Table	of	Contents

# 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,	2015

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

Common	stock,	par	value	$0.10	per	share

# Name	of	each	exchange	on	which	registered

The	New	York	Stock	Exchange

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

Indicate	by	check	mark	if	the	registrant	is	a	well-known	seasoned	issuer,	as	defined	in	Rule	405	of	the	Securities	Act.				Yes		x				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		x

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		x				No		¨

Indicate	by	check	mark	whether	the	registrant	has	submitted	electronically	and	posted	on	its	corporate	Web	site,	if	any,	every	Interactive	Data	File	required	to	be submitted	and	posted	pursuant	to	Rule	405	of	Regulation	S-T	(§232.405	of	this	chapter)	during	the	preceding	12	months	(or	for	such	shorter	period	that	the	registrant	was required	to	submit	and	post	such	files).				Yes		x				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,	or	a	smaller	reporting	company.	See	the definitions	of	"large	accelerated	filer,"	"accelerated	filer"	and	"smaller	reporting	company"	in	Rule	12b-2	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		x

The	aggregate	market	value	of	the	voting	common	stock	held	by	non-affiliates	of	the	registrant	as	of	June	30,	2015	was	approximately	$24.3	billion,	based	upon the	closing	price	of	$59.49	per	share	as	reported	by	the	New	York	Stock	Exchange	on	such	date.	On	February	10,	2016,	441.3	million	shares	of	common	stock	were outstanding.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

Proxy	statement	for	the	2016	annual	meeting	of	stockholders	–	Part	III

# PART	I

| DEVON	ENERGY	CORPORATION |  |
| :--- | :--- |
| FORM\t10-K |  |
| TABLE\tOF\tCONTENTS |  |
| PART\tI |  |
| Items\t1\tand\t2.\tBusiness\tand\tProperties | 6 |
| Item\t1A.\t\tRisk\tFactors | 20 |
| Item\t1B.\t\tUnresolved\tStaff\tComments | 26 |
| Item\t3.\t\t\t\t\tLegal\tProceedings | 26 |
| Item\t4.\t\t\t\t\tMine\tSafety\tDisclosures | 26 |
| PART\tII |  |
| Item\t5.\t\t\t\t\t\tMarket\tfor\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 27 |
| Item\t6.\t\t\t\t\tSelected\tFinancial\tData | 29 |
| Item\t7.\t\t\t\t\t\tManagement's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 30 |
| Item\t7A.\t\tQuantitative\tand\tQualitative\tDisclosures\tabout\tMarket\tRisk | 55 |
| Item\t8.\t\t\t\t\tFinancial\tStatements\tand\tSupplementary\tData | 56 |
| Item\t9.\t\t\t\t\t\tChanges\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | \t120 |
| Item\t9A.\t\tControls\tand\tProcedures | \t120 |
| Item\t9B.\t\tOther\tInformation | \t120 |
| PART\tIII |  |
| Item\t10.\t\t\tDirectors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | \t121 |
| Item\t11.\t\t\tExecutive\tCompensation | \t121 |
| Item\t12.\t\t\t\tSecurity\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | \t121 |
| Item\t13.\t\t\tCertain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | \t121 |
| Item\t14.\t\t\tPrincipal\tAccountant\tFees\tand\tServices | \t121 |
| PART\tIV |  |
| Item\t15.\t\t\tExhibits\tand\tFinancial\tStatement\tSchedules | \t122 |
| Signatures | \t129 |

# DEFINITIONS

Unless	the	context	otherwise	indicates,	references	to	"us,"	"we,"	"our,"	"ours,"	"Devon"	and	the	"Company"	refer	to	Devon	Energy	Corporation	and	its consolidated	subsidiaries.	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.

"ASU"	means	Accounting	Standards	Update.

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

"Bcf"	means	billion	cubic	feet.

"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.

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

"Coronado"	means	Coronado	Midstream	Holdings	LLC.

"Crosstex"	means	Crosstex	Energy,	Inc.	together	with	Crosstex	Energy	L.P.

"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.

"DOE"	means	Department	of	Energy.

"E2"	means	E2	Energy	Services,	LLC	together	with	E2	Appalachian	Compression,	LLC.

"EMH"	means	EnLink	Midstream	Holdings,	LP.

"EnLink"	means	EnLink	Midstream	Partners,	L.P.,	a	master	limited	partnership.

"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.

"General	Partner"	means	EnLink	Midstream,	LLC,	the	general	partner	entity	of	EnLink.

"GeoSouthern"	means	GeoSouthern	Energy	Corporation.

"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.

"LPC"	means	LPC	Crude	Oil	Marketing	LLC.

"Matador"	means	MRC	Energy	Company.

"MBbls"	means	thousand	barrels.

"MBoe"	means	thousand	Boe.

"Mcf"	means	thousand	cubic	feet.

"MLP"	means	master	limited	partnership.

"MMBbls"	means	million	barrels.

"MMBoe"	means	million	Boe.

"MMBtu"	means	million	Btu.

"MMcf"	means	million	cubic	feet.

"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.

"Pre-tax	10%	present	value"	means	the	present	value	of	Devon's	pre-tax	future	net	revenue	to	be	generated	from	the	production	of	proved	reserves,	net	of estimated	production	and	development	costs	and	site	restoration	and	abandonment	charges.

"SEC"	means	United	States	Securities	and	Exchange	Commission.

"Senior	Credit	Facility"	means	Devon's	syndicated	unsecured	revolving	line	of	credit.

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

"Tall	Oak"	means	Tall	Oak	Midstream,	LLC.

"TSR"	means	total	shareholder	return.

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

"VEX"	means	Victoria	Express	Pipeline	and	related	truck	terminal	and	storage	assets.

"WTI"	means	West	Texas	Intermediate.

# INFORMATION	REGARDING	FORWARD-LOOKING	STATEMENTS

This	report	includes	"forward-looking	statements"	as	defined	by	the	SEC.	Such	statements	are	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	"expects,"	"believes,"	"will,"	"would,"	"could," "forecasts,"	"projections,"	"estimates,"	"plans,"	"expectations,"	"targets,"	"opportunities,"	"potential,"	"anticipates,"	"outlook"	and	other	similar	terminology.	Such forward-looking	statements	are	based	on	our	examination	of	historical	operating	trends,	the	information	used	to	prepare	our	December	31,	2015	reserve	reports	and	other data	in	our	possession	or	available	from	third	parties.	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,	including	the	currently	depressed	commodity	price	environment;

•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	exploration	and	development	activities;

•risks	related	to	our	hedging	activities;

# •counterparty	credit	risks;

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

•risks	relating	to	our	indebtedness;

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

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

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

•	 midstream	capacity	constraints	and	potential	interruptions	in	production;

•competition	for	leases,	materials,	people	and	capital;

•cyberattacks	targeting	our	systems	and	infrastructure;	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.

# Items	1	and	2.	Business	and	Properties

# General

Devon	is	a	leading	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.	Our	portfolio	of	oil	and	gas	properties	provides	stable,	environmentally	responsible production	and	a	platform	for	future	growth.	We	have	doubled	our	onshore	North	American	oil	production	since	2010	to	more	than	275	MBbls	per	day	and	have	a	deep inventory	of	development	opportunities.	Devon	also	produces	over	1.6	Bcf	of	natural	gas	a	day	and	more	than	136	MBbls	of	NGLs	per	day.

Additionally,	we	control	EnLink,	a	leading	integrated	midstream	business	with	significant	size	and	scale	in	key	operating	regions	in	the	U.S.	This	MLP	focuses	on providing	gathering,	transmission,	processing,	fractionation	and	marketing	to	producers	of	natural	gas,	NGLs,	crude	oil	and	condensate.

A	Delaware	corporation	formed	in	1971,	we	have	been	publicly	held	since	1988,	and	our	common	stock	is	listed	on	the	NYSE.	Our	principal	and	administrative offices	are	located	at	333	West	Sheridan,	Oklahoma	City,	OK	73102-5015	(telephone	405-235-3611).	As	of	December	31,	2015,	Devon	and	its	consolidated subsidiaries	had	approximately	6,600	employees.	Approximately	1,400	of	such	employees	are	employed	by	EnLink	(through	its	subsidiaries).

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,	http://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	(including	our	Code	of	Ethics	for	the	Chief	Executive Officer,	Chief	Financial	Officer	and	Chief	Accounting	Officer).	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.

In	addition,	the	public	may	read	and	copy	any	materials	Devon	files	with	the	SEC	at	the	SEC's	Public	Reference	Room	at	100	F	Street,	N.E.,	Washington	D.C. 20549.	The	public	may	also	obtain	information	about	the	operation	of	the	Public	Reference	Room	by	calling	the	SEC	at	1-800-SEC-0330.	Reports	filed	with	the	SEC	are also	made	available	on	its	website	at	www.sec.gov.

# Strategy

Our	primary	goal	is	to	build	value	per	debt-adjusted	share	by:

•exploring	for	undiscovered	oil	and	natural	gas	reserves;

•purchasing	and	developing	oil	and	natural	gas	properties;

•enhancing	the	value	of	production	through	marketing	and	midstream	activities;

•optimizing	production	operations	to	control	costs;	and

•	 maintaining	a	strong	balance	sheet.

During	2015,	we	continued	to	execute	on	this	strategy	and	experienced	a	number	of	key	achievements	that	are	outlined	in	this	report.	However,	we,	and	the	entire upstream	energy	sector,	have	faced	both	operational	and	financial	challenges	as	oil	and	natural	gas	prices	weakened	significantly	throughout	2015	and	continued	into 2016.	To	navigate	these	turbulent	times,	we	are	using	our	focused	strategy,	flexible	portfolio	of	assets	and	leadership	experience	to	execute	on	a	number	of	initiatives that	will	ensure	our	long-term	financial	strength.

Specifically,	after	completing	the	STACK	acquisition	discussed	in	this	report,	we	had	approximately	$3.9	billion	of	liquidity.

While	we	will	continue	to	operate	and	develop	our	premier	portfolio	of	assets,	we	are	committed	to	protecting	our	balance	sheet	and	managing	our	capital programs	to	be	within	our	cash	inflows,	including	Access	Pipeline	proceeds.	As	a	result,	we	are	significantly	reducing	our	capital	investment	in	response	to	lower commodity	prices.	We	plan	to	invest	$900	million	to	$1.1	billion	in	our	upstream	programs,	a	decrease	of	roughly	75%	compared	to	our	2015	capital.	We	are	also committed	to	reducing	our	G&A	and	field-level	operating	costs	commensurate	with	our	reduced,	but	focused,	activity	level.	Following	a	number	of	cost-reduction initiatives	culminating	with	our	February	2016	workforce	reduction,	we	are	expecting	a	$700	million	to	$900	million	reduction	in	operating	and	G&A	costs	on	an annualized	basis.

Also,	in	February	2016,	we	reduced	our	quarterly	common	stock	dividend	75%	to	$0.06	per	share.

# Oil	and	Gas	Properties

# Property	Profiles

The	locations	of	our	core	oil	and	gas	properties	are	presented	on	the	following	map.	Additional	information	related	to	these	properties	follows	this	map,	as	well	as information	describing	EnLink's	assets.

The	following	table	outlines	a	summary	of	key	data	in	each	of	our	operating	areas	as	of	and	for	the	year	ended	December	31,	2015.	Notes	20	and	21	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.

|  | MMBoe | %	of<br>Total | %	Liquids | MBoe/d | %	of<br>Total | %<br>Liquids | Wells<br>Drilled |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Delaware\tBasin | 123 | 6% | 78% | 61 | 9% | 79% | 167 |
| STACK | 264 | 12% | 42% | 64 | 9% | 42% | 130 |
| Eagle\tFord | 103 | 4% | 76% | 115 | 17% | 79% | 275 |
| Rockies\tOil | 28 | 1% | 66% | 23 | 3% | 70% | 65 |
| Heavy\tOil | 544 | 25% | 100% | 115 | 17% | 97% | 79 |
| Barnett\tShale | 841 | 39% | 25% | 182 | 27% | 27% | 5 |
| Core\tassets | \t 1,903 | 87% | 55% | 560 | 82% | 61% | 721 |
| Other | 279 | 13% | 57% | 120 | 18% | 58% | 129 |
| Total | \t 2,182 | \t100% | 56% | 680 | \t100% | 60% | 850 |

Delaware	Basin	–	The	Delaware	Basin	has	been	a	legacy	asset	for	Devon	and	continues	to	offer	exploration	and	low-risk	development	opportunities	from	many geologic	reservoirs	and	play	types,	including	the	oil-rich	Bone	Spring,	Delaware,	Wolfcamp	and	Leonard	formations.	These	oil	and	liquids-rich	opportunities	across	our acreage	in	the	Delaware	Basin	will	offer	high-margin	growth	potential	for	many	years	to	come.	In	2016,	we	plan	to	invest	approximately	$200	million	of	capital	in	the Delaware	Basin,	primarily	focused	on	the	second	Bone	Spring	opportunity	in	the	basin	of	southeast	New	Mexico.

STACK	–	In	early	January	2016,	we	increased	our	acreage	in	the	Woodford	Shale	and	Meramec	plays	by	acquiring	80,000	net	acres	in	the	STACK.	The	STACK development,	located	primarily	in	Oklahoma's	Canadian,	Kingfisher	and	Blaine	counties,	is	named	for	the	stacked	pay	in	the	area.	Our	Woodford	Shale	position	is	the largest	and	one	of	the	best	in	the	industry.	Recent	well-completion	design	enhancements	have	resulted	in	greater	productivity	and	improved	economics.	Early	drilling activity	in	the	Meramec	play	has	been	encouraging	across	our	core	position	in	the	oil	and	liquids	window.	In	2016,	we	plan	approximately	$325	million	of	capital investment.

Eagle	Ford	–	We	acquired	our	position	in	the	Eagle	Ford	in	early	2014	from	GeoSouthern	and	have	approximately	66,000	net	acres	located	in	the	DeWitt	and Lavaca	counties	in	south	Texas.	Since	acquiring	these	assets,	we	have	delivered	tremendous	results,	increasing	production	by	125%.	Our	excellent	results	are	driven	by our	development	in	DeWitt	County	which	is	located	in	the	economic	core	of	the	play.	In	2016,	we	expect	our	Eagle	Ford	assets	to	once	again	deliver	the	highest operating	margin	of	any	asset	in	the	portfolio	and	plan	approximately	$200	million	of	capital	investment.

Rockies	Oil	–	Our	operations	are	focused	on	emerging	oil	opportunities	in	the	Powder	River	Basin	and	the	Wind	River	Basin.	In	the	Powder	River,	we	are currently	targeting	several	Cretaceous	oil	objectives,	including	the	Turner,	Parkman	and	Frontier	formations.	Recent	drilling	success	in	these	formations	has	expanded our	drilling	inventory,	and	we	expect	further	growth	as	we	continue	to	de-risk	this	emerging	light-oil	opportunity.	In	December	2015,	we	acquired	253,000	net	acres	in the	"core"	of	the	oil	fairway	in	the	Powder	River.	This	acquisition	delivers	some	of	the	best	returns	in	our	portfolio	and	is	a	significant	resource	opportunity.	In	2016,	we plan	approximately	$75	million	of	capital	investment.

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,	a 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.	In	2014,	we	brought	the	third	phase	of	Jackfish	into	operation,	which	ramped	up	to	facility	capacity	by

the	third	quarter	of	2015.	We	expect	each	phase	to	maintain	a	reasonably	flat	production	profile	for	greater	than	20	years	at	an	average	gross	production	rate	of approximately	35	MBbls	per	day	at	each	facility.

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,	2015.	With	our	50%	partner,	we	are	evaluating	our development	timeline	for	Pike.

To	facilitate	the	delivery	of	our	heavy	oil	production,	we	have	a	50%	interest	in	the	Access	Pipeline	transportation	system	in	Canada.	This	pipeline	system	allows us	to	blend	our	heavy	oil	production	with	condensate	or	other	blend-stock	and	transport	the	combined	product	to	the	Edmonton	area	for	sale.	The	Access	Pipeline	system has	the	capacity	to	transport	approximately	170	MBbls	of	bitumen	blend	per	day,	net	to	our	50%	interest.	As	discussed	in	"Item	7.	Management's	Discussion	and Analysis	of	Financial	Condition	and	Results	of	Operations"	of	this	report,	we	have	plans	to	monetize	our	interest	in	Access	Pipeline	in	2016.	With	any	buyer	of	Access Pipeline,	we	will	also	enter	into	a	contractual	arrangement	to	continue	transporting	our	heavy	oil	volumes	on	Access	Pipeline.

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,	high	margin	oil	development	play	that	produces	heavy	oil	by	conventional	means,	without	the	need	for	steam	injection.

In	2016,	we	plan	approximately	$175	million	of	capital	investment	in	our	Canadian	Heavy	Oil	business.

Barnett	Shale	–	This	is	our	largest	property	in	terms	of	production	and	proved	reserves.	Our	leases	are	located	primarily	in	Denton,	Johnson,	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	into	one	of	the	top	producing	gas	fields	in	North	America.	Given	the	commodity	price	environment	in	2015,	we	shifted focus	to	enhancing	existing	well	performance	through	re-fracturing,	artificial	lift	and	line	pressure	reduction	projects.	In	2015,	we	accelerated	our	horizontal	refrac program	to	test	the	re-stimulation	of	25	wells	and	also	had	an	active	vertical	refrac	program,	re-stimulating	140	vertical	wells.	In	2016,	we	plan	on	minimal	refrac activity	in	the	Barnett.

Other	–	Other	assets	are	located	primarily	in	the	Midland	Basin,	east	Texas,	Granite	Wash	and	Mississippian-Lime	areas.	Substantially	all	of	these	properties	have been	identified	for	divestiture	in	2016.

# Proved	Reserves

For	estimates	of	our	proved	developed	and	proved	undeveloped	reserves	and	the	discussion	of	the	contribution	by	each	key	property,	see	Note	21	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report.

Since	the	beginning	of	2015,	no	estimates	of	our	proved	reserves	have	been	filed	with	or	included	in	reports	to	any	federal	or	foreign	governmental	authority	or agency	except	in	filings	with	the	SEC	and	the	DOE.	Reserve	estimates	filed	with	the	SEC	correspond	with	the	estimates	of	our	reserves	contained	in	this	report.	Reserve estimates	filed	with	the	DOE	are	based	upon	the	same	underlying	technical	and	economic	assumptions	as	the	estimates	of	our	reserves	included	in	this	report.	However, the	DOE	requires	reports	to	include	the	interests	of	all	owners	in	wells	that	we	operate	and	to	exclude	all	interests	in	wells	that	we	do	not	operate.

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	("Qualified	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	Group's	Director	and	key	members	of	the	Group	have	appropriate	technical	qualifications	to	oversee	the	preparation	of	reserves	estimates,	including	any	or	all	of	the following:

•an	undergraduate	degree	in	petroleum	engineering	from	an	accredited	university,	or	equivalent;

•a	petroleum	engineering	license,	or	similar	certification;

•	 memberships	in	oil	and	gas	industry	or	trade	groups;	and

•relevant	experience	estimating	reserves.

The	current	Director	of	the	Group	has	all	of	the	qualifications	listed	above.	The	current	Director	has	been	involved	with	reserves	estimation	in	accordance	with SEC	definitions	and	guidance	since	1987.	He	has	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.	He	has	been	employed	by	Devon	for	the	past	fifteen	years,	including	the	past	eight	in	his	current	position.	During	his	career,	he	has been	responsible	for	reserves	estimation	as	the	primary	reservoir	engineer	for	projects	including,	but	not	limited	to:

•	 Hugoton	Gas	Field	(Kansas);

•Sho-Vel-Tum	CO 	Flood	(Oklahoma);

•	 West	Loco	Hills	Unit	Waterflood	and	CO 	Flood	(New	Mexico);

•	 Dagger	Draw	Oil	Field	(New	Mexico);

•	 Clarke	Lake	Gas	Field	(Alberta,	Canada);

•Panyu	4-2	and	5-1	Joint	Development	(Offshore	South	China	Sea);	and

•	 ACG	Unit	(Caspian	Sea).

From	2003	to	2010,	he	served	as	the	reservoir	engineering	representative	on	our	internal	peer	review	team.	In	this	role,	he	reviewed	reserves	and	resource estimates	for	projects	including,	but	not	limited	to,	the	Mobile	Bay	Norphlet	Discoveries	(Gulf	of	Mexico	Shelf),	Cascade	Lower	Tertiary	Development	(Gulf	of	Mexico Deepwater)	and	Polvo	Development	(Campos	Basin,	Brazil).

The	Group	reports	independently	of	any	of	our	operating	divisions	and	currently	is	in	our	Chief	Financial	Officer's	organization.	No	portion	of	the	Group's compensation	is	directly	dependent	on	the	quantity	of	reserves	booked.

Throughout	the	year,	the	Group	performs	internal	reserves	audits	of	each	operating	division's	reserves.	Selection	criteria	of	reserves	that	are	audited	include major	fields	and	major	additions	and	revisions	to	reserves.	In	addition,	the	Group	reviews	reserve	estimates	with	each	of	the	third-party	petroleum	consultants	discussed below.	The	Group	also	ensures	our	Qualified	Estimators	obtain	continuing	education	related	to	the	fundamentals	of	SEC	proved	reserves	assignments.

The	Group	also	oversees	audits	and	reserves	estimates	performed	by	third-party	petroleum	consulting	firms.	During	2015,	we	engaged	two	such	firms	to	audit 95%	of	our	proved	reserves.	LaRoche	Petroleum	Consultants,	Ltd.	audited	94%	of	our	2015	U.S.	reserves,	and	Deloitte	LLP	audited	96%	of	our	Canadian	reserves.

"Audited"	reserves	are	those	quantities	of	reserves	that	were	estimated	by	our	employees	and	audited	by	an	independent	petroleum	consultant.	The	Society	of Petroleum	Engineers'	definition	of	an	audit	is	an	examination	of	a	company's	proved	oil	and	gas	reserves	and	net	cash	flow	by	an	independent	petroleum	consultant	that is	conducted	for	the	purpose	of	expressing	an	opinion	as	to	whether	such	estimates,	in	aggregate,	are	reasonable	and	have	been	estimated	and	presented	in	conformity with	generally	accepted	petroleum	engineering	and	evaluation	methods	and	procedures.

In	addition	to	conducting	these	internal	and	external	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	Reserves	Committee	assists	the	Board	of	Directors	with its	duties	and	responsibilities	in	evaluating	and	reporting	our	proved	reserves,	much	like	our	Audit	Committee	assists	the	Board	of	Directors	in	supervising	our	audit	and financial	reporting	requirements.	Besides	being	independent,	the	members	of	our	Reserves	Committee	also	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	responsibilities	of	the	Reserves	Committee	include	the	following:

•approve	the	scope	of	and	oversee	an	annual	review	and	evaluation	of	our	oil,	gas	and	NGL	reserves;

•oversee	the	integrity	of	our	reserves	evaluation	and	reporting	system;

•oversee	and	evaluate	our	compliance	with	legal	and	regulatory	requirements	related	to	our	reserves;

•review	the	qualifications	and	independence	of	our	third-party	petroleum	consultants;	and

•	 monitor	the	performance	of	our	third-party	petroleum	consultants.

The	following	table	presents	our	estimated	pre-tax	cash	flow	information	related	to	our	proved	reserves.	These	estimates	correspond	with	the	method	used	in presenting	the	"Supplemental	Information	on	Oil	and	Gas	Operations"	in	Note	21	to	our	consolidated	financial	statements	included	in	this	report.

|  | Year	Ended	December	31,	2015 | Year	Ended	December	31,	2015 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Pre-Tax\tFuture\tNet\tRevenue\t(Non-GAAP)\t^(1) |  |  |  |
| Proved\tDeveloped\tReserves | $6,382 | $1,874 | $8,256 |
| Proved\tUndeveloped\tReserves | 459 | \t 1,523 | 1,982 |
| Total\tProved\tReserves | $6,841 | $3,397 | $10,238 |
| Pre-Tax\t10%\tPresent\tValue\t(Non-GAAP)\t^(1) |  |  |  |
| Proved\tDeveloped\tReserves | $4,609 | $1,657 | $6,266 |
| Proved\tUndeveloped\tReserves | 259 | 458 | 717 |
| Total\tProved\tReserves | $4,868 | $2,115 | $6,983 |

(1) Estimated	pre-tax	future	net	revenue	represents	estimated	future	revenue	to	be	generated	from	the	production	of	proved	reserves,	net	of	estimated	production	and development	costs	and	site	restoration	and	abandonment	charges.	The	amounts	shown	do	not	give	effect	to	DD&A,	asset	impairments	or	non-property	related expenses	such	as	debt	service	and	income	tax	expense.

Pre-tax	future	net	revenue	and	pre-tax	10%	present	value	are	non-GAAP	measures.	The	standardized	measure	was	$6.7	billion	at	the	end	of	2015.	Included	as	part of	the	standardized	measure	were	discounted	future	income	taxes	of	$0.3	billion.	Excluding	these	taxes,	the	pre-tax	10%	present	value	was	$7.0	billion.	We believe	the	pre-tax	10%	present	value	is	a	useful	measure	in	addition	to	the	after-tax	standardized

measure.	The	pre-tax	10%	present	value	assists	in	both	the	estimation	of	future	cash	flows	of	the	current	reserves	as	well	as	in	making	relative	value	comparisons among	peer	companies.	The	after-tax	standardized	measure	is	dependent	on	the	unique	tax	situation	of	each	individual	company,	while	the	pre-tax	10%	present value	is	based	on	prices	and	discount	factors,	which	are	more	consistent	from	company	to	company.

# Production,	Production	Prices	and	Production	Costs

The	following	table	presents	production,	price	and	cost	information	for	each	significant	field,	country	and	continent.

| Year	Ended	December	31, | Oil	(MMBbls) | Bitumen	(MMBbls) | Gas	(Bcf) | NGLs	(MMBbls) | Total	(MMBoe) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2015 |  |  |  |  |  |
| Barnett\tShale | — | — | 291 | 17 | 66 |
| Jackfish | — | 31 | — | — | 31 |
| U.S. | 60 | — | 579 | 50 | 206 |
| Canada | 10 | 31 | 8 | — | 42 |
| Total\tNorth\tAmerica | 70 | 31 | 587 | 50 | 248 |
| 2014 |  |  |  |  |  |
| Barnett\tShale | 1 | — | 332 | 20 | 76 |
| Jackfish | — | 20 | — | — | 20 |
| U.S. | 47 | — | 660 | 50 | 207 |
| Canada | 10 | 20 | 41 | 1 | 39 |
| Total\tNorth\tAmerica | 57 | 20 | 701 | 51 | 246 |
| 2013 |  |  |  |  |  |
| Barnett\tShale | 1 | — | 374 | 20 | 83 |
| Jackfish | — | 19 | — | — | 19 |
| U.S. | 28 | — | 709 | 41 | 189 |
| Canada | 15 | 19 | 165 | 4 | 64 |
| Total\tNorth\tAmerica | 43 | 19 | 874 | 45 | 253 |

| Year	Ended	December	31, | Oil	(Per	Bbl) | Bitumen	(Per	Bbl) | Gas	(Per	Mcf) | NGLs	(Per	Bbl) | Production	Cost<br>(1)<br>(Per	Boe) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2015 |  |  |  |  |  |
| Barnett\tShale | $46.47 | $— | $2.00 | $9.62 | $6.02 |
| Jackfish | $— | $23.41 | $— | $— | $12.43 |
| U.S. | $44.01 | $— | $2.17 | $9.32 | $7.52 |
| Canada | $30.58 | $23.41 | $0.67 | $— | $13.18 |
| Total\tNorth\tAmerica | $42.12 | $23.41 | $2.14 | $9.32 | $8.48 |
| 2014 |  |  |  |  |  |
| Barnett\tShale | $95.51 | $— | $3.78 | $21.98 | $5.25 |
| Jackfish | $— | $55.88 | $— | $— | $20.59 |
| U.S. | $85.64 | $— | $3.92 | $24.46 | $7.52 |
| Canada | $68.14 | $55.88 | $3.64 | $50.52 | $20.10 |
| Total\tNorth\tAmerica | $82.47 | $55.88 | $3.90 | $24.89 | $9.49 |
| 2013 |  |  |  |  |  |
| Barnett\tShale | $97.74 | $— | $2.90 | $22.45 | $4.12 |
| Jackfish | $— | $48.04 | $— | $— | $17.98 |
| U.S. | $94.52 | $— | $3.10 | $25.75 | $6.65 |
| Canada | $69.18 | $48.04 | $3.05 | $46.17 | $15.78 |
| Total\tNorth\tAmerica | $86.02 | $48.04 | $3.09 | $27.33 | $8.97 |

(1) Represents	LOE	per	Boe	and	excludes	severance	and	property	taxes.

# Drilling	Statistics

The	following	table	summarizes	our	development	and	exploratory	drilling	results.

| Year	Ended	December	31, | Development	Wells^		(1)<br>Productive | Dry | Exploratory	Wells		^(1)<br>Productive | Dry | Productive | Total	Wells	^(1)<br>Dry | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2015 |  |  |  |  |  |  |  |
| U.S. | 298.6 | 1.8 | 40.7 | \t — | 339.3 | \t 1.8 | \t341.1 |
| Canada | 79.0 | \t — | — | \t — | 79.0 | \t— | 79.0 |
| Total\tNorth\tAmerica | 377.6 | 1.8 | 40.7 | \t — | 418.3 | \t 1.8 | \t420.1 |
| 2014 |  |  |  |  |  |  |  |
| U.S. | 474.4 | 0.4 | 5.0 | 1.2 | 479.4 | \t 1.6 | \t481.0 |
| Canada | 190.8 | 1.0 | — | 0.5 | 190.8 | \t 1.5 | \t192.3 |
| Total\tNorth\tAmerica | 665.2 | 1.4 | 5.0 | 1.7 | 670.2 | \t 3.1 | \t673.3 |
| 2013 |  |  |  |  |  |  |  |
| U.S. | 555.3 | \t — | 56.1 | 7.0 | 611.4 | \t 7.0 | \t618.4 |
| Canada | 211.9 | 1.0 | 7.4 | \t — | 219.3 | \t 1.0 | \t220.3 |
| Total\tNorth\tAmerica | 767.2 | 1.0 | 63.5 | 7.0 | 830.7 | \t 8.0 | \t838.7 |

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

The	following	table	presents	the	wells	that	were	in	progress	on	December	31,	2015.	As	of	February	1,	2016,	these	wells	were	still	in	progress.

|  |  |  |  |  |  |  | Gross^	(1) |  | Net^	(2) |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| U.S. | U.S. | U.S. | U.S. | U.S. | U.S. |  | 17.0 | 17.0 | 8.6 | 8.6 |  |
| Canada |  |  |  |  |  |  | — | — | \t — | \t — |  |
| Total\tNorth\tAmerica | Total\tNorth\tAmerica | Total\tNorth\tAmerica | Total\tNorth\tAmerica | Total\tNorth\tAmerica | Total\tNorth\tAmerica |  | 17.0 | 17.0 | 8.6 | 8.6 |  |
| (1) |  |  |  |  |  |  |  |  |  |  |  |
| (2) |  |  |  |  |  |  |  |  |  |  |  |
| Productive\tWells |  |  |  |  |  |  |  |  |  |  |  |
|  | Oil\tWells | \t(1) |  | Natural\tGas\tWells | Natural\tGas\tWells | Natural\tGas\tWells |  |  | Total\tWells | (1) | (1) |
| Gross | \t\t(2)(4) | Net | \t(3) | Gross | \t\t(2)(4) | Net | \t(3) | Gross | \t\t(2)(4) | Net | \t(3) |
| U.S. | 10,895 | \t4,352 | \t4,352 | 15,130 | 15,130 | \t10,313 | \t10,313 | 26,025 | 26,025 | \t 14,665 | \t 14,665 |
| Canada | 3,264 | \t3,166 | \t3,166 |  | 698 |  | 498 |  | 3,962 | 3,664 | 3,664 |
| Total\tNorth\tAmerica | 14,159 | \t7,518 | \t7,518 | 15,828 | 15,828 | \t10,811 | \t10,811 | 29,987 | 29,987 | \t 18,329 | \t 18,329 |

(1) Includes	bitumen	wells.

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

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

(4) Includes	809	and	1,565	oil	and	gas	wells,	respectively,	which	had	multiple	completions	and	were	operated	by	Devon.

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	19,000	wells.	As operator,	we	receive	reimbursement	for	direct	expenses	incurred	to	perform	our	duties,	as	well	as	monthly	per-well	producing	and	drilling	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,	2015.	Of	our	5.5	million	net	acres,	approximately 3.0	million	acres	are	held	by	production.	The	acreage	in	the	table	includes	0.2	million,	0.4	million	and	0.1	million	net	acres	subject	to	leases	that	are	scheduled	to	expire during	2016,	2017	and	2018,	respectively.	As	of	December	31,	2015,	there	were	no	proved	undeveloped	reserves	associated	with	our	expiring	acreage.	Of	the 0.7	million	net	acres	set	to	expire	by	December	31,	2018,	we	will	perform	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	2015,	we	allowed	approximately 0.8	million	acres	to	expire.

|  | Developed |  | Undeveloped | Undeveloped | Total |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross^\t(1) | Net^\t(2) | Gross^\t(1) | Net^\t(2) | Gross^\t(1) | Net^\t(2) |
|  |  |  | (Thousands) | (Thousands) |  |  |
| U.S. | \t 2,598 | \t1,732 | \t 4,654 | \t2,207 | 7,252 | \t3,939 |
| Canada | 705 | 520 | \t 2,147 | \t1,026 | 2,852 | \t1,546 |
| Total\tNorth\tAmerica | \t 3,303 | \t2,252 | \t 6,801 | \t3,233 | \t10,104 | \t5,485 |

(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,	other	than	a	preliminary	review	of	local	records,	little	investigation	of	record	title	is	made	at	the	time	of	acquisitions	of undeveloped	properties.	Investigations,	which	generally	include	a	title	opinion	of	outside	counsel,	are	made	prior	to	the	consummation	of	an	acquisition	of	producing properties	and	before	commencement	of	drilling	operations	on	undeveloped	properties.

# EnLink	Properties

EnLink's	assets	are	comprised	of	systems	and	other	assets	located	in	four	primary	regions:

•Texas	–	The	Texas	assets	consist	of	transmission	pipelines	with	a	capacity	of	approximately	1.3	Bcf/d,	processing	facilities	with	a	total	processing	capacity of	approximately	1.4	Bcf/d	and	gathering	systems	with	total	capacity	of	approximately	2.9	Bcf/d.

•	 Oklahoma	–	The	Oklahoma	assets	consist	of	processing	facilities	with	a	total	processing	capacity	of	approximately	550	MMcf/d	and	gathering	systems	with total	capacity	of	approximately	605	MMcf/d.

•Louisiana	–	The	Louisiana	assets	consist	of	transmission	pipelines	with	a	capacity	of	approximately	3.5	Bcf/d,	processing	facilities	with	a	total	processing capacity	of	approximately	1.7	Bcf/d,	gathering

systems	with	total	capacity	of	approximately	510	MMcf/d,	660	miles	of	liquids	transport	lines	and	four	fractionation	assets	with	total	fractionation	capacity of	198	MBbls/d.

•	 Crude	and	Condensate	–	The	Crude	and	Condensate	assets	consist	of	approximately	350	miles	of	crude	oil	and	condensate	pipelines	with	total	capacity	of approximately	101	MBbls/d,	900	MBbls	of	above	ground	storage	and	eight	condensate	stabilization	and	natural	gas	compression	stations	with	combined capacities	of	approximately	36	MBbls/d	of	condensate	stabilization	and	780	MMcf/d	of	natural	gas	compression.

