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,	2014

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	of	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.	(Check	one):

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

The	aggregate	market	value	of	the	voting	common	stock	held	by	non-affiliates	of	the	registrant	as	of	June	30,	2014,	was	approximately	$32.3	billion,	based	upon the	closing	price	of	$79.40	per	share	as	reported	by	the	New	York	Stock	Exchange	on	such	date.	On	February	11,	2015,	411.1	million	shares	of	common	stock	were outstanding.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

Proxy	statement	for	the	2015	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 | 3 |
| Item\t1A.\t\tRisk\tFactors | 18 |
| Item\t1B.\t\tUnresolved\tStaff\tComments | 22 |
| Item\t3.\t\t\t\t\tLegal\tProceedings | 22 |
| Item\t4.\t\t\t\t\tMine\tSafety\tDisclosures | 22 |
| PART\tII |  |
| Item\t5.\t\t\t\t\t\tMarket\tfor\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 23 |
| Item\t6.\t\t\t\t\tSelected\tFinancial\tData | 25 |
| Item\t7.\t\t\t\t\t\tManagement's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 26 |
| Item\t7A.\t\tQuantitative\tand\tQualitative\tDisclosures\tabout\tMarket\tRisk | 50 |
| Item\t8.\t\t\t\t\tFinancial\tStatements\tand\tSupplementary\tData | 52 |
| Item\t9.\t\t\t\t\t\tChanges\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | \t115 |
| Item\t9A.\t\tControls\tand\tProcedures | \t115 |
| Item\t9B.\t\tOther\tInformation | \t115 |
| PART\tIII |  |
| Item\t10.\t\t\tDirectors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | \t116 |
| Item\t11.\t\t\tExecutive\tCompensation | \t116 |
| Item\t12.\t\t\t\tSecurity\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | \t116 |
| Item\t13.\t\t\tCertain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | \t116 |
| Item\t14.\t\t\tPrincipal\tAccountant\tFees\tand\tServices | \t116 |
| PART\tIV |  |
| Item\t15.\t\t\tExhibits\tand\tFinancial\tStatement\tSchedules | \t117 |
| Signatures | \t124 |

# INFORMATION	REGARDING	FORWARD-LOOKING	STATEMENTS

This	report	includes	"forward-looking	statements"	as	defined	by	the	United	States	Securities	and	Exchange	Commission	("SEC").	Such	statements	are	those concerning	strategic	plans,	our	expectations	and	objectives	for	future	operations,	as	well	as	other	future	events	or	conditions.	Such	forward-looking	statements	are	based on	our	examination	of	historical	operating	trends,	the	information	used	to	prepare	our	December	31,	2014	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,	such	as	changes	in	the	supply	of	and	demand	for	oil,	natural	gas	and	natural	gas	liquids ("NGLs")	and	related	products	and	services;	exploration	or	drilling	programs;	our	ability	to	successfully	complete	mergers,	acquisitions	and	divestitures;	political	or regulatory	events;	general	economic	and	financial	market	conditions;	and	other	risks	and	factors	discussed	in	this	report.

All	subsequent	written	and	oral	forward-looking	statements	attributable	to	Devon	Energy	Corporation,	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	Energy	Corporation	("Devon")	is	a	leading	independent	energy	company	engaged	primarily	in	the	exploration,	development	and	production	of	oil,	natural gas	and	natural	gas	liquids	(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	200,000	barrels	per	day	and	have	a	deep	inventory	of	development	opportunities.	Devon	also	produces	over	1.6	billion	cubic	feet	of	natural	gas	a	day and	more	than	130,000	barrels	of	natural	gas	liquids	per	day.

Additionally,	in	2014,	we	combined	substantially	all	of	our	U.S.	midstream	assets	with	Crosstex	Energy,	Inc.	and	Crosstex	Energy,	LP	(together	"Crosstex")	to form	a	leading	integrated	midstream	business	with	enhanced	size	and	scale	in	key	operating	regions	in	the	U.S.	This	midstream	business	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	New	York	Stock	Exchange.	Our	principal and	administrative	offices	are	located	at	333	West	Sheridan,	Oklahoma	City,	OK	73102-5015	(telephone	405-235-3611).	As	of	December	31,	2014,	Devon	and	its consolidated	subsidiaries	had	approximately	6,600	employees.	Approximately	1,100	of	such	employees	are	employed	by	EnLink	Midstream	Partners,	LP	("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	share.	In	pursuit	of	this	objective,	we	focus	on	growing	cash	flow	per	share,	adjusted	for	debt,	which	we	believe	has	the greatest	long-term	correlation	to	share	price	appreciation	in	our	industry.	We	also	focus	on	growth	in	earnings,	production	and	reserves,	all	on	a	per	debt-adjusted	share basis.	We	do	this	by:

•growing	and	sustaining	a	premier	portfolio	of	assets	focused	on	high	rate-of-return	projects;

•achieving	superior	execution	through	operational	and	technical	excellence,	effective	project	management	and	exceptional	safety	results;

•optimizing	cash	flow	through	disciplined	capital	allocation	and	cost	management;	and

•	 maintaining	financial	flexibility	and	a	strong	balance	sheet.

In	pursuit	of	our	goal	to	build	value	per	share,	we	executed	three	strategic	initiatives	in	2014:

•Eagle	Ford	Acquisition	–	On	February	28,	2014,	we	completed	our	$6	billion	acquisition	of	interests	in	certain	oil	and	gas	properties,	leasehold	mineral interests	and	related	assets	located	in	the	Eagle	Ford	from	GeoSouthern	Energy	Corporation	("GeoSouthern").	We	funded	the	acquisition	price	with	cash	on hand	and	debt	financing.	In	connection	with	the	GeoSouthern	transaction,	we	acquired	approximately	82,000	net	acres	located	in	DeWitt	and	Lavaca counties	in	south	Texas.

•	 MLP	Formation	–	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	new	midstream	business.	The	new	business	consists	of	EnLink	and	EnLink	Midstream,	LLC	(the	"General	Partner"),	a	master limited	partnership	("MLP")	and	a	general	partner	entity,	respectively,	which	are	both	publicly	traded.	Devon	controls	this	consolidated	entity	through	its ownership	interest	in	the	General	Partner.

In	exchange	for	a	controlling	interest	in	both	EnLink	and	the	General	Partner,	we	contributed	our	equity	interest	in	EnLink	Midstream	Holdings,	LP,	a newly	formed	Devon	subsidiary	("EnLink	Holdings")	and	$100	million	in	cash.	EnLink	Holdings	owns	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.	As of	December	31,	2014,	the	General	Partner	and	EnLink	each	held	50%	of	EnLink	Holdings.

•Asset	Divestitures	–	In	2014,	we	completed	the	divestitures	of	certain	U.S.	and	Canadian	assets	for	total	cash	consideration	in	excess	of	$5	billion.	Proceeds were	primarily	used	to	repay	debt	resulting	from	the	Eagle	Ford	acquisition	noted	above.

The	initiatives	above	resulted	in	a	more	focused	asset	base,	allowing	us	to	better	allocate	capital	and	employee	resources	to	the	highest-value	properties	and prospects	in	our	portfolio.

# Oil	and	Gas	Properties

# Property	Profiles

The	locations	of	our	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	for	2014.	Notes	21	and	22	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.	In	the	following	table	and throughout	this	report,	we	convert	our	proved	reserves	and	production	to	Boe.	Gas	proved	reserves	and	production	are	converted,	at	the	pressure	base	standard	of	each respective	state	in	which	the	gas	is	produced,	to	Boe	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.

|  | MMBoe | %	of<br>Total | %	Liquids | MBoe/d | %	of<br>Total | %<br>Liquids | Wells<br>Drilled |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Anadarko\tBasin | 419 | 15% | 42% | 94 | 14% | 45% | 130 |
| Barnett\tShale | \t 1,037 | 38% | 25% | 208 | 31% | 27% | 84 |
| Eagle\tFord | 247 | 9% | 74% | 65 | 10% | 78% | 242 |
| Mississippian-Woodford\tTrend | 22 | 1% | 73% | 20 | 3% | 79% | 236 |
| Permian\tBasin | 279 | 10% | 79% | 96 | 14% | 77% | 324 |
| Rockies | 42 | 2% | 48% | 20 | 3% | 50% | 40 |
| U.S.\t–\tother | 159 | 5% | 35% | 33 | 5% | 32% | 5 |
| Total\tU.S. | \t 2,205 | 80% | 42% | 536 | 80% | 48% | \t1,061 |
| Canadian\theavy\toil | 549 | 20% | 99% | 86 | 12% | 95% | 205 |
| Total\tretained\tproperties | \t 2,754 | \t100% | 53% | 622 | 92% | 55% | \t1,266 |
| Divested\tproperties | — | \tN/A | N/A | 51 | 8% | 24% | — |
| Total | \t 2,754 | \t100% | 53% | 673 | \t100% | 52% | \t1,266 |

Anadarko	Basin	–	Our	acreage	is	located	primarily	in	Oklahoma's	Canadian,	Blaine	and	Caddo	counties.	The	Anadarko	Basin	is	a	non-conventional	reservoir	and produces	natural	gas,	NGLs	and	condensate.

The	Cana-Woodford	play	in	the	Anadarko	Basin	has	emerged	as	one	of	the	most	economic	shale	plays	in	North	America.	We	are	the	largest	leaseholder	and	the largest	producer	in	this	play.	During	2014,	we	increased	our	production	by	21	percent.	We	have	several	thousand	remaining	drilling	locations.	In	2015,	we	plan	to	drill approximately	95	gross	wells	in	the	Anadarko	Basin.

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.	The	Barnett	Shale	is	a	non-conventional	reservoir,	producing	natural	gas,	NGLs	and	condensate.

Since	acquiring	a	substantial	position	in	this	field	in	2002,	we	continue	to	introduce	technology	and	new	innovations	to	enhance	production	and	have	transformed this	into	one	of	the	top	producing	gas	fields	in	North	America.	In	2015,	we	plan	to	drill	approximately	10	gross	wells.

Eagle	Ford	–	We	have	approximately	82,000	net	acres	located	in	the	DeWitt	and	Lavaca	counties	in	south	Texas.	The	Eagle	Ford	is	an	industry-leading,	light-oil play	and	is	delivering	some	of	the	highest	rate-of-return	drilling	opportunities	in	North	America.

We	acquired	our	position	in	the	Eagle	Ford	on	February	28,	2014	from	GeoSouthern	and	subsequently	have	produced	approximately	24	MMBoe	with	oil accounting	for	61	percent	of	production	from	the	play.	Our	acreage	in	DeWitt	County	is	derisked	with	at	least	one	well	drilled	in	each	of	the	drilling	units,	providing	us with	a	significant	development	drilling	inventory.	Our	development	in	Lavaca	County	is	less	mature,	but	we	have	had	encouraging	results	from	recently	drilled	wells.	In 2015,	we	plan	to	drill	approximately	225	gross	wells.

In	addition,	we	have	a	100	percent	interest	in	the	Victoria	Express	Pipeline	("VEX")	in	south	Texas.	The	VEX	pipeline	is	a	56	mile	crude	oil	pipeline	from	the Eagle	Ford	to	the	Port	of	Victoria	terminal	that	has	a	current	capacity	of	50	MBOPD.

Mississippian-Woodford	Trend	–	Our	leases	are	located	in	north	central	Oklahoma	targeting	oil	in	the	Mississippian	Lime	and	Woodford	Shale.	These	areas	are being	explored	and	developed	under	an	arrangement	with	our	joint	venture	partner	and	independently	by	us	on	the	acreage	outside	of	our	area	of	mutual	interest	with	our joint	venture	partner.	In	2015,	we	plan	to	drill	approximately	50	gross	wells.

Permian	Basin	–	The	Permian	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,	Wolfcamp	Shale,	Delaware	and	various	conventional	formations.	These	and	other	emerging	oil and	liquids-rich	opportunities	across	our	acreage	in	the	Permian	Basin	will	deliver	high-margin	growth	for	many	years	to	come.	In	2015,	we	plan	to	drill	approximately 240	gross	wells.

Rockies	–	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	2015,	we	plan	to	drill	approximately	40	gross	wells	in	the Powder	River	Basin.

Canadian	Heavy	Oil	–	We	currently	have	two	main	projects,	Jackfish	and	Pike,	located	in	Alberta,	Canada.	In	addition,	our	Lloydminster	properties	are	located	to the	south	and	east	of	Jackfish	in	eastern	Alberta.	Lloydminster	produces	heavy	oil	by	conventional	means,	without	the	need	for	steam	injection.

Jackfish	is	our	thermal	heavy	oil	project	in	the	non-conventional	oil	sands	of	east	central	Alberta.	We	are	employing	steam-assisted	gravity	drainage	at	Jackfish. In	2014,	we	brought	the	third	phase	of	Jackfish	into	operation.	Each	phase	has	a	gross	facility	capacity	of	35	MBbls	per	day	at	each	facility.	With	three	phases	of Jackfish	operating,	production	increased	8	percent	in	2014.	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.

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,	2014.	The	regulatory	application	we	filed	in	2012	for	the	first phase	of	this	project	was	approved	in	2014	for	initial	gross	capacity	of	105	MBbls	per	day.	We	operate	and	hold	a	50	percent	interest	in	the	Pike	project.	Our	planned activity	at	Pike	in	2015	consists	of	front-end	engineering	and	design	work,	as	well	as	further	understanding	reservoir	characteristics.

To	facilitate	the	delivery	of	our	heavy	oil	production,	we	have	a	50	percent	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.	In	2014,	we completed	a	capacity	expansion	on	the	Access	Pipeline	system,	increasing	the	capacity	to	transport	approximately	170,000	barrels	of	bitumen	blend	per	day,	net	to	our 50%	interest.	This	expansion	is	expected	to	create	adequate	capacity	to	transport	our	growing	heavy	oil	production	to	the	Edmonton	market	hub.	Additionally,	it	will increase	the	transport	capacity	of	condensate	diluent	available	at	our	thermal	oil	facilities.

In	addition	to	our	Jackfish	and	Pike	projects,	we	hold	acreage	and	own	producing	assets	in	the	Lloydminster	region.	Our	Lloydminster	region	is	well-developed with	significant	infrastructure	and	is	primarily	accessible	year-round	for	drilling.	Lloydminster	is	a	low-risk,	high	margin	oil	development	play.

In	2015,	we	plan	to	drill	approximately	130	gross	wells	in	Canada.

Divested	Properties	–	During	2014,	we	monetized	certain	assets	through	an	asset	divestiture	program.	See	Note	2	to	the	financial	statements	included	in	"Item	8. Financial	Statements	and	Supplementary	Data"	of	this	report.

# Proved	Reserves

For	estimates	of	our	proved	developed	and	proved	undeveloped	reserves	and	the	discussion	of	the	contribution	by	each	key	property,	see	Note	22	to	the	financial statements	included	in	"Item	8.	Financial	Statements	and	Supplementary	Data"	of	this	report.

No	estimates	of	our	proved	reserves	have	been	filed	with	or	included	in	reports	to	any	federal	or	foreign	governmental	authority	or	agency	since	the	beginning	of 2014	except	in	filings	with	the	SEC	and	the	Department	of	Energy	("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	fourteen	years,	including	the	past	seven	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.	The	Group's	Director	reports	to	our	Vice	President	of	Budget	and	Reserves,	who	reports	to our	Senior	Vice	President	of	Business	Development,	who	reports	to	our	Chief	Financial	Officer.	No	portion	of	the	Group's	compensation	is	directly	dependent	on	the quantity	of	reserves	booked.

Throughout	the	year,	the	Group	performs	internal	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	consulting	firms.	During	2014,	we	engaged	two	such	firms	to	audit	91	percent	of our	proved	reserves.	LaRoche	Petroleum	Consultants,	Ltd.	audited	90	percent	of	our	2014	U.S.	reserves,	and	Deloitte	LLP	audited	95	percent	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	reviews,	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	independent	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	independent	engineering	consultants;	and

•	 monitor	the	performance	of	our	independent	engineering	consultants.

The	following	table	presents	our	estimated	pre-tax	cash	flow	information	related	to	proved	reserves.	These	estimates	correspond	with	the	method	used	in presenting	the	"Supplemental	Information	on	Oil	and	Gas	Operations"	in	Note	22	to	our	consolidated	financial	statements	included	in	this	report.

|  | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Pre-Tax\tFuture\tNet\tRevenue\t(Non-GAAP)\t^(1) |  |  |  |
| Proved\tDeveloped\tReserves | $32,560 | $4,295 | $36,855 |
| Proved\tUndeveloped\tReserves | 6,379 | 9,225 | \t 15,604 |
| Total\tProved\tReserves | $38,939 | $13,520 | $52,459 |
| Pre-Tax\t10%\tPresent\tValue\t(Non-GAAP)\t^(1) |  |  |  |
| Proved\tDeveloped\tReserves | $17,907 | $3,735 | $21,642 |
| Proved\tUndeveloped\tReserves | 3,134 | 3,189 | 6,323 |
| Total\tProved\tReserves | $21,041 | $6,924 | $27,965 |

(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	depreciation,	depletion	and	amortization,	asset impairments	or	non-property	related	expenses	such	as	debt	service	and	income	tax	expense.

Pre-tax	future	net	revenue	and	pre-tax	10	percent	present	value	are	non-GAAP	measures.	The	present	value	of	after-tax	future	net	revenues	discounted	at	10 percent	per	annum	("standardized	measure")	was	$20.5	billion	at	the	end	of	2014.	Included	as	part	of	standardized	measure	were	discounted	future	income	taxes of	$7.5	billion.	Excluding	these	taxes,	the	present	value	of	our	pre-tax	future	net	revenue	("pre-tax	10	percent	present	value")	was	$28	billion.	We	believe	the	pre- tax	10	percent	present	value	is	a	useful	measure	in	addition	to	the	after-tax	standardized	measure.	The	pre-tax	10	percent	present	value	assists	in	both	the determination	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	percent	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	(MBbls/d) | Bitumen	(MBbls/d) | Gas	(MMcf/d) | NGLs	(MBbls/d) | Total	(MBoe/d) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2014 |  |  |  |  |  |
| Barnett\tShale | 2 | — | 909 | 54 | 208 |
| Jackfish | — | 56 | — | — | 56 |
| U.S. | 130 | — | 1,809 | 137 | 568 |
| Canada | 28 | 56 | 111 | 2 | 105 |
| Total\tNorth\tAmerica | 158 | 56 | 1,920 | 139 | 673 |
| 2013 |  |  |  |  |  |
| Barnett\tShale | 2 | — | 1,025 | 55 | 228 |
| Jackfish | — | 51 | — | — | 51 |
| U.S. | 78 | — | 1,942 | 116 | 517 |
| Canada | 39 | 51 | 451 | 10 | 176 |
| Total\tNorth\tAmerica | 117 | 51 | 2,393 | 126 | 693 |
| 2012 |  |  |  |  |  |
| Barnett\tShale | 2 | — | 1,075 | 47 | 228 |
| Jackfish | — | 48 | — | — | 48 |
| U.S. | 58 | — | 2,055 | 99 | 500 |
| Canada | 40 | 48 | 508 | 10 | 182 |
| Total\tNorth\tAmerica | 98 | 48 | 2,563 | 109 | 682 |

| Year	Ended	December	31, | Oil	(Per	Bbl) | Bitumen	(Per	Bbl) | Gas	(Per	Mcf) | NGLs	(Per	Bbl) | Production	Cost<br>(Per	Boe) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 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 |
| 2012 |  |  |  |  |  |
| Barnett\tShale | $91.45 | $— | $2.23 | $27.57 | $3.91 |
| Jackfish | $— | $47.57 | $— | $— | $19.51 |
| U.S. | $88.68 | $— | $2.32 | $28.49 | $5.79 |
| Canada | $68.29 | $47.57 | $2.49 | $48.63 | $15.18 |
| Total\tNorth\tAmerica | $80.43 | $47.57 | $2.36 | $30.42 | $8.30 |

# Drilling	Statistics

The	following	table	summarizes	our	development	and	exploratory	drilling	results.

(1) Includes	bitumen	wells.

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

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

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	general	and	administrative	expense,	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,	2014.	The	acreage	in	the	table	includes	0.9	million, 0.3	million	and	0.5	million	net	acres	subject	to	leases	that	are	scheduled	to	expire	during	2015,	2016	and	2017,	respectively.	As	of	December	31,	2014,	there	were	no proved	undeveloped	reserves	associated	with	our	expiring	acreage.	Of	the	1.7	million	net	acres	set	to	expire	by	December	31,	2017,	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	2014,	we	allowed	approximately	0.2	million	acres	to	expire.

|  | Developed |  | Undeveloped |  | Total |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross^\t\t(1) | Net^\t(2) | Gross^\t\t(1) | Net^\t(2) | Gross^\t(1) | Net^\t(2) |
|  |  |  | (In\tthousands) | (In\tthousands) |  |  |
| U.S. | 2,688 | \t1,735 | 5,797 | \t2,931 | 8,485 | \t4,666 |
| Canada | 777 | 582 | 2,147 | 995 | 2,924 | \t1,577 |
| Total\tNorth\tAmerica | 3,465 | \t2,317 | 7,944 | \t3,926 | \t11,409 | \t6,243 |

(1) Gross	acres	are	the	sum	of	all	acres	in	which	we	own	an	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	–	These	assets	consist	of	transmission	pipelines	with	a	capacity	of	approximately	1.3	Bcf/d,	processing	facilities	with	a	total	processing	capacity	of approximately	1.2	Bcf/d	and	gathering	systems	with	total	capacity	of	approximately	2.8	Bcf/d.

•	 Oklahoma	–	These	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	and	gathering	systems	with	total	capacity	of	approximately	510	MMcf/d.

•	 Ohio	River	Valley	–	The	Ohio	River	Valley	("ORV")	operations	are	an	integrated	network	of	assets	comprised	of	a	5,000-barrel-per-hour	crude	oil	and condensate	barge	loading	terminal	on	the	Ohio	River,	a	20-spot	operation	crude	oil	and	condensate	rail	loading	terminal	on	the	Ohio	Central	Railroad network	and	approximately	200	miles	of	crude	oil	and	condensate	pipelines	in	Ohio	and	West	Virginia.	The	assets	also	include	500,000	barrels	of	above ground	storage	and	a	trucking	fleet	of	approximately	100	vehicles	comprised	of	both	semi	and	straight	trucks.	EnLink	has	eight	existing	brine	disposal wells	with	an	injection	capacity	of	approximately	5,000	Bbls/d.	Additionally,	ORV	operations	include	five	condensate	stabilization	and	natural	gas compression	stations,	including	two	stations	under	construction,	with	combined	capacities	of	19,000	Bbls/d	of	condensate	stabilization	and	580	MMcf/d	of natural	gas	compression.

# Marketing	and	Midstream	Activities

# Midstream	Operations

Comprising	approximately	95%	of	our	2014	midstream	operating	profit,	EnLink	is	the	primary	component	of	our	midstream	operations.	EnLink's	operations primarily	focus	on	providing	midstream	energy	services,	including	gathering,	transmission,	processing,	fractionation	and	marketing,	to	producers	of	natural	gas,	NGLs, crude	oil	and	condensate,	including	Devon.	EnLink	also	provides	crude	oil,	condensate	and	brine	services	to	producers.	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.	Further,	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	to	the	financial	statements	included	in	"Item	8.

Financial	Statements	and	Supplementary	Data"	of	this	report	for	further	information.

