnings	and	core	earnings	per	share	attributable	to	Devon	are	financial	measures	not	prepared	in	accordance	with	GAAP.	For	a	description	of	core	earnings and	core	earnings	per	share	attributable	to	Devon,	as	well	as	reconciliations	to	the	comparable	GAAP	measures,	see	"Non-GAAP	Measures"	in	this	Item	7.

(2) Excludes	any	impact	of	oil,	gas	and	NGL	derivatives.

# Business	and	Industry	Outlook

Market	prices	for	crude	oil	and	natural	gas	are	inherently	volatile.	Therefore,	we	cannot	predict	with	certainty	the	future	prices	for	the	commodities	we	produce and	sell.	In	2018,	WTI	oil	prices	averaged	approximately	$67/Bbl	through	October,	supported	by	stronger-than-expected	oil	demand,	market	management	by	both OPEC	and	non-OPEC	partners	and	unplanned	supply	outages.	However,	oil	prices	markedly	declined	in	November	and	December,	averaging	approximately	$53/Bbl	and reaching	as	low	as	$42.53/Bbl	in	December.	The	deterioration	of	WTI	was	driven	by	OPEC	and	non-OPEC	partners	unwinding	their	production	cut	agreement, compounded	by	rising	supply	and	concerns	over	slowing	global	economic	growth.	Western	Canadian	Select	basis	differentials	were	challenged	in	the	fourth	quarter	of 2018	due	to	robust	production	outpacing	local	demand,	pipeline	capacity	and	rail	capacity	out	of	the	region.	Looking	ahead,	current	market	fundamentals	indicate	that 2019	crude	pricing	is	expected	to	improve	from	its	fourth	quarter	2018	levels.	Additionally,	Western	Canadian	Select	differentials	are	also	projected	to	improve,	driven by	provincially	mandated	production	cuts	combined	with	takeaway	capacity	additions	expected	in	late	2019.	Changes	in	OPEC	production	strategies,	the	macro- economic	environment,	geopolitical	risks	and	other	factors	could	impact	our	current	forecasts.

In	2018,	Devon	marked	its	30th	year	as	a	public	company	and	47th	anniversary	in	the	oil	and	gas	business,	so	we	are	experienced	in	dealing	with	the	volatile nature	of	commodity	prices.	To	mitigate	our	exposure	to	commodity	market	volatility	and	ensure	our	financial	strength,	we	use	a	disciplined,	risk-management	hedging program.	Our	hedging	program	incorporates	both	systematic	hedges	added	on	a	regular	basis	and	discretionary	hedges	layered	in	on	an	opportunistic	basis	to	take advantage	of	favorable	market	conditions.	We	have	approximately	50%	of	our	anticipated	2019	oil	and	gas	volumes	hedged,	and	we	are	currently	adding	hedges	for 2020	as	well.	Further	insulating	our	cash	flow,	we	are	proactively	locking	in	hedges	on	the	Western	Canadian	Select	basis	differential	to	WTI	and	currently	have approximately	50%	of	our	2019	Canadian	heavy	oil	production	hedged.

Despite	the	uncertainties	pertaining	to	commodity	prices,	we	remain	focused	on	our	strategic	priorities	of	having	a	premier	portfolio	of	assets,	delivering	superior execution	as	we	drill	and	operate	oil	and	natural	gas	wells,	and	maintaining	our	financial	strength	and	flexibility.	2019	will	be	an	important	year	for	Devon	as	we	plan	to separate	our	Canadian	and	Barnett	Shale	assets	and	complete	our	multi-year	transition	to	a	U.S.	oil	company	with	operations	focused	on	four	core	areas	in	the	Delaware Basin,	STACK,	Eagle	Ford	and	Rockies.	With	a	focused	portfolio	of	U.S.	oil	assets,	we	also	intend	to	optimize	our	cost	structure	by	reducing	our	annual	capital	costs, G&A	costs,	interest	expense	and	production	expenses	by	$780	million	in	the	aggregate	by	2021.	We	expect	to	deliver	70%	of	these	annualized	cost	savings	in	2019,	as the	Canadian	and	Barnett	Shale	assets	are	separated,	and	we	align	our	workforce	with	the	retained	business	and	reduce	outstanding	debt.

Importantly,	the	portfolio	changes	and	optimized	cost	performance	are	expected	to	enhance	our	competitive	positioning	as	oil	production	growth,	price realizations,	field-level	margins	and	corporate	rates-of-return	should	all	improve.	With	these	improved	expected	outcomes,	we	remained	focused	on	our	2019	capital allocation	priorities	of	funding	our	core	operations,	protecting	our	investment-grade	credit	ratings	and	paying	our	shareholder	dividend.	Further,	when	considering	the current	commodity	price	environment	and	our	current	hedge	position,	we	can	achieve	all	our	capital	allocation	priorities	at	$46/Bbl	WTI	and	$3.00/Mcf	Henry	Hub. Should	WTI	drop	closer	to	$40/Bbl	for	an	extended	period,	we	would	shift	our	focus	to	preserving	our	financial	strength	and	operational	continuity.	However,	as	WTI rises	above	$46/Bbl,	our	free	cash	flow	will	accelerate,	providing	additional	capital	allocation	opportunities.

The	following	graphs,	discussion	and	analysis	are	intended	to	provide	an	understanding	of	our	results	of	operations	and	current	financial	condition.	Specifically, the	graph	below	shows	the	change	in	net	earnings	from	2017	to	2018.	The	material	changes	are	further	discussed	by	category	on	the	following	pages.	To	facilitate	the review,	these	numbers	are	being	presented	before	consideration	of	earnings	attributable	to	noncontrolling	interests.

(1) Other	in	the	table	above	includes	asset	impairments,	asset	dispositions,	restructuring	and	transaction	costs	and	other	expenses.

# The	graph	below	presents	the	drivers	of	the	upstream	operations	change	presented	above,	with	additional	details	and	discussion	of	the	drivers	following	the

# graph.

(2) As	further	discussed	in	Note	1	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	in	this	report,	in	2018	the	presentation	of	certain	processing	arrangements	changed	from	a net	to	a	gross	presentation.	The	change	resulted	in	an	increase	to	our	upstream	revenues	and	production	expenses	by	$254	million	during	2018	with	no	impact	to	net	earnings.

# Upstream	Operations

# Oil,	Gas	and	NGL	Production

|  | 2018 | %	of<br>Total | 2017 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(MBbls/d) |  |  |  |  |
| Delaware\tBasin | 42 | 17% | 29 | +42% |
| STACK | 32 | 13% | 25 | +28% |
| Rockies\tOil | 14 | 6% | 10 | +37% |
| Heavy\tOil | 18 | 7% | 18 | +1% |
| Eagle\tFord | 28 | 12% | 34 | -\t17% |
| Barnett\tShale | 1 | 0% | 1 | -\t7% |
| Other | 5 | 2% | 5 | -\t3% |
| Retained\tassets | 140 | 57% | 122 | +14% |
| U.S.\tdivested\tassets | 9 | 4% | 12 | -\t23% |
| Total\tOil | 149 | 61% | 134 | +11% |
| Bitumen | 97 | 39% | 110 | -\t12% |
| Total\tOil\tand\tbitumen | 246 | 100% | 244 | +1% |

|  | 2018 | %	of<br>Total | 2017 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Gas\t(MMcf/d) |  |  |  |  |
| Delaware\tBasin | 105 | 10% | 86 | +22% |
| STACK | 334 | 30% | 294 | +13% |
| Rockies\tOil | 16 | 1% | 8 | +85% |
| Heavy\tOil | 10 | 1% | 17 | -\t39% |
| Eagle\tFord | 79 | 7% | 95 | -\t17% |
| Barnett\tShale | 447 | 41% | 475 | -\t6% |
| Other | 1 | 0% | 1 | +6% |
| Retained\tassets | 992 | 90% | 976 | +2% |
| U.S.\tdivested\tassets | 108 | 10% | 227 | -\t52% |
| Total | 1,100 | 100% | 1,203 | -\t9% |

|  |  | %	of |  |  |
| :--- | :--- | :--- | :--- | :--- |
| NGLs\t(MBbls/d) | 2018 | Total | 2017 | Change |
| Delaware\tBasin | 16 | 15% | 10 | +53% |
| STACK | 37 | 35% | 30 | +24% |
| Rockies\tOil | 1 | 2% | 1 | +75% |
| Eagle\tFord | 13 | 12% | 13 | +2% |
| Barnett\tShale | 30 | 28% | 31 | -\t4% |
| Other | 1 | 1% | 1 | -\t5% |
| Retained\tassets | 98 | 93% | 86 | +14% |
| U.S.\tdivested\tassets | 8 | 7% | 13 | -\t40% |
| Total | 106 | 100% | 99 | +7% |

|  | 2018 | %	of<br>Total | 2017 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Combined\t(MBoe/d) |  |  |  |  |
| Delaware\tBasin | 75 | 14% | 54 | +39% |
| STACK | 125 | 24% | 104 | +20% |
| Rockies\tOil | 17 | 3% | 12 | +43% |
| Heavy\tOil | 117 | 22% | 131 | -\t11% |
| Eagle\tFord | 54 | 10% | 62 | -\t13% |
| Barnett\tShale | 105 | 20% | 111 | -\t5% |
| Other | 7 | 1% | 7 | -\t3% |
| Retained\tassets | 500 | 94% | 481 | +4% |
| U.S.\tdivested\tassets | 35 | 6% | 62 | -\t44% |
| Total | 535 | 100% | 543 | -\t2% |

Focused	development	activities	in	the	Delaware	Basin,	STACK	and	Rockies resulted	in	an	approximate	28%	increase	in	production	from	those	areas	compared to	2017.	These	increases	also	drove	a	17%	increase	in	our	U.S.	retained	oil production.	This	strong	performance	led	to	the	overall	growth	in	our	retained assets	during	2018.	Production	increases	from	our	capital	focused	assets	were partially	offset	by	the	effects	of	facility	repairs	and	other	maintenance	work	at	the Jackfish	facilities,	as	well	as	by	lower	production	resulting	from	our	U.S.	non-core divestitures.

# Oil,	Gas	and	NGL	Prices

|  | 2018 | Realization | 2017 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(per\tBbl) |  |  |  |  |
| WTI\tindex | \t$64.79 |  | \t$50.99 | +27% |
| Access\tWestern\tBlend\tindex | \t$34.75 |  | \t$36.90 | -\t6% |
| U.S. | \t$61.97 | 96% | \t$49.41 | +25% |
| Canada | \t$19.37 | 30% | \t$29.99 | -\t35% |
| Realized\tprice,\tunhedged | \t$42.04 | 65% | \t$39.23 | +7% |
| Cash\tsettlements | \t$(0.49) |  | \t$0.23 |  |
| Realized\tprice,\twith\thedges | \t$41.55 | 64% | \t$39.46 | +5% |

(1) Based	upon	composition	of	our	NGL	barrel.

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Combined\t(per\tBoe) |  |  |  |
| U.S. | \t$31.86 | \t$24.88 | +28% |
| Canada | \t$19.12 | \t$29.39 | -\t35% |
| Realized\tprice,\tunhedged | \t$29.08 | \t$25.96 | +12% |
| Cash\tsettlements | \t$(0.43) | \t$0.27 |  |
| Realized\tprice,\twith\thedges | \t$28.65 | \t$26.23 | +9% |

Upstream	revenues	increased	as	a	result	of	higher	unhedged,	realized	prices	for our	U.S.	oil	and	NGLs.

The	increase	in	oil	sales	primarily	resulted	from	higher	average	WTI	crude index	prices,	which	were	27%	higher	in	2018,	resulting	in	an	increase	of approximately	$568	million.

NGL	sales	increased	$351	million	as	a	result	of	14%	higher	NGL	prices	at	the Mont	Belvieu,	Texas	hub,	as	well	as	improved	realizations	in	our	NGL	price.

These	increases	were	partially	offset	by	widening	differentials	to	the	WTI index	for	bitumen	sales,	which	negatively	impacted	our	upstream	revenues	by $406	million.	In	the	fourth	quarter	of	2018,	market	forces	widened	Canadian heavy	oil	differentials	beyond	historical	norms	and	negatively	impacted	the	price we	realized	on	our	Canadian	production.	We	had	basis	swaps	for	approximately half	of	our	fourth	quarter	production	to	mitigate	the	effect	of	the	lower	market price.	To	further	mitigate	the	effects	of	the	lower	price,	we	reduced	our	Jackfish production	in	November	2018	which	impacted	our	fourth	quarter	production	by approximately	8	MBbls/d.	Our	Canadian	heavy	oil	unhedged	realized	price	for	the fourth	quarter	was	near	zero.	To	date	in	2019,	heavy	oil	differentials	have significantly	improved	driven	by	provincially	mandated	production	cuts	combined with	takeaway	capacity	additions	expected	in	2019.

As	further	discussed	in	Note	1	in	"Item	8.	Financial	Statements	and Supplementary	Data"	of	this	report,	in	2018	the	presentation	of	certain	processing arrangements	changed	from	a	net	to	a	gross	presentation.	The	change	resulted	in an	increase	to	our	upstream	revenues	and	production	expenses	by	approximately $254	million	with	no	impact	to	net	earnings.

# Commodity	Derivatives

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
|  | Q |  |  |
| Oil | \t $(44)\t $ | 21 | -\t310% |
| Natural\tgas | 5 | 35 | -\t86% |
| NGL | (45) | (3) | -\t1400% |
| Total\tcash\tsettlements | (84) | 53 | -\t258% |
| Valuation\tchanges | 692 | 104 | +565% |
| Total | \t $608 | \t $157 | +287% |

Cash	settlements	as	presented	in	the	tables	above	represent	realized	gains	or losses	related	to	the	instruments	described	in	Note	3	in	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

In	addition	to	cash	settlements,	we	also	recognize	fair	value	changes	on	our	oil, gas	and	NGL	derivative	instruments	in	each	reporting	period.	The	changes	in	fair value	resulted	from	new	positions	and	settlements	that	occurred	during	each period,	as	well	as	the	relationship	between	contract	prices	and	the	associated forward	curves.

# Production	Expenses

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| LOE | \t$995 | \t$927 | +7% |
| Gathering,\tprocessing\t&amp;\ttransportation | 891 | 647 | +38% |
| Production\ttaxes | 278 | 194 | +43% |
| Property\ttaxes | 61 | 55 | +11% |
| Total | \t$2,225 | \t$1,823 | +22% |
| Per\tBoe: |  |  |  |
| LOE | \t$5.10 | \t$4.67 | +9% |
| Gathering,\tprocessing\t&amp; |  |  |  |
| \t\t\ttransportation\nPercent\tof\toil,\tgas\tand\tNGL\tsales: | \t$4.56 | \t$3.26 | +40% |
| Production\ttaxes | 4.9% | 3.8% | +27% |

LOE	increased	$68	million	primarily	due	to	continued	focus	on	growing	our liquids-rich	assets	within	the	STACK	and	Delaware	Basin	and	higher	maintenance costs	at	our	Jackfish	facilities,	partially	offset	by	our	U.S.	non-core	divestitures.

Production	taxes	increased	on	an	absolute	dollar	basis	primarily	due	to	the increase	in	our	U.S.	upstream	revenues,	on	which	the	majority	of	our	production taxes	are	assessed.	Additionally,	the	increase	in	Oklahoma	severance	tax	rates	that became	effective	during	the	third	quarter	of	2018	also	contributed	to	the	increase on	an	absolute	dollar	basis	and	as	a	percentage	of	oil,	gas	and	NGL	sales.

Property	taxes	increased	as	a	result	of	higher	property	value	assessments, primarily	on	our	Texas	properties,	partially	offset	by	our	U.S.	non-core divestitures.

# Marketing	Operations

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Marketing\trevenues | \t$4,449 | \t$3,571 | +25% |
| Marketing\texpenses | (4,363) | (3,619) | -\t21% |
| Margin | \t$86 | \t$(48) | +279% |

The	overall	increase	in	marketing	operating	margin	was	primarily	due	to improved	commodity	prices,	which	were	partially	offset	by	the	impact	of	our downstream	marketing	commitments.

# Exploration	Expenses

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Unproved\timpairments | \t$95\t\t$ | 217 | -\t56% |
| Geological\tand\tgeophysical | 21 | 110 | -\t81% |
| Exploration\toverhead\tand\tother | 61 | 53 | +15% |
| Total | \t$177\t\t$ | 380 | -\t53% |

Unproved	impairments	in	both	periods	primarily	relate	to	a	portion	of	acreage in	our	U.S.	non-core	operations	upon	which	we	do	not	intend	to	pursue	further exploration	and	development.	Geological	and	geophysical	costs	decreased primarily	in	the	STACK	and	Delaware	Basin.

# Depreciation,	Depletion	and	Amortization

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Oil\tand\tgas\tper\tBoe | \t$7.98 | $7.15 | +12% |
| Oil\tand\tgas | \t$1,559 | $1,419 | +10% |
| Other\tproperty\tand\tequipment | 99 | 110 | -\t10% |
| Total | \t$1,658 | \t$1,529 | +8% |

Our	oil	and	gas	DD&A	increased	primarily	due	to	continued	development	in the	STACK,	Delaware	Basin	and	Rockies	properties.	The	increases	were	slightly offset	by	reduced	production	volumes	at	the	Jackfish	facilities	and	from	our	2018 U.S.	non-core	asset	divestitures.

# General	and	Administrative	Expenses

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Labor\tand\tbenefits | \t$494 | \t$582 | -\t15% |
| Non-labor | 236 | 228 | +4% |
| Reimbursed\tG&amp;A | (80) | (73) | -\t10% |
| Total\tDevon | \t$650 | \t$737 | -\t12% |

Labor	and	benefits	decreased	primarily	as	a	result	of	the	workforce	reduction that	occurred	during	2018	as	discussed	in	Note	6	in	"Item	8.	Financial	Statements and	Supplementary	Data"	of	this	report.	Non-labor	costs	were	higher	due	to	an increase	in	costs	related	to	automation	and	process	improvements.

# Financing	Costs,	net

Financing	costs,	net	increased	$277	million	as	a	result	of	a	$312	million	loss	on early	retirement	of	debt.	For	further	discussion	of	early	retirement	premiums	and reduced	interest	expense	resulting	from	our	lower	debt	balances,	see	Note	15	in

"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Other

|  | 2018 | 2017 | Change |
| :--- | :--- | :--- | :--- |
| Asset\timpairments | \t$156 | \t$— | N/M |
| Asset\tdispositions | (263) | (217) | -\t21% |
| Restructuring | 114 | — | N/M |
| Other | 140 | (83) | +269% |
| Total | \t$147 | \t$(300) | +149% |

Additional	information	regarding	the	impairments	is	discussed	in	Note	5	in "Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

We	recognized	gains	in	conjunction	with	certain	of	our	U.S.	asset	dispositions in	2017	and	2018.	For	further	discussion,	see	Note	2	in	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

During	2018,	we	recognized	restructuring	and	transaction	costs	of	$114 million	primarily	as	a	result	of	our	workforce	reduction.	See	Note	6	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report.

The	remaining	change	in	other	expense	was	driven	primarily	by	changes	on foreign	currency	exchange	instruments	as	further	discussed	in	Note	7	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report.

# Income	Taxes

|  | 2018 | 2017 |
| :--- | :--- | :--- |
| Current\texpense\t(benefit) | \t$(70) | $112 |
| Deferred\texpense\t(benefit) | 226 | (97) |
| Total\texpense | \t$156 | $15 |
| Effective\tincome\ttax\trate | 17% | 2% |

For	discussion	on	income	taxes,	see	Note	8	in	"Item	8.	Financial	Statements and	Supplementary	Data"	of	this	report.

# Discontinued	Operations

Discontinued	operations	net	earnings	increased	primarily	due	to	the	gain	on	the sale	of	our	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	of $2.6	billion	($2.2	billion	after-tax).	For	discussion	on	discontinued	operations, see	Note	19	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this report"	of	this	report.

The	graph	below	shows	the	change	in	net	earnings	from	2016	to	2017.	The	material	changes	are	further	discussed	by	category	on	the	following	pages.	To facilitate	the	review,	these	numbers	are	being	presented	before	consideration	of	earnings	attributable	to	noncontrolling	interests.

The	graph	below	presents	the	drivers	of	the	upstream	operations	change	presented	above,	with	additional	details	and	discussion	of	the	drivers	following	the graph.

|  | 2017 | %	of<br>Total | 2016 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(MBbls/d) |  |  |  |  |
| Delaware\tBasin | 29 | 12% | 32 | -\t7% |
| STACK | 25 | 11% | 18 | +39% |
| Rockies\tOil | 10 | 4% | 9 | +9% |
| Heavy\tOil | 18 | 7% | 22 | -\t19% |
| Eagle\tFord | 34 | 14% | 39 | -\t14% |
| Barnett\tShale | 1 | 0% | 1 | -\t25% |
| Other | 5 | 2% | 6 | -\t13% |
| Retained\tassets | 122 | 50% | 127 | -\t4% |
| U.S.\tdivested\tassets | 12 | 5% | 24 | -\t51% |
| Total\tOil | 134 | 55% | 151 | -\t11% |
| Bitumen | 110 | 45% | 109 | +1% |
| Total\tOil\tand\tbitumen | 244 | 100% | 260 | -\t6% |

|  |  | %	of |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Gas\t(MMcf/d) | 2017 | Total | 2016 | Change |
| Delaware\tBasin | 86 | 7% | 86 | +1% |
| STACK | 294 | 24% | 282 | +4% |
| Rockies\tOil | 8 | 1% | 16 | -\t48% |
| Heavy\tOil | 17 | 2% | 20 | -\t14% |
| Eagle\tFord | 95 | 8% | 101 | -\t6% |
| Barnett\tShale | 475 | 39% | 530 | -\t10% |
| Other | 1 | 0% | 1 | -\t10% |
| Retained\tassets | 976 | 81% | 1,036 | -\t6% |
| U.S.\tdivested\tassets | 227 | 19% | 377 | -\t40% |
| Total | 1,203 | 100% | 1,413 | -\t15% |

|  | 2017 | %	of<br>Total | 2016 | Change |
| :--- | :--- | :--- | :--- | :--- |
| NGLs\t(MBbls/d) |  |  |  |  |
| Delaware\tBasin | 10 | 10% | 11 | -\t10% |
| STACK | 30 | 30% | 25 | +19% |
| Rockies\tOil | 1 | 1% | 1 | +23% |
| Eagle\tFord | 13 | 13% | 16 | -\t19% |
| Barnett\tShale | 31 | 32% | 34 | -\t9% |
| Other | 1 | 1% | 1 | -\t4% |
| Retained\tassets | 86 | 87% | 88 | -\t3% |
| U.S.\tdivested\tassets | 13 | 13% | 28 | -\t53% |
| Total | 99 | 100% | 116 | -\t15% |

|  | 2017 | %	of<br>Total | 2016 | Change |
| :--- | :--- | :--- | :--- | :--- |
| Combined\t(MBoe/d) |  |  |  |  |
| Delaware\tBasin | 54 | 10% | 57 | -\t6% |
| STACK | 104 | 19% | 90 | +15% |
| Rockies\tOil | 12 | 2% | 13 | -\t3% |
| Heavy\tOil | 131 | 24% | 134 | -\t2% |
| Eagle\tFord | 62 | 11% | 72 | -\t13% |
| Barnett\tShale | 111 | 21% | 123 | -\t10% |
| Other | 7 | 1% | 8 | -\t6% |
| Retained\tassets | 481 | 88% | 497 | -\t3% |
| U.S.\tdivested\tassets | 62 | 12% | 114 | -\t45% |
| Total | 543 | 100% | 611 | -\t11% |

Production	declines	reduced	our	upstream	revenues	by	$427	million	primarily as	a	result	of	our	U.S.	divested	assets.	Retained	production	volumes	decreased	due to	reduced	completion	activity	in	the	Eagle	Ford	and	natural	production	declines	in the	Barnett	Shale.	These	decreases	were	partially	offset	by	expanded	drilling	and performance	in	the	STACK.

| Oil	and	bitumen	(per	Bbl) | 2017 | Realization | 2016 | Change |
| :--- | :--- | :--- | :--- | :--- |
| WTI\tindex | \t$50.99 |  | \t\t$43.36 | +18% |
| Access\tWestern\tBlend\tindex | \t$36.90 |  | \t\t$26.96 | +37% |
| U.S. | \t$49.41 | 97% | \t$38.92 | +27% |
| Canada | \t$29.99 | 59% | \t$20.53 | +46% |
| Realized\tprice,\tunhedged | \t$39.23 | 77% | \t$29.65 | +32% |
| Cash\tsettlements | \t$0.23 |  | \t$(0.43) |  |
| Realized\tprice,\twith\thedges | \t$39.46 | 77% | \t$29.22 | +35% |

(1) Based	upon	composition	of	average	Devon	NGL	barrel.

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
| Combined\t(per\tBoe) |  |  |  |
| U.S. | \t$24.88 | \t$18.34 | +36% |
| Canada | \t$29.39 | \t$20.07 | +46% |
| Realized\tprice,\tunhedged | \t$25.96 | \t$18.72 | +39% |
| Cash\tsettlements | \t$0.27 | \t$(0.05) |  |
| Realized\tprice,\twith\thedges | \t$26.23 | \t$18.67 | +40% |

Upstream	revenues	increased	$1.4	billion	as	a	result	of	higher	unhedged, realized	prices	across	our	entire	portfolio.	The	increase	in	oil	and	bitumen	sales primarily	resulted	from	higher	average	WTI	crude	index	prices,	which	were	18% higher	in	2017.	Additionally,	our	oil	and	bitumen	sales	benefited	from	tighter differentials	to	the	WTI	index.	The	increase	in	gas	sales	was	driven	by	higher North	American	regional	index	prices	upon	which	our	gas	sales	are	based	and higher	NGL	prices	at	the	Mont	Belvieu,	Texas	hub.

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
|  | Q |  |  |
| Oil | \t $21 | \t $(41) | +151% |
| Natural\tgas | 35 | 35 | +0% |
| NGL | (3) | (5) | +40% |
| Total\tcash\tsettlements | 53 | (11) | N/M |
| Valuation\tchanges | 104 | (190) | +155% |
| Total | \t $157 | \t $(201) | +178% |

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
| LOE | \t$927 | \t$1,027 | -\t10% |
| Gathering,\tprocessing\t&amp;\ttransportation | 647 | 555 | +17% |
| Production\ttaxes | 194 | 149 | +30% |
| Property\ttaxes | 55 | 74 | -\t26% |
| Total | \t$1,823 | \t$1,805 | +1% |
| Per\tBoe: |  |  |  |
| LOE | \t$4.67 | \t$4.59 | +2% |
| Gathering,\tprocessing\t&amp; |  |  |  |
| \t\t\ttransportation | \t$3.26 | \t$2.48 | +31% |
| Percent\tof\toil,\tgas\tand\tNGL\tsales: |  |  |  |
| Production\ttaxes | 3.8% | 3.5% | +7% |

LOE	decreased	$100	million	primarily	due	to	our	U.S.	property	divestitures	in 2016.	Well	optimization	and	cost	reduction	initiatives	across	our	portfolio	offset industry	inflation.	These	initiatives	have	been	primarily	focused	on	reducing	costs associated	with	water	disposal,	power	and	fuel,	compression	and	workovers.

Gathering	and	transportation	expense	increased	$92	million	primarily	due	to	a full	year	of	the	Access	Pipeline	transportation	tolls,	which	commenced	in	the fourth	quarter	of	2016	subsequent	to	the	sale	of	our	interest	in	the	pipeline.	Our Access	transportation	agreement	contains	a	base	transportation	commitment, which	for	the	initial	five	years	averages	$110	million	annually.

Production	taxes	increased	on	an	absolute	dollar	basis	primarily	due	to	the increase	in	our	U.S.	upstream	revenues,	on	which	the	majority	of	our	production taxes	are	assessed.

Property	taxes	decreased	as	a	result	of	lower	property	value	assessments	from the	local	taxing	authorities	across	our	key	operating	areas	and	as	a	result	of	our U.S.	asset	divestitures.

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
| Unproved\timpairments | $217 | \t$77 | +182% |
| Geological\tand\tgeophysical | 110 | 65 | +70% |
| Exploration\toverhead\tand\tother | 53 | 73 | -\t27% |
| Total | $380 | \t$215 | +77% |

Unproved	impairments	primarily	relate	to	a	portion	of	acreage	in	our	U.S.	non- core	operations	upon	which	we	do	not	intend	to	pursue	further	exploration	and development.	Geological	and	geophysical	costs	increased	primarily	in	the	STACK and	Delaware	Basin.

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
| Oil\tand\tgas\tper\tBoe | \t$7.15 | $6.47 | +11% |
| Oil\tand\tgas | \t$1,419 | $1,446 | -\t2% |
| Other\tproperty\tand\tequipment | 110 | 146 | -\t25% |
| Total | \t$1,529 | \t$1,592 | -\t4% |

Our	oil	and	gas	DD&A	remained	relatively	flat	as	compared	to	the	prior	year. Increases	in	oil	and	gas	DD&A	rates	due	to	continued	development	in	the	STACK and	Delaware	Basin	were	offset	by	reduced	production	volumes	resulting	from	the 2016	U.S.	asset	divestitures.	DD&A	from	our	other	property	and	equipment decreased	due	to	the	divestiture	of	the	Access	Pipeline	in	the	fourth	quarter	of 2016.

Financing	costs,	net	decreased	$400	million	primarily	as	a	result	of	our	$2.1 billion	early	debt	retirement	in	2016.	For	further	discussion	of	early	retirement premiums	and	reduced	interest	expense	resulting	from	our	lower	debt	balances, see	Note	15	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this report.

|  | 2017 | 2016 | Change |
| :--- | :--- | :--- | :--- |
| Asset\timpairments | \t$—\t\t$437 | \t$—\t\t$437 | -\t100% |
| Asset\tdispositions | (217) | (1,496) | +85% |
| Restructuring | — | 261 | -\t100% |
| Other | (83) | 101 | -\t183% |
| Total | \t$(300)\t$ | (697) | +57% |

In	2016,	we	recognized	proved	asset	impairments	on	a	portion	of	our	U.S. assets.	See	Note	5	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of this	report	for	additional	information.

We	recognized	gains	in	conjunction	with	certain	of	our	asset	dispositions	in both	2016	and	2017	and	the	divestiture	of	our	50%	interest	in	the	Access	Pipeline in	2016.	For	further	discussion,	see	Note	2	in	"Item	8.	Financial	Statements	and Supplementary	Data"	of	this	report.

During	2016,	we	recognized	restructuring	and	transaction	costs	of	$261 million	primarily	as	a	result	of	our	workforce	reduction.	For	discussion	of	our reorganization	programs	and	the	associated	restructuring	costs,	see	Note	6	in	"Item 8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

|  | 2017 | 2016 |
| :--- | :--- | :--- |
| Current\texpense | $112 | $98 |
| Deferred\texpense\t(benefit) | (97) | 43 |
| Total\texpense | $15 | $141 |
| Effective\tincome\ttax\trate | 2% | (33%) |

For	discussion	on	discontinued	operations,	see	Note	19	in	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

# Capital	Resources,	Uses	and	Liquidity

# Sources	and	Uses	of	Cash

The	following	table	presents	the	major	changes	in	cash	and	cash	equivalents	for	the	time	periods	presented	below.

|  |  | Year	ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Operating\tcash\tflow\tfrom\tcontinuing\toperations | $2,228 | \t$2,209 | $834 |
| Divestitures\tof\tproperty\tand\tequipment | 1,013 | 426 | 3,020 |
| Capital\texpenditures | (2,451) | (1,968) | (1,384) |
| Acquisitions\tof\tproperty\tand\tequipment | (55) | (46) | (849) |
| Debt\tactivity,\tnet | (1,226) | — | (3,383) |
| Repurchases\tof\tcommon\tstock | (2,956) | — | — |
| Common\tstock\tdividends | (149) | (127) | (221) |
| Issuance\tof\tcommon\tstock | — | — | 1,469 |
| Effect\tof\texchange\trate\tand\tother | 151 | (53) | (96) |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\trestricted\tcash |  |  |  |
| \t\t\tfrom\tdiscontinued\toperations | 3,207 | 284 | 259 |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\trestricted\tcash | $(238) | $725 | $(351) |
| Cash,\tcash\tequivalents\tand\trestricted\tcash\tat\tend\tof\tperiod | $2,446 | \t$2,684 | $1,959 |

# Operating	Cash	Flow	–	Continuing	Operations

Net	cash	provided	by	operating	activities	continued	to	be	a	significant	source	of	capital	and	liquidity	in	2018.	Our	operating	cash	flow	was	relatively	flat compared	to	2017.	In	2018,	our	operating	cash	flow	funded	approximately	86%	of	our	capital	expenditure	program	and	dividends.	We	utilized	available	cash	balances and	divestiture	proceeds	to	supplement	our	operating	cash	flows.	Operating	cash	flow	for	2018	included	a	realized	foreign	exchange	loss	of	$241	million	relating	to foreign	currency	denominated	intercompany	loan	activity	as	described	in	Note	7	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.	There	was	an offset	in	the	effect	of	exchange	rate	and	other	line	in	the	above	table,	resulting	in	no	impact	to	the	net	change	in	cash,	cash	equivalents	and	restricted	cash.

Our	operating	cash	flow	increased	$1.4	billion,	or	165%,	from	2016	to	2017.	In	2017,	our	operating	cash	flow	fully	funded	our	capital	expenditures	program	as well	as	our	dividends.	In	2016,	our	operating	cash	flow	did	not	fully	fund	our	capital	requirements	and	dividends;	as	a	result,	we	utilized	available	cash	balances	and divestiture	proceeds	to	supplement	our	operating	cash	flows.