# Marketing	and	Midstream	Activities

# Midstream	Operations

Comprising	approximately	98%	of	our	2015	midstream	operating	profit,	EnLink	is	the	primary	component	of	our	midstream	operations.	EnLink's	operations primarily	focus	on	providing	midstream	energy	services,	which	consist	of	gathering,	transmission,	processing,	fractionation	and	marketing,	to	producers	of	natural	gas, NGLs,	crude	oil	and	condensate,	including	Devon.	EnLink	connects	the	wells	of	natural	gas	producers	in	its	market	areas	to	its	gathering	systems,	processes	natural	gas for	the	removal	of	NGLs,	fractionates	NGLs	into	purity	products	and	markets	those	products	for	a	fee,	transports	natural	gas	and	ultimately	provides	natural	gas	to	a variety	of	markets.	Furthermore,	EnLink	purchases	natural	gas	from	natural	gas	producers	and	other	supply	sources	and	sells	that	natural	gas	to	utilities,	industrial consumers,	other	marketers	and	pipelines.

# 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	periodically	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	2016,	our	production	was	sold	under	the	following	contract	terms.

|  | Short-Term |  | Long-Term |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Variable | Fixed | Variable | Fixed |
| Oil\tand\tbitumen | 72% | \t— | 28% | \t— |
| Natural\tgas | 36% | 4% | 60% | \t— |
| NGLs | 52% | 10% | 38% | \t— |

# 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, 2015,	we	were	committed	to	deliver	the	following	fixed	quantities	of	production.

|  | Total | Less	Than	1	Year | 1-3	Years | 3-5	Years | More	Than	5	Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(MMBbls) | 145 | 38 | 56 | 46 | 5 |
| Natural\tgas\t(Bcf) | \t\t\t\t\t\t\t736 | \t\t\t\t\t\t\t\t439 | \t\t\t\t\t\t\t\t\t287 | \t\t\t\t\t\t\t\t\t10 | \t\t\t\t\t\t\t\t— |
| NGLs\t(MMBbls) | 12 | 12 | — | — | — |
| Total\t(MMBoe) | 280 | 123 | 104 | 48 | 5 |

We	expect	to	fulfill	our	delivery	commitments	primarily	with	production	from	our	proved	developed	reserves.	In	certain	regions,	such	as	in	our	Heavy	Oil operation	in	Canada,	we	expect	to	fulfill	these	longer-term	delivery	commitments	with	our	proved	undeveloped	reserves.

Generally,	our	proved	reserves	have	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 may	be	subject	to	deficiency	payments.	In	such	instances,	we	can	and	may	use	spot	market	purchases	to	satisfy	the	commitments.

# Customers

During	2015,	2014	and	2013,	no	purchaser	accounted	for	over	10%	of	our	consolidated	operating	revenues.

# 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	integration	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,	state	conservation	laws	generally	limit	the	venting	or	flaring	of	natural	gas	and	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	by	the	federal	government	and	administered	by	the	Bureau	of	Land	Management	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.	The	federal	government	has	been	particularly	active	in	recent	years	in evaluating	and,	in	some	cases,	promulgating	new	rules	and	regulations	regarding	competitive	lease	bidding,	venting	and	flaring	and	royalty	payment	obligations	for production	from	federal	lands.

# Royalties	and	Incentives	in	Canada

The	royalty	system	in	Canada	is	a	significant	factor	in	the	profitability	of	Canadian	oil	and	gas	production.	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.	The	regulations	prescribe	lower	royalty	rates	for	oil	sands	projects	until	allowable	capital	costs	have	been	recovered. Recently,	the	province	of	Alberta	released	the	findings	of	the	Royalty	Review	Advisory	Panel,	which	concluded	that	the	royalties	for	oil	sands	were	appropriate	and should	be	maintained	in	the	new	royalty	system	to	be	implemented	in	2017.

# Marketing	in	Canada

Any	oil	or	gas	export	that	exceeds	a	certain	duration	or	a	certain	quantity	requires	an	exporter	to	obtain	export	authorizations	from	Canada's	National	Energy Board.	The	governments	of	Alberta,	British	Columbia	and	Saskatchewan	also	regulate	the	volume	of	natural	gas	that	may	be	removed	from	those	provinces	for consumption	elsewhere.

# Environmental	and	Occupational	Regulations

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.	Environmental	laws	and	regulations	relate	to:

•the	discharge	of	pollutants	into	federal	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;	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.	We	consider	the	costs	of	environmental	protection	and	safety	and	health	compliance	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	will	likely	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.

# Oil,	Gas	and	NGL	Prices	Are	Volatile

Our	financial	results	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.	Since	the	second	half	of	2014,	there	has	been	a	significant	decline	in	oil,	gas	and	NGL	prices,	which	has	adversely affected	our	2015	operating	results	and	contributed	to	a	reduction	in	our	anticipated	future	capital	expenditures.	In	addition,	this	decline	in	commodity	prices	has adversely	impacted	our	estimated	proved	reserves	and	resulted	in	substantial	impairments	to	our	oil	and	gas	properties	during	2015.	A	sustained	weakness	or	further deterioration	in	commodity	prices	could	materially	and	adversely	impact	our	business	by	resulting	in,	or	exacerbating,	the	following	effects:

•reducing	the	amount	of	oil,	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	further	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	additional	noncash	write-downs.

Historically,	market	prices	and	our	realized	prices	have	been	volatile	and	are	likely	to	continue	to	be	volatile	in	the	future	due	to	numerous	factors	beyond	our control.	These	factors	include,	but	are	not	limited	to:

•supply	of	and	demand	for	oil,	gas	and	NGLs,	including	consumer	demand	in	emerging	markets,	such	as	China;

•conservation	and	environmental	protection	efforts;

•	 OPEC	production	levels;

•geopolitical	risks;

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

•regional	pricing	differentials;

•differing	quality	of	oil	produced	(i.e.,	sweet	crude	versus	heavy	or	sour	crude);

•differing	quality	and	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;

•the	overall	economic	environment;	and

•governmental	regulations	and	taxes.

# Estimates	of	Oil,	Gas	and	NGL	Reserves	Are	Uncertain

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	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	estimates	of	future	net	revenue,	as	well	as	our	financial	condition	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.

# Future	Exploration	and	Drilling	Results	Are	Uncertain	and	Involve	Substantial	Costs

Our	exploration	and	development	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	drilling	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;

•unexpected	pressure	conditions	or	irregularities	in	reservoir	formations;

•equipment	failures	or	accidents;

•fires,	explosions,	blowouts	and	surface	cratering;

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

•lack	of	access	to	pipelines	or	other	transportation	methods;

•environmental	hazards	or	liabilities;

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

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

A	significant	occurrence	of	one	of	these	factors	could	result	in	a	partial	or	total	loss	of	our	investment	in	a	particular	property,	and	certain	of	these	events, particularly	equipment	failures	or	accidents,	could	impact	third	parties,	including	persons	living	in	proximity	to	our	operations,	our	employees	and	employees	of	our contractors,	leading	to	possible	injuries,	death	or	significant	property	damage.

# Hedging	Limits	Participation	in	Commodity	Price	Increases

We	periodically	enter	into	hedging	activities	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	may	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.

# 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	shares	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	liquidity	problems	and	may	not	be	able	to	meet	their	financial	obligations	to	us,	particularly	if	commodity	prices remain	depressed	or	decline	further.	Any	such	default	by	these	counterparties	could	adversely	impact	our	financial	results.

# 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,	health and	safety,	wildlife	conservation,	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	and	well	operations.	If	permits	are	not	issued,	or	if	unfavorable	restrictions	or	conditions	are	imposed	on	our	drilling	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	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	at	times	in	the	future	could	affect,	our	operations.	Regulatory	developments	could,	among	other	things, restrict	production	levels,	enact	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.	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,	seismic	activity,	income	taxes	and	climate	change	as	discussed	below.

Hydraulic	Fracturing	–	The	U.S.	Environmental	Protection	Agency	("EPA")	and	other	federal	agencies,	including	the	Bureau	of	Land	Management	("BLM") have	made	proposals	that,	if	implemented,	could	either	restrict	the	practice	of	hydraulic	fracturing	or	subject	the	process	to	further	regulation.	For	example,	the	EPA	has also	issued	final	regulations	under	the	federal	Clean	Air	Act	establishing	performance	standards,	including	standards	for	the	capture	of	air	emissions	released	during hydraulic	fracturing	and	proposed	in	April	2015	to	prohibit	the	discharge	of	wastewater	from	hydraulic	fracturing	operations	to	publicly	owned	wastewater	treatment plants.	The	BLM	and	many	states	have	already	adopted	and	more	states	are	considering	adopting	laws	and/or	regulations	that	require	disclosure	of	chemicals	used	in hydraulic	fracturing	and	impose	stringent	permitting,	disclosure	and	well-construction	requirements	on	hydraulic	fracturing	operations.	In	addition,	some	states	and municipalities	have	significantly	limited	drilling	activities	and/or	hydraulic	fracturing,	or	are	considering	doing	so.	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	Department	of	Transportation,	through	the	Pipeline	and	Hazardous	Materials	Safety	Administration	("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.	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	–	Recent	earthquakes	in	north-central	Oklahoma	and	elsewhere	have	prompted	concerns	about	seismic	activity	and	possible	relationships	with	the energy	industry,	specifically	disposal	wells	used	to	inject,	into	the	subsurface,	water	that	is	produced	along	with	oil	and	natural	gas.	Legislative	and	regulatory	initiatives intended	to	address	these	concerns	may	result	in	additional	levels	of	regulation	that	could	limit	or	eliminate	our	ability	to	inject	produced	water	into	certain	disposal wells.	Restrictions	on	such	disposal	wells	could	lead	to	operational	delays,	increase	our	operating	and	compliance	costs	or	otherwise	adversely	affect	our	operations.	In addition,	we	could	be	subject	to	third-party	lawsuits	seeking	alleged	property	damages	as	a	result	of	induced	seismic	activity	in	our	areas	of	operation.

Income	Taxes	–	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.	The	U.S.	President	and	other	policy	makers	have	proposed provisions	that	would,	if	enacted,	make	significant	changes	to	U.S.	tax	laws	applicable	to	us.	One	significant	proposal	that	has	recently	been	considered	at	the	federal level	would	eliminate	the	immediate	deduction	for	intangible	drilling	and	development	costs.	The	adoption	of	this	proposal	or	other	tax	changes	could	have	a	material adverse	effect	on	our	profitability,	financial	condition	and	liquidity.

Climate	Change	–	Policy	makers	in	the	U.S.	and	Canada	are	increasingly	focusing	on	whether	the	emissions	of	greenhouse	gases,	such	as	carbon	dioxide	and methane,	are	contributing	to	harmful	climatic	changes.	Policy	makers	at	both	the	U.S.	federal	and	state	levels	have	introduced	legislation	and	proposed	new	regulations that	are	designed	to	quantify	and	limit	the	emission	of	greenhouse	gases	through	inventories,	limitations	and/or	taxes	on	greenhouse	gas	emissions.	For	example,	both	the EPA	and	the	BLM	have	proposed	regulations	for	the	control	of	methane	emissions,	which	also	include	leak	detection	and	repair	requirements,	for	the	oil	and	gas industry.	Legislative	and	state	initiatives	to	date	have	generally	focused	on	the	development	of	cap-and-trade	and/or	carbon	tax	programs.	A	cap-and-trade	program generally	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.	Carbon	taxes	could likewise	affect	us	by	being	based	on	emissions	from	our	equipment	and/or	emissions	resulting	from	use	of	our	products	by	our	customers.	Although	it	is	not	possible	at this	time	to	predict	how	legislation	or	new	regulations	that	may	be	adopted	to	address	greenhouse	gas	emissions	would	impact	our	business,	any	such	future	laws	and regulations	imposing	reporting	obligations	on,	or	limiting	emissions	of	greenhouse	gases	from,	our	equipment	and	operations	could	require	us	to	incur	costs	to	reduce emissions	of	greenhouse	gases	associated	with	our	operations.	Severe	limitations	on	greenhouse	gas	emissions	could	also	adversely	affect	demand	for	oil	and	natural	gas, which	could	have	a	material	adverse	effect	our	profitability,	financial	condition	and	liquidity.

Currently,	the	Alberta	Government	is	developing	a	new	strategy	on	climate	change	based	on	recommendations	put	forward	by	the	Climate	Change	Advisory Panel.	It	is	expected	that	these	recommendations	will	create	additional	costs	for	the	Canadian	oil	and	gas	industry.	Presently,	it	is	not	possible	to	accurately	estimate	the costs	we	could	incur	to	comply	with	any	law	or	regulations	developed.

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

As	of	December	31,	2015,	we	had	total	consolidated	indebtedness	of	$13.1	billion.	Our	indebtedness	and	other	financial	commitments	have	important consequences	to	our	business,	including,	but	not	limited	to:

•requiring	us	to	dedicate	a	significant	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	assets	sales	and	purchases,	liquidity,	forecasted	production	growth	and	commodity	prices.	A	ratings	downgrade	could	adversely	impact	our	ability to	access	financing	and	trade	credit	and	increase	our	interest	rate	under	any	credit	facility	borrowing	as	well	as	the	cost	of	any	other	future	debt.	A	ratings	downgrade	to a	rating	below	investment-grade	made	by	one	or	more	rating	agencies	could	potentially	require	us	to	post	collateral	under	certain	contractual	arrangements.

# 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.

# 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,	then	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	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	and potential	post-closing	claims	for	indemnification.	Moreover,	the	current	commodity	price	environment	may	result	in	fewer	potential	bidders,	unsuccessful	sales	efforts and	a	higher	risk	that	buyers	may	seek	to	terminate	a	transaction	prior	to	closing.	In	addition,	we	may	not	realize	any	expected	cost	savings	from	asset	dispositions,	in part	because	of	revenue	losses	from	the	divested	properties.

# Insurance	Does	Not	Cover	All	Risks

Our	business	is	hazardous	and	is	subject	to	all	of	the	operating	risks	normally	associated	with	the	exploration,	development,	production,	processing	and transportation	of	oil,	natural	gas	and	NGLs.	Such	risks	include	potential	blowouts,	cratering,	fires,	loss	of	well	control,	mishandling	of	fluids	and	chemicals	and	possible underground	migration	of	hydrocarbons	and	chemicals.	The	occurrence	of	any	of	these	risks	could	result	in	environmental	pollution,	damage	to	or	destruction	of	our property,	equipment	and	natural	resources,	injury	to	people	or	loss	of	life.	Additionally,	for	our	non-operated	properties,	we	generally	depend	on	the	operator	for operational	safety	and	regulatory	compliance.

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,	insurance	coverage	is	generally	not	available	to	us	for	pollution	events	that	are	considered	gradual,	and	we	have limited	or	no	insurance	coverage	for	certain	risks	such	as	political	risk,	war	and	terrorism.	Our	insurance	does	not	cover	penalties	or	fines	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.

# 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	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	natural	gas	production	and	to	transport	our	oil,	natural	gas	and	NGL	production	to	downstream markets.	Such	midstream	systems	include	EnLink's	systems,	as

well	as	other	systems	operated	by	us	or	third	parties.	Regardless	of	who	operates	the	midstream	systems	we	rely	upon,	a	portion	of	our	production	in	any	region	may	be interrupted	or	shut	in	from	time	to	time	from	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,	we	and	third	parties	may	be	subject	to	constraints	that	limit our	or	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.

# 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.	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.	They	also	may	have	established strategic	long-term	positions	and	relationships	in	areas	in	which	we	may	seek	new	entry.	As	a	consequence,	we	may	be	at	a	competitive	disadvantage	in	bidding	for assets	or	services.	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.

# Cyber	Attacks	Targeting	Our	Systems	and	Infrastructure	May	Adversely	Impact	Our	Operations

Our	industry	has	become	increasingly	dependent	on	digital	technologies	to	conduct	daily	operations.	Concurrently,	the	industry	has	become	the	subject	of increased	levels	of	cyber-attack	activity.	Cyber	attacks	often	attempt	to	gain	unauthorized	access	to	digital	systems	for	purposes	of	misappropriating	assets	or	sensitive information,	corrupting	data	or	causing	operational	disruption	and	may	be	carried	out	by	third	parties	or	insiders.	The	techniques	utilized	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.	Although	we have	not	suffered	material	losses	related	to	cyber	attacks	to	date,	if	we	were	successfully	attacked,	we	might	incur	substantial	remediation	and	other	costs	or	suffer	other negative	consequences.	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.

# Item	1B.	Unresolved	Staff	Comments

Not	applicable.

# Item	3.	Legal	Proceedings

We	are	involved	in	various	routine	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.

# 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.	On	February	10,	2016,	there	were	8,307	holders	of	record	of	our	common	stock.	We	began	paying	regular	quarterly cash	dividends	on	our	common	stock	in	the	second	quarter	of	1993.	The	following	table	sets	forth	the	quarterly	high	and	low	sales	prices	for	our	common	stock	as reported	by	the	NYSE	during	2015	and	2014,	as	well	as	the	quarterly	dividends	per	share	paid	during	2015	and	2014.

|  | Price	Range	of	Common	Stock<br>								High | Low | Dividends<br>				Per	Share |
| :--- | :--- | :--- | :--- |
| Quarter\tEnded\t2015: |  |  |  |
| December\t31,\t2015 | $48.68 | $28.00 | $0.24 |
| September\t30,\t2015 | $59.80 | $36.01 | $0.24 |
| June\t30,\t2015 | $70.48 | $58.77 | $0.24 |
| March\t31,\t2015 | $67.08 | $56.35 | $0.24 |
| Quarter\tEnded\t2014: |  |  |  |
| December\t31,\t2014 | $68.80 | $51.76 | $0.24 |
| September\t30,\t2014 | $80.01 | $67.58 | $0.24 |
| June\t30,\t2014 | $80.63 | $66.75 | $0.24 |
| March\t31,\t2014 | $66.95 | $57.67 | $0.22 |

In	February	2016,	we	reduced	our	quarterly	common	stock	dividend	75%	to	$0.06	per	share.

# 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,	our new	peer	group	and	our	old	peer	group	of	companies.	Our	new	peer	group	includes	Anadarko	Petroleum	Corporation,	Apache	Corporation,	Chesapeake	Energy Corporation,	Concho	Resources,	Inc.,	Continental	Resources,	Inc.,	ConocoPhillips,	Encana	Corporation,	EOG	Resources,	Inc.,	Hess	Corporation,	Marathon	Oil Corporation,	Murphy	Oil	Corporation,	Noble	Energy,	Inc.,	Occidental	Petroleum	Corporation	and	Pioneer	Natural	Resources	Company.	Concho	Resources,	Inc.	and Continental	Resources,	Inc.	replaced	Newfield	Exploration	Company	and	Talisman	Energy,	Inc.	from	our	old	peer	group.	The	graph	was	prepared	assuming	$100	was invested	on	December	31,	2010	in	Devon's	common	stock,	the	S&P	500	Index	and	the	peer	groups,	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	2015.

| Period | Total	Number	of<br>Shares	Purchased^	(1) | Average	Price	Paid<br>per	Share |
| :--- | :--- | :--- |
| October\t1\t–\tOctober\t31 | 5,404 | $41.78 |
| November\t1\t–\tNovember\t30 | 128,025 | $45.99 |
| December\t1\t–\tDecember\t31 | 113,085 | $44.94 |
| Total | 246,514 | $45.41 |

(1) Share	repurchases	represent	shares	received	by	us	from	employees	and	directors	for	the	payment	of	personal	income	tax	withholding	on	restricted	stock	vesting.

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	71,500	shares	of	our	common	stock	in	2015,	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	the	Devon	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,	Sun	Life	Assurance	Company	of	Canada.	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	2015,	there	were	no	shares	purchased	by	Canadian	employees.

# 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.

|  |  |  | Year	Ended	December	31, | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | 2015 | 2014 | 2013 | 2012 | 2011 |
|  |  |  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | Operating\trevenues | $13,145 | $19,566 | $10,397 | $9,501 | $11,445 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | \t(1) | $(15,203) | $1,691 | $(20) | $(185) | $2,134 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tDevon | Earnings\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tDevon | $(14,454) | $1,607 | $(20) | $(185) | $2,134 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tBasic | Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tBasic | $(35.55) | $3.93 | $(0.06) | $(0.47) | $5.12 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tDiluted | Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tDiluted | $(35.55) | $3.91 | $(0.06) | $(0.47) | $5.10 |
| Cash\tdividends\tper\tcommon\tshare |  | $0.96 | $0.94 | $0.86 | $0.80 | $0.67 |
| Weighted\taverage\tcommon\tshares\toutstanding\t–\tBasic | Weighted\taverage\tcommon\tshares\toutstanding\t–\tBasic | 412 | 409 | 406 | 404 | 417 |
| Weighted\taverage\tcommon\tshares\toutstanding\t–\tDiluted | Weighted\taverage\tcommon\tshares\toutstanding\t–\tDiluted | 412 | 411 | 406 | 404 | 418 |
| \t(1)\nTotal\tassets |  | $29,532 | $50,637 | $42,877 | $43,326 | $41,117 |
| (2)\nLong-term\tdebt |  | $12,137 | $9,830 | $7,956 | $8,455 | $5,969 |
| Stockholders'\tequity | Stockholders'\tequity | $10,989 | $26,341 | $20,499 | $21,278 | $21,430 |

(1) During	2015,	we	recorded	noncash	asset	impairments	totaling	$20.8	billion.	During	2014,	2013	and	2012,	we	recorded	noncash	asset	impairments	totaling	$2.0	billion	in	each	year.

(2) Debt	balances	at	December	31,	2015	and	2014	include	$3.1	billion	and	$2.0	billion,	respectively,	of	EnLink	debt	that	is	non-recourse	to	Devon.

# 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	2015	Results

By	executing	on	our	strategy	outlined	in	"Items	1	and	2.	Business	and	Properties"	of	this	report,	we	strive	to	optimize	value	for	our	shareholders	by	growing	cash flow,	earnings,	production	and	reserves,	all	on	a	per	debt-adjusted	share	basis.	During	2015,	we	had	several	key	operating	and	financial	achievements:

•	 Delivered	record	crude	oil	and	bitumen	production,	representing	41%	of	our	total	production

•	 Achieved	top-quartile	well	results	in	the	Delaware	Basin	of	southeast	New	Mexico

•Exceeded	35	MBbls	per	day	nameplate	capacity	at	Jackfish	3

•Expanded	and	improved	our	positions	in	the	STACK	and	Powder	River	Basin	areas	with	two	separate	acquisitions	completed	for	approximately	$2	billion of	cash	and	common	equity	in	late	2015	and	early	2016

•Sold	EnLink	units	and	dropped	our	interest	in	VEX	to	EnLink,	generating	$821	million	in	total	cash	inflows	to	Devon

•	 Realized	$2.4	billion	in	cash	settlements	on	our	commodity	hedge	positions

•	 Reduced	LOE	$228	million,	or	10%,	primarily	through	cost	reduction	initiatives

•Exited	2015	with	$4.7	billion	of	liquidity	consisting	of	$2.3	billion	of	cash	and	$2.4	billion	of	capacity	on	our	Senior	Credit	Facility.	We	have	managed	our debt	maturity	schedule	to	provide	maximum	flexibility	with	near-term	liquidity;	we	have	no	major	long-term	debt	maturities	until	December	2018.

In	spite	of	these	and	other	operating achievements,	weak	commodity	prices	made	2015	a challenging	year	for	the	upstream	energy	sector, including	us.	As	presented	in	the	graph	at	left,	the significant	decline	in	crude	oil	prices	that	began	in	the third	quarter	of	2014	continued	throughout	2015	and weakened	further	during	the	first	two	months	of 2016.	The	2015	WTI	crude	oil	index	was approximately	50%	lower	than	the	2014	average.	The downward	pressure	on	oil	prices	has	largely	resulted from	increased	global	supply,	from	both	OPEC	and non-OPEC	countries,	and	a	global	economic slowdown	that	has	decreased	demand	for	oil. Similarly,	the	Henry	Hub	natural	gas	and	OPIS	Mont Belvieu,	Texas	indices	decreased	significantly	since the	end	of	2014	as	a	result	of	an	imbalance	between supply	and	demand	across	North	America.

As	a	result	of	these	large	commodity	price	declines	and	in	spite	of	our	operating	achievements,	we	recognized	$21	billion	of	noncash	asset	impairments throughout	2015	that	have	negatively	impacted	our	financial	earnings	and	retained	earnings.	Additionally,	our	core	earnings,	core	earnings	per	share	and	operating	cash flow	for	2015	decreased	significantly	compared	to	2014.	Key	measures	of	our	financial	performance	in	2015	are	summarized	in	the	following	table:

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  | (Millions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) | (Millions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) | (Millions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $(14,454) | \t N/M | $1,607 | \t N/M | $(20) |
| Core\tearnings\tattributable\tto\tDevon^\t(1) | $1,044 | -48% | $2,017 | +16% | $1,734 |
| Earnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $(35.55) | \t N/M | $3.91 | \t N/M | $(0.06) |
| Core\tearnings\tper\tshare\tattributable\tto\tDevon^\t(1) | $2.52 | -49% | $4.91 | +15% | $4.26 |
| Core\tproduction\t(MBoe/d)^\t(2) | 560 | +15% | 489 | +16% | 423 |
| Total\tproduction\t(MBoe/d) | 680 | +1% | 673 | -3% | 693 |
| Realized\tprice\tper\tBoe\t^(3) | $21.68 | -46% | $40.33 | +20% | $33.70 |
| Operating\tcash\tflow | $5,383 | -10% | $5,981 | +10% | $5,436 |
| Capitalized\tcosts,\tincluding\tacquisitions | $6,233 | -54% | $13,559 | \t +104% | $6,643 |
| Shareholder\tand\tnoncontrolling\tinterests\tdistributions | $650 | +5% | $621 | +78% | $348 |
| Reserves\t(MMBoe) | 2,182 | -21% | 2,754 | -7% | \t 2,963 |

(1) Core	earnings	and	core	earnings	per	share	attributable	to	Devon	are	financial	measures	not	prepared	in	accordance	with	accounting	principles	generally	accepted	in the	U.S.	("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) Core	production	is	comprised	of	production	in	our	key	operating	areas	as	outlined	and	discussed	in	"Items	1	and	2.	Business	and	Properties"	of	this	report.

(3) 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.	However,	current	market	fundamentals	indicate	prices	for	crude	oil	and	natural	gas	will	continue	to	be	depressed	for	much	of	2016.	Although	changes	in	OPEC production	strategies,	macro-economic	forecasts,	geopolitical	risks	or	other	factors	could	impact	current	forecasts,	we	anticipate	weak	oil	and	natural	gas	prices throughout	the	majority	of	2016.

In	2015,	Devon	marked	its	44th	anniversary	in	the	oil	and	gas	business	and	its	27th	year	as	a	public	company.	As	an	established	company	with	a	strong leadership	team,	we	have	experience	operating	in	periods	of	weak	commodity	prices.	With	our	focused	strategy	and	portfolio	of	quality	assets,	we	are	prepared	to successfully	navigate	the	current	pricing	challenges	and	ensure	our	long-term	financial	strength.

Specifically,	after	completing	the	STACK	acquisition,	we	began	2016	with	approximately	$3.9	billion	of	liquidity,	consisting	of	cash	and	borrowing	capacity under	our	credit	facility.	We	expect	to	bolster	this	liquidity	in	2016	by	monetizing	our	interest	in	Access	Pipeline	and	other	non-core	upstream	assets	for	targeted	total proceeds	of	$2	billion	to	$3	billion.

While	we	will	continue	to	operate	and	develop	our	premier	portfolio	of	assets,	we	are	committed	to	protecting	our	balance	sheet	and	managing	our	capital programs	to	be	within	our	cash	inflows,	including	Access	Pipeline	proceeds.	As	a	result,	we	are	significantly	reducing	our	capital	investment	in	response	to	lower commodity	prices.	We	plan	to	invest	$900	million	to	$1.1	billion	in	our	upstream	programs,	a	decrease	of	roughly	75%	compared	to	our	2015	capital.

We	are	also	committed	to	reducing	our	G&A	and	field-level	operating	costs	commensurate	with	our	reduced,	but	focused,	activity	level.	In	the	first	quarter	of 2016,	we	announced	plans	to	significantly	reduce	our

workforce	and	other	G&A	costs	to	better	align	with	the	activity	level	of	our	core	business	in	the	current	commodity	price	environment.	The	reductions	are	expected	to decrease	gross	G&A	costs	by	approximately	$400	million	to	$500	million	on	an	annualized	basis,	excluding	associated	employee	severance	and	other	restructuring costs.	Following	a	number	of	cost-reduction	initiatives	culminating	with	our	February	2016	workforce	reduction,	we	are	expecting	a	$700	million	to	$900	million reduction	in	operating	and	G&A	costs	on	an	annualized	basis.

We	estimate	we	will	incur	approximately	$225	million	to	$275	million	of	restructuring	costs	as	a	result	of	the	workforce	reduction.	We	expect	to	recognize	the majority	of	these	restructuring	costs	in	the	first	quarter	of	2016	and	will	recognize	the	remaining	costs	throughout	2016	until	our	planned	divestiture	transactions	have closed	and	further	workforce	reductions	occur.

# Results	of	Operations

# Oil,	Gas	and	NGL	Production

|  | 2015 | Change | Year	Ended	December	31,<br>2014 | Change | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Oil\t(MBbls/d) |  |  |  |  |  |
| Delaware\tBasin | 39 | +48% | 26 | +33% | 20 |
| STACK | 6 | +6% | 6 | +23% | 5 |
| Eagle\tFord | 66 | +66% | 39 | \t N/M | — |
| Rockies\tOil | 15 | +39% | 10 | -1% | 11 |
| Heavy\tOil | 27 | +3% | 26 | -7% | 28 |
| Barnett\tShale | 1 | -38% | 2 | -2% | 2 |
| Core\tassets | 154 | +42% | 109 | +66% | 66 |
| Other\t^(1) | 37 | -25% | 49 | -5% | 51 |
| Total | 191 | +20% | 158 | +36% | 117 |
| Bitumen\t(MBbls/d) |  |  |  |  |  |
| Heavy\tOil | 84 | +51% | 56 | +8% | 51 |
| Gas\t(MMcf/d) |  |  |  |  |  |
| Delaware\tBasin | 73 | +9% | 67 | +16% | 57 |
| STACK | 226 | -3% | 234 | +14% | 205 |
| Eagle\tFord | 148 | +70% | 87 | \t N/M | — |
| Rockies\tOil | 40 | -17% | 47 | -22% | 61 |
| Heavy\tOil | 22 | -5% | 23 | -19% | 28 |
| Barnett\tShale | 797 | -12% | 909 | -11% | \t1,025 |
| Core\tassets | \t1,306 | -4% | \t1,367 | -1% | \t1,376 |
| Other\t^(1) | 304 | -45% | 553 | -46% | \t1,017 |
| Total | \t1,610 | -16% | \t1,920 | -20% | \t2,393 |
| NGLs\t(MBbls/d) |  |  |  |  |  |
| Delaware\tBasin | 9 | +24% | 8 | +24% | 6 |
| STACK | 21 | -8% | 22 | +33% | 17 |
| Eagle\tFord | 25 | \t +115% | 11 | \t N/M | — |
| Rockies\tOil | 1 | +33% | 1 | +27% | 1 |
| Barnett\tShale | 48 | -12% | 55 | -1% | 55 |
| Core\tassets | 104 | +7% | 97 | +23% | 79 |
| Other\t^(1) | 32 | -25% | 42 | -11% | 47 |
| Total | 136 | -2% | 139 | +10% | 126 |
| Combined\t(MBoe/d) |  |  |  |  |  |
| Delaware\tBasin | 61 | +35% | 45 | +27% | 36 |
| STACK | 64 | -4% | 67 | +21% | 56 |
| Eagle\tFord | 115 | +75% | 65 | \t N/M | — |
| Rockies\tOil | 23 | +29% | 18 | -6% | 19 |
| Heavy\tOil | 115 | +34% | 86 | +2% | 85 |
| Barnett\tShale | 182 | -13% | 208 | -9% | 228 |
| Core\tassets | 560 | +14% | 489 | +15% | 424 |
| Other\t^(1) | 120 | -35% | 184 | -32% | 269 |
| Total | 680 | +1% | 673 | -3% | 693 |

(1) Other	assets	are	located	primarily	in	the	Midland	Basin,	east	Texas,	Granite	Wash	and	Mississippian-Lime	areas.	Substantially	all	of	these	properties	have	been identified	for	divestiture	in	2016.

# Oil,	Gas	and	NGL	Pricing

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015^\t(1) | Change | 2014\t^(1) | Change | 2013\t^(1) |
| Oil\t(per\tBbl) |  |  |  |  |  |
| U.S. | $44.01 | -49% | $85.64 | -9% | $94.52 |
| Canada | $30.58 | -55% | $68.14 | -1% | $69.18 |
| Total | $42.12 | -49% | $82.47 | -4% | $86.02 |
| Bitumen\t(per\tBbl) |  |  |  |  |  |
| Canada | $23.41 | -58% | $55.88 | +16% | $48.04 |
| Gas\t(per\tMcf) |  |  |  |  |  |
| U.S. | $2.17 | -45% | $3.92 | +27% | $3.10 |
| Canada\t^(2) | $0.67 | -82% | $3.64 | +19% | $3.05 |
| Total | $2.14 | -45% | $3.90 | +26% | $3.09 |
| NGLs\t(per\tBbl) |  |  |  |  |  |
| U.S. | $9.32 | -62% | $24.46 | -5% | $25.75 |
| Canada | $— | \t N/M | $50.52 | +9% | $46.17 |
| Total | $9.32 | -63% | $24.89 | -9% | $27.33 |
| Combined\t(per\tBoe) |  |  |  |  |  |
| U.S. | $21.12 | -44% | $37.96 | +20% | $31.59 |
| Canada | $24.46 | -54% | $53.11 | +33% | $39.91 |
| Total | $21.68 | -46% | $40.33 | +20% | $33.70 |

(1) Prices	presented	exclude	any	effects	of	oil,	gas	and	NGL	derivatives.

(2) The	reported	Canadian	gas	volumes	include	12,	21	and	25	MMcf	per	day	for	the	years	ended	2015,	2014	and	2013,	respectively,	that	are	produced	from	certain	of our	leases	and	then	transported	to	our	Jackfish	operations	where	the	gas	is	used	as	fuel.	However,	the	revenues	and	expenses	related	to	this	consumed	gas	are eliminated	in	our	consolidated	financial	results.	With	the	sale	of	the	vast	majority	of	the	Canadian	gas	business	in	the	second	quarter	of	2014,	the	eliminated	gas revenues	subsequently	impacted	our	gas	price	more	significantly.

# Commodity	Sales

The	volume	and	price	changes	in	the	tables	above	caused	the	following	changes	to	our	oil,	gas	and	NGL	sales.

|  | Oil | Bitumen | Gas | NGLs | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| 2013\tsales | $3,668 | $902 | $2,698 | $1,254 | $8,522 |
| Change\tdue\tto\tvolumes | 1,311 | 76 | (533) | 131 | 985 |
| Change\tdue\tto\tprices | (206) | 160 | 572 | (123) | 403 |
| 2014\tsales | $4,773 | $1,138 | $2,737 | $1,262 | $9,910 |
| Change\tdue\tto\tvolumes | 976 | 584 | (443) | (23) | 1,094 |
| Change\tdue\tto\tprices | (2,813) | (1,000) | (1,034) | (775) | (5,622) |
| 2015\tsales | $2,936 | $722 | $1,260 | $464 | $5,382 |

Volumes	2015	vs.	2014	Oil,	gas	and	NGL	sales	increased	due	to	volumes	in	2015	because	of	strong	production	growth	from	our	U.S.	oil	properties.	The	growth was	primarily	driven	by	the	continued	development	of	our	Eagle	Ford,	Delaware	Basin	and	Rockies	Oil	properties.	Additionally,	our	bitumen	production	increased primarily	due	to	Jackfish	3	coming	on-line	late	in	the	third	quarter	of	2014	and	reaching	nameplate	capacity	in	the	third	quarter	of	2015.	Lower	royalties	resulting	from the	significant	price	decrease	also	increased	our	heavy

oil	production.	The	increases	were	partially	offset	by	a	decrease	in	our	gas	production,	which	resulted	primarily	from	asset	divestitures	in	2014	and	natural	reservoir declines.