As	of	January	2015,	our	production	was	sold	under	the	following	contracts.

|  | Short-Term |  | Long-Term |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Variable | Fixed | Variable | Fixed |
| Oil\tand\tbitumen | 51% | \t— | 49% | \t— |
| Natural\tgas | 69% | 1% | 30% | \t— |
| NGLs | 63% | 13% | 24% | \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, 2014,	we	were	committed	to	deliver	the	following	fixed	quantities	of	production.

|  |  |  |  |  | More	Than |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Total | Less\tThan\t1\tYear | 1-3\tYears | 3-5\tYears | 5\tYears |
| Oil\tand\tbitumen\t(MMBbls) | 180 | 51 | 54 | 47 | 28 |
| Natural\tgas\t(Bcf) | \t\t\t\t\t\t\t711 | \t\t\t\t\t\t\t\t382 | \t\t\t\t\t\t\t\t\t314 | \t\t\t\t\t\t\t\t\t15 | \t\t\t\t\t\t\t\t\t— |
| NGLs\t(MMBbls) | 4 | 4 | — | — | — |
| Total\t(MMBoe) | 302 | 118 | 107 | 49 | 28 |

We	expect	to	fulfill	our	delivery	commitments	over	the	next	three	years	with	production	from	our	proved	developed	reserves.	We	expect	to	fulfill	our	longer-term delivery	commitments	beyond	three	years	primarily	with	our	proved	developed	reserves.	In	certain	regions,	we	expect	to	fulfill	these	longer-term	delivery	commitments with	our	proved	undeveloped	reserves.

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 satisfy	our	future	commitments.	However,	should	our	proved	reserves	not	be	sufficient	to	satisfy	our	delivery	commitments,	we	can	and	may	use	spot	market	purchases to	fulfill	the	commitments.

# Customers

During	2014,	2013	and	2012,	no	purchaser	accounted	for	over	10	percent	of	our	operating	revenues.

# Competition

See	"Item	1A.	Risk	Factors."

# Public	Policy	and	Government	Regulation

Our	industry	is	subject	to	regulation	throughout	the	world.	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	laws	and	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	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,	state,	provincial,	tribal	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	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.

# 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:

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

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

•the	emission	of	certain	gases	into	the	atmosphere;

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

•the	development	of	emergency	response	and	spill	contingency	plans.

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	activities,	and	our	industry	in	general,	are	subject	to	a	variety	of	risks.	If	any	of	the	following	risk	factors	should	occur,	our	profitability,	financial condition	or	liquidity	could	be	materially	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	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.	A	significant	downward	movement	of	the	prices	for	these	commodities	could	have	a	material	adverse	effect	on	our	revenues,	operating	cash	flows and	profitability.	Such	a	downward	price	movement	could	also	have	a	material	adverse	effect	on	our	estimated	proved	reserves,	the	carrying	value	of	our	oil	and	gas properties,	the	level	of	planned	drilling	activities	and	future	growth.	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	consumer	demand	for	oil,	gas	and	NGLs;

•conservation	efforts;

•	 OPEC	production	levels;

•geopolitical	risks;

•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;

•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	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	or,	through	engineering	studies,	identify	additional	producing	zones	in	existing	wells,	utilize secondary	or	tertiary	recovery	techniques	or	acquire	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

Substantial	costs	are	often	required	to	locate	and	acquire	properties	and	drill	exploratory	wells.	Such	activities	are	subject	to	numerous	risks,	including	the	risk that	we	will	not	encounter	commercially	productive	oil	or	gas	reservoirs.	The	costs	of	drilling	and	completing	wells	are	often	uncertain.	In	addition,	oil	and	gas properties	can	become	damaged	or	drilling	operations	may	be	curtailed,	delayed	or	canceled	as	a	result	of	a	variety	of	factors	including	but	not	limited	to:

•unexpected	drilling	conditions;

•pressure	or	irregularities	in	reservoir	formations;

•equipment	failures	or	accidents;

•fires,	explosions,	blowouts	and	surface	cratering;

•adverse	weather	conditions;

•lack	of	access	to	pipelines	or	other	transportation	methods;

•environmental	hazards	or	liabilities;	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.	In	addition,	drilling	activities	may not	be	successful	in	establishing	proved	reserves.	Such	a	failure	could	have	an	adverse	effect	on	our	future	results	of	operations	and	financial	condition.	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.

# Competition	for	Leases,	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.	Typically,	during	times	of	high	or	rising	commodity	prices,	drilling	and	operating	costs	will	also	increase.	Higher	prices	will	also generally	increase	the	cost	to	acquire	properties.	Certain	of	our	competitors	have	financial	and	other	resources	substantially	larger	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	drilling	rights.	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.

# 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.	When	possible,	we	gain	access	to	midstream systems	that	provide	the	most	advantageous	downstream	market	prices	available	to	us.	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	due	to	loss	of	access	to	plants,	pipelines	or	gathering	systems.	Such	access	could	be	lost	due	to	a 19

number	of	factors,	including,	but	not	limited	to,	weather	conditions,	accidents,	field	labor	issues	or	strikes.	Additionally,	we	and	third-parties	may	be	subject	to constraints	that	limit	our	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.

# Hedging	Limits	Participation	in	Commodity	Price	Increases	and	Increases	Counterparty	Credit	Risk	Exposure

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.

# Public	Policy,	which	Includes	Laws,	Rules	and	Regulations,	can	Change

Our	operations	are	generally	subject	to	federal	laws,	rules	and	regulations	in	the	United	States	and	Canada.	In	addition,	we	are	also	subject	to	the	laws	and regulations	of	various	states,	provinces,	tribal	and	local	governments.	Pursuant	to	public	policy	changes,	numerous	government	departments	and	agencies	have	issued extensive	rules	and	regulations	binding	on	the	oil	and	gas	industry	and	its	individual	members,	some	of	which	require	substantial	compliance	costs	and	carry	substantial penalties	for	failure	to	comply.	Changes	in	such	public	policy	have	affected,	and	at	times	in	the	future	could	affect,	our	operations.	Political	developments	can	restrict production	levels,	enact	price	controls,	change	environmental	protection	requirements	and	increase	taxes,	royalties	and	other	amounts	payable	to	governments	or governmental	agencies.	Existing	laws	and	regulations	can	also	require	us	to	incur	substantial	costs	to	maintain	regulatory	compliance.	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,	income	taxes	and	climate	change	as	discussed	below.

Hydraulic	Fracturing	–	Several	proposals	are	before	the	U.S.	Congress	and	other	federal	agencies	that,	if	implemented,	could	either	restrict	the	practice	of hydraulic	fracturing	or	subject	the	process	to	further	regulation,	including	regulation	of	hydraulic	fracturing	on	federal	lands	and	tribal	reservations;	regulation	of	air emissions;	regulation	of	wastewater	discharges	from	unconventional	oil	and	gas	resources;	and	required	disclosure	of	chemicals	and	mixtures	used	in	hydraulic fracturing.	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.	Hydraulic	fracturing	of	wells	and subsurface	water	disposal	are	also	under	public	and	governmental	scrutiny	due	to	potential	environmental	and	physical	impacts.	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.

Income	Taxes	–	We	are	subject	to	federal,	state,	provincial	and	local	income	taxes,	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	United	States	President	and	other	policy	makers	have	proposed	provisions	that	would,	if	enacted,	make significant	changes	to	United	States	tax	laws	applicable	to	us.	The	most	significant	change	to	our	business	would	eliminate	the	immediate	deduction	for	intangible drilling	and	development	costs.	Such	a	change	could	have	a	material	adverse	effect	on	our	profitability,	financial	condition	and	liquidity.

Climate	Change	–	Policymakers	in	the	United	States	and	Canada	are	increasingly	focusing	on	whether	the	emissions	of	greenhouse	gases,	such	as	carbon	dioxide and	methane,	are	contributing	to	harmful	climatic	changes.	Policymakers	at	both	the	United	States	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. Legislative	initiatives	and	discussions	to	date	have	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.	Cap-and-trade	programs	could	be	relevant	to	us	and	our	operations	in	several	ways.	First,	the	equipment	we	use	to	explore	for,	develop,	produce and	process	oil	and	natural	gas	emits	greenhouse	gases.	We	could	therefore	be	subject	to	caps	and	penalties	if	emissions	exceeded	the	caps.	Second,	the	combustion	of carbon-based	fuels,	such	as	the	oil,	gas	and	NGLs	we	sell,	emits	carbon	dioxide	and	other	greenhouse	gases.	Therefore,	demand	for	our	products	could	be	reduced	by imposition	of	caps	and	penalties	on	our	customers.	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.	Of	overriding	significance	would	be	the	point	of	regulation	or	taxation.	Application	of	caps	or	taxes	on	companies	such	as Devon,	based	on	carbon	content	of	produced	oil	and	gas	volumes	rather	than	on	consumer	emissions,	could	lead	to	penalties,	fees	or	tax	assessments	for	which	there	are no	mechanisms	to	pass	them	through	the	distribution	and	consumption	chain	where	fuel	use	or	conservation	choices	are	made.	Moreover,	because	oil	and	natural	gas	are used	as	chemical	feed	stocks	and	not	solely	as	fossil	fuel,	applying	a	carbon	tax	to	oil	and	gas	at	the	production	stage	would	be	excessive	with	respect	to	actual	carbon emissions	from	petroleum	fuels.

# Environmental	Matters	and	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	pollution clean-up	resulting	from	our	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.

# 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	worker's	compensation	and	employer's	liability	insurance.	However,	our	insurance	coverage	does	not	provide	100	percent	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	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.

# 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.	We	apply technical	and	process	controls	in	line	with	the	National	Institute	of	Standards	&	Technology	framework	to	secure	corporate	information	assets.	In	addition,	we	participate in	information	sharing	partnerships	to	collect	relevant	threat	intelligence	and	pro-actively	identify	and	mitigate	targeted	attacks.	Although	we	have	not	suffered	material losses	related	to	cyber	attacks,	if	we	were	successfully	attacked,	we	may	incur	substantial	remediation	and	other	costs	or	suffer	other	negative	consequences.	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	New	York	Stock	Exchange	(the	"NYSE").	On	February	11,	2015,	there	were	8,605	holders	of	record	of	our	common	stock. The	following	table	sets	forth	the	quarterly	high	and	low	sales	prices	for	our	common	stock	as	reported	by	the	NYSE	during	2014	and	2013,	as	well	as	the	quarterly dividends	per	share	paid	during	2014	and	2013.	We	began	paying	regular	quarterly	cash	dividends	on	our	common	stock	in	the	second	quarter	of	1993.	We	anticipate continuing	to	pay	regular	quarterly	dividends	in	the	foreseeable	future.

|  | Price	Range	of	Common	Stock<br>								High | Low | Dividends<br>				Per	Share |
| :--- | :--- | :--- | :--- |
| 2014: |  |  |  |
| Quarter\tEnded\tDecember\t31,\t2014 | $68.80 | $51.76 | $0.24 |
| Quarter\tEnded\tSeptember\t30,\t2014 | $80.01 | $67.58 | $0.24 |
| Quarter\tEnded\tJune\t30,\t2014 | $80.63 | $66.75 | $0.24 |
| Quarter\tEnded\tMarch\t31,\t2014 | $66.95 | $57.67 | $0.22 |
| 2013: |  |  |  |
| Quarter\tEnded\tDecember\t31,\t2013 | $66.92 | $57.58 | $0.22 |
| Quarter\tEnded\tSeptember\t30,\t2013 | $60.38 | $52.00 | $0.22 |
| Quarter\tEnded\tJune\t30,\t2013 | $61.10 | $50.81 | $0.22 |
| Quarter\tEnded\tMarch\t31,\t2013 | $61.80 | $51.63 | $0.20 |

# Performance	Graph

The	following	performance	graph	compares	the	yearly	percentage	change	in	the	cumulative	total	shareholder	return	on	Devon's	common	stock	with	the cumulative	total	returns	of	the	Standard	&	Poor's	500	index	("the	S&P	500	Index")	and	a	peer	group	of	companies	to	which	we	compare	our	performance.	The	peer group	includes	Anadarko	Petroleum	Corporation,	Apache	Corporation,	Chesapeake	Energy	Corporation,	ConocoPhillips,	Encana	Corporation,	EOG	Resources,	Inc., Hess	Corporation,	Marathon	Oil	Corporation,	Murphy	Oil	Corporation,	Newfield	Exploration	Company,	Noble	Energy,	Inc.,	Occidental	Petroleum	Corporation,	Pioneer Natural	Resources	Company	and	Talisman	Energy,	Inc.	The	graph	was	prepared	assuming	$100	was	invested	on	December	31,	2009	in	Devon's	common	stock,	the S&P	500	Index	and	the	peer	group	and	dividends	have	been	reinvested	subsequent	to	the	initial	investment.

The	graph	and	related	information	shall	not	be	deemed	"soliciting	material"	or	to	be	"filed"	with	the	SEC,	nor	shall	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	2014.

| Period | Total	Number	of<br>Shares	Purchased^	(1) | Average	Price	Paid<br>per	Share |
| :--- | :--- | :--- |
| October\t1\t–\tOctober\t31 | 1,036 | $60.00 |
| November\t1\t–\tNovember\t30 | 39 | $57.07 |
| December\t1\t–\tDecember\t31 | 343,187 | $59.94 |
| Total | 344,262 | $59.94 |

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

Under	the	Devon	Energy	Corporation	Incentive	Savings	Plan	(the	"Plan"),	eligible	employees	may	purchase	shares	of	our	common	stock	through	an	investment in	the	Devon	Stock	Fund	(the	"Stock	Fund"),	which	is	administered	by	an	independent	trustee.	Eligible	employees	purchased	approximately	57,300	shares	of	our common	stock	in	2014,	at	then-prevailing	stock	prices,	that	they	held	through	their	ownership	in	the	Stock	Fund.	We	acquired	the	shares	of	our	common	stock	sold under	the	Plan	through	open-market	purchases.

Similarly,	under	the	Devon	Canada	Corporation	Savings	Plan	(the	"Canadian	Plan"),	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	2014,	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, |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 | 2011 | 2010 |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | $19,566 | $10,397 | $9,501 | $11,445 | $9,935 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations^\t(1) | $1,691 | $(20) | $(185) | $2,134 | $2,333 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tDevon | $1,607 | $(20) | $(185) | $2,134 | $2,333 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tBasic | $3.93 | $(0.06) | $(0.47) | $5.12 | $5.31 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon\t–\tDiluted | $3.91 | $(0.06) | $(0.47) | $5.10 | $5.29 |
| Cash\tdividends\tper\tcommon\tshare | $0.94 | $0.86 | $0.80 | $0.67 | $0.64 |
| Weighted\taverage\tcommon\tshares\toutstanding\t–\tBasic | 409 | 406 | 404 | 417 | 440 |
| Weighted\taverage\tcommon\tshares\toutstanding\t–\tDiluted | 411 | 406 | 404 | 418 | 441 |
| Total\tassets^\t(1) | $50,637 | $42,877 | $43,326 | $41,117 | $32,927 |
| Long-term\tdebt | $9,830 | $7,956 | $8,455 | $5,969 | $3,819 |
| Stockholders'\tequity | $26,341 | $20,499 | $21,278 | $21,430 | $19,253 |

# 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	2014	Results

As	an	enterprise,	we	strive	to	optimize	value	for	our	shareholders	by	growing	cash	flow,	earnings,	production	and	reserves,	all	on	a	per	debt-adjusted	share	basis. We	accomplish	this	by	executing	our	strategy,	which	is	outlined	in	"Items	1	and	2.	Business	and	Properties"	of	this	report.

2014	was	a	year	of	strong	execution	and	strengthening	of	the	portfolio	for	Devon.	We	completed	three	strategic	portfolio	transformation	initiatives	that	were focused	on	building	value	per	share.

On	February	28,	2014,	we	acquired	certain	of	GeoSouthern's	Eagle	Ford	assets	and	operations	in	south	Texas	for	approximately	$6.0	billion.	This	acquisition included	approximately	250	MMBoe	of	proved	reserves.	Additionally,	since	closing	the	transaction,	we	have	produced	approximately	24	MMBoe	from	our	Eagle	Ford development,	with	oil	accounting	for	approximately	61%	of	our	production	from	the	play.

On	March	7,	2014,	we	completed	a	transaction	to	combine	substantially	all	of	our	U.S.	midstream	assets	with	Crosstex's	assets	to	form	EnLink,	a	new	midstream business	that	we	control.	This	transaction	is	described	more	fully	in	Note	2	to	the	financial	statements	included	in	"Item	8.	Financial	Statements	and	Supplementary Data"	in	this	report.	Subsequent	to	the	formation	of	EnLink's	midstream	business,	EnLink	acquired	additional	oil	and	gas	pipeline	assets.

The	results	of	operations	from	our	assets	contributed	to	EnLink	are	included	in	our	consolidated	financial	statements	for	all	periods	presented.	Additionally,	the results	of	operations	for	all	assets	contributed	to	EnLink	are	included	in	our	consolidated	financial	statements	subsequent	to	the	completion	of	the	transaction.	The portions	of	EnLink's	net	earnings	and	stockholders'	equity	not	attributable	to	Devon's	controlling	interest	are	shown	separately	as	noncontrolling	interests	in	our consolidated	comprehensive	statements	of	earnings	and	consolidated	balance	sheets.

Finally,	we	completed	our	asset	divestitures	of	certain	U.S.	and	Canadian	properties	through	two	significant	transactions.	On	April	1,	2014,	we	sold	Canadian conventional	assets	for	$2.8	billion	($3.125	billion	Canadian	dollars),	and	on	August	29,	2014,	we	sold	certain	U.S.	assets	for	$2.2	billion.

Key	measures	of	our	performance	are	summarized	below.

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  | ($\tin\tmillions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) | ($\tin\tmillions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) | ($\tin\tmillions,\texcept\tper\tshare\tand\tper\tBoe\tamounts) |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $1,607 | \t+8184% | $(20) | +90% | $(206) |
| Core\tearnings\tattributable\tto\tDevon^\t(1) | $2,017 | +16% | $1,734 | +33% | $1,305 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare\tattributable\tto\tDevon | $3.91 | \t+6933% | $(0.06) | +87% | $(0.47) |
| Core\tearnings\tper\tshare\tattributable\tto\tDevon^\t(1) | $4.91 | +15% | $4.26 | +32% | $3.22 |
| Retained\tproduction\t(MBoe/d) | 622 | +15% | 541 | +6% | 511 |
| Total\tproduction\t(MBoe/d) | 673 | -3% | 693 | +2% | 682 |
| Realized\tprice\tper\tBoe | $40.33 | +20% | $33.70 | +18% | $28.65 |
| Core\toperating\tincome\tper\tBoe^\t(2) | $27.28 | +27% | $21.47 | +28% | $16.78 |
| Operating\tcash\tflow\t–\tcontinuing\toperations | $5,981 | +10% | $5,436 | +10% | $4,930 |
| Capitalized\tcosts,\tincluding\tacquisitions | $13,559 | +104% | $6,643 | -22% | $8,474 |
| Shareholder\tand\tnoncontrolling\tinterest\tdistributions | $621 | +78% | $348 | +8% | $324 |
| Reserves\t(MMBoe) | 2,754 | -7% | \t 2,963 | 0% | \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) Computed	as	revenues	from	commodity	sales	and	marketing	and	midstream	operations,	less	expenses	for	lease	operations,	marketing	and	midstream	operations, cash-based	general	and	administrative,	production	and	property	taxes	and	net	financing	costs,	with	the	result	divided	by	total	production.

Our	2014	net	earnings	attributable	to	Devon,	core	earnings,	core	earnings	per	share	and	core	operating	income	per	Boe	all	increased	compared	to	2013.	The improved	2014	results	were	driven	primarily	by	increases	in	production	from	our	retained	properties,	particularly	higher-margin	liquids	volumes,	combined	with	higher gas	and	bitumen	price	realizations.	EnLink's	earnings	growth	also	contributed	to	improved	2014	results.	These	factors,	along	with	our	portfolio	transformation,	drove higher	earnings	and	operating	cash	flow	in	2014.

# Business	and	Industry	Outlook

North	American	crude	oil	and	natural	gas	prices	have	historically	been	volatile	based	on	supply	and	demand	dynamics,	and	we	expect	this	volatility	to	continue into	2015.

In	the	second	half	of	2014,	crude	oil	prices	began	a	rapid	and	significant	decline	as	global	supply	outpaced	demand.	The	decline	increased	further	following OPEC's	announcement	in	late	November	2014	that	it	would	not	reduce	its	production	targets.	This	decline	continued	into	2015	but	has	started	to	stabilize	with	the	West Texas	Intermediate	("WTI")	benchmark	generally	ranging	between	$45-$50	per	barrel	throughout	January	and	early	February	2015.	If	WTI	remained	at	this	level throughout	2015,	our	realized	crude	price,	excluding	the	effects	of	hedges,	would	decrease	approximately	50%	compared	to	2014.

Although	natural	gas	prices	improved	in	2014	compared	to	2013,	natural	gas	continues	to	be	challenged	due	to	an	imbalance	between	supply	and	demand	across North	America.	We	expect	most	natural	gas	benchmark	prices	to	be	lower	in	2015,	as	supply	continues	to	surpass	demand.

Our	industry	will	be	challenged	by	lower	commodity	prices.	However,	we	have	strategically	positioned	our	company	so	that	we	can	prudently	continue	investing in	our	portfolio	of	assets.	First,	following	our	2014	asset	divestitures	our	portfolio	is	more	focused,	and	we	will	concentrate	our	capital	programs	on	the	highest	return assets	in	our	portfolio.	We	exited	2014	with	a	production	profile	comprised	of	roughly	35	percent	oil,	20	percent	natural	gas	liquids	and	45	percent	natural	gas. Recognizing	the	relative	value	of	crude	oil,	we	are	devoting	the	vast	majority	of	our	2015	capital	investment	toward	growing	our	oil	production,	particularly	the	sweet grades	of	oil	found	in	the	U.S.

Second,	we	have	hedged	approximately	50	percent	of	our	projected	2015	crude	production	at	a	floor	price	of	$91	per	barrel	and	approximately	40	percent	of	our natural	gas	production	at	$4.17	per	Mcf.	These	2015	contracts	had	an	approximate	value	of	$2	billion	at	December	31,	2014.	Additionally,	costs	for	the	services	we	use are	declining	in	response	to	lower	commodity	prices.	These	factors	will	partially	mitigate	the	effects	of	lower	commodity	prices.

Finally,	EnLink's	growth	as	a	result	of	recent	acquisitions	and	planned	asset	dropdowns	from	Devon	will	generate	additional	cash	resources	that	can	be	used	for our	capital	investment.

Nevertheless,	lower	commodity	prices	create	headwinds	on	our	business.	Therefore,	we	are	projecting	a	20	percent	decrease	in	capital	spending	in	2015.	Such spending	will	be	focused	on	the	oily	assets	in	our	portfolio	currently	generating	the	highest	returns.	With	this	focus	on	our	highest	return	assets,	we	expect	growth	in	oil production	to	be	between	20	and	25	percent	in	2015.

# Results	of	Operations

All	amounts	in	this	document	related	to	our	International	operations	for	the	year	ended	December	31,	2012	are	presented	as	discontinued.	Therefore,	all	results from	those	operations	are	excluded	in	the	"Results	of	Operations"	section	unless	otherwise	noted.