# Divestitures	of	Property	and	Investments

During	2018,	as	part	of	our	announced	divestiture	program,	we	sold	non-core	U.S.	upstream	assets	for	approximately	$1.0	billion.	For	further	discussion,	see Note	2	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

During	2017,	as	part	of	our	announced	divestiture	program,	we	sold	non-core	U.S.	upstream	assets	for	approximately	$420	million.	For	further	discussion,	see Note	2	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

During	2016,	we	divested	certain	non-core	upstream	assets	in	the	U.S.	and	our	50%	interest	in	the	Access	Pipeline	in	Canada	for	approximately	$3.0	billion,	net of	purchase	price	adjustments.	Proceeds	from	these	divestitures	were	used	primarily	for	debt	repayment	and	to	support	capital	investment	in	our	core	resource	plays.	For further	discussion,	see	Note	2	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

We	did	not	have	significant	current	cash	income	taxes	resulting	from	the	divestitures	in	2018,	2017	and	2016.

# Capital	Expenditures

The	following	table	summarizes	our	capital	expenditures	and	property	acquisitions.

|  |  | Year	ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Oil\tand\tgas | $2,395 | $1,879 | $1,341 |
| Corporate\tand\tother | 56 | 89 | 43 |
| Total\tcapital\texpenditures | \t $2,451 | $1,968 | $1,384 |
| Acquisitions | $55 | $46 | $849 |

Capital	expenditures	consist	primarily	of	amounts	related	to	our	oil	and	gas	exploration	and	development	operations	and	other	corporate	activities.	The	vast majority	of	our	capital	expenditures	are	for	the	acquisition,	drilling	and	development	of	oil	and	gas	properties.	Our	capital	program	is	designed	to	operate	within	or	near operating	cash	flow	and	may	fluctuate	with	changes	to	commodity	prices	and	other	factors	impacting	cash	flow.	This	is	evidenced	by	our	operating	cash	flow	funding approximately	91%	of	capital	expenditures	in	2018	and	fully	funding	capital	expenditures	in	2017.

Acquisition	costs	in	2016	primarily	consisted	of	Devon's	bolt-on	acquisition	of	assets	in	the	STACK	play	for	$1.5	billion.	Approximately	$849	million	was	paid in	cash	at	closing	with	the	remainder	of	the	purchase	price	funded	with	equity	consideration.	See	Note	2	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of this	report	for	more	information.

# Debt	Activity,	Net

During	2018,	our	debt	decreased	$922	million	due	to	completed	tender	offers	of	certain	long-term	debt	as	well	as	the	maturity	of	certain	senior	notes.	In conjunction	with	the	tender	offers,	we	recognized	a	$312	million	loss	on	the	early	retirement	of	debt,	including	$304	million	of	cash	retirement	costs	and	fees.	For additional	information,	see	Note	15	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

During	2016,	our	debt	decreased	$3.1	billion	due	to	completed	tender	offers	to	purchase	and	redeem	$2.1	billion	of	debt	securities	prior	to	their	maturity	and	a	$1 billion	reduction	in	short-term	borrowings.	In	conjunction	with	the	tender	offers,	we	recognized	a	$269	million	loss	on	the	early	retirement	of	debt,	including	$265 million	of	cash	retirement	costs	and	fees.	For	additional	information,	see	Note	15	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Repurchases	of	Common	Stock	and	Shareholder	Distributions

In	June	2018,	in	conjunction	with	the	announcement	of	the	divestiture	of	our	investment	in	EnLink	and	the	General	Partner,	our	Board	of	Directors	authorized	a $4.0	billion	share	repurchase	program	of	our	common	stock.	The	share	repurchase	program	expires	December	31,	2019.	As	discussed	further	in	Note	18	in	"Item	8. Financial	Statements	and	Supplementary	Data"	in	this	report,	we	repurchased	78.1	million	shares	of	common	stock	for	$3.0	billion,	or	$38.11	per	share,	under	the	ASR agreement	and	through	open-market	share	repurchases	through	December	31,	2018.

Devon	paid	common	stock	dividends	of	$149	million,	$127	million	and	$221	million	during	2018,	2017	and	2016,	respectively.	During	the	second	quarter	of 2018,	we	increased	our	quarterly	dividend	33%	to	$0.08	per	share	as	part	of	our	initiative	to	return	cash	to	shareholders.	Our	prior	quarterly	dividend	was	$0.06	per	share subsequent	to	a	reduction	from	$0.24	per	share	in	the	second	quarter	of	2016	due	to	the	depressed	commodity	price	environment.	For	additional	information,	see	Note	18 in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Issuance	of	Common	Stock

In	February	2016,	we	issued	79	million	shares	of	our	common	stock	to	the	public,	inclusive	of	10	million	shares	sold	as	part	of	the	underwriters'	option.	Net proceeds	from	the	offering	were	approximately	$1.5	billion.

# Cash	Flows	from	Discontinued	Operations

All	cash	flows	in	the	following	table	relate	to	activities	of	EnLink	and	the	General	Partner.

|  | 2018 | Year	ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Cash\tflows\tfrom\tdiscontinued\toperations: |  |  |  |
| Operating\tactivities | $476 | $700 | $666 |
| Capital\texpenditures\tand\tother | (556) | (801) | (1,381) |
| Divestitures\tof\tinvestments | 3,104 | 190 | — |
| Investing\tactivities | 2,548 | (611) | (1,381) |
| Debt\tactivity,\tnet | 347 | 2 | 228 |
| Issuance\tof\tsubsidiary\tunits | 1 | 501 | 892 |
| Distributions\tto\tnoncontrolling\tinterests | (217) | (354) | (304) |
| Other | 52 | 46 | 158 |
| Financing\tactivities | 183 | 195 | 974 |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\n\t\t\trestricted\tcash\tof\tdiscontinued\toperations | $3,207 | $284 | $259 |

Operating	cash	flow	in	2018	decreased	$224	million	and	$190	million	from	2017	and	2016,	respectively,	as	a	result	of	the	divestiture	of	our	aggregate	ownership interests	in	EnLink	and	the	General	Partner	in	July	2018.

Cash	flows	from	investing	activities	for	2018	includes	$3.125	billion	received	from	the	divestiture	of	our	aggregate	ownership	interests	in	EnLink	and	the General	Partner,	partially	offset	by	capital	expenditures	and	other	items.	Capital	expenditures	for	EnLink's	midstream	operations	are	primarily	for	the	construction	and expansion	of	oil	and	gas	gathering	facilities	and	pipelines.	During	2017,	EnLink	divested	its	ownership	interest	in	Howard	Energy	Partners	for	approximately	$190 million.	During	2016,	EnLink	acquired	Anadarko	Basin	gathering	and	processing	midstream	assets	for	$1.5	billion.	Approximately	$792	million	was	paid	in	cash	at closing	with	the	remainder	of	the	purchase	price	funded	with	equity	consideration	and	debt.

Cash	flows	from	financing	activities	includes	common	and	preferred	units	EnLink	issued	and	sold	during	2017	and	2016	generating	net	proceeds	of approximately	$501	million	and	$892	million,	respectively.	Distributions	to	noncontrolling	interests	in	the	table	above	exclude	the	distributions	EnLink	and	the	General Partner	paid	to	Devon,	which	have	been	eliminated	in	consolidation.	Distributions	Enlink	and	the	General	Partner	paid	to	Devon	were	$134	million,	$265	million	and $265	million	during	2018,	2017	and	2016,	respectively.

# Liquidity

The	business	of	exploring	for,	developing	and	producing	oil	and	natural	gas	is	capital	intensive.	Because	oil,	natural	gas	and	NGL	reserves	are	a	depleting resource,	we,	like	all	upstream	operators,	must	continually	make	capital	investments	to	grow	and	even	sustain	production.	Generally,	our	capital	investments	are	focused on	drilling	and	completing	new	wells	and	maintaining	production	from	existing	wells.	At	opportunistic	times,	we	also	acquire	operations	and	properties	from	other operators	or	land	owners	to	enhance	our	existing	portfolio	of	assets.

Historically,	our	primary	sources	of	capital	funding	and	liquidity	have	been	our	operating	cash	flow,	cash	on	hand	and	asset	divestiture	proceeds.	Additionally, we	maintain	a	commercial	paper	program,	supported	by	our	revolving	line	of	credit,	which	can	be	accessed	as	needed	to	supplement	operating	cash	flow	and	cash balances.	If	needed,	we	can	also	issue	debt	and	equity	securities	pursuant	to	our	shelf	registration	statement	filed	with	the	SEC.	In	February	2019,	we	also	announced plans	to	separate	our	Canadian	and	Barnett	Shale	assets	and	operations.	We	expect	to	complete	these	asset	separations	in	2019.	We	plan	to	use	the	proceeds	from	these transactions	for	debt	repayments	and	common	share	repurchases.	We	estimate	the	combination	of	our	sources	of	capital	will	continue	to	be	adequate	to	fund	our	planned capital	requirements	as	discussed	in	this	section.

# Operating	Cash	Flow

Key	inputs	into	determining	our	planned	capital	investment	is	the	amount	of	cash	we	hold	and	operating	cash	flow	we	expect	to	generate	over	the	next	one	to three	or	more	years.	At	the	end	of	2018,	we	held	approximately	$2.4	billion	of	cash.	Our	operating	cash	flow	forecasts	are	sensitive	to	many	variables	and	include	a measure	of	uncertainty	as	these	variables	differ	from	our	expectations.

Commodity	Prices	–	The	most	uncertain	and	volatile	variables	for	our	operating	cash	flow	are	the	prices	of	the	oil,	bitumen,	gas	and	NGLs	we	produce	and	sell. Prices	are	determined	primarily	by	prevailing	market	conditions.	Regional	and	worldwide	economic	activity,	weather	and	other	substantially	variable	factors	influence market	conditions	for	these	products.	These	factors,	which	are	difficult	to	predict,	create	volatility	in	prices	and	are	beyond	our	control.	For	illustration,	our	operating cash	flow	slightly	increased	in	2018	largely	due	to	16%	growth	from	our	retained	U.S.	liquids	portfolio,	as	well	as	32%	higher	realized	pricing	related	to	these	assets. These	increases	were	mostly	offset	by	a	significant	decrease	in	our	realized	price	for	our	bitumen	production	in	2018.	Western	Canadian	Select	basis	differentials widened	significantly	above	historical	norms	due	to	robust	production	outpacing	local	demand,	pipeline	capacity	and	rail	capacity	out	of	the	region.	The	market fundamentals	led	our	fourth	quarter	unhedged	realized	price	for	bitumen	to	be	near	$0	per	Bbl.	In	the	first	two	months	of	2019,	government-mandated	production curtailments	and	current	market	fundamentals	have	led	to	a	significant	improvement	in	the	Western	Canadian	Select	basis	differential.

To	mitigate	some	of	the	risk	inherent	in	prices,	we	utilize	various	derivative	financial	instruments	to	protect	a	portion	of	our	production	against	downside	price risk.	We	target	hedging	approximately	50%	of	our	production	in	a	manner	that	systematically	places	hedges	for	several	quarters	in	advance,	allowing	us	to	maintain	a disciplined	risk	management	program	as	it	relates	to	commodity	price	volatility.	We	supplement	the	systematic	hedging	program	with	discretionary	hedges	that	take advantage	of	favorable	market	conditions.	We	currently	have	approximately	50%	of	our	anticipated	2019	oil	and	gas	volumes	hedged,	and	we	are	adding	hedges	for 2020	as	well.	Further	insulating	our	cash	flow,	we	are	proactively	locking	in	hedges	on	the	Western	Canada	Select	basis	differential	to	WTI	and	currently	have approximately	50%	of	our	2019	Canadian	heavy	oil	production	hedged.	The	key	terms	to	our	oil,	gas	and	NGL	derivative	financial	instruments	as	of	December	31,	2018 are	presented	in	Note	3	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

Further,	when	considering	the	current	commodity	price	environment	and	our	current	hedge	position,	we	expect	to	achieve	our	capital	investment	priorities	at $46/Bbl	WTI	and	$3.00/Mcf	Henry	Hub.	Should	WTI	drop	closer	to	$40/Bbl	for	an	extended	period,	we	would	shift	our	focus	to	preserving	our	financial	strength	and operational	continuity.	However,	as	WTI/Bbl	rises	above	$46,	our	free	cash	flow	will	accelerate,	providing	additional	capital	allocation	opportunities.

Operating	Expenses	–	Commodity	prices	can	also	affect	our	operating	cash	flow	through	an	indirect	effect	on	operating	expenses.	Significant	commodity	price decreases	can	lead	to	a	decrease	in	drilling	and	development	activities.	As	a	result,	the	demand	and	cost	for	people,	services,	equipment	and	materials	may	also	decrease, causing	a	positive	impact	on	our	cash	flow	as	the	prices	paid	for	services	and	equipment	decline.	However,	the	inverse	is	also	generally	true	during	periods	of	rising commodity	prices.

For	2019,	we	expect	to	aggressively	optimize	our	cost	structure	in	conjunction	with	our	planned	Canadian	and	Barnett	Shale	asset	divestitures,	as	we	focus	on	our remaining	four	U.S.	oil	plays,	align	our	workforce	with	the	retained	business	and	reduce	outstanding	debt.	We	anticipate	the	planned	$780	million	reduction	of annualized	costs	will	occur	over	three	years,	with	roughly	70%	of	the	savings	delivered	by	the	end	of	2019.	Approximately	40%	of	the	reduced	costs	relate	to	our	capital programs	and	the	remainder	relates	to	our	operating	expenses,	including	G&A,	interest	expense	and	production	expenses.

Credit	Losses	–	Our	operating	cash	flow	is	also	exposed	to	credit	risk	in	a	variety	of	ways.	This	includes	the	credit	risk	related	to	customers	who	purchase	our	oil, gas	and	NGL	production,	the	collection	of	receivables	from	our	joint-interest	partners	for	their	proportionate	share	of	expenditures	made	on	projects	we	operate	and counterparties	to	our	derivative	financial	contracts.	We	utilize	a	variety	of	mechanisms	to	limit	our	exposure	to	the	credit	risks	of	our	customers,	partners	and counterparties.	Such	mechanisms	include,	under	certain	conditions,	requiring	letters	of	credit,	prepayments	or	collateral	postings.

# Divestitures	of	Property	and	Equipment

In	the	first	quarter	of	2019,	we	sold	non-core	assets	for	approximately	$300	million.	We	also	anticipate	separating	our	Canadian	and	Barnett	Shale	businesses from	our	Company	in	2019.

# Credit	Availability

Our	2018	Senior	Credit	Facility,	under	which	we	have	$2.9	billion	of	available	borrowing	capacity	at	December	31,	2018,	matures	on	October	5,	2023,	with	the option	to	extend	the	maturity	date	by	two	additional	one-year	periods	subject	to	lender	consent.	The	2018	Senior	Credit	Facility	supports	our	$3.0	billion	of	short-term credit	under	our	commercial	paper	program.	As	of	December	31,	2018,	there	were	no	borrowings	under	our	commercial	paper	program.	See	Note	15	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report	for	further	discussion.

The	2018	Senior	Credit	Facility	contains	only	one	material	financial	covenant.	This	covenant	requires	us	to	maintain	a	ratio	of	total	funded	debt	to	total capitalization,	as	defined	in	the	credit	agreement,	of	no	more	than	65%.	As	of	December	31,	2018,	we	were	in	compliance	with	this	covenant	with	a	21.0%	debt-to- capitalization	ratio.

Our	access	to	funds	from	the	2018	Senior	Credit	Facility	is	not	restricted	under	any	"material	adverse	effect"	clauses.	It	is	not	uncommon	for	credit	agreements to	include	such	clauses.	These	clauses	can	remove	the	obligation	of	the	banks	to	fund	the	credit	line	if	any	condition	or	event	would	reasonably	be	expected	to	have	a material	and	adverse	effect	on	the	borrower's	financial	condition,	operations,	properties	or	business	considered	as	a	whole,	the	borrower's	ability	to	make	timely	debt payments	or	the	enforceability	of	material	terms	of	the	credit	agreement.	While	our	credit	facility	includes	covenants	that	require	us	to	report	a	condition	or	event	having a	material	adverse	effect,	the	obligation	of	the	banks	to	fund	the	credit	facility	is	not	conditioned	on	the	absence	of	a	material	adverse	effect.

As	market	conditions	warrant	and	subject	to	our	contractual	restrictions,	liquidity	position	and	other	factors,	we	may	from	time	to	time	seek	to	repurchase	or retire	our	outstanding	debt	through	cash	purchases	and/or	exchanges	for	other	debt	or	equity	securities	in	open	market	transactions,	privately	negotiated	transactions,	by tender	offer	or	otherwise.	Any	such	cash	repurchases	by	us	may	be	funded	by	cash	on	hand	or	incurring	new	debt.	The	amounts	involved	in	any	such	transactions, individually	or	in	the	aggregate,	may	be	material.	Furthermore,	any	such	repurchases	or	exchanges	may	result	in	our	acquiring	and	retiring	a	substantial	amount	of	such indebtedness,	which	would	impact	the	trading	liquidity	of	such	indebtedness.

In	January	2019,	we	repaid	the	$162	million	of	6.30%	senior	notes	at	maturity	with	cash	on	hand.

# Debt	Ratings

We	receive	debt	ratings	from	the	major	ratings	agencies	in	the	U.S.	In	determining	our	debt	ratings,	the	agencies	consider	a	number	of	qualitative	and quantitative	items	including,	but	not	limited	to,	commodity	pricing	levels,	our	liquidity,	asset	quality,	reserve	mix,	debt	levels,	cost	structure,	planned	asset	sales	and production	growth	opportunities.	Our	credit	rating	from	Standard	and	Poor's	Financial	Services	is	BBB	with	a	stable	outlook.	Our	credit	rating	from	Fitch	is	BBB+	with a	stable	outlook.	Our	credit	rating	from	Moody's	Investor	Service	is	Ba1	with	a	positive	outlook.	Any	rating	downgrades	may	result	in	additional	letters	of	credit	or	cash collateral	being	posted	under	certain	contractual	arrangements.

There	are	no	"rating	triggers"	in	any	of	our	contractual	debt	obligations	that	would	accelerate	scheduled	maturities	should	our	debt	rating	fall	below	a	specified level.	However,	a	downgrade	could	adversely	impact	our	interest	rate	on	any	credit	facility	borrowings	and	the	ability	to	economically	access	debt	markets	in	the	future.

# Share	Repurchase	Program

In	February	2019,	our	Board	of	Directors	increased	our	share	repurchase	program	by	an	additional	$1	billion.	The	$5	billion	share	repurchase	program	expires December	31,	2019.	Through	February	15,	2019,	we	have	executed	$3.4	billion	of	the	authorized	program.

Our	2019	exploration	and	development	budget	is	expected	to	be	approximately	$2.0	billion	to	$2.25	billion,	including	capital	associated	with	our	Canadian	and Barnett	Shale	upstream	assets.

# Contractual	Obligations

The	following	table	presents	a	summary	of	our	contractual	obligations	as	of	December	31,	2018.

|  |  | Less	Than	1 |  |  | More	Than	5 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Total | Year | 1-3\tYears | 3-5\tYears | Years |
| Devon\tobligations: |  |  |  |  |  |
| Debt\t(1) | $6,011 | $162 | $500 | $1,000 | $4,349 |
| Interest\texpense\t(2) | 4,951 | 317 | 623 | 535 | 3,476 |
| Purchase\tobligations\t(3) | 1,248 | 541 | 707 | — | — |
| Operational\tagreements\t(4) | 5,626 | 587 | 892 | 773 | 3,374 |
| Asset\tretirement\tobligations\t(5) | 1,057 | 27 | 76 | 79 | 875 |
| Drilling\tand\tfacility\tobligations\t(6) | 445 | 274 | 133 | 22 | 16 |
| Lease\tobligations\t(7) | 500 | 64 | 74 | 51 | 311 |
| Other\t(8) | 295 | 32 | 78 | 27 | 158 |
| Total\tobligations | $20,133 | $2,004 | $3,083 | $2,487 | $12,559 |

(1) Debt	amounts	represent	scheduled	maturities	of	debt	obligations	at	December	31,	2018,	excluding	net	discounts	and	debt	issue	costs	included	in	the	carrying value	of	debt.

(2) Interest	expense	represents	the	scheduled	cash	payments	on	long-term	fixed-rate	debt	(including	current	portion	of	long	term	debt).

(3) Purchase	obligation	amounts	represent	contractual	commitments	primarily	to	purchase	condensate	at	market	prices	for	use	at	our	heavy	oil	projects	in	Canada. We	have	entered	into	these	agreements	because	condensate	is	an	integral	part	of	the	heavy	oil	transportation	process.	Any	disruption	in	our	ability	to	obtain condensate	could	negatively	affect	our	ability	to	transport	heavy	oil	at	these	locations.	Our	total	obligation	related	to	condensate	purchases	expires	in	2021.	The value	of	the	obligation	in	the	table	above	is	based	on	the	contractual	volumes	and	our	internal	estimate	of	future	condensate	market	prices.

(4) Operational	agreements	represent	commitments	to	transport	or	process	certain	volumes	of	oil,	gas	and	NGLs	for	a	fixed	fee.	We	have	entered	into	these agreements	to	aid	the	movement	of	our	production	to	downstream	markets.	Approximately	$1.9	billion	relates	to	the	transportation	agreement	we	entered	in	2016 in	which	we	dedicated	our	thermal-oil	acreage	to	the	Access	Pipeline	for	an	initial	term	of	25	years	following	the	divestment	of	our	50%	interest	in	the	Access Pipeline.	For	additional	information,	see	Note	2	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

(5) Asset	retirement	obligations	represent	estimated	discounted	costs	for	future	dismantlement,	abandonment	and	rehabilitation	costs.	These	obligations	are	recorded as	liabilities	on	our	December	31,	2018	balance	sheet.

(6) Drilling	and	facility	obligations	represent	gross	contractual	agreements	with	third-party	service	providers	to	procure	drilling	rigs	and	other	related	services	for developmental	and	exploratory	drilling	and	facilities	construction.

(7) Lease	obligations	consist	primarily	of	non-cancelable	leases	for	office	space	and	equipment.

(8) Other	obligations	primarily	relate	to	various	tax	obligations.

# Contingencies	and	Legal	Matters

For	a	detailed	discussion	of	contingencies	and	legal	matters,	see	Note	20	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Critical	Accounting	Estimates

The	preparation	of	financial	statements	in	conformity	with	accounting	principles	generally	accepted	in	the	U.S.	requires	us	to	make	estimates,	judgments	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	amounts	could	differ	from	these	estimates,	and	changes	in	these	estimates	are	recorded when	known.	We	consider	the

following	to	be	our	most	critical	accounting	estimates	that	involve	judgment	and	have	reviewed	these	critical	accounting	estimates	with	the	Audit	Committee	of	our Board	of	Directors.

# Oil	and	Gas	Assets	Accounting,	Classification,	Reserves	&	Valuation

# Successful	Efforts	Method	of	Accounting	and	Classification

We	utilize	the	successful	efforts	method	of	accounting	for	our	oil	and	natural	gas	exploration	and	development	activities	which	requires	management's assessment	of	the	proper	designation	of	wells	and	associated	costs	as	developmental	or	exploratory.	This	classification	assessment	is	dependent	on	the	determination	and existence	of	proved	reserves,	which	is	a	critical	estimate	discussed	in	the	section	below.	The	classification	of	developmental	and	exploratory	costs	has	a	direct	impact	on the	amount	of	costs	we	initially	recognize	as	exploration	expense	or	capitalize,	then	subject	to	DD&A	calculations	and	impairment	assessments	and	valuations.

Once	a	well	is	drilled,	the	determination	that	proved	reserves	have	been	discovered	may	take	considerable	time	and	requires	both	judgment	and	application	of industry	experience.	Development	wells	are	always	capitalized.	Costs	associated	with	drilling	an	exploratory	well	are	initially	capitalized,	or	suspended,	pending	a determination	as	to	whether	proved	reserves	have	been	found.	At	the	end	of	each	quarter,	management	reviews	the	status	of	all	suspended	exploratory	drilling	costs	to determine	whether	the	costs	should	continue	to	remain	capitalized	or	shall	be	expensed.	When	making	this	determination,	management	considers	current	activities,	near- term	plans	for	additional	exploratory	or	appraisal	drilling	and	the	likelihood	of	reaching	a	development	program.	If	management	determines	future	development activities	and	the	determination	of	proved	reserves	are	unlikely	to	occur,	the	associated	suspended	exploratory	well	costs	are	recorded	as	dry	hole	expense	and	reported in	exploration	expense	in	the	Consolidated	Comprehensive	Statement	of	Earnings.	Otherwise,	the	costs	of	exploratory	wells	remain	capitalized.	At	December	31,	2018, Devon	had	approximately	$200	million	of	well	costs	suspended	for	more	than	one	year,	which	largely	pertain	to	its	Pike	Heavy	Oil	project.	Stratigraphic	testing	has demonstrated	reserves	can	be	produced	economically	at	Pike.	However,	this	capital	intensive,	long-duration	project	remains	unsanctioned	by	Devon	and	its	50%	partner, which	is	the	primary	reason	reserves	have	not	been	designated	as	proven	at	Pike.	With	no	lease	expiration	at	Pike	in	the	near	future,	management	continues	to	keep	the Pike	exploratory	costs	capitalized.

Similar	to	the	evaluation	of	suspended	exploratory	well	costs,	costs	for	undeveloped	leasehold,	for	which	reserves	have	not	been	proven,	must	also	be	evaluated for	continued	capitalization	or	impairment.	At	the	end	of	each	quarter,	management	assesses	undeveloped	leasehold	costs	for	impairment	by	considering	future	drilling plans,	drilling	activity	results,	commodity	price	outlooks,	planned	future	sales	or	expiration	of	all	or	a	portion	of	such	projects.	At	December	31,	2018,	Devon	had	$1.2 billion	of	undeveloped	leasehold	and	capitalized	interest,	which	includes	approximately	$750	million	related	to	Pike.	Consistent	with	the	evaluation	above	on	suspended well	costs,	the	costs	for	Pike	continue	to	remain	capitalized.	Of	the	remaining	undeveloped	leasehold	costs	at	December	31,	2018,	approximately	$10	million	is scheduled	to	expire	in	2019.	The	leasehold	expiring	in	2019	relates	to	areas	in	which	Devon	is	actively	drilling.	If	our	drilling	is	not	successful,	this	leasehold	could become	partially	or	entirely	impaired.

# Reserves

Our	estimates	of	proved	and	proved	developed	reserves	are	a	major	component	of	DD&A	calculations.	Additionally,	our	proved	reserves	represent	the	element of	these	calculations	that	require	the	most	subjective	judgments.	Estimates	of	reserves	are	forecasts	based	on	engineering	data,	projected	future	rates	of	production	and the	timing	of	future	expenditures.	The	process	of	estimating	oil,	gas	and	NGL	reserves	requires	substantial	judgment,	resulting	in	imprecise	determinations,	particularly for	new	discoveries.	Different	reserve	engineers	may	make	different	estimates	of	reserve	quantities	based	on	the	same	data.	Our	engineers	prepare	our	reserve	estimates. We	then	subject	certain	of	our	reserve	estimates	to	audits	performed	by	third-party	petroleum	consulting	firms.	In	2018,	89%	of	our	reserves	were	subjected	to	such audits.

The	passage	of	time	provides	more	qualitative	information	regarding	estimates	of	reserves,	when	revisions	are	made	to	prior	estimates	to	reflect	updated information.	In	the	past	five	years,	annual	performance	revisions	to	our	reserve	estimates,	which	have	been	both	increases	and	decreases	in	individual	years,	have averaged	less	than	5%	of	the	previous	year's	estimate.	However,	there	can	be	no	assurance	that	more	significant	revisions	will	not	be	necessary	in	the	future.	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.

# Valuation	of	Long-Lived	Assets

Long-lived	assets	used	in	operations,	including	proved	and	unproved	oil	and	gas	properties,	are	depreciated	and	assessed	for	impairment	annually	or	whenever changes	in	facts	and	circumstances	indicate	a	possible	significant	deterioration	in	future	cash	flows	is	expected	to	be	generated	by	an	asset	group.	For	DD&A calculations	and	impairment	assessments,	management	groups	individual

assets	based	on	a	judgmental	assessment	of	the	lowest	level	("common	operating	field")	for	which	there	are	identifiable	cash	flows	that	are	largely	independent	of	the cash	flows	of	other	groups	of	assets.	The	determination	of	common	operating	fields	is	largely	based	on	geological	structural	features	or	stratigraphic	condition,	which requires	judgment.	Management	also	considers	the	nature	of	production,	common	infrastructure,	common	sales	points,	common	processing	plants,	common	regulation and	management	oversight	to	make	common	operating	field	determinations.	These	determinations	impact	the	amount	of	DD&A	recognized	each	period	and	could impact	the	determination	and	measurement	of	a	potential	asset	impairment.

Management	evaluates	assets	for	impairment	through	an	established	process	in	which	changes	to	significant	assumptions	such	as	prices,	volumes,	and	future development	plans	are	reviewed.	If,	upon	review,	the	sum	of	the	undiscounted	pre-tax	cash	flows	is	less	than	the	carrying	value	of	the	asset	group,	the	carrying	value	is written	down	to	estimated	fair	value.	Because	there	usually	is	a	lack	of	quoted	market	prices	for	long-lived	assets,	the	fair	value	of	impaired	assets	is	typically determined	based	on	the	present	values	of	expected	future	cash	flows	using	discount	rates	believed	to	be	consistent	with	those	used	by	principal	market	participants.	The expected	future	cash	flows	used	for	impairment	reviews	and	related	fair	value	calculations	are	typically	based	on	judgmental	assessments	of	future	production	volumes, commodity	prices,	operating	costs,	and	capital	investment	plans,	considering	all	available	information	at	the	date	of	review.	Besides	the	estimates	of	reserves	and	future production	volumes,	future	commodity	prices	are	the	largest	driver	in	the	variability	of	undiscounted	pre-tax	cash	flows.	For	our	impairment	determinations,	we generally	utilize	the	forward	strip	prices	for	the	first	five	years	and	apply	internally	generated	price	forecasts	for	subsequent	years.	We	estimate	and	escalate	or	de- escalate	future	capital	and	operating	costs	by	using	a	method	that	correlates	cost	movements	to	price	movements	similar	to	recent	history.	Changes	to	any	of	these assumptions	could	result	in	lower	undiscounted	pre-tax	cash	flows	and	impact	both	the	recognition	and	timing	of	impairments.	Due	to	suppressed	commodity	prices	in 2016,	we	recognized	significant	asset	impairments.	With	generally	higher	pricing	in	2017	and	2018,	we	did	not	recognize	material	asset	impairments.

# Goodwill

We	test	goodwill	for	impairment	annually	at	October	31,	or	more	frequently	if	events	or	changes	in	circumstances	dictate	that	the	carrying	value	of	goodwill	may not	be	recoverable.	As	of	December	31,	2018,	the	U.S.	reporting	unit	had	goodwill	totaling	$841	million.

We	perform	a	qualitative	assessment	to	determine	whether	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit	is	less	than	its	carrying	amount.	If	our qualitative	assessment	determines	that	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit	is	less	than	its	carrying	amount,	including	goodwill,	then	a quantitative	goodwill	impairment	test	is	performed.	As	part	of	our	qualitative	assessment,	we	considered	the	general	macroeconomic,	industry	and	market	conditions, changes	in	cost	factors,	actual	and	expected	financial	performance,	significant	changes	in	management,	strategy	or	customers,	and	stock	performance.	If	the	qualitative assessment	determines	that	a	quantitative	goodwill	impairment	test	is	required,	then	the	fair	value	of	each	reporting	unit	is	compared	to	the	carrying	value	of	the reporting	unit.	If	the	fair	value	of	the	reporting	unit	is	less	than	the	carrying	value,	an	impairment	charge	will	be	recognized	for	the	amount	by	which	the	carrying amount	exceeds	the	fair	value.	Because	quoted	market	prices	are	not	available	for	our	reporting	units,	the	fair	values	of	the	reporting	units	are	estimated	based	upon several	valuation	analyses,	including	comparable	companies,	comparable	transactions	and	premiums	paid.	The	determination	of	fair	value	requires	judgment	and involves	the	use	of	significant	estimates	and	assumptions	about	expected	future	cash	flows	derived	from	internal	forecasts	and	the	impact	of	market	conditions	on	those assumptions.

Based	on	our	qualitative	assessment	as	of	October	31,	2018,	it	is	not	more	likely	than	not	that	the	fair	value	of	the	U.S.	reporting	unit	is	less	than	its	carrying amount.	Since	our	annual	test	for	goodwill	impairment	on	October	31,	2018	was	performed,	our	stock	price	decreased	30%	from	October	31	to	December	31.	As	such, we	performed	an	updated	assessment	as	of	December	31,	2018	to	determine	if	it	is	more	likely	than	not	that	the	fair	value	of	our	reporting	unit	is	less	than	its	carrying amount.	Based	on	our	qualitative	assessment	as	of	December	31,	2018,	it	is	not	more	likely	than	not	that	the	fair	value	of	the	U.S.	reporting	unit	is	less	than	its	carrying value.

Our	impairment	determinations	involved	significant	assumptions	and	judgments,	as	discussed	above.	Differing	assumptions	regarding	any	of	these	inputs	could have	a	significant	effect	on	the	various	valuations.	If	actual	future	results	are	not	consistent	with	these	assumptions	and	estimates,	or	the	assumptions	and	estimates change	due	to	new	information,	we	may	be	exposed	to	additional	goodwill	impairment	charges,	which	would	be	recognized	in	the	period	in	which	we	would	determine that	the	carrying	value	exceeds	fair	value.	We	would	expect	that	a	prolonged	or	sustained	period	of	lower	commodity	prices	would	adversely	affect	the	estimate	of	future operating	results,	which	could	result	in	future	goodwill	impairments	for	our	U.S.	reporting	unit	due	to	the	potential	impact	on	the	cash	flows	of	our	operations.