Volumes	2014	vs.	2013	Oil,	gas	and	NGL	sales	increased	due	to	volumes	primarily	because	of	a	66%	increase	in	our	core	assets	oil	production.	Such	growth resulted	from	our	Eagle	Ford	properties	and	the	continued	development	of	our	properties	in	the	Delaware	Basin.	In	addition,	we	continued	to	grow	our	NGL	production from	the	Delaware	Basin	and	STACK,	which	resulted	in	$131	million	of	additional	sales.	Bitumen	sales	increased	due	to	development	of	our	Jackfish	thermal	heavy	oil projects	in	Canada,	including	Jackfish	3	which	had	first	sales	in	2014.	These	increases	were	partially	offset	by	a	20%	decrease	in	our	2014	gas	production,	which	was impacted	by	our	asset	divestitures	and	natural	declines.

Prices	2015	vs.	2014	Oil,	gas	and	NGL	sales	decreased	in	2015	as	a	result	of	significantly	lower	prices	for	all	commodities.	The	decrease	in	oil	and	bitumen	sales primarily	resulted	from	significantly	lower	average	WTI	crude	oil	index	prices,	which	were	approximately	50%	lower	in	2015	as	compared	to	2014.	The	decreases	in	gas and	NGL	sales	were	driven	by	lower	North	American	regional	index	prices	upon	which	our	gas	sales	are	based	and	lower	NGL	prices	at	the	Mont	Belvieu,	Texas	hub.

Prices	2014	vs.	2013	Oil,	gas	and	NGL	sales	increased	primarily	because	of	a	20%	increase	in	our	realized	prices	without	hedges.	Our	gas	sales	were	the	most significantly	impacted.	The	change	in	our	realized	gas	price	was	largely	due	to	higher	North	American	regional	index	prices	upon	which	our	gas	sales	are	based. Additionally,	our	bitumen	sales	increased	as	a	result	of	a	16%	increase	in	our	realized	price,	as	a	result	of	tighter	bitumen	and	heavy	oil	differentials.	These	increases were	partially	offset	by	lower	oil	and	NGL	realized	prices	resulting	from	lower	WTI	crude	oil	index	prices	and	lower	NGL	prices	at	the	Mont	Belvieu,	Texas	hub.

# Oil,	Gas	and	NGL	Derivatives

The	following	tables	provide	financial	information	associated	with	our	oil,	gas	and	NGL	hedges.	The	first	table	presents	the	cash	settlements	and	fair	value	gains and	losses	recognized	as	components	of	our	revenues.	The	subsequent	tables	present	our	oil,	gas	and	NGL	prices	with	and	without	the	effects	of	the	cash	settlements. The	prices	do	not	include	the	effects	of	fair	value	gains	and	losses.

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Cash\tsettlements: |  |  |  |
| Oil\tderivatives | $2,083 | $90 | $55 |
| Gas\tderivatives | 333 | (36) | 139 |
| NGL\tderivatives | — | 1 | 1 |
| Total\tcash\tsettlements | 2,416 | 55 | 195 |
| Gains\t(losses)\ton\tfair\tvalue\tchanges: |  |  |  |
| Oil\tderivatives | (1,687) | \t 1,721 | (243) |
| Gas\tderivatives | (226) | 213 | (139) |
| NGL\tderivatives | — | — | (4) |
| Total\tgains\t(losses)\ton\tfair\tvalue\tchanges | (1,913) | \t 1,934 | (386) |
| Oil,\tgas\tand\tNGL\tderivatives | $503 | $1,989 | $(191) |

|  |  | Year	Ended	December	31,	2015 | Year	Ended	December	31,	2015 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Oil\n(Per\tBbl) | Bitumen\n(Per\tBbl) | Gas\n(Per\tMcf) | NGLs\n(Per\tBbl) | Boe\n(Per\tBoe) |
| Realized\tprice\twithout\thedges | $ 42.12 | $ 23.41 | $2.14 | $9.32 | $21.68 |
| Cash\tsettlements\tof\thedges | 29.88 | — | 0.57 | — | 9.74 |
| Realized\tprice,\tincluding\tcash\tsettlements | $ 72.00 | $ 23.41 | $2.71 | $9.32 | $31.42 |

|  |  | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2014 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Oil\n(Per\tBbl) | Bitumen\n(Per\tBbl) | Gas\n(Per\tMcf) | NGLs\n(Per\tBbl) | Boe\n(Per\tBoe) |
| Realized\tprice\twithout\thedges | $ 82.47 | $ 55.88 | $3.90 | $ 24.89 | $40.33 |
| Cash\tsettlements\tof\thedges | 1.56 | — | (0.05) | 0.02 | 0.22 |
| Realized\tprice,\tincluding\tcash\tsettlements | $ 84.03 | $ 55.88 | $3.85 | $ 24.91 | $40.55 |
|  |  | Year\tEnded\tDecember\t31,\t2013 | Year\tEnded\tDecember\t31,\t2013 |  |  |
|  | Oil | Bitumen | Gas | NGLs | Boe |

Cash	settlements	as	presented	in	the	tables	above	represent	realized	gains	or	losses	related	to	these	various	instruments.	A	summary	of	our	open	commodity derivative	positions	is	included	in	Note	3	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.	Our	oil,	gas	and	NGL	derivatives	include	price swaps,	costless	collars,	basis	swaps	and	call	options.	To	facilitate	a	portion	of	our	price	swaps,	we	sold	gas	and	oil	call	options	for	2015	through	2016.	The	call	options give	counterparties	the	right	to	purchase	production	at	a	predetermined	price.

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	relationships	between	contract	prices	and	the	associated	forward curves.	Including	the	cash	settlements	discussed	above,	our	oil,	gas	and	NGL	derivatives	generated	net	gains	in	2015	and	2014	and	incurred	a	net	loss	in	2013.

# Marketing	and	Midstream	Revenues	and	Operating	Expenses

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  |  | (Millions) |  |  |
| Operating\trevenues | $7,260 | -5% | $7,667 | \t +271% | $2,066 |
| Product\tpurchases | (6,028) | -8% | (6,540) | \t +382% | (1,356) |
| Operations\tand\tmaintenance\texpenses | (392) | +43% | (275) | +40% | (197) |
| Operating\tprofit | $840 | -1% | $852 | +66% | $513 |
| Devon\tprofit | $14 | -84% | $88 | -5% | $93 |
| EnLink\tprofit | 826 | +8% | 764 | +82% | 420 |
| Total\tprofit | $840 | -1% | $852 | +66% | $513 |

2015	vs.	2014	Marketing	and	midstream	operating	profit	changes	were	largely	driven	by	a	full	year	of	EnLink's	legacy	asset	operations	compared	to	prior	year	and facility	expansions	coming	online	in	late	2014,	along	with	assets	acquired	during	2015.	The	change	was	offset	by	a	decrease	in	Devon's	marketing	activities	due	to	a decrease	in	commodity	prices.

2014	vs.	2013	Marketing	and	midstream	operating	profit	largely	increased	as	a	result	of	higher	prices	and	volumes,	partially	offset	by	higher	operations	and maintenance	expenses.	Of	the	$339	million	increase,	$344	million	was	attributed	to	EnLink's	operations.	Higher	profits	from	EnLink's	Texas	segment,	which	includes the	Bridgeport	facility,	and	Louisiana	segment	were	the	largest	drivers	of	the	increase.	The	Louisiana	segment	operating	profit	increased	because	of	acquisitions	and completions	of	additional	pipelines.

Devon's	marketing	activities	were	the	primary	driver	of	the	increases	in	both	operating	revenues	and	product	purchases.	The	higher	marketing	revenues	and product	purchases	are	primarily	due	to	commitments	we	entered	into	to	secure	capacity	on	downstream	oil	pipelines.	Marketing	activities	of	EnLink	also	contributed	to these	increases.

# Lease	Operating	Expenses

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  | (Millions,\texcept\tper\tBoe\tamounts) | (Millions,\texcept\tper\tBoe\tamounts) |  |  |
| LOE: |  |  |  |  |  |
| U.S. | $1,551 | -0% | $1,559 | +24% | $1,257 |
| Canada | 553 | -28% | 773 | -24% | \t 1,011 |
| Total | $2,104 | -10% | $2,332 | +3% | $2,268 |
| LOE\tper\tBoe: |  |  |  |  |  |
| U.S. | $7.52 | +0% | $7.52 | +13% | $6.65 |
| Canada | $13.18 | -34% | $20.10 | +27% | $15.78 |
| Total | $8.48 | -11% | $9.49 | +6% | $8.97 |

2015	vs.	2014	LOE	per	Boe	decreased	during	2015	primarily	as	a	result	of	higher	Jackfish	3	volumes,	our	well	optimization	and	cost	reduction	initiatives,	lower royalties	and	changes	in	the	Canadian	to	U.S.	foreign	exchange	rate.	As	Canadian	royalties	decrease,	our	net	production	volumes	increase,	causing	improvements	to	our per-unit	operating	costs.	The	flat	U.S.	rate	is	primarily	related	to	our	2014	non-core	natural	gas	asset	divestitures	and	our	oil	production	growth,	where	projects	generate higher	margins	but	generally	require	a	higher	cost	to	produce	per	unit	than	our	retained	and	divested	gas	projects.

2014	vs.	2013	Our	absolute	LOE	changed	largely	as	a	result	of	our	portfolio	transformation	initiatives,	including	our	February	2014	purchase	of	Eagle	Ford	assets and	our	2014	divestitures	of	non-core	gas	properties	in	the	U.S.	and	Canada.	Higher	volumes	from	development	of	our	Eagle	Ford	assets,	as	well	as	our	Delaware	Basin assets,	caused	U.S.	LOE	to	increase.	This	increase	was	partially	offset	by	the	decrease	resulting	from	the	U.S.	divestitures.	The	Canadian	divestitures	were	the	primary cause	of	the	decrease	in	Canadian	LOE.

Total	LOE	increased	$0.52	per	Boe	primarily	because	of	higher	unit	costs	related	to	our	Canadian	operations.	The	higher	Canadian	unit	costs	largely	resulted	from the	divestiture	of	the	conventional	natural	gas	assets	in	the	second	quarter	of	2014	which	resulted	in	lower	total	volumes	while	retaining	the	relatively	higher-cost	thermal heavy	oil	operations.	Additionally,	higher	Jackfish	royalties	paid	in	2014	also	contributed	to	higher	Canadian	unit	costs.	The	higher	unit	cost	in	the	U.S.	was	primarily related	to	our	liquids	production	growth,	particularly	in	the	Delaware	Basin	and	Mississippian-Woodford	Trend,	where	projects	generate	higher	revenues	but	generally require	a	higher	cost	to	produce	per	unit	than	our	gas	projects.	Additionally,	we	experienced	inflationary	pressures	on	costs	in	certain	operating	areas,	which	also contributed	to	the	higher	LOE	per	Boe.

# General	and	Administrative	Expenses

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  | (Millions,\texcept\tper\tBoe\tamounts) | (Millions,\texcept\tper\tBoe\tamounts) |  |  |
| Gross\tG&amp;A | $1,347 | -2% | $1,369 | +21% | $1,128 |
| Capitalized\tG&amp;A | (372) | -1% | (376) | +2% | (368) |
| Reimbursed\tG&amp;A | (120) | -18% | (146) | +2% | (143) |
| Net\tG&amp;A | $855 | +1% | $847 | +37% | $617 |
| Net\tG&amp;A\tper\tBoe | $3.45 | +0% | $3.45 | +41% | $2.44 |

2015	vs.	2014	Gross	G&A	decreased	during	2015	largely	because	of	a	lower	employee	performance	bonus	pool	and	our	cost	reduction	initiatives.	Furthermore, $22	million	in	one-time	costs	related	to	the	EnLink	and	GeoSouthern	transactions	contributed	to	higher	costs	in	the	first	quarter	of	2014.	These	decreases	were	offset	by an	increase	in	EnLink	G&A	of	approximately	$40	million	primarily	resulting	from	a	workforce	increase	associated	with	EnLink's	2015	acquisitions.	Reimbursed	G&A decreased	subsequent	to	our	2014	asset	divestitures.

2014	vs.	2013	Net	G&A	and	net	G&A	per	Boe	increased	largely	due	to	higher	employee	compensation	and	benefits	and	$22	million	of	2014	costs	related	to	the EnLink	and	GeoSouthern	transactions.	The	higher	employee	compensation	and	benefits	costs	were	primarily	related	to	share-based	awards,	which	cause	our	G&A	to	be higher	in	the	period	in	which	our	annual	share-based	grant	is	made.	The	grant	related	to	our	2013	compensation	cycle	was	made	in	the	first	quarter	of	2014.	The	grant related	to	our	2012	compensation	cycle	was	made	in	the	fourth	quarter	of	2012.	Additionally,	the	expansion	of	our	workforce	as	a	part	of	growing	production	operations at	certain	of	our	key	areas	also	contributed	to	the	increase.

# Production	and	Property	Taxes

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  |  | (Millions) |  |  |
| Production | $198 | -45% | $360 | +31% | $275 |
| Property\tand\tother | \t 190 | +8% | \t 175 | -6% | \t 186 |
| Production\tand\tproperty\ttaxes | $388 | -28% | $535 | +16% | $461 |
| Percentage\tof\toil,\tgas\tand\tNGL\tsales: |  |  |  |  |  |
| Production | 3.7% | +1% | 3.6% | +13% | 3.2% |
| Property\tand\tother | 3.5% | \t +100% | 1.8% | -19% | 2.2% |
| Total | 7.2% | +33% | 5.4% | -0% | 5.4% |

2015	vs.	2014	Our	absolute	production	taxes	decreased	during	2015	primarily	because	of	a	decrease	in	our	U.S.	revenues,	on	which	the	majority	of	our	production taxes	are	assessed.	Property	taxes	as	a	percentage	of	oil,	gas	and	NGL	sales	increased	during	2015	primarily	due	to	ad	valorem	and	other	taxes	that	do	not	change	in direct	correlation	with	oil,	gas	and	NGL	sales.

2014	vs.	2013	Production	and	property	taxes	increased	primarily	as	a	result	of	an	increase	in	our	U.S.	revenues.

# Depreciation,	Depletion	and	Amortization

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  | (Millions,\texcept\tper\tBoe\tamounts) | (Millions,\texcept\tper\tBoe\tamounts) |  |  |
| DD&amp;A: |  |  |  |  |  |
| Oil\tand\tgas\tproperties | $2,580 | -11% | $2,896 | +18% | $2,465 |
| Other\tassets | 549 | +30% | 423 | +34% | 315 |
| Total | $3,129 | -6% | $3,319 | +19% | $2,780 |
| DD&amp;A\tper\tBoe: |  |  |  |  |  |
| Oil\tand\tgas\tproperties | $10.40 | -12% | $11.79 | +21% | $9.75 |
| Other\tassets | 2.21 | +28% | 1.72 | +38% | 1.24 |
| Total | $12.61 | -7% | $13.51 | +23% | $10.99 |

A	description	of	how	DD&A	of	our	oil	and	gas	properties	is	calculated	is	included	in	Note	1	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this report.	Generally,	when	reserve	volumes	are	revised	up	or	down,	the	DD&A	rate	per	unit	of	production	will	change	inversely.	However,	when	the	depletable	base changes,	the	DD&A	rate	moves	in	the	same	direction.	The	per	unit	DD&A	rate	is	not	affected	by	production	volumes.	Absolute	or	total	DD&A,	as	opposed	to	the	rate per	unit	of	production,	generally	moves	in	the	same	direction	as	production	volumes.

2015	vs.	2014	DD&A	from	our	oil	and	gas	properties	decreased	in	2015	compared	to	2014	largely	because	of	the	2014	divestitures	of	certain	U.S.	and	Canadian assets	and	the	oil	and	gas	asset	impairments	recognized	in	2015.	Other	DD&A	increased	primarily	due	to	EnLink's	acquisitions	in	2014	and	2015.

2014	vs.	2013	DD&A	from	our	oil	and	gas	properties	increased	in	2014	largely	because	of	higher	DD&A	rates.	The	higher	rates	resulted	from	our	oil	and	gas drilling	and	development	activities	and	the	GeoSouthern	acquisition,	which	were	partially	offset	by	the	asset	impairments	recognized	in	2013	and	the	2014	asset divestitures.	Other	DD&A	increased	primarily	due	to	the	formation	of	EnLink	in	2014.

# Asset	Impairments

During	2015,	2014	and	2013,	we	recognized	asset	impairments	of	$20.8	billion,	$2.0	billion	and	$2.0	billion,	respectively.	For	discussion	on	asset	impairments, see	Note	5	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Restructuring	Costs

During	2015,	2014	and	2013,	we	recognized	restructuring	costs	of	$78	million,	$46	million	and	$54	million,	respectively.	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.

# Gains	on	Asset	Sales

In	conjunction	with	the	divestiture	of	certain	Canadian	properties,	we	recognized	gains	of	$1.1	billion	in	2014.	For	further	discussion,	see	Note	2	in	"Item	8.

Financial	Statements	and	Supplementary	Data"	of	this	report.

# Net	Financing	Costs

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | Change | 2014 | Change | 2013 |
|  |  |  | (Millions) |  |  |
| Interest\tbased\ton\tdebt\toutstanding | $565 | +6% | $532 | +14% | $466 |
| Early\tretirement\tof\tdebt | \t — | \t N/M | 48 | \t N/M | \t — |
| Capitalized\tinterest | (62) | -11% | (70) | +26% | (56) |
| Other\tfees\tand\texpenses | 20 | -24% | 26 | -1% | 27 |
| Interest\texpense | \t 523 | -3% | \t 536 | +23% | \t 437 |
| Interest\tincome | (6) | -41% | (10) | -49% | (20) |
| Net\tfinancing\tcosts | $517 | -2% | $526 | +26% | $417 |

2015	vs.	2014	Net	financing	costs	decreased	during	2015	primarily	as	a	result	of	the	retirement	premium	and	costs	related	to	the	early	redemption	of	senior	notes in	2014,	which	is	further	discussed	in	Note	13	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.	Interest	on	outstanding	borrowings	increased during	2015	primarily	due	to	an	increase	of	$51	million	in	EnLink	interest	expense	as	a	result	of	an	increase	in	fixed-rate	borrowings,	partially	offset	by	a	$18	million decrease	in	Devon	interest	expense	as	a	result	of	a	decrease	in	its	average	fixed-rate	borrowings.

2014	vs.	2013	Net	financing	costs	increased	primarily	because	of	higher	average	borrowings	resulting	from	the	EnLink	and	GeoSouthern	transactions	and	the 2014	early	retirement	premium	and	costs.

# Income	Taxes

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
| Total\tincome\ttax\texpense\t(benefit)\t(millions) | $(6,065) | $2,368 | $169 |
| Effective\tincome\ttax\trate | (29)% | 58% | \t 113% |

For	discussion	on	income	taxes,	see	Note	7	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	source	and	use	categories	of	our	cash	and	cash	equivalents.

|  | Devon |  | EnLink |  |  | Consolidated |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | 2013\t^(1) |
|  |  |  |  | (Millions) |  |  |  |
| Operating\tcash\tflow | $4,756 | $5,467 | $627 | $514 | $5,383 | $5,981 | $5,436 |
| Sale\tof\tsubsidiary\tunits | 654 | — | — | \t — | 654 | — | — |
| Divestitures\tof\tproperty\tand\tequipment | 106 | 5,120 | 1 | \t — | 107 | 5,120 | 419 |
| Capital\texpenditures | (4,735) | (6,192) | (573) | (796) | (5,308) | (6,988) | (6,502) |
| Acquisitions\tof\tproperty,\tequipment\tand\tbusinesses | (583) | (6,104) | (524) | (358) | (1,107) | (6,462) | (256) |
| Short-term\tinvestment\tactivity,\tnet | — | — | — | \t — | — | — | 2,343 |
| Debt\tactivity,\tnet | 770 | (2,789) | \t 1,061 | 555 | 1,831 | (2,234) | 361 |
| Shareholder\tand\tnoncontrolling\tinterests\tdistributions | (396) | (486) | (254) | (135) | (650) | (621) | (348) |
| EnLink\tand\tGeneral\tPartner\tdistributions | 268 | 158 | (268) | (158) | — | — | — |
| EnLink\tdropdowns | 167 | — | (167) | \t — | — | — | — |
| Stock\toption\tproceeds | 4 | 93 | — | \t — | 4 | 93 | 3 |
| Issuance\tof\tsubsidiary\tunits | — | — | 25 | 410 | 25 | 410 | — |
| Effect\tof\texchange\trate\tand\tother | (131) | 79 | 22 | 36 | (109) | 115 | (27) |
| Net\tchange\tin\tcash\tand\tcash\tequivalents | $880 | $(4,654) | $(50) | $68 | $830 | $(4,586) | $1,429 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $2,292 | $1,412 | $18 | $68 | $2,310 | $1,480 | $6,066 |

(1) 2013	amounts	for	EnLink	consist	of	legacy	Devon	midstream	assets.

# Operating	Cash	Flow

Net	cash	provided	by	operating	activities	continued	to	be	a	significant	source	of	capital	and	liquidity	in	2015.	Our	operating	cash	flow	decreased	10%	during	2015 primarily	due	to	lower	commodity	prices.	The	effects	of	lower	commodity	prices	were	partially	offset	by	the	collection	of	$425	million	of	income	taxes	receivable	in	the first	quarter	of	2015	and	$2.4	billion	of	cash	settlements	associated	with	our	commodity	derivatives	during	2015.

Our	operating	cash	flow	increased	10%	during	2014	primarily	because	of	higher	realized	prices	and	liquids	production	growth,	partially	offset	by	higher	expenses.

Excluding	payments	made	for	acquisitions,	our	consolidated	operating	cash	flow	funded	100%	and	approximately	86%	of	our	capital	expenditures	during	2015 and	2014,	respectively.	In	2015	and	2014,	leveraging	our	liquidity	and	other	capital	resources,	we	also	used	cash	balances,	short-term	debt,	proceeds	from	EnLink transactions	and	divestiture	proceeds	to	fund	our	acquisitions,	dividends	and	capital	requirements.

# Sale	of	Subsidiary	Units

In	early	2015,	we	conducted	an	underwritten	secondary	public	offering	of	26.2	million	common	units	representing	limited	partner	interests	in	EnLink,	raising proceeds	of	$654	million,	net	of	underwriting	discount.	See	Note	17	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

# Divestitures	of	Property	and	Equipment

During	2014,	we	completed	our	Canadian	asset	divestiture	program	and	received	proceeds	of	approximately	$2.9	billion.	Additionally,	we	completed	the divestment	of	certain	of	our	U.S.	assets	and	received	proceeds	of	approximately	$2.2	billion.

During	2013,	we	sold	our	Thunder	Creek	operations	in	Wyoming	for	approximately	$148	million	and	our	Bear	Paw	Basin	assets	in	Havre,	Montana	for approximately	$73	million.	We	also	sold	other	minor	oil	and	gas	assets.

# Capital	Expenditures

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Oil\tand\tgas | $4,577 | $5,735 | $5,710 |
| Midstream | 56 | 348 | 455 |
| Corporate\tand\tother | 102 | 109 | 93 |
| Devon\tcapital\texpenditures | \t 4,735 | \t 6,192 | \t 6,258 |
| EnLink\tcapital\texpenditures | 573 | 796 | 244 |
| Total\tcapital\texpenditures | $5,308 | $6,988 | $6,502 |
| Devon\tacquisitions | $583 | $6,104 | $256 |
| EnLink\tacquisitions | 524 | 358 | — |
| Total\tacquisitions | $1,107 | $6,462 | $256 |

Capital	expenditures	consist	of	amounts	related	to	our	oil	and	gas	exploration	and	development	operations,	our	midstream	operations,	other	corporate	activities and	EnLink	growth	and	maintenance	activities.

The	vast	majority	of	our	capital	expenditures	are	for	the	acquisition,	drilling	and	development	of	oil	and	gas	properties.	In	response	to	lower	commodity	prices, Devon's	2015	capital	program	was	designed	to	be	lower	than	2014,	particularly	compared	to	the	second	half	of	2014	when	oil	prices	began	to	significantly	decline.	This change	is	evidenced	by	a	48%	decrease	in	exploration	and	development	costs	from	the	fourth	quarter	of	2014	to	the	fourth	quarter	of	2015,	as	well	as	a	24%	decrease	in total	capital	expenditures	from	2014	to	2015,	excluding	acquisitions.	Excluding	acquisitions,	oil	and	gas	capital	spending	was	flat	from	2013	to	2014,	primarily	due	to utilization	of	the	drilling	carries	in	2014	from	our	joint	venture	arrangements.

Capital	expenditures	for	Devon's	midstream	operations	are	primarily	for	the	construction	and	expansion	of	oil	and	gas	gathering	facilities	and	pipelines	and	are largely	impacted	by	Devon's	oil	and	gas	drilling	activities.	Our	2014	and	2013	midstream	capital	expenditures	largely	related	to	the	expansion	of	our	Access	Pipeline	in Canada.	The	majority	of	our	midstream	capital	is	incurred	by	EnLink.	EnLink's	2015	capital	expenditures	decreased	compared	to	2014	primarily	as	a	result	of	pipeline construction	and	expansion	projects	that	went	into	service	in	2014.	EnLink's	2013	capital	expenditures	primarily	related	to	expansions	of	plants	serving	the	Barnett Shale	and	Cana-Woodford	Shale.

Acquisition	capital	spend	in	2015	primarily	consisted	of	the	Powder	River	Basin	asset	acquisition	in	the	fourth	quarter.	The	majority	of	the	acquisition	capital	in 2014	related	to	the	GeoSouthern	acquisition	in	the	Eagle	Ford.	EnLink's	acquisitions	in	2015	and	2014	consisted	of	additional	oil	and	gas	pipeline	assets,	including gathering,	transportation	and	processing	facilities.	For	further	discussion	on	EnLink	acquisition	activity,	see	Note	2	in	"Item	8.	Financial	Statements	and	Supplementary Data"	of	this	report.

# Short-Term	Investment	Activity,	Net

During	2013,	we	purchased	approximately	$1.1	billion	of	short-term	investments	and	redeemed	approximately	$3.4	billion.	We	consider	securities	with	original contract	maturities	in	excess	of	three	months	but	less	than	one	year	to	be	short-term	investments.

# Debt	Activity,	Net

During	2015,	our	consolidated	net	debt	borrowings	increased	$1.8	billion.	In	June	2015,	we	issued	$750	million	of	5.0%	senior	notes.	We	used	these	proceeds	to repay	the	aggregate	principal	amount	of	our	floating	rate	senior	notes	upon	maturity	on	December	15,	2015,	as	well	as	outstanding	commercial	paper	balances.	In December	2015,	we	issued	$850	million	of	5.85%	senior	notes	to	fund	acquisitions	announced	in	the	fourth	quarter.	EnLink's	net	debt	borrowings	increased	$1.1	billion primarily	from	borrowings	made	to	fund	acquisitions	and	dropdowns.

During	2014,	we	decreased	our	net	debt	borrowings	by	$2.2	billion.	The	decrease	was	primarily	related	to	the	repayment	of	debt	used	to	fund	the	GeoSouthern transaction.	This	was	partially	offset	by	$555	million	of	net	borrowings	from	EnLink	to	fund	its	operations.

During	2013,	we	increased	our	debt	borrowings	by	$361	million	as	a	result	of	issuing	$2.25	billion	of	debt	related	to	the	planned	Eagle	Ford	acquisition	and repaying	approximately	$1.9	billion	of	outstanding	short-term	debt.

# Shareholder	and	Noncontrolling	Interests	Distributions

The	following	table	summarizes	our	common	stock	dividends.	The	quarterly	cash	dividend	was	$0.20	per	share	in	the	first	quarter	of	2013.	We	increased	the dividend	rate	to	$0.22	per	share	in	the	second	quarter	of	2013	and	to	$0.24	per	share	in	the	second	quarter	of	2014.

|  | Amount | Per	Share | Amount | Per	Share | Amount | Per	Share |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |  |  |
| Dividends | $\t396 | $0.96 | $386 | $0.94 | $348 | $0.86 |

In	conjunction	with	the	formation	of	EnLink	in	the	first	quarter	of	2014,	we	made	a	payment	of	$100	million	to	noncontrolling	interests.	Furthermore,	EnLink	and the	General	Partner	distributed	$254	and	$135	million	to	non-Devon	unitholders	during	2015	and	2014,	respectively.

# EnLink	and	General	Partner	Distributions

Devon	received	$268	million	and	$158	million	in	distributions	from	EnLink	and	the	General	Partner	during	2015	and	2014,	respectively.

# EnLink	Dropdowns

In	the	second	quarter	of	2015,	Devon	received	$167	million	in	cash	from	EnLink	in	exchange	for	VEX.	For	further	discussion,	see	Note	2	in	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

# Stock	Option	Proceeds

# Issuance	of	Subsidiary	Units

During	2015	and	2014,	EnLink	issued	and	sold	approximately	1.3	million	and	14.8	million	common	units	through	general	public	offerings	and	its	"at	the	market" equity	program,	generating	net	proceeds	of	approximately	$25	million	and	$410	million,	respectively.	Furthermore,	in	October	2015,	EnLink	issued	approximately 2.8	million	common	units	in	a	private	placement	transaction	with	the	General	Partner,	generating	approximately	$50	million	in	proceeds.

# Liquidity

Historically,	our	primary	sources	of	capital	and	liquidity	have	been	our	operating	cash	flow,	asset	divestiture	proceeds	and	cash	on	hand.	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. Other	available	sources	of	capital	and	liquidity	include,	among	other	things,	debt	and	equity	securities	that	can	be	issued	pursuant	to	our	shelf	registration	statement	filed with	the	SEC,	as	well	as	the	sale	of	a	portion	of	our	common	units	representing	interests	in	our	investment	in	EnLink	and	the	General	Partner.	We	estimate	the combination	of	these	sources	of	capital	will	continue	to	be	adequate	to	fund	future	capital	expenditures,	debt	repayments	and	other	contractual	commitments	as	discussed in	this	section.

Our	operating	cash	flow	is	sensitive	to	many	variables,	the	most	volatile	of	which	are	the	prices	of	the	oil,	bitumen,	gas	and	NGLs	we	produce	and	sell.	Our consolidated	operating	cash	flow	decreased	10%	in	2015	as	a	result	of	the	significant	decrease	in	commodity	prices.	In	spite	of	this	decline,	we	expect	operating	cash flow	to	continue	to	be	a	primary	source	of	liquidity	as	we	adjust	our	capital	program	in	response	to	lower	commodity	prices.	Additionally,	we	anticipate	utilizing divestiture	proceeds	and	our	credit	availability	to	provide	additional	liquidity	as	needed.

Commodity	Prices	–	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.	We expect	lower	prices	to	continue	throughout	2016,	and	currently,	our	production	is	largely	unhedged.	If	commodity	prices	remain	consistent	with	2015	and	we	are	unable to	obtain	favorable	hedge	contracts	for	our	2016	production,	our	2016	operating	cash	flow	could	materially	decline	from	what	it	was	in	2015.

The	key	terms	to	our	oil,	gas	and	NGL	derivative	financial	instruments	as	of	December	31,	2015	are	presented	in	Note	3	in	"Item	8.	Financial	Statements	and Supplementary	Data"	of	this	report.

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.

Divestitures	of	Property	and	Equipment	–	In	the	fourth	quarter	of	2015,	we	announced	our	intention	to	monetize	up	to	80	MBoe	per	day	of	certain	non-core upstream	assets	across	our	portfolio	in	2016.	In	addition,	we	also	intend	to	market	our	Access	Pipeline	in	Canada.	We	anticipate	these	divestitures	will	generate approximately	$2	billion	to	$3	billion	of	proceeds	to	further	strengthen	our	financial	position	in	2016.

Interest	Rates	–	Our	operating	cash	flow	can	also	be	impacted	by	interest	rate	fluctuations.	As	of	December	31,	2015,	we	had	total	debt	of	$13.1	billion	with	an overall	weighted-average	borrowing	rate	of	4.9%.	Of	the	$13.1	billion	of	total	debt,	$1.4	billion	is	comprised	of	floating	rate	debt	instruments	that	bear	interest	rates averaging	1.1%.

Credit	Losses	–	Our	operating	cash	flow	is	also	exposed	to	credit	risk	in	a	variety	of	ways.	We	are	exposed	to	the	credit	risk	of	the	customers	who	purchase	our oil,	gas	and	NGL	production.	We	are	also	exposed	to	credit	risk	related	to	the	collection	of	receivables	from	our	joint-interest	partners	for	their	proportionate	share	of expenditures	made	on	projects	we	operate.	Additionally,	we	are	exposed	to	the	credit	risk	of	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.

As	recent	years	indicate,	we	have	a	history	of	investing	more	than	100%	of	our	operating	cash	flow	into	capital	development	activities	to	grow	our	company	and maximize	value	for	our	shareholders.	Therefore,	negative	movements	in	any	of	the	variables	discussed	above	would	not	only	impact	our	operating	cash	flow	but	also would	likely	impact	the	amount	of	capital	investment	we	could	or	would	make.	In	the	current	environment,	assuming	current	pricing	expectations,	our	2016	exploration and	development	capital	budget	is	expected	to	be	approximately	$900	million	to	$1.1	billion,	or	roughly	75%	less	than	our	2015	capital	program.	With	our	2016	capital focused	primarily	on	oil	development,	we	anticipate	our	oil	production	will	remain	relatively	flat	from	2015	to	2016,	but	our	natural	gas	and	NGL	production	will decline,	resulting	in	a	6%	production	decline	in	our	core	assets.

At	the	end	of	2015,	we	held	approximately	$2.3	billion	of	cash.	Included	in	this	total	was	$646	million	of	cash	held	by	our	foreign	subsidiaries.	If	we	were	to repatriate	a	portion	or	all	of	the	cash	held	by	our	foreign	subsidiaries,	we	would	recognize	and	pay	current	income	taxes	in	accordance	with	current	U.S.	tax	law.	The payment	of	such	additional	income	tax	would	decrease	the	amount	of	cash	ultimately	available	to	fund	our	business.

# Credit	Availability

We	have	a	$3.0	billion	Senior	Credit	Facility.	The	maturity	date	for	$30	million	of	the	Senior	Credit	Facility	is	October	24,	2017.	The	maturity	date	for	$164 million	of	the	Senior	Credit	Facility	is	October	24,	2018.	The	maturity	date	for	the	remaining	$2.8	billion	is	October	24,	2019.	This	credit	facility	supports	our	$3.0 billion	commercial	paper	program.	Amounts	borrowed	under	the	Senior	Credit	Facility	may,	at	our	election,	bear	interest	at	various	fixed	rate	options	for	periods	of	up to	twelve	months.	Such	rates	are	generally	less	than	the	prime	rate.	However,	we	may	elect	to	borrow	at	the	prime	rate.	As	of	December	31,	2015,	there	were	no borrowings	under	the	Senior	Credit	Facility.