# Oil,	Gas	and	NGL	Production

|  | 2014 | Change | Year	Ended	December	31,<br>2013 | Change | 2012 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Oil\t(MBbls/d) |  |  |  |  |  |
| Anadarko\tBasin | 10 | +12% | 9 | +38% | 7 |
| Barnett\tShale | 2 | -2% | 2 | +22% | 2 |
| Eagle\tFord | 39 | \t N/M | — | \t N/M | — |
| Mississippian-Woodford\tTrend | 9 | +93% | 5 | \t +625% | 1 |
| Permian\tBasin | 56 | +19% | 46 | +28% | 36 |
| Rockies | 9 | +13% | 8 | +31% | 6 |
| Other | 2 | -33% | 3 | +50% | 2 |
| Total\tU.S. | 127 | +74% | 73 | +35% | 54 |
| Canada | 26 | -7% | 28 | -4% | 29 |
| Total\tretained\tproperties | 153 | +52% | 101 | +22% | 83 |
| Divested\tproperties | 5 | -66% | 16 | +3% | 15 |
| Total | 158 | +36% | 117 | +19% | 98 |
| Bitumen\t(MBbls/d) |  |  |  |  |  |
| Canada | 56 | +8% | 51 | +8% | 48 |
| Gas\t(MMcf/d) |  |  |  |  |  |
| Anadarko\tBasin | 310 | +9% | 285 | -0% | 285 |
| Barnett\tShale | 909 | -11% | \t1,025 | -5% | \t1,075 |
| Eagle\tFord | 86 | \t N/M | — | \t N/M | — |
| Mississippian-Woodford\tTrend | 30 | \t +155% | 12 | \t +701% | 1 |
| Permian\tBasin | 132 | +26% | 105 | +24% | 85 |
| Rockies | 64 | -18% | 78 | -28% | 108 |
| Other | 131 | -14% | 153 | -13% | 176 |
| Total\tU.S | \t1,662 | +0% | \t1,658 | -4% | \t1,730 |
| Canada | 23 | -19% | 28 | +30% | 22 |
| Total\tretained\tproperties | \t1,685 | -0% | \t1,686 | -4% | \t1,752 |
| Divested\tproperties | 235 | -67% | 707 | -13% | 811 |
| Total | \t1,920 | -20% | \t2,393 | -7% | \t2,563 |
| NGLs\t(MBbls/d) |  |  |  |  |  |
| Anadarko\tBasin | 32 | +28% | 25 | +43% | 17 |
| Barnett\tShale | 54 | -1% | 55 | +17% | 47 |
| Eagle\tFord | 11 | \t N/M | — | \t N/M | — |
| Mississippian-Woodford\tTrend | 5 | \t +342% | 1 | \t +770% | — |
| Permian\tBasin | 18 | +29% | 14 | +26% | 11 |
| Rockies | 1 | +24% | 1 | +7% | 1 |
| Other | 11 | +0% | 11 | +0% | 11 |
| Total\tU.S. | 132 | +23% | 107 | +23% | 87 |
| Divested\tproperties | 7 | -63% | 19 | -13% | 22 |
| Total | 139 | +10% | 126 | +15% | 109 |
| Combined\t(MBoe/d) |  |  |  |  |  |
| Anadarko\tBasin | 94 | +15% | 82 | +14% | 72 |
| Barnett\tShale | 208 | -9% | 228 | +0% | 228 |
| Eagle\tFord | 65 | \t N/M | — | \t N/M | — |
| Mississippian-Woodford\tTrend | 20 | \t +160% | 8 | \t +662% | 1 |
| Permian\tBasin | 96 | +23% | 78 | +27% | 62 |
| Rockies | 20 | -5% | 22 | -13% | 25 |
| Other | 33 | -13% | 38 | -7% | 41 |
| Total\tU.S. | 536 | +18% | 456 | +6% | 429 |
| Canada | 86 | +2% | 85 | +4% | 81 |
| Total\tretained\tproperties | 622 | +15% | 541 | +6% | 510 |
| Divested\tproperties | 51 | -66% | 152 | -11% | 172 |
| Total | 673 | -3% | 693 | +2% | 682 |

# Oil,	Gas	and	NGL	Pricing

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014\t^(1) | Change | 2013\t^(1) | Change | 2012\t^(1) |
| Oil\t(per\tBbl) |  |  |  |  |  |
| U.S. | $85.64 | -9% | $94.52 | +7% | $88.68 |
| Canada | $68.14 | -1% | $69.18 | +1% | $68.29 |
| Total | $82.47 | -4% | $86.02 | +7% | $80.43 |
| Bitumen\t(per\tBbl) |  |  |  |  |  |
| Canada | $55.88 | +16% | $48.04 | +1% | $47.57 |
| Gas\t(per\tMcf) |  |  |  |  |  |
| U.S. | $3.92 | +27% | $3.10 | +33% | $2.32 |
| Canada\t^(2) | $3.64 | +19% | $3.05 | +23% | $2.49 |
| Total | $3.90 | +26% | $3.09 | +31% | $2.36 |
| NGLs\t(per\tBbl) |  |  |  |  |  |
| U.S. | $24.46 | -5% | $25.75 | -10% | $28.49 |
| Canada | $50.52 | +9% | $46.17 | -5% | $48.63 |
| Total | $24.89 | -9% | $27.33 | -10% | $30.42 |
| Combined\t(per\tBoe) |  |  |  |  |  |
| U.S. | $37.96 | +20% | $31.59 | +23% | $25.59 |
| Canada | $53.11 | +33% | $39.91 | +8% | $37.01 |
| Total | $40.33 | +20% | $33.70 | +18% | $28.65 |

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

(2) The	reported	Canadian	gas	volumes	include	21	and	25	MMcf	per	day	for	the	years	ended	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	impact	of	the eliminated	gas	revenues	more	significantly	impacts	our	gas	price.

# 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 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| 2012\tsales | $2,899 | $828 | $2,211 | $1,215 | $7,153 |
| Change\tdue\tto\tvolumes | 531 | 65 | (152) | 181 | 625 |
| Change\tdue\tto\tprices | 238 | 9 | 639 | (142) | 744 |
| 2013\tsales | $3,668 | $902 | $2,698 | $1,254 | $8,522 |
| Change\tdue\tto\tvolumes | \t 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 |

Volumes	2014	vs.	2013	Oil,	gas	and	NGL	sales	increased	$985	million	due	to	volumes.	The	primary	driver	of	the	increase	resulted	from	a	74	percent	increase	in our	U.S.	oil	production.	Such	growth	resulted	from	our	recently	acquired	Eagle	Ford	properties	and	the	continued	development	of	our	properties	in	the	Permian	Basin and	Mississippian-Woodford	Trend	properties.	In	addition,	we	continue	to	grow	our	NGL	production	from	these	plays,	which	resulted	in	$131	million	of	additional sales.	Bitumen	sales	increased	$76	million	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 percent	decrease	in	our	2014	gas	production,	which	was	impacted	by	our	asset	divestitures,	resulting	in	a	$533	million	decline	in	sales.

Volumes	2013	vs.	2012	Oil,	gas	and	NGL	sales	increased	$625	million	due	to	a	15	percent	increase	in	our	liquids	production,	partially	offset	by	a	7	percent decline	in	our	gas	production.	Oil	production	was	the	largest	driver	of	the	increase,	accounting	for	85	percent	of	the	higher	sales.	Largely	due	to	continued	development of	our	properties	in	the	Permian	Basin,	the	Mississippian-Woodford	Trend	and	the	Anadarko	Basin,	our	oil	sales	increased	$531	million.	Bitumen	sales	increased	$65 million	due	to	development	of	our	Jackfish	thermal	heavy	oil	projects	in	Canada.	Additionally,	our	NGL	sales	increased	$181	million	as	a	result	of	continued	drilling	in the	liquids-rich	gas	portions	of	the	Barnett	Shale	and	the	Anadarko	Basin.	These	increases	were	partially	offset	by	a	7	percent	decrease	in	our	2013	gas	production, resulting	in	a	$152	million	decline	in	sales.

Prices	2014	vs.	2013	Oil,	gas	and	NGL	sales	increased	$403	million	due	to	a	20	percent	increase	in	our	realized	prices	without	hedges.	Our	gas	sales	were	the most	significantly	impacted	with	a	$572	million	increase	in	sales.	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	$160	million	due	to	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	due	to	lower	NYMEX	West	Texas	Intermediate	index	prices	and	lower NGL	prices	at	the	Mont	Belvieu,	Texas	index.

Prices	2013	vs.	2012	Oil,	gas	and	NGL	sales	increased	$744	million	due	to	an	18	percent	increase	in	our	realized	prices	without	hedges.	Our	gas	sales	were	the most	significantly	impacted	with	a	$639	million	increase	in	sales.	The	change	in	our	gas	price	was	largely	due	to	higher	North	American	regional	index	prices	upon which	our	gas	sales	are	based.	Our	liquid	sales	increased	$105	million	due	to	higher	oil	and	bitumen	sales	partially	offset	by	lower	NGL	sales.	The	largest	contributors	to the	higher	liquids	prices	were	an	increase	in	the	average	NYMEX	West	Texas	Intermediate	index	price	and	a	slightly	higher	bitumen	realized	price,	partially	offset	by 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, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Cash\tsettlements: |  |  |  |
| Oil\tderivatives | $90 | $55 | $259 |
| Gas\tderivatives | (36) | 139 | 610 |
| NGL\tderivatives | 1 | 1 | 1 |
| Total\tcash\tsettlements | 55 | 195 | 870 |
| Gains\t(losses)\ton\tfair\tvalue\tchanges: |  |  |  |
| Oil\tderivatives | \t 1,721 | (243) | 150 |
| Gas\tderivatives | 213 | (139) | (330) |
| NGL\tderivatives | — | (4) | 3 |
| Total\tgains\t(losses)\ton\tfair\tvalue\tchanges | \t 1,934 | (386) | (177) |
| Oil,\tgas\tand\tNGL\tderivatives | $1,989 | $(191) | $693 |

|  |  | 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	to	the	financial	statements	included	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	of	$2.0	billion	in	2014,	incurred	net	losses	of	$191	million in	2013	and	generated	net	gains	of	$693	million	in	2012.

# Marketing	and	Midstream	Revenues	and	Operating	Expenses

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  |  | ($\tin\tmillions) |  |  |
| Operating\trevenues | $7,667 | \t +271% | $2,066 | +25% | $1,655 |
| Product\tpurchases | (6,540) | \t +382% | (1,356) | +31% | (1,039) |
| Operations\tand\tmaintenance\texpenses | (275) | +40% | (197) | -5% | (207) |
| Operating\tprofit | $852 | +66% | $513 | +25% | $409 |
| Devon | $90 | -3% | $93 | +31% | $71 |
| EnLink | 762 | +81% | 420 | +24% | 338 |
| Total\toperating\tprofit | $852 | +66% | $513 | +25% | $409 |

Our	profit	largely	increased	due	to	higher	prices	and	volumes,	partially	offset	by	higher	operations	and	maintenance	expenses.	Of	the	$339	million	increase,	$342 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	due	to	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	have	entered	into	to	secure	capacity	on	downstream	oil	pipelines.	Marketing	activities	of	EnLink	also contributed	to	these	increases.

Our	profit	largely	increased	due	to	the	effects	of	pricing	and	marketing	activities.	Our	profit	increased	nearly	$40	million	due	to	our	NGL	and	gas	marketing. Additionally,	changes	in	pricing	led	to	an	increase	in	operating	profit	of	approximately	$32	million.	Higher	residue	natural	gas	prices	were	the	primary	contributor	to	the higher	profit.

Higher	gathering	and	processing	volumes	were	responsible	for	an	increase	in	operating	profit	of	$21	million.	Higher	volumes	were	primarily	the	result	of	NGL production.	The	increase	was	largely	driven	by	higher	inlet	volumes	at	the	Cana	processing	facility,	improved	efficiencies	at	the	Cana	and	Bridgeport	processing facilities	and	downtime	impacting	our	Bridgeport	processing	facility	in	2012.

Operations	and	maintenance	expenses	decreased	$10	million,	or	5	percent,	primarily	due	to	expenditures	for	regulatory	testing	in	2012.

# Lease	Operating	Expenses	("LOE")

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  | (In\tmillions,\texcept\tper\tBoe\tamounts) | (In\tmillions,\texcept\tper\tBoe\tamounts) |  |  |
| LOE: |  |  |  |  |  |
| U.S. | $1,559 | +24% | $1,257 | +19% | $1,059 |
| Canada | 773 | -24% | \t 1,011 | -0% | \t 1,015 |
| Total | $2,332 | +3% | $2,268 | +9% | $2,074 |
| LOE\tper\tBoe: |  |  |  |  |  |
| U.S. | $7.52 | +13% | $6.65 | +15% | $5.79 |
| Canada | $20.10 | +27% | $15.78 | +4% | $15.18 |
| Total | $9.49 | +6% | $8.97 | +8% | $8.30 |

2014	vs.	2013	Our	absolute	LOE	changed	largely	as	a	result	of	our	portfolio	transformation	initiatives,	including	our	February	2014	purchase	of	GeoSouthern's Eagle	Ford	assets	and	our	2014	divestitures	of	certain	properties	in	the	U.S.	and	Canada.	Higher	volumes	from	development	of	our	Eagle	Ford	assets,	as	well	as	our Permian	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	due	to	higher	unit	costs	related	to	our	Canadian	operations.	The	higher	Canadian	unit	costs	largely	resulted	from	the divestiture	of	the	conventional	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.	As

Canadian	royalties	increase,	our	net	production	volumes	decrease,	causing	upward	pressure	on	our	per-unit	operating	costs.	The	higher	unit	cost	in	the	U.S.	was	primarily related	to	our	liquids	production	growth,	particularly	in	the	Permian	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.

2013	vs.	2012	LOE	increased	$0.67	per	Boe	largely	because	of	our	liquids	production	growth,	particularly	in	the	Permian	Basin	and	the	Mississippian-Woodford Trend	in	the	U.S.	These	projects	generally	require	a	higher	per	unit	cost	than	our	gas	projects,	particularly	because	they	are	in	the	early	stages	of	development. Additionally,	we	conducted	a	turnaround	at	Jackfish	2	in	the	third	quarter	of	2013,	contributing	to	higher	unit	costs	in	2013.	We	also	experienced	inflationary	pressures on	costs	in	certain	operating	areas,	which	increased	LOE	per	Boe.

# General	and	Administrative	Expenses	("G&A")

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  | (In\tmillions,\texcept\tper\tBoe\tamounts) | (In\tmillions,\texcept\tper\tBoe\tamounts) |  |  |
| Gross\tG&amp;A | $1,369 | +21% | $1,128 | -4% | $1,171 |
| Capitalized\tG&amp;A | (376) | +2% | (368) | +3% | (359) |
| Reimbursed\tG&amp;A | (146) | +2% | (143) | +19% | (120) |
| Net\tG&amp;A | $847 | +37% | $617 | -11% | $692 |
| Net\tG&amp;A\tper\tBoe | $3.45 | +41% | $2.44 | -12% | $2.77 |

2014	vs.	2013	Net	G&A	and	net	G&A	per	Boe	increased	largely	due	to	higher	employee	compensation	and	benefits	and	$22	million	in	costs	in	the	first	quarter	of 2014	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.

2013	vs.	2012	Net	G&A	and	net	G&A	per	Boe	decreased	largely	due	to	lower	personnel	expenses	and	office	rent	as	a	result	of	the	Houston	office	consolidation	in 2012	and	lower	costs	as	a	result	of	the	company-wide	implementation	of	SAP	in	2012.	Higher	reimbursements	due	to	increased	liquids	drilling	activity	and reimbursement	rates	also	contributed	to	the	decrease	in	net	G&A	and	net	G&A	per	Boe.	Further	reducing	our	G&A	in	2013	was	the	timing	of	our	share-based	awards,	as noted	above.

# Production	and	Property	Taxes

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  |  | ($\tin\tmillions) |  |  |
| Production | $360 | +31% | $275 | +23% | $224 |
| Property\tand\tother | \t 175 | -6% | \t 186 | -2% | \t 190 |
| Production\tand\tproperty\ttaxes | $535 | +16% | $461 | +11% | $414 |
| Percentage\tof\toil,\tgas\tand\tNGL\tsales: |  |  |  |  |  |
| Production | 3.6% | +13% | 3.2% | +3% | 3.1% |
| Property\tand\tother | 1.8% | -19% | 2.2% | -18% | 2.7% |
| Total | 5.4% | -0% | 5.4% | -6% | 5.8% |

2014	vs.	2013	Production	and	property	taxes	increased	primarily	due	to	an	increase	in	our	U.S.	revenues,	on	which	the	majority	of	our	production	taxes	are assessed.

# Depreciation,	Depletion	and	Amortization	("DD&A")

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  | (In\tmillions,\texcept\tper\tBoe\tamounts) | (In\tmillions,\texcept\tper\tBoe\tamounts) |  |  |
| DD&amp;A: |  |  |  |  |  |
| Oil\t&amp;\tgas\tproperties | $2,896 | +18% | $2,465 | -2% | $2,526 |
| Other\tassets | 423 | +34% | 315 | +11% | 285 |
| Total | $3,319 | +19% | $2,780 | -1% | $2,811 |
| DD&amp;A\tper\tBoe: |  |  |  |  |  |
| Oil\t&amp;\tgas\tproperties | $11.79 | +21% | $9.75 | -4% | $10.12 |
| Other\tassets | 1.72 | +38% | 1.24 | +9% | 1.14 |
| Total | $13.51 | +23% | $10.99 | -2% | $11.26 |

A	description	of	how	DD&A	of	our	oil	and	gas	properties	is	calculated	is	included	in	Note	1	to	the	financial	statements	included	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.

2014	vs.	2013	DD&A	from	our	oil	and	gas	properties	increased	in	2014	largely	due	to	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	asset	divestitures.	Other DD&A	increased	primarily	due	to	the	EnLink	transaction.

2013	vs.	2012	Oil	and	gas	property	DD&A	decreased	$61	million	largely	as	a	result	of	the	asset	impairment	charges	recognized	in	2012	and	2013.	Depreciation and	amortization	on	our	other	properties	increased	$30	million	largely	from	the	construction	of	our	new	headquarters	in	Oklahoma	City	and	natural	gas	pipeline development	in	the	Cana-Woodford	Shale.

# Asset	Impairments

|  | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2013 | Year	Ended	December	31,	2013 | Year	Ended	December	31,	2012 | Year	Ended	December	31,	2012 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes |
|  |  |  | (In\tmillions) | (In\tmillions) |  |  |
| Goodwill | $1,941 | $1,941 | $— | $— | $— | $— |
| U.S.\toil\tand\tgas\tassets | — | — | 1,110 | 707 | 1,793 | 1,142 |
| Canada\toil\tand\tgas\tassets | — | — | 843 | 632 | 163 | 122 |
| Midstream\tassets | 12 | 7 | 23 | 14 | 68 | 44 |
| Asset\timpairments | $1,953 | $1,948 | $1,976 | $1,353 | $2,024 | $1,308 |

For	further	discussion	of	our	goodwill	and	property	and	equipment	impairments,	see	Note	12	and	Note	5,	respectively,	in	"Item	8.	Financial	Statements	and Supplementary	Data."

# Restructuring	Costs

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Canadian\tdivestitures | $46 | $— | $ — |
| Office\tconsolidation | \t — | 54 | 80 |
| Offshore\tdivestiture | \t — | \t — | (6) |
| Restructuring\tcosts | $46 | $54 | $74 |

For	further	discussion	of	our	Canadian	divestitures,	office	consolidation	and	offshore	divestiture	restructuring	activities	and	consolidated	financial	statements impact,	see	Note	6	in	"Item	8.	Financial	Statements	and	Supplementary	Data."

# Gains	on	Asset	Sales

In	conjunction	with	the	divestiture	of	certain	Canadian	properties,	we	recognized	gains	in	the	first	and	second	quarters	of	2014.	Under	full	cost	accounting	rules, sales	or	dispositions	of	oil	and	gas	properties	are	generally	accounted	for	as	adjustments	to	capitalized	costs,	with	no	recognition	of	a	gain	or	loss.	However,	if	not recognizing	a	gain	or	loss	on	the	disposition	would	otherwise	significantly	alter	the	relationship	between	a	cost	center's	capitalized	costs	and	proved	reserves,	then	a	gain or	loss	must	be	recognized.	Our	Canadian	divestitures	significantly	altered	such	relationship.	Therefore,	we	recognized	a	total	gain	of	$1.1	billion	($0.6	billion	after-tax) during	2014.

# Net	Financing	Costs

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | Change | 2013 | Change | 2012 |
|  |  |  | (In\tmillions) |  |  |
| Interest\tbased\ton\tdebt\toutstanding | $546 | +17% | $466 | +6% | $440 |
| Early\tretirement\tof\tdebt | 48 | \t N/M | \t — | \t N/M | \t — |
| Capitalized\tinterest | (70) | +26% | (56) | +15% | (48) |
| Other\tfees\tand\texpenses | 12 | -55% | 27 | +94% | 14 |
| Interest\texpense | \t 536 | +23% | \t 437 | +8% | \t 406 |
| Interest\tincome | (10) | -49% | (20) | -43% | (36) |
| Net\tfinancing\tcosts | $526 | +26% | $417 | +13% | $370 |

2014	vs.	2013	Net	financing	costs	increased	primarily	due	to	higher	average	borrowings	resulting	from	the	EnLink	and	GeoSouthern	transactions.	Additionally, we	incurred	a	$40	million	early	retirement	premium	related	to	the	redemption	of	our	2.4%	$500	million	senior	notes	due	2016,	1.2%	$650	million	senior	notes	due	2016 and	1.875%	$750	million	senior	notes	due	2017	prior	to	their	maturity.	In	conjunction	with	the	early	retirement,	we	also	expensed	$8	million	in	remaining	unamortized discount	and	issuance	costs.

2013	vs.	2012	Net	financing	costs	increased	primarily	due	to	additional	debt	borrowings	and	associated	fees,	partially	offset	by	lower	weighted-average	interest rates	and	higher	capitalized	interest.	Borrowings	were	primarily	used	to	fund	capital	expenditures	in	excess	of	our	operating	cash	flow	and	to	provide	funding	for	our Eagle	Ford	acquisition	which	closed	in	the	first	quarter	of	2014.

# Income	Taxes

The	following	table	presents	our	total	income	tax	expense	(benefit)	and	a	reconciliation	of	our	effective	income	tax	rate	to	the	United	States	statutory	income	tax rate.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
| Total\tincome\ttax\texpense\t(benefit)\t(in\tmillions) | $2,368 | $169 | $(132) |
| U.S.\tstatutory\tincome\ttax\trate | 35% | 35% | (35%) |
| Non-deductible\tgoodwill\ttransactions | 23% | 0% | 0% |
| Taxation\ton\tCanadian\toperations | (4%) | 9% | (6%) |
| State\tincome\ttaxes | 2% | 23% | 6% |
| Repatriations | 2% | 65% | 0% |
| Taxes\ton\tEnLink\tformation | 1% | 0% | 0% |
| Other | (1%) | (19%) | (7%) |
| Effective\tincome\ttax\trate | 58% | \t 113% | (42%) |

For	further	discussion	of	our	income	tax	expense	(benefit),	see	Note	7	in	"Item	8.	Financial	Statements	and	Supplementary	Data."

# Earnings	(Loss)	from	Discontinued	Operations

In	2012,	we	incurred	a	loss	related	to	discontinued	operations	of	$16	million	($21	million	net	of	taxes)	for	the	sale	of	our	assets	in	Angola.	There	were	no operating	revenues	related	to	discontinued	operations	during	2012.	In	2014	and	2013,	there	were	no	earnings	or	losses	associated	with	discontinued	operations.

# 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.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Operating\tcash\tflow\t–\tcontinuing\toperations | $5,981 | $5,436 | $4,930 |
| Divestitures\tof\tproperty\tand\tequipment | 5,120 | 419 | 1,539 |
| Capital\texpenditures | (6,988) | (6,758) | (8,225) |
| Acquisitions\tof\tproperty,\tequipment\tand\tbusinesses | (6,462) | — | — |
| Debt\tactivity,\tnet | (2,234) | 361 | 1,921 |
| Shareholder\tand\tnoncontrolling\tinterests\tdistributions | (621) | (348) | (324) |
| Stock\toption\tproceeds | 93 | 3 | 27 |
| Proceeds\tfrom\tissuance\tof\tsubsidiary\tunits | 410 | — | — |
| Other | 115 | (27) | 54 |
| Net\tchange\tin\tcash\tand\tshort-term\tinvestments | $(4,586) | $(914) | $(78) |
| Cash\tand\tshort-term\tinvestments\tat\tend\tof\tperiod | $1,480 | $6,066 | $6,980 |

# Operating	Cash	Flow	–	Continuing	Operations

Net	cash	provided	by	operating	activities	continued	to	be	a	significant	source	of	capital	and	liquidity	in	2014.	Our	operating	cash	flow	increased	10	percent	during 2014	primarily	due	to	higher	realized	prices	and

liquids	production	growth,	partially	offset	by	higher	expenses.	Our	operating	cash	flow	increased	10	percent	during	2013	primarily	due	to	higher	commodity	prices	and production	growth,	partially	offset	by	higher	expenses.