The	impairment	of	goodwill	has	no	effect	on	liquidity	or	capital	resources.	However,	it	adversely	affects	our	results	of	operations	in	the	period	recognized.

The	amount	of	income	taxes	recorded	requires	interpretations	of	complex	rules	and	regulations	of	federal,	state,	provincial	and	foreign	tax	jurisdictions.	We recognize	current	tax	expense	based	on	estimated	taxable	income	for	the	current	period	and	the	applicable	statutory	tax	rates.	We	routinely	assess	potential	uncertain	tax positions	and,	if	required,	estimate	and	establish	accruals	for	such	amounts.	We	have	recognized	deferred	tax	assets	and	liabilities	for	temporary	differences,	operating losses	and	other	tax	carryforwards.	We	routinely	assess	our	deferred	tax	assets	and	reduce	such	assets	by	a	valuation	allowance	if	we	deem	it	is	more	likely	than	not	that some	portion	or	all	of	the	deferred	tax	assets	will	not	be	realized.	At	the	end	of	2017,	we	recorded	a	100%	valuation	allowance	against	our	U.S.	deferred	tax	assets. Upon	closing	the	EnLink	divestiture	in	the	third	quarter	of	2018,	Devon	reassessed	its	position	and	determined	that	its	U.S.	segment	is	no	longer	in	a	full	valuation allowance	position,	maintaining	only	valuation	allowances	against	certain	deferred	tax	assets,	including	certain	tax	credits	and	state	net	operating	losses.	Devon	also	has recorded	a	partial	valuation	allowance	against	certain	Canadian	deferred	tax	assets	that	were	generated	by	a	2017	Canadian	legal	entity	restructuring.

The	accruals	for	deferred	tax	assets	and	liabilities	are	often	based	on	assumptions	that	are	subject	to	a	significant	amount	of	judgment	by	management.	These assumptions	and	judgments	are	reviewed	and	adjusted	as	facts	and	circumstances	change.	Material	changes	to	our	income	tax	accruals	may	occur	in	the	future	based	on the	progress	of	ongoing	audits,	changes	in	legislation	or	resolution	of	pending	matters.

We	also	assess	factors	relative	to	whether	our	foreign	earnings	are	considered	indefinitely	reinvested.	These	factors	include	forecasted	and	actual	results	for	both our	U.S.	and	Canadian	operations,	borrowing	conditions	in	the	U.S.	and	existing	U.S.	income	tax	laws.	Changes	in	any	of	these	factors	could	require	recognition	of additional	deferred,	or	even	current,	U.S.	income	tax	expense.	We	accrue	deferred	U.S.	income	tax	expense	on	our	foreign	earnings	when	the	factors	indicate	that	these earnings	are	no	longer	considered	indefinitely	reinvested.

For	our	foreign	earnings	deemed	indefinitely	reinvested,	we	do	not	calculate	a	hypothetical	deferred	tax	liability	on	these	earnings.	Calculating	a	hypothetical	tax on	these	accumulated	earnings	is	much	different	from	the	calculation	of	the	deferred	tax	liability	on	our	earnings	deemed	not	indefinitely	reinvested.	A	hypothetical	tax calculation	on	the	indefinitely	reinvested	earnings	would	require	the	following	additional	activities:

•relying	on	tax	rates	on	a	future	remittance	that	could	vary	significantly	depending	on	alternative	approaches	available	to	repatriate	the	earnings; •determining	the	nature	of	a	yet-to-be-determined	future	remittance,	such	as	whether	the	distribution	would	be	a	non-taxable	return	of	capital	or	a distribution	of	taxable	earnings	and	calculation	of	associated	withholding	taxes,	which	would	vary	significantly	depending	on	the	circumstances	at	the deemed	time	of	remittance;	and

•further	analysis	of	a	variety	of	other	inputs	such	as	the	earnings	and	profits,	U.S./foreign	country	tax	treaty	provisions	and	the	related	foreign	taxes	paid	by our	foreign	subsidiaries,	whose	earnings	are	deemed	permanently	reinvested,	over	a	lengthy	history	of	operations.

Because	of	the	administrative	burden	required	to	perform	these	additional	activities,	it	is	impractical	to	calculate	a	hypothetical	tax	on	the	foreign	earnings associated	with	this	separate	and	more	complicated	chain	of	companies.

# Non-GAAP	Measures

# Core	Earnings

We	make	reference	to	"core	earnings	(loss)	attributable	to	Devon"	and	"core	earnings	(loss)	per	share	attributable	to	Devon"	in	"Overview	of	2018	Results"	in this	Item	7	that	are	not	required	by	or	presented	in	accordance	with	GAAP.	These	non-GAAP	measures	should	not	be	considered	as	alternatives	to	GAAP	measures. Core	earnings	(loss)	attributable	to	Devon,	as	well	as	the	per	share	amount,	represent	net	earnings	excluding	certain	noncash	and	other	items	that	are	typically	excluded by	securities	analysts	in	their	published	estimates	of	our	financial	results.	Additionally,	we've	presented	our	discontinued	operations	associated	with	the	sale	of	our aggregate	ownership	interests	in	EnLink	and	the	General	Partner	separately	to	show	our	results	on	a	go-forward	basis.	For	more	information	on	the	results	of	operations for	EnLink	and	the	General	Partner,	see	Note	19	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	in	this	report.	Our	non-GAAP	measures	are	typically	used	as a	performance	measure.	Amounts	excluded	for	2018	relate	to	asset	dispositions,	the	gain	on	the	sale	of	Devon's	aggregate	ownership	interests	in	EnLink	and	the	General Partner,	noncash	asset	impairments	including	noncash	unproved	asset	impairments,	deferred	tax	asset	valuation	allowance,	costs	associated	with	early	retirement	of	debt, fair	value	changes	in	derivative	financial	instruments	and	foreign	currency,	restructuring	and	transaction	costs	associated	with	the	2018	workforce	reduction	and settlements	relating	to	minimum	volume	contract	commitments.

Amounts	excluded	for	2017	relate	to	asset	dispositions,	noncash	asset	impairments	including	noncash	unproved	asset	impairments,	U.S.	tax	reform	changes, deferred	tax	asset	valuation	allowance,	derivatives	and	financial	instrument	fair	value	changes,	legal	entity	restructuring	and	costs	associated	with	early	retirement	of debt.

Amounts	excluded	for	2016	relate	to	asset	dispositions,	noncash	asset	impairments	(including	an	impairment	of	EnLink	goodwill)	including	noncash	unproved asset	impairments	and	dry	hole	costs	relating	to	exploration	expenses,	rig	stacking	costs,	deferred	tax	asset	valuation	allowance,	restructuring	and	transaction	costs associated	with	the	2016	workforce	reduction,	derivatives	and	financial	instrument	fair	value	changes	and	costs	associated	with	early	retirement	of	debt.

We	believe	these	non-GAAP	measures	facilitate	comparisons	of	our	performance	to	earnings	estimates	published	by	securities	analysts,	which	typically	make similar	adjustments	in	their	estimates	of	our	financial	results.	We	also	believe	these	non-GAAP	measures	can	facilitate	comparisons	of	our	performance	between	periods and	to	the	performance	of	our	peers.

Below	are	reconciliations	of	our	core	earnings	and	earnings	per	share	to	their	comparable	GAAP	measures.

|  | Before	tax | After	tax | Noncontrolling<br>Interests | Per	Diluted<br>Share |
| :--- | :--- | :--- | :--- | :--- |
| 2018 |  |  |  |  |
| Continuing\tOperations |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $920 | \t$764 | \t$764 | \t$1.52 |
| Adjustments: |  |  |  |  |
| Asset\tdispositions | (263) | (202) | (202) | (0.41) |
| Asset\tand\texploration\timpairments | 257 | 198 | 198 | 0.40 |
| Deferred\ttax\tasset\tvaluation\tallowance | — | (42) | (42) | (0.08) |
| Early\tretirement\tof\tdebt | 312 | 240 | 240 | 0.48 |
| Fair\tvalue\tchanges\tin\tfinancial |  |  |  |  |
| \t\t\tinstruments\tand\tforeign\tcurrency | (614) | (458) | (458) | (0.92) |
| Restructuring\tand\ttransaction\tcosts | 114 | 87 | 87 | 0.18 |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $726 | \t$587 | \t$587 | \t$1.17 |
| Discontinued\tOperations |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $2,863 | \t$2,460 | \t$2,300 | \t$4.58 |
| Adjustments: |  |  |  |  |
| Gain\ton\tsale\tof\tEnLink\tand\tthe\tGeneral\tPartner | (2,607) | (2,222) | (2,222) | (4.43) |
| Fair\tvalue\tchanges,\tand\tminimum\tvolume\tcommitment\tsettlement | (34) | (28) | (10) | (0.02) |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $222 | \t$210 | \t$68 | \t$0.13 |
| Total |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $3,783 | \t$3,224 | \t$3,064 | \t$6.10 |
| Adjustments: |  |  |  |  |
| Continuing\tOperations | (194) | (177) | (177) | (0.35) |
| Discontinued\tOperations | (2,641) | (2,250) | (2,232) | (4.45) |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $948 | \t$797 | \t$655 | \t$1.30 |
| 2017 |  |  |  |  |
| Continuing\tOperations |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $773 | $758 | $758 | $1.43 |
| Adjustments: |  |  |  |  |
| Asset\tdispositions | (217) | (138) | (138) | (0.26) |
| Asset\tand\texploration\timpairments | 217 | 138 | 138 | 0.25 |
| Deferred\ttax\tasset\tvaluation\tallowance | — | (76) | (76) | (0.14) |
| Fair\tvalue\tchanges\tin\tfinancial |  |  |  |  |
| \t\t\tinstruments\tand\tforeign\tcurrency | (214) | (199) | (199) | (0.37) |
| Legal\tentity\trestructuring | — | (86) | (86) | (0.16) |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $559 | \t$397 | \t$397 | \t$0.75 |
| Discontinued\tOperations |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $123 | \t$320 | \t$140 | \t$0.27 |
| Adjustments: |  |  |  |  |
| U.S.\ttax\treform | — | (211) | (112) | (0.21) |
| Asset\tdispositions,\timpairments,\tfair\tvalue\tchanges\tand\tearly\tretirement\tof\tdebt | 4 | 4 | 2 | 0.00 |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $127 | \t$113 | \t$30 | \t$0.06 |
| Total |  |  |  |  |
| Earnings\tattributable\tto\tDevon\t(GAAP) | $896 | \t$1,078 | \t$898 | \t$1.70 |
| Adjustments: |  |  |  |  |
| Continuing\tOperations | (214) | (361) | (361) | (0.68) |
| Discontinued\tOperations | 4 | (207) | (110) | (0.21) |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $686 | \t$510 | \t$427 | \t$0.81 |

|  | Before	tax | After	tax | Noncontrolling<br>Interests | Per	Diluted<br>Share |
| :--- | :--- | :--- | :--- | :--- |
| 2016 |  |  |  |  |
| Continuing\tOperations |  |  |  |  |
| Loss\tattributable\tto\tDevon\t(GAAP) | $(433) | $(574) | $(575) | $(1.14) |
| Adjustments: |  |  |  |  |
| Asset\tdispositions | (1,496) | (1,001) | (1,001) | (1.97) |
| Asset\tand\texploration\timpairments | 537 | 340 | 340 | 0.69 |
| Rig\tstacking\tcosts | 10 | 6 | 6 | 0.01 |
| Deferred\ttax\tasset\tvaluation\tallowance | — | 385 | 385 | 0.76 |
| Restructuring\tand\ttransaction\tcosts | 261 | 168 | 168 | 0.33 |
| Fair\tvalue\tchanges\tin\tfinancial\n\t\t\tinstruments\tand\tforeign\tcurrency | 248 | 135 | 135 | 0.26 |
| Early\tretirement\tof\tdebt | 269 | 171 | 171 | 0.33 |
| Core\tloss\tattributable\tto\tDevon\t(Non-GAAP) | $(604) | \t$(370) | \t$(371) | \t$(0.73) |
| Discontinued\tOperations |  |  |  |  |
| Loss\tattributable\tto\tDevon\t(GAAP) | $(884) | \t$(884) | \t$(481) | \t$(0.95) |
| Adjustments: |  |  |  |  |
| Asset\timpairments | 893 | 890 | 467 | 0.91 |
| Asset\tdispositions,\trestructuring\tand\ttransaction\tcosts\tand\tfair\tvalue\tchanges | 41 | 35 | 18 | 0.04 |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $50 | \t$41 | \t$4 | \t$0.00 |
| Total |  |  |  |  |
| Loss\tattributable\tto\tDevon\t(GAAP) | $(1,317) | \t$(1,458) | \t$(1,056) | \t$(2.09) |
| Adjustments: |  |  |  |  |
| Continuing\tOperations | (171) | 204 | 204 | 0.41 |
| Discontinued\tOperations | 934 | 925 | 485 | 0.95 |
| Core\tloss\tattributable\tto\tDevon\t(Non-GAAP) | $(554) | \t$(329) | \t$(367) | \t$(0.73) |

# EBITDAX	and	Field-Level	Cash	Margin

To	assess	the	performance	of	our	assets,	we	use	EBITDAX	and	Field-Level	Cash	Margin.	We	compute	EBITDAX	as	net	earnings	from	continuing	operations before	income	tax	expense;	financing	costs,	net;	exploration	expenses;	depreciation,	depletion	and	amortization;	asset	impairments;	asset	disposition	gains	and	losses; non-cash	share-based	compensation;	non-cash	valuation	changes	for	derivatives	and	financial	instruments;	restructuring	and	transaction	costs;	accretion	on	discounted liabilities;	and	other	items	not	related	to	our	normal	operations.	Field-Level	Cash	Margin	is	computed	as	oil,	gas	and	NGL	revenues	less	production	expenses. Production	expenses	consist	of	lease	operating,	gathering,	processing	and	transportation	expenses,	as	well	as	production	and	property	taxes.

We	exclude	financing	costs	from	EBITDAX	to	assess	our	operating	results	without	regard	to	our	financing	methods	or	capital	structure.	Exploration	expenses and	asset	disposition	gains	and	losses	are	excluded	from	EBITDAX	because	they	are	not	indicators	of	operating	efficiency	for	a	given	reporting	period.	DD&A	and impairments	are	excluded	from	EBITDAX	because	capital	expenditures	are	evaluated	at	the	time	capital	costs	are	incurred.	We	exclude	share-based	compensation, valuation	changes,	restructuring	and	transaction	costs,	accretion	on	discounted	liabilities	and	other	items	from	EBITDAX	because	they	are	not	considered	a	measure	of asset	operating	performance.

We	believe	EBITDAX	and	Field-Level	Cash	Margin	provide	information	useful	in	assessing	our	operating	and	financial	performance	across	periods.	EBITDAX and	Field-Level	Cash	Margin	as	defined	by	Devon	may	not	be	comparable	to	similarly	titled	measures	used	by	other	companies	and	should	be	considered	in	conjunction with	net	earnings	from	continuing	operations.

Below	are	reconciliations	of	net	earnings	from	continuing	operations	to	EBITDAX	and	a	further	reconciliation	to	Field-Level	Cash	Margin.	Because	we	have sold	upstream	assets	in	the	periods	presented	and	have	plans	to	dispose	our	Canadian	and	Barnett	Shale	businesses,	which	represent	approximately	40%	of	our	2018 production	volumes,	we	have	also	excluded	the	EBITDAX	and	Field-Level	Cash	Margin	for	our	divested	assets,	Canada	and	the	Barnett	Shale	to	compute	Adjusted EBITDAX	and	Adjusted	Field-Level	Cash	Margin.	We	use	Adjusted	EBITDAX	and	Adjusted	Field-Level	Cash	Margin	to	assess	the	performance	of	our	portfolio	of upstream	assets	on	a	"same-store"	basis	across	periods.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Net\tearnings\tfrom\tcontinuing\toperations\t(GAAP) | $764 | \t$758 | \t$(574) |
| Financing\tcosts,\tnet | 594 | 317 | 717 |
| Income\ttax\texpense | 156 | 15 | 141 |
| Exploration\texpenses | 177 | 380 | 215 |
| Depreciation,\tdepletion\tand\tamortization | 1,658 | 1,529 | 1,592 |
| Asset\timpairments | 156 | — | 437 |
| Asset\tdisposition\tgains | (263) | (217) | (1,496) |
| Share-based\tcompensation | 122 | 141 | 124 |
| Derivative\tand\tfinancial\tinstrument\tnon-cash\tvaluation\tchanges | (614) | (214) | 248 |
| Restructuring\tand\ttransaction\tcosts | 114 | — | 261 |
| Accretion\ton\tdiscounted\tliabilities\tand\tother | 61 | 29 | 44 |
| EBITDAX\t(non-GAAP) | 2,925 | 2,738 | 1,709 |
| Marketing\trevenues\tand\texpenses,\tnet | (86) | 48 | 49 |
| Commodity\tderivative\tcash\tsettlements | 84 | (53) | 11 |
| General\tand\tadministration\texpenses,\tcash-based | 529 | 596 | 609 |
| Field-level\tcash\tmargin\t(non-GAAP) | $3,452 | \t$3,329 | \t$2,378 |
| EBITDAX\t(non-GAAP) | $2,925 | \t$2,738 | \t$1,709 |
| EBITDAX,\tDivested\tassets | (184) | (267) | (346) |
| EBITDAX,\tCanada | (593) | (748) | (491) |
| EBITDAX,\tBarnett\tShale | (248) | (262) | (148) |
| Adjusted\tEBITDAX\t(non-GAAP) | $1,900 | \t$1,461 | \t$724 |
| Field-level\tcash\tmargin\t(non-GAAP) | $3,452 | \t$3,329 | \t$2,378 |
| Field-level\tcash\tmargin,\tdivested\tassets | (184) | (267) | (346) |
| Field-level\tcash\tmargin,\tCanada | (210) | (812) | (490) |
| Field-level\tcash\tmargin,\tBarnett\tShale | (248) | (262) | (148) |
| Adjusted\tfield-level\tcash\tmargin\t(non-GAAP) | $2,810 | \t$1,988 | \t$1,394 |

# Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk

The	primary	objective	of	the	following	information	is	to	provide	forward-looking	quantitative	and	qualitative	information	about	our	potential	exposure	to	market risks.	The	term	"market	risk"	refers	to	our	risk	of	loss	arising	from	adverse	changes	in	oil,	bitumen,	gas	and	NGL	prices,	interest	rates	and	foreign	currency	exchange rates.	The	following	disclosures	are	not	meant	to	be	precise	indicators	of	expected	future	losses	but	rather	indicators	of	reasonably	possible	losses.	This	forward-looking information	provides	indicators	of	how	we	view	and	manage	our	ongoing	market	risk	exposures.	All	of	our	market	risk	sensitive	instruments	were	entered	into	for purposes	other	than	speculative	trading.

# Commodity	Price	Risk

Our	major	market	risk	exposure	is	the	pricing	applicable	to	our	oil,	bitumen,	gas	and	NGL	production.	Realized	pricing	is	primarily	driven	by	the	prevailing worldwide	price	for	crude	oil	and	spot	market	prices	applicable	to	our	U.S.	and	Canadian	gas	and	NGL	production.	Pricing	for	oil	and	gas	production	has	been	volatile and	unpredictable	as	discussed	in	"Item	1A.	Risk	Factors"	of	this	report.	Consequently,	we	systematically	hedge	a	portion	of	our	production	through	various	financial transactions.	The	key	terms	to	our	oil	and	gas	derivative	financial	instruments	as	of	December	31,	2018	are	presented	in	Note	3	in	"Item	8.	Financial	Statements	and Supplementary	Data"	of	this	report.

The	fair	values	of	our	commodity	derivatives	are	largely	determined	by	estimates	of	the	forward	curves	of	the	relevant	price	indices.	At	December	31,	2018,	a 10%	change	in	the	forward	curves	associated	with	our	commodity	derivative	instruments	would	have	changed	our	net	asset	positions	by	approximately	$270	million.

# Interest	Rate	Risk

At	December	31,	2018,	we	had	total	debt	of	$5.9	billion.	All	of	our	debt	is	based	on	fixed	interest	rates	averaging	5.4%.

As	of	December	31,	2018,	we	had	one	open	interest	rate	swap	position	that	is	presented	in	Note	3	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of this	report.	The	fair	value	of	our	interest	rate	swap	is	largely	determined	by	estimates	of	the	forward	curves	of	the	three	month	LIBOR	rate.	A	10%	change	in	these forward	curves	would	not	have	materially	impacted	our	balance	sheet	or	liquidity	at	December	31,	2018.

# Foreign	Currency	Risk

Our	net	assets,	net	earnings	and	cash	flows	from	our	Canadian	subsidiaries	are	based	on	the	U.S.	dollar	equivalent	of	such	amounts	measured	in	the	Canadian dollar	functional	currency.	Assets	and	liabilities	of	the	Canadian	subsidiaries	are	translated	to	U.S.	dollars	using	the	applicable	exchange	rate	as	of	the	end	of	a	reporting period.	Revenues,	expenses	and	cash	flow	are	translated	using	an	average	exchange	rate	during	the	reporting	period.	A	10%	unfavorable	change	in	the	Canadian-to-U.S. dollar	exchange	rate	would	not	have	materially	impacted	our	December	31,	2018	balance	sheet.

Devon	engages	in	intercompany	loan	activity	between	subsidiaries	with	different	functional	currencies.	The	value	of	these	foreign	currency	denominated intercompany	loans	increases	or	decreases	from	the	remeasurement	into	the	subsidiaries'	functional	currency.	Based	on	the	amount	of	the	intercompany	loans	as	of December	31,	2018,	a	10%	change	in	the	foreign	currency	exchange	rates	would	not	have	materially	impacted	our	balance	sheet.

# Item	8.	Financial	Statements	and	Supplementary	Data

# INDEX	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# AND	CONSOLIDATED	FINANCIAL	STATEMENT	SCHEDULES

| Report	of	Independent	Registered	Public	Accounting	Firm | 51 |
| :--- | :--- |
| Consolidated\tFinancial\tStatements |  |
| Consolidated\tComprehensive\tStatements\tof\tEarnings | 53 |
| Consolidated\tStatements\tof\tCash\tFlows | 54 |
| Consolidated\tBalance\tSheets | 55 |
| Consolidated\tStatements\tof\tEquity | 56 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 57 |
| Note\t1\t–\tSummary\tof\tSignificant\tAccounting\tPolicies | 57 |
| Note\t2\t–\tAcquisitions\tand\tDivestitures | 67 |
| Note\t3\t–\tDerivative\tFinancial\tInstruments | 69 |
| Note\t4\t–\tShare-Based\tCompensation | 71 |
| Note\t5\t–\tAsset\tImpairments | 74 |
| Note\t6\t–\tRestructuring\tand\tTransaction\tCosts | 74 |
| Note\t7\t–\tOther\tExpenses | 75 |
| Note\t8\t–\tIncome\tTaxes | 76 |
| Note\t9\t–\tNet\tEarnings\t(Loss)\tPer\tShare\tFrom\tContinuing\tOperations | 81 |
| Note\t10\t–\tOther\tComprehensive\tEarnings | 81 |
| Note\t11\t–\tSupplemental\tInformation\tto\tStatements\tof\tCash\tFlows | 82 |
| Note\t12\t–\tAccounts\tReceivable | 82 |
| Note\t13\t–\tProperty,\tPlant\tand\tEquipment | 83 |
| Note\t14\t–\tOther\tCurrent\tLiabilities | 84 |
| Note\t15\t–\tDebt\tand\tRelated\tExpenses | 85 |
| Note\t16\t–\tAsset\tRetirement\tObligations | 87 |
| Note\t17\t–\tRetirement\tPlans | 87 |
| Note\t18\t–\tStockholders'\tEquity | 91 |
| Note\t19\t–\tDiscontinued\tOperations\tand\tAssets\tHeld\tFor\tSale | 93 |
| Note\t20\t–\tCommitments\tand\tContingencies | 95 |
| Note\t21\t–\tFair\tValue\tMeasurements | 97 |
| Note\t22\t–\tSegment\tInformation | 98 |
| Note\t23\t–\tSupplemental\tInformation\ton\tOil\tand\tGas\tOperations\t(Unaudited) | 100 |
| Note\t24\t–\tSupplemental\tQuarterly\tFinancial\tInformation\t(Unaudited) | 107 |

All	financial	statement	schedules	are	omitted	as	they	are	inapplicable	or	the	required	information	has	been	included	in	the	consolidated	financial	statements	or notes	thereto.

# Report	of	Independent	Registered	Public	Accounting	Firm

# The	Board	of	Directors	and	Stockholders

# Opinions	on	the	Consolidated	Financial	Statements	and	Internal	Control	Over	Financial	Reporting

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Devon	Energy	Corporation	and	subsidiaries	(the	"Company")	as	of	December	31,	2018	and	2017,	the related	consolidated	statements	of	comprehensive	earnings,	stockholders'	equity,	and	cash	flows	for	each	of	the	years	in	the	three-year	period	ended	December	31,	2018, and	the	related	notes	(collectively,	the	"consolidated	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.

In	our	opinion,	the	consolidated	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	years	in	the	three-year	period	ended	December	31,	2018,	in	conformity	with	U.S. generally	accepted	accounting	principles.	Also	in	our	opinion,	the	Company	maintained,	in	all	material	respects,	effective	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.

# Adoption	of	New	Accounting	Standard

As	discussed	in	Note	1	to	the	consolidated	financial	statements,	the	Company	has	changed	its	method	of	accounting	for	revenue	from	contracts	with	customers	in	2018 due	to	the	adoption	of	Accounting	Standards	Update	2014-09,	Revenue	from	Contracts	with	Customers	(ASC	606).

# Basis	for	Opinion

The	Company's	management	is	responsible	for	these	consolidated	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	contained	in	"Item	9A.	Controls	and	Procedures."	Our	responsibility	is	to	express	an	opinion	on	the	Company's	consolidated	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	consolidated	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	consolidated	financial	statements	included	performing	procedures	to	assess	the	risks	of	material	misstatement	of	the	consolidated	financial	statements, whether	due	to	error	or	fraud,	and	performing	procedures	that	respond	to	those	risks.	Such	procedures	included	examining,	on	a	test	basis,	evidence	regarding	the amounts	and	disclosures	in	the	consolidated	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	consolidated	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/	KPMG	LLP

# We	have	served	as	the	Company's	auditor	since	1980.

Oklahoma	City,	Oklahoma

# DEVON	ENERGY	CORPORATION	AND	SUBSIDIARIES

# CONSOLIDATED	COMPREHENSIVE	STATEMENTS	OF	EARNINGS

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Upstream\trevenues | $6,285 | $5,307 | $3,981 |
| Marketing\trevenues | 4,449 | 3,571 | 2,772 |
| Total\trevenues | 10,734 | 8,878 | 6,753 |
| Production\texpenses | 2,225 | 1,823 | 1,805 |
| Exploration\texpenses | 177 | 380 | 215 |
| Marketing\texpenses | 4,363 | 3,619 | 2,821 |
| Depreciation,\tdepletion\tand\tamortization | 1,658 | 1,529 | 1,592 |
| Asset\timpairments | 156 | — | 437 |
| Asset\tdispositions | (263) | (217) | (1,496) |
| General\tand\tadministrative\texpenses | 650 | 737 | 733 |
| Financing\tcosts,\tnet | 594 | 317 | 717 |
| Restructuring\tand\ttransaction\tcosts | 114 | — | 261 |
| Other\texpenses | 140 | (83) | 101 |
| Total\texpenses | 9,814 | 8,105 | 7,186 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 920 | 773 | (433) |
| Income\ttax\texpense | 156 | 15 | 141 |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations | 764 | 758 | (574) |
| Net\tearnings\t(loss)\tfrom\tdiscontinued\toperations,\tnet\tof\tincome\ttax\texpense | 2,460 | 320 | (884) |
| Net\tearnings\t(loss) | 3,224 | 1,078 | (1,458) |
| Net\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | 160 | 180 | (402) |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $3,064 | $898 | $(1,056) |
| Basic\tnet\tearnings\t(loss)\tper\tshare: |  |  |  |
| Basic\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $1.53 | $1.44 | $(1.14) |
| Basic\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | 4.61 | 0.27 | (0.95) |
| Basic\tnet\tearnings\t(loss)\tper\tshare | $6.14 | $1.71 | $(2.09) |
| Diluted\tnet\tearnings\t(loss)\tper\tshare: |  |  |  |
| Diluted\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $1.52 | $1.43 | $(1.14) |
| Diluted\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | 4.58 | 0.27 | (0.95) |
| Diluted\tnet\tearnings\t(loss)\tper\tshare | $6.10 | $1.70 | $(2.09) |
| Comprehensive\tearnings\t(loss): |  |  |  |
| Net\tearnings\t(loss) | $3,224 | $1,078 | $(1,458) |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax: |  |  |  |
| Foreign\tcurrency\ttranslation | (152) | 83 | 11 |
| Pension\tand\tpostretirement\tplans | 44 | 29 | 22 |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax | (108) | 112 | 33 |
| Comprehensive\tearnings\t(loss) | 3,116 | 1,190 | (1,425) |
| Comprehensive\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | 160 | 180 | (402) |
| Comprehensive\tearnings\t(loss)\tattributable\tto\tDevon | $2,956 | $1,010 | $(1,023) |

See	accompanying	notes	to	consolidated	financial	statements.