The	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%.	The	credit	agreement	defines	total	funded	debt	as	funds	received	through	the	issuance	of	debt	securities	such	as debentures,	bonds,	notes	payable,	credit	facility	borrowings	and	short-term	commercial	paper	borrowings.	In	addition,	total	funded	debt	includes	all	obligations	with respect	to	payments	received	in	consideration	for	oil,	gas	and	NGL	production	yet	to	be	acquired	or	produced	at	the	time	of	payment.	Funded	debt	excludes	our outstanding	letters	of	credit	and	trade	payables.	The	credit	agreement	defines	total	capitalization	as	the	sum	of	funded	debt	and	stockholders'	equity	adjusted	for	noncash financial	write-downs,	such	as	full	cost	ceiling	and	goodwill	impairments.	As	of	December	31,	2015,	we	were	in	compliance	with	this	covenant.	Our	debt-to- capitalization	ratio	at	December	31,	2015,	as	calculated	pursuant	to	the	terms	of	the	agreement,	was	23.7%.

Our	access	to	funds	from	the	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.

Our	Senior	Credit	Facility	supports	our	$3.0	billion	of	short-term	credit	under	our	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,	2015,	we	had $626	million	of	borrowings	under	our	commercial	paper	program.

EnLink	has	a	$1.5	billion	unsecured	revolving	credit	facility.	The	General	Partner	has	a	$250	million	revolving	credit	facility.	As	of	December	31,	2015,	there were	$11	million	in	outstanding	letters	of	credit	and	$414	million	borrowed	under	the	$1.5	billion	credit	facility	and	no	outstanding	borrowings	under	the	$250	million credit	facility.	All	of	EnLink's	and	the	General	Partner's	debt	is	non-recourse	to	Devon.

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.

# Debt	Ratings

Devon	and	EnLink	are	rated	by	the	major	debt	ratings	agencies	in	the	U.S.	However,	the	General	Partner	does	not	receive	debt	ratings.	In	determining	those	debt ratings,	the	agencies	consider	a	number	of	qualitative	and	quantitative	items	including,	but	not	limited	to,	commodity	pricing	levels,	liquidity,	asset	quality,	reserve	mix, debt	levels,	cost	structure,	planned	asset	sales,	near-term	and	long-term	growth	opportunities	and	capital	allocation	challenges.

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

In	January	2016,	Devon	acquired	Anadarko	Basin	STACK	assets	for	approximately	$1.5	billion	in	cash	and	equity,	subject	to	certain	adjustments.	Including	this acquisition	but	excluding	EnLink,	our	2016	capital	expenditures	are	expected	to	range	from	$1.2	billion	to	$1.4	billion,	including	$900	million	to	$1.1	billion	for	our	oil and	gas	capital	program.	To	a	certain	degree,	the	ultimate	timing	of	these	capital	expenditures	is	within	our	control.	Therefore,	if	commodity	prices	fluctuate	from	our current	estimates,	we	could	choose	to	defer	a	portion	of	these	planned	2016	capital	expenditures	until	later	periods	or	accelerate	capital	expenditures	planned	for	periods beyond	2016	to	achieve	the	desired	balance	between	sources	and	uses	of	liquidity.	Based	upon	current	price	expectations	for	2016,	available	cash	balances	and	credit availability	and	proceeds	from	our	divestiture	program,	we	anticipate	having	adequate	capital	resources	to	fund	our	2016	capital	expenditures.

In	connection	with	our	acquisition	of	the	STACK	play	and	Powder	River	Basin	assets,	we	issued	23,470,000	shares	of	our	common	stock	(the	"STACK Acquisition	Shares")	and	6,857,488	shares	of	our	common	stock	(the	"PRB	Acquisition	Shares"),	respectively.	Pursuant	to	the	terms	of	these	acquisitions,	we	agreed	to register	for	resale	with	the	SEC	the	STACK	Acquisition	Shares	and	the	PRB	Acquisition	Shares.	Following	such	respective	registrations,	the	STACK	Acquisition Shares	and	the	PRB	Acquisition	Shares	can	generally	be	freely	sold	in	the	public	markets	at	any	time	on	or	after	February	21,	2016	and	March	16,	2016,	respectively.

# EnLink	Capital	Resources	and	Expenditures

In	January	2016,	EnLink	acquired	Tall	Oak,	a	gathering	and	processing	midstream	company	with	assets	in	central	Oklahoma,	for	approximately	$1.5	billion	in cash	and	equity,	subject	to	certain	adjustments.

Excluding	this	acquisition,	EnLink's	2016	capital	budget	includes	approximately	$445	million	to	$570	million	of	identified	growth	projects.	EnLink's	primary capital	projects	for	2016	include	completing	the	construction	of	the	Riptide	plant	in	Texas,	acquired	as	part	of	the	Coronado	transaction,	commencing	construction	on	an NGL	pipeline	in	Louisiana	and	development	of	its	Tall	Oak	assets.

EnLink	expects	to	fund	the	growth	capital	expenditures	from	the	proceeds	of	borrowings	under	its	bank	credit	facility	and	proceeds	from	other	debt	and	equity sources.	EnLink	expects	to	fund	its	2016	maintenance	capital	expenditures	from	operating	cash	flows.	In	2016,	it	is	possible	that	not	all	of	the	planned	projects	will	be commenced	or	completed.	EnLink's	ability	to	pay	distributions	to	its	unitholders,	fund	planned	capital	expenditures	and	make	acquisitions	will	depend	upon	its	future operating	performance,	which	will	be	affected	by	prevailing	economic	conditions	in	the	industry	and	financial,	business	and	other	factors,	some	of	which	are	beyond	its control.

# Contractual	Obligations

The	following	table	presents	a	summary	of	our	contractual	obligations	as	of	December	31,	2015.

|  |  | Less	Than |  |  | More	Than |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Total | 1\tYear | \t\t1-3\tYears | \t\t3-5\tYears | 5\tYears |
|  |  |  | (Millions) |  |  |
| Devon\tdebt\t^(1) | $10,051 | $976 | $875 | $700 | $7,500 |
| EnLink\tdebt\t^(2) | 3,077 | — | — | 814 | 2,263 |
| Interest\texpense\t^(3) | 9,804 | 630 | 1,252 | 1,115 | 6,807 |
| Purchase\tobligations\t^(4) | 3,905 | 557 | 1,494 | 1,648 | 206 |
| Operational\tagreements\t^(5) | 4,601 | 994 | 1,908 | 657 | 1,042 |
| Asset\tretirement\tobligations\t^(6) | 1,414 | 44 | 104 | 102 | 1,164 |
| Drilling\tand\tfacility\tobligations\t^(7) | 189 | 69 | 85 | 7 | 28 |
| Lease\tobligations\t^(8) | 443 | 70 | 134 | 110 | 129 |
| Other\t^(9) | 140 | 2 | 92 | 39 | 7 |
| Total\t^(10) | $33,624 | $3,342 | $5,944 | $5,192 | $19,146 |

(1) Debt	amounts	represent	scheduled	maturities	of	Devon's	debt	obligations	at	December	31,	2015,	excluding	$28	million	of	net	discounts	included	in	the	carrying value	of	debt.	Debt	due	less	than	one	year	includes	$626	million	of	commercial	paper,	which	can	be	renewed	beyond	one	year.

(2) Debt	amounts	represent	scheduled	maturities	of	EnLink's	debt	obligations	at	December	31,	2015,	excluding	$13	million	of	net	premiums	included	in	the	carrying value	of	debt.	All	of	EnLink's	debt	is	non-recourse	to	Devon.

(3) Interest	expense	represents	the	scheduled	cash	payments	on	long-term,	fixed-rate	debt	and	an	estimate	of	our	floating-rate	notes.	These	amounts	include	$1.8 billion	of	interest	expense	related	to	EnLink.

(4) 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.

(5) 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.	Operational	agreements	include	approximately	$1.7	billion	of	minimum	volume commitments	between	Devon	and	EnLink.	The	initial	terms	of	the	gas	volume	contracts	with	EnLink	are	summarized	in	the	following	table.	In	addition,	Devon and	EnLink	have	a	30	MBbls/d	minimum	transportation	volume	commitment	for	the	VEX	pipeline.	All	contracts	with	EnLink	expire	in	2019.

|  |  | Minimum | Minimum | Minimum |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Gathering | Processing | Volume |  |
|  | Contract | Volume | Volume | Commitment | Annual |
| Contract | Terms\n(Years) | Commitment\n(MMcf/d) | Commitment\n(MMcf/d) | Term\n(Years) | Rate\nEscalators |
| Bridgeport\tgathering\tand\tprocessing\tcontract | 10 | 850 | 650 | 5 | CPI |
| East\tJohnson\tCounty\tgathering\tcontract | 10 | 125 | — | 5 | CPI |
| Cana\tgathering\tand\tprocessing\tcontract | 10 | 330 | 330 | 5 | CPI |

(6) Asset	retirement	obligations	represent	estimated	discounted	costs	for	future	dismantlement,	abandonment	and	rehabilitation	costs.	These	obligations	are	recorded as	liabilities	on	our	December	31,	2015	balance	sheet.

(7) 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.

(8) Lease	obligations	consist	primarily	of	non-cancelable	leases	for	office	space	and	equipment	used	in	our	daily	operations.

(9) These	amounts	include	$133	million	related	to	uncertain	tax	positions.

(10) This	table	excludes	approximately	$1.7	billion	of	cash	payments	made	on	January	7,	2016	upon	closing	the	STACK	acquisition	and	EnLink's	acquisition	of	Tall Oak.	The	table	also	excludes	the	$500	million	of	future	cash	installment	payments	required	to	be	paid	by	EnLink	within	24	months	as	part	of	the	Tall	Oak acquisition.

# Contingencies	and	Legal	Matters

For	a	detailed	discussion	of	contingencies	and	legal	matters,	see	Note	18	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.

# Full	Cost	Method	of	Accounting	and	Proved	Reserves

Our	estimates	of	proved	reserves	are	a	major	component	of	the	depletion	and	full	cost	ceiling	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	2015,	95%	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	3%	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.

While	the	quantities	of	proved	reserves	require	substantial	judgment,	the	associated	prices	of	oil,	gas	and	NGL	reserves,	and	the	applicable	discount	rate,	that	are used	to	calculate	the	discounted	present	value	of	the	reserves	do	not	require	judgment.	Applicable	rules	require	future	net	revenues	to	be	calculated	using	prices	that represent	the	average	of	the	first-day-of-the-month	price	for	the	12-month	period	prior	to	the	end	of	each	quarterly	period.	Such	rules	also	dictate	that	a	10%	discount factor	be	used.	Therefore,	the	discounted	future	net	revenues	associated	with	the	estimated	proved	reserves	are	not	based	on	our	assessment	of	future	prices	or	costs	or our	enterprise	risk.

Because	the	ceiling	calculation	dictates	the	use	of	prices	that	are	not	representative	of	future	prices	and	requires	a	10%	discount	factor,	the	resulting	value	is	not indicative	of	the	true	fair	value	of	the	reserves.	Oil	and	gas	prices	have	historically	been	cyclical	and,	for	any	particular	12-month	period,	can	be	either	higher	or	lower than	our	long-term	price	forecast,	which	is	a	more	appropriate	input	for	estimating	fair	value.	Therefore,	oil	and	gas	property	write-downs	that	result	from	applying	the full	cost	ceiling	limitation,	and	that	are	caused	by	fluctuations	in	price	as	opposed	to	reductions	to	the	underlying	quantities	of	reserves,	should	not	be	viewed	as	absolute indicators	of	a	reduction	of	the	ultimate	value	of	the	related	reserves.

Because	of	the	volatile	nature	of	oil	and	gas	prices,	it	generally	is	not	possible	to	predict	the	timing	or	magnitude	of	full	cost	write-downs.	In	addition,	because	of the	inter-relationship	of	the	various	judgments	made	to	estimate	proved	reserves,	it	is	impractical	to	provide	quantitative	analyses	of	the	effects	of	potential	changes	in these	estimates.	However,	decreases	in	estimates	of	proved	reserves	would	generally	increase	our	depletion	rate	and,	thus,	our	depletion	expense.	Decreases	in	our proved	reserves	may	also	increase	the	likelihood	of	recognizing	a	full	cost	ceiling	write-down.

Based	on	prices	for	the	last	nine	months	of	2015	and	the	short-term	pricing	outlook	for	the	first	quarter	of	2016,	we	expect	to	recognize	additional	U.S.	and Canadian	full	cost	impairments	in	the	first	quarter	of	2016.	The	estimated	U.S.	impairment	would	be	material	to	our	net	earnings,	but	we	believe	it	will	not	be	as	large	as the	$3.7	billion	impairment	we	recognized	in	the	fourth	quarter	of	2015.	We	also	expect	to	recognize	an	impairment	related	to	our	Canadian	oil	and	gas	properties	that will	approximate	the	impairment	recognized	in	the	fourth	quarter	of	2015.	While	difficult	to	measure,	we	estimate	that	the	first	quarter	2016	impairments	will approximate	$3	billion	in	the	aggregate.	Our	full	cost	impairments	have	no	impact	to	our	cash	flow	or	liquidity.

# Derivative	Financial	Instruments

We	periodically	enter	into	derivative	financial	instruments	with	respect	to	a	portion	of	our	oil,	gas	and	NGL	production	to	hedge	future	prices	received. Additionally,	EnLink	periodically	enters	into	derivative	financial	instruments	with	respect	to	its	oil,	gas	and	NGL	marketing	activity.	These	commodity	derivative financial	instruments	include	financial	price	swaps,	basis	swaps,	costless	price	collars	and	call	options.

The	estimates	of	the	fair	values	of	our	derivative	instruments	require	substantial	judgment.	We	estimate	the	fair	values	of	our	commodity	derivative	financial instruments	primarily	by	using	internal	discounted	cash	flow	calculations.	The	most	significant	variable	to	our	cash	flow	calculations	is	our	estimate	of	future commodity	prices.	We	base	our	estimate	of	future	prices	upon	published	forward	commodity	price	curves	such	as	the	Inside	FERC	Henry	Hub	forward	curve	for	gas instruments	and	the	NYMEX	WTI	forward	curve	for	oil	instruments.	Another	key	input	to	our	cash	flow	calculations	is	our	estimate	of	volatility	for	these	forward curves,	which	we

base	primarily	upon	implied	volatility.	The	resulting	estimated	future	cash	inflows	or	outflows	over	the	lives	of	the	contracts	are	discounted	primarily	using	U.S. Treasury	bill	rates.	These	pricing	and	discounting	variables	are	sensitive	to	the	period	of	the	contract	and	market	volatility	as	well	as	changes	in	forward	prices	and regional	price	differentials.

We	periodically	enter	into	interest	rate	swaps	to	manage	our	exposure	to	interest	rate	volatility.	We	estimate	the	fair	values	of	our	interest	rate	swap	financial instruments	primarily	by	using	internal	discounted	cash	flow	calculations	based	upon	forward	interest	rate	yields.	The	most	significant	variable	to	our	cash	flow calculations	is	our	estimate	of	future	interest	rate	yields.	We	base	our	estimate	of	future	yields	upon	our	own	internal	model	that	utilizes	forward	curves	such	as	the LIBOR	or	the	Federal	Funds	Rate	provided	by	third	parties.	The	resulting	estimated	future	cash	inflows	or	outflows	over	the	lives	of	the	contracts	are	discounted	using the	LIBOR	and	money	market	futures	rates.	These	yield	and	discounting	variables	are	sensitive	to	the	period	of	the	contract	and	market	volatility.

We	periodically	enter	into	foreign	exchange	forward	contracts	to	manage	our	exposure	to	fluctuations	in	exchange	rates.	Under	the	terms	of	our	foreign	exchange forward	contracts,	we	generally	receive	U.S.	dollars	and	pay	Canadian	dollars	based	on	a	total	notional	amount.	We	estimate	the	fair	values	of	our	foreign	exchange forward	contracts	primarily	by	using	internal	discounted	cash	flow	calculations	based	upon	forward	exchange	rates.	The	most	significant	variable	to	our	cash	flow calculations	is	our	observation	of	forward	foreign	exchange	rates.	The	resulting	future	cash	inflows	or	outflows	at	maturity	of	the	contracts	are	discounted	using	Treasury rates.	These	discounting	variables	are	sensitive	to	the	period	of	the	contract	and	market	volatility.

We	periodically	validate	our	valuation	techniques	by	comparing	our	internally	generated	fair	value	estimates	with	those	obtained	from	contract	counterparties.

Counterparty	credit	risk	has	not	had	a	significant	effect	on	our	cash	flow	calculations	and	derivative	valuations.	This	is	primarily	the	result	of	two	factors.	First, we	have	mitigated	our	exposure	to	any	single	counterparty	by	contracting	with	numerous	counterparties.	Our	oil,	gas	and	NGL	commodity	derivative	contracts	are	held with	thirteen	separate	counterparties,	and	our	foreign	exchange	forward	contracts	are	held	with	six	separate	counterparties.	Second,	our	derivative	contracts	generally require	cash	collateral	to	be	posted	if	either	our	or	the	counterparty's	credit	rating	falls	below	certain	credit	rating	levels.

Because	we	have	chosen	not	to	qualify	our	derivatives	for	hedge	accounting	treatment,	changes	in	the	fair	values	of	derivatives	can	have	a	significant	impact	on our	reported	results	of	operations.	Generally,	changes	in	derivative	fair	values	will	not	impact	our	liquidity	or	capital	resources.

Settlements	of	derivative	instruments,	regardless	of	whether	they	qualify	for	hedge	accounting,	do	have	an	impact	on	our	liquidity	and	results	of	operations. Generally,	if	actual	market	prices	are	higher	than	the	price	of	the	derivative	instruments,	our	net	earnings	and	cash	flow	from	operations	will	be	lower	relative	to	the results	that	would	have	occurred	absent	these	instruments.	The	opposite	is	also	true.	Additional	information	regarding	the	effects	that	changes	in	market	prices	can	have on	our	derivative	financial	instruments,	net	earnings	and	cash	flow	from	operations	is	included	in	"Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk" of	this	report.

# Business	Combinations

Accounting	for	the	acquisition	of	a	business	requires	the	assets	and	liabilities	of	the	acquired	business	to	be	recorded	at	fair	value.	Deferred	taxes	are	recorded	for any	differences	between	the	fair	value	and	the	tax	basis	of	the	acquired	assets	and	liabilities.	Any	excess	of	the	purchase	price	over	the	fair	values	of	the	tangible	and intangible	net	assets	acquired	is	recorded	as	goodwill.

There	are	various	assumptions	we	make	in	determining	the	fair	values	of	an	acquired	company's	assets	and	liabilities.	The	most	significant	assumptions,	and	the ones	requiring	the	most	judgment,	involve	the	estimated	fair	values	of	the	oil	and	gas	properties	acquired.	To	determine	the	fair	values	of	these	properties,	we	prepare estimates	of	oil,	natural	gas	and	NGL	reserves.	These	estimates	are	based	on	work	performed	by	our	engineers	and	that	of	outside	consultants.	The	judgments	associated with	these	estimated	reserves	are	described	earlier	in	this	section	in	connection	with	the	full	cost	ceiling	calculation.

However,	there	are	factors	involved	in	estimating	the	fair	values	of	acquired	oil,	natural	gas	and	NGL	properties	that	require	more	judgment	than	that	involved	in the	full	cost	ceiling	calculation.	As	stated	above,	the	full	cost	ceiling	calculation	applies	a	historical	12-month	average	price	to	the	reserves	to	arrive	at	the	ceiling amount.	By	contrast,	the	fair	value	of	reserves	acquired	in	a	business	combination	must	be	based	on	our	estimates	of	future	oil,	natural	gas	and	NGL	prices.	Our estimates	of	future	prices	are	based	on	our	own	analysis	of	pricing	trends.	These	estimates	are	based	on	current	data	obtained	with	regard	to	regional	and	worldwide supply	and	demand	dynamics	such	as	economic	growth	forecasts.	They	are	also	based	on	industry	data	regarding	natural	gas	storage	availability,	drilling	rig	activity, changes	in	delivery	capacity,	trends	in	regional	pricing	differentials	and	other	fundamental	analysis.	Forecasts	of	future	prices	from	independent	third	parties	are	noted when	we	make	our	pricing	estimates.

We	estimate	future	prices	to	apply	to	the	estimated	reserve	quantities	acquired,	and	estimate	future	operating	and	development	costs,	to	arrive	at	estimates	of future	net	revenues.	For	estimated	proved	reserves,	the	future	net	revenues	are	then	discounted	using	a	rate	determined	appropriate	at	the	time	of	the	business combination	based	upon	our	cost	of	capital.

We	also	apply	these	same	general	principles	to	estimate	the	fair	value	of	unproved	properties	acquired	in	a	business	combination.	These	unproved	properties generally	represent	the	value	of	probable	and	possible	reserves.	Because	of	their	very	nature,	probable	and	possible	reserve	estimates	are	more	imprecise	than	those	of proved	reserves.	To	compensate	for	the	inherent	risk	of	estimating	and	valuing	unproved	reserves,	the	discounted	future	net	revenues	of	probable	and	possible	reserves are	reduced	by	what	we	consider	to	be	an	appropriate	risk-weighting	factor	in	each	particular	instance.

In	addition,	our	acquisitions	have	involved	other	entities	whose	operations	included	substantial	midstream	activities.	In	these	transactions,	the	purchase	price	is allocated	to	the	fair	value	of	midstream	facilities	and	equipment,	generally	consisting	of	processing	facilities	and	pipeline	systems.	Estimating	the	fair	value	of	these assets	requires	certain	assumptions	to	be	made	regarding	future	quantities	of	commodities	estimated	to	be	processed	and	transported	through	these	facilities	and pipelines,	as	well	as	estimates	of	future	expected	prices	and	operating	and	capital	costs.

# 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.	While	we	use	data	as	of	October	31	for	our	test,	we	typically	complete	the	test	in	late	December	or	early	January	as	the	October	31	market	data	used in	our	test	becomes	available.	We	first	assess	the	qualitative	factors	to	determine	whether	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit	is	less	than	its carrying	amount	as	a	basis	for	determining	whether	it	is	necessary	to	perform	the	two-step	goodwill	impairment	test.	If	we	determine	that	it	is	more	likely	than	not	that its	fair	value	is	less	than	its	carrying	amount,	then	the	two-step	goodwill	impairment	test	is	performed.

In	the	first	step	of	the	impairment	test,	the	fair	value	of	a	reporting	unit	is	compared	to	its	carrying	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.	If	the	carrying	value	of	a	reporting	unit	exceeds	its	fair	value,	the	second	step	of	the	impairment

test	is	performed	for	purposes	of	measuring	the	impairment.	In	the	second	step,	the	fair	value	of	the	reporting	unit	is	allocated	to	all	of	the	assets	and	liabilities	of	the reporting	unit	to	determine	an	implied	goodwill	value.	This	allocation	is	similar	to	a	purchase	price	allocation.	If	the	carrying	amount	of	the	reporting	unit's	goodwill exceeds	the	implied	fair	value	of	goodwill,	an	impairment	loss	is	recognized	in	an	amount	equal	to	that	excess.	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.	Critical	assumptions	primarily	include	revenue	growth	rates	driven	by	future	commodity	prices	and	volume	expectations,	operating	margins	and	capital expenditures.

For	our	October	31,	2015	impairment	test,	step	one	of	our	impairment	analysis	showed	that	the	fair	value	of	our	U.S.	reporting	unit	exceeded	its	carrying	value.

Sustained	weakness	in	the	overall	energy	sector	beginning	in	the	fourth	quarter	of	2014	and	continuing	into	2015	driven	by	low	commodity	prices,	together	with	a decline	in	the	EnLink	unit	price,	caused	a	change	in	circumstances	warranting	an	interim	impairment	test	for	EnLink's	reporting	units,	as	well	as	an	update	performed	as of	December	31.	Based	on	the	results	of	the	impairment	analysis,	it	was	determined	that	the	estimated	fair	value	of	EnLink's	Crude	and	Condensate,	Louisiana	and	Texas reporting	units	were	less	than	their	carrying	amounts,	primarily	due	to	changes	in	assumptions	related	to	commodity	prices	and	discount	rates.	Through	the	analysis, goodwill	impairments	of	$492	million,	$787	million	and	$49	million	for	EnLink's	Texas,	Louisiana	and	Crude	and	Condensate	reporting	units,	respectively,	were recognized	in	2015.	Subsequent	to	the	impairments,	EnLink	had	$93	million	and	$704	million	of	goodwill	allocated	to	the	Crude	and	Condensate	and	Texas	reporting units,	respectively.	The	Louisiana	reporting	unit's	goodwill	was	entirely	written	off.	As	of	December	31,	2015,	the	fair	value	of	EnLink's	Texas	reporting	unit	exceeded its	carrying	value	by	approximately	7%,	and	the	carrying	value	of	EnLink's	Crude	and	Condensate	reporting	unit	approximated	its	fair	value.

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

# Other	Intangible	Assets

In	2015,	the	assessment	of	customer	relationships	was	updated	due	to	the	factors	described	in	the	aforementioned	goodwill	section.	This	assessment	resulted	in	a $223	million	impairment	of	other	intangible	assets	related	to	EnLink's	Crude	and	Condensate	reporting	unit.	Level	3	fair	value	measurements	were	utilized	for	the impairment	analysis	of	definite-lived	intangible	assets,	which	included	discounted	cash	flow	estimates,	consistent	with	those	utilized	in	the	goodwill	impairment assessment.

The	other	intangible	assets	impairment	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	2015,	we	had	deferred	tax	assets	that	largely	resulted	from	the	full	cost	impairments recognized	in	the	fourth	quarter	of	2015.	As	a	result	of	our	recent	cumulative	losses,	we	recorded	a	100%	valuation	allowance	against	our	U.S.	deferred	tax	assets	as	of December	31,	2015.

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,	particularly	the	laws	pertaining	to	the	deductibility	of	intangible drilling	costs	and	repatriations	of	foreign	earnings.	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:

•separate	analysis	of	a	diverse	chain	of	foreign	entities;

•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,	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

We	make	reference	to	"core	earnings	attributable	to	Devon"	and	"core	earnings	per	share	attributable	to	Devon"	in	"Overview	of	2015	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 attributable	to	Devon,	as	well	as	the	per	share	amount,	represent	net	earnings	excluding	certain	noncash	or	non-recurring	items	that	are	typically	excluded	by	securities analysts	in	their	published	estimates	of	our	financial	results.	Our	non-GAAP	measures	are	typically	used	as	a	quarterly	performance	measure.	Items	may	appear	to	be recurring	when	comparing	on	an	annual	basis.	In	the	table	below,	restructuring	costs	were	incurred	in	each	of	the	three	year	periods;	however,	these	costs	relate	to different	restructuring	programs.	Amounts	excluded	for	2015	relate	to	derivatives	and	financial	instrument	fair	value	changes,	asset	impairments	(including	an impairment	of	goodwill),	deferred	tax	asset	valuation	allowance,	restructuring	costs	and	repatriation	of	funds	to	the	U.S.	Amounts	excluded	for	2014	relate	to	derivatives and	financial	instrument	fair	value	changes,	asset	impairments	(including	an	impairment	of	goodwill),	our	divestiture	programs	and	related	gains	on	asset	sales	and restructuring	costs,	repatriation	of	proceeds	to	the	U.S.,	loss	on	early	retirement	of	debt	and	deferred	income	tax	on	the	formation	of	the	General	Partner.	Amounts excluded	for	2013	relate	to	derivatives	and	financial	instrument	fair	value	changes,	asset	impairments,	our	divestiture	programs	and	related	repatriation	of	proceeds	to	the U.S.	and	restructuring	costs.	For	more	information	on	our	restructuring	programs,	see	Note	6	in	"Item	8.	Financial

Statements	and	Supplementary	Data"	of	this	report.	We	believe	these	non-GAAP	measures	facilitate	comparisons	of	our	performance	to	earnings	estimates	published	by securities	analysts.	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.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2015 | \t\t\t\t2014 | \t\t\t\t2013 |
|  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon\t(GAAP) | $(14,454) | $1,607 | $(20) |
| Adjustments\t(net\tof\ttaxes\tand\tnoncontrolling\tinterests): |  |  |  |
| Derivatives\tand\tother\tfinancial\tinstruments | (206) | (1,262) | 131 |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 1,552 | 31 | 139 |
| Noncash\teffect\tof\tderivatives\tand\tfinancial\tinstruments | 1,346 | (1,231) | 270 |
| Asset\timpairments | 13,100 | 1,948 | 1,353 |
| Deferred\ttax\tasset\tvaluation\tallowance | 967 | — | — |
| Gain\ton\tasset\tsales\tand\trepatriations | 33 | (421) | 97 |
| Investment\tin\tGeneral\tPartner\tdeferred\tincome\ttax | — | 48 | — |
| Restructuring\tcosts | 52 | 35 | 34 |
| Early\tretirement\tof\tdebt | — | 31 | — |
| Core\tearnings\tattributable\tto\tDevon\t(non-GAAP) | $1,044 | $2,017 | $1,734 |
| Earnings\t(loss)\tper\tshare\tattributable\tto\tDevon\t(GAAP) | $(35.55) | $3.91 | $(0.06) |
| Adjustments\t(net\tof\ttaxes\tand\tnoncontrolling\tinterests): |  |  |  |
| Derivatives\tand\tother\tfinancial\tinstruments | (0.49) | (3.07) | 0.31 |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 3.80 | 0.08 | 0.34 |
| Noncash\teffect\tof\tderivatives\tand\tfinancial\tinstruments | 3.31 | (2.99) | 0.65 |
| Asset\timpairments | 32.18 | 4.74 | 3.35 |
| Deferred\ttax\tasset\tvaluation\tallowance | 2.37 | — | — |
| Gain\ton\tasset\tsales\tand\trepatriations | 0.08 | (1.02) | 0.24 |
| Investment\tin\tGeneral\tPartner\tdeferred\tincome\ttax | — | 0.12 | — |
| Restructuring\tcosts | 0.13 | 0.08 | 0.08 |
| Early\tretirement\tof\tdebt | — | 0.07 | — |
| Core\tearnings\tper\tshare\tattributable\tto\tDevon\t(non-GAAP) | $2.52 | $4.91 | $4.26 |

# 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,	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,	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	production.	Pricing	for	oil	and	gas	production	has	been	volatile	and	unpredictable	as discussed	in	"Item	1A.	Risk	Factors"	of	this	report.	Consequently,	we	periodically	hedge	a	portion	of	our	production	through	various	financial	transactions.	The	key terms	to	all	our	oil	and	gas	derivative	financial	instruments	as	of	December	31,	2015	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,	2015,	a 10%	change	in	the	forward	curves	associated	with	our	commodity	derivative	instruments	would	not	have	materially	impacted	our	balance	sheet	at	December	31,	2015.

# Interest	Rate	Risk

At	December	31,	2015,	we	had	total	debt	of	$13.1	billion.	Of	this	amount,	$11.7	billion	bears	fixed	interest	rates	averaging	5.3%,	and	$1.4	billion	is	comprised	of floating	rate	debt	with	interest	rates	averaging	1.1%.	Our	commercial	paper	borrowings	typically	have	maturities	between	1	and	90	days.

As	of	December	31,	2015,	we	had	open	interest	rate	swap	positions	that	are	presented	in	Note	3	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this report.	The	fair	values	of	our	interest	rate	swaps	are	largely	determined	by	estimates	of	the	forward	curves	of	the	3	month	LIBOR	rate.	A	10%	change	in	these	forward curves	would	not	have	materially	impacted	our	balance	sheet	at	December	31,	2015.

# 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,	2015	balance	sheet.

Our	non-Canadian	foreign	subsidiaries	have	a	U.S.	dollar	functional	currency.	However,	some	of	our	subsidiaries	hold	Canadian-dollar	cash	and	engage	in intercompany	loans	with	Canadian	subsidiaries	that	are	based	in	Canadian	dollars.	The	value	of	the	Canadian-dollar	cash	and	intercompany	loans	increases	or	decreases from	the	remeasurement	of	the	cash	and	loans	into	the	U.S.	dollar	functional	currency.	Additionally,	at	December	31,	2015,	we	held	foreign	currency	exchange	forward contracts	to	hedge	exposures	to	fluctuations	in	exchange	rates	on	the	Canadian-dollar	cash	and	intercompany	loans.	The	increase	or	decrease	in	the	value	of	the	forward contracts	is	offset	by	the	increase	or	decrease	to	the	U.S.	dollar	equivalent	of	the	Canadian-dollar	cash	and	intercompany	loans.	Based	on	the	amount	of	the	cash	and intercompany	loans	as	of	December	31,	2015,	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 | 57 |
| :--- | :--- |
| Consolidated\tFinancial\tStatements |  |
| Consolidated\tComprehensive\tStatements\tof\tEarnings | \t58 |
| Consolidated\tStatements\tof\tCash\tFlows | \t59 |
| Consolidated\tBalance\tSheets | \t60 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | \t61 |
| Notes\tto\tConsolidated\tFinancial\tStatements | \t62 |

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

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Devon	Energy	Corporation	and	subsidiaries	as	of	December	31,	2015	and	2014,	and	the related	consolidated	comprehensive	statements	of	earnings,	cash	flows,	and	stockholders'	equity	for	each	of	the	years	in	the	three-year	period	ended	December	31,	2015. We	also	have	audited	Devon	Energy	Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2015,	based	on	criteria	established	in	Internal	Control	– Integrated	Framework	(2013)	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(COSO).	Devon	Energy	Corporation'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	Management's	Annual	Report	contained	in	"Item	9A.	Controls	and	Procedures"	of	Devon	Energy	Corporation's Annual	Report	on	Form	10-K.	Our	responsibility	is	to	express	an	opinion	on	these	consolidated	financial	statements	and	an	opinion	on	the	Company's	internal	control over	financial	reporting	based	on	our	audits.

We	conducted	our	audits	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we plan	and	perform	the	audits	to	obtain	reasonable	assurance	about	whether	the	financial	statements	are	free	of	material	misstatement	and	whether	effective	internal	control over	financial	reporting	was	maintained	in	all	material	respects.	Our	audits	of	the	consolidated	financial	statements	included	examining,	on	a	test	basis,	evidence supporting	the	amounts	and	disclosures	in	the	financial	statements,	assessing	the	accounting	principles	used	and	significant	estimates	made	by	management,	and evaluating	the	overall	financial	statement	presentation.	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.

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.

In	our	opinion,	the	consolidated	financial	statements	referred	to	above	present	fairly,	in	all	material	respects,	the	financial	position	of	Devon	Energy	Corporation and	subsidiaries	as	of	December	31,	2015	and	2014,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	years	in	the	three-year	period	ended	December	31, 2015,	in	conformity	with	U.S	generally	accepted	accounting	principles.	Also	in	our	opinion,	Devon	Energy	Corporation	maintained,	in	all	material	respects,	effective internal	control	over	financial	reporting	as	of	December	31,	2015,	based	on	criteria	established	in	Internal	Control	–	Integrated	Framework	(2013)	issued	by	the Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission.