Excluding	the	$6.5	billion	attributable	to	the	GeoSouthern	and	other	acquisitions,	our	operating	cash	flow	funded	approximately	86	percent	of	our	cash	payments for	capital	expenditures	during	2014.	Leveraging	our	liquidity,	we	used	cash	balances,	short-term	debt	and	divestiture	proceeds	to	fund	the	remainder	of	our	cash-based capital	expenditures.

# 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.

In	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.

During	2012,	we	closed	two	key	joint	venture	transactions.	Under	one	of	these	arrangements,	our	joint	venture	partner	paid	approximately	$900	million	in	cash and	received	a	33.3	percent	interest	in	five	of	our	exploration	plays	in	the	U.S.	Our	joint	venture	partner	is	also	funding	approximately	$1.6	billion	of	our	share	of	future exploration,	development	and	drilling	costs	associated	with	these	plays.	Under	the	second	transaction,	our	joint	venture	partner	paid	approximately	$400	million	and received	a	30	percent	interest	in	the	Cline	and	Midland-Wolfcamp	Shale	plays	in	Texas.	Additionally,	our	joint	venture	partner	is	funding	approximately	$1.0	billion	of our	share	of	future	exploration,	development	and	drilling	costs	associated	with	these	plays.

Also	in	2012,	we	sold	our	West	Johnson	County	Plant	and	gathering	system	in	north	Texas	for	approximately	$90	million	and	divested	our	Angola	operations	for approximately	$71	million.

# Capital	Expenditures

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Development | $5,014 | $4,754 | $5,183 |
| Exploration | 353 | 602 | 541 |
| Acquisition\tof\toil\tand\tgas\tproperties | 6,179 | 256 | \t 1,329 |
| Capitalized\tG&amp;A\tand\tinterest | 368 | 354 | 343 |
| Total\toil\tand\tgas | \t 11,914 | \t 5,966 | \t 7,396 |
| Midstream | 380 | 455 | 167 |
| Corporate\tand\tother | 109 | 93 | 325 |
| Devon\tcapital\texpenditures | \t 12,403 | \t 6,514 | \t 7,888 |
| EnLink,\tincluding\tacquisitions | 1,047 | 244 | 337 |
| Total\tcapital\texpenditures | $13,450 | $6,758 | $8,225 |

Our	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,	which	totaled	$11.9	billion,	$6.0	billion	and	$7.4	billion	in	2014,	2013	and	2012,	respectively.	The

increase	in	capital	spending	was	primarily	due	to	the	GeoSouthern	acquisition.	Excluding	acquisitions,	exploration	and	development	capital	spending	decreased	4 percent,	primarily	due	to	utilization	of	the	drilling	carries	in	2014	from	our	joint	venture	arrangements.	In	2013,	utilization	of	these	drilling	carries	contributed	to	a	20 percent	decline	in	exploration,	development	and	acquisition	capital	spending,	along	with	a	decline	in	new	venture	acreage	acquisitions.	Exploration	and	development capital	spending	in	2012	was	primarily	related	to	new	venture	acreage	acquisitions	and	increased	drilling	and	development.	With	rising	oil	prices	and	proceeds	from	our offshore	divestitures,	we	increased	our	onshore	North	American	acreage	positions	and	associated	exploration	and	development	activities	to	drive	near-term	growth	of	our oil	production.

Capital	expenditures	for	our	midstream	operations	are	primarily	for	the	construction	and	expansion	of	natural	gas	processing	plants,	natural	gas	systems	and	oil pipelines.	Our	midstream	capital	expenditures	are	largely	impacted	by	our	oil	and	gas	drilling	activities.	Our	2014	and	2013	midstream	capital	expenditures	largely related	to	the	expansion	of	our	Access	Pipeline	in	Canada.	Additionally,	our	2014	midstream	capital	expenditures	also	related	to	pipeline	construction	and	expansion	in the	Eagle	Ford.	During	2014,	EnLink's	capital	expenditures	totaled	approximately	$1.0	billion.	The	higher	expenditures	primarily	resulted	from	the	acquisition	of additional	oil	and	gas	pipeline	assets.	EnLink's	2013	and	2012	capital	expenditures	primarily	related	to	expansions	of	plants	serving	the	Barnett	Shale	and	Cana- Woodford	Shale.

Capital	expenditures	related	to	other	activities	decreased	in	2014	and	2013	compared	to	2012.	This	decrease	is	largely	driven	by	the	construction	of	our	new headquarters	in	Oklahoma	City,	which	was	completed	in	2012.

# Debt	Activity,	Net

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.

During	2012,	we	increased	our	debt	borrowings	by	$1.9	billion	as	a	result	of	issuing	$2.5	billion	of	long-term	debt	and	repaying	approximately	$0.6	billion	of outstanding	short-term	debt.	The	additional	borrowings	were	primarily	used	to	fund	capital	expenditures	in	excess	of	our	operating	cash	flow.

# Shareholder	and	Noncontrolling	Interests	Distributions

The	following	table	summarizes	our	common	stock	dividends	(amounts	in	millions).	In	the	second	quarter	of	2014,	we	increased	our	quarterly	dividend	to	$0.24 per	share.

|  | Amount | Per	Share | Amount | Per	Share | Amount | Per	Share |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Dividends | $386 | $0.94 | $348 | $0.86 | $324 | $0.80 |

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

# Stock	Option	Proceeds

# Proceeds	from	Issuance	of	Subsidiary	Units

During	2014,	EnLink	sold	approximately	14.8	million	limited	partner	units	to	the	public,	raising	net	proceeds	of	approximately	$410	million.

# 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	debt	and	equity	securities	that	can	be	issued	pursuant	to	our	shelf	registration	statement	filed	with	the	SEC.	We estimate	the	combination	of	these	sources	of	capital	will	be	adequate	to	fund	future	capital	expenditures,	debt	repayments	and	other	contractual	commitments	as discussed	in	this	section.

# Operating	Cash	Flow	and	Cash	Balances

Our	operating	cash	flow	is	sensitive	to	many	variables,	the	most	volatile	of	which	are	the	prices	of	the	oil,	gas	and	NGLs	we	produce.	Due	to	higher	realized	prices and	increased	liquids	production	growth	during	2014,	our	operating	cash	flow	from	continuing	operations	increased	10	percent	to	$6.0	billion	in	2014.	We	expect operating	cash	flow	to	continue	to	be	our	primary	source	of	liquidity.

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.	In	the fourth	quarter	of	2014,	oil	and	NGL	prices	decreased	significantly.	We	expect	this	volatility	to	continue	throughout	2015	and	expect	2015	oil,	gas	and	NGL	prices	will be	noticeably	lower	than	those	for	2014.	The	corresponding	reduction	in	our	operating	cash	flow	will	require	us	to	scale	back	certain	uses	of	cash	during	2015	compared to	2014,	including	most	notably	our	capital	expenditures.

To	mitigate	some	of	the	risk	inherent	in	prices,	we	have	utilized	various	derivative	financial	instruments	to	set	minimum	prices	on	our	future	production.	The	key terms	to	our	oil,	gas	and	NGL	derivative	financial	instruments	as	of	December	31,	2014	are	presented	in	Note	3	to	the	financial	statements	under	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.	Additional	discussion	on	the	extent	of	our	hedged	production	is	included	in	the	"Business	and	Industry	Outlook" section	above.

Commodity	prices	can	also	affect	our	operating	cash	flow	through	an	indirect	effect	on	operating	expenses.	Significant	commodity	price	increases	can	lead	to	an increase	in	drilling	and	development	activities.	As	a	result,	the	demand	and	cost	for	people,	services,	equipment	and	materials	may	also	increase,	causing	a	negative impact	on	our	cash	flow.	However,	the	inverse	is	also	generally	true	during	periods	of	depressed	commodity	prices	or	reduced	activity.

Interest	Rates	–	Our	operating	cash	flow	can	also	be	impacted	by	interest	rate	fluctuations.	As	of	December	31,	2014,	we	had	total	debt	of	$11.3	billion	with	an overall	weighted-average	borrowing	rate	of	4.6	percent.	Of	the	$11.3	billion	of	total	debt,	$2.0	billion	is	comprised	of	floating	rate	debt	that	bear	interest	rates	averaging 0.74	percent.

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	percent	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.

At	the	end	of	2014,	we	held	approximately	$1.5	billion	of	cash.	Included	in	this	total	was	$1.2	billion	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	syndicated,	unsecured	revolving	line	of	credit	(the	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,	2014,	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	percent.	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,	2014,	we	were	in	compliance	with	this	covenant.	Our	debt-to- capitalization	ratio	at	December	31,	2014,	as	calculated	pursuant	to	the	terms	of	the	agreement,	was	20.9	percent.

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.

We	also	have	access	to	$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,	2014,	we	had	$932 million	of	borrowings	under	our	commercial	paper	program.

EnLink	has	a	$1.0	billion	unsecured	revolving	credit	facility.	On	February	5,	2015,	the	commitments	under	EnLink's	credit	facility	were	increased	to	$1.5	billion. The	General	Partner	also	has	a	$250	million	revolving	credit	facility.	As	of	December	31,	2014,	there	were	$14	million	in	outstanding	letters	of	credit	and	$237	million borrowed	under	the	$1.0	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.

# Debt	Ratings

We	and	EnLink	receive	debt	ratings	from	the	major	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	debt	contractual	obligations	that	would	accelerate	scheduled	maturities	should	debt	ratings	fall	below	a specified	level.	Our	cost	of	borrowing	under	our	Senior	Credit	Facility	is	predicated	on	our	corporate	debt	rating.	Therefore,	even	though	a	ratings	downgrade	would	not accelerate	scheduled	maturities,	it	could	adversely	impact	the	interest	rate	on	any	borrowings	under	our	Senior	Credit	Facility.	Under	the	terms	of	the	Senior	Credit Facility,	a	one-notch	downgrade	from	our	current	debt	ratings	would	increase	the	drawn	borrowing	costs	by	12.5	basis	points.	Similarly,	a	ratings	downgrade	would	not accelerate	EnLink's	scheduled	maturities,	however,	it	could	adversely	impact	the	interest	rate	on	any	borrowings	under	EnLink's	credit	facility.	Under	the	terms	of EnLink's	credit	facility,	a	one	notch	downgrade	would	increase	the	drawn	borrowing	costs	by	25	basis	points.	A	ratings	downgrade	could	also	adversely	impact	our	and EnLink's	ability	to	economically	access	debt	markets	in	the	future.

Excluding	EnLink,	our	2015	capital	expenditures	are	expected	to	range	from	$4.7	billion	to	$5.2	billion,	including	$4.5	billion	to	$4.9	billion	for	our	oil	and	gas operations,	which	include	capitalized	G&A	and	interest.	This	estimate	is	approximately	20%	lower	than	our	2014	capital	expenditures.	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	2015	capital	expenditures	until	later	periods	or	accelerate	capital	expenditures	planned	for	periods	beyond	2015	to	achieve	the	desired	balance	between sources	and	uses	of	liquidity.	Based	upon	current	price	expectations	for	2015,	our	existing	commodity	hedging	contracts,	available	cash	balances	and	credit	availability, we	anticipate	having	adequate	capital	resources	to	fund	our	2015	capital	expenditures.

Additionally,	our	financial	and	operational	flexibility	has	been	further	enhanced	by	the	joint	venture	transactions	that	we	entered	into	in	2012.	Pursuant	to	the joint	venture	agreements,	our	joint	venture	partners	are	subject	to	drilling	carries	with	remaining	commitments	that	totaled	approximately	$250	million	at	the	end	of 2014.	These	drilling	carries	will	fund	70	percent	of	our	capital	requirements	related	to	joint	venture	properties,	which	results	in	our	partners	paying	approximately	80 percent	of	the	overall	development	costs	during	the	carry	period.	This	has	allowed	us	to	accelerate	the	de-risking	and	commercialization	of	the	joint	venture	properties without	diverting	capital	from	our	core	development	projects.	We	expect	a	significant	portion	of	the	carries	will	be	utilized	by	the	end	of	2015.

# EnLink	Capital	Resources	and	Expenditures

On	January	31,	2015,	EnLink	acquired	LPC	Crude	Oil	Marketing	LLC,	which	has	crude	oil	gathering,	transportation	and	marketing	operations	in	the	Permian Basin	for	approximately	$100	million	in	cash,	subject	to	certain	adjustments.

On	February	1,	2015,	EnLink	signed	a	definitive	agreement	to	acquire	Coronado	Midstream	Holdings	LLC,	which	owns	natural	gas	gathering	and	processing facilities	in	the	Permian	Basin	for	approximately	$600	million	in	cash	and	equity,	subject	to	certain	adjustments.

Beyond	these	acquisitions,	EnLink's	2015	capital	budget	includes	approximately	$350	million	to	$400	million	of	identified	growth	projects,	including	capitalized interest.	EnLink's	primary	capital	projects	for	2015

include	the	construction	of	its	ORV	condensate	pipeline,	Bearkat	plant	facilities	and	West	Texas	expansion	project.	During	2014,	EnLink	invested	in	several	capital projects	which	primarily	included	the	expansion	of	the	Cajun-Sibon	NGL	Pipeline	and	the	construction	of	the	Bearkat	facilities.

EnLink	expects	to	fund	its	2015	maintenance	capital	expenditures	from	operating	cash	flows.	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.	In	2015,	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

A	summary	of	our	contractual	obligations	as	of	December	31,	2014	is	provided	in	the	following	table.

|  |  | Less	Than |  |  | More	Than	5 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Total | 1\tYear | \t\t1-3\tYears | \t\t3-5\tYears | Years |
|  |  |  | (In\tmillions) |  |  |
| Debt\t^(1) | $11,257 | $1,432 | $350 | $2,212 | $7,263 |
| Interest\texpense\t^(2) | 8,185 | 505 | 1,003 | 945 | 5,732 |
| Purchase\tobligations\t^(3) | 5,306 | 663 | 1,694 | 1,815 | 1,134 |
| Operational\tagreements\t^(4) | 5,084 | 943 | 1,809 | 1,190 | 1,142 |
| Asset\tretirement\tobligations\t^(5) | 1,399 | 60 | 107 | 94 | 1,138 |
| Drilling\tand\tfacility\tobligations\t^(6) | 446 | 234 | 193 | 14 | 5 |
| Lease\tobligations\t^(7) | 405 | 72 | 100 | 84 | 149 |
| Other\t^(8) | 362 | 128 | 103 | 127 | 4 |
| Total | $32,444 | $4,037 | $5,359 | $6,481 | $16,567 |

(1) Debt	amounts	represent	scheduled	maturities	of	our	debt	obligations	at	December	31,	2014,	excluding	$5	million	of	net	premiums	included	in	the	carrying	value of	debt.

(2) Interest	expense	represents	the	scheduled	cash	payments	on	long-term,	fixed-rate	debt	and	an	estimate	of	our	floating-rate	notes.

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

(4) Operational	agreements	represent	commitments	to	transport	or	process	certain	volumes	of	oil,	gas	and	NGLs	for	a	fixed	fee.	We	have	entered	into	these agreements	to	aid	the	movement	of	our	production	to	downstream	markets.	Operational	agreements	include	approximately	$2.1	billion	of	minimum	volume commitments	between	Devon	and	EnLink.	The	initial	terms	of	the	contracts	with	EnLink	are	summarized	in	the	following	table.	All	contracts	began	in	March 2014.

|  | Contract<br>Terms | Minimum<br>Gathering<br>Volume<br>Commitment | Minimum<br>Processing<br>Volume<br>Commitment | Minimum<br>Volume<br>Commitment<br>Term | Annual<br>Rate |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Contract | (Years) | (MMcf/d) | (MMcf/d) | (Years) | Escalators |
| 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 |

(5) Asset	retirement	obligations	represent	estimated	discounted	costs	for	future	dismantlement,	abandonment	and	rehabilitation	costs.	These	obligations	are	recorded as	liabilities	on	our	December	31,	2014	balance	sheet.

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

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

(8) These	amounts	include	$243	million	related	to	uncertain	tax	positions.

# Contingencies	and	Legal	Matters

For	a	detailed	discussion	of	contingencies	and	legal	matters,	see	Note	18	to	the	financial	statements	included	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	United	States	of	America	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	outside	petroleum	consultants.	In	2014,	91	percent	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	three	percent	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	percent 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	percent	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,	due	to	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.

Although	uncertain	future	prices	impact	the	ability	to	predict	future	full	cost	write-downs,	we	do	expect	to	recognize	full	cost	write-downs	in	2015,	beginning	with the	first	quarter	of	2015.	This	conclusion	is	based	on	the	historic	prices	for	the	last	9	months	of	2014	and	the	short-term	pricing	outlook.	Although	we	can	predict	with relative	certainty	we	will	recognize	full	cost	write-downs	in	2015,	we	are	not	able	to	reasonably	estimate	the	amounts.	However,	we	expect	the	amounts	will	be	material to	our	net	earnings	but	will	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	West	Texas	Intermediate	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	United	States	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.	Under	the	terms	of	our	interest	rate	swaps,	we	generally	receive	a fixed	rate	and	pay	a	variable	rate	on	a	total	notional	amount.

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	as	well	as	changes	in	forward	interest	rate	yields.

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	fourteen	separate	counterparties,	and	our	foreign	exchange	forward	contracts	are	held	with	five	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.	The	mark-to-market	exposure	threshold	for collateral	posting	decreases	as	the	debt	rating	falls	further	below	such	credit	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,	2014	impairment	test,	step	one	of	our	impairment	analysis	showed	that	the	fair	value	of	our	U.S.	and	EnLink	reporting	units	exceeded	their carrying	value.	However,	the	fair	value	of	the	EnLink	Louisiana	reporting	unit	did	not	substantially	exceed	its	carrying	value.	As	of	October	31,	2014,	the	fair	value	of the	EnLink	Louisiana	reporting	unit	exceeded	its	carrying	value	by	approximately	14	percent.	Furthermore,	the	fair	value	of	our	Canadian	reporting	unit	did	not	exceed its	carrying	value.

As	disclosed	in	previous	years,	the	fair	value	of	our	Canadian	unit	did	not	significantly	exceed	its	carrying	value.	Consequently,	we	performed	the	requisite qualitative	analysis	of	our	Canadian	goodwill	each	quarter	throughout	2014.	We	also	performed	quantitative	analysis	following	the	significant	Canadian	asset divestitures	we	completed	in	the	second	quarter	of	2014.	None	of	this	analysis	indicated	the	existence	of	a	Canadian	goodwill	impairment	through	September	30,	2014. Therefore,	with	the	failure	of	step	one	as	a	result	of	our	October	31	test,	we	concluded	the	impairment	was	the	result	of	the	decline	in	oil	prices	that	began	in	the	third quarter	of	2014	and	intensified	after	OPEC's	decision	not	to	reduce	its	production	targets	that	was	announced	in	late	November	2014.

Because	the	oil	price	decline	continued	into	early	2015,	we	decided	to	perform	a	revised	step	one	and	then	step	two	of	the	impairment	test	as	of	December	31, 2014	to	measure	the	amount	of	the	Canadian	impairment.	As	a	result	of	this	evaluation,	we	concluded	the	implied	fair	value	of	our	Canadian	goodwill	was	zero	as	of December	31,	2014.	Consequently,	in	the	fourth	quarter	of	2014,	we	wrote	off	our	remaining	Canadian	goodwill	and	recognized	a	$1.9	billion	impairment.

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.

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	United	States	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,	United	States/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	impracticable	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	2014	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	while	comparing	on	an	annual	basis.	In	the	below	table,	restructuring	costs	were	incurred	in	each	of	the	three	year	periods;	however,	these	costs	relate	to different	restructuring	programs.	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,	repatriation	of	proceeds	to	the	U.S.,	restructuring	costs,	loss	on	early	retirement	of debt	and	deferred	income	tax	on	the	formation	of	EnLink.	Amounts	excluded	for	2013	relate	to	our	office	consolidation	and	asset	impairments.	Amounts	excluded	in 2012	relate	to	our	office	consolidation,	offshore	exit	and	asset	impairments.	For	more	information	on	our	restructuring	programs,	see	Note	6	to	the	financial	statements included	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.	The	reconciliations	exclude	amounts	related	to	our discontinued	operations.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2014 | \t\t\t\t2013 | \t\t\t\t2012 |
|  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Net\tearnings\t(loss)\tattributable\tto\tDevon\t(GAAP) | $1,607 | $(20) | $(185) |
| Adjustments\t(net\tof\ttaxes): |  |  |  |
| Derivatives\tand\tother\tfinancial\tinstruments | (1,262) | 131 | (425) |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 31 | 139 | 558 |
| Noncash\teffect\tof\tderivatives\tand\tfinancial\tinstruments | (1,231) | 270 | 133 |
| Asset\timpairments | 1,948 | 1,353 | 1,308 |
| Gain\ton\tasset\tsales\tand\trelated\trepatriation | (421) | 97 | — |
| Investment\tin\tEnLink\tdeferred\tincome\ttax | 48 | — | — |
| Restructuring\tcosts | 35 | 34 | 49 |
| Early\tretirement\tof\tdebt | 31 | — | — |
| Core\tearnings\tattributable\tto\tDevon\t(Non-GAAP) | $2,017 | $1,734 | $1,305 |
| Earnings\t(loss)\tper\tshare\t(GAAP) | $3.91 | $(0.06) | $(0.47) |
| Adjustments\t(net\tof\ttaxes): |  |  |  |
| Derivatives\tand\tother\tfinancial\tinstruments | (3.07) | 0.31 | (1.04) |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 0.08 | 0.34 | 1.37 |
| Noncash\teffect\tof\tderivatives\tand\tfinancial\tinstruments | (2.99) | 0.65 | 0.33 |
| Asset\timpairments | 4.74 | 3.35 | 3.23 |
| Gain\ton\tasset\tsales\tand\trelated\trepatriation | (1.02) | 0.24 | — |
| Investment\tin\tEnLink\tdeferred\tincome\ttax | 0.12 | — | — |
| Restructuring\tcosts | 0.08 | 0.08 | 0.13 |
| Early\tretirement\tof\tdebt | 0.07 | — | — |
| Core\tearnings\tper\tshare\t(Non-GAAP) | $4.91 | $4.26 | $3.22 |

# 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	enter	into	financial	hedging	activities	with	respect	to	a	portion	of	our	production through	various	financial	transactions	that	hedge	future	prices	received.	The	key	terms	to	all	our	oil	and	gas	derivative	financial	instruments	as	of	December	31,	2014	are presented	in	Note	3	to	the	financial	statements	under	"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,	2014,	a	10 percent	increase	or	a	10	percent	decrease	in	the	forward	curves	associated	with	our	commodity	derivative	instruments	would	have	changed	our	net	asset	positions	by	the following	amounts:

|  | 10%	Increase |  | 10%	Decrease |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Gain\t(loss): |  |  |  |
| Gas\tderivatives | $(74) |  | $69 |
| Oil\tderivatives | $(282) |  | $279 |
| Processing\tand\tfractionation\tderivatives | $(2) |  | $2 |

# Interest	Rate	Risk

At	December	31,	2014,	we	had	total	debt	of	$11.3	billion.	Of	this	amount,	$9.3	billion	bears	fixed	interest	rates	averaging	5.4	percent.	Of	the	$11.3	billion	of	total debt,	$2.0	billion	is	comprised	of	floating	rate	debt	that	bear	interest	rates	averaging	0.74	percent.	Our	commercial	paper	borrowings	typically	have	maturities	between	1 and	90	days.

As	of	December	31,	2014,	we	had	open	interest	rate	swap	positions	that	are	presented	in	"Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	3"	in	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	percent	change	in	these forward	curves	would	not	have	materially	impacted	our	balance	sheet	at	December	31,	2014.

# 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	percent	unfavorable	change	in	the	Canadian- to-U.S.	dollar	exchange	rate	would	not	materially	impact	our	December	31,	2014	balance	sheet.