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Cash\tflows\tfrom\toperating\tactivities: |  |  |  |
| Net\tearnings\t(loss) | $3,224 | $1,078 | $(1,458) |
| Adjustments\tto\treconcile\tnet\tearnings\tto\tnet\tcash\tfrom\toperating\tactivities: |  |  |  |
| Net\t(earnings)\tloss\tfrom\tdiscontinued\toperations,\tnet\tof\tincome\ttax\texpense | (2,460) | (320) | 884 |
| Depreciation,\tdepletion\tand\tamortization | 1,658 | 1,529 | 1,592 |
| Asset\timpairments | 156 | — | 437 |
| Leasehold\timpairments | 95 | 219 | 113 |
| Accretion\ton\tdiscounted\tliabilities | 61 | 63 | 75 |
| Total\t(gains)\tlosses\ton\tcommodity\tderivatives | (608) | (157) | 201 |
| Cash\tsettlements\ton\tcommodity\tderivatives | (84) | 53 | 1 |
| Gains\ton\tasset\tdispositions | (263) | (217) | (1,496) |
| Deferred\tincome\ttax\texpense\t(benefit) | 226 | (97) | 43 |
| Share-based\tcompensation | 161 | 150 | 203 |
| Early\tretirement\tof\tdebt | 312 | — | 269 |
| Total\t(gains)\tlosses\ton\tforeign\texchange | 139 | (132) | (121) |
| Settlements\tof\tintercompany\tforeign\tdenominated\tassets/liabilities | (241) | 9 | 63 |
| Other | (5) | (1) | 4 |
| Changes\tin\tassets\tand\tliabilities,\tnet | (143) | 32 | 24 |
| Net\tcash\tfrom\toperating\tactivities\t-\tcontinuing\toperations | 2,228 | 2,209 | 834 |
| Cash\tflows\tfrom\tinvesting\tactivities: |  |  |  |
| Capital\texpenditures | (2,451) | (1,968) | (1,384) |
| Acquisitions\tof\tproperty\tand\tequipment | (55) | (46) | (849) |
| Divestitures\tof\tproperty\tand\tequipment | 1,013 | 426 | 3,020 |
| Net\tcash\tfrom\tinvesting\tactivities\t-\tcontinuing\toperations | (1,493) | (1,588) | 787 |
| Cash\tflows\tfrom\tfinancing\tactivities: |  |  |  |
| Repayments\tof\tlong-term\tdebt\tprincipal | (922) | — | (2,492) |
| Net\tshort-term\tdebt\trepayments | — | — | (626) |
| Early\tretirement\tof\tdebt | (304) | — | (265) |
| Issuance\tof\tcommon\tstock | — | — | 1,469 |
| Repurchases\tof\tcommon\tstock | (2,956) | — | — |
| Dividends\tpaid\ton\tcommon\tstock | (149) | (127) | (221) |
| Shares\texchanged\tfor\ttax\twithholdings | (48) | (59) | (35) |
| Other | (7) | — | — |
| Net\tcash\tfrom\tfinancing\tactivities\t-\tcontinuing\toperations | (4,386) | (186) | (2,170) |
| Effect\tof\texchange\trate\tchanges\ton\tcash: |  |  |  |
| Settlements\tof\tintercompany\tforeign\tdenominated\tassets/liabilities | 241 | (9) | (63) |
| Other | (35) | 15 | 2 |
| Total\teffect\tof\texchange\trate\tchanges\ton\tcash\t-\tcontinuing\toperations | 206 | 6 | (61) |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\trestricted\tcash\tof\tcontinuing\toperations | (3,445) | 441 | (610) |
| Cash\tflows\tfrom\tdiscontinued\toperations: |  |  |  |
| Operating\tactivities | 476 | 700 | 666 |
| Investing\tactivities | 2,548 | (611) | (1,381) |
| Financing\tactivities | 183 | 195 | 974 |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\trestricted\tcash\tof\tdiscontinued\toperations | 3,207 | 284 | 259 |
| Net\tchange\tin\tcash,\tcash\tequivalents\tand\trestricted\tcash | (238) | 725 | (351) |
| Cash,\tcash\tequivalents\tand\trestricted\tcash\tat\tbeginning\tof\tperiod | 2,684 | 1,959 | 2,310 |
| Cash,\tcash\tequivalents\tand\trestricted\tcash\tat\tend\tof\tperiod | $2,446 | $2,684 | $1,959 |
| Reconciliation\tof\tcash,\tcash\tequivalents\tand\trestricted\tcash: |  |  |  |
| Cash\tand\tcash\tequivalents | $2,414 | $2,642 | $1,947 |
| Restricted\tcash\tincluded\tin\tother\tcurrent\tassets | 32 | 11 | — |
| Cash\tand\tcash\tequivalents\tincluded\tin\tcurrent\tassets\theld\tfor\tsale | — | 31 | 12 |
| Total\tcash,\tcash\tequivalents\tand\trestricted\tcash | $2,446 | $2,684 | $1,959 |

# CONSOLIDATED	BALANCE	SHEETS

| ASSETS | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $2,414 | $2,642 |
| Accounts\treceivable | 885 | 989 |
| Current\tassets\theld\tfor\tsale | 197 | 760 |
| Other\tcurrent\tassets | 941 | 400 |
| Total\tcurrent\tassets | 4,437 | 4,791 |
| Oil\tand\tgas\tproperty\tand\tequipment,\tbased\ton\tsuccessful\tefforts |  |  |
| \t\t\taccounting,\tnet | 12,813 | 13,318 |
| Other\tproperty\tand\tequipment,\tnet | 1,122 | 1,266 |
| Total\tproperty\tand\tequipment,\tnet | 13,935 | 14,584 |
| Goodwill | 841 | 841 |
| Other\tlong-term\tassets | 353 | 296 |
| Long-term\tassets\theld\tfor\tsale | — | 9,729 |
| Total\tassets | $19,566 | $30,241 |
| LIABILITIES\tAND\tEQUITY |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $662 | $633 |
| Revenues\tand\troyalties\tpayable | 898 | 748 |
| Short-term\tdebt | 162 | 115 |
| Current\tliabilities\theld\tfor\tsale | 69 | 991 |
| Other\tcurrent\tliabilities | 435 | 828 |
| Total\tcurrent\tliabilities | 2,226 | 3,315 |
| Long-term\tdebt | 5,785 | 6,749 |
| Asset\tretirement\tobligations | 1,030 | 1,099 |
| Other\tlong-term\tliabilities | 462 | 549 |
| Long-term\tliabilities\theld\tfor\tsale | — | 3,936 |
| Deferred\tincome\ttaxes | 877 | 489 |
| Equity: |  |  |
| Common\tstock,\t$0.10\tpar\tvalue.\tAuthorized\t1.0\tbillion\tshares;\tissued |  |  |
| \t\t\t450\tmillion\tand\t525\tmillion\tshares\tin\t2018\tand\t2017,\trespectively | 45 | 53 |
| Additional\tpaid-in\tcapital | 4,486 | 7,333 |
| Retained\tearnings | 3,650 | 702 |
| Accumulated\tother\tcomprehensive\tearnings | 1,027 | 1,166 |
| Treasury\tstock,\tat\tcost,\t1.0\tmillion\tshares\tin\t2018 | (22) | — |
| Total\tstockholders'\tequity\tattributable\tto\tDevon | 9,186 | 9,254 |
| Noncontrolling\tinterests | — | 4,850 |
| Total\tequity | 9,186 | 14,104 |
| Total\tliabilities\tand\tequity | $19,566 | $30,241 |

# CONSOLIDATED	STATEMENTS	OF	EQUITY

|  |  |  |  | Retained | Accumulated |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Additional | Earnings | Other |  |  |  |
|  | Common\tStock | Common\tStock | Paid-In | (Accumulated | \t Comprehensive | Treasury | \t Noncontrolling | Total |
|  | Shares | Amount | Capital | Deficit) | Earnings | Stock | Interests | Equity |
| Balance\tas\tof\tDecember\t31,\t2015 | 418 | \t$42 | \t$4,996 | \t$1,112 | \t$1,021 | \t$— | \t$3,940 | \t$11,111 |
| Net\tloss | — | — | — | (1,056) | — | — | (402) | (1,458) |
| Other\tcomprehensive\tearnings,\tnet\tof\ttax | — | — | — | — | 33 | — | — | 33 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 2 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | — | — | — | — | — | (28) | — | (28) |
| Common\tstock\tretired | — | — | (28) | — | — | 28 | — | — |
| Common\tstock\tdividends | — | — | (96) | (125) | — | — | — | (221) |
| Common\tstock\tissued | 103 | 10 | 2,117 | — | — | — | — | 2,127 |
| Share-based\tcompensation | — | — | 168 | — | — | — | — | 168 |
| Subsidiary\tequity\ttransactions | — | — | 80 | — | — | — | 1,214 | 1,294 |
| Distributions\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | (304) | (304) |
| Balance\tas\tof\tDecember\t31,\t2016 | 523 | \t$52 | \t$7,237 | \t$(69) | \t$1,054 | \t$— | \t$4,448 | \t$12,722 |
| Net\tearnings | — | — | — | 898 | — | — | 180 | 1,078 |
| Other\tcomprehensive\tearnings,\tnet\tof\ttax | — | — | — | — | 112 | — | — | 112 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 1 | 1 | — | — | — | — | — | 1 |
| Common\tstock\trepurchased | — | — | — | — | — | (44) | — | (44) |
| Common\tstock\tretired | — | — | (44) | — | — | 44 | — | — |
| Common\tstock\tdividends | — | — | — | (127) | — | — | — | (127) |
| Share-based\tcompensation | 1 | — | 126 | — | — | — | — | 126 |
| Subsidiary\tequity\ttransactions | — | — | 14 | — | — | — | 576 | 590 |
| Distributions\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | (354) | (354) |
| Balance\tas\tof\tDecember\t31,\t2017 | 525 | \t$53 | \t$7,333 | \t$702 | \t$1,166 | \t$— | \t$4,850 | \t$14,104 |
| Net\tearnings | — | — | — | 3,064 | — | — | 160 | 3,224 |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | — | — | — | — | (108) | — | — | (108) |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 3 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | — | — | — | — | — | (3,017) | — | (3,017) |
| Common\tstock\tretired | (79) | (8) | (2,987) | — | — | 2,995 | — | — |
| Common\tstock\tdividends | — | — | — | (149) | — | — | — | (149) |
| Share-based\tcompensation | 1 | — | 140 | — | — | — | — | 140 |
| Divestment\tof\tsubsidiary\tequity\tinvestment | — | — | — | — | 2 | — | (4,863) | (4,861) |
| Subsidiary\tequity\ttransactions | — | — | — | — | — | — | 72 | 72 |
| Distributions\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | (219) | (219) |
| Other | — | — | — | 33 | (33) | — | — | — |
| Balance\tas\tof\tDecember\t31,\t2018 | 450 | \t$45 | \t$4,486 | \t$3,650 | \t$1,027 | \t$(22) | \t$— | \t$9,186 |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# 1. Summary	of	Significant	Accounting	Policies

Devon	is	a	leading	independent	energy	company	engaged	primarily	in	the	exploration,	development	and	production	of	oil,	natural	gas	and	NGLs.	Devon's operations	are	concentrated	in	various	North	American	onshore	areas	in	the	U.S.	and	Canada.

As	further	discussed	in	Note	2,	Devon	sold	its	interests	in	EnLink	and	the	General	Partner	on	July	18,	2018.	Activity	relating	to	EnLink	and	the	General	Partner are	classified	as	discontinued	operations	within	Devon's	consolidated	comprehensive	statements	of	earnings	and	consolidated	statements	of	cash	flows.	The	associated assets	and	liabilities	of	EnLink	and	the	General	Partner	are	presented	as	assets	and	liabilities	held	for	sale	on	the	consolidated	balance	sheets.

Accounting	policies	used	by	Devon	and	its	subsidiaries	conform	to	accounting	principles	generally	accepted	in	the	U.S.	and	reflect	industry	practices.	The	more significant	of	such	policies	are	discussed	below.

# Principles	of	Consolidation

The	accompanying	consolidated	financial	statements	include	the	accounts	of	Devon	and	entities	in	which	it	holds	a	controlling	interest.	All	intercompany transactions	have	been	eliminated.	Undivided	interests	in	oil	and	natural	gas	exploration	and	production	joint	ventures	are	consolidated	on	a	proportionate	basis. Investments	in	non-controlled	entities,	over	which	Devon	has	the	ability	to	exercise	significant	influence	over	operating	and	financial	policies,	are	accounted	for	using the	equity	method.	In	applying	the	equity	method	of	accounting,	the	investments	are	initially	recognized	at	cost	and	subsequently	adjusted	for	Devon's	proportionate share	of	earnings,	losses,	contributions	and	distributions.	Investments	accounted	for	using	the	equity	method	and	cost	method	are	reported	as	a	component	of	other	long- term	assets.

# Use	of	Estimates

The	preparation	of	financial	statements	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	amounts	could	differ	from	these	estimates,	and	changes	in	these	estimates	are	recorded	when	known.	Significant	items	subject	to	such	estimates	and	assumptions include	the	following:

•proved	reserves	and	related	present	value	of	future	net	revenues;

•evaluation	of	suspended	well	costs;

•the	carrying	and	fair	values	of	oil	and	gas	properties,	other	property	and	equipment	and	product	and	equipment	inventories;

•derivative	financial	instruments;

•the	fair	value	of	reporting	units	and	related	assessment	of	goodwill	for	impairment;

•asset	retirement	obligations;

•obligations	related	to	employee	pension	and	postretirement	benefits;

•legal	and	environmental	risks	and	exposures;	and

•general	credit	risk	associated	with	receivables	and	other	assets.

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	–	(Continued)

# Revenue	Recognition

# Impact	of	ASC	606	Adoption

In	January	2018,	Devon	adopted	ASC	606	–	Revenue	from	Contracts	with	Customers	(ASC	606)	using	the	modified	retrospective	method	and	has	applied	the standard	to	all	existing	contracts.	ASC	606	supersedes	previous	revenue	recognition	requirements	in	ASC	605	and	includes	a	five-step	revenue	recognition	model	to depict	the	transfer	of	goods	or	services	to	customers	in	an	amount	that	reflects	the	consideration	in	exchange	for	those	goods	or	services.

The	impact	of	adoption	in	the	current	period	results	is	as	follows:

|  |  | Year	Ended	December	31,	2018 |  |
| :--- | :--- | :--- | :--- |
|  | Under\tASC | Under\tASC | Increase/ |
|  | 606 | 605 | (Decrease) |
| Upstream\trevenues | $6,285 | $6,031 | $254 |
| Marketing\trevenues | 4,449 | 4,449 | — |
| Total\timpacted\trevenues | $10,734 | $10,480 | $254 |
| Production\texpenses | $2,225 | $1,971 | $254 |
| Marketing\texpenses | 4,363 | 4,363 | — |
| Total\timpacted\texpenses | $6,588 | $6,334 | $254 |
| Earnings\tfrom\tcontinuing\n\t\t\toperations\tbefore\tincome\ttaxes | $920 | $920 | $— |

Changes	to	upstream	revenues	and	production	expenses	are	due	to	the	conclusion	that	Devon	represents	the	principal	and	controls	a	promised	product	before transferring	it	to	the	ultimate	third	party	customer	in	accordance	with	the	control	model	in	ASC	606.	This	is	a	change	from	previous	conclusions	reached	for	these agreements	utilizing	the	principal	versus	agent	indicators	under	ASC	605	where	the	assessment	was	focused	on	Devon	passing	title	and	not	control	to	the	processing entity	and	Devon	ultimately	receiving	a	net	price	from	the	third-party	end	customer.	As	a	result,	Devon	has	changed	the	presentation	of	revenues	and	expenses	for	these agreements.	Revenues	related	to	these	agreements	are	now	presented	on	a	gross	basis	for	amounts	expected	to	be	received	from	third-party	customers	through	the marketing	process.	Gathering,	processing	and	transportation	expenses	related	to	these	agreements,	incurred	prior	to	the	transfer	of	control	to	the	customer	at	the	tailgate of	the	natural	gas	processing	facilities,	are	now	presented	as	production	expenses.

# Upstream	Revenues

Upstream	revenues	include	the	sale	of	oil,	gas	and	NGL	production.	Oil,	gas	and	NGL	sales	are	recognized	when	production	is	sold	to	a	purchaser	at	a	fixed	or determinable	price,	delivery	has	occurred,	control	has	transferred	and	collectability	of	the	revenue	is	probable.	Devon's	performance	obligations	are	satisfied	at	a	point in	time.	This	occurs	when	control	is	transferred	to	the	purchaser	upon	delivery	of	contract	specified	production	volumes	at	a	specified	point.	The	transaction	price	used	to recognize	revenue	is	a	function	of	the	contract	billing	terms.	Revenue	is	invoiced,	if	required,	by	calendar	month	based	on	volumes	at	contractually	based	rates	with payment	typically	received	within	30	days	of	the	end	of	the	production	month.	Taxes	assessed	by	governmental	authorities	on	oil,	gas	and	NGL	sales	are	presented separately	from	such	revenues	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

# Natural	gas	and	NGL	sales

Under	Devon's	natural	gas	processing	contracts,	natural	gas	is	delivered	to	a	midstream	processing	entity	at	the	wellhead	or	the	inlet	of	the	midstream processing	entity's	system.	The	midstream	processing	entity	gathers	and	processes	the	natural	gas	and	remits	proceeds	for	the	resulting	sales	of	NGLs	and	residue	gas.	In these	scenarios,	Devon	evaluates	whether	it	is	the	principal	or	the	agent	in	the	transaction.	Devon	has	concluded	it	is	the	principal	under	these	contracts	and	the	ultimate third	party	is	the	customer.	Revenue	is	recognized	on	a	gross	basis,	with	gathering,	processing	and	transportation	fees	presented	as	a	component	of	production	expenses in	the	consolidated	comprehensive	statements	of	earnings.

In	certain	natural	gas	processing	agreements,	Devon	may	elect	to	take	residue	gas	and/or	NGLs	in-kind	at	the	tailgate	of	the	midstream	entity's	processing plant	and	subsequently	market	the	product.	Through	the	marketing	process,	the	product	is	delivered	to	the	ultimate	third-party	purchaser	at	a	contractually	agreed-upon delivery	point,	and	Devon	receives	a	specified	index	price	from	the	purchaser.	In	this	scenario,	revenue	is	recognized	when	control	transfers	to	the	purchaser	at	the delivery	point	based	on	the	index	price	received	from	the	purchaser.	The	gathering,	processing	and	compression	fees	attributable	to	the	gas	processing	contract,	as	well as	any	transportation	fees	incurred	to	deliver	the	product	to	the	purchaser,	are	presented	as	gathering,	processing	and	transportation	expense	as	a	component	of production	expenses	in	the	consolidated	comprehensive	statements	of	earnings.

# Oil	sales

Devon's	oil	sales	contracts	are	generally	structured	in	one	of	two	ways.	First,	production	is	sold	at	the	wellhead	at	an	agreed-upon	index	price,	net	of	pricing differentials.	In	this	scenario,	revenue	is	recognized	when	control	transfers	to	the	purchaser	at	the	wellhead	at	the	net	price	received.	Alternatively,	production	is delivered	to	the	purchaser	at	a	contractually	agreed-upon	delivery	point	at	which	the	purchaser	takes	custody,	title	and	risk	of	loss	of	the	product.	Under	this arrangement,	a	third	party	is	paid	to	transport	the	product	and	Devon	receives	a	specified	index	price	from	the	purchaser	with	no	transportation	deduction.	In	this scenario,	revenue	is	recognized	when	control	transfers	to	the	purchaser	at	the	delivery	point	based	on	the	price	received	from	the	purchaser.	The	third-party	costs	are recorded	as	gathering,	processing	and	transportation	expense	as	a	component	of	production	expenses	in	the	consolidated	comprehensive	statements	of	earnings.

# Marketing	Revenues

Marketing	revenues	are	generated	primarily	as	a	result	of	Devon	selling	commodities	purchased	from	third	parties.	Marketing	revenues	are	recognized	when performance	obligations	are	satisfied.	This	occurs	at	the	time	contract	specified	products	are	sold	to	third	parties	at	a	contractually	fixed	or	determinable	price,	delivery occurs	at	a	specified	point	or	performance	has	occurred,	control	has	transferred	and	collectability	of	the	revenue	is	probable.	The	transaction	price	used	to	recognize revenue	and	invoice	customers	is	based	on	a	contractually	stated	fee	or	on	a	third	party	published	index	price	plus	or	minus	a	known	differential.	Devon	typically receives	payment	for	invoiced	amounts	within	30	days.	Marketing	revenues	and	expenses	attributable	to	oil,	gas	and	NGL	purchases	are	reported	on	a	gross	basis	when Devon	takes	control	of	the	products	and	has	risks	and	rewards	of	ownership.

# Satisfaction	of	Performance	Obligations	and	Revenue	Recognitions

Because	Devon	has	a	right	to	consideration	from	its	customers	in	amounts	that	correspond	directly	to	the	value	that	the	customer	receives	from	the performance	completed	on	each	contract,	Devon	recognizes	revenue	for	sales	at	the	time	the	natural	gas,	NGLs	or	crude	oil	are	delivered	at	a	fixed	or	determinable	price.

# Transaction	Price	Allocated	to	Remaining	Performance	Obligations

Most	of	Devon's	contracts	are	short-term	in	nature	with	a	contract	term	of	one	year	or	less.	Devon	applies	the	practical	expedient	in	ASC	606	exempting	the disclosure	of	the	transaction	price	allocated	to	remaining	performance	obligations	if	the	performance	obligation	is	part	of	a	contract	that	has	an	original	expected duration	of	one	year	or	less.	For	contracts	with	terms	greater	than	one	year,	Devon	applies	the	practical	expedient	in	ASC	606	exempting	the	disclosure	of	the	transaction price	allocated	to	remaining	performance	obligations	if	the	variable	consideration	is	allocated	entirely	to	a	wholly	unsatisfied	performance	obligation.	Under	Devon's contracts,	each	unit	of	product	typically	represents	a	separate	performance	obligation;	therefore,	future	volumes	are	wholly	unsatisfied	and	disclosure	of	the	transaction price	allocated	to	remaining	performance	obligations	is	not	required.

# Contract	Balances

Cash	received	relating	to	future	performance	obligations	is	deferred	and	recognized	when	all	revenue	recognition	criteria	are	met.	Contract	liabilities	generated from	such	deferred	revenue	are	not	considered	material	as	of	December	31,	2018.	Devon's	product	sales	and	marketing	contracts	do	not	give	rise	to	contract	assets.

# Disaggregation	of	Revenue

Revenue	from	oil,	gas	and	NGL	sales	and	marketing	revenues	represent	revenue	from	contracts	with	customers.	Disaggregation	of	revenue	disclosures	can	be found	in	Note	22.

During	2018,	Devon	had	one	purchaser	that	accounted	for	approximately	11%	of	Devon's	consolidated	sales	revenue.

During	2017	and	2016,	no	purchaser	accounted	for	more	than	10%	of	Devon's	consolidated	sales	revenue.

Devon	is	exposed	to	certain	risks	relating	to	its	ongoing	business	operations,	including	risks	related	to	commodity	prices,	interest	rates	and	Canadian	to	U.S. dollar	exchange	rates.	As	discussed	more	fully	below,	Devon	uses	derivative	instruments	primarily	to	manage	commodity	price	risk,	interest	rate	risk	and	foreign exchange	risk.	Devon	does	not	intend	to	issue	or	hold	derivative	financial	instruments	for	speculative	trading	purposes.

Devon	enters	into	derivative	financial	instruments	with	respect	to	a	portion	of	its	oil,	gas	and	NGL	production	to	hedge	future	prices	received.	These instruments	are	used	to	manage	the	inherent	uncertainty	of	future	revenues	resulting	from	commodity	price	volatility.	Devon's	derivative	financial	instruments	typically include	financial	price	swaps,	basis	swaps	and	costless	price	collars.	Under	the	terms	of	the	price	swaps,	Devon	receives	a	fixed	price	for	its	production	and	pays	a variable	market	price	to	the	contract	counterparty.	For	the	basis	swaps,	Devon	receives	a	fixed	differential	between	two	regional	index	prices	and	pays	a	variable differential	on	the	same	two	index	prices	to	the	contract	counterparty.	For	price	collars,	Devon	utilizes	both	two-way	price	collars	and	three-way	price	collars.	The	two- way	price	collars	set	a	floor	and	ceiling	price	for	the	hedged	production.	If	the	applicable	monthly	price	indices	are	outside	of	the	ranges	set	by	the	floor	and	ceiling prices	in	the	various	collars,	Devon	will	cash-settle	the	difference	with	the	counterparty.	The	three-way	price	collars	consist	of	a	two-way	collar	with	an	additional	short put	option	sold	by	Devon,	and	cash-settle	similarly	to	the	two-way	collars	unless	the	market	price	falls	below	the	additional	short	put	causing	the	company	to	receive	the market	price	plus	the	long	put	to	short	put	price	differential.

Devon	periodically	enters	into	interest	rate	swaps	to	manage	its	exposure	to	interest	rate	volatility	and	foreign	exchange	forward	contracts	to	manage	its exposure	to	fluctuations	in	the	U.S.	and	Canadian	dollar	exchange	rates.	As	of	December	31,	2018,	Devon	did	not	have	any	open	foreign	exchange	contracts.

All	derivative	financial	instruments	are	recognized	at	their	current	fair	value	as	either	assets	or	liabilities	in	the	balance	sheet.	Changes	in	the	fair	value	of	these derivative	financial	instruments	are	recorded	in	earnings	unless	specific	hedge	accounting	criteria	are	met.	For	derivative	financial	instruments	held	during	the	three-year period	ended	December	31,	2018,	Devon	chose	not	to	meet	the	necessary	criteria	to	qualify	its	derivative	financial	instruments	for	hedge	accounting	treatment.	Cash settlements	with	counterparties	on	Devon's	derivative	financial	instruments	are	also	recorded	in	earnings.

By	using	derivative	financial	instruments	to	hedge	exposures	to	changes	in	commodity	prices,	interest	rates	and	foreign	currency	rates,	Devon	is	exposed	to credit	risk.	Credit	risk	is	the	failure	of	the	counterparty	to	perform	under	the	terms	of	the	derivative	contract.	To	mitigate	this	risk,	the	hedging	instruments	are	placed with	a	number	of	counterparties	whom	Devon	believes	are	acceptable	credit	risks.	It	is	Devon's	policy	to	enter	into	derivative	contracts	only	with	investment-grade	rated counterparties	deemed	by	management	to	be	competent	and	competitive	market	makers.	Additionally,	Devon's	derivative	contracts	generally	require	cash	collateral	to be	posted	if	either	its	or	the	counterparty's	credit	rating	falls	below	certain	credit	rating	levels.	As	of	December	31,	2018,	Devon	held	no	cash	collateral	of	its counterparties	nor	posted	collateral	to	its	counterparties.

G&A	is	reported	net	of	amounts	reimbursed	by	working	interest	owners	of	the	oil	and	gas	properties	operated	by	Devon.

# Share-Based	Compensation

Devon	grants	share-based	awards	to	members	of	its	Board	of	Directors	and	select	employees.	All	such	awards	are	measured	at	fair	value	on	the	date	of	grant and	are	generally	recognized	as	a	component	of	G&A	in	the	accompanying	consolidated	comprehensive	statements	of	earnings	over	the	applicable	requisite	service periods.	As	a	result	of	Devon's	restructuring	activity	discussed	in	Note	6,	certain	share-based	awards	were	accelerated	and	recognized	as	a	component	of	restructuring costs	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

Generally,	Devon	uses	new	shares	from	approved	incentive	programs	to	grant	share-based	awards	and	to	issue	shares	upon	stock	option	exercises.	Shares repurchased	under	approved	programs	are	generally	available	to	be	issued	as	part	of	Devon's	share-based	awards.	However,	Devon	has	historically	canceled	these shares	upon	repurchase.

Devon	is	subject	to	current	income	taxes	assessed	by	the	federal	and	various	state	jurisdictions	in	the	U.S.	and	by	other	foreign	jurisdictions.	In	addition,	Devon accounts	for	deferred	income	taxes	related	to	these	jurisdictions	using	the	asset	and	liability	method.	Under	this	method,	deferred	tax	assets	and	liabilities	are	recognized for	the	future	tax	consequences	attributable	to	differences	between	the	financial	statement	carrying	amounts	of	assets	and	liabilities	and	their	respective	tax	basis. Deferred	tax	assets	and	liabilities	are	measured	using	enacted	tax	rates	expected	to	apply	to	taxable	income	in	the	years	in	which	those	temporary	differences	and carryforwards	are	expected	to	be	recovered	or	settled.	The	effect	on	deferred	tax	assets	and	liabilities	of	a	change	in	tax	rates	is	recognized	in	income	in	the	period	that includes	the	enactment	date.

Deferred	tax	assets	are	also	recognized	for	the	future	tax	benefits	attributable	to	the	expected	utilization	of	existing	tax	net	operating	loss	carryforwards	and	other types	of	carryforwards.	If	the	future	utilization	of	some	portion	of	the	deferred	tax	assets	is	determined	to	be	unlikely,	a	valuation	allowance	is	provided	to	reduce	the recorded	tax	benefits	from	such	assets.	Devon	periodically	weighs	the	positive	and	negative	evidence	to	determine	if	it	is	more	likely	than	not	that	some	or	all	of	the deferred	tax	assets	will	be	realized.	Forming	a	conclusion	that	a	valuation	allowance	is	not	required	is	difficult	when	there	is	negative	evidence,	such	as	cumulative losses	in	recent	years.	See	Note	8	for	further	discussion.

Devon	recognizes	the	financial	statement	effects	of	tax	positions	when	it	is	more	likely	than	not,	based	on	the	technical	merits,	that	the	position	will	be sustained	upon	examination	by	a	taxing	authority.	Recognized	tax	positions	are	initially	and	subsequently	measured	as	the	largest	amount	of	tax	benefit	that	is	more likely	than	not	of	being	realized	upon	ultimate	settlement	with	a	taxing	authority.	Liabilities	for	unrecognized	tax	benefits	related	to	such	tax	positions	are	included	in other	long-term	liabilities	unless	the	tax	position	is	expected	to	be	settled	within	the	upcoming	year,	in	which	case	the	liabilities	are	included	in	other	current	liabilities. Interest	and	penalties	related	to	unrecognized	tax	benefits	are	included	in	current	income	tax	expense.

Devon	estimates	its	annual	effective	income	tax	rate	in	recording	its	provision	for	income	taxes	in	the	various	jurisdictions	in	which	it	operates.	Statutory	tax rate	changes	and	other	significant	or	unusual	items	are	recognized	as	discrete	items	in	the	period	in	which	they	occur.

# Net	Earnings	(Loss)	Per	Share	Attributable	to	Devon

Devon's	basic	earnings	per	share	amounts	have	been	computed	based	on	the	average	number	of	shares	of	common	stock	outstanding	for	the	period.	Basic earnings	per	share	includes	the	effect	of	participating	securities,	which	primarily	consist	of	Devon's	outstanding	restricted	stock	awards,	as	well	as	performance-based restricted	stock	awards	that	have	met	the	requisite	performance	targets.	Diluted	earnings	per	share	is	calculated	using	the	treasury	stock	method	to	reflect	the	assumed issuance	of	common	shares	for	all	potentially	dilutive	securities.	Such	securities	primarily	consist	of	unvested	performance	share	units.

# Cash	and	Cash	Equivalents

Devon	considers	all	highly	liquid	investments	with	original	contractual	maturities	of	three	months	or	less	to	be	cash	equivalents.

# Accounts	Receivable

Devon's	accounts	receivable	balance	primarily	consists	of	oil	and	gas	sales	receivables,	marketing	revenue	receivables	and	joint	interest	receivables	for	which Devon	does	not	require	collateral	security.	Devon	has	established	an	allowance	for	bad	debts	equal	to	the	estimable	portions	of	accounts	receivable,	including	joint interest	receivables,	for	which	failure	to	collect	is	considered	probable.	When	a	portion	of	the	receivable	is	deemed	uncollectible,	the	write-off	is	made	against	the allowance.

# Property	and	Equipment

# Oil	and	Gas	Property	and	Equipment

Devon	follows	the	successful	efforts	method	of	accounting	for	its	oil	and	gas	properties.	Exploration	costs,	such	as	exploratory	geological	and	geophysical costs,	and	costs	associated	with	nonproductive	exploratory	wells,	delay	rentals	and	exploration	overhead	are	charged	against	earnings	as	incurred.	Costs	of	drilling successful

exploratory	wells	along	with	acquisition	costs	and	the	costs	of	drilling	development	wells,	including	those	that	are	unsuccessful,	are	capitalized.	Devon	groups	its	oil	and gas	properties	with	a	common	geological	structure	or	stratigraphic	condition	("common	operating	field")	for	purposes	of	computing	DD&A,	assessing	proved	property impairments	and	accounting	for	asset	dispositions.

Exploratory	drilling	costs	and	exploratory-type	stratigraphic	test	wells	are	initially	capitalized,	or	suspended,	pending	the	determination	of	proved	reserves.	If proved	reserves	are	found,	drilling	costs	remain	capitalized	as	proved	properties.	Costs	of	unsuccessful	wells	are	charged	to	exploration	expense.	For	exploratory	wells that	find	reserves	that	cannot	be	classified	as	proved	when	drilling	is	completed,	costs	continue	to	be	capitalized	as	suspended	exploratory	well	costs	if	there	have	been sufficient	reserves	found	to	justify	completion	as	a	producing	well	and	sufficient	progress	is	being	made	in	assessing	the	reserves	and	the	economic	and	operating viability	of	the	project.	If	management	determines	that	future	appraisal	drilling	or	development	activities	are	unlikely	to	occur,	associated	suspended	exploratory	well costs	are	expensed.	In	some	instances,	this	determination	may	take	longer	than	one	year.	Devon	reviews	the	status	of	all	suspended	exploratory	drilling	costs	quarterly.

Capitalized	costs	of	proved	oil	and	gas	properties	are	depleted	by	an	equivalent	unit-of-production	method,	converting	gas	to	oil	at	the	ratio	of	six	Mcf	of	gas	to one	Bbl	of	oil.	Proved	leasehold	acquisition	costs,	less	accumulated	amortization,	are	depleted	over	total	proved	reserves,	which	includes	proved	undeveloped	reserves. Capitalized	costs	of	wells	and	related	equipment	and	facilities,	including	estimated	asset	retirement	costs,	net	of	estimated	salvage	values	and	less	accumulated amortization	are	depreciated	over	proved	developed	reserves	associated	with	those	capitalized	costs.	Depletion	is	calculated	by	applying	the	DD&A	rate	(amortizable base	divided	by	beginning	of	period	proved	reserves)	to	current	period	production.

Costs	associated	with	unproved	properties	are	excluded	from	the	depletion	calculation	until	it	is	determined	whether	or	not	proved	reserves	can	be	assigned	to such	properties.	Devon	assesses	its	unproved	properties	for	impairment	annually,	or	more	frequently	if	events	or	changes	in	circumstances	dictate	that	the	carrying	value of	those	assets	may	not	be	recoverable.	Significant	unproved	properties	are	assessed	individually.	Costs	of	insignificant	unproved	properties	are	amortized	to	exploration expense	on	a	group	basis	using	estimated	lease	surrender	rates	over	average	lease	terms.

Proved	properties	are	assessed	for	impairment	annually,	or	more	frequently	if	events	or	changes	in	circumstances	dictate	that	the	carrying	value	of	those	assets may	not	be	recoverable.	Individual	assets	are	grouped	for	impairment	purposes	based	on	a	common	operating	field.	If	there	is	an	indication	the	carrying	amount	of	an asset	may	not	be	recovered,	the	asset	is	assessed	for	potential	impairment	by	management	through	an	established	process.	If,	upon	review,	the	sum	of	the	undiscounted pre-tax	cash	flows	is	less	than	the	carrying	value	of	the	asset,	the	carrying	value	is	written	down	to	estimated	fair	value.	Because	there	is	usually	a	lack	of	quoted	market prices	for	long-lived	assets,	the	fair	value	of	impaired	assets	is	typically	determined	based	on	the	present	values	of	expected	future	cash	flows	using	discount	rates believed	to	be	consistent	with	those	used	by	principal	market	participants	or	by	comparable	transactions.	The	expected	future	cash	flows	used	for	impairment	reviews and	related	fair	value	calculations	are	typically	based	on	judgmental	assessments	of	future	production	volumes,	commodity	prices,	operating	costs,	and	capital investment	plans,	considering	all	available	information	at	the	date	of	review.

Gains	or	losses	are	recorded	for	sales	or	dispositions	of	oil	and	gas	properties	which	constitute	an	entire	common	operating	field	or	which	result	in	a	significant alteration	of	the	common	operating	field's	DD&A	rate.	These	gains	and	losses	are	classified	as	asset	dispositions	in	the	accompanying	consolidated	statements	of earnings.	Partial	common	operating	field	sales	or	dispositions	deemed	not	to	significantly	alter	the	DD&A	rates	are	generally	accounted	for	as	adjustments	to	capitalized costs	with	no	gain	or	loss	recognized.

Devon	capitalizes	interest	costs	incurred	and	attributable	to	material	unproved	oil	and	gas	properties	and	major	development	projects	of	oil	and	gas	properties.

# Other	Property	and	Equipment

Depreciation	and	amortization	of	other	property	and	equipment,	including	corporate	and	leasehold	improvements,	are	provided	using	the	straight-line	method based	on	estimated	useful	lives	ranging	from	three	to	60	years.	Interest	costs	incurred	and	attributable	to	major	corporate	construction	projects	are	also	capitalized.

Devon	recognizes	liabilities	for	retirement	obligations	associated	with	tangible	long-lived	assets,	such	as	producing	well	sites	when	there	is	a	legal	obligation associated	with	the	retirement	of	such	assets	and	the	amount	can	be	reasonably	estimated.	The	initial	measurement	of	an	asset	retirement	obligation	is	recorded	as	a liability	at	its	fair	value,	with	an	offsetting	asset	retirement	cost	recorded	as	an	increase	to	the	associated	property	and	equipment	on	the	consolidated	balance	sheet. When	the	assumptions	used	to	estimate	a	recorded	asset	retirement	obligation	change,	a	revision	is	recorded	to	both	the	asset	retirement	obligation	and	the	asset retirement	cost.	Devon's	asset	retirement	obligations	also	include	estimated	environmental	remediation	costs	which	arise	from	normal	operations	and	are	associated	with the	retirement	of	such	long-lived	assets.	The	asset	retirement	cost	is	depreciated	using	a	systematic	and	rational	method	similar	to	that	used	for	the	associated	property and	equipment.