/s/	KPMG	LLP

Oklahoma	City,	Oklahoma

# DEVON	ENERGY	CORPORATION	AND	SUBSIDIARIES

# CONSOLIDATED	COMPREHENSIVE	STATEMENTS	OF	EARNINGS

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2015 | \t\t\t\t2014 | \t\t\t\t2013 |
|  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |
| Oil,\tgas\tand\tNGL\tsales | $5,382 | $9,910 | $8,522 |
| Oil,\tgas\tand\tNGL\tderivatives | 503 | 1,989 | (191) |
| Marketing\tand\tmidstream\trevenues | 7,260 | 7,667 | 2,066 |
| Total\toperating\trevenues | 13,145 | \t 19,566 | 10,397 |
| Lease\toperating\texpenses | 2,104 | 2,332 | 2,268 |
| Marketing\tand\tmidstream\toperating\texpenses | 6,420 | 6,815 | 1,553 |
| General\tand\tadministrative\texpenses | 855 | 847 | 617 |
| Production\tand\tproperty\ttaxes | 388 | 535 | 461 |
| Depreciation,\tdepletion\tand\tamortization | 3,129 | 3,319 | 2,780 |
| Asset\timpairments | 20,820 | 1,953 | 1,976 |
| Restructuring\tcosts | 78 | 46 | 54 |
| Gains\tand\tlosses\ton\tasset\tsales | — | (1,072) | 9 |
| Other\toperating\titems | 78 | 93 | 112 |
| Total\toperating\texpenses | 33,872 | \t 14,868 | 9,830 |
| Operating\tincome\t(loss) | (20,727) | 4,698 | 567 |
| Net\tfinancing\tcosts | 517 | 526 | 417 |
| Other\tnonoperating\titems | 24 | 113 | 1 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | (21,268) | 4,059 | 149 |
| Income\ttax\texpense\t(benefit) | (6,065) | 2,368 | 169 |
| Net\tearnings\t(loss) | (15,203) | 1,691 | (20) |
| Net\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | (749) | 84 | — |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $(14,454) | $1,607 | $(20) |
| Net\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon: |  |  |  |
| Basic | $(35.55) | $3.93 | $(0.06) |
| Diluted | $(35.55) | $3.91 | $(0.06) |
| Comprehensive\tearnings\t(loss): |  |  |  |
| Net\tearnings\t(loss) | $(15,203) | $1,691 | $(20) |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax: |  |  |  |
| Foreign\tcurrency\ttranslation | (559) | (465) | (548) |
| Pension\tand\tpostretirement\tplans | 10 | (24) | 45 |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | (549) | (489) | (503) |
| Comprehensive\tearnings\t(loss) | (15,752) | 1,202 | (523) |
| Comprehensive\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | (749) | 84 | — |
| Comprehensive\tearnings\t(loss)\tattributable\tto\tDevon | $(15,003) | $1,118 | $(523) |

See	accompanying	notes	to	consolidated	financial	statements.

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Cash\tflows\tfrom\toperating\tactivities: |  |  |  |
| Net\tearnings\t(loss) | $(15,203) | $1,691 | $(20) |
| Adjustments\tto\treconcile\tnet\tearnings\t(loss)\tto\tnet\tcash\tfrom\toperating\tactivities: |  |  |  |
| Depreciation,\tdepletion\tand\tamortization | 3,129 | 3,319 | 2,780 |
| Asset\timpairments | 20,820 | 1,953 | 1,976 |
| Gains\tand\tlosses\ton\tasset\tsales | — | (1,072) | 9 |
| Deferred\tincome\ttax\texpense\t(benefit) | (5,828) | 1,891 | 97 |
| Derivatives\tand\tother\tfinancial\tinstruments | (738) | (2,070) | 135 |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 2,688 | 104 | 277 |
| Other\tnoncash\tcharges | 537 | 457 | 309 |
| Net\tchange\tin\tworking\tcapital | (301) | 50 | (298) |
| Change\tin\tlong-term\tother\tassets | 285 | (421) | 10 |
| Change\tin\tlong-term\tother\tliabilities | (6) | 79 | 161 |
| Net\tcash\tfrom\toperating\tactivities | 5,383 | 5,981 | 5,436 |
| Cash\tflows\tfrom\tinvesting\tactivities: |  |  |  |
| Capital\texpenditures | (5,308) | (6,988) | (6,502) |
| Acquisitions\tof\tproperty,\tequipment\tand\tbusinesses | (1,107) | (6,462) | (256) |
| Divestitures\tof\tproperty\tand\tequipment | 107 | 5,120 | 419 |
| Purchases\tof\tshort-term\tinvestments | — | — | (1,076) |
| Redemptions\tof\tshort-term\tinvestments | — | — | 3,419 |
| Redemptions\tof\tlong-term\tinvestments | — | 57 | — |
| Other | (16) | 89 | (3) |
| Net\tcash\tfrom\tinvesting\tactivities | (6,324) | (8,184) | (3,999) |
| Cash\tflows\tfrom\tfinancing\tactivities: |  |  |  |
| Borrowings\tof\tlong-term\tdebt,\tnet\tof\tissuance\tcosts | 4,772 | 5,340 | 2,233 |
| Repayments\tof\tlong-term\tdebt | (2,634) | (7,189) | — |
| Net\tshort-term\tdebt\trepayments | (307) | (385) | (1,872) |
| Stock\toption\texercises | 4 | 93 | 3 |
| Sale\tof\tsubsidiary\tunits | 654 | — | — |
| Issuance\tof\tsubsidiary\tunits | 25 | 410 | — |
| Dividends\tpaid\ton\tcommon\tstock | (396) | (386) | (348) |
| Distributions\tto\tnoncontrolling\tinterests | (254) | (235) | — |
| Other | (16) | (2) | 4 |
| Net\tcash\tfrom\tfinancing\tactivities | 1,848 | (2,354) | 20 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (77) | (29) | (28) |
| Net\tchange\tin\tcash\tand\tcash\tequivalents | 830 | (4,586) | 1,429 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 1,480 | 6,066 | 4,637 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $2,310 | $1,480 | $6,066 |

# CONSOLIDATED	BALANCE	SHEETS

| Cash	and	cash	equivalents | $2,310 | $1,480 |
| :--- | :--- | :--- |
| Accounts\treceivable | 1,105 | 1,959 |
| Derivatives,\tat\tfair\tvalue | 43 | 1,993 |
| Income\ttaxes\treceivable | 147 | 522 |
| Other\tcurrent\tassets | 421 | 544 |
| Total\tcurrent\tassets | 4,026 | 6,498 |
| Property\tand\tequipment,\tat\tcost: |  |  |
| Oil\tand\tgas,\tbased\ton\tfull\tcost\taccounting: |  |  |
| Subject\tto\tamortization | 78,190 | 75,738 |
| Not\tsubject\tto\tamortization | 2,584 | 2,752 |
| Total\toil\tand\tgas | 80,774 | 78,490 |
| Midstream\tand\tother | 10,380 | 9,695 |
| Total\tproperty\tand\tequipment,\tat\tcost | 91,154 | 88,185 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | (72,086) | (51,889) |
| Property\tand\tequipment,\tnet | 19,068 | 36,296 |
| Goodwill | 5,032 | 6,303 |
| Other\tlong-term\tassets | 1,406 | 1,540 |
| Total\tassets | $29,532 | $50,637 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $906 | $1,400 |
| Revenues\tand\troyalties\tpayable | 763 | 1,193 |
| Short-term\tdebt | 976 | 1,432 |
| Deferred\tincome\ttaxes | — | 730 |
| Other\tcurrent\tliabilities | 650 | 1,180 |
| Total\tcurrent\tliabilities | 3,295 | 5,935 |
| Long-term\tdebt | 12,137 | 9,830 |
| Asset\tretirement\tobligations | 1,370 | 1,339 |
| Other\tlong-term\tliabilities | 853 | 948 |
| Deferred\tincome\ttaxes | 888 | 6,244 |
| Stockholders'\tequity: |  |  |
| shares\tin\t2015\tand\t2014,\trespectively | 42 | 41 |
| Additional\tpaid-in\tcapital | 4,996 | 4,088 |
| Retained\tearnings | 1,781 | 16,631 |
| Accumulated\tother\tcomprehensive\tearnings | 230 | 779 |
| Total\tstockholders'\tequity\tattributable\tto\tDevon | 7,049 | 21,539 |
| Noncontrolling\tinterests | 3,940 | 4,802 |
| Total\tstockholders'\tequity | 10,989 | 26,341 |
| Commitments\tand\tcontingencies\t(Note\t18)\nTotal\tliabilities\tand\tstockholders'\tequity | $29,532 | $50,637 |

# CONSOLIDATED	STATEMENTS	OF	STOCKHOLDERS'	EQUITY

|  | Common	Stock<br>Shares | Amount | Additional<br>Paid-In<br>Capital | Retained<br>Earnings | Accumulated<br>Other<br>Comprehensive<br>Earnings | Treasury<br>Stock | Noncontrolling<br>Interests | Total<br>Stockholders'<br>Equity |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  | (Millions) |  |  |  |
| Balance\tas\tof\tDecember\t31,\t2012 | 406 | $41 | $3,688 | $15,778 | $1,771 | $— | $— | $21,278 |
| Net\tloss | — | — | — | (20) | — | — | — | (20) |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | — | — | — | — | (503) | — | — | (503) |
| Stock\toption\texercises | — | — | 3 | — | — | — | — | 3 |
| Common\tstock\trepurchased | — | — | — | — | — | (36) | — | (36) |
| Common\tstock\tretired | — | — | (36) | — | — | 36 | — | — |
| Common\tstock\tdividends | — | — | — | (348) | — | — | — | (348) |
| Share-based\tcompensation | — | — | 121 | — | — | — | — | 121 |
| Share-based\tcompensation\ttax\tbenefits | — | — | 4 | — | — | — | — | 4 |
| Balance\tas\tof\tDecember\t31,\t2013 | 406 | 41 | 3,780 | 15,410 | 1,268 | — | — | 20,499 |
| Net\tearnings | — | — | — | 1,607 | — | — | 84 | 1,691 |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | — | — | — | — | (489) | — | — | (489) |
| Stock\toption\texercises | 1 | — | 93 | — | — | — | — | 93 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 2 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | — | — | — | — | — | (27) | — | (27) |
| Common\tstock\tretired | — | — | (27) | — | — | 27 | — | — |
| Common\tstock\tdividends | — | — | — | (386) | — | — | — | (386) |
| Share-based\tcompensation | — | — | 151 | — | — | — | — | 151 |
| Share-based\tcompensation\ttax\texpense | — | — | (3) | — | — | — | — | (3) |
| Acquisition\tof\tnoncontrolling\tinterests | — | — | — | — | — | — | 4,670 | 4,670 |
| Subsidiary\tequity\ttransactions | — | — | 93 | — | — | — | 277 | 370 |
| Distributions\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | (235) | (235) |
| Other | — | — | 1 | — | — | — | 6 | 7 |
| Balance\tas\tof\tDecember\t31,\t2014 | 409 | 41 | 4,088 | 16,631 | 779 | — | 4,802 | 26,341 |
| Net\tloss | — | — | — | (14,454) | — | — | (749) | (15,203) |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | — | — | — | — | (549) | — | — | (549) |
| Stock\toption\texercises | — | — | 4 | — | — | — | — | 4 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 2 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | — | — | — | — | — | (35) | — | (35) |
| Common\tstock\tretired | — | — | (35) | — | — | 35 | — | — |
| Common\tstock\tdividends | — | — | — | (396) | — | — | — | (396) |
| Common\tstock\tissued | 7 | 1 | 198 | — | — | — | — | 199 |
| Share-based\tcompensation | — | — | 165 | — | — | — | — | 165 |
| Share-based\tcompensation\ttax\texpense | — | — | (9) | — | — | — | — | (9) |
| Subsidiary\tequity\ttransactions | — | — | 585 | — | — | — | 141 | 726 |
| Distributions\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | (254) | (254) |
| Balance\tas\tof\tDecember\t31,\t2015 | 418 | $42 | $4,996 | $1,781 | $230 | $— | $3,940 | $10,989 |

# 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.	Devon	also	owns	natural	gas	pipelines,	plants	and	treatment	facilities through	its	ownership	in	EnLink	and	the	General	Partner.

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	and	distributions.	Investments	accounted	for	using	the	equity	method	and	cost	method	are	reported	as	a	component	of	other	long-term	assets.

As	discussed	more	fully	in	Note	2,	Devon	completed	a	business	combination	in	2014	whereby	Devon	controls	both	EnLink	and	the	General	Partner.	Devon controls	both	the	General	Partner's	and	EnLink's	operations;	therefore,	the	General	Partner's	and	EnLink's	accounts	are	included	in	Devon's	accompanying	consolidated financial	statements	subsequent	to	the	completion	of	the	transaction.	The	portions	of	the	General	Partner's	and	EnLink's	net	earnings	and	stockholders'	equity	not attributable	to	Devon's	controlling	interest	are	shown	separately	as	noncontrolling	interests	in	the	accompanying	consolidated	comprehensive	statements	of	earnings	and consolidated	balance	sheets.

# 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;

•the	carrying	value	of	oil	and	gas	properties,	midstream	assets	and	product	and	equipment	inventories;

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

•the	fair	value	of	intangible	assets	other	than	goodwill;

•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

Oil,	gas	and	NGL	sales	are	recognized	when	production	is	sold	to	a	purchaser	at	a	fixed	or	determinable	price,	delivery	has	occurred,	title	has	transferred	and collectability	of	the	revenue	is	probable.	Delivery	occurs	and	title	typically	is	transferred	when	production	has	been	delivered	to	a	pipeline,	railcar	or	truck.	Cash received	relating	to	future	production	is	deferred	and	recognized	when	all	revenue	recognition	criteria	are	met.	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.

Marketing	and	midstream	revenues	are	recorded	at	the	time	products	are	sold	or	services	are	provided	to	third	parties	at	a	fixed	or	determinable	price,	delivery	or performance	has	occurred,	title	has	transferred	and	collectability	of	the	revenue	is	probable.	Revenues	and	expenses	attributable	to	oil,	gas	and	NGL	purchases, transportation	and	processing	contracts	are	reported	on	a	gross	basis	when	Devon	takes	title	to	the	products	and	has	risks	and	rewards	of	ownership.

During	2015,	2014	and	2013,	no	purchaser	accounted	for	more	than	10%	of	Devon's	operating	revenues.

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	periodically	enters	into	derivative	financial	instruments	with	respect	to	a	portion	of	its	oil,	gas	and	NGL	production	to	hedge	future	prices	received. Additionally,	Devon	and	EnLink	periodically	enter	into	derivative	financial	instruments	with	respect	to	a	portion	of	their	oil,	gas	and	NGL	marketing	activities.	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,	costless	price	collars	and	call	options.	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.	The	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	to	the	collars. The	call	options	give	counterparties	the	right	to	purchase	production	at	a	predetermined	price.

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.

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,	2015,	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.	Cash	settlements	that	Devon	is	entitled	to	are	accrued	for	in other	current	assets	in	the	accompanying	consolidated	balance	sheets.	As	of	December	31,	2015,	Devon	accrued	$236	million	that	it	received	in	January	2016	related	to cash	settlements.

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,	2015	and	December	31,	2014,	Devon	held	$75 million	and	$524	million,	respectively,	of	cash	collateral,	which	represented	the	estimated	fair	value	of	certain	derivative	positions	in	excess	of	Devon's	credit guidelines.	The	collateral	is	reported	in	other	current	liabilities	in	the	accompanying	consolidated	balance	sheets.

G&A	is	reported	net	of	amounts	reimbursed	by	working	interest	owners	of	the	oil	and	gas	properties	operated	by	Devon	and	net	of	amounts	capitalized	pursuant to	the	full	cost	method	of	accounting.

# Share-Based	Compensation

Independent	of	EnLink,	Devon	grants	share-based	awards	to	independent	members	of	its	Board	of	Directors	and	selected	employees.	EnLink	and	the	General Partner	also	grant	share-based	awards	to	independent	members	of	its	Board	of	Directors	and	selected	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	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	7	for	further	discussion.

Devon	does	not	recognize	U.S.	deferred	income	taxes	on	the	unremitted	earnings	of	its	foreign	subsidiaries	that	are	deemed	to	be	indefinitely	reinvested.	When such	earnings	are	no	longer	deemed	indefinitely	reinvested,	Devon	recognizes	the	appropriate	deferred,	or	even	current,	income	tax	liabilities.

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.

# 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	outstanding	stock	options.

# 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	and	midstream	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	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.

# Investments

Devon	periodically	invests	excess	cash	in	U.S.	and	Canadian	treasury	securities	and	other	marketable	securities.	Devon	considers	securities	with	original contractual	maturities	in	excess	of	three	months	but	less	than	one	year	to	be	short-term	investments.	Investments	with	contractual	maturities	in	excess	of	one	year	are classified	as	long-term,	unless	such	investments	are	classified	as	trading	or	available-for-sale.	Devon	reports	its	investments	and	other	marketable	securities	at	fair	value.

# Property	and	Equipment

Devon	follows	the	full	cost	method	of	accounting	for	its	oil	and	gas	properties.	Accordingly,	all	costs	incidental	to	the	acquisition,	exploration	and	development	of oil	and	gas	properties,	including	costs	of	undeveloped	leasehold,	dry	holes	and	leasehold	equipment,	are	capitalized.	Internal	costs	incurred	that	are	directly	identified with	acquisition,	exploration	and	development	activities	undertaken	by	Devon	for	its	own	account,	and	that	are	not	related	to	production,	general	corporate	overhead	or similar	activities,	are	also

capitalized.	Interest	costs	incurred	and	attributable	to	unproved	oil	and	gas	properties	under	current	evaluation	and	major	development	projects	of	oil	and	gas	properties are	also	capitalized.	All	costs	related	to	production	activities,	including	workover	costs	incurred	solely	to	maintain	or	increase	levels	of	production	from	an	existing completion	interval,	are	charged	to	expense	as	incurred.

Capitalized	costs	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.	Depletion	is calculated	using	the	capitalized	costs,	including	estimated	asset	retirement	costs,	plus	the	estimated	future	expenditures	(based	on	current	costs)	to	be	incurred	in developing	proved	reserves,	net	of	estimated	salvage	values.

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	quarterly.	Significant	unproved	properties	are	assessed	individually.	Costs	of	insignificant unproved	properties	are	transferred	into	the	depletion	calculation	over	holding	periods	ranging	from	three	to	four	years.

Sales	or	dispositions	of	oil	and	gas	properties	are	generally	accounted	for	as	adjustments	to	capitalized	costs	with	no	gain	or	loss	recognized	upon	disposal	of	oil and	gas	properties	unless	such	disposal	significantly	alters	the	relationship	between	capitalized	costs	and	proved	reserves	in	a	particular	country.	As	discussed	more	fully in	Note	2,	the	2014	divestitures	of	certain	Canadian	assets	significantly	altered	such	relationship,	and	Devon	recognized	a	gain,	which	is	included	as	a	separate	item	in the	accompanying	consolidated	comprehensive	statements	of	earnings.

Under	the	full	cost	method	of	accounting,	capitalized	costs	of	oil	and	gas	properties,	net	of	accumulated	DD&A	and	deferred	income	taxes,	may	not	exceed	the full	cost	"ceiling"	at	the	end	of	each	quarter.	The	ceiling	is	calculated	separately	for	each	country	and	is	based	on	the	present	value	of	estimated	future	net	cash	flows from	proved	oil	and	gas	reserves,	discounted	at	10%	per	annum,	net	of	related	tax	effects.	The	estimated	future	net	revenues	exclude	future	cash	outflows	associated with	settling	asset	retirement	obligations	included	in	the	net	book	value	of	oil	and	gas	properties.

Estimated	future	net	cash	flows	are	calculated	using	end-of-period	costs	and	an	unweighted	arithmetic	average	of	commodity	prices	in	effect	on	the	first	day	of each	of	the	previous	12	months.	Prices	are	held	constant	indefinitely	and	are	not	changed	except	where	different	prices	are	fixed	and	determinable	from	applicable contracts	for	the	remaining	term	of	those	contracts,	including	derivative	contracts	in	place	that	qualify	for	hedge	accounting	treatment.	None	of	Devon's	derivative contracts	held	during	the	three-year	period	ended	December	31,	2015	qualified	for	hedge	accounting	treatment.

Any	excess	of	the	net	book	value,	less	related	deferred	taxes,	over	the	ceiling	is	written	off	as	an	expense.	An	expense	recorded	in	one	period	may	not	be	reversed in	a	subsequent	period	even	though	higher	commodity	prices	may	have	increased	the	ceiling	applicable	to	the	subsequent	period.

Costs	for	midstream	assets	that	are	in	use	are	depreciated	over	the	assets'	estimated	useful	lives,	using	either	the	unit-of-production	or	straight-line	method. 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	midstream	and	corporate	construction	projects	are	also	capitalized.

Devon	recognizes	liabilities	for	retirement	obligations	associated	with	tangible	long-lived	assets,	such	as	producing	well	sites	and	midstream	pipelines	and processing	plants	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	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	an	assessment	of qualitative	and	quantitative	factors.	The	impairment	test	requires	allocating	goodwill	and	all	other	assets	and	liabilities	to	assigned	reporting	units.	The	fair	value	of	each reporting	unit	is	estimated	and	compared	to	the	net	book	value	of	the	reporting	unit.	If	the	estimated	fair	value	of	the	reporting	unit	is	less	than	the	net	book	value, including	goodwill,	then	the	goodwill	is	written	down	to	the	implied	fair	value	of	the	goodwill	through	a	charge	to	expense.	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	annual	impairment	tests	of	goodwill	in	the	fourth	quarters	of	2015,	2014	and	2013.	No	impairment	of	goodwill	was	required	in	2013.	However, write-downs	were	required	in	2015	and	2014	based	on	the	annual	impairment	test.	EnLink's	Texas,	Louisiana	and	Crude	and	Condensate	reporting	segment	goodwill were	deemed	impaired	in	2015,	and	Devon's	Canadian	reporting	unit	goodwill	was	deemed	impaired	in	2014.	See	Note	12	for	further	discussion.

# Intangible	Assets

Unamortized	capitalized	intangible	assets,	consisting	of	EnLink	customer	relationships,	are	presented	in	other	long-term	assets	in	the	accompanying	consolidated balance	sheets.	These	assets	are	amortized	on	a	straight-line	basis	over	the	expected	periods	of	benefits,	which	range	from	10-20	years.	During	2015,	EnLink's	customer relationships	were	also	evaluated	for	impairment,	and	a	portion	of	these	intangibles	was	considered	impaired.	See	Note	12	for	further	discussion.

# 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	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	Issued	Accounting	Standards

The	FASB	issued	ASU	2014-09,	Revenue	from	Contracts	with	Customers	(Topic	606).	This	ASU	supersedes	the	revenue	recognition	requirements	in	Topic	605, Revenue	Recognition	and	industry-specific	guidance	in	Subtopic	932-605,	Extractive	Activities	–	Oil	and	Gas	–	Revenue	Recognition.	This	ASU	provides	guidance concerning	the	recognition	and	measurement	of	revenue	from	contracts	with	customers.	Its	objective	is	to	increase	the	usefulness	of	information	in	the	financial statements	regarding	the	nature,	timing	and	uncertainty	of	revenues.	The	effective	date	for	ASU	2014-09	was	delayed	through	the	issuance	of	ASU	2015-14,	Revenue from	Contracts	with	Customers	–	Deferral	of	the	Effective	Date,	to	annual	and	interim	periods	beginning	in	2018	and	is	required	to	be	adopted	using	either	the retrospective	or	cumulative	effect	(modified	retrospective)	transition	method,	with	early	adoption	permitted	in	2017.	Devon	is	evaluating	the	impact	this	ASU	will	have on	its	consolidated	financial	statements	and	related	disclosures	and	does	not	plan	on	early	adopting.

The	FASB	issued	ASU	2015-02,	Consolidation	(Topic	810):	Amendments	to	the	Consolidation	Analysis.	This	ASU	provides	additional	guidance	to	reporting entities	in	evaluating	whether	certain	legal	entities,	such	as	limited	partnerships,	limited	liability	corporations	and	securitization	structures,	should	be	consolidated.	The ASU

is	considered	to	be	an	improvement	on	current	accounting	requirements	as	it	reduces	the	number	of	existing	consolidation	models.	This	ASU	is	effective	for	Devon beginning	January	1,	2016	and	will	be	applied	using	the	retrospective	approach.	This	ASU	will	not	have	a	material	impact	on	Devon's	consolidated	financial	statements and	related	disclosures.

The	FASB	issued	ASU	2015-03,	Interest	–	Imputation	of	Interest	(Topic	835):	Simplifying	the	Presentation	of	Debt	Issuance	Costs	and	ASU	2015-15,	Interest	– Imputation	of	Interest	(Topic	835):	Presentation	and	Subsequent	Measurement	of	Debt	Issuance	Costs	Associated	with	Line-of-Credit	Arrangements.	These	ASUs require	debt	issuance	costs	related	to	a	recognized	debt	liability,	except	for	those	related	to	revolving	credit	facilities,	to	be	presented	on	the	balance	sheet	as	a	direct deduction	from	the	carrying	amount	of	that	debt	liability	rather	than	as	an	asset.	These	ASUs	are	effective	for	Devon	beginning	January	1,	2016	and	will	be	applied using	the	retrospective	approach.	These	ASUs	will	not	have	a	material	impact	on	Devon's	consolidated	financial	statements	and	related	disclosures.

The	FASB	issued	ASU	2015-17,	Balance	Sheet	Classification	of	Deferred	Taxes.	This	ASU	requires	that	all	deferred	tax	assets	and	liabilities,	along	with	any related	valuation	allowance,	be	classified	as	noncurrent	on	the	balance	sheet.	This	ASU	is	effective	for	annual	and	interim	periods	beginning	in	2017	and	can	be	applied prospectively	or	retrospectively,	with	early	adoption	permitted.	This	ASU	will	be	early-adopted	by	Devon,	effective	January	1,	2016	and	will	be	applied	using	the retrospective	approach.	This	ASU	will	not	have	a	material	impact	on	Devon's	consolidated	financial	statements	and	related	disclosures.

# 2. Acquisitions	and	Divestitures

# Formation	of	EnLink	and	the	General	Partner

On	March	7,	2014,	Devon	and	Crosstex	completed	a	transaction	to	combine	substantially	all	of	Devon's	U.S.	midstream	assets	with	Crosstex's	assets	to	form	a midstream	business	that	consists	of	the	General	Partner	and	EnLink,	which	are	both	publicly	traded.

In	exchange	for	a	controlling	interest	in	both	EnLink	and	the	General	Partner,	Devon	contributed	its	equity	interest	in	a	newly	formed	Devon	subsidiary,	EMH, and	$100	million	in	cash.	EMH	owned	midstream	assets	in	the	Barnett	Shale	in	north	Texas	and	the	Cana-	and	Arkoma-Woodford	Shales	in	Oklahoma,	as	well	as	an economic	interest	in	Gulf	Coast	Fractionators	in	Mont	Belvieu,	Texas.

This	business	combination	was	accounted	for	using	the	acquisition	method	of	accounting.	Under	the	acquisition	method	of	accounting,	EMH	was	the	accounting acquirer	because	its	parent	company,	Devon,	obtained	control	of	EnLink	and	the	General	Partner	as	a	result	of	the	business	combination.	Consequently,	EMH's	assets and	liabilities	retained	their	carrying	values.	Additionally,	the	Crosstex	assets	acquired	and	liabilities	assumed	by	the	General	Partner	and	EnLink	in	the	business combination,	as	well	as	the	General	Partner's	noncontrolling	interest	in	EnLink,	were	recorded	at	their	fair	values	which	were	measured	as	of	the	acquisition	date, March	7,	2014.	The	excess	of	the	purchase	price	over	the	estimated	fair	values	of	Crosstex's	net	assets	acquired	was	recorded	as	goodwill.

| The	following	table	summarizes	the	purchase	price	(millions,	except	unit	price). |  |  |
| :--- | :--- | :--- |
| Crosstex\tEnergy,\tInc.\toutstanding\tcommon\tshares: |  |  |
| Held\tby\tpublic\tshareholders | Held\tby\tpublic\tshareholders | 48.0 |
| Restricted\tshares | Restricted\tshares | 0.4 |
| Total\tsubject\tto\tconversion | Total\tsubject\tto\tconversion | 48.4 |
| Exchange\tratio | Exchange\tratio | 1.0x |
| Converted\tshares |  | 48.4 |
| Crosstex\tEnergy,\tInc.\tcommon\tshare\tprice\t^(1) | Crosstex\tEnergy,\tInc.\tcommon\tshare\tprice\t^(1) | $37.60 |
| Crosstex\tEnergy,\tInc.\tconsideration | Crosstex\tEnergy,\tInc.\tconsideration | $1,823 |
| Fair\tvalue\tof\tnoncontrolling\tinterests\tin\tE2\t^(2) | Fair\tvalue\tof\tnoncontrolling\tinterests\tin\tE2\t^(2) | 18 |
| Total\tCrosstex\tEnergy,\tInc.\tconsideration\tand\tfair\tvalue\tof\tnoncontrolling\tinterests | Total\tCrosstex\tEnergy,\tInc.\tconsideration\tand\tfair\tvalue\tof\tnoncontrolling\tinterests | $1,841 |
| Crosstex\tEnergy,\tLP\toutstanding\tunits: |  |  |
| Common\tunits\theld\tby\tpublic\tunitholders | Common\tunits\theld\tby\tpublic\tunitholders | 75.1 |
| Preferred\tunits\theld\tby\tthird\tparty^\t(3) | Preferred\tunits\theld\tby\tthird\tparty^\t(3) | 17.1 |
| Restricted\tunits |  | 0.4 |
| Total | Total | 92.6 |
| Crosstex\tEnergy,\tLP\tcommon\tunit\tprice\t^(4) |  | $30.51 |
| Crosstex\tEnergy,\tLP\tcommon\tunits\tvalue | Crosstex\tEnergy,\tLP\tcommon\tunits\tvalue | $2,825 |
| Crosstex\tEnergy,\tLP\toutstanding\tunit\toptions\tvalue |  | 4 |
| Total\tfair\tvalue\tof\tnoncontrolling\tinterests\tin\tCrosstex\tEnergy,\tLP | (4) | \t 2,829 |
| Total\tconsideration\tand\tfair\tvalue\tof\tnoncontrolling\tinterests |  | $4,670 |
| (1) |  |  |
| (2) |  |  |
| (3) |  |  |
| (4) |  |  |
| The\tallocation\tof\tthe\tpurchase\tprice\tis\tas\tfollows\t(millions): |  |  |
| Assets\tacquired: |  |  |
| Current\tassets | Current\tassets | $437 |
| Property,\tplant\tand\tequipment,\tnet | Property,\tplant\tand\tequipment,\tnet | 2,438 |
| Intangible\tassets |  | 569 |
| Equity\tinvestment | Equity\tinvestment | 222 |
| Goodwill^\t(1) |  | 3,283 |
| Other\tlong-term\tassets | Other\tlong-term\tassets | 1 |
| Liabilities\tassumed: |  |  |
| Current\tliabilities | Current\tliabilities | (515) |
| Long-term\tdebt |  | (1,454) |
| Deferred\tincome\ttaxes | Deferred\tincome\ttaxes | (210) |
| Other\tlong-term\tliabilities |  | (101) |
| Total\tconsideration\tand\tfair\tvalue\tof\tnoncontrolling\tinterests | Total\tconsideration\tand\tfair\tvalue\tof\tnoncontrolling\tinterests | $4,670 |

(1) Goodwill	is	the	excess	of	the	consideration	transferred	over	the	net	assets	recognized	and	represents	the	future	economic	benefits	arising	from	other	assets acquired	that	could	not	be	individually	identified	and	separately	recognized.	Goodwill	is	not	amortized	and	is	not	deductible	for	tax	purposes.

# EnLink	Acquisitions

The	following	table	presents	a	summary	of	EnLink's	acquisition	activity	for	2015.

| Date | Acquiree | Cash | EnLink<br>Units | PP&amp;E | Goodwill | Intangibles | Other |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| January\t31 | LPC | $108 | — | $30 | $30 | $43 | $5 |
| March\t16 | Coronado | $240 | $360 | $302 | $18 | $281 | $(1) |
| October\t1 | Matador | $145 | — | $36 | $9 | $99 | $1 |

On	January	7,	2016,	EnLink	also	acquired	Anadarko	Basin	gathering	and	processing	midstream	assets	from	Tall	Oak	for	approximately	$1.5	billion,	subject	to certain	adjustments.	EnLink	paid	approximately	$800	million	of	cash	at	the	time	of	closing,	primarily	funded	with	the	issuance	of	EnLink	preferred	units,	with	another $500	million	of	cash	to	be	paid	within	24	months.	The	remainder	of	the	purchase	price	consisted	of	approximately	15.6	million	General	Partner	common	units.

In	February	2015,	EnLink	acquired	a	25%	equity	interest	in	EMH	from	the	General	Partner	in	exchange	for	units	valued	at	approximately	$925	million.	In	May 2015,	EnLink	acquired	the	remaining	25%	equity	interest	in	EMH	from	the	General	Partner	in	exchange	for	units	valued	at	approximately	$900	million.

In	April	2015,	EnLink	acquired	VEX	from	Devon	for	approximately	$176	million	in	cash	and	equity.	EnLink	also	assumed	approximately	$35	million	in	certain future	construction	costs	to	expand	the	system	to	full	capacity.	Because	Devon	controls	EnLink	and	the	General	Partner,	the	acquisition	of	VEX	by	EnLink	from	Devon was	accounted	for	as	a	transfer	of	net	assets	between	entities	under	common	control.

# Devon	Acquisitions

On	February	28,	2014,	Devon	completed	its	acquisition	of	interests	in	certain	affiliates	of	GeoSouthern	for	approximately	$6.0	billion.	Devon	funded	the acquisition	with	cash	on	hand	and	debt	financing.	In	connection	with	the	GeoSouthern	transaction,	Devon	acquired	approximately	82,000	net	acres	(unaudited)	located in	DeWitt	and	Lavaca	counties	in	south	Texas.	The	transaction	was	accounted	for	using	the	acquisition	method,	which	requires,	among	other	things,	that	assets	acquired and	liabilities	assumed	be	recognized	at	their	fair	values	as	of	the	acquisition	date.

The	allocation	of	the	purchase	price	is	as	follows	(millions).

On	December	17,	2015,	Devon	acquired	approximately	253,000	net	acres	(unaudited)	and	assets	in	the	Powder	River	Basin	for	approximately	$499	million. Devon	funded	the	acquisition	with	$300	million	of	cash	and	$199	million	of	equity.	A	preliminary	allocation	of	the	purchase	price	at	December	31,	2015	was	$386 million	to	unproved	properties	and	$113	million	to	proved	properties	and	gathering	systems.

On	January	7,	2016,	Devon	acquired	approximately	80,000	net	acres	(unaudited)	and	assets	in	the	STACK	play	for	approximately	$1.5	billion.	Devon	funded	the acquisition	with	$850	million	of	cash	and	$659	million	of	equity.

# Pro	Forma	Financial	Information

The	following	unaudited	pro	forma	financial	information	has	been	prepared	assuming	both	the	EnLink	formation	and	the	GeoSouthern	acquisition	occurred	on January	1,	2013.	The	pro	forma	information	is	not	intended	to	reflect	the	actual	results	of	operations	that	would	have	occurred	if	the	business	combination	and acquisition	had	been	completed	at	the	dates	indicated.	In	addition,	they	do	not	project	Devon's	results	of	operations	for	any	future	period.

|  | Year	Ended	December	31,<br>				2014 | 2013 |
| :--- | :--- | :--- |
|  | (Millions) |  |
| Total\toperating\trevenues | $20,213 | $12,979 |
| Net\tearnings | $1,716 | $35 |
| Noncontrolling\tinterests | $97 | $45 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $1,619 | $(10) |
| Net\tearnings\t(loss)\tper\tcommon\tshare\tattributable\tto\tDevon | $3.94 | $(0.02) |

# Asset	Divestitures

During	2014,	Devon	divested	certain	properties	located	throughout	Canada	and	the	U.S.	as	part	of	its	asset	portfolio	transformation.