Our	non-Canadian	foreign	subsidiaries	have	a	U.S.	dollar	functional	currency.	However,	one	of	these	foreign	subsidiaries	holds	Canadian-dollar	cash	and	engages 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,	2014,	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,	2014,	a	10	percent	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 | 53 |
| :--- | :--- |
| Consolidated\tFinancial\tStatements |  |
| Consolidated\tComprehensive\tStatements\tof\tEarnings | \t54 |
| Consolidated\tStatements\tof\tCash\tFlows | \t55 |
| Consolidated\tBalance\tSheets | \t56 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | \t57 |
| Notes\tto\tConsolidated\tFinancial\tStatements | \t58 |

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,	2014	and	2013,	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,	2014. We	also	have	audited	Devon	Energy	Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2014,	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,	2014	and	2013,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	years	in	the	three-year	period	ended	December	31, 2014,	in	conformity	with	United	States	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,	2014,	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\t2014 | \t\t\t\t2013 | \t\t\t\t2012 |
|  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Oil,\tgas\tand\tNGL\tsales | $9,910 | $8,522 | $7,153 |
| Oil,\tgas\tand\tNGL\tderivatives | 1,989 | (191) | 693 |
| Marketing\tand\tmidstream\trevenues | 7,667 | 2,066 | 1,655 |
| Total\toperating\trevenues | 19,566 | 10,397 | 9,501 |
| Lease\toperating\texpenses | 2,332 | 2,268 | 2,074 |
| Marketing\tand\tmidstream\toperating\texpenses | 6,815 | 1,553 | 1,246 |
| General\tand\tadministrative\texpenses | 847 | 617 | 692 |
| Production\tand\tproperty\ttaxes | 535 | 461 | 414 |
| Depreciation,\tdepletion\tand\tamortization | 3,319 | 2,780 | 2,811 |
| Asset\timpairments | 1,953 | 1,976 | 2,024 |
| Restructuring\tcosts | 46 | 54 | 74 |
| Gains\tand\tlosses\ton\tasset\tsales | (1,072) | 9 | (13) |
| Other\toperating\titems | 93 | 112 | 105 |
| Total\toperating\texpenses | 14,868 | 9,830 | 9,427 |
| Operating\tincome | 4,698 | 567 | 74 |
| Net\tfinancing\tcosts | 526 | 417 | 370 |
| Other\tnonoperating\titems | 113 | 1 | 21 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 4,059 | 149 | (317) |
| Income\ttax\texpense\t(benefit) | 2,368 | 169 | (132) |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | 1,691 | (20) | (185) |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations,\tnet\tof\ttax | — | — | (21) |
| Net\tearnings\t(loss) | 1,691 | (20) | (206) |
| Net\tearnings\tattributable\tto\tnoncontrolling\tinterests | 84 | — | — |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $1,607 | $(20) | $(206) |
| Net\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon: |  |  |  |
| Basic\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $3.93 | $(0.06) | $(0.47) |
| Basic\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | — | — | (0.05) |
| Basic\tnet\tearnings\t(loss)\tper\tshare: | $3.93 | $(0.06) | $(0.52) |
| Diluted\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $3.91 | $(0.06) | $(0.47) |
| Diluted\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | — | — | (0.05) |
| Diluted\tnet\tearnings\t(loss)\tper\tshare | $3.91 | $(0.06) | $(0.52) |
| Comprehensive\tearnings\t(loss): |  |  |  |
| Net\tearnings\t(loss) | $1,691 | $(20) | $(206) |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax: |  |  |  |
| Foreign\tcurrency\ttranslation | (465) | (548) | 194 |
| Pension\tand\tpostretirement\tplans | (24) | 45 | 2 |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax | (489) | (503) | 196 |
| Comprehensive\tearnings\t(loss) |  |  |  |
|  | 1,202 | (523) | (10) |
| Comprehensive\tearnings\tattributable\tto\tnoncontrolling\tinterests | 84 | — | — |
| Comprehensive\tearnings\t(loss)\tattributable\tto\tDevon | $1,118 | $(523) | $(10) |

See	accompanying	notes	to	consolidated	financial	statements.

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Cash\tflows\tfrom\toperating\tactivities: |  |  |  |
| Net\tearnings\t(loss) | $1,691 | $(20) | $(206) |
| Loss\tfrom\tdiscontinued\toperations,\tnet\tof\ttax | — | — | 21 |
| Adjustments\tto\treconcile\tearnings\t(loss)\tfrom\tcontinuing\toperations\tto\tnet\tcash\tfrom\toperating\tactivities: |  |  |  |
| Depreciation,\tdepletion\tand\tamortization | 3,319 | 2,780 | 2,811 |
| Asset\timpairments | 1,953 | 1,976 | 2,024 |
| Gains\tand\tlosses\ton\tasset\tsales | (1,072) | 9 | (13) |
| Deferred\tincome\ttax\texpense\t(benefit) | 1,891 | 97 | (184) |
| Derivatives\tand\tother\tfinancial\tinstruments | (2,070) | 135 | (660) |
| Cash\tsettlements\ton\tderivatives\tand\tfinancial\tinstruments | 104 | 277 | 865 |
| Other\tnoncash\tcharges | 457 | 309 | 253 |
| Net\tchange\tin\tworking\tcapital | 50 | (298) | (50) |
| Change\tin\tlong-term\tother\tassets | (421) | 10 | (36) |
| Change\tin\tlong-term\tother\tliabilities | 79 | 161 | 105 |
| Cash\tfrom\toperating\tactivities\t–\tcontinuing\toperations | 5,981 | 5,436 | 4,930 |
| Cash\tfrom\toperating\tactivities\t–\tdiscontinued\toperations | — | — | 26 |
| Net\tcash\tfrom\toperating\tactivities | 5,981 | 5,436 | 4,956 |
| Cash\tflows\tfrom\tinvesting\tactivities: |  |  |  |
| Capital\texpenditures | (6,988) | (6,758) | (8,225) |
| Acquisitions\tof\tproperty,\tequipment\tand\tbusinesses | (6,462) | — | — |
| Proceeds\tfrom\tproperty\tand\tequipment\tdivestitures | 5,120 | 419 | 1,468 |
| Purchases\tof\tshort-term\tinvestments | — | (1,076) | (4,106) |
| Redemptions\tof\tshort-term\tinvestments | — | 3,419 | 3,266 |
| Redemptions\tof\tlong-term\tinvestments | 57 | — | — |
| Other | 89 | (3) | 14 |
| Cash\tfrom\tinvesting\tactivities\t–\tcontinuing\toperations |  |  |  |
|  | (8,184) | (3,999) | (7,583) |
| Cash\tfrom\tinvesting\tactivities\t–\tdiscontinued\toperations | — | — | 57 |
| Net\tcash\tfrom\tinvesting\tactivities | (8,184) | (3,999) | (7,526) |
| Cash\tflows\tfrom\tfinancing\tactivities: |  |  |  |
| Proceeds\tfrom\tborrowings\tof\tlong-term\tdebt,\tnet\tof\tissuance\tcosts | 5,340 | 2,233 | 3,208 |
| Net\tshort-term\tdebt\trepayments | (385) | (1,872) | (537) |
| Long-term\tdebt\trepayments | (7,189) | — | (750) |
| Proceeds\tfrom\tstock\toption\texercises | 93 | 3 | 27 |
| Proceeds\tfrom\tissuance\tof\tsubsidiary\tunits | 410 | — | — |
| Dividends\tpaid\ton\tcommon\tstock | (386) | (348) | (324) |
| Distributions\tto\tnoncontrolling\tinterests | (235) | — | — |
| Other | (2) | 4 | 5 |
| Net\tcash\tfrom\tfinancing\tactivities | (2,354) | 20 | 1,629 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (29) | (28) | 23 |
| Net\tchange\tin\tcash\tand\tcash\tequivalents | (4,586) | 1,429 | (918) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 6,066 | 4,637 | 5,555 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $1,480 | $6,066 | $4,637 |

# CONSOLIDATED	BALANCE	SHEETS

December	31,

| Cash	and	cash	equivalents | $1,480 | $6,066 |
| :--- | :--- | :--- |
| Accounts\treceivable | 1,959 | 1,520 |
| Derivatives,\tat\tfair\tvalue | 1,993 | 75 |
| Income\ttaxes\treceivable | 522 | 89 |
| Other\tcurrent\tassets | 544 | 255 |
| Total\tcurrent\tassets | 6,498 | 8,005 |
| Property\tand\tequipment,\tat\tcost: |  |  |
| Oil\tand\tgas,\tbased\ton\tfull\tcost\taccounting: |  |  |
| Subject\tto\tamortization | 75,738 | 73,995 |
| Not\tsubject\tto\tamortization | 2,752 | 2,791 |
| Total\toil\tand\tgas | 78,490 | 76,786 |
| Midstream\tand\tother | 9,695 | 6,195 |
| Total\tproperty\tand\tequipment,\tat\tcost | 88,185 | 82,981 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | (51,889) | (54,534) |
| Property\tand\tequipment,\tnet | 36,296 | 28,447 |
| Goodwill | 6,303 | 5,858 |
| Other\tlong-term\tassets | 1,540 | 567 |
| Total\tassets | $50,637 | $42,877 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $1,400 | $1,229 |
| Revenues\tand\troyalties\tpayable | 1,193 | 786 |
| Short-term\tdebt | 1,432 | 4,066 |
| Deferred\tincome\ttaxes | 730 | 19 |
| Other\tcurrent\tliabilities | 1,180 | 555 |
| Total\tcurrent\tliabilities | 5,935 | 6,655 |
| Long-term\tdebt | 9,830 | 7,956 |
| Asset\tretirement\tobligations | 1,339 | 2,140 |
| Other\tlong-term\tliabilities | 948 | 834 |
| Deferred\tincome\ttaxes | 6,244 | 4,793 |
| Stockholders'\tequity: |  |  |
| respectively | 41 | 41 |
| Additional\tpaid-in\tcapital | 4,088 | 3,780 |
| Retained\tearnings | 16,631 | 15,410 |
| Accumulated\tother\tcomprehensive\tearnings | 779 | 1,268 |
| Total\tstockholders'\tequity\tattributable\tto\tDevon | 21,539 | 20,499 |
| Noncontrolling\tinterests | 4,802 | — |
| Total\tstockholders'\tequity | 26,341 | 20,499 |
| Commitments\tand\tcontingencies\t(Note\t18)\nTotal\tliabilities\tand\tstockholders'\tequity | $50,637 | $42,877 |

# CONSOLIDATED	STATEMENTS	OF	STOCKHOLDERS'	EQUITY

|  |  |  |  |  | Accumulated |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Common\tStock\nShares | Amount | Additional\nPaid-In\nCapital | Retained\nEarnings | Other\nComprehensive\nEarnings | Treasury\nStock | Noncontrolling\nInterests | Total\nStockholders'\nEquity |
|  |  |  |  |  | (In\tmillions) |  |  |  |
| Balance\tas\tof\tDecember\t31,\t2011 | 404 | $40 | $3,507 | $16,308 | $1,575 | $— | $— | $21,430 |
| Net\tloss | \t — | — | — | (206) | — | — | — | (206) |
| Other\tcomprehensive\tearnings,\tnet\tof\ttax | \t — | — | — | — | 196 | — | — | 196 |
| Stock\toption\texercises | 1 | 1 | 49 | — | — | (23) | — | 27 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 1 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | \t — | — | — | — | — | (29) | — | (29) |
| Common\tstock\tretired | \t — | — | (52) | — | — | 52 | — | — |
| Common\tstock\tdividends | \t — | — | — | (324) | — | — | — | (324) |
| Share-based\tcompensation | \t — | — | 179 | — | — | — | — | 179 |
| Share-based\tcompensation\ttax\tbenefits | \t — | — | 5 | — | — | — | — | 5 |
| Balance\tas\tof\tDecember\t31,\t2012 | 406 | 41 | 3,688 | \t 15,778 | 1,771 | — | — | 21,278 |
| Net\tloss | \t — | — | — | (20) | — | — | — | (20) |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | \t — | — | — | — | (503) | — | — | (503) |
| Stock\toption\texercises | \t — | — | 3 | — | — | — | — | 3 |
| Common\tstock\trepurchased | \t — | — | — | — | — | (36) | — | (36) |
| Common\tstock\tretired | \t — | — | (36) | — | — | 36 | — | — |
| Common\tstock\tdividends | \t — | — | — | (348) | — | — | — | (348) |
| Share-based\tcompensation | \t — | — | 121 | — | — | — | — | 121 |
| Share-based\tcompensation\ttax\tbenefits | \t — | — | 4 | — | — | — | — | 4 |
| Balance\tas\tof\tDecember\t31,\t2013 | 406 | 41 | 3,780 | \t 15,410 | 1,268 | — | — | 20,499 |
| Net\tearnings | \t — | — | — | 1,607 | — | — | 84 | 1,691 |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | \t — | — | — | — | (489) | — | — | (489) |
| Stock\toption\texercises | 1 | — | 93 | — | — | — | — | 93 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 2 | — | — | — | — | — | — | — |
| Common\tstock\trepurchased | \t — | — | — | — | — | (27) | — | (27) |
| Common\tstock\tretired | \t — | — | (27) | — | — | 27 | — | — |
| Common\tstock\tdividends | \t — | — | — | (386) | — | — | — | (386) |
| Share-based\tcompensation | \t — | — | 151 | — | — | — | — | 151 |
| Share-based\tcompensation\ttax\tbenefits | \t — | — | (3) | — | — | — | — | (3) |
| Acquisition\tof\tnoncontrolling\tinterests | \t — | — | — | — | — | — | 4,670 | 4,670 |
| Subsidiary\tequity\ttransactions | \t — | — | 93 | — | — | — | 277 | 370 |
| Distributions\tto\tnoncontrolling\tinterests | \t — | — | — | — | — | — | (235) | (235) |
| Other | \t — | — | 1 | — | — | — | 6 | 7 |
| Balance\tas\tof\tDecember\t31,\t2014 | 409 | $41 | $4,088 | $16,631 | $779 | $— | $4,802 | $26,341 |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# 1. Summary	of	Significant	Accounting	Policies

Devon	Energy	Corporation	("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	Midstream	Partners,	LP,	a	publicly	traded	MLP.

Accounting	policies	used	by	Devon	and	its	subsidiaries	conform	to	accounting	principles	generally	accepted	in	the	United	States	of	America	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,	on	March	7,	2014,	Devon	completed	a	business	combination	whereby	Devon	controls	both	EnLink	Midstream	Partners,	LP ("EnLink")	and	its	general	partner	entity,	EnLink	Midstream,	LLC	(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	and	midstream	assets;

•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;

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	–	(Continued)

•obligations	related	to	employee	pension	and	postretirement	benefits;	and

•legal	and	environmental	risks	and	exposures.

# Revenue	Recognition	and	Gas	Balancing

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	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.

Devon	follows	the	sales	method	of	accounting	for	gas	production	imbalances.	The	volumes	of	gas	sold	may	differ	from	the	volumes	to	which	Devon	is	entitled based	on	its	interests	in	the	properties.	These	differences	create	imbalances	that	are	recognized	as	a	liability	only	when	the	estimated	remaining	reserves	will	not	be sufficient	to	enable	the	underproduced	owner	to	recoup	its	entitled	share	through	production.	The	liability	is	measured	based	on	current	market	prices.	No	receivables are	recorded	for	those	wells	where	Devon	has	taken	less	than	its	share	of	production	unless	all	revenue	recognition	criteria	are	met.	If	an	imbalance	exists	at	the	time	the wells'	reserves	are	depleted,	settlements	are	made	among	the	joint	interest	owners	under	a	variety	of	arrangements.

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	2014,	2013	and	2012,	no	purchaser	accounted	for	more	than	10	percent	of	Devon's	operating	revenues	from	continuing	operations.

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,	through	EnLink,	periodically	enters	into	derivative	financial	instruments	with	respect	to	a	portion	of	EnLink's	oil,	gas	and	NGL	marketing activities.	These	instruments	are	used	to	manage	the	inherent	uncertainty	of	future	revenues	due	to	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.	Devon	periodically	enters	into	foreign	exchange	forward contracts	to	manage	its	exposure	to	fluctuations	in	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,	2014,	Devon	chose	not	to	meet	the	necessary	criteria	to	qualify	its	derivative	financial	instruments	for	hedge	accounting	treatment.	Cash settlements	with	counterparties	on	Devon's	derivative	financial	instruments	are	also	recorded	in	earnings.

By	using	derivative	financial	instruments	to	hedge	exposures	to	changes	in	commodity	prices,	interest	rates	and	foreign	currency	rates,	Devon	is	exposed	to	credit risk.	Credit	risk	is	the	failure	of	the	counterparty	to	perform	under	the	terms	of	the	derivative	contract.	To	mitigate	this	risk,	the	hedging	instruments	are	placed	with	a number	of	counterparties	whom	Devon	believes	are	acceptable	credit	risks.	It	is	Devon's	policy	to	enter	into	derivative	contracts	only	with	investment-grade	rated counterparties	deemed	by	management	to	be	competent	and	competitive	market	makers.	Additionally,	Devon's	derivative	contracts	generally	require	cash	collateral	to be	posted	if	either	its	or	the	counterparty's	credit	rating	falls	below	certain	credit	rating	levels.	The	mark-to-market	exposure	threshold,	above	which	collateral	must	be posted,	decreases	as	the	debt	rating	falls	further	below	such	credit	levels.	As	of	December	31,	2014,	Devon	held	$524	million	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	sheet.

# General	and	Administrative	Expenses

General	and	administrative	expenses	are	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	its	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	general	and	administrative	expenses	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	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	carryforwards	is	determined	to	be	unlikely,	a valuation	allowance	is	provided	to	reduce	the	recorded	tax	benefits	from	such	assets.	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.

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.	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.

# Investments

Devon	periodically	invests	excess	cash	in	United	States	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,	except	for	debt	securities	in	which	management	has	the	ability	and	intent	to	hold	until maturity.	At	December	31,	2013,	such	debt	securities	totaled	$62	million	and	are	included	in	other	long-term	assets	in	the	accompanying	consolidated	balance	sheet. Devon	redeemed	all	these	securities	in	the	first	quarter	of	2014.

# 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	thousand	cubic	feet	of	gas	to	one	barrel	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.

No	gain	or	loss	is	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.

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	percent	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,	2014	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	2014,	2013	and	2012.	No	impairment	of	goodwill	was	required	in	2012	and	2013. However,	based	on	the	2014	assessment,	Devon's	Canadian	reporting	unit	goodwill	was	deemed	impaired.	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.

# 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.

# Discontinued	Operations

All	amounts	related	to	Devon's	International	operations	that	were	sold	in	2012	are	classified	as	discontinued	operations.

# Foreign	Currency	Translation	Adjustments

The	United	States	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	United	States	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	Not	Yet	Adopted

In	May	2014,	the	Financial	Accounting	Standards	Board	issued	Accounting	Standards	Update	2014-09,	Revenue	from	Contracts	with	Customers	(Topic	606). The	update	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	update	is	effective	for	Devon	beginning	on	January	1,	2017.	The standard	permits	the	use	of	either	the	retrospective	or	cumulative	effect	transition	method.	Devon	has	not	yet	selected	a	transition	method	and	is	evaluating	the	impact this	standard	will	have	on	its	consolidated	financial	statements	and	related	disclosures.

# 2. Acquisitions	and	Divestitures

# Formation	of	EnLink	Midstream,	LLC	and	EnLink	Midstream	Partners,	LP

On	March	7,	2014,	Devon,	Crosstex	Energy,	Inc.	and	Crosstex	Energy,	LP	(together	with	Crosstex	Energy,	Inc.,	"Crosstex")	completed	a	transaction	to	combine substantially	all	of	Devon's	U.S.	midstream	assets	with	Crosstex's	assets	to	form	a	new	midstream	business.	The	new	business	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,	EnLink Midstream	Holdings,	LP	("EnLink	Holdings")	and	$100	million	in	cash.	EnLink	Holdings	owns	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.	As	of	December	31,	2014,	the	General Partner	and	EnLink	each	own	50%	of	EnLink	Holdings.

As	of	December	31,	2014,	the	ownership	of	the	General	Partner	is	approximately:

•30%	–	Public	unitholders

As	of	December	31,	2014,	the	ownership	of	EnLink	is	approximately:

•43%	–	Public	unitholders

•8%	–	General	Partner

This	business	combination	was	accounted	for	using	the	acquisition	method	of	accounting.	Under	the	acquisition	method	of	accounting,	EnLink	Holdings	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, EnLink	Holdings'	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	(in	millions,	except	unit	price).

(2) Represents	the	value	of	noncontrolling	interests	related	to	the	General	Partner's	equity	investment	in	E2	Energy	Services,	LLC	and	E2	Appalachian	Compression, LLC	(collectively	"E2").

(3) Crosstex	Energy,	LP	converted	the	preferred	units	to	common	units	in	February	2014.

(4) The	final	purchase	price	is	based	on	the	fair	value	of	Crosstex	Energy,	LP's	common	units	as	of	the	closing	date,	March	7,	2014.

(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	and	Dropdowns

On	October	22,	2014,	EnLink	acquired	equity	interests	in	E2	Appalachian	Compression,	LLC	and	E2	Energy	Services,	LLC	(together	"E2")	from	the	General Partner.	The	total	consideration	for	the	transaction	was	approximately	$194	million,	including	a	$163	million	cash	payment	and	1.0	million	EnLink	units	valued	at	$31.2 million	based	on	the	fair	value	of	the	EnLink	units	as	of	the	closing	date	of	the	transaction.	Furthermore,	on	November	1,	2014,	EnLink	acquired	Gulf	Coast	natural	gas pipeline	assets	predominantly	located	in	southern	Louisiana	for	$234	million,	subject	to	certain	adjustments.

# GeoSouthern	Energy	Acquisition

On	February	28,	2014,	Devon	completed	its	acquisition	of	interests	in	certain	affiliates	of	GeoSouthern	Energy	Corporation	("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	(in	millions).

| The	allocation	of	the	purchase	price	is	as	follows	(in	millions). |  |
| :--- | :--- |
| Cash\tand\tcash\tequivalents | $95 |
| Other\tcurrent\tassets | 256 |
| Proved\tproperties | \t 5,026 |
| Unproved\tproperties | \t 1,007 |
| Midstream\tassets | 86 |
| Current\tliabilities | (434) |
| Long-term\tliabilities | (6) |
| Net\tassets\tacquired | $6,030 |

# EnLink	and	GeoSouthern	Operating	Results

The	following	table	presents	the	General	Partner's	and	EnLink's	(acquired	Crosstex	operations)	and	GeoSouthern's	operating	revenues	and	net	earnings	included in	Devon's	consolidated	comprehensive	statements	of	earnings	subsequent	to	the	transactions	described	above.

|  | Year	Ended	December	31,	2014<br>		GeoSouthern | EnLink |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Total\toperating\trevenues | $1,873 | $2,509 |
| Total\toperating\texpenses | 960 | 2,464 |
| Operating\tincome | $913 | $45 |

# 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 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| 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

In	November	2013,	Devon	announced	plans	to	divest	certain	properties	located	throughout	Canada	and	the	U.S.

# Canada

In	the	first	quarter	of	2014,	Devon	completed	minor	divestiture	transactions	for	$142	million	($155	million	Canadian	dollars).	In	the	second	quarter	of	2014, Devon	sold	conventional	assets	to	Canadian	Natural	Resources	Limited	for	$2.8	billion	($3.125	billion	Canadian	dollars).

Under	full	cost	accounting	rules,	sales	or	dispositions	of	oil	and	gas	properties	are	generally	accounted	for	as	adjustments	to	capitalized	costs,	with	no	recognition of	a	gain	or	loss.	However,	if	not	recognizing	a	gain	or	loss	on	the	disposition	would	otherwise	significantly	alter	the	relationship	between	a	cost	center's	capitalized costs	and	proved	reserves,	then	a	gain	or	loss	must	be	recognized.	The	Canadian	divestitures	significantly	altered	such	relationship.	Therefore,	Devon	recognized	gains totaling	$1.1	billion	($0.6	billion	after-tax)	in	2014.	These	gains	are	included	as	a	separate	item	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

Included	in	the	gain	calculation	noted	above	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	divestitures	noted	above,	Devon	repatriated	approximately	$2.8	billion	of	proceeds	to	the	U.S.	in	the	second	quarter	of	2014.	The	proceeds were	used	to	repay	$0.7	billion	of	commercial	paper	and	the	$2.0	billion	term	loans	that	were	drawn	in	the	first	quarter	of	2014	to	fund	a	portion	of	the	GeoSouthern acquisition.	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.