Goodwill	represents	the	excess	of	the	purchase	price	of	business	combinations	over	the	fair	value	of	the	net	assets	acquired	and	is	tested	for	impairment annually,	or	more	frequently	if	events	or	changes	in	circumstances	dictate	that	the	carrying	value	of	goodwill	may	not	be	recoverable.	Such	test	includes	a	qualitative assessment	to	determine	whether	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit	is	less	than	its	carrying	amount.	If	the	qualitative	assessment	determines that	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit	is	less	than	its	carrying	amount,	including	goodwill,	then	a	quantitative	goodwill	impairment	test	is performed.	The	quantitative	goodwill	impairment	test	requires	the	fair	value	of	each	reporting	unit	be	compared	to	the	carrying	value	of	the	reporting	unit.	If	the	fair value	of	the	reporting	unit	is	less	than	the	carrying	value,	an	impairment	charge	will	be	recognized	for	the	amount	by	which	the	carrying	amount	exceeds	the	fair	value. Because	quoted	market	prices	are	not	available	for	Devon's	reporting	units,	the	fair	values	of	the	reporting	units	are	estimated	based	upon	several	valuation	analyses, including	comparable	companies,	comparable	transactions	and	premiums	paid.

Devon	performed	impairment	tests	of	goodwill	in	the	fourth	quarters	of	2018,	2017	and	2016.	No	impairment	was	required	as	a	result	of	the	annual	tests	in	these time	periods.

# Commitments	and	Contingencies

Liabilities	for	loss	contingencies	arising	from	claims,	assessments,	litigation	or	other	sources	are	recorded	when	it	is	probable	that	a	liability	has	been	incurred and	the	amount	can	be	reasonably	estimated.	Liabilities	for	environmental	remediation	or	restoration	claims	resulting	from	allegations	of	improper	operation	of	assets are	recorded	when	it	is	probable	that	obligations	have	been	incurred	and	the	amounts	can	be	reasonably	estimated.	Expenditures	related	to	such	environmental	matters are	expensed	or	capitalized	in	accordance	with	Devon's	accounting	policy	for	property	and	equipment.

# Fair	Value	Measurements

Certain	of	Devon's	assets	and	liabilities	are	measured	at	fair	value	at	each	reporting	date.	Fair	value	represents	the	price	that	would	be	received	to	sell	the	asset or	paid	to	transfer	the	liability	in	an	orderly	transaction	between	market	participants.	This	price	is	commonly	referred	to	as	the	"exit	price."	Fair	value	measurements	are classified	according	to	a	hierarchy	that	prioritizes	the	inputs	underlying	the	valuation	techniques.	This	hierarchy	consists	of	three	broad	levels:

•Level	1	–	Inputs	consist	of	unadjusted	quoted	prices	in	active	markets	for	identical	assets	and	liabilities	and	have	the	highest	priority.	When	available, Devon	measures	fair	value	using	Level	1	inputs	because	they	generally	provide	the	most	reliable	evidence	of	fair	value.

•Level	2	–	Inputs	consist	of	quoted	prices	that	are	generally	observable	for	the	asset	or	liability.	Common	examples	of	Level	2	inputs	include	quoted prices	for	similar	assets	and	liabilities	in	active	markets	or	quoted	prices	for	identical	assets	and	liabilities	in	markets	not	considered	to	be	active.

•Level	3	–	Inputs	are	not	observable	from	objective	sources	and	have	the	lowest	priority.	The	most	common	Level	3	fair	value	measurement	is	an internally	developed	cash	flow	model.

# Foreign	Currency	Translation	Adjustments

The	U.S.	dollar	is	the	functional	currency	for	Devon's	consolidated	operations	except	its	Canadian	subsidiaries,	which	use	the	Canadian	dollar	as	the	functional currency.	Assets	and	liabilities	of	the	Canadian	subsidiaries	are	translated	to	U.S.	dollars	using	the	applicable	exchange	rate	as	of	the	end	of	a	reporting	period. Revenues,	expenses	and	cash	flow	are	translated	using	an	average	exchange	rate	during	the	reporting	period.	Translation	adjustments	have	no	effect	on	net	income	and are	included	in	accumulated	other	comprehensive	earnings	in	stockholders'	equity.

# Noncontrolling	Interests

Noncontrolling	interests	represent	third-party	ownership	in	the	net	assets	of	Devon's	consolidated	subsidiaries	and	are	presented	as	a	component	of	equity. Changes	in	Devon's	ownership	interests	in	subsidiaries	that	do	not	result	in	deconsolidation	are	recognized	in	equity.

# Recently	Adopted	Accounting	Standards

In	January	2018,	Devon	adopted	ASU	2014-09,	Revenue	from	Contracts	with	Customers	(ASC	606),	using	the	modified	retrospective	method.	See	revenue recognition	section	above	for	further	discussion	regarding	Devon's	adoption	of	this	revenue	recognition	standard.

In	January	2018,	Devon	adopted	ASU	2017-07,	Compensation	–	Retirement	Benefits	(Topic	715),	Improving	the	Presentation	of	Net	Periodic	Pension	Cost	and Net	Periodic	Postretirement	Benefit	Cost.	This	ASU	requires	entities	to	present	the	service	cost	component	of	net	periodic	benefit	cost	in	the	same	line	item	as	other employee	compensation	costs.	Only	the	service	cost	component	of	net	periodic	benefit	cost	is	eligible	for	capitalization.	As	a	result	of	the	adoption	of	this	ASU, consolidated	statements	of	earnings	presentation	changes	were	applied	retrospectively,	while	service	cost	component	capitalization	was	applied	prospectively.	Upon adoption,	Devon	reclassified	$7	million	and	$14	million	of	non-service	cost	components	of	net	periodic	benefit	costs	for	2017	and	2016,	respectively,	from	G&A	to other	expenses.

In	January	2018,	Devon	adopted	ASU	2016-18,	Statement	of	Cash	Flows	(Topic	230):	Restricted	Cash.	This	ASU	requires	an	entity	to	show	the	changes	in	the total	of	cash,	cash	equivalents,	restricted	cash,	and	restricted	cash	equivalents	on	the	statement	of	cash	flows	and	to	provide	a	reconciliation	of	the	totals	in	the	statement of	cash	flows	to	the	related	captions	in	the	balance	sheet	when	the	cash,	cash	equivalents,	restricted	cash,	and	restricted	cash	equivalents	are	presented	in	more	than	one line	item	on	the	balance	sheet.	As	a	result	of	the	adoption	of	this	ASU,	Devon	made	changes	to	the	statement	of	cash	flows	to	include	the	required	presentation	and reconciliation	of	cash,	cash	equivalents,	restricted	cash,	and	restricted	cash	equivalents	retrospectively.	Other	than	presentation,	adoption	of	this	ASU	did	not	have	a material	impact	on	Devon's	consolidated	statements	of	cash	flows.

In	the	fourth	quarter	of	2018,	Devon	early	adopted	ASU	2018-02,	Income	Statement	–	Reporting	Comprehensive	Income	–	Reclassification	of	Certain	Tax Effects	from	Accumulated	Other	Comprehensive	Income	(Topic	220).	This	ASU	allows	for	a	reclassification	from	accumulated	other	comprehensive	income	to	retained earnings	for	stranded	tax	effects	resulting	from	the	Tax	Reform	Legislation.	As	a	result	of	adopting	this	ASU,	Devon	reclassified	$33	million	from	accumulated	other comprehensive	income	to	retained	earnings	in	the	December	31,	2018	consolidated	balance	sheet.

In	the	fourth	quarter	of	2018,	Devon	early	adopted	ASU	2018-14,	Compensation,	Retirement	Benefits	and	Defined	Benefit	Plans	(Subtopic	715-20):	Changes	to the	Disclosure	Requirements	for	Defined	Benefit	Plans.	This	ASU	eliminated	and	added	certain	disclosure	requirements	for	employers	that	sponsors	defined	benefit plans	and/or	other	postretirement	plans.	Other	than	changes	to	required	disclosures,	this	ASU	did	not	have	a	material	impact	on	Devon's	consolidated	financial statements	and	related	disclosures.

The	SEC	released	Final	Rule	No.	33	-10532,	Disclosure	Update	and	Simplification,	which	amends	various	SEC	disclosure	requirements	determined	to	be redundant,	duplicative,	overlapping,	outdated	or	superseded	as	part	of	the	SEC's	ongoing	disclosure	effectiveness	initiative.	The	rule	was	effective	November	5,	2018. The	rule	amended	numerous	SEC	rules,	items	and	forms	covering	a	diverse	group	of	topics.	Devon	has	implemented	these	required	changes	to	disclosures	which generally	reduced	or	eliminated	disclosures.	Devon	will	adopt	the	requirement	of	presenting	a	current	and	comparative	year-to-date	change	in	stockholder's	equity	roll forward	during	the	first	quarter	of	2019.

# Issued	Accounting	Standards	Not	Yet	Adopted

The	FASB	issued	ASU	2016-02,	Leases	(Topic	842).	This	ASU	will	supersede	the	lease	requirements	in	Topic	840,	Leases.	Its	objective	is	to	increase transparency	and	comparability	among	organizations.	This	ASU	provides	guidance	requiring	lessees	to	recognize	most	leases	on	their	balance	sheet.	Short-term	leases can	continue	being	accounted	for	off	balance	sheet	based	on	a	policy	election.	Lessor	accounting	does	not	significantly	change,	except	for	some	changes	made	to	align with	new	revenue	recognition	requirements.	Devon	is	adopting	this	ASU	beginning	January	1,	2019.

Devon	will	apply	the	guidance	using	a	modified	retrospective	transition	method	at	the	adoption	date.	Devon	has	elected	the	practical	expedient	provided	in	the standard	that	allows	the	new	guidance	to	be	applied	prospectively	to	all	new	or	modified	land	easements	and	rights-of-way.	Devon	also	has	elected	a	policy	not	to recognize	right-of-use	assets	and	lease	liabilities	related	to	short-term	leases.	Devon	will	be	allowed	to	continue	to	apply	the	legacy	guidance	in	Topic	840,	including	its disclosure	requirements,	in	the	comparative	periods	presented	with	the	2019	adoption	year.	Devon	has	implemented	processes,	controls,	and	a	technology	solution needed	to	comply	with	the	requirements	of	this	ASU.

To	adopt	Topic	842,	Devon	expects	to	recognize	right-of-use	assets	of	approximately	$400	million	with	a	corresponding	lease	liability	based	on	the	present value	of	the	remaining	term	minimum	lease	payments.	Devon's	right-of-use	assets	are	for	certain	leases	related	to	real	estate,	drilling	rigs	and	other	equipment	related	to the	exploration,	development	and	production	of	oil	and	gas.	Additionally,	Devon	will	recognize	a	$24	million	before	tax,	$19	million	net	of	tax	cumulative-effect adjustment	to	reduce	retained	earnings.

The	FASB	issued	ASU	2018-04,	Fair	Value	Measurement	(Topic	820):	Changes	to	the	Disclosure	Requirements	for	Fair	Value	Measurement.	This	ASU	will eliminate,	add	and	modify	certain	disclosure	requirements	for	fair	value	measurement.	The	ASU	is	effective	for	annual	and	interim	periods	beginning	January	1,	2020, with	early	adoption	permitted	for	either	the	entire	standard	or	only	the	provisions	that	eliminate	or	modify	requirements.	The	ASU	requires	the	additional	disclosure requirements	to	be	adopted	using	a	retrospective	approach.	Devon	is	currently	evaluating	the	provisions	of	this	ASU	and	assessing	the	impact	it	may	have	on	its disclosures	in	the	notes	to	the	consolidated	financial	statements.

The	FASB	issued	ASU	2018-05-15,	Intangibles,	Goodwill	and	Other	Internal-Use	Software	(Subtopic	350-40):	Customer's	Accounting	for	Implementation Costs	Incurred	in	a	Cloud	Computing	Arrangement	That	is	a	Service	Contract.	This	ASU	will	require	a	customer	in	a	cloud	computing	arrangement	(i.e.,	hosting arrangement)	that	is	a	service	contract	to	follow	the	internal-use	software	guidance	in	ASC	350-40	to	determine	which	implementation	costs	to	capitalize	as	assets	or expense	as	incurred.	Capitalized	implementation	costs	related	to	a	hosting	arrangement	that	is	a	service	contract	will	be	amortized	over	the	term	of	the	hosting arrangement,	beginning	when	the	module	or	component	of	the	hosting	arrangement	is	ready	for	its	intended	use.	This	ASU	is	effective	for	annual	and	interim	periods beginning	January	1,	2020,	with	early	adoption	permitted.	Entities	have	the	option	to	adopt	the	ASU	using	either	a	retrospective	approach	or	a	prospective	approach applied	to	all	implementation	costs	incurred	after	the	date	of	the	adoption.	Devon	is	currently	evaluating	the	provisions	of	this	ASU	and	assessing	the	impact	it	may	have on	its	consolidated	financial	statements.

# 2. Acquisitions	and	Divestitures

# Acquisitions

In	January	2016,	Devon	acquired	approximately	80,000	net	acres	and	assets	in	the	STACK	play	for	approximately	$1.5	billion.	Devon	funded	the	acquisition with	$849	million	of	cash,	after	adjustments,	and	$659	million	of	equity.	The	allocation	of	the	purchase	price	was	approximately	$1.3	billion	to	unproved	properties	and approximately	$200	million	to	proved	properties.

# Divestitures

# EnLink	and	General	Partner

During	the	third	quarter	of	2018,	Devon	completed	the	sale	of	its	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	for	$3.125	billion	and recognized	a	gain	of	approximately	$2.6	billion	($2.2	billion	after-tax).	The	proceeds	from	the	sale	were	utilized	to	increase	Devon's	share	repurchase	program	to	$4.0 billion,	which	is	discussed	further	in	Note	18.	Additional	information	on	these	discontinued	operations	can	be	found	in	Note	19.

# Upstream	Assets

During	2018,	Devon	received	proceeds	of	approximately	$1.0	billion	and	recognized	a	net	gain	on	asset	dispositions	of	approximately	$260	million,	primarily from	sales	of	non-core	assets	in	the	Barnett	Shale	and	Delaware	Basin.	As	part	of	the	transactions,	approximately	$84	million	of	asset	retirement	obligations	were assumed	by	the	purchasers.	In	conjunction	with	the	divestitures,	Devon	settled	certain	gas	processing	contracts	and	recognized	$40	million	in	settlement	expense,	which is	included	in	asset	dispositions	within	the	2018	consolidated	statements	of	earnings.	In	aggregate,	the	total	estimated	proved	reserves	associated	with	these	divested assets	were	approximately	267	MMBoe,	or	18%,	of	total	U.S.	proved	reserves.

Additionally,	in	the	first	quarter	of	2019,	Devon	completed	two	separate	divestitures	of	non-core	assets	in	the	Permian	Basin	totaling	$300	million.	One	of	the divestitures	related	to	the	sale	of	an	entire	common	operating	field,	and	Devon	expects	to	recognize	a	gain	of	approximately	$35	million	during	the	first	quarter	of	2019. As	of	December	31,	2018,	these	associated	assets	and	liabilities	were	classified	as	held	for	sale	in	the	accompanying	consolidated	balance	sheet.	See	Note	19	for additional	information.	In	aggregate,	the	total	estimated	proved	reserves	associated	with	these	divested	assets	were	approximately	25	MMBoe,	or	less	than	2%,	of	total U.S.	proved	reserves.

During	2017,	Devon	received	proceeds	totaling	approximately	$420	million,	and	recognized	a	net	gain	on	asset	dispositions	of	$212	million.	Estimated	proved reserves	associated	with	these	assets	were	less	than	1%	of	total	U.S.	proved	reserves.

During	2016,	Devon	received	proceeds	totaling	approximately	$1.9	billion	and	recognized	a	net	gain	on	asset	dispositions	of	$809	million,	primarily	from	sales of	non-core	assets	in	the	Mississippian,	east	Texas,	the	Anadarko	Basin	and	the	Midland	Basin.	Estimated	proved	reserves	associated	with	these	assets	were approximately	157	MMBoe,	or	10%,	of	total	U.S.	proved	reserves.	As	part	of	the	transactions,	approximately	$290	million	of	asset	retirement	obligations	were	assumed by	purchasers	and	approximately	$80	million	of	goodwill	was	allocated	to	these	divested	assets.

# Access	Pipeline

In	October	2016,	Devon	divested	its	50%	interest	in	Access	Pipeline	for	$1.1	billion	($1.4	billion	Canadian	dollars)	and	recognized	a	gain	of	approximately $540	million	on	the	transaction.	In	conjunction	with	the	divestiture,	Devon	entered	into	a	transportation	agreement	whereby	Devon's	Canadian	thermal-oil	acreage	is dedicated	to	Access	Pipeline	for	an	initial	term	of	25	years.	Devon	will	be	charged	a	market-based	toll	on	its	thermal-oil	production	over	this	term.	Devon	is	committed to	use	less	than	90%	of	the	potential	pipeline	capacity.	In	addition,	Devon	is	entitled	to	an	incremental	payment	of	approximately	$150	million	Canadian	dollars following	sanctioning	and	committing	to	the	requisite	volume	increase	in	respect	of	a	new	thermal-oil	project	on	Devon's	Pike	lease	in	Alberta,	with	such	incremental payment	being	received	prior	to	tolls	being	payable	on	such	volumes.

# Canada	and	Barnett	Shale	(Subsequent	Event)

In	February	2019,	Devon	announced	its	intent	to	separate	its	Canadian	business	and	Barnett	Shale	assets	from	the	Company,	based	on	authorizations	provided by	its	Board	of	Directors	subsequent	to	December	31,	2018.	Devon	will	evaluate	multiple	methods	of	separation	for	these	assets,	including	potential	sales	or	spin-offs. Devon	is	in	the	early	stages	of	marketing	these	assets	and	does	not	currently	have	any	indications	that	it	would	recognize	an	impairment	upon	separating	its	Canadian business	or	its	Barnett	Shale	assets.

Devon	anticipates	reporting	all	financial	information	for	its	Canadian	business	and	Barnett	Shale	assets	as	discontinued	operations	in	2019	when	all	the	requisite criteria	are	met	for	such	financial	statement	presentation.

As	of	December	31,	2018,	Devon	had	the	following	open	oil	derivative	positions.	The	first	two	tables	present	Devon's	oil	derivatives	that	settle	against	the average	of	the	prompt	month	NYMEX	WTI	futures	price.	The	third	table	presents	Devon's	oil	derivatives	that	settle	against	the	respective	indices	noted	within	the	table.

As	of	December	31,	2018,	Devon	had	the	following	open	natural	gas	derivative	positions.	The	first	table	presents	Devon's	natural	gas	derivatives	that	settle against	the	Inside	FERC	first	of	the	month	Henry	Hub	index.	The	second	table	presents	Devon's	natural	gas	derivatives	that	settle	against	the	respective	indices	noted within	the	table.

|  | Price	Swaps |  |  | Price	Collars |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Period | Volume\t(MMBtu/d) | Weighted\tAverage\tPrice\n($/MMBtu) | Volume\t(MMBtu/d) | Weighted\tAverage\tFloor\nPrice\t($/MMBtu) | Weighted\tAverage\nCeiling\tPrice\t($/MMBtu) |
| Q1-Q4\t2019 | 266,293 | $2.86 | 231,474 | $2.69 | $3.06 |
| Q1-Q4\t2020 | 26,480 | $2.92 | 24,490 | $2.74 | $3.04 |

| Period | Index | Volume<br>(MMBtu/d) | Henry	Hub<br>($/MMBtu) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2019 | Panhandle\tEastern\tPipe\tLine | 84,466 | $(0.73) |
| Q1-Q4\t2019 | El\tPaso\tNatural\tGas | 130,000 | $(1.46) |
| Q1-Q4\t2019 | Houston\tShip\tChannel | 142,637 | $0.01 |
| Q1-Q4\t2019 | Transco\tZone\t4 | 7,397 | $(0.03) |

As	of	December	31,	2018,	Devon	had	the	following	open	NGL	derivative	positions.	Devon's	NGL	positions	settle	against	the	average	of	the	prompt	month OPIS	Mont	Belvieu,	Texas	index.

| Period | Product | Volume	(Bbls/d) | ($/Bbl) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2019 | Ethane | 1,000 | $11.55 |
| Q1-Q4\t2019 | Natural\tGasoline | 4,500 | $55.93 |
| Q1-Q4\t2019 | Normal\tButane | 4,000 | $33.69 |
| Q1-Q4\t2019 | Propane | 8,500 | $30.01 |

# Interest	Rate	Derivatives

As	of	December	31,	2018,	Devon	had	the	following	open	interest	rate	derivative	positions:

In	January	2019,	this	interest	rate	derivative	position	settled.

# Financial	Statement	Presentation

The	following	table	presents	the	net	gains	and	losses	by	derivative	financial	instrument	type	followed	by	the	corresponding	individual	consolidated comprehensive	statements	of	earnings	caption.

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Commodity\tderivatives: |  |  |  |
| Upstream\trevenues | $608 | $157 | $(201) |
| Marketing\trevenues | (1) | 3 | (2) |
| Interest\trate\tderivatives: |  |  |  |
| Other\texpenses | 65 | (22) | (19) |
| Foreign\tcurrency\tderivatives: |  |  |  |
| Other\texpenses | — | — | (153) |
| Net\tgains\t(losses)\trecognized | $672 | $138 | $(375) |

The	following	table	presents	the	derivative	fair	values	by	derivative	financial	instrument	type	followed	by	the	corresponding	individual	consolidated	balance sheet	caption.

|  | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| Commodity\tderivative\tassets: |  |  |
| Other\tcurrent\tassets | $637 | $203 |
| Other\tlong-term\tassets | 40 | 2 |
| Interest\trate\tderivative\tassets: |  |  |
| Other\tcurrent\tassets | — | 1 |
| Total\tderivative\tassets | $677 | $206 |
| Commodity\tderivative\tliabilities: |  |  |
| Other\tcurrent\tliabilities | $67 | $259 |
| Other\tlong-term\tliabilities | 1 | 27 |
| Interest\trate\tderivative\tliabilities: |  |  |
| Other\tcurrent\tliabilities | — | 64 |
| Total\tderivative\tliabilities | $68 | $350 |

In	2017,	Devon's	stockholders	approved	the	2017	Plan.	The	2017	Plan	replaces	the	2015	Plan.	From	the	effective	date	of	the	2017	Plan,	no	further	awards	may be	made	under	the	2015	Plan,	and	awards	previously	granted	will	continue	to	be	governed	by	the	terms	of	the	respective	award	documents.	Subject	to	the	terms	of	the 2017	Plan,	awards	may	be	made	for	a	total	of	33.5	million	shares	of	Devon	common	stock,	plus	the	number	of	shares	available	for	issuance	under	the	2015	Plan (including	shares	subject	to	outstanding	awards	that	were	transferred	to	the	2017	Plan	in	accordance	with	its	terms).	The	2017	Plan	authorizes	the	Compensation Committee,	which	consists	of	independent,	non-management	members	of	Devon's	Board	of	Directors,	to	grant	nonqualified	and	incentive	stock	options,	restricted	stock awards	or	units,	Canadian	restricted	stock	units,	performance	units	and	stock	appreciation	rights	to	eligible	employees.	The	2017	Plan	also	authorizes	the	grant	of nonqualified	stock	options,	restricted	stock	awards	or	units	and	stock	appreciation	rights	to	non-employee	directors.	To	calculate	the	number	of	shares	that	may	be granted	in	awards	under	the	2017	Plan,	options	and	stock	appreciation	rights	represent	one	share	and	other	awards	represent	2.3	shares.

The	vesting	for	certain	share-based	awards	was	accelerated	in	2018	and	2016	in	conjunction	with	the	reduction	of	workforce	activities	described	in	Note	6	and is	included	in	restructuring	and	transaction	costs	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

The	table	below	presents	the	share-based	compensation	expense	included	in	Devon's	accompanying	consolidated	comprehensive	statements	of	earnings.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| G&amp;A | $122 | $141 | $124 |
| Exploration\texpenses | 4 | 7 | 6 |
| Restructuring\tand\ttransaction\tcosts | 31 | — | 60 |
| Total | $157 | $148 | $190 |
| Related\tincome\ttax\tbenefit | $22 | $6 | $6 |

The	following	table	presents	a	summary	of	Devon's	unvested	restricted	stock	awards	and	units,	performance-based	restricted	stock	awards	and	performance share	units	granted	under	the	plans.

The	following	table	presents	the	unrecognized	compensation	cost	and	the	related	weighted	average	recognition	period	associated	with	unvested	awards	and units	as	of	December	31,	2018.

|  |  | Performance-Based |  |
| :--- | :--- | :--- | :--- |
|  | Restricted\tStock | Restricted\tStock | Performance |
|  | Awards\tand\tUnits | Awards | Share\tUnits |
| Unrecognized\tcompensation\tcost | $117 | $1 | $23 |
| Weighted\taverage\tperiod\tfor\trecognition\t(years) | 2.4 | 1.0 | 1.7 |

# Restricted	Stock	Awards	and	Units

Restricted	stock	awards	and	units	are	subject	to	the	terms,	conditions,	restrictions	and	limitations,	if	any,	that	the	Compensation	Committee	deems	appropriate, including	restrictions	on	continued	employment.	Generally,	the	service	requirement	for	vesting	ranges	from	one	to	four	years.	During	the	vesting	period,	recipients	of restricted	stock	awards	made	under	the	2015	Plan	or	2009	Plan	receive	dividends	that	are	not	subject	to	restrictions	or	other	limitations.	However,	dividends	declared during	the	vesting	period	with	respect	to	restricted	stock	awards	made	under	the	2017	Plan	and	all	restricted	stock	units	will	not	be	paid	until	the	underlying	award	vests. Devon	estimates	the	fair	values	of	restricted	stock	awards	and	units	as	the	closing	price	of	Devon's	common	stock	on	the	grant	date	of	the	award	or	unit,	which	is expensed	over	the	applicable	vesting	period.

# Performance-Based	Restricted	Stock	Awards

Performance-based	restricted	stock	awards	were	granted	to	certain	members	of	Devon's	senior	management.	Vesting	of	the	awards	is	dependent	on	Devon meeting	certain	internal	performance	targets	and	the	recipient	meeting	certain	service	requirements.	Generally,	the	service	requirement	for	vesting	ranges	from	one	to four	years.	In	order	for	awards	to	vest,	the	performance	target	must	be	met	in	the	first	year.	If	the	performance	target	is	met,	the	recipient	is	entitled	to	dividends	under the	same	terms	described	above	for	nonperformance-based	restricted	stock.	If	the	performance	target	and	service	period	requirements	are	not	met,	the	award	does	not vest.	Devon	estimates	the	fair	values	of	the	awards	as	the	closing	price	of	Devon's	common	stock	on	the	grant	date	of	the	award,	which	is	expensed	over	the	applicable vesting	period.

# Performance	Share	Units

Performance	share	units	are	granted	to	certain	members	of	Devon's	management	and	senior	employees.	Each	unit	that	vests	entitles	the	recipient	to	one	share	of Devon	common	stock.	The	vesting	of	these	units	is	based	on	comparing	Devon's	TSR	to	the	TSR	of	a	predetermined	group	of	fourteen	peer	companies	over	the specified	three-year	performance	period.	The	vesting	of	units	may	be	between	zero	and	200%	of	the	units	granted	depending	on	Devon's	TSR	as	compared	to	the	peer group	on	the	vesting	date.

At	the	end	of	the	vesting	period,	recipients	receive	dividend	equivalents	with	respect	to	the	number	of	units	vested.	The	fair	value	of	each	performance	share unit	is	estimated	as	of	the	date	of	grant	using	a	Monte	Carlo	simulation	with	the	following	assumptions	used	for	all	grants	made	under	the	plan:	(i)	a	risk-free	interest	rate based	on	U.S.	Treasury	rates	as	of	the	grant	date;	(ii)	a	volatility	assumption	based	on	the	historical	realized	price	volatility	of	Devon	and	the	designated	peer	group;	and (iii)	an	estimated	ranking	of	Devon	among	the	designated	peer	group.	The	fair	value	of	the	unit	on	the	date	of	grant	is	expensed	over	the	applicable	vesting	period.	The following	table	presents	the	assumptions	related	to	performance	share	units	granted.

# Stock	Options

In	accordance	with	Devon's	incentive	plans,	the	exercise	price	of	stock	options	granted	may	not	be	less	than	the	market	value	of	the	stock	at	the	date	of	grant. In	addition,	options	granted	are	exercisable	during	a	period	established	for	each	grant,	which	may	not	exceed	eight	years	from	the	date	of	grant.	The	recipient	must	pay the	exercise	price	in	cash	or	in	common	stock,	or	a	combination	thereof,	at	the	time	that	the	option	is	exercised.	Generally,	the	service	requirement	for	vesting	ranges from	one	to	four	years.	The	fair	value	of	stock	options	on	the	date	of	grant	is	expensed	over	the	applicable	vesting	period.	No	stock	options	were	granted	in	2018,	2017 and	2016.	The	following	table	presents	a	summary	of	Devon's	outstanding	stock	options.

|  |  | Weighted	Average |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Options | Exercise\tPrice | Remaining\tTerm | Intrinsic\tValue |
|  | (Thousands) |  | (Years) |  |
| Outstanding\tat\tDecember\t31,\t2017 | 1,746 | $70.04 |  |  |
| Expired | (1,029) | $72.51 |  |  |
| Outstanding\tat\tDecember\t31,\t2018 | 717 | $66.49 | 0.87 | $— |
| Exercisable\tat\tDecember\t31,\t2018 | 717 | $66.49 | 0.87 | $— |

As	of	December	31,	2018,	Devon	had	no	unrecognized	compensation	cost	related	to	unvested	stock	options.

# 5. Asset	Impairments

The	following	table	presents	a	summary	of	Devon's	asset	impairments.	Unproved	impairments	shown	below	are	included	in	exploration	expenses	in	the consolidated	comprehensive	statements	of	earnings.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Proved\toil\tand\tgas\tassets | $109 | $— | $435 |
| Other\tassets | 47 | — | 2 |
| Total\tasset\timpairments | $156 | $— | $437 |
| Unproved\timpairments | $95 | $217 | $77 |

# Proved	Oil	and	Gas	and	Other	Asset	Impairments

In	2018,	Devon	recognized	$109	million	of	proved	asset	impairments	relating	to	U.S.	non-core	assets	no	longer	in	its	development	plans	and	approximately	$47 million	of	non-oil	and	gas	asset	impairments.

In	2016,	Devon	impaired	a	portion	of	its	U.S.	oil	and	gas	portfolio	due	to	lower	forecasted	oil,	gas	and	NGL	prices.

# Unproved	Impairments

In	2018,	2017	and	2016,	Devon	allowed	certain	non-core	acreage	to	expire	without	plans	for	development	resulting	in	unproved	impairments.

# 6. Restructuring	and	Transaction	Costs

The	following	table	summarizes	Devon's	restructuring	liabilities	presented	in	the	accompanying	consolidated	balance	sheets.

|  | Other | Other |  |
| :--- | :--- | :--- | :--- |
|  | Current | Long-term |  |
|  | Liabilities | Liabilities | Total |
| Balance\tas\tof\tDecember\t31,\t2016 | $48 | $62 | $110 |
| Changes\trelated\tto\tprior\tyears'\trestructurings | (29) | (31) | (60) |
| Balance\tas\tof\tDecember\t31,\t2017 | $19 | $31 | $50 |
| Changes\tdue\tto\t2018\tworkforce\treductions | 30 | — | 30 |
| Changes\trelated\tto\tprior\tyears'\trestructurings | (2) | (15) | (17) |
| Balance\tas\tof\tDecember\t31,\t2018 | $47 | $16 | $63 |

# 2018	Workforce	Reductions

In	2018,	Devon	announced	workforce	reductions	and	other	initiatives	designed	to	enhance	its	operational	focus	and	cost	structure.	As	a	result,	Devon recognized	$114	million	of	restructuring	expenses	during	2018,	primarily	consisting	of	employee-related	costs.	Of	these	expenses,	$31	million	resulted	from	accelerated vesting	of	share-based	grants,	which	are	noncash	charges.	Additionally,	$14	million	resulted	from	estimated	settlements	of	defined	retirement	benefits.

# Prior	Years'	Restructurings

In	2016,	Devon	recognized	$227	million	in	employee-related	and	other	costs	associated	with	a	reduction	in	workforce	that	was	made	in	response	to	the depressed	commodity	price	environment.	Of	these	employee-related	costs,	approximately	$60	million	resulted	from	accelerated	vesting	of	share-based	grants,	which	are noncash	charges.	Additionally,	approximately	$24	million	resulted	from	estimated	defined	benefit	settlements.

As	a	result	of	the	reduction	of	workforce,	Devon	ceased	using	certain	office	space	that	was	subject	to	non-cancellable	operating	lease	arrangements.	Devon recognized	$23	million	in	restructuring	costs	that	represent	the	present	value	of	its	future	obligations	under	the	leases	and	impairment	charges	for	leasehold improvements	and	furniture	associated	with	the	office	space	it	ceased	using.

# Transaction	Costs

In	2016,	Devon	recognized	$11	million	in	transaction	costs	primarily	associated	with	the	closing	of	the	STACK	acquisition	discussed	in	Note	2.