# Canada

In	the	second	quarter	of	2014,	Devon	sold	Canadian	conventional	assets	for	$2.8	billion	($3.125	billion	Canadian	dollars)	and	recognized	a	gain	totaling	$1.1 billion	($0.6	billion	after-tax).	This	gain	is	included	as	a	separate	item	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.	Included	in	the	gain calculation	were	asset	retirement	obligations	of	approximately	$700	million	assumed	by	the	purchaser	as	well	as	the	derecognition	of	approximately	$700	million	of goodwill	allocated	to	the	sold	assets.	In	conjunction	with	the	divestiture,	Devon	repatriated	approximately	$2.8	billion	of	proceeds	to	the	U.S.	in	the	second	quarter	of 2014,	which	was	utilized	to	repay	commercial	paper	and	term	loan	balances.	Between	collecting	the	divestiture	proceeds	and	repatriating	funds	to	the	U.S.,	Devon recognized	an	$84	million	foreign	currency	exchange	loss	and	a	$29	million	foreign	exchange	currency	derivative	loss.	These	losses	are	included	in	other	nonoperating items	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

In	the	third	quarter	of	2014,	Devon	sold	certain	U.S.	assets	for	$2.2	billion.	Additionally,	approximately	$200	million	of	asset	retirement	obligations	were assumed	by	the	purchaser.	No	gain	or	loss	was	recognized	on	the	sale.	These	proceeds	were	used	toward	the	early	retirement	of	$1.9	billion	in	senior	notes	in	November 2014	as	discussed	in	Note	13.

# Commodity	Derivatives

As	of	December	31,	2015,	Devon	had	the	following	open	oil	derivative	positions.	The	first	table	presents	Devon's	oil	derivatives	that	settle	against	the	average	of the	prompt	month	NYMEX	WTI	futures	price.	The	second	table	presents	Devon's	oil	derivatives	that	settle	against	the	respective	indices	noted	within	the	table.

As	of	December	31,	2015,	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.

As	of	December	31,	2015,	EnLink	had	the	following	open	derivative	positions	associated	with	gas	processing	and	fractionation.	EnLink's	NGL	positions	settle	by purity	product	against	the	average	of	the	prompt	month	OPIS	Mont	Belvieu,	Texas	index.	EnLink's	natural	gas	positions	settle	against	the	Henry	Hub	Gas	Daily	index.

# Interest	Rate	Derivatives

As	of	December	31,	2015,	Devon	had	the	following	open	interest	rate	derivative	positions:

(1) Mandatory	settlement	in	December	2018.

# Foreign	Currency	Derivatives

As	of	December	31,	2015,	Devon	had	the	following	open	foreign	currency	derivative	position:

|  |  |  | Weighted	Average |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Contract | CAD | Fixed\tRate |  |
| Currency | Type | Notional | Received | Expiration |
|  |  | (Millions) | (CAD-USD) |  |
| Canadian\tDollar | Sell | $3,560 | 0.723 | March\t2016 |

# 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.

|  | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Commodity\tderivatives: |  |  |  |
| Oil,\tgas\tand\tNGL\tderivatives | $503 | $1,989 | $(191) |
| Marketing\tand\tmidstream\trevenues | 9 | 22 | \t — |
| Interest\trate\tderivatives: |  |  |  |
| Other\tnonoperating\titems | (20) | (1) | \t — |
| Foreign\tcurrency\tderivatives: |  |  |  |
| Other\tnonoperating\titems | \t 246 | 60 | 56 |
| Net\tgains\t(losses)\trecognized | $738 | $2,070 | $(135) |

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

# caption.

|  | December	31,<br>2015 |  | December	31,<br>2014 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Commodity\tderivative\tassets: |  |  |  |
| Derivatives,\tat\tfair\tvalue | $34 |  | $1,984 |
| Other\tlong-term\tassets | 1 |  | 11 |
| Interest\trate\tderivative\tassets: |  |  |  |
| Derivatives,\tat\tfair\tvalue | 1 |  | 1 |
| Other\tlong-term\tassets | 1 |  | — |
| Foreign\tcurrency\tderivative\tassets: |  |  |  |
| Derivatives,\tat\tfair\tvalue | 8 |  | 8 |
| Total\tderivative\tassets | $45 |  | $2,004 |
| Commodity\tderivative\tliabilities: |  |  |  |
| Other\tcurrent\tliabilities | $14 |  | $28 |
| Other\tlong-term\tliabilities | 4 |  | 28 |
| Interest\trate\tderivative\tliabilities: |  |  |  |
| Other\tcurrent\tliabilities | — |  | 1 |
| Other\tlong-term\tliabilities | 22 |  | — |
| Foreign\tcurrency\tderivative\tliabilities: |  |  |  |
| Other\tcurrent\tliabilities | 8 |  | — |
| Total\tderivative\tliabilities | $48 |  | $57 |

In	the	second	quarter	of	2015,	Devon's	stockholders	approved	the	2015	Long-Term	Incentive	Plan.	The	2015	Plan	replaces	the	2009	Long-Term	Incentive	Plan, as	amended.	From	the	effective	date	of	the	2015	Plan,	no	further	awards	may	be	made	under	the	2009	Plan,	and	awards	previously	granted	will	continue	to	be	governed by	the	terms	of	the	2009	Plan.	Subject	to	the	terms	of	the	2015	Plan,	awards	may	be	made	under	the	2015	Plan	for	a	total	of	28	million	shares	of	Devon	common	stock, plus	the	number	of	shares	available	for	issuance	under	the	2009	Plan	(including	shares	subject	to	outstanding	awards	under	the	2009	Plan	that	are	subsequently	forfeited, canceled	or	expire).	The	2015	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	awards	or	units	and	stock	appreciation rights	to	eligible	employees.	The	2015	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	2015	Plan,	options	and	stock	appreciation	rights	represent	one	share	and other	awards	represent	three	shares.

Devon	also	has	a	stock	option	plan	that	was	adopted	in	2005	under	which	stock	options	were	issued	to	certain	employees.	Options	granted	under	this	plan	remain exercisable	by	the	employees	owning	such	options,	but	no	new	options	or	restricted	stock	awards	will	be	granted	under	this	plan.

Devon	did	not	have	an	annual	long-term	incentive	grant	in	2013	due	to	revisions	in	the	timing	of	the	employee	compensation	cycle.	The	annual	long-term incentive	grant	related	to	2013	performance	was	granted	in	February	2014.

The	following	table	presents	the	effects	of	share-based	compensation	included	in	Devon's	accompanying	consolidated	comprehensive	statements	of	earnings. Gross	G&A	for	the	years	ended	December	31,	2015	and	2014	includes	$31	million	and	$17	million,	respectively,	of	unit-based	compensation	related	to	grants	made under	EnLink's	long-term	incentive	plans.

The	vesting	for	certain	share-based	awards	was	accelerated	in	2014	in	conjunction	with	the	divestiture	of	Devon's	Canadian	conventional	assets.	For	the	year ended	December	31,	2014,	approximately	$15	million	of	associated	expense	for	these	accelerated	awards	is	included	in	restructuring	costs	in	the	accompanying consolidated	comprehensive	statements	of	earnings.

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Gross\tgeneral\tand\tadministrative\texpense\tfor\tshare-based\tcompensation | $225 | $199 | $157 |
| Share-based\tcompensation\texpense\tcapitalized\tpursuant\tto\tthe\tfull\tcost\tmethod\tof\taccounting\tfor\toil |  |  |  |
| and\tgas\tproperties | $63 | $53 | $60 |
| Related\tincome\ttax\tbenefit | $45 | $42 | $29 |

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.

|  | Restricted	Stock<br>Awards	and	Units | Restricted	Stock<br>Awards	and	Units | Performance-Based<br>Restricted	Stock	Awards | Performance-Based<br>Restricted	Stock	Awards | Performance	Share<br>Units | Performance	Share<br>Units |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Awards\nand\nUnits | Weighted\nAverage\nGrant-Date\nFair\tValue | Awards | Weighted\nAverage\nGrant-Date\nFair\tValue | Units | Weighted\nAverage\nGrant-Date\nFair\tValue |
|  |  |  | (Thousands,\texcept\tfair\tvalue\tdata) | (Thousands,\texcept\tfair\tvalue\tdata) |  |  |
| Unvested\tat\t12/31/14 | 4,304 | $60.85 | 380 | $59.41 | \t1,477 | $70.90 |
| Granted | 2,771 | $63.57 | 236 | $62.02 | 786 | $84.14 |
| Vested | \t(1,834) | $60.33 | (153) | $59.49 | (337) | $66.00 |
| Forfeited | (503) | $62.22 | (29) | $64.18 | (67) | $79.20 |
| Unvested\tat\t12/31/15 | 4,738 | $62.49 | 434 | $60.48 | \t1,859^(1) | $76.17 |

(1) A	maximum	of	3.7	million	common	shares	could	be	awarded	based	upon	Devon's	final	TSR	ranking.

The	following	table	presents	the	aggregate	fair	value	of	awards	and	units	that	vested	during	the	indicated	period.

|  | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Restricted\tstock\tawards\tand\tunits | $101 | $112 | $141 |
| Performance-based\trestricted\tstock\tawards | $8 | $10 | $5 |
| Performance\tshare\tunits | $22 | $— | $— |

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,	2015.

|  | Restricted	Stock<br>Awards	and	Units | Performance-Based<br>Restricted	Stock<br>Awards | Performance<br>Share	Units |
| :--- | :--- | :--- | :--- |
| Unrecognized\tcompensation\tcost\t(millions) | $198 | $6 | $45 |
| Weighted\taverage\tperiod\tfor\trecognition\t(years) | 2.5 | 2.6 | 1.8 |

# 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	zero	to	four	years.	During	the	vesting	period,	recipients	of restricted	stock	awards	receive	dividends	that	are	not	subject	to	restrictions	or	other	limitations.	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	are	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	zero	to	four	years. In	order	for	awards	to	vest,	the	performance	target	must	be	met	in	the	first	year,	and	if	met,	recipients	are	entitled	to	dividends	on	the	awards	over	the	remaining	service vesting	period.	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	senior	management.	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	two-	or	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.

|  | 2015 | 2014 | 2013 |
| :--- | :--- | :--- | :--- |
| Grant-date\tfair\tvalue | $81.99\t–\t$85.05 | $70.18\t–\t$81.05 | $61.27\t–\t$63.48 |
| Risk-free\tinterest\trate | 1.06% | 0.54% | 0.26%\t–\t0.36% |
| Volatility\tfactor | 26.2% | 28.8% | 30.3% |
| Contractual\tterm\t(years) | 2.89 | 2.89 | 3.0 |

# 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 zero	to	four	years.	The	fair	value	of	stock	options	on

the	date	of	grant	is	expensed	over	the	applicable	vesting	period.	Devon	estimates	the	fair	values	of	stock	options	granted	using	a	Black-Scholes	option	valuation	model, which	requires	Devon	to	make	several	assumptions,	including	a	volatility	factor,	dividend	yield	rate,	risk-free	interest	rate	and	expected	term.	No	stock	options	were granted	in	2015,	2014	and	2013.	The	following	table	presents	a	summary	of	Devon's	outstanding	stock	options.

|  |  | Weighted	Average |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Options | Exercise\nPrice | Remaining\nTerm | Intrinsic\nValue |
|  | (Thousands) | (Years) | (Years) | (Millions) |
| Outstanding\tat\tDecember\t31,\t2014 | 4,218 | $70.56 |  |  |
| Granted | — | $— |  |  |
| Exercised | (63) | $64.25 |  |  |
| Expired | (680) | $84.36 |  |  |
| Forfeited | (27) | $66.71 |  |  |
| Outstanding\tat\tDecember\t31,\t2015 | 3,448 | $67.98 | 2.41 | $— |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2015 | 3,448 | $67.98 | 2.41 | $— |
| Exercisable\tat\tDecember\t31,\t2015 | 3,448 | $67.98 | 2.41 | $— |

The	aggregate	intrinsic	value	of	stock	options	that	were	exercised	during	2015,	2014	and	2013	was	$0.2	million,	$9	million	and	$0.3	million,	respectively.	As	of December	31,	2015,	Devon	had	no	unrecognized	compensation	cost	related	to	unvested	stock	options.

# EnLink	Share-Based	Awards

In	March	2015,	the	General	Partner	and	EnLink	issued	restricted	incentive	units	as	bonus	payments	to	officers	and	certain	employees	for	2014.	The	combined grant	fair	value	was	$7	million,	and	the	total	cost	was	recognized	in	the	first	quarter	of	2015	due	to	the	awards	vesting	immediately.

The	following	table	presents	a	summary	of	the	unrecognized	compensation	cost	and	the	related	weighted	average	recognition	period	associated	with	the	General Partner's	and	EnLink's	unvested	restricted	incentive	units	and	performance	units	as	of	December	31,	2015.

|  | Restricted<br>Incentive	Units | Performance<br>Units | Restricted<br>Incentive	Units | Performance<br>Units |
| :--- | :--- | :--- | :--- | :--- |
| Unrecognized\tcompensation\tcost\t(millions) | $17 | $3 | $16 | $3 |
| Weighted\taverage\tperiod\tfor\trecognition\t(years) | 1.6 | 2.0 | 1.6 | 2.0 |

The	following	table	presents	the	asset	impairments	recognized	in	2015,	2014	and	2013.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| U.S.\toil\tand\tgas\tassets | $17,992 | $— | $1,110 |
| Canada\toil\tand\tgas\tassets | 1,257 | — | 843 |
| Canada\tgoodwill | — | \t 1,941 | — |
| EnLink\tgoodwill | 1,328 | — | — |
| EnLink\tother\tintangible\tassets | 223 | — | — |
| Other\tassets | 20 | 12 | 23 |
| Total\tasset\timpairments | $20,820 | $1,953 | $1,976 |

# Oil	and	Gas	Impairments

Under	the	full	cost	method	of	accounting,	capitalized	costs	of	oil	and	gas	properties	are	subject	to	a	quarterly	full	cost	ceiling	test,	which	is	discussed	in	Note	1.

The	oil	and	gas	impairments	resulted	from	declines	in	the	U.S.	and	Canada	full	cost	ceilings.	The	lower	ceiling	values	resulted	primarily	from	significant decreases	in	the	12-month	average	trailing	prices	for	oil,	bitumen,	natural	gas	and	NGLs,	which	significantly	reduced	proved	reserves	values	and,	to	a	lesser	degree, proved	reserves.	For	further	information,	see	Note	21.

# Goodwill	and	Other	Intangible	Assets	Impairments

In	2015,	Devon	recognized	goodwill	and	other	intangible	asset	impairments	related	to	EnLink's	business.	In	2014,	Devon	recognized	a	goodwill	impairment related	to	its	Canadian	reporting	unit.	Additional	information	regarding	these	impairments	is	discussed	in	Note	12.

# Canadian	Reduction	in	Work	Force

In	2015,	Devon	recognized	$24	million	of	employee	related	and	other	costs	associated	with	the	reduction	in	work	force	made	subsequent	to	the	completion	of	the Jackfish	development	projects	and	a	decrease	in	planned	capital	investment	resulting	from	the	drop	in	commodity	prices.	Devon	incurred	employee	severance,	lease obligation	and	other	costs	related	to	the	vacated	office	space	as	part	of	the	cost	reduction	plan.

# Canadian	Divestitures

During	2014,	Devon	recognized	$46	million	of	employee	related	and	other	costs	associated	with	its	divestiture	of	certain	Canadian	assets.	Approximately	$15 million	of	the	employee	related	costs	resulted	from	accelerated	vesting	of	share-based	grants,	which	are	noncash	charges.

# Office	Consolidation

Near	the	end	of	2012,	Devon	consolidated	its	U.S.	personnel	into	a	single	operations	group	centrally	located	at	the	company's	corporate	headquarters	in Oklahoma	City.	As	a	result,	Devon	closed	its	office	in	Houston,

transferred	operational	responsibilities	for	assets	in	south	Texas,	east	Texas	and	Louisiana	to	Oklahoma	City	and	incurred	$134	million	of	restructuring	costs	associated with	the	consolidation.	The	employee	severance	and	retention	costs	included	amounts	related	to	cash	severance	costs	and	accelerated	vesting	of	share-based	grants.	The lease	obligations	and	other	costs	are	associated	with	certain	office	space	that	is	subject	to	non-cancellable	operating	lease	agreements	that	Devon	ceased	using	as	part	of the	office	consolidation.

Due	to	a	lack	of	demand	for	vacated	office	space	in	which	Devon's	remaining	leases	are	located,	in	2015,	Devon	recognized	an	additional	$54	million	expense	as a	result	of	its	inability	to	fully	sublease	remaining	office	space.

The	following	table	summarizes	restructuring	costs	presented	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t2015 | \t\t2014 | \t\t2013 |
|  |  | (Millions) |  |
| Office\tconsolidation\tand\toffshore\tdivestiture: |  |  |  |
| Employee\tseverance\tand\tretention | $ — | $ — | $13 |
| Lease\tobligations\tand\tother | 54 | \t — | 41 |
| Canada\tdivestitures: |  |  |  |
| Employee\tseverance\tand\tretention | 11 | 42 | \t — |
| Lease\tobligations\tand\tother | 13 | 4 | \t — |
| Restructuring\tcosts | $78 | $46 | $54 |

The	following	table	summarizes	Devon's	restructuring	liabilities.

|  | Other<br>Current<br>Liabilities | Other<br>Long-term<br>Liabilities | Total |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Balance\tas\tof\tDecember\t31,\t2013 | $27 | $18 | $45 |
| Changes\tdue\tto\toffice\tconsolidation\tand\toffshore\tdivestiture | (18) | (11) | (29) |
| Changes\tdue\tto\tCanadian\tdivestitures | 4 | — | 4 |
| Balance\tas\tof\tDecember\t31,\t2014 | 13 | 7 | 20 |
| Changes\tdue\tto\toffice\tconsolidation\tand\toffshore\tdivestiture | 1 | 46 | 47 |
| Changes\tdue\tto\tCanadian\tdivestitures | (1) | 10 | 9 |
| Balance\tas\tof\tDecember\t31,\t2015 | $13 | $63 | $76 |

# Income	Tax	Expense	(Benefit)

The	following	table	presents	Devon's	income	tax	components.

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Current\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | $(243) | $152 | $73 |
| Various\tstates | (8) | 18 | (5) |
| Canada\tand\tvarious\tprovinces | 14 | 307 | 4 |
| Total\tcurrent\ttax\texpense\t(benefit) | (237) | 477 | 72 |
| Deferred\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | (5,033) | \t 1,610 | 198 |
| Various\tstates | (336) | 93 | 59 |
| Canada\tand\tvarious\tprovinces | (459) | 188 | (160) |
| Total\tdeferred\ttax\texpense\t(benefit) | (5,828) | \t 1,891 | 97 |
| Total\tincome\ttax\texpense\t(benefit) | $(6,065) | $2,368 | $169 |

Total	income	tax	expense	(benefit)	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
| Total\tincome\ttax\texpense\t(benefit)\t(millions) | $(6,065) | $2,368 | $169 |
| U.S.\tstatutory\tincome\ttax\trate | (35)% | 35% | 35% |
| Non-deductible\tgoodwill\tand\tintangible\timpairment | 2% | 23% | 0% |
| Taxation\ton\tCanadian\toperations | 1% | (4)% | 9% |
| State\tincome\ttaxes | (1)% | 2% | 23% |
| Repatriations | 0% | 2% | 65% |
| Deferred\ttax\tasset\tvaluation\tallowance | 4% | 0% | 0% |
| Other | 0% | 0% | (19)% |
| Effective\tincome\ttax\trate | (29)% | 58% | \t 113% |

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.

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	examination	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	judgements	and	assumptions	are	inherent	in	the	determination	of	future	taxable	income,	including	factors	such	as	future	operation	conditions (particularly	as	related	to	prevailing	oil	and	gas	prices)	and	changing	tax	laws.

In	the	third	and	fourth	quarters	of	2015,	EnLink	recorded	goodwill	and	intangibles	impairments	of	approximately	$1.6	billion.	These	impairments	are	not deductible	for	purposes	of	calculating	income	tax	and,	therefore,	have	an	impact	on	the	effective	tax	rate.

During	2015,	Devon	recorded	approximately	$18	billion	of	oil	and	gas	impairments	related	to	its	U.S.	operations.	These	impairments	resulted	in	deferred	tax assets	against	which	we	recognized	a	$967	million	valuation	allowance	that	impacted	the	effective	tax	rate	and	is	discussed	in	the	next	section.

In	the	second	and	fourth	quarters	of	2014,	goodwill	was	removed	in	conjunction	with	the	Canadian	conventional	asset	divestitures,	and	Devon	recorded	a	goodwill impairment	in	the	Canadian	reporting	unit,	respectively.	These	transactions	are	not	deductible	for	purposes	of	calculating	income	tax	and	therefore	have	an	impact	on	the effective	tax	rate.

Additionally,	during	2014,	Devon	repatriated	to	the	U.S.	$2.8	billion	of	cash	relating	to	the	Canadian	asset	divestiture.	In	conjunction	with	the	repatriation,	Devon recognized	approximately	$105	million	of	additional	income	tax	expense	for	the	full	year.	Prior	to	the	repatriation,	Devon	had	recognized	a	$143	million	deferred income	tax	liability	associated	with	the	planned	repatriation.	When	the	repatriation	was	made,	Devon	retained	a	larger	property	basis	in	Canada	than	was	previously estimated,	resulting	in	the	incremental	tax.	After	the	use	of	foreign	tax	credits,	the	current	income	tax	on	the	repatriation	was	$67	million.

Furthermore,	Devon	completed	its	divestiture	program	of	certain	assets	in	the	U.S.	In	conjunction	with	the	divestiture	closing	and	due	to	the	availability	of additional	tax	deductions,	Devon	recognized	$294	million	of	current	income	tax	expense.	The	current	tax	expense	was	entirely	offset	by	the	recognition	of	deferred	tax benefits.

Devon	also	recorded	a	$46	million	deferred	tax	liability	in	conjunction	with	the	formation	of	EnLink	in	2014.

In	the	second	and	fourth	quarters	of	2013,	Devon	repatriated	to	the	U.S.	a	total	of	$4.3	billion	of	its	cash	held	outside	of	the	U.S.	In	the	fourth	quarter	of	2013, Devon	announced	plans	to	divest	of	its	Canadian	conventional	assets.	These	events	resulted	in	an	incremental	income	tax	expense	of	$97	million.	The	incremental expense	included	$180	million	of	current	income	tax	expense	offset	by	$83	million	of	deferred	income	tax	benefit.	The	$83	million	deferred	tax	benefit	was	comprised of	$180	million	of	deferred	tax	benefits	that	offset	the	incremental	current	income	tax	expense	and	an	additional	$97	million	of	deferred	income	tax	expense	accrued	in the	fourth	quarter	for	assumed	repatriations.

# 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.

| Property	and	equipment | $490 | $— |
| :--- | :--- | :--- |
| Asset\tretirement\tobligations | 485 | 458 |
| Accrued\tliabilities | 160 | 150 |
| Net\toperating\tloss\tcarryforwards | 175 | 200 |
| Pension\tbenefit\tobligations | 106 | 113 |
| Other | 162 | 180 |
| Total\tdeferred\ttax\tassets\tbefore\tvaluation\tallowance | 1,578 | 1,101 |
| Less:\tvaluation\tallowance | (967) | — |
| Net\tdeferred\ttax\tassets | 611 | 1,101 |
| Deferred\ttax\tliabilities: |  |  |
| Property\tand\tequipment | (1,187) | (6,940) |
| Fair\tvalue\tof\tfinancial\tinstruments | — | (699) |
| Long-term\tdebt | (36) | (115) |
| Other | (271) | (160) |
| Total\tdeferred\ttax\tliabilities | (1,494) | (7,914) |
| Net\tdeferred\ttax\tliability | $(883) | $(6,813) |

At	December	31,	2015,	Devon	has	$175	million	of	deferred	tax	assets	related	to	various	net	operating	loss	carryforwards	available	to	offset	future	income	taxes. The	net	operating	loss	carryforwards	consist	of	$495	million	of	Canadian	carryforwards	that	expire	between	2030	and	2035,	$275	million	of	U.S.	state	carryforwards that	expire	between	2018	and	2035	and	$205	million	of	carryforwards	related	to	EnLink's	operations	that	expire	between	2028	and	2035.	In	the	current	environment, Devon	expects	the	tax	benefits	from	the	Canadian	and	EnLink	net	operating	loss	carryforwards	to	be	utilized	in	2017	and	beyond.	Devon	also	has	$6	million	of	deferred tax	assets	related	to	alternative	minimum	tax	credits,	which	have	no	expiration	date	and	will	be	available	for	use	against	tax	on	future	taxable	income.

At	the	end	of	2015,	Devon	had	deferred	tax	assets	that	largely	resulted	from	the	full	cost	impairments	recognized	during	2015.	As	a	result	of	the	recent cumulative	financial	losses,	Devon	recorded	a	$967	million,	or	100%,	valuation	allowance	against	the	U.S.	deferred	tax	assets	as	of	December	31,	2015.	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.

As	of	December	31,	2015,	Devon's	unremitted	foreign	earnings	from	its	other	international	operations	totaled	approximately	$1.2	billion.	All	but	$37	million	of the	$1.2	billion	was	deemed	to	be	indefinitely	reinvested	into	the	development	and	growth	of	Devon's	Canadian	business.	Therefore,	Devon	has	not	recognized	a deferred	tax	liability	for	U.S.	income	taxes	associated	with	such	earnings.	If	such	earnings	were	to	be	repatriated	to	the	U.S.,	Devon	may	be	subject	to	U.S.	income	taxes and	foreign	withholding	taxes.	However,	it	is	not	practical	to	estimate	the	amount	of	such	additional	taxes	that	may	be	payable	due	to	the	inter-relationship	of	the	various factors	involved	in	making	such	an	estimate.

For	the	remaining	$37	million	of	unremitted	earnings	deemed	not	to	be	indefinitely	reinvested,	Devon	has	recognized	a	$10	million	deferred	tax	liability associated	with	such	unremitted	earnings	as	of	December	31,	2015.

# Unrecognized	Tax	Benefits

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

|  | December	31,<br>2015 | 2014 |
| :--- | :--- | :--- |
|  | (Millions) |  |
| Balance\tat\tbeginning\tof\tyear | $241 | $243 |
| Tax\tpositions\ttaken\tin\tprior\tperiods | (19) | \t — |
| Tax\tpositions\ttaken\tin\tcurrent\tyear | 31 | \t — |
| Accrual\tof\tinterest\trelated\tto\ttax\tpositions\ttaken | (5) | 2 |
| Settlements | (108) | \t — |
| Foreign\tcurrency\ttranslation | (9) | (4) |
| Balance\tat\tend\tof\tyear | $131 | $241 |

Devon's	unrecognized	tax	benefit	balance	at	December	31,	2015	and	2014	included	$29	million	and	$34	million,	respectively,	of	interest	and	penalties.	If recognized,	$131	million	of	Devon's	unrecognized	tax	benefits	as	of	December	31,	2015	would	affect	Devon's	effective	income	tax	rate.	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. As	a	result,	Devon	cannot	reasonably	anticipate	the	extent	that	the	liabilities	for	unrecognized	tax	benefits	will	increase	or	decrease	within	the	next	twelve	months.

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

| Net	earnings	(loss)	attributable	to	Devon | $(14,454) | $1,607 | $(20) |
| :--- | :--- | :--- | :--- |
| Attributable\tto\tparticipating\tsecurities | (5) | (17) | (2) |
| Basic\tand\tdiluted\tearnings\t(loss) | $(14,459) | $1,590 | $(22) |
| Common\tshares: |  |  |  |
| Common\tshares\toutstanding\t-\ttotal | 412 | 409 | 406 |
| Attributable\tto\tparticipating\tsecurities | (5) | (4) | (4) |
| Common\tshares\toutstanding\t-\tbasic | 407 | 405 | 402 |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | 2 | — |
| Common\tshares\toutstanding\t-\tdiluted | 407 | 407 | 402 |
| Net\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon: |  |  |  |
| Basic | $(35.55) | $3.93 | $(0.06) |
| Diluted | $(35.55) | $3.91 | $(0.06) |
| Antidilutive\toptions^\t(1) | 4 | 3 | 7 |

(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.

# 9. Other	Comprehensive	Earnings

Components	of	other	comprehensive	earnings	consist	of	the	following:

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Foreign\tcurrency\ttranslation: |  |  |  |
| Beginning\taccumulated\tforeign\tcurrency\ttranslation | $983 | $1,448 | $1,996 |
| Change\tin\tcumulative\ttranslation\tadjustment | (621) | (499) | (574) |
| Income\ttax\tbenefit | 62 | 34 | 26 |
| Ending\taccumulated\tforeign\tcurrency\ttranslation | 424 | 983 | \t 1,448 |
| Pension\tand\tpostretirement\tbenefit\tplans: |  |  |  |
| Beginning\taccumulated\tpension\tand\tpostretirement\tbenefits | (204) | (180) | (225) |
| Net\tactuarial\tgain\t(loss)\tand\tprior\tservice\tcost\tarising\tin\tcurrent\tyear | (5) | (57) | 48 |
| Recognition\tof\tnet\tactuarial\tloss\tand\tprior\tservice\tcost\tin\tearnings^\t(1) | 21 | 20 | 24 |
| Income\ttax\tbenefit\t(expense) | (6) | 13 | (27) |
| Ending\taccumulated\tpension\tand\tpostretirement\tbenefits | (194) | (204) | (180) |
| Accumulated\tother\tcomprehensive\tearnings,\tnet\tof\ttax | $230 | $779 | $1,268 |

(1) These	accumulated	other	comprehensive	earnings	components	are	included	in	the	computation	of	net	periodic	benefit	cost,	which	is	a	component	of	G&A	on	the accompanying	consolidated	comprehensive	statements	of	earnings.	See	Note	15	for	additional	details.

# 10. Supplemental	Information	to	Statements	of	Cash	Flows

| 10.<br>Supplemental	Information	to	Statements	of	Cash	Flows |  |  |  |
| :--- | :--- | :--- | :--- |
|  | Year\tEnded\tDecember\t31, | Year\tEnded\tDecember\t31, |  |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Net\tchange\tin\tworking\tcapital\taccounts: |  |  |  |
| Accounts\treceivable | $942 | $128 | $(288) |
| Income\ttaxes\treceivable | 384 | (467) | 29 |
| Other\tcurrent\tassets | (57) | (222) | 20 |
| Accounts\tpayable | (190) | (68) | 26 |
| Revenues\tand\troyalties\tpayable | (526) | 133 | 35 |
| Income\ttaxes\tpayable | (275) | 30 | \t — |
| Other\tcurrent\tliabilities | (579) | 516 | (120) |
| Net\tchange\tin\tworking\tcapital | $(301) | $50 | $(298) |
| Interest\tpaid\t(net\tof\tcapitalized\tinterest) | $494 | $514 | $406 |
| Income\ttaxes\tpaid\t(received) | $(279) | $899 | $13 |

On	March	7,	2014,	Devon	completed	a	business	combination	to	form	EnLink.	With	the	exception	of	a	$100	million	cash	payment	to	noncontrolling	interests,	the business	combination	was	a	non-monetary	transaction.	EnLink's	noncash	acquisition	activity	during	2015	included	a	portion	of	the	Coronado	transaction.

As	discussed	in	Note	2,	Devon's	acquisition	of	certain	Powder	River	Basin	assets	included	noncash	common	stock	issuance	totaling	$199	million.

|  | December	31,	2015 |  | December	31,	2014 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Oil,\tgas\tand\tNGL\tsales | $362 |  | $723 |
| Joint\tinterest\tbillings | 211 |  | 475 |
| Marketing\tand\tmidstream\trevenues | 520 |  | 706 |
| Other | 30 |  | 71 |
| Gross\taccounts\treceivable | 1,123 |  | 1,975 |
| Allowance\tfor\tdoubtful\taccounts | (18) |  | (16) |
| Net\taccounts\treceivable | $1,105 |  | $1,959 |

# 12. Goodwill	and	Other	Intangible	Assets

The	following	table	presents	a	summary	of	Devon's	goodwill.

|  | U.S. | Canada | EnLink | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |  |
| Balance\tas\tof\tDecember\t31,\t2013 | $2,618 | $2,838 | $402 | $5,858 |
| Acquired\tduring\tperiod | — | — | 3,283 | 3,283 |
| Asset\tdivestitures | — | (706) | — | (706) |
| Impairment | — | (1,941) | — | (1,941) |
| Foreign\tcurrency\ttranslation\tadjustments | — | (191) | — | (191) |
| Balance\tas\tof\tDecember\t31,\t2014 | $2,618 | $— | $3,685 | $6,303 |
| Acquired\tduring\tperiod | — | — | 57 | 57 |
| Impairment | — | — | (1,328) | (1,328) |
| Balance\tas\tof\tDecember\t31,\t2015 | $2,618 | $— | $2,414 | $5,032 |

The	following	table	presents	the	General	Partner's	and	EnLink's	goodwill	activity	by	reporting	unit.

|  | Texas | Louisiana | Oklahoma | Crude	and<br>Condensate | General<br>Partner | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |  |
| Balance\tas\tof\tDecember\t31,\t2013 | $326 | $— | $76 | $— | $— | $402 |
| Acquired\tduring\tperiod | 842 | 787 | 114 | 113 | \t 1,427 | 3,283 |
| Balance\tas\tof\tDecember\t31,\t2014 | $1,168 | $787 | $190 | $113 | $1,427 | $3,685 |
| Acquired\tduring\tperiod | 28 | — | — | 29 | — | 57 |
| Impairment | (492) | (787) | — | (49) | — | (1,328) |
| Balance\tas\tof\tDecember\t31,\t2015 | $704 | $— | $190 | $93 | $1,427 | $2,414 |

# Acquired	During	Period

Included	in	the	assets	Devon	contributed	to	EMH	was	$402	million	of	goodwill.	See	Note	2	for	discussion	of	acquired	goodwill	resulting	from	EnLink's formation	in	2014	and	acquisitions	in	2015.

In	conjunction	with	the	Canadian	conventional	asset	divestitures	in	2014,	Devon	removed	$706	million	of	goodwill,	which	was	allocated	to	these	assets.

# Impairment

As	further	discussed	in	Note	1,	Devon	performs	an	annual	impairment	test	of	goodwill	at	October	31,	or	more	frequently	if	events	or	changes	in	circumstances indicate	that	the	carrying	value	of	a	reporting	unit	may	not	be	recoverable.	Sustained	weakness	in	the	overall	energy	sector	driven	by	low	commodity	prices,	together with	a	decline	in	EnLink's	unit	price,	caused	a	change	in	circumstances	warranting	an	interim	impairment	test	of	EnLink's	reporting	units.	Furthermore,	due	to	the continued	impact	of	declining	commodity	prices	and	EnLink	unit	price,	an	update	was	performed	as	of	December	31,	2015.	As	a	result	of	these	tests,	noncash	goodwill impairments	were	recorded	related	to	EnLink's	Texas,	Louisiana	and	Crude	and	Condensate	reporting	units	in	2015.

In	the	fourth	quarter	of	2014,	as	a	result	of	its	annual	impairment	test	of	goodwill,	Devon	concluded	the	implied	fair	value	of	its	Canadian	goodwill	was	zero	and wrote	off	the	remaining	goodwill.	This	conclusion	was	largely	based	on	the	significant	decline	in	benchmark	oil	prices,	particularly	after	OPEC's	decision	not	to	reduce its	production	targets	that	was	announced	in	late	November	2014.	Devon's	Canadian	goodwill	was	originally	recognized	in	2001	as	a	result	of	a	business	combination consisting	almost	entirely	of	conventional	gas	assets	that	Devon	no	longer	owns.

During	2015,	EnLink's	customer	relationships	were	also	evaluated	for	impairment	due	to	the	factors	in	the	aforementioned	goodwill	impairment	analysis.	Level	3 fair	value	measurements	were	utilized	for	the	impairment	analysis	of	definite-lived	intangible	assets,	which	included	discounted	cash	flow	estimates,	consistent	with those	utilized	in	the	goodwill	impairment	assessment.	This	assessment	resulted	in	a	$223	million	noncash	impairment	related	to	EnLink's	Crude	and	Condensate customer	relationships	in	2015.