On	August	29,	2014,	Devon	sold	certain	U.S.	assets	to	LINN	Energy	for	$2.2	billion	($2.0	billion	after-tax	proceeds).	Additionally,	approximately	$200	million	of asset	retirement	obligations	were	assumed	by	LINN	Energy.	No	gain	or	loss	was	recognized	on	the	sale.	These	proceeds	were	used	towards	the	early	retirement	of	$1.9 billion	in	senior	notes	in	November	2014	as	discussed	in	Note	13.

# Commodity	Derivatives

As	of	December	31,	2014,	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	West	Texas	Intermediate	futures	price.	The	second	table	presents	Devon's	oil	derivatives	that	settle	against	the	Western	Canadian	Select, West	Texas	Sour	and	Midland	Sweet	indices.

|  | Price	Swaps |  |  | Price	Collars |  | Call	Options	Sold | Call	Options	Sold |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Weighted |  |  |  | Weighted | Weighted |
| Period | Volume\n(Bbls/d) | Average\tPrice\n($/Bbl) | Volume\n(Bbls/d) | Weighted\tAverage\nFloor\tPrice\t($/Bbl) | Weighted\tAverage\nCeiling\tPrice\t($/Bbl) | Volume\n(Bbls/d) | Average\tPrice\n($/Bbl) |
| Q1-Q4\t2015 | \t107,203 | $91.07 | \t31,500 | $89.67 | $97.84 | \t28,000 | $116.43 |
| Q1-Q4\t2016 | — | $— | — | $— | $— | \t18,500 | $103.11 |

| Period | Index | Volume	(Bbls/d) | ($/Bbl) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2015 | Western\tCanadian\tSelect | 22,514 | $(18.35) |
| Q1-Q4\t2015 | West\tTexas\tSour | 8,000 | $(3.68) |
| Q1-Q4\t2015 | Midland\tSweet | 14,247 | $(2.92) |

As	of	December	31,	2014,	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	Panhandle	Eastern	Pipe Line,	El	Paso	Natural	Gas	and	Houston	Ship	Channel	indices.

|  | Price	Swaps |  |  | Price	Collars |  | Call	Options	Sold | Call	Options	Sold |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Weighted |  | Weighted\tAverage | Weighted\tAverage | Weighted | Weighted |
| Period | Volume\n(MMBtu/d) | Average\tPrice\n($/MMBtu) | Volume\n(MMBtu/d) | Floor\tPrice\n($/MMBtu) | Ceiling\tPrice\n($/MMBtu) | Volume\n(MMBtu/d) | Average\t\tPrice\n($/MMBtu) |
| Q1-Q4\t2015 | \t 250,000 | $4.32 | \t 328,452 | $4.05 | $4.36 | \t 550,000 | $5.09 |
| Q1-Q4\t2016 | — | $— | — | $— | $— | \t 400,000 | $5.00 |

| Period | Index | Volume	(MMBtu/d) | ($/MMBtu) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2015 | Panhandle\tEastern\tPipe\tLine | 100,000 | $(0.28) |
| Q1-Q4\t2015 | El\tPaso\tNatural\tGas | 70,000 | $(0.11) |
| Q1-Q4\t2015 | Houston\tShip\tChannel | 200,000 | $0.01 |
| Q1-Q4\t2016 | Panhandle\tEastern\tPipe\tLine | 30,000 | $(0.33) |
| Q1-Q4\t2016 | El\tPaso\tNatural\tGas | 15,000 | $(0.13) |
| Q1-Q4\t2016 | Houston\tShip\tChannel | 30,000 | $0.11 |

As	of	December	31,	2014,	the	following	were	open	derivative	positions	associated	with	gas	processing	and	fractionation	at	EnLink.	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	as	defined	by	the	pricing	dates	in	the	derivative	contracts.

# Interest	Rate	Derivatives

As	of	December	31,	2014,	Devon	had	the	following	open	interest	rate	derivative	positions:

| Notional | Rate	Received | Rate	Paid | Expiration |
| :--- | :--- | :--- | :--- |
| (In\tmillions) |  |  |  |
| $100 | Three\tMonth\tLIBOR | 0.92% | December\t2016 |
| $100 | 1.76% | Three\tMonth\tLIBOR | January\t2019 |

# Foreign	Currency	Derivatives

As	of	December	31,	2014,	Devon	had	the	following	open	foreign	currency	derivative	position:

|  | Forward	Contract |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Contract | CAD | Weighted\tAverage |  |
| Currency | Type | Notional | Fixed\tRate\tReceived | Expiration |
|  |  | (In\tmillions) | (CAD-USD) |  |
| Canadian\tDollar | Sell | $1,884 | 0.864 | March\t2015 |

# Financial	Statement	Presentation

The	following	table	presents	the	net	gains	and	losses	recognized	in	the	accompanying	consolidated	comprehensive	statements	of	earnings	associated	with derivative	financial	instruments.

|  | Comprehensive	Statements	of | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Earnings\tCaption | 2014 | 2013 | 2012 |
|  |  |  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tcommodity\tderivatives | Oil,\tgas\tand\tNGL\tderivatives | $1,989 | $(191) | $693 |
| Midstream\tcommodity\tderivatives | Marketing\tand\tmidstream\trevenues | 22 | — | — |
| Interest\trate\tderivatives | Other\tnonoperating\titems | (1) | — | (15) |
| Foreign\tcurrency\tderivatives | Other\tnonoperating\titems | 60 | 56 | (18) |
| Net\tgains\t(losses)\trecognized\tin\tcomprehensive\tstatements\tof\tearnings | Net\tgains\t(losses)\trecognized\tin\tcomprehensive\tstatements\tof\tearnings | $2,070 | $(135) | $660 |

The	following	table	presents	the	derivative	fair	values	included	in	the	accompanying	consolidated	balance	sheets.

On	June	3,	2009,	Devon's	stockholders	adopted	the	2009	Long-Term	Incentive	Plan,	which	expires	on	June	2,	2019.	This	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,	performance	restricted	stock	awards,	restricted	stock	units,	performance	share	units,	stock	appreciation	rights	and	cash-out	rights	to	eligible	employees.	The plan	also	authorizes	the	grant	of	nonqualified	stock	options,	restricted	stock	awards,	restricted	stock	units	and	stock	appreciation	rights	to	directors.

In	the	second	quarter	of	2012,	Devon's	stockholders	adopted	an	amendment	to	the	2009	Long-Term	Incentive	Plan,	which	also	expires	June	2,	2019.	This amendment	increases	the	number	of	shares	authorized	for	issuance	from	21.5	million	shares	to	47.0	million	shares.	To	calculate	shares	issued	under	the	2009	Long- Term	Incentive	Plan	subsequent	to	this	amendment,	options	and	stock	appreciation	rights	represent	one	share	and	other	awards	represent	2.38	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. Devon's	gross	general	and	administrative	expense	for	the	year	ended	December	31,	2014	includes	$17	million	of	unit-based	compensation	related	to	grants	made	under EnLink's	long-term	incentive	plans.

The	vesting	for	certain	share-based	awards	was	accelerated	as	part	of	Devon's	restructuring	as	discussed	in	Note	6.	The	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Gross\tgeneral\tand\tadministrative\texpense | $199 | $157 | $179 |
| Share-based\tcompensation\texpense\tcapitalized\tpursuant\tto\tthe\tfull\tcost\tmethod\tof\taccounting\tfor\toil |  |  |  |
| and\tgas\tproperties | $53 | $60 | $56 |
| Related\tincome\ttax\tbenefit | $30 | $23 | $34 |

# 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.	The	volatility	of	Devon's	common	stock	is	based	on	the	historical	volatility of	the	market	price	of	Devon's	common	stock	over	a	period	of	time	equal	to	the	expected	term	of	the	option	and	ending	on	the	grant	date.	The	dividend	yield	is	based	on Devon's	historical	and	current	yield	in	effect	at	the	date	of	grant.	The	risk-free	interest	rate	is	based	on	the	zero-coupon	United	States	Treasury	yield	for	the	expected term	of	the	option	at	the	date	of	grant.	The	expected	term	of	the	options	is	based	on	historical	exercise	and	termination	experience	for	various	groups	of	employees	and directors.	Each	group	is	determined	based	on	the	similarity	of	their	historical	exercise	and	termination	behavior.	The	following	table	presents	a	summary	of	the	grant- date	fair	values	of	stock	options	granted	and	the	related	assumptions	for	2012.	All	such	amounts	represent	the	weighted-average	amounts	for	the	year.	No	stock	options were	granted	in	2014	and	2013.

The	following	table	presents	a	summary	of	Devon's	outstanding	stock	options.

|  |  |  | Weighted	Average |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Exercise | Remaining | Intrinsic |
|  | Options | Price | Term | Value |
|  | (In\tthousands) |  | (In\tyears) | (In\tmillions) |
| Outstanding\tat\tDecember\t31,\t2013 | 6,446 | $69.35 |  |  |
| Granted | — | $— |  |  |
| Exercised | (1,417) | $65.55 |  |  |
| Expired | (528) | $70.64 |  |  |
| Forfeited | (283) | $67.86 |  |  |
| Outstanding\tat\tDecember\t31,\t2014 | 4,218 | $70.56 | 3.11 | $1 |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2014 | 4,201 | $70.57 | 3.10 | $1 |
| Exercisable\tat\tDecember\t31,\t2014 | 3,969 | $70.80 | 3.00 | $1 |

The	aggregate	intrinsic	value	of	stock	options	that	were	exercised	during	2014,	2013	and	2012	was	$9	million,	$0.3	million	and	$34	million,	respectively.	As	of December	31,	2014,	Devon's	unrecognized	compensation	cost	related	to	unvested	stock	options	was	$3	million.	Such	cost	is	expected	to	be	recognized	over	a	weighted- average	period	of	1.0	years.

# 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.	The	following	table	presents	a	summary	of	Devon's	unvested restricted	stock	awards	and	units.

|  | Restricted<br>Stock	Awards		&amp;<br>Units | Average<br>Grant-Date<br>Fair	Value |
| :--- | :--- | :--- |
|  | (In\tthousands) |  |
| Unvested\tat\tDecember\t31,\t2013 | 3,292 | $59.76 |
| Granted | 3,487 | $62.75 |
| Vested | (1,767) | $60.23 |
| Forfeited | (708) | $60.47 |
| Unvested\tat\tDecember\t31,\t2014 | 4,304 | $60.85 |

The	aggregate	fair	value	of	restricted	stock	awards	and	units	that	vested	during	2014,	2013	and	2012	was	$112	million,	$141	million	and	$112	million, respectively.	As	of	December	31,	2014,	Devon's	unrecognized	compensation	cost	related	to	unvested	restricted	stock	awards	and	units	was	$194	million.	Such	cost	is expected	to	be	recognized	over	a	weighted-average	period	of	2.5	years.

# 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. If	Devon	meets	or	exceeds	the	performance	target,	the	awards	vest	after	the	recipient	meets	the	related	requisite	service	period.	If	the	performance	target	and	service period	requirement	are	not	met,	the	award	does	not	vest.	Once	vested,	recipients	are	entitled	to	dividends	on	the	awards.	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.	The	following	table	presents	a summary	of	Devon's	performance-based	restricted	stock	awards.

|  | Performance<br>Restricted<br>Stock	Awards | Average<br>Grant-Date<br>Fair	Value |
| :--- | :--- | :--- |
|  | (In\tthousands) |  |
| Unvested\tat\tDecember\t31,\t2013 | 316 | $56.25 |
| Granted | 234 | $61.33 |
| Vested | (170) | $56.18 |
| Unvested\tat\tDecember\t31,\t2014 | 380 | $59.41 |

The	aggregate	fair	value	of	performance-based	restricted	stock	awards	that	vested	during	2014	and	2013	was	$10	million	and	$5	million,	respectively.	No	awards vested	in	2012.	As	of	December	31,	2014,	Devon's	unrecognized	compensation	cost	related	to	these	awards	was	$5	million.	Such	cost	is	expected	to	be	recognized	over a	weighted-average	period	of	2.9	years.

# 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	total	shareholder	return	("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	percent	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	United	States	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	a	summary	of	the	grant-date	fair	values	of	performance	share	units	granted	and	the	related	assumptions.

|  | 2014 | 2013 | 2012 |
| :--- | :--- | :--- | :--- |
| Grant-date\tfair\tvalue | $70.18\t–\t$81.05 | $61.27\t–\t$63.48 | $61.27\t–\t$63.48 |
| Risk-free\tinterest\trate | 0.54% | 0.26%\t–\t0.36% | 0.26%\t–\t0.36% |
| Volatility\tfactor | 28.8% | 30.3% | 30.3% |
| Contractual\tterm\t(in\tyears) | 2.89 | 3.0 | 3.0 |

The	following	table	presents	a	summary	of	Devon's	performance	share	units.

|  | Performance | Grant-Date |
| :--- | :--- | :--- |
|  | Share\tUnits | Fair\tValue |
|  | (In\tthousands) |  |
| Unvested\tat\tDecember\t31,\t2013 | 925 | $66.64 |
| Granted | 708 | $77.77 |
| Forfeited | (156) | $76.59 |
| Unvested\tat\tDecember\t31,\t2014\t^(1) | 1,477 | $70.90 |

(1) A	maximum	of	3.0	million	common	shares	could	be	awarded	based	upon	Devon's	final	TSR	ranking.

As	of	December	31,	2014,	Devon's	unrecognized	compensation	cost	related	to	unvested	units	was	$34	million.	Such	cost	is	expected	to	be	recognized	over	a weighted-average	period	of	1.8	years.

# EnLink	Share-Based	Awards

As	of	December	31,	2014,	EnLink's	unrecognized	compensation	cost	related	to	unvested	restricted	incentive	units	was	$20	million.	Such	cost	is	expected	to	be recognized	over	a	weighted-average	period	of	1.9	years.

As	of	December	31,	2014,	the	General	Partner's	unrecognized	compensation	cost	related	to	unvested	restricted	incentive	units	was	$21	million.	Such	cost	is expected	to	be	recognized	over	a	weighted-average	period	of	1.9	years.

In	2014,	2013	and	2012,	Devon	recognized	asset	impairments	as	presented	below.

|  | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2014 | Year	Ended	December	31,	2013 | Year	Ended	December	31,	2013 | Year	Ended	December	31,	2012 | Year	Ended	December	31,	2012 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes | \t\t\t\tGross | \t\t\t\tNet\tof\tTaxes |
|  |  |  | (In\tmillions) | (In\tmillions) |  |  |
| Goodwill | $1,941 | $1,941 | $— | $— | $— | $— |
| U.S.\toil\tand\tgas\tassets | — | — | 1,110 | 707 | 1,793 | 1,142 |
| Canada\toil\tand\tgas\tassets | — | — | 843 | 632 | 163 | 122 |
| Midstream\tassets | 12 | 7 | 23 | 14 | 68 | 44 |
| Asset\timpairments | $1,953 | $1,948 | $1,976 | $1,353 | $2,024 | $1,308 |

# Goodwill	Impairment

In	2014,	Devon	recognized	$1.9	billion	in	goodwill	impairment	related	to	its	Canadian	reporting	unit.	Additional	information	regarding	the	impairment	is discussed	in	Note	12.

# 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	primarily	from	declines	in	the	U.S.	and	Canada	full	cost	ceilings.	The	lower	ceiling	values	resulted	primarily	from	decreases in	the	12-month	average	trailing	prices	for	oil,	natural	gas	and	NGLs,	which	reduced	proved	reserve	values.

# Midstream	Impairments

Due	to	the	significant	decline	in	oil	prices	during	the	fourth	quarter	of	2014,	Devon	wrote	down	its	pipeline	line	fill	inventory,	as	the	carrying	amount	exceeded its	fair	value,	which	was	determined	based	on	the	West	Texas	Intermediate	spot	price	at	December	31,	2014.

Due	to	declining	natural	gas	production	resulting	from	low	natural	gas	and	NGL	prices	in	2013	and	2012,	Devon	determined	that	the	carrying	amounts	of	certain of	its	midstream	facilities	were	not	recoverable	from	estimated	future	cash	flows.	Consequently,	the	assets	were	written	down	to	their	estimated	fair	values,	which	were determined	using	discounted	cash	flow	models.	The	fair	value	of	Devon's	midstream	assets	is	considered	a	Level	3	fair	value	measurement.

# 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

In	October	2012,	Devon	announced	plans	to	consolidate	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	related	to	certain	office	space	that	is	subject to	non-cancellable	operating	lease	agreements	and	that	Devon	ceased	using	as	part	of	the	office	consolidation.

# Divestiture	of	Offshore	Assets

In	the	fourth	quarter	of	2009,	Devon	announced	plans	to	divest	its	offshore	assets.	As	of	December	31,	2012,	Devon	had	divested	all	of	its	U.S.	Offshore	and International	assets	and	incurred	$196	million	of	restructuring	costs	associated	with	the	divestitures.

The	schedule	below	summarizes	restructuring	costs	presented	in	the	accompanying	consolidated	comprehensive	statements	of	earnings.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Canada\tdivestitures: |  |  |  |
| Employee\tseverance\tand\tretention | $42 | $— | $— |
| Lease\tobligations\tand\tother | 4 | \t — | \t — |
| Office\tconsolidation: |  |  |  |
| Employee\tseverance\tand\tretention | \t — | 13 | 77 |
| Lease\tobligations\tand\tother | \t — | 41 | 3 |
| Offshore\tdivestiture: |  |  |  |
| Employee\tseverance\tand\tretention | \t — | \t — | (3) |
| Lease\tobligations\tand\tother | \t — | \t — | (3) |
| Restructuring\tcosts | $46 | $54 | $74 |

The	schedule	below	summarizes	Devon's	restructuring	liabilities.

|  | Other<br>Current<br>Liabilities | Other<br>Long-term<br>Liabilities | Total |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Balance\tas\tof\tDecember\t31,\t2012 | $52 | $9 | $61 |
| Changes\tdue\tto\toffice\tconsolidation | (22) | 11 | (11) |
| Changes\tdue\tto\toffshore\tdivestiture | (3) | (2) | (5) |
| Balance\tas\tof\tDecember\t31,\t2013 | 27 | 18 | 45 |
| Changes\tdue\tto\tCanadian\tdivestitures | 4 | — | 4 |
| Changes\tdue\tto\toffice\tconsolidation | (15) | (10) | (25) |
| Changes\tdue\tto\toffshore\tdivestiture | (3) | (1) | (4) |
| Balance\tas\tof\tDecember\t31,\t2014 | $13 | $7 | $20 |

# Income	Tax	Expense	(Benefit)

Devon's	income	tax	components	are	presented	in	the	following	table.

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Current\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | $152 | $73 | $60 |
| Various\tstates | 18 | (5) | (3) |
| Canada\tand\tvarious\tprovinces | 307 | 4 | (5) |
| Total\tcurrent\ttax\texpense\t(benefit) | 477 | 72 | 52 |
| Deferred\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | \t 1,610 | 198 | (188) |
| Various\tstates | 93 | 59 | 34 |
| Canada\tand\tvarious\tprovinces | 188 | (160) | (30) |
| Total\tdeferred\ttax\texpense\t(benefit) | \t 1,891 | 97 | (184) |
| Total\tincome\ttax\texpense\t(benefit) | $2,368 | $169 | $(132) |

Total	income	tax	expense	(benefit)	differed	from	the	amounts	computed	by	applying	the	United	States	federal	income	tax	rate	to	earnings	from	continuing operations	before	income	taxes	as	a	result	of	the	following:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
| Total\tincome\ttax\texpense\t(benefit)\t(in\tmillions) | $2,368 | $169 | $(132) |
| U.S.\tstatutory\tincome\ttax\trate | 35% | 35% | (35)% |
| Non-deductible\tgoodwill\ttransactions | 23% | 0% | 0% |
| Taxation\ton\tCanadian\toperations | (4)% | 9% | (6)% |
| State\tincome\ttaxes | 2% | 23% | 6% |
| Repatriations | 2% | 65% | 0% |
| Taxes\ton\tEnLink\tformation | 1% | 0% | 0% |
| Other | (1)% | (19)% | (7)% |
| Effective\tincome\ttax\trate | 58% | \t 113% | (42)% |

During	2014,	Devon	had	non-deductible	goodwill	transactions.	Goodwill	was	removed	in	conjunction	with	the	Canadian	conventional	asset	divestiture	to Canadian	Natural	Resources	Limited,	and	there	was	a	goodwill	impairment	in	the	Canadian	reporting	unit.	See	Note	12	for	further	discussion.

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	tax	effects	of	temporary	differences	that	gave	rise	to	Devon's	deferred	tax	assets	and	liabilities	are	presented	below:

|  | December	31,<br>2014 | 2013 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Deferred\ttax\tassets: |  |  |
| Asset\tretirement\tobligations | $458 | $673 |
| Foreign\ttax\tcredits | — | 248 |
| Net\toperating\tloss\tcarryforwards | 200 | 183 |
| Alternative\tminimum\ttax\tcredits | 57 | 105 |
| Pension\tbenefit\tobligations | 113 | 104 |
| Other | 273 | 163 |
| Total\tdeferred\ttax\tassets | 1,101 | 1,476 |
| Deferred\ttax\tliabilities: |  |  |
| Property\tand\tequipment | (6,940) | (5,895) |
| Long-term\tdebt | (115) | (161) |
| Taxes\ton\tunremitted\tforeign\tearnings | (6) | (157) |
| Fair\tvalue\tof\tfinancial\tinstruments | (699) | (7) |
| Other | (154) | (52) |
| Total\tdeferred\ttax\tliabilities | (7,914) | (6,272) |
| Net\tdeferred\ttax\tliability | $(6,813) | $(4,796) |

Devon	has	recognized	$200	million	of	deferred	tax	assets	related	to	various	net	operating	loss	carryforwards	available	to	offset	future	income	taxes.	The carryforwards	consist	of	$621	million	of	Canadian	net	operating	loss	carryforwards,	which	expire	between	2029	and	2034,	$180	million	of	state	net	operating	loss carryforwards,	which	expire	primarily	between	2018	and	2032	and	$135	million	of	net	operating	loss	carryforwards	related	to	EnLink's	operations,	which	expire between	2028	and	2034.	Devon	expects	the	tax	benefits	from	the	Canadian	net	operating	loss	carryforwards	to	be	utilized	between	2015	and	2017	and	the	state	net operating	loss

carryforwards	to	be	utilized	between	2017	and	2029.	The	EnLink	net	operating	losses	are	expected	to	be	utilized	during	2015.	Devon	has	also	recognized	a	$57	million deferred	tax	asset	related	to	alternative	minimum	tax	credits	which	have	no	expiration	date	and	will	be	available	for	use	against	tax	on	future	taxable	income.

The	expected	utilization	of	Devon's	carryforwards	and	credits	is	based	upon	current	estimates	of	taxable	income,	considering	limitations	on	the	annual	utilization of	these	benefits	as	set	forth	by	tax	regulations.	Significant	changes	in	such	estimates	caused	by	variables	such	as	future	oil,	gas	and	NGL	prices	or	capital	expenditures could	alter	the	timing	of	the	eventual	utilization	of	such	carryforwards.	There	can	be	no	assurance	that	Devon	will	generate	any	specific	level	of	continuing	taxable earnings.	However,	management	believes	that	Devon's	future	taxable	income	will	more	likely	than	not	be	sufficient	to	utilize	its	tax	carryforwards	and	credits	prior	to their	expiration.