# 7. Other	Expenses

The	following	table	summarizes	Devon's	other	expenses	presented	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Foreign\texchange\t(gain)\tloss,\tnet | $139 | $(132) | $39 |
| Asset\tretirement\tobligation\taccretion | 59 | 62 | 75 |
| Other,\tnet | (58) | (13) | (13) |
| Total | $140 | $(83) | $101 |

# Foreign	exchange	(gain)	loss,	net

The	U.S.	dollar	is	the	functional	currency	for	Devon's	consolidated	operations	except	its	Canadian	subsidiaries,	which	use	the	Canadian	dollar	as	the	functional currency.	The	amounts	in	the	table	above	include	both	unrealized	and	realized	foreign	exchange	impacts	of	foreign	currency	denominated	monetary	assets	and	liabilities, including	intercompany	loans	between	subsidiaries	with	different	functional	currencies.	Unrealized	gains	and	losses	arise	from	the	remeasurement	of	these	foreign currency	denominated	monetary	assets	and	liabilities	and	intercompany	loans.	Realized	gains	and	losses	arise	when	there	are	settlements	of	these	foreign	currency denominated	monetary	assets	and	liabilities	and	intercompany	loans.

Foreign	currency	denominated	intercompany	loan	activity	during	2018	resulted	in	a	realized	loss	of	$241	million,	as	a	result	of	the	strengthening	of	the	U.S. dollar	in	relation	to	the	Canadian	dollar.	These	losses	during	2018,	were	partially	offset	by	reversing	$195	million	of	previously	recognized	unrealized	losses	on intercompany	loan	activity.

Foreign	currency	denominated	intercompany	loan	activity	during	2016	resulted	in	a	realized	gain	of	$63	million,	as	a	result	of	the	weakening	of	the	U.S.	dollar in	relation	to	the	Canadian	dollar.	These	gains	during	2016,	were	partially	offset	by	reversing	$10	million	of	previously	recognized	unrealized	gains	on	intercompany loan	activity.

# Income	Tax	Expense	(Benefit)

The	following	table	presents	Devon's	income	tax	components.

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Current\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | $(14) | $9 | $3 |
| Various\tstates | (3) | — | (11) |
| Canada\tand\tvarious\tprovinces | (53) | 103 | 106 |
| Total\tcurrent\ttax\texpense\t(benefit) | (70) | 112 | 98 |
| Deferred\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | 248 | — | — |
| Various\tstates | 63 | — | — |
| Canada\tand\tvarious\tprovinces | (85) | (97) | 43 |
| Total\tdeferred\ttax\texpense\t(benefit) | 226 | (97) | 43 |
| Total\tincome\ttax\texpense | $156 | $15 | $141 |

Total	income	tax	expense	differed	from	the	amounts	computed	by	applying	the	U.S.	federal	income	tax	rate	to	earnings	before	income	taxes	as	a	result	of	the

# following:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Current\tincome\ttax\texpense\t(benefit) | \t $(70) | $112 | $98 |
| Deferred\tincome\ttax\texpense\t(benefit) | 226 | (97) | 43 |
| Total\tincome\ttax\texpense | \t $156 | $15 | $141 |
| U.S.\tstatutory\tincome\ttax\trate | 21% | 35% | 35% |
| U.S.\tTax\tReform | 0% | 36% | 0% |
| Legal\tentity\trestructuring | 2% | (94%) | 19% |
| State\tincome\ttaxes | 5% | 0% | 10% |
| Change\tin\tunrecognized\ttax\tbenefits | (5%) | 2% | (16%) |
| Other | (0%) | (13%) | 8% |
| Deferred\ttax\tasset\tvaluation\tallowance | (6%) | 36% | (89%) |
| Effective\tincome\ttax\trate | 17% | 2% | (33%) |

Devon	and	its	subsidiaries	are	subject	to	U.S.	federal	income	tax	as	well	as	income	or	capital	taxes	in	various	state	and	foreign	jurisdictions.	Devon's	tax reserves	are	related	to	tax	years	that	may	be	subject	to	examinations	by	the	relevant	taxing	authority.	Devon	is	under	audit	in	the	U.S.	and	various	foreign	jurisdictions	as part	of	its	normal	course	of	business.

Devon	assesses	the	realizability	of	its	deferred	tax	assets.	If	Devon	concludes	that	it	is	more	likely	than	not	that	some	portion	or	all	of	the	deferred	tax	assets will	not	be	realized,	the	asset	is	reduced	by	a	valuation	allowance.	Numerous	judgments	and	assumptions	are	inherent	in	the	determination	of	future	taxable	income, including	factors	such	as	future	operating	conditions	(particularly	as	related	to	prevailing	oil	and	gas	prices)	and	changing	tax	laws.

In	the	second	quarter	of	2018,	Devon's	Canadian	segment	utilized	a	portion	of	its	capital	losses	as	a	part	of	an	internal	legal	entity	restructuring.	A	valuation allowance	remains	recorded	against	the	remaining	balance	of	the	capital	losses.

During	2018,	Devon	recorded	a	tax	benefit	of	$42	million	related	to	unrecognized	tax	benefits,	primarily	as	a	result	of	a	favorable	Canadian	court	decision and	the	closure	of	prior	year	IRS	audits.

Throughout	2017	and	through	the	first	two	quarters	of	2018,	Devon's	U.S.	segment	maintained	a	100%	valuation	allowance	against	its	U.S.	deferred	tax assets.	However,	upon	closing	the	EnLink	divestiture	in	the	third	quarter	of	2018,	Devon	realized	a	pre-tax	gain	of	$2.6	billion.	Based	on	its	net	deferred	tax	liability position,	current	period	projected	net	operating	loss	utilization,	and	projections	of	future	taxable	income,	Devon	reassessed	its	position	and	determined	that	its	U.S. segment	is	no	longer	in	a	full	valuation	allowance	position,	maintaining	only	valuation	allowances	against	certain	deferred	tax	assets,	including	certain	tax	credits	and state	net	operating	losses.	As	part	of	its	reassessment,	Devon	determined	that	apart	from	the	sale	of	EnLink	and	the	General	Partner,	Devon's	U.S.	segment	would	have remained	in	a	full	valuation	allowance	position.	Accordingly,	the	deferred	tax	benefit	resulting	from	the	release	of	the	valuation	allowance	that	was	generated	in	the	first two	quarters	was	allocated	to	continuing	operations,	while	the	$259	million	of	the	deferred	tax	benefit	resulting	from	the	release	of	the	remainder	of	the	full	valuation allowance	position	was	allocated	entirely	to	discontinued	operations.	A	partial	valuation	allowance	continues	to	be	held	against	certain	Canadian	segment	deferred	tax assets.	During	2018,	the	Canadian	segment	reduced	its	valuation	allowance	by	approximately	$59	million.

The	Tax	Reform	Legislation,	enacted	on	December	22,	2017,	contained	several	key	tax	provisions	that	affected	Devon,	including	a	one-time	mandatory transition	tax	on	accumulated	foreign	earnings	and	a	reduction	of	the	corporate	income	tax	rate	to	21%	effective	January	1,	2018.	Devon	was	required	to	recognize	the effect	of	the	tax	law	changes	in	the	period	of	enactment,	such	as	determining	the	transition	tax,	remeasuring	U.S.	deferred	tax	assets	and	liabilities	and	reassessing	the	net realizability	of	deferred	tax	assets	and	liabilities.	Devon's	U.S.	segment	recognized	$167	million	of	deferred	tax	expense	for	the	one-time	mandatory	transition	tax	on accumulated	foreign	earnings,	and	$108	million	in	deferred	tax	expense	related	to	the	reduction	of	the	U.S.	corporate	income	tax	rate	to	21%.

In	the	fourth	quarter	of	2017,	Devon's	Canadian	segment	generated	nonrecurring	capital	losses	from	internal	legal	entity	restructuring.	A	deferred	tax	asset	of $727	million	was	recognized	related	to	the	capital	losses,	offset	by	a	$641	million	increase	in	the	valuation	allowance.

Devon	maintained	a	100%	valuation	allowance	against	its	U.S.	deferred	tax	assets	resulting	from	prior	year	cumulative	financial	losses	largely	due	to	asset impairments	and	significant	net	operating	losses	for	U.S.	federal	and	state	income	tax.	Devon	reduced	its	U.S.	segment	valuation	allowance	by	$323	million	in	2017 based	primarily	on	the	financial	income	recorded	during	the	period.	Furthermore,	a	partial	allowance	continues	to	be	held	against	certain	Canadian	segment	deferred	tax assets.

Also	in	the	table	above,	the	"other"	effect	is	primarily	composed	of	permanent	differences	for	which	dollar	amounts	do	not	increase	or	decrease	in	relation	to the	change	in	pre-tax	earnings.	Generally,	such	items	have	an	insignificant	impact	on	our	effective	income	tax	rate.	However,	these	items	have	a	more	noticeable	impact to	our	rate	in	2017	due	to	lower	relative	earnings	during	the	period.

Devon	recorded	a	tax	expense	of	$63	million	related	to	unrecognized	tax	benefits	during	2016,	primarily	as	a	result	of	Canadian	audits	and	legal	proceedings.

During	2016,	Devon's	U.S.	segment	recognized	an	additional	$313	million	valuation	allowance	against	its	deferred	tax	assets.	The	allowance	resulted	from continued	financial	losses	in	2016.	As	of	December	31,	2016,	the	allowance	continued	to	represent	a	100%	valuation	against	the	U.S.	net	deferred	tax	assets. Additionally,	the	Canadian	segment	recognized	a	$71	million	partial	valuation	allowance	resulting	from	continued	financial	losses.

During	the	third	quarter	of	2016,	Devon	derecognized	$83	million	of	goodwill	related	to	its	U.S.	operations	in	conjunction	with	the	divestiture	of	certain	non- core	U.S.	upstream	oil	and	gas	assets.	These	items	were	not	deductible	for	purposes	of	calculating	income	tax	and,	therefore,	impacted	the	effective	tax	rate.

# Deferred	Tax	Assets	and	Liabilities

The	following	table	presents	the	tax	effects	of	temporary	differences	that	gave	rise	to	Devon's	deferred	tax	assets	and	liabilities.

|  | December	31,<br>2018 | 2017 |
| :--- | :--- | :--- |
| Deferred\ttax\tassets: |  |  |
| Asset\tretirement\tobligations | $300 | $313 |
| Accrued\tliabilities | 50 | 62 |
| Net\toperating\tloss\tcarryforwards | 287 | 796 |
| Pension\tbenefit\tobligations | 44 | 54 |
| Canadian\tcapital\tloss\tcarryforwards | 609 | 760 |
| Other | 87 | 135 |
| Total\tdeferred\ttax\tassets\tbefore\tvaluation\tallowance | 1,377 | 2,120 |
| Less:\tvaluation\tallowance | (640) | (968) |
| Net\tdeferred\ttax\tassets | 737 | 1,152 |
| Deferred\ttax\tliabilities: |  |  |
| Property\tand\tequipment | (1,473) | (1,288) |
| Long-term\tdebt | — | (92) |
| Other | (141) | (261) |
| Total\tdeferred\ttax\tliabilities | (1,614) | (1,641) |
| Net\tdeferred\ttax\tliability | $(877) | $(489) |

At	December	31,	2018,	Devon	has	recognized	$287	million	of	deferred	tax	assets	related	to	various	net	operating	loss	carryforwards	available	to	offset	future income	taxes.	The	Canadian	segment	has	$595	million	of	noncapital	loss	carryforwards	expiring	between	2029	and	2038.	Devon's	U.S.	segment	has	$389	million	of U.S.	federal	net	operating	loss	carryforwards	expiring	in	2037	and	$784	million	of	U.S.	state	net	operating	loss	carryforwards	expiring	between	2019	and	2038.	In	the current	environment,	Devon	expects	tax	benefits	from	the	U.S.	federal,	majority	of	U.S.	state	and	Canadian	noncapital	loss	carryforwards	to	be	utilized	in	2019	and beyond.

As	a	result	of	Devon's	sale	of	its	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	during	the	third	quarter	of	2018,	Devon's	U.S.	segment reassessed	its	position	and	released	its	full	valuation	allowance	position,	maintaining	only	$31	million	of	valuation	allowance	against	certain	deferred	tax	assets, including	certain	tax	credits	and	state	net	operating	losses.	Also	during	2018,	Devon's	Canadian	segment	maintained	a	valuation	allowance	of	$609	million	against	the deferred	tax	asset	related	to	the	Canadian	capital	loss	carryforward	due	to	projected	lack	of	future	capital	gain	income.	In	the	event	Devon	were	to	determine	that	it would	be	able	to	realize	the	deferred	income	tax	assets	in	the	future,	Devon	would	adjust	the	valuation	allowance,	reducing	the	provision	for	income	taxes	in	the	period of	such	adjustment.

After	enactment	of	the	Tax	Reform	Legislation,	Devon's	Canadian	segment	is	the	sole	foreign	operation	to	be	considered	for	the	indefinitely	reinvested assertion	of	APB	23.	Devon's	Canadian	operations	are	robust	and	active	and	requires	continuing	capital	investment.	Accordingly,	as	of	December	31,	2018,	no	income taxes	should	be	accrued	by	Devon	relative	to	its	investment	in	its	Canadian	operations.	In	view	of	Devon's	decision	in	February	2019	to	dispose	of	the	Canadian business,	the	indefinitely	reinvested	assertion	of	APB	23	and	any	required	accrual	of	income	tax	will	be	reevaluated	in	2019.

# Unrecognized	Tax	Benefits

The	following	table	presents	changes	in	Devon's	unrecognized	tax	benefits.

|  | December	31, |  |
| :--- | :--- | :--- |
|  | 2018 | 2017 |
| Balance\tat\tbeginning\tof\tyear | $115 | $202 |
| Tax\tpositions\ttaken\tin\tprior\tperiods | (43) | (7) |
| Tax\tpositions\ttaken\tin\tcurrent\tyear | (2) | (3) |
| Accrual\tof\tinterest\trelated\tto\ttax\tpositions\ttaken | 3 | 16 |
| Settlements | — | (101) |
| Foreign\tcurrency\ttranslation | (3) | 8 |
| Balance\tat\tend\tof\tyear | $70 | $115 |

Devon's	unrecognized	tax	benefit	balance	at	December	31,	2018	and	2017	included	$12	million	and	$28	million,	respectively,	of	interest	and	penalties.	If recognized,	$70	million	of	Devon's	unrecognized	tax	benefits	as	of	December	31,	2018	would	affect	Devon's	effective	income	tax	rate.	During	2018,	Devon	removed $43	million	of	unrecognized	tax	benefits,	including	$20	million	of	interest,	as	a	result	of	the	closure	of	certain	tax	examinations.	Included	below	is	a	summary	of	the	tax years,	by	jurisdiction,	that	remain	subject	to	examination	by	taxing	authorities.

Certain	statute	of	limitation	expirations	are	scheduled	to	occur	in	the	next	twelve	months.	However,	Devon	is	currently	in	various	stages	of	the	administrative review	process	for	certain	open	tax	years.	In	addition,	Devon	is	currently	subject	to	various	income	tax	audits	that	have	not	reached	the	administrative	review	process.

# 9. Net	Earnings	(Loss)	Per	Share	from	Continuing	Operations

The	following	table	reconciles	net	earnings	(loss)	from	continuing	operations	and	weighted-average	common	shares	outstanding	used	in	the	calculations	of basic	and	diluted	net	earnings	(loss)	per	share	from	continuing	operations.

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations: |  |  |  |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations | $764 | $758 | $(574) |
| Attributable\tto\tparticipating\tsecurities | (9) | (8) | (2) |
| Basic\tand\tdiluted\tearnings\t(loss)\tfrom\tcontinuing\toperations | $755 | $750 | $(576) |
| Common\tshares: |  |  |  |
| Common\tshares\toutstanding\t-\ttotal | 499 | 525 | 513 |
| Attributable\tto\tparticipating\tsecurities | (5) | (5) | (6) |
| Common\tshares\toutstanding\t-\tbasic | 494 | 520 | 507 |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | 3 | 3 | — |
| Common\tshares\toutstanding\t-\tdiluted | 497 | 523 | 507 |
| Net\tearnings\t(loss)\tper\tshare\tfrom\tcontinuing\toperations: |  |  |  |
| Basic | $1.53 | $1.44 | $(1.14) |
| Diluted | $1.52 | $1.43 | $(1.14) |
| Antidilutive\toptions\t(1) | 1 | 2 | 3 |

(1) Amounts	represent	options	to	purchase	shares	of	Devon's	common	stock	that	are	excluded	from	the	diluted	net	earnings	per	share	calculations	because	the options	are	antidilutive.

# 10. Other	Comprehensive	Earnings

Components	of	other	comprehensive	earnings	consist	of	the	following:

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Foreign\tcurrency\ttranslation: |  |  |  |
| Beginning\taccumulated\tforeign\tcurrency\ttranslation | \t$1,309 | $1,226 | $1,215 |
| Change\tin\tcumulative\ttranslation\tadjustment | (166) | 113 | 22 |
| Income\ttax\tbenefit\t(expense) | 14 | (30) | (11) |
| Ending\taccumulated\tforeign\tcurrency\ttranslation | 1,157 | 1,309 | 1,226 |
| Pension\tand\tpostretirement\tbenefit\tplans: |  |  |  |
| Beginning\taccumulated\tpension\tand\tpostretirement\tbenefits | (143) | (172) | (194) |
| Net\tactuarial\tloss\tand\tprior\tservice\tcost\tarising\tin\tcurrent\tyear | (3) | 10 | (28) |
| Recognition\tof\tnet\tactuarial\tloss\tand\tprior\tservice\tcost\tin\tearnings\t(1) | 12 | 19 | 26 |
| Curtailment\tand\tsettlement\tof\tpension\tbenefits | 47 | — | 24 |
| Income\ttax\texpense | (12) | — | — |
| Other\t(2) | (33) | — | — |
| Ending\taccumulated\tpension\tand\tpostretirement\tbenefits | (132) | (143) | (172) |
| Other | 2 | — | — |
| Accumulated\tother\tcomprehensive\tearnings,\tnet\tof\ttax | \t$1,027 | $1,166 | $1,054 |

(1) These	accumulated	other	comprehensive	earnings	components	are	included	in	the	computation	of	net	periodic	benefit	cost,	which	is	a	component	of	other expenses	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.	See	Note	17	for	additional	details.

(2) As	a	result	of	Devon's	early	adoption	of	ASU	2018-02	in	the	fourth	quarter	of	2018,	Devon	reclassified	$33	million	from	accumulated	other	comprehensive income	to	retained	earnings	in	the	December	31,	2018	consolidated	balance	sheet.	See	Note	1	for	additional	details.

# 11. Supplemental	Information	to	Statements	of	Cash	Flows

|  | 2018 | Year	Ended	December	31,<br>2017 | 2016 |
| :--- | :--- | :--- | :--- |
| Changes\tin\tassets\tand\tliabilities,\tnet |  |  |  |
| Accounts\treceivable | $88 | $(94) | $(58) |
| Other\tcurrent\tassets | (128) | 20 | 326 |
| Other\tlong-term\tassets | (28) | (47) | 36 |
| Accounts\tpayable | — | 113 | (196) |
| Revenues\tand\troyalties\tpayable | 153 | 106 | (26) |
| Other\tcurrent\tliabilities | (150) | (53) | (74) |
| Other\tlong-term\tliabilities | (78) | (13) | 16 |
| Total | $(143) | $32 | $24 |
| Supplementary\tcash\tflow\tdata\t-\ttotal\toperations: |  |  |  |
| Interest\tpaid\t(net\tof\tcapitalized\tinterest) | $385 | $481 | $569 |
| Income\ttaxes\tpaid\t(received) | $40 | $78 | $(159) |

In	2016,	Devon's	acquisition	of	certain	STACK	assets	included	the	noncash	issuance	of	Devon	common	stock.	See	Note	2	for	additional	details.	Further,	in 2016,	EnLink's	acquisition	of	Anadarko	Basin	gathering	and	processing	midstream	assets	included	noncash	issuance	of	General	Partner	common	units.	Additionally, EnLink's	formation	of	a	joint	venture	during	the	third	quarter	of	2016	included	non-monetary	asset	contributions.

Components	of	accounts	receivable	include	the	following:

|  | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| Oil,\tgas\tand\tNGL\tsales | $430 | $559 |
| Joint\tinterest\tbillings | 155 | 134 |
| Marketing\trevenues | 285 | 278 |
| Other | 23 | 29 |
| Gross\taccounts\treceivable | 893 | 1,000 |
| Allowance\tfor\tdoubtful\taccounts | (8) | (11) |
| Net\taccounts\treceivable | $885 | $989 |

# 13. Property,	Plant	and	Equipment

# Capitalized	Costs

The	following	table	reflects	the	aggregate	capitalized	costs	related	to	Devon's	oil	and	gas	and	non-oil	and	gas	activities.

|  | U.S. | December	31,	2018<br>Canada | Total |
| :--- | :--- | :--- | :--- |
| Property\tand\tequipment: |  |  |  |
| Proved | $40,378 | $6,427 | $46,805 |
| Unproved\tand\tproperties\tunder\tdevelopment | 833 | 1,434 | 2,267 |
| Total\toil\tand\tgas | 41,211 | 7,861 | 49,072 |
| Less\taccumulated\tDD&amp;A | (32,229) | (4,030) | (36,259) |
| Oil\tand\tgas\tproperty\tand\tequipment,\tnet | $8,982 | $3,831 | $12,813 |
| Other\tproperty\tand\tequipment |  |  | 1,832 |
| Less\taccumulated\tDD&amp;A |  |  | (710) |
| Other\tproperty\tand\tequipment,\tnet |  |  | 1,122 |
| Property\tand\tequipment,\tnet |  |  | $13,935 |

|  | U.S. | December	31,	2017<br>Canada | Total |
| :--- | :--- | :--- | :--- |
| Property\tand\tequipment: |  |  |  |
| Proved | $40,491 | $6,804 | $47,295 |
| Unproved\tand\tproperties\tunder\tdevelopment | 984 | 1,473 | 2,457 |
| Total\toil\tand\tgas | 41,475 | 8,277 | 49,752 |
| Less\taccumulated\tDD&amp;A | (32,379) | (4,055) | (36,434) |
| Oil\tand\tgas\tproperty\tand\tequipment,\tnet | $9,096 | $4,222 | $13,318 |
| Other\tproperty\tand\tequipment |  |  | 1,955 |
| Less\taccumulated\tDD&amp;A |  |  | (689) |
| Other\tproperty\tand\tequipment,\tnet |  |  | 1,266 |
| Property\tand\tequipment,\tnet |  |  | $14,584 |

# Suspended	Exploratory	Well	Costs

The	following	summarizes	the	changes	in	suspended	exploratory	well	costs	for	the	three	years	ended	December	31,	2018.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Beginning\tbalance | $313 | $261 | $225 |
| Additions\tpending\tdetermination\tof\tproved\treserves | 672 | 504 | 247 |
| Charges\tto\texploration\texpense | — | — | (29) |
| Reclassifications\tto\tproved\tproperties | (662) | (466) | (189) |
| Foreign\tcurrency\ttranslation\tadjustment | (19) | 14 | 7 |
| Ending\tbalance | $304 | $313 | $261 |

The	following	table	provides	an	aging	of	capitalized	well	costs	and	the	number	of	projects	for	which	exploratory	well	costs	have	been	capitalized	for	a	period greater	than	one	year	since	the	completion	of	drilling.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Exploratory\twell\tcosts\tcapitalized\tfor\ta\tperiod\tof\tone\tyear\tor\tless | $110 | $113 | $88 |
| Exploratory\twell\tcosts\tcapitalized\tfor\ta\tperiod\tgreater\tthan\tone\tyear | 194 | 200 | 173 |
| Ending\tbalance | $304 | $313 | $261 |
| Number\tof\tprojects\twith\texploratory\twell\tcosts\tcapitalized\tfor\ta\n\t\t\tperiod\tgreater\tthan\tone\tyear | 2 | 2 | 2 |

Projects	with	suspended	exploratory	well	costs	capitalized	for	a	period	greater	than	one	year	since	the	completion	of	drilling	relate	to	Devon's	heavy	oil operations.	Management	believes	these	projects	with	suspended	exploratory	well	costs	exhibit	sufficient	quantities	of	hydrocarbons	to	justify	potential	development. Currently,	Devon	has	not	planned	additional	exploratory	work	in	the	near	future	on	these	assets	and	will	continue	to	assess	its	future	development	timeline	of	these	long cycle	projects	as	it	competes	for	capital	allocation	within	Devon's	portfolio.	Devon's	interest	in	this	acreage	does	not	begin	to	expire	until	2025.

# 14. Other	Current	Liabilities

Components	of	other	current	liabilities	include	the	following:

|  | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| Derivative\tliabilities | $67 | $323 |
| Accrued\tinterest\tpayable | 80 | 96 |
| Income\ttaxes\tpayable | 14 | 144 |
| Restructuring\tliabilities | 47 | 19 |
| Other | 227 | 246 |
| Other\tcurrent\tliabilities | $435 | $828 |

# 15. Debt	and	Related	Expenses

See	below	for	a	summary	of	debt	instruments	and	balances.	The	notes	and	debentures	are	senior,	unsecured	obligations	of	Devon.

|  | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| 8.25%\tdue\tJuly\t1,\t2018\t(1) | \t $— | $20 |
| 2.25%\tdue\tDecember\t15,\t2018 | — | 95 |
| 6.30%\tdue\tJanuary\t15,\t2019 | 162 | 162 |
| 4.00%\tdue\tJuly\t15,\t2021 | 500 | 500 |
| 3.25%\tdue\tMay\t15,\t2022 | 1,000 | 1,000 |
| 5.85%\tdue\tDecember\t15,\t2025 | 485 | 485 |
| 7.50%\tdue\tSeptember\t15,\t2027\t(1) | 73 | 73 |
| 7.875%\tdue\tSeptember\t30,\t2031\t(2)\t(3) | 675 | 1,059 |
| 7.95%\tdue\tApril\t15,\t2032\t(2) | 366 | 789 |
| 5.60%\tdue\tJuly\t15,\t2041 | 1,250 | 1,250 |
| 4.75%\tdue\tMay\t15,\t2042 | 750 | 750 |
| 5.00%\tdue\tJune\t15,\t2045 | 750 | 750 |
| Net\tdiscount\ton\tdebentures\tand\tnotes | (24) | (30) |
| Debt\tissuance\tcosts | (40) | (39) |
| Total\tdebt | 5,947 | 6,864 |
| Less\tamount\tclassified\tas\tshort-term\tdebt\t(4) | 162 | 115 |
| Total\tlong-term\tdebt | $5,785 | $6,749 |

(1) These	instruments	were	assumed	by	Devon	in	April	2003	in	conjunction	with	the	merger	with	Ocean	Energy.	The	fair	value	and	effective	rates	of	these	8.25% notes	and	7.50%	notes	at	the	time	assumed	was	$147	million	and	5.5%,	respectively,	and	$169	million	and	6.5%,	respectively.These	instruments	are	the unsecured	and	unsubordinated	obligations	of	Devon	OEI	Operating,	L.L.C.	and	are	guaranteed	by	Devon	Energy	Production	Company,	L.P.	Each	of	these entities	is	a	wholly-owned	subsidiary	of	Devon.

(2) These	senior	notes	were	included	in	2018	tender	offer	repurchases	discussed	below.

(3) Issued	in	October	2001,	these	are	the	unsecured	and	unsubordinated	obligations	of	Devon	Financing,	a	wholly	owned	subsidiary	of	Devon.	These	instruments are	fully	and	unconditionally	guaranteed	by	Devon.

Debt	maturities	as	of	December	31,	2018,	excluding	debt	issuance	costs,	premiums	and	discounts,	are	as	follows:

|  | Total |
| :--- | :--- |
| 2019 | $162 |
| 2020 | — |
| 2021 | 500 |
| 2022 | 1,000 |
| 2023 | — |
| Thereafter | 4,349 |
| Total | $6,011 |

# Credit	Lines

Under	its	2012	Senior	Credit	Facility,	Devon	had	$3.0	billion	of	available	credit.	On	October	5,	2018,	Devon	terminated	its	2012	Senior	Credit	Facility	and subsequently	entered	into	its	new	$3.0	billion	revolving	2018	Senior	Credit	Facility.	The	2018	Senior	Credit	Facility	matures	on	October	5,	2023,	with	the	option	to extend	the	maturity	date	by	two	additional	one-year	periods	subject	to	lender	consent.	Amounts	borrowed	under	the	2018	Senior	Credit	Facility	may,	at	the	election	of Devon,	bear	interest	at	various	fixed	rate	options	for	periods	of	up	to	twelve	months.	Such	rates	are	generally	less	than	the	prime	rate.	However,	Devon	may	elect	to borrow	at	the	prime	rate.	The	2018	Senior	Credit	Facility	currently	provides	for	an	annual	facility	fee	of	$6.1	million.	As	of	December	31,	2018,	Devon	had	$48	million in	outstanding	letters	of	credit	under	the	2018	Senior	Credit	Facility.	There	were	no	borrowings	under	the	Senior	Credit	Facility	as	of	December	31,	2018.

The	2018	Senior	Credit	Facility	contains	only	one	material	financial	covenant.	This	covenant	requires	Devon's	ratio	of	total	funded	debt	to	total	capitalization, as	defined	in	the	credit	agreement,	to	be	no	greater	than	65%.	The	credit	agreement	contains	definitions	of	total	funded	debt	and	total	capitalization	that	include adjustments	to	the	respective	amounts	reported	in	the	accompanying	consolidated	financial	statements.	For	example,	total	capitalization	is	adjusted	to	add	back	noncash financial	write-downs	such	as	asset	impairments.	As	of	December	31,	2018,	Devon	was	in	compliance	with	this	covenant	with	a	debt-to-capitalization	ratio	of	21.0%.

# Commercial	Paper

Devon's	2018	Senior	Credit	Facility	supports	its	$3.0	billion	of	short-term	credit	under	its	commercial	paper	program.	Commercial	paper	debt	generally	has	a maturity	of	between	1	and	90	days,	although	it	can	have	a	maturity	of	up	to	365	days,	and	bears	interest	at	rates	agreed	to	at	the	time	of	the	borrowing.	The	interest	rate	is generally	based	on	a	standard	index	such	as	the	Federal	Funds	Rate,	LIBOR	or	the	money	market	rate	as	found	in	the	commercial	paper	market.	As	of	December	31, 2018,	Devon	had	no	outstanding	commercial	paper	borrowings.

# Retirement	of	Senior	Notes

During	2018,	Devon	completed	tender	offers	to	repurchase	$807	million	in	aggregate	principal	amount	of	debt	using	cash	on	hand.	This	included	$384	million of	the	7.875%	senior	notes	due	September	30,	2031	and	$423	million	of	the	7.95%	senior	notes	due	April	15,	2032.	Devon	recognized	a	$312	million	loss	on	early retirement	of	debt,	consisting	of	$304	million	in	cash	retirement	costs	and	$8	million	of	noncash	charges.	These	costs,	along	with	other	charges	associated	with	retiring the	debt,	are	included	in	net	financing	costs	in	the	consolidated	comprehensive	statements	of	earnings.	In	December	2018,	Devon	repaid	the	$95	million	of	2.25%	senior notes	at	maturity.	Additionally,	in	January	2019,	Devon	repaid	the	$162	million	of	6.30%	senior	notes	at	maturity.

During	2016,	Devon	completed	tender	offers	to	repurchase	$2.1	billion	of	debt	securities,	using	proceeds	from	the	asset	divestitures	discussed	in	Note	2.	Devon recognized	a	loss	on	early	retirement	of	debt,	primarily	consisting	of	$265	million	in	cash	retirement	costs	and	other	fees.	These	costs,	along	with	other	minimal	noncash charges	associated	with	retiring	the	debt,	are	included	in	net	financing	costs	in	the	consolidated	comprehensive	statements	of	earnings.

The	following	schedule	includes	the	components	of	net	financing	costs.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Interest\tbased\ton\tdebt\toutstanding | $339 | $390 | $488 |
| Early\tretirement\tof\tdebt | 312 | — | 269 |
| Capitalized\tinterest | (41) | (69) | (61) |
| Other | (16) | (4) | 21 |
| Total\tnet\tfinancing\tcosts | $594 | $317 | $717 |

The	following	table	presents	the	changes	in	asset	retirement	obligations.

|  | Year	Ended	December	31, | Year	Ended	December	31, |
| :--- | :--- | :--- |
|  | 2018 | 2017 |
| Asset\tretirement\tobligations\tas\tof\tbeginning\tof\tperiod | $1,138 | $1,258 |
| Liabilities\tincurred | 39 | 40 |
| Liabilities\tsettled\tand\tdivested | (116) | (68) |
| Revision\tof\testimated\tobligation | (25) | (184) |
| Accretion\texpense\ton\tdiscounted\tobligation | 59 | 62 |
| Foreign\tcurrency\ttranslation\tadjustment | (38) | 30 |
| Asset\tretirement\tobligations\tas\tof\tend\tof\tperiod | 1,057 | 1,138 |
| Less\tcurrent\tportion | 27 | 39 |
| Asset\tretirement\tobligations,\tlong-term | $1,030 | $1,099 |

During	2018,	Devon	reduced	its	asset	retirement	obligation	by	$84	million,	primarily	as	a	result	of	Devon's	2018	divestitures.	For	additional	information,	see

During	2017,	Devon	reduced	its	asset	retirement	obligations	by	$184	million,	primarily	due	to	changes	in	the	assumed	inflation	rate	and	retirement	dates	for	its oil	and	gas	assets.

# 17. Retirement	Plans

# Defined	Contribution	Plans

Devon	sponsors	defined	contribution	plans	covering	its	employees	in	the	U.S.	and	Canada.	Such	plans	include	its	401(k)	plan,	enhanced	contribution	plan	and Canadian	pension	and	savings	plan.	Contributions	are	primarily	based	upon	percentages	of	annual	compensation	and	years	of	service.	In	addition,	each	plan	is	subject	to regulatory	limitations	by	each	respective	government.	Devon	contributed	$50	million,	$53	million	and	$57	million	to	these	plans	in	2018,	2017	and	2016,	respectively.