The	following	table	presents	other	intangible	assets	reported	in	other	long-term	assets	in	the	accompanying	consolidated	balance	sheets.

|  | December	31,	2015 |  | December	31,	2014 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Customer\trelationships | $745 |  | $569 |
| Accumulated\tamortization | (55) |  | (36) |
| Net\tintangibles | $690 |  | $533 |

The	weighted-average	amortization	period	for	the	customer	relationships	is	12.6	years.	Amortization	expense	for	intangibles	was	approximately	$56	million	and $36	million	for	the	years	ended	December	31,	2015	and	December	31,	2014,	respectively.	The	remaining	aggregate	amortization	expense	is	estimated	to	be approximately	$46	million	each	of	the	next	five	years.

# 13. Debt	and	Related	Expenses

A	summary	of	debt	is	as	follows:

|  | December	31,	2015 |  | December	31,	2014 |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Devon\tdebt |  |  |  |
| Commercial\tpaper | $626 |  | $932 |
| Floating\trate\tdue\tDecember\t15,\t2015 | — |  | 500 |
| Floating\trate\tdue\tDecember\t15,\t2016 | 350 |  | 350 |
| 8.25%\tdue\tJuly\t1,\t2018 | 125 |  | 125 |
| 2.25%\tdue\tDecember\t15,\t2018 | 750 |  | 750 |
| 6.30%\tdue\tJanuary\t15,\t2019 | 700 |  | 700 |
| 4.00%\tdue\tJuly\t15,\t2021 | 500 |  | 500 |
| 3.25%\tdue\tMay\t15,\t2022 | 1,000 |  | 1,000 |
| 5.85%\tdue\tDecember\t15,\t2025 | 850 |  | — |
| 7.50%\tdue\tSeptember\t15,\t2027 | 150 |  | 150 |
| 7.875%\tdue\tSeptember\t30,\t2031 | 1,250 |  | 1,250 |
| 7.95%\tdue\tApril\t15,\t2032 | 1,000 |  | 1,000 |
| 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 |  | — |
| Net\tdiscount\ton\tdebentures\tand\tnotes | (28) |  | (18) |
| Total\tDevon\tdebt | 10,023 |  | 9,239 |
| EnLink\tdebt |  |  |  |
| Credit\tfacilities | 414 |  | 237 |
| 2.70%\tdue\tApril\t1,\t2019 | 400 |  | 400 |
| 7.125%\tdue\tJune\t1,\t2022 | 163 |  | 163 |
| 4.40%\tdue\tApril\t1,\t2024 | 550 |  | 550 |
| 4.15%\tdue\tJune\t1,\t2025 | 750 |  | — |
| 5.60%\tdue\tApril\t1,\t2044 | 350 |  | 350 |
| 5.05%\tdue\tApril\t1,\t2045 | 450 |  | 300 |
| Net\tpremium\ton\tdebentures\tand\tnotes | 13 |  | 23 |
| Total\tEnLink\tdebt | 3,090 |  | 2,023 |
| Total\tdebt | 13,113 |  | 11,262 |
| Less\tamount\tclassified\tas\tshort-term\tdebt^\t(1) | 976 |  | 1,432 |
| Total\tlong-term\tdebt | $12,137 |  | $9,830 |

(1) 2015	short-term	debt	consists	of	$626	million	of	commercial	paper	and	the	$350	million	floating	rate	due	on	December	15,	2016.	2014	short-term	debt	consists	of $932	million	of	commercial	paper	and	$500	million	floating	rate	due	on	December	15,	2015.

Debt	maturities	as	of	December	31,	2015,	excluding	premiums	and	discounts,	are	as	follows	(millions):

# Credit	Lines

Devon	has	a	$3.0	billion	Senior	Credit	Facility.	The	maturity	date	for	$30	million	of	the	Senior	Credit	Facility	is	October	24,	2017.	The	maturity	date	for	$164 million	of	the	Senior	Credit	Facility	is	October	24,	2018.	The	maturity	date	for	the	remaining	$2.8	billion	is	October	24,	2019.	Amounts	borrowed	under	the	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	Senior	Credit	Facility	currently	provides	for	an	annual	facility	fee	of	$3.8	million	that	is	payable quarterly	in	arrears.	As	of	December	31,	2015,	there	were	no	borrowings	under	the	Senior	Credit	Facility.

The	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.	Also,	total	capitalization	is	adjusted	to	add	back	noncash	financial	write- downs	such	as	full	cost	ceiling	impairments	or	goodwill	impairments.	As	of	December	31,	2015,	Devon	was	in	compliance	with	this	covenant	with	a	debt-to- capitalization	ratio	of	23.7%.

# Commercial	Paper

Devon's	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, 2015,	Devon's	outstanding	commercial	paper	borrowings	had	a	weighted-average	borrowing	rate	of	0.63%.

# Issuance	of	Senior	Notes

In	June	2015,	Devon	issued	$750	million	of	5.0%	senior	notes	due	2045	that	are	unsecured	and	unsubordinated	obligations.	Devon	used	the	net	proceeds	to	repay the	floating	rate	senior	notes	that	matured	on	December	15,	2015,	as	well	as	outstanding	commercial	paper	balances.

In	December	2015,	in	conjunction	with	the	announcement	of	the	Powder	River	Basin	and	STACK	acquisitions,	Devon	issued	$850	million	of	5.85%	senior	notes due	2025	that	are	unsecured	and	unsubordinated	obligations.	Devon	used	the	net	proceeds	to	fund	the	cash	portion	of	these	acquisitions.

# Retirement	of	Senior	Notes

In	November	2014,	Devon	redeemed	$1.9	billion	of	senior	notes	prior	to	their	scheduled	maturity,	primarily	with	proceeds	received	from	its	asset	divestitures. The	redemption	includes	the	2.4%	$500	million	senior	notes	due	2016,	the	1.2%	$650	million	senior	notes	due	2016	and	the	1.875%	$750	million	senior	notes	due	2017. The	notes	were	redeemed	for	$1.9	billion,	which	included	100%	of	the	principal	amount	and	a	make-whole	premium	of	$40	million.	On	the	date	of	redemption,	these notes	also	had	an	unamortized	discount	of	$2	million	and	unamortized	debt	issuance	costs	of	$6	million.	The	make-whole	premium,	unamortized	discounts	and	debt issuance	costs	are	included	in	net	financing	costs	on	the	accompanying	2014	consolidated	comprehensive	statement	of	earnings.

# Other	Debentures	and	Notes

Following	are	descriptions	of	the	various	other	debentures	and	notes	outstanding	at	December	31,	2015	and	2014,	as	listed	in	the	table	presented	at	the	beginning of	this	note.

# GeoSouthern	Debt

In	December	2013,	in	conjunction	with	the	planned	GeoSouthern	acquisition,	Devon	issued	$2.25	billion	aggregate	principal	amount	of	fixed	and	floating	rate senior	notes.	Devon	repaid	the	floating	rate	senior	notes	due	2015	upon	maturity	and	redeemed	the	1.2%	senior	notes	due	December	15,	2016	in	November	2014.	As	of December	31,	2015,	the	floating	rate	senior	notes	due	2016	and	the	2.25%	senior	notes	due	December	15,	2018	were	outstanding.	The	floating	rate	senior	notes	due 2016	bear	interest	at	a	rate	equal	to	three-month	LIBOR	plus	0.54%,	which	will	be	reset	quarterly.

# Other	Notes

In	2012,	2011,	2009	and	2002,	Devon	issued	senior	notes	that	are	unsecured	and	unsubordinated	obligations	of	Devon.	Devon	used	the	net	proceeds	to	repay outstanding	commercial	paper,	credit	facility	borrowings	and	other	long-term	debt.	The	schedule	below	summarizes	the	key	terms	of	these	notes	(millions).

|  | May	2012 | July	2011 | January	2009 | March	2002 |
| :--- | :--- | :--- | :--- | :--- |
| 3.25%\tdue\tMay\t15,\t2022 | $1,000 | $— | $— | $— |
| 4.75%\tdue\tMay\t15,\t2042 | 750 | — | — | — |
| 4.00%\tdue\tJuly\t15,\t2021 | — | 500 | — | — |
| 5.60%\tdue\tJuly\t15,\t2041 | — | 1,250 | — | — |
| 6.30%\tdue\tJanuary\t15,\t2019 | — | — | 700 | — |
| 7.95%\tdue\tApril\t15,\t2032 | — | — | — | 1,000 |
| Discount\tand\tissuance\tcosts | (28) | (24) | (8) | (14) |
| Net\tproceeds | $1,722 | $1,726 | $692 | $986 |

# Ocean	Debt

On	April	25,	2003,	Devon	merged	with	Ocean	Energy,	Inc.	and	assumed	certain	debt	instruments.	The	table	below	summarizes	the	debt	assumed	that	remains outstanding	as	of	December	31,	2015,	including	the	fair	value	of	the	debt	at	April	25,	2003	and	the	effective	interest	rate	of	the	debt	after	determining	the	fair	values using

April	25,	2003	market	interest	rates.	The	premiums	resulting	from	fair	values	exceeding	face	values	are	being	amortized	using	the	effective	interest	method.	Both	notes are	general	unsecured	obligations	of	Devon.

|  | Debt | Effective	Rate	of |
| :--- | :--- | :--- |
|  | Assumed | Debt\tAssumed |
| Debt\tAssumed | (Millions) |  |
| 8.25%\tdue\tJuly\t2018\t(principal\tof\t$125\tmillion) | $147 | 5.5% |
| 7.50%\tdue\tSeptember\t2027\t(principal\tof\t$150\tmillion) | $169 | 6.5% |

In	October	2001,	Devon,	through	Devon	Financing,	a	wholly	owned	finance	subsidiary,	sold	debentures,	which	are	unsecured	and	unsubordinated	obligations	of Devon	Financing.	Devon	has	fully	and	unconditionally	guaranteed,	on	an	unsecured	and	unsubordinated	basis,	the	obligations	of	Devon	Financing	under	the	debt securities.	The	proceeds	were	used	to	fund	a	portion	of	the	Anderson	Exploration	acquisition.

# EnLink	Debt

All	of	EnLink's	and	the	General	Partner's	debt	is	non-recourse	to	Devon.

The	table	below	summarizes	the	fair	value	of	EnLink's	debt	as	of	March	7,	2014,	the	formation	date	of	EnLink.	The	premiums	are	being	amortized	using	the effective	interest	method.

In	February	2015,	the	commitments	under	EnLink's	$1.0	billion	unsecured	revolving	credit	facility	were	increased	to	$1.5	billion,	and	the	maturity	date	was extended	by	a	year	to	March	6,	2020.	As	of	December	31,	2015,	there	were	$11	million	in	outstanding	letters	of	credit	and	$414	million	outstanding	borrowings,	with	a weighted-average	borrowing	rate	of	1.7%,	under	the	$1.5	billion	credit	facility.	The	General	Partner	has	a	$250	million	revolving	credit	facility	that	will	mature	on March	7,	2019.	As	of	December	31,	2015,	the	General	Partner	had	no	outstanding	borrowings	under	the	$250	million	credit	facility.	EnLink	and	the	General	Partner were	in	compliance	with	all	financial	covenants	in	their	respective	credit	facilities	as	of	December	31,	2015.

In	March	2014,	EnLink	issued	$1.2	billion	aggregate	principal	amount	of	unsecured	senior	notes,	consisting	of	$400	million	of	its	2.70%	senior	notes	due	2019, $450	million	of	its	4.40%	senior	notes	due	2024	and	$350	million	of	its	5.60%	senior	notes	due	2044,	at	discounts	of	their	face	value.	EnLink	used	the	net	proceeds	to redeem	the	2018	senior	notes,	reduce	outstanding	credit	facility	borrowings,	for	capital	expenditures	and	for	general	operations.

offered	as	an	additional	issue	of	EnLink's	outstanding	4.40%	senior	notes	due	2024,	issued	in	March	2014.	The	2024	notes	issued	in	March	2014	and	November	2014 are	treated	as	a	single	class	of	debt	securities	and	have	identical	terms,	other	than	the	issue	date.	EnLink	used	the	net	proceeds	for	capital	expenditures	and	for	general operations.

In	May	2015,	EnLink	issued	$900	million	principal	amount	of	unsecured	senior	notes,	consisting	of	$750	million	principal	amount	of	its	4.15%	senior	notes	due 2025	and	an	additional	$150	million	principal	amount	of	its	5.05%	senior	notes	due	2045.	EnLink	used	the	net	proceeds	to	repay	outstanding	revolving	credit	facility borrowings,	for	capital	expenditures	and	for	general	operations.

The	following	schedule	includes	the	components	of	net	financing	costs.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t2015 | \t\t2014 | \t\t2013 |
|  |  | (Millions) |  |
| Interest\tbased\ton\tdebt\toutstanding | $ 565 | $ 532 | $ 466 |
| Early\tretirement\tof\tdebt | \t — | 48 | \t — |
| Capitalized\tinterest | (62) | (70) | (56) |
| Other\tfees\tand\texpenses | 20 | 26 | 27 |
| Interest\texpense | 523 | 536 | 437 |
| Interest\tincome | (6) | (10) | (20) |
| Net\tfinancing\tcosts | $ 517 | $ 526 | $ 417 |

The	following	table	presents	the	changes	in	asset	retirement	obligations.

|  | Year	Ended	December	31,<br>						2015 | 2014 |
| :--- | :--- | :--- |
|  | (Millions) |  |
| Asset\tretirement\tobligations\tas\tof\tbeginning\tof\tperiod | $1,399 | $2,228 |
| Liabilities\tincurred | 63 | 97 |
| Liabilities\tsettled\tand\tdivested\t^(1) | (89) | (1,009) |
| Revision\tof\testimated\tobligation | 62 | 70 |
| Accretion\texpense\ton\tdiscounted\tobligation | 75 | 89 |
| Foreign\tcurrency\ttranslation\tadjustment | (96) | (76) |
| Asset\tretirement\tobligations\tas\tof\tend\tof\tperiod | 1,414 | 1,399 |
| Less\tcurrent\tportion | 44 | 60 |
| Asset\tretirement\tobligations,\tlong-term | $1,370 | $1,339 |

(1) During	2014,	Devon	reduced	its	asset	retirement	obligation	by	$953	million	for	those	obligations	that	were	assumed	by	purchasers	of	Devon's	Canadian	and	U.S. divested	oil	and	gas	properties.

# 15. Retirement	Plans

Devon	has	various	non-contributory	defined	benefit	pension	plans,	including	qualified	plans	and	nonqualified	plans.	The	qualified	plans	provide	retirement benefits	for	certain	U.S.	and	Canadian	employees	meeting	certain	age	and	service	requirements.	Benefits	for	the	qualified	plans	are	based	on	the	employees'	years	of service	and	compensation	and	are	funded	from	assets	held	in	the	plans'	trusts.

The	nonqualified	plans	provide	retirement	benefits	for	certain	employees	whose	benefits	under	the	qualified	plans	are	limited	by	income	tax	regulations.	The nonqualified	plans'	benefits	are	based	on	the	employees'	years	of	service	and	compensation.	For	certain	nonqualified	plans,	Devon	has	established	trusts	to	fund	these plans'	benefit	obligations.	The	total	value	of	these	trusts	was	$22	million	and	$25	million	at	December	31,	2015	and	2014,	respectively	and	is	included	in	other	long- term	assets	in	the	accompanying	consolidated	balance	sheets.	For	the	remaining	nonqualified	plans	for	which	trusts	have	not	been	established,	benefits	are	funded	from Devon's	available	cash	and	cash	equivalents.

Devon	also	has	defined	benefit	postretirement	plans	that	provide	benefits	for	substantially	all	qualifying	U.S.	retirees.	The	plans	provide	medical	and,	in	some cases,	life	insurance	benefits	and	are	either	contributory	or	non-contributory,	depending	on	the	type	of	plan.	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	presents	the	funded	status	of	Devon's	qualified	and	nonqualified	pension	and	postretirement	benefit	plans.	The	benefit	obligation	for	pension plans	represents	the	projected	benefit	obligation,	while	the	benefit	obligation	for	the	postretirement	benefit	plans	represents	the	accumulated	benefit	obligation.	The accumulated	benefit	obligation	differs	from	the	projected	benefit	obligation	in	that	the	former	includes	no	assumption	about	future	compensation	levels.	The accumulated	benefit	obligation	for	pension	plans	was	$1.2	billion	at	December	31,	2015	and	2014.	Devon's	benefit	obligations	and	plan	assets	are	measured	each	year as	of	December	31.	The	projected	benefit	obligations	for	Devon's	qualified	plans	were	fully	funded	as	of	December	31,	2015	and	2014.

|  | Pension	Benefits<br>2015 | 2014 |  | Postretirement	Benefits<br>				2015 | 2014 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| Change\tin\tbenefit\tobligation: |  |  |  |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $1,377 | $1,177 |  | $24 | $24 |
| Service\tcost | 33 | 30 |  | 1 | 1 |
| Interest\tcost | 52 | 55 |  | 1 | 1 |
| Actuarial\tloss\t(gain) | (68) | 203 |  | (2) | — |
| Plan\tamendments | — | — |  | 1 | — |
| Plan\tsettlements | — | (4) |  | — | — |
| Foreign\texchange\trate\tchanges | (6) | (3) |  | — | — |
| Participant\tcontributions | — | — |  | 2 | 2 |
| Benefits\tpaid | (80) | (81) |  | (4) | (4) |
| Benefit\tobligation\tat\tend\tof\tyear | \t 1,308 | \t 1,377 |  | 23 | 24 |
| Change\tin\tplan\tassets: |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | \t 1,149 | \t 1,006 |  | — | — |
| Actual\treturn\ton\tplan\tassets | (16) | 200 |  | — | — |
| Employer\tcontributions | 11 | 29 |  | 2 | 2 |
| Participant\tcontributions | — | — |  | 2 | 2 |
| Plan\tsettlements | — | (4) |  | — | — |
| Benefits\tpaid | (80) | (81) |  | (4) | (4) |
| Foreign\texchange\trate\tchanges | (5) | (1) |  | — | — |
| Fair\tvalue\tof\tplan\tassets\tat\tend\tof\tyear | \t 1,059 | \t 1,149 |  | — | — |
| Funded\tstatus\tat\tend\tof\tyear | $(249) | $(228) |  | $(23) | $(24) |
| Amounts\trecognized\tin\tbalance\tsheet: |  |  |  |  |  |
| Other\tlong-term\tassets | $2 | $22 |  | $— | $— |
| Other\tcurrent\tliabilities | (12) | (10) |  | (3) | (3) |
| Other\tlong-term\tliabilities | (239) | (240) |  | (20) | (21) |
| Net\tamount | $(249) | $(228) |  | $(23) | $(24) |
| Amounts\trecognized\tin\taccumulated\tother\tcomprehensive\tearnings: |  |  |  |  |  |
| Net\tactuarial\tloss\t(gain) | $302 | $317 |  | $(11) | $(11) |
| Prior\tservice\tcost\t(credit) | 14 | 19 |  | (6) | (9) |
| Total | $316 | $336 |  | $(17) | $(20) |

The	plan	assets	for	pension	benefits	in	the	table	above	exclude	the	assets	held	in	trusts	for	the	nonqualified	plans.	However,	employer	contributions	for	pension benefits	in	the	table	above	include	$11	million	and	$10	million	for	2015	and	2014,	respectively,	which	were	transferred	from	the	trusts	established	for	the	nonqualified plans.

Certain	of	Devon's	pension	plans	have	a	projected	benefit	obligation	and	accumulated	benefit	obligation	in	excess	of	plan	assets	at	December	31,	2015	and	2014, as	presented	in	the	following	table.

|  | 2015 | 2014 |
| :--- | :--- | :--- |
|  | (Millions) |  |
| Projected\tbenefit\tobligation | $244 | $250 |
| Accumulated\tbenefit\tobligation | $199 | $191 |
| Fair\tvalue\tof\tplan\tassets | $— | $— |

# Net	Periodic	Benefit	Cost	and	Other	Comprehensive	Earnings

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

|  | 2015 | Pension	Benefits<br>2014 | 2013 | 2015 | Postretirement	Benefits<br>2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |  |
| Net\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Service\tcost | $33 | $30 | $36 | $1 | $1 | $1 |
| Interest\tcost | 52 | 55 | 51 | 1 | 1 | 1 |
| Expected\treturn\ton\tplan\tassets | (58) | (54) | (62) | \t — | \t — | \t — |
| Curtailment\tand\tsettlement\texpense | \t — | 1 | \t — | \t — | \t — | \t — |
| Recognition\tof\tnet\tactuarial\tloss\t(gain)\t^(1) | 20 | 18 | 22 | (1) | (1) | (1) |
| Recognition\tof\tprior\tservice\tcost\t^(1) | 4 | 4 | 4 | (2) | (2) | (1) |
| Total\tnet\tperiodic\tbenefit\tcost\t^(2) | 51 | 54 | 51 | (1) | (1) | \t — |
| Other\tcomprehensive\tloss\t(earnings): |  |  |  |  |  |  |
| Actuarial\tloss\t(gain)\tarising\tin\tcurrent\tyear | 5 | 57 | (39) | (1) | \t — | (3) |
| Prior\tservice\tcost\t(credit)\tarising\tin\tcurrent\tyear | \t — | \t — | 2 | 1 | \t — | (8) |
| Recognition\tof\tnet\tactuarial\tloss,\tincluding\tsettlement\texpense,\tin\tnet\tperiodic\tbenefit\tcost | (20) | (19) | (22) | 1 | 1 | 1 |
| Recognition\tof\tprior\tservice\tcost,\tincluding\tcurtailment,\tin\tnet\tperiodic\tbenefit\tcost | (4) | (4) | (4) | 1 | 2 | 1 |
| Total\tother\tcomprehensive\tloss\t(earnings) | (19) | 34 | (63) | 2 | 3 | (9) |
| Total\trecognized | $32 | $88 | $ (12) | $1 | $2 | $(9) |

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

(2) Net	periodic	benefit	cost	is	a	component	of	G&A	on	the	accompanying	consolidated	comprehensive	statements	of	earnings.

The	following	table	presents	the	estimated	net	actuarial	loss	and	prior	service	cost	that	will	be	amortized	from	accumulated	other	comprehensive	earnings	into	net periodic	benefit	cost	during	2016.

|  | Pension<br>Benefits |  | Postretirement<br>Benefits |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Net\tactuarial\tloss\t(gain) | $22 |  | $(2) |
| Prior\tservice\tcost\t(credit) | 4 |  | (1) |
| Total | $26 |  | $(3) |

# Assumptions

The	following	table	presents	the	weighted-average	actuarial	assumptions	used	to	determine	obligations	and	periodic	costs.

|  | 2015 | Pension	Benefits<br>2014 | 2013 | 2015 | Postretirement	Benefits<br>2014 | 2013 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Assumptions\tto\tdetermine\tbenefit\tobligations: |  |  |  |  |  |  |
| Discount\trate | \t4.25% | \t3.90% | \t4.80% | \t3.63% | \t3.25% | \t3.65% |
| Rate\tof\tcompensation\tincrease | \t4.49% | \t4.49% | \t4.48% | \tN/A | \tN/A | \tN/A |
| Assumptions\tto\tdetermine\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Discount\trate | \t3.90% | \t4.80% | \t3.85% | \t3.25% | \t3.65% | \t3.30% |
| Rate\tof\tcompensation\tincrease | \t4.49% | \t4.49% | \t4.48% | \tN/A | \tN/A | \tN/A |
| Expected\treturn\ton\tplan\tassets | \t5.22% | \t5.42% | \t5.48% | \tN/A | \tN/A | \tN/A |

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

At	the	end	of	2015,	Devon	changed	the	approach	used	to	measure	service	and	interest	costs	for	pension	and	other	postretirement	benefits.	For	2015,	Devon measured	service	and	interest	costs	utilizing	a	single	weighted-average	discount	rate	derived	from	the	yield	curve	used	to	measure	the	plan	obligations.	For	2016,	Devon elected	to	measure	service	and	interest	costs	by	applying	the	specific	spot	rates	along	that	yield	curve	to	the	plans'	liability	cash	flows.	Devon	believes	the	new	approach provides	a	more	precise	measurement	of	service	and	interest	costs	by	aligning	the	timing	of	the	plans'	liability	cash	flows	to	the	corresponding	spot	rates	on	the	yield curve.	This	change	does	not	affect	the	measurement	of	the	plan	obligations	nor	the	funded	status	of	the	plans.	The	change	in	the	service	and	interest	costs	going	forward is	not	expected	to	be	significant.	This	change	has	been	accounted	for	as	a	change	in	accounting	estimate.

Rate	of	compensation	increase	–	For	measurement	of	the	2015	benefit	obligation	for	the	pension	plans,	a	4.49%	compensation	increase	was	assumed.

Expected	return	on	plan	assets	–	The	expected	rate	of	return	on	plan	assets	was	determined	by	evaluating	input	from	external	consultants	and	economists,	as	well as	long-term	inflation	assumptions.	Devon	expects	the	long-term	asset	allocation	to	approximate	the	targeted	allocation.	Therefore,	the	expected	long-term	rate	of	return on	plan	assets	is	based	on	the	target	allocation	of	investment	types.	See	the	pension	plan	assets	section	below	for	more	information	on	Devon's	target	allocations.

Mortality	rate	assumptions	–	In	2014,	the	Society	of	Actuaries	issued	updated	versions	of	its	mortality	tables	and	mortality	improvement	scale,	reflecting	the increasing	life	expectancies	in	the	U.S.	While	not	required	to	strictly	adhere	to	this	data,	Devon	utilized	actuary-produced	mortality	tables	and	an	improvement	scale derived	from	the	updated	tables	and	the	actuary's	best	estimate	of	mortality	for	the	population	of	participants	in	Devon's	plans.

Other	assumptions	–	For	measurement	of	the	2015	benefit	obligation	for	the	other	postretirement	medical	plans,	a	7.6%	annual	rate	of	increase	in	the	per	capita cost	of	covered	health	care	benefits	was	assumed	for	2016.	The	rate	was	assumed	to	decrease	annually	to	an	ultimate	rate	of	5%	in	the	year	2029	and	remain	at	that	level thereafter.	Assumed	health	care	cost-trend	rates	affect	the	amounts	reported	for	retiree	health	care	costs.	A	one-percentage-point	change	in	the	assumed	health	care	cost- trend	rates	would	have	changed	the	postretirement	benefits	obligation	as	of	December	31,	2015	by	less	than	$1	million	and	would	change	the	2015	service	and	interest cost	components	of	net	periodic	benefit	cost	by	less	than	$1	million.

# Pension	Plan	Assets

Devon's	overall	investment	objective	for	its	pension	plans'	assets	is	to	achieve	stability	of	the	plans'	funded	status	while	providing	long-term	growth	of	invested capital	and	income	to	ensure	benefit	payments	can	be	funded	when	required.	To	assist	in	achieving	this	objective,	Devon	has	established	certain	investment	strategies, including	target	allocation	percentages	and	permitted	and	prohibited	investments,	designed	to	mitigate	risks	inherent	with	investing.	Derivatives	or	other	speculative investments	considered	high	risk	are	generally	prohibited.	The	following	table	presents	Devon's	target	allocation	for	its	pension	plan	assets.

|  | 2015 | 2014 |
| :--- | :--- | :--- |
| Fixed\tincome | 70% | 70% |
| Equity | 20% | 20% |
| Other | 10% | 10% |

The	following	tables	present	the	fair	values	of	Devon's	pension	assets	by	asset	class.

|  | Actual<br>Allocation | Total | Level	1<br>Inputs | Level	2<br>Inputs | Level	3<br>Inputs |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 17% | $179 | $88 | $91 | $— |
| Corporate\tbonds | 48% | 507 | 371 | 136 | — |
| Other\tbonds | 3% | 35 | 35 | — | — |
| Total\tfixed-income\tsecurities | 68% | 721 | 494 | 227 | — |
| Equity\tsecurities: |  |  |  |  |  |
| Global\t(large,\tmid,\tsmall\tcap) | 18% | 186 | — | 186 | — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\tand\talternative\tinvestments | 11% | 120 | — | — | 120 |
| Short-term\tinvestments | 3% | 32 | 6 | 26 | — |
| Total\tother\tsecurities | 14% | 152 | 6 | 26 | 120 |
| Total\tinvestments | 100% | $1,059 | $500 | $439 | $120 |

|  |  |  |  | Using: |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Actual\nAllocation | Total | Level\t1\nInputs | Level\t2\nInputs | Level\t3\nInputs |
|  |  |  | (Millions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 35% | $405 | $50 | $355 | $ — |
| Corporate\tbonds | 32% | 364 | 269 | 95 | \t — |
| Other\tbonds | 3% | 30 | 30 | \t — | \t — |
| Total\tfixed-income\tsecurities | 70% | 799 | 349 | 450 | \t — |
| Equity\tsecurities: |  |  |  |  |  |
| Global\t(large,\tmid,\tsmall\tcap) | 17% | 197 | \t — | 197 | \t — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\tand\talternative\tinvestments | 10% | 112 | \t — | \t — | 112 |
| Short-term\tinvestments | 3% | 41 | 15 | 26 | \t — |
| Total\tother\tsecurities | 13% | 153 | 15 | 26 | 112 |
| Total\tinvestments | 100% | $1,149 | $364 | $673 | $112 |

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

Fixed-income	securities	–	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.

Devon's	fixed	income	securities	also	include	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	Level	2	securities	are	based	upon	the	net	asset	values	provided	by	the investment	managers.

Equity	securities	–	Devon's	equity	securities	include	a	commingled	global	equity	fund	that	invests	in	large,	mid	and	small	capitalization	stocks	across	the	world's developed	and	emerging	markets.	These	equity	securities	can	be	redeemed	on	demand	but	are	not	actively	traded.	The	fair	values	of	these	Level	2	securities	are	based upon	the	net	asset	values	provided	by	the	investment	managers.

Other	securities	–	Devon's	other	securities	include	cash	and	commingled,	short-term	investment	funds.	The	short-term	investment	funds'	securities	can	be redeemed	on	demand	but	are	not	actively	traded.	The	fair	values	of	these	Level	2	securities	are	based	upon	the	net	asset	values	provided	by	investment	managers.

Devon's	hedge	fund	and	alternative	investments	include	an	investment	in	an	actively	traded	global	mutual	fund	that	focuses	on	alternative	investment	strategies and	a	hedge	fund	of	funds	that	invests	both	long	and	short	using	a	variety	of	investment	strategies.	Devon's	hedge	fund	of	funds	is	not	actively	traded,	and	Devon	is subject	to	redemption	restrictions	with	regards	to	this	investment.	The	fair	value	of	this	Level	3	investment	represents	the	fair	value	as	determined	by	the	hedge	fund manager.

The	following	table	presents	a	summary	of	the	changes	in	Devon's	Level	3	plan	assets	(millions).

# Expected	Cash	Flows

The	following	table	presents	expected	cash	flow	information	for	Devon's	pension	and	postretirement	benefit	plans.

|  | Pension<br>Benefits |  | Postretirement<br>Benefits |
| :--- | :--- | :--- | :--- |
|  |  | (Millions) |  |
| Devon's\t2016\tcontributions | $12 |  | $3 |
| Benefit\tpayments: |  |  |  |
| 2016 | $73 |  | $3 |
| 2017 | $75 |  | $3 |
| 2018 | $77 |  | $3 |
| 2019 | $78 |  | $3 |
| 2020 | $83 |  | $2 |
| 2021\tto\t2025 | $446 |  | $7 |

Expected	contributions	included	in	the	table	above	include	amounts	related	to	Devon's	qualified	plans,	nonqualified	plans	and	postretirement	plans.	Of	the benefits	expected	to	be	paid	in	2016,	the	$12	million	of	pension	benefits	is	expected	to	be	funded	from	the	trusts	established	for	the	nonqualified	plans,	and	the	$3 million	of	postretirement	benefits	is	expected	to	be	funded	from	Devon's	available	cash	and	cash	equivalents.	Expected	employer	contributions	and	benefit	payments	for other	postretirement	benefits	are	presented	net	of	employee	contributions.

# Defined	Contribution	Plans

Independent	of	EnLink,	Devon	maintains	defined	contribution	plans	covering	its	employees	in	the	U.S.	and	Canada.	Such	plans	include	Devon's	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.	EnLink	also	maintains	a	401(k)	plan	covering	eligible	employees.	The	following table	presents	expense	related	to	these	defined	contribution	plans.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| 401(k)\tand\tenhanced\tcontribution\tplans | $63 | $49 | $41 |
| Canadian\tpension\tand\tsavings\tplans | 16 | 20 | 26 |
| Total | $79 | $69 | $67 |

# 16. 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	December	2015,	Devon	issued	approximately	7	million	shares	of	common	stock	as	part	of	the	Powder	River	Basin	asset	acquisition	discussed	in	Note	2.

Additionally,	in	January	2016,	Devon	issued	approximately	23	million	shares	of	common	stock	in	conjunction	with	the	STACK	asset	acquisition.

# Dividends

Devon	paid	common	stock	dividends	of	$396	million,	$386	million	and	$348	million	in	2015,	2014	and	2013,	respectively.	The	quarterly	cash	dividend	was $0.20	per	share	in	the	first	quarter	of	2013.	Devon	increased	the	dividend	rate	to	$0.22	per	share	in	the	second	quarter	of	2013	and	to	$0.24	per	share	in	the	second quarter	of	2014.

Devon	received	$4	million,	$93	million	and	$3	million	from	stock	option	proceeds	in	2015,	2014	and	2013,	respectively.

# Acquisition	of	Noncontrolling	Interests

In	March	2014,	EnLink	was	formed	as	a	publicly	traded	consolidated	subsidiary	of	Devon	to	provide	midstream	services	to	Devon	and	third	parties.	Devon obtained	approximately	120.5	million	units,	or	a	52%	ownership	interest,	as	a	result	of	this	transaction.	Approximately	92.7	million	units	were	issued	to	the	public	for	a 41%	ownership	interest,	with	the	remaining	7%	ownership	interest	held	by	the	General	Partner.

# Subsidiary	Equity	Transactions

Through	its	equity	distribution	agreements,	EnLink	has	the	ability	to	sell	common	units	through	an	"at	the	market"	equity	offering	program.	During	2015	and 2014,	EnLink	issued	and	sold	approximately	1.3	million	and	14.8	million	common	units	through	its	at	the	market	program	and	general	public	offerings,	generating	net proceeds	of	$25	million	and	$410	million,	respectively.	Furthermore,	in	October	2015,	EnLink	issued	approximately	2.8	million	common	units	in	a	private	placement transaction	with	the	General	Partner,	generating	approximately	$50	million	in	proceeds.

In	2015,	Devon	conducted	an	underwritten	secondary	public	offering	of	26.2	million	common	units	representing	limited	partner	interests	in	EnLink,	raising	net proceeds	of	$654	million.

As	a	result	of	these	transactions,	the	Coronado	acquisition	and	dropdown	transactions	discussed	in	Note	2,	the	ownership	of	EnLink	at	December	31,	2015	is approximately:

•27%	–	General	Partner	(controlled	by	Devon)

# •45%	–	Public	unitholders

The	net	gains	and	losses	and	related	income	taxes	resulting	from	these	transactions	have	been	recorded	as	an	adjustment	to	equity,	and	the	change	in	ownership reflected	as	an	adjustment	to	noncontrolling	interests.