As	of	December	31,	2014,	Devon's	unremitted	foreign	earnings	totaled	approximately	$1.8	billion.	All	but	$22	million	of	the	$1.8	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	United	States income	taxes	associated	with	such	earnings.	If	such	earnings	were	to	be	repatriated	to	the	U.S.,	Devon	may	be	subject	to	United	States	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	$22	million	of	unremitted	earnings	deemed	not	to	be	indefinitely	reinvested,	Devon	has	recognized	a	$6	million	deferred	tax	liability associated	with	such	unremitted	earnings	as	of	December	31,	2014.

# Unrecognized	Tax	Benefits

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

|  | December	31,<br>2014 | 2013 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Balance\tat\tbeginning\tof\tyear | $243 | $216 |
| Tax\tpositions\ttaken\tin\tprior\tperiods | \t — | (17) |
| Tax\tpositions\ttaken\tin\tcurrent\tyear | \t — | 42 |
| Accrual\tof\tinterest\trelated\tto\ttax\tpositions\ttaken | 2 | 5 |
| Foreign\tcurrency\ttranslation | (4) | (3) |
| Balance\tat\tend\tof\tyear | $241 | $243 |

Devon's	unrecognized	tax	benefit	balance	at	December	31,	2014	and	2013	included	$34	million	and	$32	million,	respectively,	of	interest	and	penalties.	If recognized,	$223	million	of	Devon's	unrecognized	tax	benefits	as	of	December	31,	2014	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	common	shares	outstanding	used	in	the	calculations	of	basic	and	diluted	net	earnings per	share.

|  | Earnings	(loss) | Common<br>Shares | Earnings	(loss)<br>per	Share |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Year\tEnded\tDecember\t31,\t2014: |  |  |  |
| Net\tearnings\tattributable\tto\tDevon | $1,607 | 409 |  |
| Attributable\tto\tparticipating\tsecurities | (17) | (4) |  |
| Basic\tnet\tearnings\tper\tshare | 1,590 | 405 | $3.93 |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | 2 |  |
| Diluted\tnet\tearnings\tper\tshare | $1,590 | 407 | $3.91 |
| Year\tEnded\tDecember\t31,\t2013: |  |  |  |
| Net\tloss\tattributable\tto\tDevon | $(20) | 406 |  |
| Attributable\tto\tparticipating\tsecurities | (2) | (4) |  |
| Basic\tnet\tloss\tper\tshare | (22) | 402 | $(0.06) |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | — |  |
| Diluted\tnet\tloss\tper\tshare | $(22) | 402 | $(0.06) |
| Year\tEnded\tDecember\t31,\t2012: |  |  |  |
| Net\tloss\tattributable\tto\tDevon | $(206) | 404 |  |
| Attributable\tto\tparticipating\tsecurities | (3) | (4) |  |
| Basic\tnet\tloss\tper\tshare | (209) | 400 | $(0.52) |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | — |  |
| Diluted\tnet\tloss\tper\tshare | $(209) | 400 | $(0.52) |

Certain	options	to	purchase	shares	of	Devon's	common	stock	were	excluded	from	the	dilution	calculations	because	the	options	were	antidilutive.	These	excluded options	totaled	3	million,	7	million	and	9	million	in	2014,	2013	and	2012,	respectively.

# 9. Other	Comprehensive	Earnings

Components	of	other	comprehensive	earnings	consist	of	the	following:

|  | 2014 | 2013 | 2012 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Foreign\tcurrency\ttranslation: |  |  |  |
| Beginning\taccumulated\tforeign\tcurrency\ttranslation | $1,448 | $1,996 | $1,802 |
| Change\tin\tcumulative\ttranslation\tadjustment | (499) | (574) | 203 |
| Income\ttax\tbenefit\t(expense) | 34 | 26 | (9) |
| Ending\taccumulated\tforeign\tcurrency\ttranslation | 983 | \t 1,448 | 1,996 |
| Pension\tand\tpostretirement\tbenefit\tplans: |  |  |  |
| Beginning\taccumulated\tpension\tand\tpostretirement\tbenefits | (180) | (225) | (227) |
| Net\tactuarial\tgain\t(loss)\tand\tprior\tservice\tcost\tarising\tin\tcurrent\tyear | (57) | 48 | (47) |
| Recognition\tof\tnet\tactuarial\tloss\tand\tprior\tservice\tcost\tin\tearnings^\t(1) | 20 | 24 | 51 |
| Income\ttax\tbenefit\t(expense) | 13 | (27) | (2) |
| Ending\taccumulated\tpension\tand\tpostretirement\tbenefits | (204) | (180) | (225) |
| Accumulated\tother\tcomprehensive\tearnings,\tnet\tof\ttax | $779 | $1,268 | $1,771 |

(1) These	accumulated	other	comprehensive	earnings	components	are	included	in	the	computation	of	net	periodic	benefit	cost,	which	is	a	component	of	general	and administrative	expenses	on	the	accompanying	consolidated	comprehensive	statements	of	earnings	(see	Note	15	note	for	additional	details).

# 10. Supplemental	Information	to	Statements	of	Cash	Flows

|  | 2014 | 2013 | 2012 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Net\tchange\tin\tworking\tcapital\taccounts: |  |  |  |
| Accounts\treceivable | $128 | $(288) | $140 |
| Income\ttaxes\treceivable | (467) | 29 | (55) |
| Other\tcurrent\tassets | (222) | 20 | (73) |
| Accounts\tpayable | (68) | 26 | (8) |
| Revenues\tand\troyalties\tpayable | 133 | 35 | 19 |
| Other\tcurrent\tliabilities | 546 | (120) | (73) |
| Net\tchange\tin\tworking\tcapital | $50 | $(298) | $(50) |
| Interest\tpaid\t(net\tof\tcapitalized\tinterest) | $514 | $406 | $334 |
| Income\ttaxes\tpaid | $899 | $13 | $100 |

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.	See	Note	2	for	additional	details.

# 11. Accounts	Receivable

The	components	of	accounts	receivable	include	the	following:

|  | December	31,<br>2014 |  | December	31,<br>2013 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tsales | $723 |  | $851 |
| Joint\tinterest\tbillings | 475 |  | 447 |
| Marketing\tand\tmidstream\trevenues | 706 |  | 172 |
| Other | 71 |  | 61 |
| Gross\taccounts\treceivable | 1,975 |  | 1,531 |
| Allowance\tfor\tdoubtful\taccounts | (16) |  | (11) |
| Net\taccounts\treceivable | $1,959 |  | $1,520 |

# 12. Goodwill	and	Other	Intangible	Assets

The	table	below	provides	a	summary	of	Devon's	goodwill	by	assigned	reporting	unit.

|  | U.S. | Canada | EnLink | Total |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |  |
| Balance\tas\tof\tDecember\t31,\t2012 | $2,644 | $3,033 | $402 | $6,079 |
| Asset\tdivestitures | (26) | — | — | (26) |
| Foreign\tcurrency\ttranslation\tadjustments | — | (195) | — | (195) |
| Balance\tas\tof\tDecember\t31,\t2013 | $2,618 | $2,838 | $402 | $5,858 |
| Acquired\tduring\tperiod | — | — | \t 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	During	Period

Included	in	the	assets	Devon	contributed	to	EnLink	Holdings	was	$402	million	of	goodwill.	The	additional	EnLink	goodwill	of	$3.3	billion	represents	the goodwill	recognized	upon	the	formation	of	EnLink	and	General	Partner	as	described	in	Note	2.

The	General	Partner's	and	EnLink's	goodwill	was	recognized	and	assigned	to	the	five	reporting	units	as	follows.

|  | Texas | Louisiana | Oklahoma | Ohio	River<br>Valley | General<br>Partner | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |  |
| Balance\tas\tof\tDecember\t31,\t2013 | $326 | $— | $76 | $— | $— | $402 |
| Acquired\tduring\tperiod | 842 | 787 | 114 | 113 | \t 1,427 | \t 3,283 |
| Balance\tas\tof\tDecember\t31,\t2014 | $1,168 | $787 | $190 | $113 | $1,427 | $3,685 |

In	conjunction	with	the	asset	divestitures	in	2013	and	2014,	Devon	removed	$26	million	and	$706	million	of	goodwill,	respectively,	which	were	allocated	to	these

assets.

# Impairment

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.

As	a	result	of	performing	the	goodwill	impairment	test	described	in	Note	1,	Devon	concluded	the	implied	fair	value	of	its	Canadian	goodwill	was	zero	as	of December	31,	2014.	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.	Consequently,	in	the	fourth	quarter	of	2014,	Devon	wrote	off	its	remaining	Canadian	goodwill	and	recognized	a	$1.9 billion	impairment.

# Other	Intangible	Assets

As	of	December	31,	2014,	intangible	assets	associated	with	customer	relationships	had	a	gross	carrying	amount	of	$569	million	and	$36	million	of	accumulated amortization.	The	weighted-average	amortization	period	for	the	customer	relationships	is	13.7	years.	Amortization	expense	for	intangibles	was	approximately	$36 million	for	the	year	ended	December	31,	2014.	Other	intangible	assets	are	reported	in	other	long-term	assets	in	the	accompanying	consolidated	balance	sheets.

The	following	table	summarizes	the	estimated	aggregate	amortization	expense	for	the	next	five	years.

# 13. Debt	and	Related	Expenses

A	summary	of	Devon's	debt	is	as	follows:

|  | December	31,	2014 |  | December	31,	2013 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Devon\tdebt |  |  |  |
| Commercial\tpaper | $932 |  | $1,317 |
| 5.625%\tdue\tJanuary\t15,\t2014 | — |  | 500 |
| Floating\trate\tdue\tDecember\t15,\t2015 | 500 |  | 500 |
| 2.40%\tdue\tJuly\t15,\t2016 | — |  | 500 |
| Floating\trate\tdue\tDecember\t15,\t2016 | 350 |  | 350 |
| 1.20%\tdue\tDecember\t15,\t2016 | — |  | 650 |
| 1.875%\tdue\tMay\t15,\t2017 | — |  | 750 |
| 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 |
| 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 |
| Net\tdiscount\ton\tdebentures\tand\tnotes | (18) |  | (20) |
| Total\tDevon\tdebt | 9,239 |  | 12,022 |
| EnLink\tdebt |  |  |  |
| Credit\tfacilities | 237 |  | — |
| 2.70%\tdue\tApril\t1,\t2019 | 400 |  | — |
| 7.125%\tdue\tJune\t1,\t2022 | 163 |  | — |
| 4.40%\tdue\tApril\t1,\t2024 | 550 |  | — |
| 5.60%\tdue\tApril\t1,\t2044 | 350 |  | — |
| 5.05%\tdue\tApril\t1,\t2045 | 300 |  | — |
| Net\tpremium\ton\tdebentures\tand\tnotes | 23 |  | — |
| Total\tEnLink\tdebt | 2,023 |  | — |
| Total\tdebt | 11,262 |  | 12,022 |
| Less\tamount\tclassified\tas\tshort-term\tdebt^\t(1) | 1,432 |  | 4,066 |
| Total\tlong-term\tdebt | $9,830 |  | $7,956 |

(1) 2014	short-term	debt	consists	of	$932	million	of	commercial	paper	and	$500	million	floating	rate	due	on	December	15,	2015.	2013	short-term	debt	consists	of $2.25	billion	of	senior	notes	issued	in	conjunction	with	the	GeoSouthern	acquisition,	$1.3	billion	of	commercial	paper	and	$500	million	of	senior	notes	due January	15,	2014.

Debt	maturities	as	of	December	31,	2014,	excluding	premiums	and	discounts,	are	as	follows	(in	millions):

# Credit	Lines

Devon	has	a	$3.0	billion	syndicated,	unsecured	revolving	line	of	credit	(the	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,	2014,	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	percent.	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,	2014,	Devon	was	in	compliance	with	this	covenant	with	a debt-to-capitalization	ratio	of	20.9	percent.

# Commercial	Paper

Devon	has	access	to	$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,	2014,	Devon's commercial	paper	borrowings	of	$932	million	have	a	weighted-average	borrowing	rate	of	0.44	percent.

# Retirement	of	Senior	Notes

On	November	13,	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	percent	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,	2014	and	2013,	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	resulting	in	cash	proceeds	of	approximately	$2.2	billion,	net	of	discounts	and	issuance	costs.	The	floating	rate	senior	notes	due	in	2015	bear	interest	at	a	rate equal	to	three-month	LIBOR	plus	0.45	percent,	which	rate	will	be	reset	quarterly.	The	floating	rate	senior	notes	due	in	2016	bears	interest	at	a	rate	equal	to	three-month LIBOR	plus	0.54	percent,	which	rate	will	be	reset	quarterly.	The	schedule	below	summarizes	the	key	terms	of	these	notes	(in	millions).

The	senior	notes	were	classified	as	short-term	debt	on	Devon's	consolidated	balance	sheet	as	of	December	31,	2013	due	to	certain	redemption	features	in	the	event that	the	GeoSouthern	acquisition	was	not	completed	on	or	prior	to	June	30,	2014.	On	February	28,	2014,	the	GeoSouthern	acquisition	closed	and	thus	the	senior	notes were	subsequently	classified	as	long-term	debt.

Additionally,	during	December	2013,	Devon	entered	into	a	term	loan	agreement	with	a	group	of	major	financial	institutions	pursuant	to	which	Devon	could	draw up	to	$2.0	billion	to	finance,	in	part,	the	GeoSouthern	acquisition	and	to	pay	transaction	costs.	In	February	2014,	Devon	drew	the	$2.0	billion	of	term	loans	for	the GeoSouthern	transaction,	and	the	amount	was	subsequently	repaid	on	June	30,	2014	with	the	Canadian	divestiture	proceeds	that	were	repatriated	to	the	U.S.	in	June 2014,	at	which	point	the	term	loan	was	terminated.

# 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	and	credit	facility	borrowings.	The	schedule	below	summarizes	the	key	terms	of	these	notes	(in	millions).

|  | May	2012 | July	2011 | January	2009 | March	2002 |
| :--- | :--- | :--- | :--- | :--- |
| 1.875%\tdue\tMay\t15,\t2017\t^(1) | $750 | $— | $— | $— |
| 3.25%\tdue\tMay\t15,\t2022 | 1,000 | — | — | — |
| 4.75%\tdue\tMay\t15,\t2042 | 750 | — | — | — |
| 2.40%\tdue\tJuly\t15,\t2016\t^(1) | — | 500 | — | — |
| 4.00%\tdue\tJuly\t15,\t2021 | — | 500 | — | — |
| 5.60%\tdue\tJuly\t15,\t2041 | — | 1,250 | — | — |
| 5.625%\tdue\tJanuary\t15,\t2014\t^(2) | — | — | 500 | — |
| 6.30%\tdue\tJanuary\t15,\t2019 | — | — | 700 | — |
| 7.95%\tdue\tApril\t15,\t2032 | — | — | — | 1,000 |
| Discount\tand\tissuance\tcosts | (35) | (29) | (13) | (14) |
| Net\tproceeds | $2,465 | $2,221 | $1,187 | $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,	2014,	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.

In	October	2001,	Devon,	through	Devon	Financing	Corporation,	U.L.C.	("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	acquisition	of	Anderson	Exploration.

# 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.

EnLink	has	a	$1.0	billion	unsecured	revolving	credit	facility.	As	of	December	31,	2014,	there	were	$14	million	in	outstanding	letters	of	credit	and	$237	million outstanding	borrowings	under	the	$1.0	billion	credit	facility,	leaving	$749	million	available	for	future	borrowing.

The	$1.0	billion	credit	facility	matures	on	the	fifth	anniversary	of	the	initial	funding	date,	which	was	March	7,	2014,	unless	EnLink	requests,	and	the	requisite lenders	agree,	to	extend	it	pursuant	to	its	terms.	On	February	5,	2015,	the	commitments	under	EnLink's	credit	facility	were	increased	to	$1.5	billion,	and	the	maturity date	was	extended	by	a	year	to	March	7,	2020.

The	credit	facility	contains	certain	financial,	operational	and	legal	covenants.	Among	other	things,	these	covenants	include	maintaining	a	ratio	of	EnLink's consolidated	indebtedness	to	consolidated	EBITDA	(as	defined	in	the	credit	facility,	which	definition	includes	projected	EBITDA	from	certain	capital	expansion projects)	of	no	more	than	5.0	to	1.0.	If	EnLink	consummates	one	or	more	acquisitions	in	which	the	aggregate	purchase	price	is	$50	million	or	more,	the	maximum allowed	ratio	of	EnLink's	consolidated	indebtedness	to	consolidated	EBITDA	may	increase	to	5.5	to	1.0	for	the	quarter	of	the	acquisition	and	the	three	following quarters.

Additionally,	as	of	December	31,	2014,	E2	Energy	Services,	LLC	had	certain	promissory	notes	outstanding	related	to	its	vehicle	fleet	in	the	amount	of	$0.4 million	due	in	increments	through	July	2017.

The	General	Partner	also	has	a	$250	million	revolving	credit	facility.	As	of	December	31,	2014,	the	General	Partner	had	no	outstanding	borrowings	under	the $250	million	credit	facility.

The	$250	million	credit	facility	will	mature	on	March	7,	2019.	The	credit	facility	contains	certain	financial,	operational	and	legal	covenants.	The	financial covenants	are	tested	on	a	quarterly	basis,	based	on	the	rolling	four-quarter	period	that	ends	on	the	last	day	of	each	fiscal	quarter,	and	include	(i)	maintaining	a	maximum consolidated	leverage	ratio	(as	defined	in	the	credit	facility,	but	generally	computed	as	the	ratio	of	consolidated	funded	indebtedness	to	consolidated	earnings	before interest,	taxes,	depreciation,	amortization	and	certain	other	noncash	charges)	of	4.00	to	1.00,	provided	that	the	maximum	consolidated	leverage	ratio	is	4.50	to	1.00 during	an	acquisition	period	(as	defined	in	the	credit	facility)	and	(ii)	maintaining	a	minimum	consolidated	interest	coverage	ratio	(as	defined	in	the	credit	facility,	but generally	computed	as	the	ratio	of	consolidated	earnings	before	interest,	taxes,	depreciation,	amortization	and	certain	other	noncash	charges	to	consolidated	interest charges)	of	2.50	to	1.00	at	all	times	unless	an	investment	grade	event	(as	defined	in	the	credit	facility)	occurs.	EnLink	and	the	General	Partner	are	in	compliance	with	all such	covenants	as	of	December	31,	2014.

On	March	19,	2014,	EnLink	issued	$1.2	billion	aggregate	principal	amount	of	unsecured	senior	notes,	consisting	of	$400	million	aggregate	principal	amount	of its	2.70%	senior	notes	due	2019,	$450	million	aggregate	principal	amount	of	its	4.40%	senior	notes	due	2024	and	$350	million	aggregate	principal	amount	of	its	5.60% senior	notes	due	2044,	at	discounts	of	their	face	value.	The	2019	notes	mature	on	April	1,	2019,	the	2024	notes	mature	on	April	1,	2024	and	the	2044	notes	mature	on April	1,	2044.	The	interest	payments	on	the	notes	are	due	semi-annually	in	arrears	in	April	and	October.

On	November	12,	2014,	EnLink	issued	$100	million	aggregate	principal	amount	of	its	4.40%	senior	notes	due	2024	and	$300	million	aggregate	principal	amount of	its	5.05%	senior	notes	due	2045,	at	a	premium	and	discount,	respectively,	of	their	face	value.	The	2024	notes	were	offered	as	an	additional	issue	of	EnLink's outstanding	4.40%	senior	notes	due	2024,	issued	in	an	aggregate	principal	amount	of	$450	million	on	March	19,	2014.	The	2024	notes	and	the	notes	issued	March	19, 2014	are	treated	as	a	single	class	of	debt	securities	and	have	identical	terms,	other	than	the	issue	date.	The	2045	notes	mature	on	April	1,	2045,	and	interest	payments	on the	2045	notes	are	due	semi-annually	in	arrears	in	April	and	October.

The	following	schedule	includes	the	components	of	net	financing	costs.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t2014 | \t\t2013 | \t\t2012 |
|  |  | (In\tmillions) |  |
| Interest\tbased\ton\tdebt\toutstanding | $ 546 | $ 466 | $ 440 |
| Early\tretirement\tof\tdebt | 48 | \t — | \t — |
| Capitalized\tinterest | (70) | (56) | (48) |
| Other\tfees\tand\texpenses | 12 | 27 | 14 |
| Interest\texpense | 536 | 437 | 406 |
| Interest\tincome | (10) | (20) | (36) |
| Net\tfinancing\tcosts | $ 526 | $ 417 | $ 370 |

The	schedule	below	summarizes	changes	in	asset	retirement	obligations.

|  | Year	Ended	December	31,<br>						2014 | 2013 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Asset\tretirement\tobligations\tas\tof\tbeginning\tof\tperiod | $2,228 | $2,095 |
| Liabilities\tincurred | 97 | 112 |
| Liabilities\tsettled | (56) | (83) |
| Revision\tof\testimated\tobligation | 70 | 104 |
| Liabilities\tassumed\tby\tothers | (953) | (28) |
| Accretion\texpense\ton\tdiscounted\tobligation | 89 | 115 |
| Foreign\tcurrency\ttranslation\tadjustment | (76) | (87) |
| Asset\tretirement\tobligations\tas\tof\tend\tof\tperiod | 1,399 | 2,228 |
| Less\tcurrent\tportion | 60 | 88 |
| Asset\tretirement\tobligations,\tlong-term | $1,339 | $2,140 |

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	$25	million	and	$27	million	at	December	31,	2014	and	2013,	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	U.S.	employees.	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	and	$1.1	billion	at	December	31,	2014	and	2013,	respectively.	Devon's	benefit	obligations	and	plan assets	are	measured	each	year	as	of	December	31.	The	projected	benefit	obligation	for	Devon's	qualified	plans	was	fully	funded	as	of	December	31,	2014	and	2013.

|  | Pension	Benefits |  | Postretirement	Benefits |  |
| :--- | :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | \t\t\t\t2014 | \t\t\t\t2013 |
|  |  | (In\tmillions) |  |  |
| Change\tin\tbenefit\tobligation: |  |  |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $1,177 | $1,360 | $24 | $34 |
| Service\tcost | 30 | 36 | 1 | 1 |
| Interest\tcost | 55 | 51 | 1 | 1 |
| Actuarial\tloss\t(gain) | 203 | (158) | — | (3) |
| Plan\tamendments | — | 2 | — | (8) |
| Plan\tsettlements | (4) | — | — | — |
| Foreign\texchange\trate\tchanges | (3) | (2) | — | — |
| Participant\tcontributions | — | — | 2 | 3 |
| Benefits\tpaid | (81) | (112) | (4) | (4) |
| Benefit\tobligation\tat\tend\tof\tyear | \t 1,377 | \t 1,177 | 24 | 24 |
| Change\tin\tplan\tassets: |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | \t 1,006 | \t 1,165 | — | — |
| Actual\treturn\ton\tplan\tassets | 200 | (57) | — | — |
| Employer\tcontributions | 29 | 11 | 2 | 1 |
| Participant\tcontributions | — | — | 2 | 3 |
| Plan\tsettlements | (4) | — | — | — |
| Benefits\tpaid | (81) | (112) | (4) | (4) |
| Foreign\texchange\trate\tchanges | (1) | (1) | — | — |
| Fair\tvalue\tof\tplan\tassets\tat\tend\tof\tyear | \t 1,149 | \t 1,006 | — | — |
| Funded\tstatus\tat\tend\tof\tyear | $(228) | $(171) | $(24) | $(24) |
| Amounts\trecognized\tin\tbalance\tsheet: |  |  |  |  |
| Other\tlong-term\tassets | $22 | $47 | $— | $— |
| Other\tcurrent\tliabilities | (10) | (12) | (3) | (3) |
| Other\tlong-term\tliabilities | (240) | (206) | (21) | (21) |
| Net\tamount | $(228) | $(171) | $(24) | $(24) |
| Amounts\trecognized\tin\taccumulated\tother\tcomprehensive\tearnings: |  |  |  |  |
| Net\tactuarial\tloss\t(gain) | $317 | $279 | $(11) | $(13) |
| Prior\tservice\tcost\t(credit) | 19 | 23 | (9) | (11) |
| Total | $336 | $302 | $(20) | $(24) |