# Defined	Benefit	Plans

Devon	has	various	non-contributory	defined	benefit	pension	plans,	including	qualified	plans	and	nonqualified	plans	covering	eligible	U.S.	and	Canadian employees	and	former	employees	meeting	certain	age	and	service	requirements.	Benefits	under	the	defined	benefit	plans	have	been	closed	to	new	employees;	however, eligible	employees	continue	to	accrue	benefits	based	upon	years	of	service	and	compensation.	Benefits	are	primarily	funded	from	assets	held	in	the	plans'	trusts.

Devon's	investment	objective	for	its	plans'	assets	is	to	achieve	stability	of	the	funded	status	while	providing	long-term	growth	of	invested	capital	and	income	to ensure	benefit	payments	can	be	funded	when	required.	Devon	has	established	certain	investment	strategies,	including	target	allocation	percentages	and	permitted	and prohibited	investments,	designed	to	mitigate	risks	inherent	with	investing.	Devon's	target	allocations	for	its	plan	assets	are	70%	fixed	income,	20%	equity	and	10% other.	See	the	following	discussion	for	Devon's	pension	assets	by	asset	class.

Fixed-income	–	Devon's	fixed-income	securities	consist	of	U.S.	Treasury	obligations,	bonds	issued	by	investment-grade	companies	from	diverse	industries	and asset-backed	securities.	These	fixed-income	securities	are	actively	traded	securities	that	can	be	redeemed	upon	demand.	The	fair	values	of	these	Level	1	securities	are based	upon	quoted	market	prices	and	were	$193	million	and	$342	million	at	December	31,	2018	and	2017,	respectively.	Also,	included	are	commingled	funds	that primarily	invest	in	long-term	bonds	and	U.S.	Treasury	securities.	These	fixed	income	securities	can	be	redeemed	on	demand	but	are	not	actively	traded.	The	fair	values of	these	securities	are	based	upon	the	net	asset	values	provided	by	the	investment	managers	and	were	$301	million	and	$401	million	at	December	31,	2018	and	2017, respectively.

Equity	–	Devon's	equity	securities	include	commingled	global	equity	funds	that	invest	in	large,	mid	and	small	capitalization	stocks	across	the	world's developed	and	emerging	markets	and	international	large	cap	equity	securities.	These	equity	securities	can	be	sold	on	demand	but	are	not	actively	traded.	The	fair	values of	these	securities	are	based	upon	the	net	asset	values	provided	by	the	investment	managers	and	were	$84	million	and	$157	million	at	December	31,	2018	and	2017, respectively.

Other	–	Devon's	other	securities	include	short-term	investment	funds	and	a	hedge	fund	that	invest	both	long	and	short	using	a	variety	of	investment	strategies. The	fair	value	of	these	securities	is	based	upon	the	net	asset	values	provided	by	investment	managers	and	were	$132	million	and	$135	million	at	December	31,	2018	and 2017,	respectively.

# Defined	Postretirement	Plans

Devon	also	has	defined	benefit	postretirement	plans	that	provide	benefits	for	substantially	all	qualifying	U.S.	retirees.	Benefit	obligations	for	such	plans	are estimated	based	on	Devon's	future	cost-sharing	intentions.	Devon's	funding	policy	for	the	plans	is	to	fund	the	benefits	as	they	become	payable	with	available	cash	and cash	equivalents.

# Benefit	Obligations	and	Funded	Status

The	following	table	summarizes	the	benefit	obligations,	assets,	funded	status	and	balance	sheet	impacts	associated	with	its	defined	pension	and	postretirement plans.	Devon's	benefit	obligations	and	plan	assets	are	measured	each	year	as	of	December	31.	The	accumulated	benefit	obligation	for	pension	plans	approximated	the projected	benefit	obligation	at	December	31,	2018	and	2017.

|  | Pension	Benefits<br>2018 | 2017 | Postretirement	Benefits<br>2018 | 2017 |
| :--- | :--- | :--- | :--- | :--- |
| Change\tin\tbenefit\tobligation: |  |  |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $1,279 | $1,249 | $19 | $21 |
| Service\tcost | 10 | 15 | — | — |
| Interest\tcost | 39 | 42 | — | — |
| Actuarial\tloss\t(gain) | (83) | 59 | (3) | — |
| Plan\tamendments | — | — | — | — |
| Plan\tcurtailments | 2 | — | 2 | — |
| Plan\tsettlements | (241) | — | — | — |
| Foreign\texchange\trate\tchanges | (3) | 2 | — | — |
| Participant\tcontributions | — | — | 2 | 1 |
| Benefits\tpaid | (60) | (88) | (3) | (3) |
| Benefit\tobligation\tat\tend\tof\tyear | 943 | 1,279 | 17 | 19 |
| Change\tin\tplan\tassets: |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | 1,035 | 985 | — | — |
| Actual\treturn\ton\tplan\tassets | (36) | 122 | — | — |
| Employer\tcontributions | 14 | 14 | 1 | 2 |
| Participant\tcontributions | — | — | 2 | 1 |
| Plan\tsettlements | (241) | — | — | — |
| Benefits\tpaid | (60) | (88) | (3) | (3) |
| Foreign\texchange\trate\tchanges | (3) | 2 | — | — |
| Fair\tvalue\tof\tplan\tassets\tat\tend\tof\tyear | 709 | 1,035 | — | — |
| Funded\tstatus\tat\tend\tof\tyear | $(234) | $(244) | $(17) | $(19) |
| Amounts\trecognized\tin\tbalance\tsheet: |  |  |  |  |
| Other\tlong-term\tassets | $3 | $4 | $— | $— |
| Other\tcurrent\tliabilities | (14) | (13) | (3) | (3) |
| Other\tlong-term\tliabilities | (223) | (235) | (14) | (16) |
| Net\tamount | $(234) | $(244) | $(17) | $(19) |
| Amounts\trecognized\tin\taccumulated\tother |  |  |  |  |
| \t\t\tcomprehensive\tearnings: |  |  |  |  |
| Net\tactuarial\tloss\t(gain) | $202 | $257 | $(11) | $(11) |
| Prior\tservice\tcost\t(credit) | 4 | 6 | (2) | (3) |
| Total | $206 | $263 | $(13) | $(14) |

During	the	third	quarter	of	2018,	Devon	entered	into	a	group	annuity	contract,	under	which	a	third	party	has	permanently	assumed	certain	of	Devon's	defined benefit	pension	obligations.	The	purchase	of	this	group	annuity	contract	reduced	Devon's	pension	assets	and	liabilities	and	is	the	primary	component	of	the	$241	million of	plan	settlements	within	the	preceding	table.	In	connection	with	the	group	annuity	contract	transaction,	Devon	recorded	a	settlement	expense	of	approximately $33	million,	which	was	reclassified	from	other	comprehensive	earnings	to	other	expense	on	the	consolidated	comprehensive	statements	of	earnings	in	2018.

Certain	of	Devon's	pension	plans	have	a	combined	projected	benefit	obligation	or	accumulated	benefit	obligation	in	excess	of	plan	assets	at	December	31,	2018 and	December	31,	2017,	as	presented	in	the	table	below.

|  | December	31, |  |
| :--- | :--- | :--- |
|  | 2018 | 2017 |
| Projected\tbenefit\tobligation | $922 | $1,255 |
| Accumulated\tbenefit\tobligation | $906 | $1,226 |
| Fair\tvalue\tof\tplan\tassets | $685 | $1,007 |

The	following	table	presents	the	components	of	net	periodic	benefit	cost	and	other	comprehensive	earnings.

|  | 2018 | Pension	Benefits<br>2017 | 2016 | 2018 | Postretirement	Benefits<br>2017 | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Net\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Service\tcost | $10 | $15 | $15 | $— | $— | $— |
| Interest\tcost | 39 | 42 | 42 | — | — | 1 |
| Expected\treturn\ton\tplan\tassets | (49) | (54) | (55) | — | — | — |
| Recognition\tof\tnet\tactuarial\tloss\t(gain)\t(1) | 13 | 19 | 25 | (1) | (1) | (1) |
| Recognition\tof\tprior\tservice\tcost\t(1) | 1 | 2 | 3 | (1) | (1) | (1) |
| Total\tnet\tperiodic\tbenefit\tcost\t(2) | 14 | 24 | 30 | (2) | (2) | (1) |
| Other\tcomprehensive\tloss\t(earnings): |  |  |  |  |  |  |
| Actuarial\tloss\t(gain)\tarising\tin\tcurrent\tyear | 4 | (9) | 26 | (1) | (1) | — |
| Prior\tservice\tcost\tarising\tin\tcurrent\tyear | — | — | 2 | — | — | — |
| Recognition\tof\tnet\tactuarial\tgain\t(loss),\tincluding |  |  |  |  |  |  |
| \t\t\tsettlement\texpense,\tin\tnet\tperiodic\tbenefit\tcost\t(3) | (60) | (19) | (43) | 1 | 1 | 1 |
| Recognition\tof\tprior\tservice\tcost,\tincluding |  |  |  |  |  |  |
| \t\t\tcurtailment,\tin\tnet\tperiodic\tbenefit\tcost\t(3) | (2) | (2) | (9) | 1 | 1 | 1 |
| Total\tother\tcomprehensive\tloss\t(earnings) | (58) | (30) | (24) | 1 | 1 | 2 |
| Total\trecognized | $(44) | $(6) | $6 | $(1) | $(1) | $1 |

(1) These	net	periodic	benefit	costs	were	reclassified	out	of	other	comprehensive	earnings	in	the	current	period.

(2) The	service	cost	component	of	net	periodic	benefit	cost	is	included	in	G&A	expense	and	the	remaining	components	of	net	periodic	benefit	costs	are	included	in other	expenses	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

(3) These	amounts	include	restructuring	costs	that	were	reclassified	out	of	other	comprehensive	earnings	in	2018	and	2016.	See	Note	6	for	further	discussion.

|  | 2018 | Pension	Benefits<br>2017 | 2016 | 2018 | Postretirement	Benefits<br>2017 | 2016 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Assumptions\tto\tdetermine\tbenefit\tobligations: |  |  |  |  |  |  |
| Discount\trate | 4.21% | 3.59% | 4.07% | 4.01% | 3.25% | 3.46% |
| Rate\tof\tcompensation\tincrease | 2.50% | 2.50% | 4.49% | N/A | N/A | N/A |
| Assumptions\tto\tdetermine\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Discount\trate\t-\tservice\tcost | 3.98% | 4.29% | 4.39% | 4.13% | 4.22% | 3.63% |
| Discount\trate\t-\tinterest\tcost | 3.22% | 2.99% | 4.39% | 2.67% | 2.39% | 3.63% |
| Rate\tof\tcompensation\tincrease | 2.50% | 4.48% | 4.49% | N/A | N/A | N/A |
| Expected\treturn\ton\tplan\tassets | 5.67% | 5.69% | 5.20% | N/A | N/A | N/A |

Discount	Rate	-	Future	pension	and	post-retirement	obligations	are	discounted	based	on	the	rate	at	which	obligations	could	be	effectively	settled,	considering the	timing	of	expected	future	cash	flows	related	to	the	plans.	This	rate	is	based	on	high-quality	bond	yields,	after	allowing	for	call	and	default	risk.

Expected	return	on	plan	assets	–	This	was	determined	by	evaluating	input	from	external	consultants	and	economists,	as	well	as	long-term	inflation	assumptions and	consideration	of	target	allocation	of	investment	types.

Mortality	rate	–	Devon	utilized	the	Society	of	Actuaries	produced	mortality	tables	and	an	improvement	scale	derived	from	the	updated	tables	for	2017	and	2018 and	the	actuary's	best	estimate	of	mortality	for	2016	for	the	population	of	participants	in	Devon's	plans.

Other	assumptions	–	For	measurement	of	the	2018	benefit	obligation	for	the	other	postretirement	medical	plans,	a	7.1%	annual	rate	of	increase	in	the	per	capita cost	of	covered	health	care	benefits	was	assumed	for	2019.	The	rate	was	assumed	to	decrease	annually	to	an	ultimate	rate	of	5%	in	the	year	2029	and	remain	at	that	level thereafter.

# Expected	Cash	Flows

Devon	expects	benefit	plan	payments	to	average	approximately	$59	million	a	year	for	the	next	five	years	and	$153	million	total	for	the	five	years	thereafter.	Of these	payments	to	be	paid	in	2019,	$17	million	is	expected	to	be	funded	from	Devon's	available	cash,	cash	equivalents	and	other	assets.

# 18. Stockholders'	Equity

The	authorized	capital	stock	of	Devon	consists	of	1.0	billion	shares	of	common	stock,	par	value	$0.10	per	share,	and	4.5	million	shares	of	preferred	stock,	par value	$1.00	per	share.	The	preferred	stock	may	be	issued	in	one	or	more	series,	and	the	terms	and	rights	of	such	stock	will	be	determined	by	the	Board	of	Directors.

# Common	Stock	Issued

In	January	2016,	Devon	issued	approximately	23	million	shares	of	common	stock	in	conjunction	with	the	STACK	asset	acquisition	discussed	in	Note	2. Additionally,	in	February	2016,	Devon	issued	79	million	shares	of	common	stock	to	the	public,	inclusive	of	10	million	shares	sold	as	part	of	the	underwriters'	option. Net	proceeds	from	the	offering	were	$1.5	billion.

In	March	2018,	Devon	announced	a	share	repurchase	program	to	buy	up	to	$1.0	billion	of	shares	of	common	stock.	In	June	2018,	in	conjunction	with	the announced	divestiture	of	its	investment	in	EnLink	and	the	General	Partner,	Devon	increased	its	program	by	an	additional	$3.0	billion.	In	February	2019,	Devon's	Board of	Directors	authorized	an	expansion	of	the	share	repurchase	program	by	an	additional	$1.0	billion,	bringing	the	total	to	$5.0	billion.	The	share	repurchase	program expires	December	31,	2019.

During	the	third	quarter	of	2018,	Devon	entered	into	and	completed	an	ASR	transaction	to	repurchase	$1.0	billion	of	the	$4.0	billion	program.	The	table	below provides	information	regarding	purchases	of	Devon's	common	stock	that	were	made	during	2018	(shares	in	thousands).

|  | Total	Number	of<br>Shares	Purchased | Dollar	Value	of<br>Shares	Purchased | Average	Price	Paid<br>per	Share |
| :--- | :--- | :--- | :--- |
| First\tquarter\t2018: |  |  |  |
| Open-Market | 2,561 | $82 | $32.19 |
| Second\tquarter\t2018: |  |  |  |
| Open-Market | 11,154 | 439 | 39.35 |
| Third\tquarter\t2018: |  |  |  |
| Open-Market | 16,492 | 712 | 43.13 |
| ASR | 24,330 | 1,000 | 41.10 |
| Total | 40,822 | 1,712 | 41.92 |
| Fourth\tquarter\t2018: |  |  |  |
| Open-Market | 23,612 | 745 | 31.57 |
| Total\tyear-to-date | 78,149 | \t$2,978 | \t$38.11 |

# Dividends

The	table	below	summarizes	the	dividends	Devon	paid	on	its	common	stock.

|  | Amounts | Rate	Per	Share |
| :--- | :--- | :--- |
| Year\tEnded\t2018: |  |  |
| First\tquarter | $32 | $0.06 |
| Second\tquarter | 42 | $0.08 |
| Third\tquarter | 38 | $0.08 |
| Fourth\tquarter | 37 | $0.08 |
| Total\tyear-to-date | $149 |  |
| Year\tEnded\t2017: |  |  |
| First\tquarter | $32 | $0.06 |
| Second\tquarter | 33 | $0.06 |
| Third\tquarter | 30 | $0.06 |
| Fourth\tquarter | 32 | $0.06 |
| Total\tyear-to-date | $127 |  |
| Year\tEnded\t2016: |  |  |
| First\tquarter | $125 | $0.24 |
| Second\tquarter | 33 | $0.06 |
| Third\tquarter | 32 | $0.06 |
| Fourth\tquarter | 31 | $0.06 |
| Total\tyear-to-date | $221 |  |

In	response	to	the	depressed	commodity	price	environment,	Devon	reduced	the	quarterly	dividend	rate	from	$0.24	to	$0.06	per	share	in	the	second	quarter	of 2016.	Devon	increased	the	quarterly	dividend	by	33%	to	$0.08	per	share	in	the	second	quarter	of	2018.	In	February	2019,	Devon	announced	a	12.5%	increase	to	its quarterly	dividend,	to	$0.09	per	share,	beginning	in	the	second	quarter	of	2019.

# 19. Discontinued	Operations	and	Assets	Held	For	Sale

On	June	6,	2018,	Devon	announced	that	it	had	entered	into	an	agreement	to	sell	its	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	for	$3.125 billion.	Upon	entering	into	the	agreement	to	sell	its	ownership	interest	in	June	2018,	Devon	concluded	that	the	transaction	was	a	strategic	shift	and	met	the	requirements of	assets	held	for	sale	and	discontinued	operations.	As	part	of	its	assessment,	Devon	considered	the	following:	1)	Devon	is	exiting	its	entire	midstream	business ownership;	2)	EnLink	and	the	General	Partner	are	a	separate	reportable	segment	and	are	a	component	of	Devon's	business;	and	3)	the	transaction	resulted	in	a	material reduction	in	total	assets,	debt,	revenues,	net	earnings	and	operating	cash	flows.	As	a	result,	Devon	classified	the	results	of	operations	and	cash	flows	related	to	EnLink and	the	General	Partner	as	discontinued	operations	on	its	consolidated	financial	statements.	Additionally,	Devon	ceased	depreciation	and	amortization	for	all	plant, property	and	equipment	and	intangible	assets	classified	as	assets	held	for	sale	on	the	date	the	sales	agreement	was	signed.

On	July	18,	2018,	Devon	completed	the	sale	of	its	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	for	$3.125		billion	and	recognized	a	gain	of approximately	$2.6		billion	($2.2		billion	after-tax).	Current	(cash)	income	tax	associated	with	the	transaction	was	approximately	$12	million.	The	vast	majority	of	the	tax effect	relates	to	deferred	tax	expense	offset	by	the	valuation	allowance	adjustment	explained	in	Note	8.

As	part	of	the	sale	agreement,	Devon	extended	its	fixed-fee	gathering	and	processing	contracts	with	respect	to	the	Bridgeport	and	Cana	plants	with	EnLink through	2029.	Although	the	agreements	were	extended	to	2029,	the	minimum	volume	commitments	for	the	Bridgeport	and	Cana	plants	expired	at	the	end	of	2018. Devon	has	minimum	volume	commitments	for	gathering	and	processing	of	77-128	MMcf/d	with	EnLink	at	the	Chisholm	plant	through	early	2021.

From	the	period	of	July	19,	2018	through	December	31,	2018,	Devon	had	net	outflows	of	approximately	$380	million	with	EnLink,	which	primarily	related	to gathering	and	processing	expenses.	These	net	outflows	represent	gross	cash	amounts	and	not	net	working	interest	amounts.

Prior	to	the	divestment	of	Devon's	aggregate	ownership	of	EnLink	and	the	General	Partner,	certain	activity	between	Devon	and	EnLink	were	eliminated	in consolidation.	Subsequent	to	the	divestment,	all	activity	related	to	EnLink	represent	third-party	transactions	and	are	no	longer	eliminated	in	consolidation.

The	following	table	presents	the	amounts	reported	in	the	consolidated	comprehensive	statements	of	earnings	as	discontinued	operations.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Marketing\tand\tmidstream\trevenues | $3,567 | $5,071 | $3,551 |
| Marketing\tand\tmidstream\texpenses | 2,912 | 4,111 | 2,712 |
| Depreciation,\tdepletion\tand\tamortization | 244 | 545 | 504 |
| General\tand\tadministrative\texpenses | 65 | 128 | 118 |
| Financing\tcosts,\tnet | 98 | 181 | 190 |
| Asset\timpairments | — | 17 | 873 |
| Asset\tdispositions | (2,607) | — | 13 |
| Other\texpenses | (8) | (34) | 25 |
| Total\texpenses | 704 | 4,948 | 4,435 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations\tbefore\tincome\ttaxes | 2,863 | 123 | (884) |
| Income\ttax\texpense\t(benefit) | 403 | (197) | — |
| Net\tearnings\t(loss)\tfrom\tdiscontinued\toperations,\tnet\tof |  |  |  |
| \t\t\tincome\ttax\texpense | 2,460 | 320 | (884) |
| Net\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | 160 | 180 | (403) |
| Net\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tattributable\tto\tDevon | $2,300 | $140 | $(481) |

The	following	table	presents	the	carrying	amounts	of	the	assets	and	liabilities	classified	as	held	for	sale	on	the	consolidated	balance	sheets.	The	assets	and liabilities	classified	as	held	for	sale	at	December	31,	2018	are	related	to	the	divestiture	of	non-core	upstream	Permian	Basin	assets	which	closed	in	January	2019	as further	discussed	in	Note	2.	The	assets	and	liabilities	classified	as	held	for	sale	at	December	31,	2017	are	related	to	the	divestiture	of	EnLink	and	the	General	Partner.

|  | December	31,	2018 | December	31,	2017 |
| :--- | :--- | :--- |
| Cash\tand\tcash\tequivalents | \t$— | $31 |
| Accounts\treceivable | 7 | 681 |
| Other\tcurrent\tassets | — | 48 |
| Oil\tand\tgas\tproperty\tand\tequipment,\tbased\ton |  |  |
| \t\t\tsuccessful\tefforts\taccounting,\tnet | 190 | — |
| Midstream\tand\tother\tproperty\tand\tequipment,\tnet | — | 6,587 |
| Goodwill | — | 1,542 |
| Other\tlong-term\tassets | — | 1,600 |
| Total\tassets\theld\tfor\tsale | \t$197 | $10,489 |
| Accounts\tpayable | \t$3 | $186 |
| Revenues\tand\troyalties\tpayable | — | 432 |
| Other\tcurrent\tliabilities | 19 | 373 |
| Long-term\tdebt | — | 3,542 |
| Deferred\tincome\ttaxes | — | 346 |
| Asset\tretirement\tobligations | 47 | 14 |
| Other\tlong-term\tliabilities | — | 34 |
| Total\tliabilities\theld\tfor\tsale | \t$69 | $4,927 |

# 20. Commitments	and	Contingencies

Devon	is	party	to	various	legal	actions	arising	in	the	normal	course	of	business.	Matters	that	are	probable	of	unfavorable	outcome	to	Devon	and	which	can	be reasonably	estimated	are	accrued.	Such	accruals	are	based	on	information	known	about	the	matters,	Devon's	estimates	of	the	outcomes	of	such	matters	and	its experience	in	contesting,	litigating	and	settling	similar	matters.	None	of	the	actions	are	believed	by	management	to	likely	involve	future	amounts	that	would	be	material to	Devon's	financial	position	or	results	of	operations	after	consideration	of	recorded	accruals.	Actual	amounts	could	differ	materially	from	management's	estimates.

# Royalty	Matters

Numerous	oil	and	natural	gas	producers	and	related	parties,	including	Devon,	have	been	named	in	various	lawsuits	alleging	royalty	underpayments.	Devon	is currently	named	as	a	defendant	in	a	number	of	such	lawsuits,	including	some	lawsuits	in	which	the	plaintiffs	seek	to	certify	classes	of	similarly	situated	plaintiffs.	Among the	allegations	typically	asserted	in	these	suits	are	claims	that	Devon	used	below-market	prices,	made	improper	deductions,	used	improper	measurement	techniques	and entered	into	gas	purchase	and	processing	arrangements	with	affiliates	that	resulted	in	underpayment	of	royalties	in	connection	with	oil,	natural	gas	and	NGLs	produced and	sold.	Devon	is	also	involved	in	governmental	agency	proceedings	and	royalty	audits	and	is	subject	to	related	contracts	and	regulatory	controls	in	the	ordinary	course of	business,	some	that	may	lead	to	additional	royalty	claims.	Devon	does	not	currently	believe	that	it	is	subject	to	material	exposure	with	respect	to	such	royalty	matters.

# Environmental	Matters

Devon	is	subject	to	certain	laws	and	regulations	relating	to	environmental	remediation	activities	associated	with	past	operations,	such	as	the	Comprehensive Environmental	Response,	Compensation,	and	Liability	Act	and	similar	state	statutes.	In	response	to	liabilities	associated	with	these	activities,	loss	accruals	primarily consist	of	estimated	uninsured	remediation	costs.	Devon's	monetary	exposure	for	environmental	matters	is	not	expected	to	be	material.

Beginning	in	2013,	various	parishes	in	Louisiana	filed	suit	against	more	than	100	oil	and	gas	companies,	including	Devon,	alleging	that	the	companies' operations	and	activities	in	certain	fields	violated	the	State	and	Local	Coastal	Resource	Management	Act	of	1978,	as	amended,	and	caused	substantial	environmental contamination,	subsidence	and	other	environmental	damages	to	land	and	water	bodies	located	in	the	coastal	zone	of	Louisiana.	The	plaintiffs	seek,	among	other	things, the	payment	of	the	costs	necessary	to	clear,	re-vegetate	and	otherwise	restore	the	allegedly	impacted	areas.	Although	we	cannot	predict	the	ultimate	outcome	of	these matters,	Devon	is	vigorously	defending	against	these	claims.

# Other	Matters

Devon	is	involved	in	other	various	legal	proceedings	incidental	to	its	business.	However,	to	Devon's	knowledge,	there	were	no	material	pending	legal proceedings	to	which	Devon	is	a	party	or	to	which	any	of	its	property	is	subject.

# Commitments

The	following	table	presents	Devon's	commitments	that	have	initial	or	remaining	noncancelable	terms	in	excess	of	one	year	as	of	December	31,	2018.

| Year	Ending	December	31, | Purchase	Obligations | Drilling	and	Facility<br>Obligations | Operational	Agreements | Office	and	Equipment<br>Leases |
| :--- | :--- | :--- | :--- | :--- |
| 2019 | $541 | $274 | $587 | $64 |
| 2020 | 567 | 85 | 519 | 43 |
| 2021 | 140 | 48 | 373 | 31 |
| 2022 | — | 14 | 419 | 26 |
| 2023 | — | 8 | 354 | 25 |
| Thereafter | — | 16 | 3,374 | 311 |
| Total | $1,248 | $445 | $5,626 | $500 |

Purchase	obligation	amounts	represent	contractual	commitments	primarily	to	purchase	condensate	at	market	prices	for	use	at	Devon's	heavy	oil	projects	in Canada.	Devon	has	entered	into	these	agreements	because	condensate	is	an	integral	part	of	the	heavy	oil	transportation	process.	Any	disruption	in	Devon's	ability	to obtain	condensate	could	negatively	affect	its	ability	to	transport	heavy	oil	at	these	locations.	Devon's	total	obligation	related	to	condensate	purchases	expires	in	2021. The	value	of	the	obligation	in	the	table	above	is	based	on	the	contractual	volumes	and	Devon's	internal	estimate	of	future	condensate	market	prices.

Devon	has	certain	drilling	and	facility	obligations	under	contractual	agreements	with	third-party	service	providers	to	procure	drilling	rigs	and	other	related services	for	developmental	and	exploratory	drilling	and	facilities	construction.	The	value	of	the	drilling	obligations	reported	is	based	on	gross	contractual	value.

Devon	has	certain	operational	agreements	whereby	Devon	has	committed	to	transport	or	process	certain	volumes	of	oil,	gas	and	NGLs	for	a	fixed	fee.	Devon has	entered	into	these	agreements	to	aid	the	movement	of	its	production	to	downstream	markets.

Devon	leases	certain	office	space	and	equipment	under	operating	lease	arrangements.	Total	rental	expense	recognized	for	operating	leases,	net	of	sublease income,	was	$11	million,	$7	million	and	$11	million	in	2018,	2017	and	2016,	respectively.

The	following	table	provides	carrying	value	and	fair	value	measurement	information	for	certain	of	Devon's	financial	assets	and	liabilities.	None	of	the	items below	are	measured	using	Level	3	inputs.	The	carrying	values	of	cash,	accounts	receivable,	other	current	receivables,	accounts	payable,	other	current	payables	and accrued	expenses	included	in	the	accompanying	consolidated	balance	sheets	approximated	fair	value	at	December	31,	2018	and	December	31,	2017,	as	applicable. Therefore,	such	financial	assets	and	liabilities	are	not	presented	in	the	following	table.	Additionally,	the	fair	values	of	oil	and	gas	assets	and	related	impairments	are measured	as	of	the	impairment	date	using	Level	3	inputs.	Additional	information	on	asset	impairments	and	the	pension	plan	assets	is	provided	in	Note	5,	and	Note	17, respectively.

|  | Carrying<br>Amount | Total	Fair<br>Value | Fair	Value	Measurements	Using:<br>Level	1<br>Inputs | Level	2<br>Inputs |
| :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2018\tassets\t(liabilities): |  |  |  |  |
| Cash\tequivalents | $1,505 | \t$1,505 | \t$1,405 | \t$100 |
| Commodity\tderivatives | $677 | \t$677 | \t$— | \t$677 |
| Commodity\tderivatives | $(68) | \t$(68) | \t$— | \t$(68) |
| Debt | $(5,947) | \t$(5,965) | \t$— | \t$(5,965) |
| December\t31,\t2017\tassets\t(liabilities): |  |  |  |  |
| Cash\tequivalents | $1,533 | \t$1,533 | \t$1,454 | \t$79 |
| Commodity\tderivatives | $205 | \t$205 | \t$— | \t$205 |
| Commodity\tderivatives | $(286) | \t$(286) | \t$— | \t$(286) |
| Interest\trate\tderivatives | $1 | \t$1 | \t$— | \t$1 |
| Interest\trate\tderivatives | $(64) | \t$(64) | \t$— | \t$(64) |
| Debt | $(6,864) | $(8,131) | $— | $(8,131) |

The	following	methods	and	assumptions	were	used	to	estimate	the	fair	values	in	the	tables	above.

# Level	1	Fair	Value	Measurements

Cash	equivalents	–	Amounts	consist	primarily	of	money	market	investments	and	the	fair	value	approximates	the	carrying	value.

Cash	equivalents	–	Amounts	consist	primarily	of	commercial	paper	and	Canadian	agency	and	provincial	securities	investments.	The	fair	value	approximates	the carrying	value.

Commodity	and	interest	rate	derivatives–	The	fair	values	of	commodity	and	interest	rate	derivatives	are	estimated	using	internal	discounted	cash	flow calculations	based	upon	forward	curves	and	data	obtained	from	independent	third	parties	for	contracts	with	similar	terms	or	data	obtained	from	counterparties	to	the agreements.

Debt	–	Devon's	debt	instruments	do	not	actively	trade	in	an	established	market.	The	fair	values	of	its	debt	are	estimated	based	on	rates	available	for	debt	with similar	terms	and	maturity.

# 22. Segment	Information

Devon	manages	its	operations	through	distinct	operating	segments,	which	are	defined	primarily	by	geographic	areas.	For	financial	reporting	purposes,	Devon aggregates	its	U.S.	operating	segments	into	one	reporting	segment	due	to	the	similar	nature	of	the	businesses.	However,	Devon's	Canadian	exploration	and	production operating	segment	is	reported	as	a	separate	reporting	segment	primarily	due	to	the	significant	differences	between	the	U.S.	and	Canadian	regulatory	environments. Devon's	U.S.	and	Canadian	segments	are	both	primarily	engaged	in	oil	and	gas	exploration	and	production	activities,	and	certain	information	regarding	such	activities for	each	segment	is	included	in	Note	23.

Devon	considers	EnLink,	combined	with	the	General	Partner,	to	be	a	segment	that	is	distinct	from	the	U.S.	and	Canadian	operating	segments.	EnLink's operations	consist	of	midstream	assets	and	operations	located	in	the	U.S.	Additionally,	EnLink	has	a	management	team	that	is	primarily	responsible	for	capital	and resource	allocation	decisions.	However,	with	Devon's	closing	of	the	divestment	of	EnLink	and	the	General	Partner	in	July	2018,	activity	related	to	EnLink	and	the General	Partner	have	now	been	classified	as	discontinued	operations	within	Devon's	consolidated	comprehensive	statements	of	earnings	and	consolidated	statements	of cash	flows,	and	the	associated	assets	and	liabilities	of	EnLink	and	the	General	Partner	are	presented	as	assets	and	liabilities	held	for	sale	on	the	consolidated	balance sheets.	Additional	information	can	be	found	in	Note	19.

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2018: |  |  |  |
| Revenues\tfrom\texternal\tcustomers\t(1) | $9,674 | $1,060 | $10,734 |
| Depreciation,\tdepletion\tand\tamortization | $1,328 | $330 | $1,658 |
| Interest\texpense | $469 | $166 | $635 |
| Asset\timpairments | $156 | $— | $156 |
| Asset\tdispositions | $(263) | $— | $(263) |
| Restructuring\tand\ttransaction\tcosts | $97 | $17 | $114 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $1,294 | $(374) | $920 |
| Income\ttax\texpense\t(benefit) | $294 | $(138) | $156 |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations | $1,000 | $(236) | $764 |
| Property\tand\tequipment,\tnet | $10,026 | $3,909 | $13,935 |
| Total\tassets\t(2) | $14,853 | $4,516 | $19,369 |
| Capital\texpenditures,\tincluding\tacquisitions | $2,294 | $282 | $2,576 |
| Year\tEnded\tDecember\t31,\t2017: |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $7,326 | $1,552 | $8,878 |
| Depreciation,\tdepletion\tand\tamortization | $1,149 | $380 | $1,529 |
| Interest\texpense | $324 | $12 | $336 |
| Asset\tdispositions | $(218) | $1 | $(217) |
| Earnings\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $443 | $330 | $773 |
| Income\ttax\texpense | $9 | $6 | $15 |
| Net\tearnings\tfrom\tcontinuing\toperations | $434 | $324 | $758 |
| Property\tand\tequipment,\tnet | $10,274 | $4,310 | $14,584 |
| Total\tassets\t(3) | $14,254 | $5,498 | $19,752 |
| Capital\texpenditures,\tincluding\tacquisitions | $1,821 | $348 | $2,169 |
| Year\tEnded\tDecember\t31,\t2016: |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $5,722 | $1,031 | $6,753 |
| Depreciation,\tdepletion\tand\tamortization | $1,178 | $414 | $1,592 |
| Interest\texpense | $624 | $100 | $724 |
| Asset\timpairments | $435 | $2 | $437 |
| Asset\tdispositions | $(955) | $(541) | $(1,496) |
| Restructuring\tand\ttransaction\tcosts | $242 | $19 | $261 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $(757) | $324 | $(433) |
| Income\ttax\texpense\t(benefit) | $(8) | $149 | $141 |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations | $(749) | $175 | $(574) |
| Property\tand\tequipment,\tnet | $10,166 | $4,110 | $14,276 |
| Total\tassets\t(3) | $13,390 | $5,071 | $18,461 |
| Capital\texpenditures,\tincluding\tacquisitions | $2,640 | $186 | $2,826 |

(1)	Revenues	from	oil,	gas	and	NGL	sales	and	marketing	revenues	represent	revenue	from	contracts	with	customers.