As	further	discussed	in	Note	2,	in	January	2016,	EnLink	acquired	midstream	assets	in	exchange	for	cash	and	equity.	Subsequent	to	this	transaction,	the	ownership of	the	General	Partner	is	approximately:

Subsequent	to	this	transaction,	the	ownership	of	EnLink	is	approximately:

# Distributions	to	Noncontrolling	Interests

In	conjunction	with	the	formation	of	the	General	Partner	in	2014,	Devon	made	a	payment	of	$100	million	to	noncontrolling	interests.	Furthermore,	EnLink	and the	General	Partner	distributed	$254	million	and	$135	million	to	non-Devon	unitholders	during	2015	and	2014,	respectively.

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	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	natural	gas	producers	and	related	parties,	including	Devon,	have	been	named	in	various	lawsuits	alleging	royalty	underpayments.	The	suits	allege	that the	producers	and	related	parties	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	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.

# Other	Matters

Devon	is	involved	in	other	various	routine	legal	proceedings	incidental	to	its	business.	However,	to	Devon's	knowledge,	there	were	no	other	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,	2015.

| Year	Ending	December	31, | Purchase<br>Obligations | and<br>Facility<br>Obligations |  | Operational<br>Agreements | Office	and<br>Equipment<br>Leases |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| 2016 | $557 | $69 |  | $994 | $70 |
| 2017 | 703 | 51 |  | 972 | 58 |
| 2018 | 791 | 34 |  | 936 | 76 |
| 2019 | 803 | 5 |  | 402 | 68 |
| 2020 | 845 | 2 |  | 255 | 42 |
| Thereafter | 206 | 28 |  | 1,042 | 129 |
| Total | $3,905 | $189 |  | $4,601 | $443 |

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	included	in	G&A	under	operating	leases,	net	of sublease	income,	was	$88	million,	$64	million	and	$26	million	in	2015,	2014	and	2013,	respectively.

The	following	table	provides	carrying	value	and	fair	value	measurement	information	for	certain	of	Devon's	financial	assets	and	liabilities.	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,	2015	and	December	31,	2014.	Therefore,	such	financial	assets	and	liabilities	are	not	presented	in	the	following	table. Additionally,	information	regarding	the	fair	values	of	oil	and	gas	assets,	goodwill	and	other	intangible	assets	and	pension	plan	assets	is	provided	in	Note	5,	Note	12	and Note	15,	respectively.

|  |  |  | Fair	Value	Measurements	Using: | Fair	Value	Measurements	Using: |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Carrying\nAmount | Total\tFair\nValue | \t\tLevel\t1\nInputs | \t\tLevel\t2\nInputs | \t\tLevel\t3\nInputs |
|  |  |  | (Millions) |  |  |
| December\t31,\t2015\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $1,871 | $1,871 | $1,471 | $400 | $— |
| Commodity\tderivatives | $35 | $35 | $— | $35 | $— |
| Commodity\tderivatives | $(18) | $(18) | $— | $(18) | $— |
| Interest\trate\tderivatives | $2 | $2 | $— | $2 | $— |
| Interest\trate\tderivatives | $(22) | $(22) | $— | $(22) | $— |
| Foreign\tcurrency\tderivatives | $8 | $8 | $— | $8 | $— |
| Foreign\tcurrency\tderivatives | $(8) | $(8) | $— | $(8) | $— |
| Debt | $(13,113) | $(11,927) | $— | $(11,927) | $— |
| Capital\tlease\tobligations | $(17) | $(16) | $— | $(16) | $— |
| December\t31,\t2014\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $950 | $950 | $340 | $610 | $— |
| Commodity\tderivatives | $1,995 | $1,995 | $— | $1,995 | $— |
| Commodity\tderivatives | $(56) | $(56) | $— | $(56) | $— |
| Interest\trate\tderivatives | $1 | $1 | $— | $1 | $— |
| Interest\trate\tderivatives | $(1) | $(1) | $— | $(1) | $— |
| Foreign\tcurrency\tderivatives | $8 | $8 | $— | $8 | $— |
| Debt | $(11,262) | $(12,472) | $— | $(12,472) | $— |
| Capital\tlease\tobligations | $(20) | $(20) | $— | $(20) | $— |

# Level	1	Fair	Value	Measurements

Cash	equivalents	–	Amounts	consist	primarily	of	money	market	investments.	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,	interest	rate	and	foreign	currency	derivatives	–	The	fair	values	of	commodity,	interest	rate	and	foreign	currency	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.	The	fair	values	of	commercial	paper	and	credit	facility	balances	are	the	carrying	values.

Capital	lease	obligations	–	The	fair	value	was	calculated	using	inputs	from	third-party	banks.

# 20. 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	21.

Devon	considers	EnLink,	combined	with	the	General	Partner,	to	be	an	operating	segment	that	is	distinct	from	the	U.S.	and	Canadian	operating	segments. EnLink's	operations	consist	of	midstream	assets	and	operations	located	across	the	U.S.	Additionally,	EnLink	has	a	management	team	that	is	primarily	responsible	for capital	and	resource	allocation	decisions.	Therefore,	EnLink	is	presented	as	a	separate	reporting	segment.	For	the	reporting	periods	prior	to	the	formation	of	EnLink, Devon	has	reclassified,	from	its	U.S.	segment	to	the	EnLink	segment,	all	asset-level	amounts	related	to	the	midstream	assets	that	it	contributed	to	EnLink.

|  | U.S.^	(1) | Canada | EnLink^	(1) | Eliminations | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| Year\tEnded\tDecember\t31,\t2015: |  |  |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $8,360 | $1,012 | $3,773 | $— | $13,145 |
| Intersegment\trevenues | $— | $— | $679 | $(679) | $— |
| Depreciation,\tdepletion\tand\tamortization | $2,220 | $522 | $387 | $— | $3,129 |
| Asset\timpairments | $18,000 | $1,257 | $1,563 | $— | $20,820 |
| Interest\texpense | $368 | $94 | $107 | $(46) | $523 |
| Loss\tbefore\tincome\ttaxes | $(18,214) | $(1,670) | $ (1,384) | $— | $(21,268) |
| Income\ttax\texpense\t(benefit) | $(5,650) | $(445) | $30 | $— | $(6,065) |
| Net\tloss | $(12,564) | $(1,225) | $ (1,414) | $— | $(15,203) |
| Net\tearnings\t(loss)\tattributable\tto\tnoncontrolling\tinterests | $1 | $— | $(750) | $— | $(749) |
| Net\tloss\tattributable\tto\tDevon | $(12,565) | $(1,225) | $(664) | $— | $(14,454) |
| Property\tand\tequipment,\tnet | $8,811 | $4,590 | $5,667 | $— | $19,068 |
| Total\tassets | $14,600 | $5,464 | $9,565 | $(97) | $29,532 |
| Capital\texpenditures | $4,575 | $680 | $978 | $— | $6,233 |
| Year\tEnded\tDecember\t31,\t2014: |  |  |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $14,854 | $2,063 | $2,649 | $— | $19,566 |
| Intersegment\trevenues | $— | $— | $859 | $(859) | $— |
| Depreciation,\tdepletion\tand\tamortization | $2,475 | $560 | $284 | $— | $3,319 |
| Asset\timpairments | $12 | $1,941 | $— | $— | $1,953 |
| Gains\tand\tlosses\ton\tasset\tsales | $5 | $(1,077) | $— | $— | $(1,072) |
| Interest\texpense | $441 | $85 | $54 | $(44) | $536 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | $4,390 | $(657) | $326 | $— | $4,059 |
| Income\ttax\texpense | $1,797 | $495 | $76 | $— | $2,368 |
| Net\tearnings\t(loss) | $2,593 | $(1,152) | $250 | $— | $1,691 |
| Net\tearnings\tattributable\tto\tnoncontrolling\tinterests | $1 | $— | $83 | $— | $84 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $2,592 | $(1,152) | $167 | $— | $1,607 |
| Property\tand\tequipment,\tnet | $24,463 | $6,790 | $5,043 | $— | $36,296 |
| Total\tassets | $32,037 | $8,517 | $10,207 | $(124) | $50,637 |
| Capital\texpenditures | $11,214 | $1,344 | $1,001 | $— | $13,559 |
| Year\tEnded\tDecember\t31,\t2013: |  |  |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $6,807 | $2,656 | $934 | $— | $10,397 |
| Intersegment\trevenues | $— | $— | $1,362 | $(1,362) | $— |
| Depreciation,\tdepletion\tand\tamortization | $1,744 | $849 | $187 | $— | $2,780 |
| Asset\timpairments | $1,133 | $843 | $— | $— | $1,976 |
| Interest\texpense | $392 | $80 | $— | $(35) | $437 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | $495 | $(532) | $186 | $— | $149 |
| Income\ttax\texpense\t(benefit) | $258 | $(156) | $67 | $— | $169 |
| Net\tearnings\t(loss) | $237 | $(376) | $119 | $— | $(20) |
| Property\tand\tequipment,\tnet | $18,201 | $8,478 | $1,768 | $— | $28,447 |
| Total\tassets | $27,080 | $13,560 | $2,237 | $— | $42,877 |
| Capital\texpenditures | $4,589 | $1,841 | $213 | $— | $6,643 |

(1) Due	to	Devon's	control	of	EnLink	through	its	control	of	the	General	Partner,	the	acquisition	of	VEX	by	EnLink	from	Devon	in	the	second	quarter	of	2015	was considered	a	transfer	of	net	assets	between	entities	under	common	control,	and	EnLink	was	required	to	recast	its	financial	statements	as	of	December	31,	2015	to include	the	activities	of	such	assets	from	the	date	of	common	control.	Therefore,	the	results	of	VEX	have	been	moved	from	the	U.S.	segment	to	the	EnLink segment	for	the	recasted	periods.

# 21. 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.

Costs	incurred	in	the	tables	above	include	additions	and	revisions	to	Devon's	asset	retirement	obligations.

Pursuant	to	the	full	cost	method	of	accounting,	Devon	capitalizes	certain	of	its	G&A	that	is	related	to	property	acquisition,	exploration	and	development	activities. Such	capitalized	expenses,	which	are	included	in	the	costs	shown	in	the	preceding	tables,	were	$372	million,	$376	million	and	$368	million	in	2015,	2014	and	2013, respectively.	Also,	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	$54	million,	$45	million	and	$42	million	in	2015,	2014	and	2013, respectively.

# Capitalized	Costs

The	following	tables	reflect	the	aggregate	capitalized	costs	related	to	oil	and	gas	activities.

|  |  | December	31,	2015 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Proved\tproperties | $64,443 | $13,747 | $78,190 |
| Unproved\tproperties | 1,352 | 1,232 | 2,584 |
| Total\toil\tand\tgas\tproperties | 65,795 | 14,979 | 80,774 |
| Accumulated\tDD&amp;A | (58,312) | (11,185) | (69,497) |
| Net\tcapitalized\tcosts | $7,483 | $3,794 | $11,277 |

|  |  | December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Proved\tproperties | $59,849 | $15,889 | $75,738 |
| Unproved\tproperties | 1,460 | 1,292 | 2,752 |
| Total\toil\tand\tgas\tproperties | 61,309 | 17,181 | 78,490 |
| Accumulated\tDD&amp;A | (38,213) | (11,347) | (49,560) |
| Net\tcapitalized\tcosts | $23,096 | $5,834 | $28,930 |

The	following	table	presents	a	summary	of	Devon's	oil	and	gas	properties	not	subject	to	amortization	as	of	December	31,	2015.

|  | 2015 | 2014 | 2013 | Prior	to<br>2013 | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (Millions) |  |  |
| Acquisition\tcosts | $672 | $412 | $61 | $510 | $1,655 |
| Exploration\tcosts | \t 191 | \t 132 | 69 | 170 | 562 |
| Development\tcosts | 9 | 28 | 17 | 128 | 182 |
| Capitalized\tinterest | 50 | 37 | 32 | 66 | 185 |
| Total\toil\tand\tgas\tproperties\tnot\tsubject\tto\tamortization | $922 | $609 | $179 | $874 | $2,584 |

Included	in	the	$2.6	billion	of	oil	and	gas	properties	not	subject	to	amortization	are	approximately	$1.9	billion	of	costs	that	Devon	deems	significant	for	individual assessment.	These	costs	primarily	relate	to	investments	in	the	Pike	thermal	oil	project	in	Canada	and	the	newly	acquired	Powder	River	Basin	assets.	Devon	anticipates determining	its	Pike	development	timeline	in	mid-2016,	with	its	50%	partner.	Based	on	the	development	plans,	Pike	costs	will	begin	to	be	included	in	the	amortization computation	when	the	first	phase	of	this	project	is	fully	approved	and	Devon	subsequently	begins	recognizing	the	associated	proved	reserves.	Devon	is	evaluating	and plans	to	develop	the	newly	acquired	Powder	River	Basin	properties	over	the	next	four	to	five	years.

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.

|  |  | December	31,	2015 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Oil,\tgas\tand\tNGL\tsales | $4,356 | $1,026 | $5,382 |
| Lease\toperating\texpenses | (1,551) | (553) | (2,104) |
| General\tand\tadministrative\texpenses | (196) | (28) | (224) |
| Production\tand\tproperty\ttaxes | (309) | (33) | (342) |
| Depreciation,\tdepletion\tand\tamortization | (2,107) | (474) | (2,581) |
| Asset\timpairments | (17,992) | (1,257) | (19,249) |
| Accretion\tof\tasset\tretirement\tobligations | (47) | (27) | (74) |
| Income\ttax\tbenefit | 5,547 | 314 | 5,861 |
| Results\tof\toperations | $(12,299) | $(1,032) | $(13,331) |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $10.21 | $11.30 | $10.40 |

|  |  | December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Oil,\tgas\tand\tNGL\tsales | $7,867 | $2,043 | $9,910 |
| Lease\toperating\texpenses | (1,559) | (773) | (2,332) |
| General\tand\tadministrative\texpenses | (153) | (57) | (210) |
| Production\tand\tproperty\ttaxes | (466) | (37) | (503) |
| Depreciation,\tdepletion\tand\tamortization | (2,365) | (531) | (2,896) |
| Gain\ton\tsale\tof\tassets | — | 1,077 | 1,077 |
| Accretion\tof\tasset\tretirement\tobligations | (49) | (39) | (88) |
| Income\ttax\texpense | (1,199) | (568) | (1,767) |
| Results\tof\toperations\t^(1) | $2,076 | $1,115 | $3,191 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $11.41 | $13.80 | $11.79 |

|  |  | December	31,	2013 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Oil,\tgas\tand\tNGL\tsales | $5,964 | $2,558 | $8,522 |
| Lease\toperating\texpenses | (1,257) | (1,011) | (2,268) |
| General\tand\tadministrative\texpenses | (125) | (77) | (202) |
| Production\tand\tproperty\ttaxes | (380) | (59) | (439) |
| Depreciation,\tdepletion\tand\tamortization | (1,640) | (825) | (2,465) |
| Asset\timpairments | (1,110) | (843) | (1,953) |
| Accretion\tof\tasset\tretirement\tobligations | (47) | (64) | (111) |
| Income\ttax\tbenefit\t(expense) | (510) | 88 | (422) |
| Results\tof\toperations | $895 | $(233) | $662 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $8.69 | $12.87 | $9.75 |

(1) During	2014,	Devon	recognized	a	Canadian	goodwill	impairment,	which	is	not	reflected	in	these	tables.	See	Note	5	for	additional	information.

The	following	tables	present	Devon's	estimated	proved	reserves	by	product	by	country.

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2012 | \t — | 528 | 528 |
| Revisions\tdue\tto\tprices | \t — | (11) | (11) |
| Revisions\tother\tthan\tprice | \t — | 16 | 16 |
| Extensions\tand\tdiscoveries | \t — | 38 | 38 |
| Production | \t — | (19) | (19) |
| December\t31,\t2013 | \t — | 552 | 552 |
| Revisions\tdue\tto\tprices | \t — | (37) | (37) |
| Revisions\tother\tthan\tprice | \t — | 18 | 18 |
| Extensions\tand\tdiscoveries | \t — | 8 | 8 |
| Production | \t — | (20) | (20) |
| December\t31,\t2014 | \t — | 521 | 521 |
| Revisions\tdue\tto\tprices | \t — | 103 | 103 |
| Revisions\tother\tthan\tprice | \t — | (84) | (84) |
| Extensions\tand\tdiscoveries | \t — | 11 | 11 |
| Production | \t — | (31) | (31) |
| December\t31,\t2015 | \t — | 520 | 520 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | \t — | 99 | 99 |
| December\t31,\t2013 | \t — | 111 | 111 |
| December\t31,\t2014 | \t — | 137 | 137 |
| December\t31,\t2015 | \t — | 219 | 219 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | \t — | 99 | 99 |
| December\t31,\t2013 | \t — | 111 | 111 |
| December\t31,\t2014 | \t — | 137 | 137 |
| December\t31,\t2015 | \t — | 219 | 219 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | \t — | 429 | 429 |
| December\t31,\t2013 | \t — | 441 | 441 |
| December\t31,\t2014 | \t — | 384 | 384 |
| December\t31,\t2015 | \t — | 301 | 301 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2012 | 8,762 | 684 | 9,446 |
| Revisions\tdue\tto\tprices | 405 | 161 | 566 |
| Revisions\tother\tthan\tprice | (299) | 67 | (232) |
| Extensions\tand\tdiscoveries | 471 | 19 | 490 |
| Purchase\tof\treserves | 1 | — | 1 |
| Production | (709) | (165) | (874) |
| Sale\tof\treserves | (81) | (8) | (89) |
| December\t31,\t2013 | 8,550 | 758 | 9,308 |
| Revisions\tdue\tto\tprices | 191 | 45 | 236 |
| Revisions\tother\tthan\tprice | (299) | 4 | (295) |
| Extensions\tand\tdiscoveries | 335 | 8 | 343 |
| Purchase\tof\treserves | 457 | — | 457 |
| Production | (660) | (41) | (701) |
| Sale\tof\treserves | (923) | (738) | \t(1,661) |
| December\t31,\t2014 | 7,651 | 36 | 7,687 |
| Revisions\tdue\tto\tprices | \t(1,412) | (9) | \t(1,421) |
| Revisions\tother\tthan\tprice | (3) | (6) | (9) |
| Extensions\tand\tdiscoveries | 171 | — | 171 |
| Purchase\tof\treserves | 17 | — | 17 |
| Production | (579) | (8) | (587) |
| Sale\tof\treserves | (37) | — | (37) |
| December\t31,\t2015 | 5,808 | 13 | 5,821 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 7,391 | 679 | 8,070 |
| December\t31,\t2013 | 7,707 | 752 | 8,459 |
| December\t31,\t2014 | 6,948 | 36 | 6,984 |
| December\t31,\t2015 | 5,694 | 13 | 5,707 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 7,091 | 624 | 7,715 |
| December\t31,\t2013 | 7,425 | 680 | 8,105 |
| December\t31,\t2014 | 6,746 | 34 | 6,780 |
| December\t31,\t2015 | 5,546 | 13 | 5,559 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 1,371 | 5 | 1,376 |
| December\t31,\t2013 | 843 | 6 | 849 |
| December\t31,\t2014 | 703 | — | 703 |
| December\t31,\t2015 | 114 | — | 114 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2012 | 571 | 20 | 591 |
| Revisions\tdue\tto\tprices | 8 | 3 | 11 |
| Revisions\tother\tthan\tprice | (50) | 3 | (47) |
| Extensions\tand\tdiscoveries | 64 | 1 | 65 |
| Production | (41) | (4) | (45) |
| December\t31,\t2013 | 552 | 23 | 575 |
| Revisions\tdue\tto\tprices | 7 | 1 | 8 |
| Revisions\tother\tthan\tprice | 2 | — | 2 |
| Extensions\tand\tdiscoveries | 47 | — | 47 |
| Purchase\tof\treserves | 57 | — | 57 |
| Production | (50) | (1) | (51) |
| Sale\tof\treserves | (37) | (23) | (60) |
| December\t31,\t2014 | 578 | — | 578 |
| Revisions\tdue\tto\tprices | \t(119) | — | (119) |
| Revisions\tother\tthan\tprice | (6) | — | (6) |
| Extensions\tand\tdiscoveries | 24 | — | 24 |
| Purchase\tof\treserves | 1 | — | 1 |
| Production | (50) | — | (50) |
| December\t31,\t2015 | 428 | — | 428 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 431 | 20 | 451 |
| December\t31,\t2013 | 468 | 23 | 491 |
| December\t31,\t2014 | 486 | — | 486 |
| December\t31,\t2015 | 411 | — | 411 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 406 | 19 | 425 |
| December\t31,\t2013 | 442 | 21 | 463 |
| December\t31,\t2014 | 467 | — | 467 |
| December\t31,\t2015 | 393 | — | 393 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 140 | — | 140 |
| December\t31,\t2013 | 84 | — | 84 |
| December\t31,\t2014 | 92 | — | 92 |
| December\t31,\t2015 | 17 | — | 17 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2012 | \t2,236 | 727 | \t2,963 |
| Revisions\tdue\tto\tprices | 76 | 18 | 94 |
| Revisions\tother\tthan\tprice | (117) | 29 | (88) |
| Extensions\tand\tdiscoveries | 212 | 49 | 261 |
| Purchase\tof\treserves | 1 | — | 1 |
| Production | (189) | (64) | (253) |
| Sale\tof\treserves | (14) | (1) | (15) |
| December\t31,\t2013 | \t2,205 | 758 | \t2,963 |
| Revisions\tdue\tto\tprices | 38 | (29) | 9 |
| Revisions\tother\tthan\tprice | (86) | 21 | (65) |
| Extensions\tand\tdiscoveries | 197 | 14 | 211 |
| Purchase\tof\treserves | 265 | — | 265 |
| Production | (207) | (39) | (246) |
| Sale\tof\treserves | (207) | (176) | (383) |
| December\t31,\t2014 | \t2,205 | 549 | \t2,754 |
| Revisions\tdue\tto\tprices | (408) | 106 | (302) |
| Revisions\tother\tthan\tprice | (59) | (83) | (142) |
| Extensions\tand\tdiscoveries | 104 | 14 | 118 |
| Purchase\tof\treserves | 9 | — | 9 |
| Production | (206) | (42) | (248) |
| Sale\tof\treserves | (7) | — | (7) |
| December\t31,\t2015 | \t1,638 | 544 | \t2,182 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | \t1,829 | 294 | \t2,123 |
| December\t31,\t2013 | \t1,947 | 315 | \t2,262 |
| December\t31,\t2014 | \t1,900 | 165 | \t2,065 |
| December\t31,\t2015 | \t1,563 | 243 | \t1,806 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | \t1,743 | 278 | \t2,021 |
| December\t31,\t2013 | \t1,857 | 297 | \t2,154 |
| December\t31,\t2014 | \t1,815 | 162 | \t1,977 |
| December\t31,\t2015 | \t1,509 | 240 | \t1,749 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2012 | 407 | 433 | 840 |
| December\t31,\t2013 | 258 | 443 | 701 |
| December\t31,\t2014 | 305 | 384 | 689 |
| December\t31,\t2015 | 75 | 301 | 376 |

(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	2015	(MMBoe).

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2014 | \t 305 | 384 | \t 689 |
| Extensions\tand\tdiscoveries | 13 | 11 | 24 |
| Revisions\tdue\tto\tprices | \t(115) | 80 | (35) |
| Revisions\tother\tthan\tprice | (40) | (80) | \t(120) |
| Conversion\tto\tproved\tdeveloped\treserves | (88) | (94) | \t(182) |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2015 | 75 | 301 | \t 376 |

Proved	undeveloped	reserves	decreased	45%	from	year-end	2014	to	year-end	2015,	and	the	year-end	2015	balance	represents	17%	of	total	proved	reserves. Drilling	and	development	activities	increased	Devon's	proved	undeveloped	reserves	24	MMBoe	and	resulted	in	the	conversion	of	182	MMBoe,	or	26%,	of	the	2014 proved	undeveloped	reserves	to	proved	developed	reserves.	Costs	incurred	to	develop	and	convert	Devon's	proved	undeveloped	reserves	were	approximately	$2.2 billion	for	2015.	Additionally,	revisions	other	than	price	decreased	Devon's	proved	undeveloped	reserves	120	MMBoe	primarily	due	to	evaluations	of	certain	properties in	the	U.S.	and	Canada.	The	largest	revisions,	which	reduced	reserves	by	80	MMBoe,	relate	to	evaluations	of	Jackfish	bitumen	reserves.	Of	the	40	MMBoe	revisions recorded	for	U.S.	properties,	a	reduction	of	approximately	27	MMBoe	represents	reserves	that	Devon	now	does	not	expect	to	develop	in	the	next	five	years,	including	20 MMBoe	attributable	to	the	Eagle	Ford.

A	significant	amount	of	Devon's	proved	undeveloped	reserves	at	the	end	of	2015	related	to	its	Jackfish	operations.	At	December	31,	2015	and	2014,	Devon's Jackfish	proved	undeveloped	reserves	were	301	MMBoe	and	384	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	5	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	to	2030.	At	the	end	of	2015,	approximately	184	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	180	MMBoe	of	proved	undeveloped	reserves	at	Jackfish	will	require	in	excess	of	five years,	from	the	date	of	this	filing,	to	develop.

# Price	Revisions

2015	–	Reserves	decreased	302	MMBoe	primarily	due	to	lower	commodity	prices	across	all	products.	The	lower	bitumen	price	increased	Canadian	reserves	due	to the	decline	in	royalties,	which	increases	Devon's	after-royalty	volumes.

2014	–	Reserves	increased	9	MMBoe	primarily	due	to	higher	gas	prices	in	the	Barnett	Shale	and	the	Anadarko	Basin,	partially	offset	by	higher	bitumen	prices, which	result	in	lower	after-royalty	volumes,	in	Canada.

2013	–	Reserves	increased	94	MMBoe	primarily	due	to	higher	gas	prices.	Of	this	increase,	43	MMBoe	related	to	the	Barnett	Shale	and	19	MMBoe	related	to	the Rocky	Mountain	area.

# Revisions	Other	Than	Price

Total	revisions	other	than	price	for	2015	primarily	related	to	evaluations	of	Eagle	Ford	and	Jackfish.	Negative	revisions	other	than	price	at	Jackfish	are	primarily due	to	a	refined	reserves	methodology	that	resulted	in	a	reduced	recovery	factor.	Revisions	other	than	price	in	2014	and	2013	primarily	related	to	Devon's	evaluation	of certain	dry	gas	regions,	with	the	largest	revisions	being	made	in	the	Cana-Woodford	Shale	and	Barnett	Shale.

# Extensions	and	Discoveries

2015	–	Of	the	118	MMBoe	of	extensions	and	discoveries,	38	MMBoe	related	to	the	Delaware	Basin,	30	MMBoe	related	to	the	Anadarko	Basin,	21	MMBoe related	to	the	Eagle	Ford	and	11	MMBoe	related	to	Jackfish.

The	2015	extensions	and	discoveries	included	13	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	primarily	consisting	of	11	MMBoe	at Jackfish.

2014	–	Of	the	211	MMBoe	of	extensions	and	discoveries,	70	MMBoe	related	to	the	Permian	Basin,	54	MMBoe	related	to	the	Eagle	Ford,	36	MMBoe	related	to the	Barnett	Shale,	14	MMBoe	related	to	the	Anadarko	Basin,	8	MMBoe	related	to	Jackfish	and	14	MMBoe	related	to	the	Mississippian-Woodford	Trend.

The	2014	extensions	and	discoveries	included	5	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	primarily	consisting	of	4	MMBoe	at	the Permian	Basin.

2013	–	Of	the	261	MMBoe	of	extensions	and	discoveries,	76	MMBoe	related	to	the	Permian	Basin,	54	MMBoe	related	to	the	Barnett	Shale,	42	MMBoe	related	to the	Anadarko	Basin,	38	MMBoe	related	to	Jackfish	and	32	MMBoe	related	to	the	Mississippian-Woodford	Trend.

The	2013	extensions	and	discoveries	included	175	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	including	23	MMBoe	at	the	Cana- Woodford	Shale,	54	MMBoe	at	the	Barnett	Shale,	38	MMBoe	at	Jackfish,	33	MMBoe	at	the	Permian	Basin	and	20	MMBoe	at	the	Mississippian-Woodford	Trend.

# Purchase	of	Reserves

2015	–	Of	the	9	MMBoe	of	reserves	purchases,	6	MMBoe	related	to	Devon's	acquisition	in	the	Powder	River	Basin.

2014	–	Of	the	265	MMBoe	of	reserves	purchases,	246	MMBoe	related	to	Devon's	GeoSouthern	acquisition	in	the	Eagle	Ford.

# Sale	of	Reserves

2015	–	The	7	MMBoe	of	reserves	sales	related	to	Devon's	asset	divestitures	in	the	San	Juan	Basin.

2014	–	The	total	383	MMBoe	of	reserves	sales	related	to	Devon's	asset	divestitures	in	the	U.S.	and	Canada.

# Standardized	Measure

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

|  |  | Year	Ended	December	31,	2015 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Future\tcash\tinflows | $27,398 | $13,047 | $40,445 |
| Future\tcosts: |  |  |  |
| Development | (3,306) | (2,759) | (6,065) |
| Production | (17,251) | (6,891) | (24,142) |
| Future\tincome\ttax\texpense | — | (475) | (475) |
| Future\tnet\tcash\tflow | 6,841 | 2,922 | 9,763 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (1,973) | (1,102) | (3,075) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $4,868 | $1,820 | $6,688 |

|  |  | Year	Ended	December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Future\tcash\tinflows | $75,847 | $31,371 | $107,218 |
| Future\tcosts: |  |  |  |
| Development | (7,168) | (3,619) | (10,787) |
| Production | (29,740) | (14,232) | (43,972) |
| Future\tincome\ttax\texpense | (11,021) | (3,026) | (14,047) |
| Future\tnet\tcash\tflow | 27,918 | 10,494 | 38,412 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (12,819) | (5,119) | (17,938) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $15,099 | $5,375 | $20,474 |

|  |  | Year	Ended	December	31,	2013 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (Millions) |  |
| Future\tcash\tinflows | $61,983 | $33,305 | $95,288 |
| Future\tcosts: |  |  |  |
| Development | (5,448) | (5,308) | (10,756) |
| Production | (26,663) | (15,709) | (42,372) |
| Future\tincome\ttax\texpense | (9,046) | (2,327) | (11,373) |
| Future\tnet\tcash\tflow | 20,826 | 9,961 | 30,787 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (10,346) | (4,700) | (15,046) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $10,480 | $5,261 | $15,741 |

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	2015	estimates,	Devon's	future	realized	prices	were	assumed	to	be	$44.33	per	Bbl	of	oil,	$23.84	per	Bbl	of bitumen,	$2.06	per	Mcf	of	gas	and	$10.11	per	Bbl	of	NGLs.	Of	the	$6.1	billion	of	future	development	costs	as	of	the	end	of	2015,	$0.6	billion,	$0.6	billion	and	$0.4 billion	are	estimated	to	be	spent	in	2016,	2017	and	2018,	respectively.

Future	development	costs	include	not	only	development	costs	but	also	future	asset	retirement	costs.	Included	as	part	of	the	$6.1	billion	of	future	development	costs are	$1.2	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2015 | 2014 | 2013 |
|  |  | (Millions) |  |
| Beginning\tbalance | $20,474 | $15,741 | $13,221 |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | (20,756) | 2,561 | 3,018 |
| Oil,\tbitumen,\tgas\tand\tNGL\tsales,\tnet\tof\tproduction\tcosts | (2,704) | (6,865) | (5,613) |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | 1,313 | (768) | 399 |
| Extensions\tand\tdiscoveries,\tnet\tof\tfuture\tdevelopment\tcosts | 1,129 | 4,836 | 4,047 |
| Purchase\tof\treserves | 95 | 6,422 | 14 |
| Sales\tof\treserves\tin\tplace | (79) | (2,384) | (44) |
| Revisions\tof\tquantity\testimates | (1,451) | (746) | (1,040) |
| Previously\testimated\tdevelopment\tcosts\tincurred\tduring\tthe\tperiod | 2,158 | 1,933 | 1,986 |
| Accretion\tof\tdiscount | 567 | 1,746 | 1,940 |
| Foreign\texchange\tand\tother | (1,254) | (107) | (583) |
| Net\tchange\tin\tincome\ttaxes | 7,196 | (1,895) | (1,604) |
| Ending\tbalance | $6,688 | $20,474 | $15,741 |

# 22. Supplemental	Quarterly	Financial	Information	(Unaudited)

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

|  | First<br>Quarter | Second<br>Quarter | Third<br>Quarter | Fourth<br>Quarter | Full<br>Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | $3,265 | $3,393 | $3,601 | $2,886 | $13,145 |
| Loss\tbefore\tincome\ttaxes | $(5,624) | $(4,479) | $(5,623) | $(5,542) | $(21,268) |
| Net\tloss\tattributable\tto\tDevon | $(3,599) | $(2,816) | $(3,507) | $(4,532) | $(14,454) |
| Basic\tnet\tloss\tper\tshare\tattributable\tto\tDevon | $(8.88) | $(6.94) | $(8.64) | $(11.12) | $(35.55) |
| Diluted\tnet\tloss\tper\tshare\tattributable\tto\tDevon | $(8.88) | $(6.94) | $(8.64) | $(11.12) | $(35.55) |

|  | First<br>Quarter | Second<br>Quarter | Third<br>Quarter | Fourth<br>Quarter | Full<br>Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) | (Millions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | $3,725 | $4,510 | $5,336 | $5,995 | $19,566 |
| Earnings\tbefore\tincome\ttaxes | $560 | $1,554 | $1,654 | $291 | $4,059 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $324 | $675 | $1,016 | $(408) | $1,607 |
| Basic\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $0.80 | $1.65 | $2.48 | $(1.01) | $3.93 |
| Diluted\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $0.79 | $1.64 | $2.47 | $(1.01) | $3.91 |

# Net	Earnings	(Loss)	Attributable	to	Devon

The	2015	quarterly	results	include	asset	impairments	of	$5.5	billion	(or	$13.46	per	diluted	share),	$4.2	billion	(or	$10.27	per	diluted	share),	$5.9	billion	($14.41 per	diluted	share)	and	$5.3	billion	(or	$13.09	per	diluted	share)	for	the	first	quarter	through	the	fourth	quarter	of	2015,	respectively,	as	discussed	in	Note	5.

The	fourth	quarter	of	2014	includes	asset	impairments	of	$1.9	billion	(or	$4.79	per	diluted	share)	as	discussed	in	Note	5.

# 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,	2015	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	17,	2016,	management	concluded	that	its	internal	control	over	financial reporting	was	effective	as	of	December	31,	2015.

The	effectiveness	of	our	internal	control	over	financial	reporting	as	of	December	31,	2015	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,	2015,	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	2015	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	not	later	than	April	29,	2016.

# 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	not	later	than	April	29,	2016.

# 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	filed	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

10.1 Credit	Agreement	dated	October	24,	2012,	among	Registrant,	as	U.S.	Borrower,	Devon	NEC	Corporation	and	Devon	Canada	Corporation,	as Canadian	Borrowers,	each	lender	from	time	to	time	party	thereto,	each	L/C	Issuer	from	time	to	time	party	thereto,	and	Bank	of	America,	N.A.,	as Administrative	Agent,	Canadian	Swing	Line	Lender	and	U.S.	Swing	Line	Lender	(incorporated	by	reference	to	Exhibit	10.1	of	Registrant's	Form 8-K	filed	October	29,	2012;	File	No.	001-32318).

# 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.

David	A.	Hager

President	and	Chief	Executive	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.

# INDEX	TO	EXHIBITS



Question: in years , what is the average contractual term for 2013 , 2014 , 2015?
Calculation:   term_2013 = 2.89
 term_2014 = 2.89
 term_2015 = 3
average_term = (term_2013 + term_2014 + term_2015) / 3
answer = average_term
Answer: 2.9266