(2)	Total	assets	in	the	table	above	do	not	include	assets	held	for	sale	related	to	Devon's	non-core	assets	in	the	Permian	Basin	closed	in	January	2019,	which	totaled	$197 million.

(3)	Total	assets	in	the	table	above	do	not	include	assets	held	for	sale	related	to	Devon's	discontinued	operations,	which	totaled	$10.5	billion	and	$10.2	billion	in	2017 and	2016,	respectively.

The	following	table	presents	revenue	from	contracts	with	customers	that	are	disaggregated	based	on	the	type	of	good.

|  |  | Year	Ended	December	31,	2018 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Oil | $2,957 | $814 | $3,771 |
| Gas | 950 | — | 950 |
| NGL | 956 | — | 956 |
| Oil,\tgas\tand\tNGL\trevenues\tfrom |  |  |  |
| \t\t\tcontracts\twith\tcustomers | 4,863 | 814 | 5,677 |
| Oil,\tgas\tand\tNGL\tderivatives | 457 | 151 | 608 |
| Upstream\trevenues | 5,320 | 965 | 6,285 |
| Oil | 2,745 | 95 | 2,840 |
| Gas | 738 | — | 738 |
| NGL | 871 | — | 871 |
| Total\tmarketing\trevenues\tfrom |  |  |  |
| \t\t\tcontracts\twith\tcustomers | 4,354 | 95 | 4,449 |
| Total\trevenues | $9,674 | $1,060 | $10,734 |

# 23. Supplemental	Information	on	Oil	and	Gas	Operations	(Unaudited)

Supplemental	unaudited	information	regarding	Devon's	oil	and	gas	activities	is	presented	in	this	note.	The	information	is	provided	separately	by	country.

# Costs	Incurred

The	following	tables	reflect	the	costs	incurred	in	oil	and	gas	property	acquisition,	exploration	and	development	activities.

Development	costs	in	the	tables	above	include	additions	and	revisions	to	Devon's	asset	retirement	obligations.	Additionally,	Devon	capitalizes	interest	costs incurred	and	attributable	to	unproved	oil	and	gas	properties	and	major	development	projects	of	oil	and	gas	properties.	Capitalized	interest	expenses,	which	are	included	in the	costs	shown	in	the	preceding	tables,	were	$41	million,	$69	million	and	$61	million	in	2018,	2017	and	2016,	respectively.

# Results	of	Operations

The	following	tables	include	revenues	and	expenses	associated	with	Devon's	oil	and	gas	producing	activities.	They	do	not	include	any	allocation	of	Devon's interest	costs	or	general	corporate	overhead	and,	therefore,	are	not	necessarily	indicative	of	the	contribution	to	net	earnings	of	Devon's	oil	and	gas	operations.	Income	tax expense	has	been	calculated	by	applying	statutory	income	tax	rates	to	oil,	gas	and	NGL	sales	after	deducting	costs,	including	DD&A	and	after	giving	effect	to	permanent differences.

|  |  | Year	Ended	December	31,	2018 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Oil,\tgas\tand\tNGL\tsales | $4,863 | \t$814 | \t$5,677 |
| Production\texpenses | (1,620) | (605) | (2,225) |
| Exploration\texpenses | (129) | (48) | (177) |
| Depreciation,\tdepletion\tand\tamortization | (1,234) | (325) | (1,559) |
| Asset\tdispositions | 262 | — | 262 |
| Asset\timpairments | (109) | — | (109) |
| Accretion\tof\tasset\tretirement\tobligations | (35) | (24) | (59) |
| Income\ttax\t(expense)\tbenefit | (460) | 51 | (409) |
| Results\tof\toperations | $1,538 | $(137) | $1,401 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $8.08 | $7.63 | $7.98 |

|  |  | Year	Ended	December	31,	2017 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Oil,\tgas\tand\tNGL\tsales | $3,746 | \t$1,404 | \t$5,150 |
| Production\texpenses | (1,232) | (591) | (1,823) |
| Exploration\texpenses | (346) | (34) | (380) |
| Depreciation,\tdepletion\tand\tamortization | (1,050) | (369) | (1,419) |
| Asset\tdispositions | 211 | 1 | 212 |
| Accretion\tof\tasset\tretirement\tobligations | (38) | (24) | (62) |
| Income\ttax\texpense | — | (104) | (104) |
| Results\tof\toperations | $1,291 | $283 | $1,574 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $6.97 | $7.73 | $7.15 |

|  |  | Year	Ended	December	31,	2016 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Oil,\tgas\tand\tNGL\tsales | $3,198 | \t$984 | \t$4,182 |
| Production\texpenses | (1,313) | (492) | (1,805) |
| Exploration\texpenses | (176) | (39) | (215) |
| Depreciation,\tdepletion\tand\tamortization | (1,066) | (380) | (1,446) |
| Asset\tdispositions | 946 | 1 | 947 |
| Asset\timpairments | (435) | — | (435) |
| Accretion\tof\tasset\tretirement\tobligations | (49) | (26) | (75) |
| Income\ttax\texpense | — | (13) | (13) |
| Results\tof\toperations | $1,105 | $35 | $1,140 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $6.11 | $7.75 | $6.47 |

The	following	table	presents	Devon's	estimated	proved	reserves	by	product	and	by	country.

|  |  |  |  | Bitumen |  |  |  | NGL |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Oil\t(MMBbls)\nCanada | Total | (MMBbls)\nCanada | U.S. | Gas\t(Bcf)\nCanada | Total | (MMBbls)\nU.S. | U.S. | Combined\t(MMBoe)\t(1)\nCanada | Total |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |  |  |  |  |
| December\t31,\t2015 | 242 | 22 | 264 | 520 | 5,808 | 13 | 5,821 | 428 | 1,638 | 544 | 2,182 |
| Revisions\tdue\tto\tprices | (18) | (2) | (20) | 23 | (103) | — | (103) | (13) | (48) | 21 | (27) |
| Revisions\tother\tthan\tprice | (2) | 3 | 1 | (19) | 628 | 10 | 638 | 48 | 151 | (14) | 137 |
| Extensions\tand\tdiscoveries | 36 | 2 | 38 | — | 280 | — | 280 | 42 | 124 | 2 | 126 |
| Purchase\tof\treserves | 8 | — | 8 | — | 33 | — | 33 | 7 | 20 | — | 20 |
| Production | (47) | (8) | (55) | (40) | (510) | (7) | (517) | (42) | (174) | (49) | (223) |
| Sale\tof\treserves | (25) | — | (25) | — | (521) | — | (521) | (45) | (157) | — | (157) |
| December\t31,\t2016 | 194 | 17 | 211 | 484 | 5,615 | 16 | 5,631 | 425 | 1,554 | 504 | 2,058 |
| Revisions\tdue\tto\tprices | 12 | (1) | 11 | (37) | 398 | 1 | 399 | 32 | 111 | (38) | 73 |
| Revisions\tother\tthan\tprice | 6 | 2 | 8 | (10) | — | 2 | 2 | (10) | (5) | (7) | (12) |
| Extensions\tand\tdiscoveries | 90 | 4 | 94 | 12 | 403 | — | 403 | 63 | 221 | 16 | 237 |
| Production | (42) | (7) | (49) | (40) | (433) | (6) | (439) | (36) | (150) | (48) | (198) |
| Sale\tof\treserves | (3) | — | (3) | — | (9) | — | (9) | (1) | (6) | — | (6) |
| December\t31,\t2017 | 257 | 15 | 272 | 409 | 5,974 | 13 | 5,987 | 473 | 1,725 | 427 | 2,152 |
| Revisions\tdue\tto\tprices | 12 | 1 | 13 | 10 | 94 | (3) | 91 | 12 | 40 | 11 | 51 |
| Revisions\tother\tthan\tprice | (10) | 2 | (8) | 2 | (163) | (4) | (167) | (23) | (60) | 3 | (57) |
| Extensions\tand\tdiscoveries | 93 | 5 | 98 | 7 | 446 | — | 446 | 64 | 232 | 11 | 243 |
| Production | (47) | (7) | (54) | (35) | (397) | (4) | (401) | (39) | (153) | (42) | (195) |
| Sale\tof\treserves | (7) | — | (7) | — | (1,195) | — | (1,195) | (61) | (267) | — | (267) |
| December\t31,\t2018 | 298 | 16 | 314 | 393 | 4,759 | 2 | 4,761 | 426 | 1,517 | 410 | 1,927 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |  |  |  |  |
| December\t31,\t2015 | 203 | 22 | 225 | 219 | 5,694 | 13 | 5,707 | 411 | 1,563 | 243 | 1,806 |
| December\t31,\t2016 | 160 | 17 | 177 | 190 | 5,361 | 16 | 5,377 | 387 | 1,439 | 210 | 1,649 |
| December\t31,\t2017 | 178 | 15 | 193 | 200 | 5,619 | 13 | 5,632 | 410 | 1,524 | 218 | 1,742 |
| December\t31,\t2018 | 198 | 16 | 214 | 187 | 4,331 | 2 | 4,333 | 359 | 1,278 | 204 | 1,482 |
| Proved\tdeveloped-producing\treserves: |  |  |  |  |  |  |  |  |  |  |  |
| December\t31,\t2015 | 192 | 19 | 211 | 219 | 5,546 | 13 | 5,559 | 393 | 1,509 | 240 | 1,749 |
| December\t31,\t2016 | 143 | 13 | 156 | 190 | 5,243 | 16 | 5,259 | 370 | 1,386 | 207 | 1,593 |
| December\t31,\t2017 | 165 | 12 | 177 | 197 | 5,512 | 13 | 5,525 | 397 | 1,481 | 212 | 1,693 |
| December\t31,\t2018 | 189 | 12 | 201 | 187 | 4,261 | 2 | 4,263 | 349 | 1,249 | 199 | 1,448 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |  |  |  |  |
| December\t31,\t2015 | 39 | — | 39 | 301 | 114 | — | 114 | 17 | 75 | 301 | 376 |
| December\t31,\t2016 | 34 | — | 34 | 294 | 254 | — | 254 | 38 | 115 | 294 | 409 |
| December\t31,\t2017 | 79 | — | 79 | 209 | 355 | — | 355 | 63 | 201 | 209 | 410 |
| December\t31,\t2018 | 100 | — | 100 | 206 | 428 | — | 428 | 67 | 239 | 206 | 445 |

(1) Gas	reserves	are	converted	to	Boe	at	the	rate	of	six	Mcf	per	Bbl	of	oil,	based	upon	the	approximate	relative	energy	content	of	gas	and	oil.	This	rate	is	not necessarily	indicative	of	the	relationship	of	natural	gas	and	oil	prices.	Bitumen	and	NGL	reserves	are	converted	to	Boe	on	a	one-to-one	basis	with	oil.

# Proved	Undeveloped	Reserves

The	following	table	presents	the	changes	in	Devon's	total	proved	undeveloped	reserves	during	2018	(MMBoe).

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2017 | 201 | 209 | 410 |
| Extensions\tand\tdiscoveries | 107 | 6 | 113 |
| Revisions\tdue\tto\tprices | 1 | 6 | 7 |
| Revisions\tother\tthan\tprice | (8) | (15) | (23) |
| Sale\tof\treserves | (10) | — | (10) |
| Conversion\tto\tproved\tdeveloped\treserves | (52) | — | (52) |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2018 | 239 | 206 | 445 |

Total	proved	undeveloped	reserves	increased	9%	from	2017	to	2018	with	the	year-end	2018	balance	representing	23%	of	total	proved	reserves.	Devon's	focus on	drilling	and	development	activities	in	the	STACK	and	Delaware	Basin	was	the	primary	driver	of	the	113	MMBoe	in	extensions	and	discoveries.	Continued development	primarily	in	the	STACK	and	Delaware	Basin	led	to	the	conversion	of	52	MMBoe,	or	26%,	of	the	2017	U.S.	proved	undeveloped	reserves	to	proved developed	reserves.	Costs	incurred	to	develop	and	convert	Devon's	proved	undeveloped	reserves	were	approximately	$691	million	for	2018.

A	significant	amount	of	Devon's	proved	undeveloped	reserves	at	the	end	of	2018	related	to	its	Jackfish	operations.	At	December	31,	2018	and	2017,	Devon's Jackfish	proved	undeveloped	reserves	were	206	MMBoe	and	209	MMBoe,	respectively.	Development	schedules	for	the	Jackfish	reserves	are	primarily	controlled	by	the need	to	keep	the	processing	plants	at	their	35	MBbl	daily	facility	capacity.	Processing	plant	capacity	is	controlled	by	factors	such	as	total	steam	processing	capacity	and steam-oil	ratios.	Furthermore,	development	of	these	projects	involves	the	up-front	construction	of	steam	injection/distribution	and	bitumen	processing	facilities.	Due	to the	large	up-front	capital	investments	and	large	reserves	required	to	provide	economic	returns,	the	project	conditions	meet	the	specific	circumstances	requiring	a	period greater	than	five	years	for	conversion	to	developed	reserves.	As	a	result,	these	reserves	are	classified	as	proved	undeveloped	for	more	than	five	years.	Currently,	the development	schedule	for	these	reserves	extends	through	2032.	At	the	end	of	2018,	approximately	125	MMBoe	of	proved	undeveloped	reserves	at	Jackfish	have remained	undeveloped	for	five	years	or	more	since	the	initial	booking.	No	other	projects	have	proved	undeveloped	reserves	that	have	remained	undeveloped	more	than five	years	from	the	initial	booking	of	the	reserves.	Furthermore,	approximately	81	MMBoe	of	proved	undeveloped	reserves	at	Jackfish	will	require	in	excess	of	five years,	from	the	date	of	this	filing,	to	develop.

# Price	Revisions

Reserves	increased	40	MMBoe	in	the	U.S.	primarily	due	to	price	increases	in	the	trailing	12	month	average	for	oil,	gas	and	NGLs	in	2018.	Reserves	increased 11	MMBoe	in	Canada	due	to	a	decrease	in	the	trailing	12	month	average	price	for	bitumen	in	2018.	The	decreased	price	has	the	effect	of	decreasing	the	applicable royalties,	which	increases	the	after-royalty	volumes.

Reserves	increased	111	MMBoe	in	the	U.S.	primarily	due	to	significant	price	increases	in	the	trailing	12	month	average	for	oil,	gas	and	NGLs	in	2017.	Reserves decreased	38	MMBoe	in	Canada	due	to	a	significant	increase	in	the	trailing	12	month	average	price	for	bitumen	in	2017.	The	increased	price	has	the	effect	of	increasing the	royalties,	which	decreases	the	after-royalty	volumes.

Reserves	decreased	27	MMBoe	during	2016	primarily	due	to	lower	commodity	prices	for	oil	and	gas.	The	lower	bitumen	price	increased	Canadian	reserves	due to	the	decline	in	royalties,	which	increases	Devon's	after-royalty	volumes.

# Revisions	Other	Than	Price

Total	revisions	other	than	price	in	2018	primarily	related	to	Devon's	evaluation	of	certain	oil	and	dry	gas	regions,	with	the	largest	revisions	being	made	in	the

# STACK.

Total	revisions	other	than	price	in	2016	primarily	related	to	Devon's	evaluation	of	certain	dry	gas	regions	and	NGLs,	with	the	largest	revisions	being	made	in the	Barnett	Shale	and	STACK	(Cana-Woodford	Shale).

# Extensions	and	Discoveries

2018	–	Approximately	72%	of	the	additions	were	through	our	focused	efforts	in	the	STACK	(87	MMBoe)	and	the	Delaware	Basin	(88	MMBoe).	The remaining	extensions	were	added	throughout	the	remainder	of	Devon's	portfolio.

The	2018	extensions	and	discoveries	included	21	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	primarily	relating	to	the	STACK.

2017	–	Over	80%	of	the	additions	were	through	our	focused	efforts	in	the	STACK	(120	MMBoe)	and	the	Delaware	Basin	(79	MMBoe).	The	remaining extensions	were	added	throughout	the	remainder	of	Devon's	portfolio.

The	2017	extensions	and	discoveries	included	66	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities	primarily	related	to	the	STACK.

2016	–	Of	the	126	MMBoe	of	extensions	and	discoveries,	97	MMBoe	related	to	STACK,	18	MMBoe	related	to	the	Delaware	Basin	and	7	MMBoe	related	to the	Eagle	Ford.

# Purchase	of	Reserves

2016	–	Primarily	related	to	Devon's	acquisition	in	the	STACK	play.

# Sale	of	Reserves

Related	to	Devon's	2018,	2017	and	2016	U.S.	non-core	asset	divestitures	as	discussed	further	in	Note	2.

# Standardized	Measure

The	following	tables	reflect	Devon's	standardized	measure	of	discounted	future	net	cash	flows	from	its	proved	reserves.

|  |  | Year	Ended	December	31,	2018 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Future\tcash\tinflows | $40,183 | \t$9,146 | \t$49,329 |
| Future\tcosts: |  |  |  |
| Development | (3,444) | (1,558) | (5,002) |
| Production | (18,107) | (5,445) | (23,552) |
| Future\tincome\ttax\texpense | (2,969) | — | (2,969) |
| Future\tnet\tcash\tflow | 15,663 | 2,143 | 17,806 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (6,897) | (717) | (7,614) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $8,766 | $1,426 | $10,192 |

|  |  | Year	Ended	December	31,	2017 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Future\tcash\tinflows | $34,701 | \t$13,602 | \t$48,303 |
| Future\tcosts: |  |  |  |
| Development | (3,316) | (1,853) | (5,169) |
| Production | (15,526) | (5,986) | (21,512) |
| Future\tincome\ttax\texpense | — | (988) | (988) |
| Future\tnet\tcash\tflow | 15,859 | 4,775 | 20,634 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (7,541) | (1,756) | (9,297) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $8,318 | $3,019 | $11,337 |

|  |  | Year	Ended	December	31,	2016 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
| Future\tcash\tinflows | $22,847 | \t$9,672 | \t$32,519 |
| Future\tcosts: |  |  |  |
| Development | (2,784) | (2,201) | (4,985) |
| Production | (11,934) | (6,049) | (17,983) |
| Future\tincome\ttax\texpense | — | (121) | (121) |
| Future\tnet\tcash\tflow | 8,129 | 1,301 | 9,430 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (3,524) | (466) | (3,990) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $4,605 | $835 | $5,440 |

Future	cash	inflows,	development	costs	and	production	costs	were	computed	using	the	same	assumptions	for	prices	and	costs	that	were	used	to	estimate	Devon's proved	oil	and	gas	reserves	at	the	end	of	each	year.	For	2018	estimates,	Devon's	future	realized	prices	were	assumed	to	be	$58.64	per	Bbl	of	oil,	$22.12	per	Bbl	of bitumen,	$2.45	per	Mcf	of	gas	and	$24.72	per	Bbl	of	NGLs.	Of	the	$5.0	billion	of	future	development	costs	as	of	the	end	of	2018,	$1.2	billion,	$0.6	billion	and	$0.3 billion	are	estimated	to	be	spent	in	2019,	2020	and	2021,	respectively.

Future	development	costs	include	not	only	development	costs	but	also	future	asset	retirement	costs.	Included	as	part	of	the	$5.0	billion	of	future	development costs	are	$1.4	billion	of	future	asset	retirement	costs.	The	future	income	tax	expenses	have	been	computed	using	statutory	tax	rates,	giving	effect	to	allowable	tax deductions	and	tax	credits	under	current	laws.

The	principal	changes	in	Devon's	standardized	measure	of	discounted	future	net	cash	flows	are	as	follows:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2018 | 2017 | 2016 |
| Beginning\tbalance | $11,337 | $5,440 | $7,883 |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | (243) | 5,218 | (2,027) |
| Oil,\tbitumen,\tgas\tand\tNGL\tsales,\tnet\tof\tproduction\tcosts | (3,452) | (3,327) | (2,377) |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (216) | 789 | 112 |
| Extensions\tand\tdiscoveries,\tnet\tof\tfuture\tdevelopment\tcosts | 3,139 | 2,497 | 674 |
| Purchase\tof\treserves | — | 2 | 224 |
| Sales\tof\treserves\tin\tplace | (588) | (3) | (577) |
| Revisions\tof\tquantity\testimates | (414) | (318) | (21) |
| Previously\testimated\tdevelopment\tcosts\tincurred\tduring\tthe\tperiod | 962 | 559 | 663 |
| Accretion\tof\tdiscount | 960 | 1,034 | 537 |
| Foreign\texchange\tand\tother | (329) | (7) | 72 |
| Net\tchange\tin\tincome\ttaxes | (964) | (547) | 277 |
| Ending\tbalance | $10,192 | $11,337 | $5,440 |

# 24. Supplemental	Quarterly	Financial	Information	(Unaudited)

The	following	tables	present	a	summary	of	Devon's	unaudited	interim	results	of	operations.

|  |  |  | 2018 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | First\tQuarter | Second\tQuarter | Third\tQuarter | Fourth\tQuarter | Full\tYear |
| Total\trevenues | $2,198 | $2,249 | $2,579 | $3,708 | $10,734 |
| Asset\tdispositions\t(1) | $(12) | $23 | $(6) | $(268) | $(263) |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes\t(2) | $(245) | $(481) | $162 | $1,484 | $920 |
| Net\tearnings\t(loss)\tfrom\tcontinuing\toperations | $(211) | $(474) | $300 | $1,149 | $764 |
| Net\tearnings\tfrom\tdiscontinued\toperations,\tnet\tof\tincome |  |  |  |  |  |
| \t\t\ttax\texpense\t(3) | $58 | $139 | $2,263 | $— | $2,460 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $(197) | $(425) | $2,537 | $1,149 | $3,064 |
| Basic\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $(0.38) | $(0.83) | $5.17 | $2.50 | $6.14 |
| Diluted\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $(0.38) | $(0.83) | $5.14 | $2.48 | $6.10 |

|  |  |  | 2017 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | First\tQuarter | Second\tQuarter | Third\tQuarter | Fourth\tQuarter | Full\tYear |
| Total\trevenues | $2,400 | $2,165 | $1,933 | $2,380 | $8,878 |
| Asset\tdispositions\t(1) | $(8) | $(22) | $(170) | $(17) | $(217) |
| Earnings\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $313 | $207 | $207 | $46 | $773 |
| Net\tearnings\tfrom\tcontinuing\toperations | $308 | $212 | $194 | $44 | $758 |
| Net\tearnings\tfrom\tdiscontinued\toperations,\tnet\tof\tincome |  |  |  |  |  |
| \t\t\ttax\texpense | $9 | $33 | $18 | $260 | $320 |
| Net\tearnings\tattributable\tto\tDevon | $303 | $219 | $193 | $183 | $898 |
| Basic\tnet\tearnings\tper\tshare\tattributable\tto\tDevon | $0.58 | $0.41 | $0.37 | $0.35 | $1.71 |
| Diluted\tnet\tearnings\tper\tshare\tattributable\tto\tDevon | $0.58 | $0.41 | $0.37 | $0.35 | $1.70 |

(1) Additional	discussion	regarding	asset	dispositions	can	be	found	in	Note	2.

(2) Includes	asset	impairments	of	approximately	$150	million	in	the	second	quarter	of	2018.	Additional	discussion	regarding	asset	impairments	can	be	found	in	 Note	5.

(3) Includes	a	gain	on	sale	associated	with	the	divestment	of	Devon's	aggregate	ownership	interests	in	EnLink	and	the	General	Partner	of	approximately	$ 2.2	billion	(after-tax)	in	the	third quarter	of	2018,	as	discussed	in	Note	19.

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

# Item	9A.	Controls	and	Procedures

# Disclosure	Controls	and	Procedures

We	have	established	disclosure	controls	and	procedures	to	ensure	that	material	information	relating	to	Devon,	including	its	consolidated	subsidiaries,	is	made known	to	the	officers	who	certify	Devon's	financial	reports	and	to	other	members	of	senior	management	and	the	Board	of	Directors.

Based	on	their	evaluation,	our	principal	executive	and	principal	financial	officers	have	concluded	that	our	disclosure	controls	and	procedures	(as	defined	in Rules	13a-15(e)	and	15d-15(e)	under	the	Securities	Exchange	Act	of	1934)	were	effective	as	of	December	31,	2018	to	ensure	that	the	information	required	to	be disclosed	by	Devon	in	the	reports	that	it	files	or	submits	under	the	Securities	Exchange	Act	of	1934	is	recorded,	processed,	summarized	and	reported	within	the	time periods	specified	in	the	SEC	rules	and	forms.

# Management's	Annual	Report	on	Internal	Control	Over	Financial	Reporting

Our	management	is	responsible	for	establishing	and	maintaining	adequate	internal	control	over	financial	reporting	for	Devon,	as	such	term	is	defined	in	Rules 13a-15(f)	and	15d-15(f)	under	the	Securities	Exchange	Act	of	1934.	Under	the	supervision	and	with	the	participation	of	Devon's	management,	including	our	principal executive	and	principal	financial	officers,	we	conducted	an	evaluation	of	the	effectiveness	of	our	internal	control	over	financial	reporting	based	on	the	framework	in Internal	Control	–	Integrated	Framework	issued	in	2013	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(the	"2013	COSO	Framework"). Based	on	this	evaluation	under	the	2013	COSO	Framework,	which	was	completed	on	February	20,	2019,	management	concluded	that	its	internal	control	over	financial reporting	was	effective	as	of	December	31,	2018.

The	effectiveness	of	our	internal	control	over	financial	reporting	as	of	December	31,	2018	has	been	audited	by	KPMG	LLP,	an	independent	registered	public accounting	firm	who	audited	our	consolidated	financial	statements	as	of	and	for	the	year	ended	December	31,	2018,	as	stated	in	their	report,	which	is	included	under "Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Changes	in	Internal	Control	Over	Financial	Reporting

There	was	no	change	in	our	internal	control	over	financial	reporting	during	the	fourth	quarter	of	2018	that	has	materially	affected,	or	is	reasonably	likely	to materially	affect,	our	internal	control	over	financial	reporting.

# Item	9B.	Other	Information

# PART	III

# Item	10.	Directors,	Executive	Officers	and	Corporate	Governance

The	information	called	for	by	this	Item	10	is	incorporated	herein	by	reference	to	the	definitive	Proxy	Statement	to	be	filed	by	Devon	pursuant	to	Regulation	14A of	the	General	Rules	and	Regulations	under	the	Securities	Exchange	Act	of	1934	no	later	than	120	days	following	the	fiscal	year	ended	December	31,	2018.

# Item	11.	Executive	Compensation

The	information	called	for	by	this	Item	11	is	incorporated	herein	by	reference	to	the	definitive	Proxy	Statement	to	be	filed	by	Devon	pursuant	to	Regulation	14A of	the	General	Rules	and	Regulations	under	the	Securities	Exchange	Act	of	1934	no	later	than	120	days	following	the	fiscal	year	ended	December	31,	2018.

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

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

# Item	14.	Principal	Accountant	Fees	and	Services

# PART	IV

# Item	15.	Exhibits	and	Financial	Statement	Schedules

# (a)	The	following	documents	are	included	as	part	of	this	report:

# 1.	Consolidated	Financial	Statements

Reference	is	made	to	the	Index	to	Consolidated	Financial	Statements	and	Consolidated	Financial	Statement	Schedules	appearing	at	"Item	8.	Financial Statements	and	Supplementary	Data"	in	this	report.

# 2.	Consolidated	Financial	Statement	Schedules

# 3.	Exhibits

		4.6 Indenture,	dated	as	of	March	1,	2002,	between	Registrant	and	The	Bank	of	New	York	Mellon	Trust	Company,	N.A.	(as	successor	to	The	Bank	of New	York),	as	Trustee	(incorporated	by	reference	to	Exhibit	4.1	of	Registrant's	Form	8-K	filed	April	9,	2002;	File	No.	000-30176).

		4.11 Senior	Indenture,	dated	as	of	September	1,	1997,	between	Devon	OEI	Operating,	L.L.C.	(as	successor	to	Seagull	Energy	Corporation)	and	The	Bank of	New	York	Mellon	Trust	Company,	N.A.	(as	successor	to	The	Bank	of	New	York),	as	Trustee,	and	related	Specimen	of	7.50%	Senior	Notes	due 2027	(incorporated	by	reference	to	Exhibit	4.4	to	Ocean	Energy	Inc.'s	Form	10-K	filed	March	23,	1998;	File	No.	001-08094).

		4.12 First	Supplemental	Indenture,	dated	as	of	March	30,	1999,	to	Senior	Indenture	dated	as	of	September	1,	1997,	by	and	among	Devon	OEI	Operating, L.L.C.,	its	Subsidiary	Guarantor,	and	The	Bank	of	New	York	Mellon	Trust	Company,	N.A.,	as	Trustee,	relating	to	the	7.50%	Senior	Notes	due	2027 (incorporated	by	reference	to	Exhibit	4.10	to	Ocean	Energy,	Inc.'s	Form	10-Q	filed	May	17,	1999;	File	No.	001-08094).

		4.13 Second	Supplemental	Indenture,	dated	as	of	May	9,	2001,	to	Senior	Indenture	dated	as	of	September	1,	1997,	by	and	among	Devon	OEI	Operating, L.L.C.,	its	Subsidiary	Guarantor,	and	The	Bank	of	New	York	Mellon	Trust	Company,	N.A.,	as	Trustee,	relating	to	the	7.50%	Senior	Notes	due	2027 (incorporated	by	reference	to	Exhibit	99.4	to	Ocean	Energy,	Inc.'s	Form	8-K	filed	May	14,	2001;	File	No.	033-06444).

		4.14 Third	Supplemental	Indenture,	dated	as	of	December	31,	2005,	to	Senior	Indenture	dated	as	of	September	1,	1997,	by	and	among	Devon	OEI Operating,	L.L.C.,	as	Issuer,	Devon	Energy	Production	Company,	L.P.,	as	Successor	Guarantor,	and	The	Bank	of	New	York	Mellon	Trust	Company, N.A.,	as	Trustee,	relating	to	the	7.50%	Senior	Notes	due	2027	(incorporated	by	reference	to	Exhibit	4.27	of	Registrant's	Form	10-K	filed	March	3, 2006;	File	No.	001-32318).

		10.34 Form	of	Notice	of	Grant	of	Performance	Restricted	Stock	Award	and	Award	Agreement	under	the	2015	Long-Term	Incentive	Plan	between Registrant	and	David	A.	Hager	for	performance	based	restricted	stock	awarded	(incorporated	by	reference	to	Exhibit	10.1	to	Registrant's	Form	10-Q filed	November	4,	2015;	File	No.	001-32318).*

		10.38 Form	of	Notice	of	Grant	of	Performance	Share	Unit	Award	and	Award	Agreement	under	the	2015	Long-Term	Incentive	Plan	between	Registrant	and executive	officers	for	performance	based	restricted	share	units	awarded	(incorporated	by	reference	to	Exhibit	10.3	to	Registrant's	Form	10-Q	filed May	4,	2016;	File	No.	001-32318).*

		10.43 2018	Form	of	Notice	of	Grant	of	Restricted	Stock	Award	and	Award	Agreement	under	the	2017	Long-Term	Incentive	Plan	between	Registrant	and all	non-management	directors	for	restricted	stock	awarded		(incorporated	by	reference	to	Exhibit	10.1	to	Registrant's	Form	10-Q	filed	May	2,	2018; File	No.	001-32318).*

		10.44 Form	of	Letter	Agreement	amending	the	restricted	stock	award	agreements	and	nonqualified	stock	option	agreements	under	the	2009	Long-Term Incentive	Plan	and	the	2005	Long-Term	Incentive	Plan	between	Registrant	and	John	Richels	(incorporated	by	reference	to	Exhibit	10.22	to Registrant's	Form	10-K	filed	February	25,	2011;	File	No.	001-32318).*

		10.45 Form	of	Amendment	to	Incentive	Stock	Option	Award	Agreements	between	Registrant	and	post-retirement	eligible	executives	relating	to	incentive stock	options	under	the	2009	Long-Term	Incentive	Plan	(incorporated	by	reference	to	Exhibit	10.24	to	Registrant's	Form	10-K	filed	February	21, 2013;	File	No.	001-32318).*

* Indicates	management	contract	or	compensatory	plan	or	arrangement.

# SIGNATURES

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

Jeffrey	L.	Ritenour

Executive	Vice	President	and

Chief	Financial	Officer

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	behalf	of	the	Registrant	and in	the	capacities	and	on	the	dates	indicated.



Question: what was the tax rate on the net earnings due to the gain on the sale of our aggregate ownership interests in enlink discontinued operations
Calculation: net_earnings_2018 = 2.6
net_earnings_2017 = 2.2
percent_change = (net_earnings_2018 - net_earnings_2017) / net_earnings_2017
answer = percent_change * 100
Answer: 18.2%