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	$10	million	and	$11	million	for	2014	and	2013,	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,	2014	and	2013, as	presented	in	the	table	below.

|  | December	31,<br>2014 | 2013 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Projected\tbenefit\tobligation | $250 | $218 |
| Accumulated\tbenefit\tobligation | $191 | $179 |
| 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.

|  |  | Pension	Benefits |  | Postretirement	Benefits | Postretirement	Benefits | Postretirement	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 |
|  |  |  | (In\tmillions) | (In\tmillions) |  |  |
| Net\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Service\tcost | $30 | $36 | $43 | $1 | $1 | $1 |
| Interest\tcost | 55 | 51 | 60 | 1 | 1 | 1 |
| Expected\treturn\ton\tplan\tassets | (54) | (62) | (64) | \t — | \t — | \t — |
| Curtailment\tand\tsettlement\texpense | 1 | \t — | 26 | \t — | \t — | 1 |
| Recognition\tof\tnet\tactuarial\tloss\t(gain)\t^(1) | 18 | 22 | 24 | (1) | (1) | (1) |
| Recognition\tof\tprior\tservice\tcost\t^(1) | 4 | 4 | 3 | (2) | (1) | (1) |
| Total\tnet\tperiodic\tbenefit\tcost\t^(2) | 54 | 51 | 92 | (1) | \t — | 1 |
| Other\tcomprehensive\tloss\t(earnings): |  |  |  |  |  |  |
| Actuarial\tloss\t(gain)\tarising\tin\tcurrent\tyear | 57 | (39) | 37 | \t — | (3) | (4) |
| Prior\tservice\tcost\t(credit)\tarising\tin\tcurrent\tyear | \t — | 2 | 14 | \t — | (8) | \t — |
| Recognition\tof\tnet\tactuarial\tloss,\tincluding\tsettlement\texpense,\tin\tnet\tperiodic\tbenefit\tcost | (19) | (22) | (45) | 1 | 1 | 1 |
| Recognition\tof\tprior\tservice\tcost,\tincluding\tcurtailment,\tin\tnet\tperiodic\tbenefit\tcost | (4) | (4) | (8) | 2 | 1 | 1 |
| Total\tother\tcomprehensive\tloss\t(earnings) | 34 | (63) | (2) | 3 | (9) | (2) |
| Total\trecognized | $88 | $ (12) | $90 | $2 | $(9) | $(1) |

(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	general	and	administrative	expenses	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	2015.

|  | Pension<br>Benefits |  | Postretirement<br>Benefits |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Net\tactuarial\tloss\t(gain) | $21 |  | $(1) |
| Prior\tservice\tcost\t(credit) | 4 |  | (2) |
| Total | $25 |  | $(3) |

# Assumptions

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

|  | 2014 | Pension	Benefits<br>2013 | 2012 | 2014 | Postretirement	Benefits<br>2013 | 2012 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Assumptions\tto\tdetermine\tbenefit\tobligations: |  |  |  |  |  |  |
| Discount\trate | \t3.90% | \t4.80% | \t3.85% | \t3.25% | \t3.65% | \t3.30% |
| Rate\tof\tcompensation\tincrease | \t4.49% | \t4.48% | \t4.48% | \tN/A | \tN/A | \tN/A |
| Assumptions\tto\tdetermine\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Discount\trate | \t4.80% | \t3.85% | \t4.65% | \t3.65% | \t3.30% | \t4.25% |
| Rate\tof\tcompensation\tincrease | \t4.49% | \t4.48% | \t4.97% | \tN/A | \tN/A | \tN/A |
| Expected\treturn\ton\tplan\tassets | \t5.42% | \t5.48% | \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. As	a	result	of	the	discount	rate	decrease,	Devon's	benefit	obligations	increased	approximately	$135	million	for	the	year	ended	December	31,	2014.

Rate	of	compensation	increase	–	For	measurement	of	the	2014	benefit	obligation	for	the	pension	plans,	a	4.49	percent	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	United	States.	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.	As	a	result	of	the	mortality	rate assumption	update,	Devon's	benefit	obligation	increased	approximately	$61	million	for	the	year	ended	December	31,	2014.

Other	assumptions	–	For	measurement	of	the	2014	benefit	obligation	for	the	other	postretirement	medical	plans,	a	7.7	percent	annual	rate	of	increase	in	the	per capita	cost	of	covered	health	care	benefits	was	assumed	for

2015.	The	rate	was	assumed	to	decrease	annually	to	an	ultimate	rate	of	5	percent	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,	2014	by	less	than	$1	million	and	would	change	the	2014	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.

|  | 2014 | 2013 |
| :--- | :--- | :--- |
| Fixed\tincome | 70% | 70% |
| Equity | 20% | 20% |
| Other | 10% | 10% |

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

|  | Actual<br>Allocation | Total | Level	1<br>Inputs | Level	2<br>Inputs | Level	3<br>Inputs |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 35.2% | $405 | $50 | $355 | $— |
| Corporate\tbonds | 31.7% | 364 | 269 | 95 | — |
| Other\tbonds | 2.6% | 30 | 30 | — | — |
| Total\tfixed-income\tsecurities | 69.5% | 799 | 349 | 450 | — |
| Equity\tsecurities: |  |  |  |  |  |
| Global\t(large,\tmid,\tsmall\tcap) | 17.2% | 197 | — | 197 | — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\tand\talternative\tinvestments | 9.7% | 112 | — | — | 112 |
| Short-term\tinvestments | 3.6% | 41 | 15 | 26 | — |
| Total\tother\tsecurities | 13.3% | 153 | 15 | 26 | 112 |
| Total\tinvestments | 100.0% | $1,149 | $364 | $673 | $112 |

|  | Actual<br>Allocation | Total | Level	1<br>Inputs | Level	2<br>Inputs | Level	3<br>Inputs |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 24.0% | $241 | $69 | $172 | $— |
| Corporate\tbonds | 39.5% | 398 | 286 | 112 | — |
| Other\tbonds | 3.1% | 31 | 31 | — | — |
| Total\tfixed-income\tsecurities | 66.6% | 670 | 386 | 284 | — |
| Equity\tsecurities: |  |  |  |  |  |
| Global\t(large,\tmid,\tsmall\tcap) | 19.0% | 190 | — | 190 | — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\tand\talternative\tinvestments | 12.5% | 127 | 15 | — | 112 |
| Short-term\tinvestments | 1.9% | 19 | — | 19 | — |
| Total\tother\tsecurities | 14.4% | 146 | 15 | 19 | 112 |
| Total\tinvestments | 100.0% | $1,006 | $401 | $493 | $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	United	States	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	United	States	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.

Included	below	is	a	summary	of	the	changes	in	Devon's	Level	3	plan	assets	(in	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 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Devon's\t2015\tcontributions | $10 |  | $3 |
| Benefit\tpayments: |  |  |  |
| 2015 | $73 |  | $3 |
| 2016 | $75 |  | $3 |
| 2017 | $79 |  | $3 |
| 2018 | $82 |  | $3 |
| 2019 | $86 |  | $2 |
| 2020\tto\t2024 | $466 |  | $8 |

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	2015,	the	$10	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	several	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| 401(k)\tand\tenhanced\tcontribution\tplans | $49 | $41 | $36 |
| Canadian\tpension\tand\tsavings\tplans | 20 | 26 | 23 |
| Total | $69 | $67 | $59 |

# 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.

# Dividends

Devon	paid	common	stock	dividends	of	$386	million,	$348	million	and	$324	million	in	2014,	2013	and	2012,	respectively.	The	quarterly	cash	dividend	was $0.20	per	share	in	the	first	quarter	of	2012.	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.

# 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.

# Distributions	to	Noncontrolling	Interests

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

# Subsidiary	Equity	Transactions

Periodically,	EnLink	enters	into	Equity	Distribution	Agreements	("EDAs")	facilitating	the	selling	of	common	units	representing	limited	partner	interests.	In	2014, EnLink	sold	approximately	14.8	million	common	units	under	these	EDAs,	generating	net	proceeds	of	approximately	$410	million.	EnLink	used	the	net	proceeds	for general	partnership	purposes,	to	fund	working	capital,	capital	expenditures	and	debt	repayments.	Subsequent	to	these	sales,	Devon's	ownership	interest	in	EnLink	was 49%.

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	natural	gas	and	NGLs	produced	and	sold.	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	is	a	schedule	by	year	of	Devon's	commitments	that	have	initial	or	remaining	noncancelable	terms	in	excess	of	one	year	as	of	December	31,	2014.

| Year	Ending	December	31, | Purchase<br>Obligations | and<br>Facility<br>Obligations | Operational<br>Agreements | Office	and<br>Equipment<br>Leases |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |  |
| 2015 | $663 | $234 | $943 | $72 |
| 2016 | 809 | 116 | 919 | 50 |
| 2017 | 885 | 77 | 890 | 50 |
| 2018 | 920 | 13 | 856 | 45 |
| 2019 | 895 | 1 | 334 | 39 |
| Thereafter | 1,134 | 5 | 1,142 | 149 |
| Total | $5,306 | $446 | $5,084 | $405 |

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	general	and	administrative	expenses	under operating	leases,	net	of	sub-lease	income,	was	$64	million,	$26	million	and	$42	million	in	2014,	2013	and	2012,	respectively.

The	following	tables	provide	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,	2014	and	December	31,	2013.	Therefore,	such	financial	assets	and	liabilities	are	not	presented	in	the	following	tables. Additionally,	information	regarding	the	fair	values	of	midstream,	goodwill	and	pension	plan	assets	is	provided	in	Note	5,	Note	12	and	Note	15,	respectively.

|  |  |  | Fair	Value	Measurements	Using: | 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 |
|  |  |  | (In\tmillions) |  |  |
| December\t31,\t2014\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $950 | $950 | $340 | $610 | $— |
| Oil,\tgas\tand\tNGL\tcommodity\tderivatives | $1,968 | $1,968 | $— | $1,968 | $— |
| Oil,\tgas\tand\tNGL\tcommodity\tderivatives | $(51) | $(51) | $— | $(51) | $— |
| Midstream\tcommodity\tderivatives | $27 | $27 | $— | $27 | $— |
| Midstream\tcommodity\tderivatives | $(5) | $(5) | $— | $(5) | $— |
| 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) | $— |
| December\t31,\t2013\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $5,305 | $5,305 | $4,191 | $1,114 | $— |
| Long-term\tinvestments | $62 | $62 | $— | $— | $62 |
| Oil,\tgas\tand\tNGL\tcommodity\tderivatives | $103 | $103 | $— | $103 | $— |
| Oil,\tgas\tand\tNGL\tcommodity\tderivatives | $(120) | $(120) | $— | $(120) | $— |
| Foreign\tcurrency\tderivatives | $(1) | $(1) | $— | $(1) | $— |
| Debt | $(12,022) | $(12,908) | $— | $(12,908) | $— |

# Level	1	Fair	Value	Measurements

Cash	equivalents	–	Amounts	consist	primarily	of	U.S.	and	Canadian	treasury	securities	and	money	market	investments.	The	fair	value	approximates	the	carrying value.

Cash	equivalents	–	Amounts	consist	primarily	of	Canadian	agency	and	provincial	securities	and	commercial	paper	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	value	of	Devon's	commercial	paper	and	credit	facility	are	the	carrying	values.

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

Long-term	investments	–	Devon's	long-term	investments	as	of	December	31,	2013	consisted	entirely	of	auction	rate	securities.	In	the	first	quarter	of	2014,	Devon redeemed	all	these	securities	for	approximately	$57	million,	or	$5	million	below	their	carrying	value.

# 20. Discontinued	Operations

In	2012,	Devon	incurred	a	loss	related	to	discontinued	operations	of	$16	million	($21	million	net	of	taxes)	for	the	sale	of	assets	in	Angola.	Devon	did	not	have operating	revenues	related	to	discontinued	operations	during	2012.

# 21. 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	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	22.

With	the	formation	of	EnLink	in	the	first	quarter	of	2014,	Devon	considers	EnLink,	combined	with	the	General	Partner,	to	be	an	operating	segment	that	is	distinct from	its	existing	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. | Canada | EnLink | Eliminations | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Year\tEnded\tDecember\t31,\t2014: |  |  |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $14,862 | $2,063 | $2,641 | $— | $19,566 |
| Intersegment\trevenues | $— | $— | $859 | $(859) | $— |
| Depreciation,\tdepletion\tand\tamortization | $2,479 | $560 | $280 | $— | $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 | $4,388 | $(657) | $328 | $— | $4,059 |
| Income\ttax\texpense | $1,797 | $495 | $76 | $— | $2,368 |
| Net\tearnings\t(loss) | $2,591 | $(1,152) | $252 | $— | $1,691 |
| Net\tearnings\tattributable\tto\tnoncontrolling\tinterests | $1 | $— | $83 | $— | $84 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $2,590 | $(1,152) | $169 | $— | $1,607 |
| Property\tand\tequipment,\tnet | $24,572 | $6,790 | $4,934 | $— | $36,296 |
| Total\tassets | $32,147 | $8,517 | $10,097 | $(124) | $50,637 |
| Capital\texpenditures | $11,245 | $1,344 | $970 | $— | $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 |
| Year\tEnded\tDecember\t31,\t2012: |  |  |  |  |  |
| Revenues\tfrom\texternal\tcustomers | $6,098 | $2,600 | $803 | $— | $9,501 |
| Intersegment\trevenues | $— | $— | $1,105 | $(1,105) | $— |
| Depreciation,\tdepletion\tand\tamortization | $1,679 | $987 | $145 | $— | $2,811 |
| Asset\timpairments | $1,845 | $163 | $16 | $— | $2,024 |
| Interest\texpense | $343 | $82 | $— | $(19) | $406 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | $(372) | $(73) | $128 | $— | $(317) |
| Income\ttax\texpense\t(benefit) | $(143) | $(35) | $46 | $— | $(132) |
| Net\tearnings\t(loss) | $(229) | $(38) | $82 | $— | $(185) |
| Property\tand\tequipment,\tnet | $16,622 | $8,955 | $1,739 | $— | $27,316 |
| Total\tassets | $22,050 | $19,070 | $2,206 | $— | $43,326 |
| Capital\texpenditures | $6,159 | $1,963 | $352 | $— | $8,474 |

# 22. 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.	Unless otherwise	noted,	this	supplemental	information	excludes	amounts	for	all	periods	presented	related	to	Devon's	discontinued	operations.

# 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.	The	proceeds	received	from	our	joint	venture transactions	at	closing	have	not	been	netted	against	the	costs	incurred.	At	December	31,	2014,	our	partners'	remaining	commitments	to	fund	our	future	costs	associated with	these	joint	venture	transactions	totaled	approximately	$250	million.

Pursuant	to	the	full	cost	method	of	accounting,	Devon	capitalizes	certain	of	its	general	and	administrative	expenses	that	are	related	to	property	acquisition, exploration	and	development	activities.	Such	capitalized

expenses,	which	are	included	in	the	costs	shown	in	the	preceding	tables,	were	$376	million,	$368	million	and	$359	million	in	the	years	2014,	2013	and	2012, 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	$45	million,	$42	million	and	$36	million	in	the	years	2014,	2013	and 2012,	respectively.

# Capitalized	Costs

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

|  |  | December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Proved\tproperties | $59,849 | $15,889 | $75,738 |
| Unproved\tproperties | 1,460 | 1,292 | 2,752 |
| Total\toil\t&amp;\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 |

|  |  | December	31,	2013 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Proved\tproperties | $51,366 | $22,629 | $73,995 |
| Unproved\tproperties | 1,277 | 1,514 | 2,791 |
| Total\toil\t&amp;\tgas\tproperties | 52,643 | 24,143 | 76,786 |
| Accumulated\tDD&amp;A | (35,848) | (16,613) | (52,461) |
| Net\tcapitalized\tcosts | $16,795 | $7,530 | $24,325 |

The	following	is	a	summary	of	Devon's	oil	and	gas	properties	not	subject	to	amortization	as	of	December	31,	2014.

|  |  |  |  | Prior	to |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 | 2012 | Total |
|  |  |  | (In\tmillions) |  |  |
| Acquisition\tcosts | $973 | $127 | $140 | $650 | $1,890 |
| Exploration\tcosts | 111 | 76 | 68 | 107 | 362 |
| Development\tcosts | 103 | 48 | \t 121 | 69 | 341 |
| Capitalized\tinterest | 43 | 38 | 30 | 48 | 159 |
| Total\toil\tand\tgas\tproperties\tnot\tsubject\tto\tamortization | $1,230 | $289 | $359 | $874 | $2,752 |

Included	in	the	$2.8	billion	of	oil	and	gas	properties	not	subject	to	amortization	are	approximately	$2.2	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	Eagle	Ford	in	Texas.	Based	on	Devon's	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	developing	the	newly	acquired	Eagle	Ford	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	depreciation,	depletion	and	amortization and	after	giving	effect	to	permanent	differences.

|  |  | December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| 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 | — | \t 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 |

(1) In	the	fourth	quarter	of	2014,	Devon	recognized	a	$1.9	billion	Canadian	goodwill	impairment	that	is	not	reflected	in	this	table.

|  |  | December	31,	2013 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| 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 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tsales | $4,679 | $2,474 | $7,153 |
| Lease\toperating\texpenses | (1,059) | (1,015) | (2,074) |
| General\tand\tadministrative\texpenses | (159) | (137) | (296) |
| Production\tand\tproperty\ttaxes | (340) | (55) | (395) |
| Depreciation,\tdepletion\tand\tamortization | (1,563) | (963) | (2,526) |
| Asset\timpairments | (1,793) | (163) | (1,956) |
| Accretion\tof\tasset\tretirement\tobligations | (40) | (69) | (109) |
| Income\ttax\tbenefit\t(expense) | 99 | (3) | 96 |
| Results\tof\toperations | $(176) | $69 | $(107) |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $8.55 | $14.41 | $10.12 |

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

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2011 | \t\t\t\t\t168 | \t\t\t\t80 | \t\t\t\t\t248 |
| Revisions\tdue\tto\tprices | (1) | (5) | (6) |
| Revisions\tother\tthan\tprice | (6) | (2) | (8) |
| Extensions\tand\tdiscoveries | 65 | 7 | 72 |
| Production | (21) | (15) | (36) |
| December\t31,\t2012 | 205 | 65 | 270 |
| Revisions\tdue\tto\tprices | 1 | (1) | — |
| Revisions\tother\tthan\tprice | (18) | — | (18) |
| Extensions\tand\tdiscoveries | 69 | 7 | 76 |
| Purchase\tof\treserves | 1 | — | 1 |
| Production | (28) | (15) | (43) |
| Sale\tof\treserves | (1) | — | (1) |
| December\t31,\t2013 | 229 | 56 | 285 |
| Revisions\tdue\tto\tprices | (1) | — | (1) |
| Revisions\tother\tthan\tprice | (38) | 1 | (37) |
| Extensions\tand\tdiscoveries | 94 | 5 | 99 |
| Purchase\tof\treserves | 132 | — | 132 |
| Production | (48) | (10) | (58) |
| Sale\tof\treserves | (17) | (29) | (46) |
| December\t31,\t2014 | 351 | 23 | 374 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 146 | 73 | 219 |
| December\t31,\t2012 | 166 | 62 | 228 |
| December\t31,\t2013 | 194 | 56 | 250 |
| December\t31,\t2014 | 255 | 23 | 278 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 139 | 65 | 204 |
| December\t31,\t2012 | 155 | 56 | 211 |
| December\t31,\t2013 | 178 | 51 | 229 |
| December\t31,\t2014 | 224 | 19 | 243 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 22 | 7 | 29 |
| December\t31,\t2012 | 39 | 3 | 42 |
| December\t31,\t2013 | 35 | — | 35 |
| December\t31,\t2014 | 96 | — | 96 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2011 | \t\t\t\t— | \t\t\t\t457 | \t\t\t\t457 |
| Revisions\tdue\tto\tprices | — | 14 | 14 |
| Revisions\tother\tthan\tprice | — | 7 | 7 |
| Extensions\tand\tdiscoveries | — | 67 | 67 |
| Production | — | (17) | (17) |
| December\t31,\t2012 | — | 528 | 528 |
| Revisions\tdue\tto\tprices | — | (11) | (11) |
| Revisions\tother\tthan\tprice | — | 16 | 16 |
| Extensions\tand\tdiscoveries | — | 38 | 38 |
| Production | — | (19) | (19) |
| December\t31,\t2013 | — | 552 | 552 |
| Revisions\tdue\tto\tprices | — | (37) | (37) |
| Revisions\tother\tthan\tprice | — | 18 | 18 |
| Extensions\tand\tdiscoveries | — | 8 | 8 |
| Production | — | (20) | (20) |
| December\t31,\t2014 | — | 521 | 521 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | — | 90 | 90 |
| December\t31,\t2012 | — | 99 | 99 |
| December\t31,\t2013 | — | 111 | 111 |
| December\t31,\t2014 | — | 137 | 137 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | — | 90 | 90 |
| December\t31,\t2012 | — | 99 | 99 |
| December\t31,\t2013 | — | 111 | 111 |
| December\t31,\t2014 | — | 137 | 137 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | — | 367 | 367 |
| December\t31,\t2012 | — | 429 | 429 |
| December\t31,\t2013 | — | 441 | 441 |
| December\t31,\t2014 | — | 384 | 384 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2011 | \t\t\t\t9,507 | \t\t\t\t979 | \t\t\t\t10,486 |
| Revisions\tdue\tto\tprices | (831) | (99) | (930) |
| Revisions\tother\tthan\tprice | (287) | (33) | (320) |
| Extensions\tand\tdiscoveries | 1,124 | 34 | 1,158 |
| Purchase\tof\treserves | 2 | — | 2 |
| Production | (752) | (186) | (938) |
| Sale\tof\treserves | (1) | (11) | (12) |
| 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) | (1,661) |
| December\t31,\t2014 | 7,651 | 36 | 7,687 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 7,957 | 951 | 8,908 |
| December\t31,\t2012 | 7,391 | 679 | 8,070 |
| December\t31,\t2013 | 7,707 | 752 | 8,459 |
| December\t31,\t2014 | 6,948 | 36 | 6,984 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 7,409 | 862 | 8,271 |
| December\t31,\t2012 | 7,091 | 624 | 7,715 |
| December\t31,\t2013 | 7,425 | 680 | 8,105 |
| December\t31,\t2014 | 6,746 | 34 | 6,780 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 1,550 | 28 | 1,578 |
| December\t31,\t2012 | 1,371 | 5 | 1,376 |
| December\t31,\t2013 | 843 | 6 | 849 |
| December\t31,\t2014 | 703 | — | 703 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2011 | \t\t\t\t\t525 | \t\t\t\t27 | \t\t\t\t552 |
| Revisions\tdue\tto\tprices | (19) | (5) | (24) |
| Revisions\tother\tthan\tprice | (13) | — | (13) |
| Extensions\tand\tdiscoveries | 114 | 2 | 116 |
| Production | (36) | (4) | (40) |
| 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 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 402 | 26 | 428 |
| December\t31,\t2012 | 431 | 20 | 451 |
| December\t31,\t2013 | 468 | 23 | 491 |
| December\t31,\t2014 | 486 | — | 486 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 372 | 24 | 396 |
| December\t31,\t2012 | 406 | 19 | 425 |
| December\t31,\t2013 | 442 | 21 | 463 |
| December\t31,\t2014 | 467 | — | 467 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 123 | 1 | 124 |
| December\t31,\t2012 | 140 | — | 140 |
| December\t31,\t2013 | 84 | — | 84 |
| December\t31,\t2014 | 92 | — | 92 |

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |
| December\t31,\t2011 | \t\t\t\t2,278 | \t\t\t\t727 | \t\t\t\t3,005 |
| Revisions\tdue\tto\tprices | (159) | (12) | (171) |
| Revisions\tother\tthan\tprice | (67) | (1) | (68) |
| Extensions\tand\tdiscoveries | 367 | 82 | 449 |
| Production | (183) | (67) | (250) |
| Sale\tof\treserves | — | (2) | (2) |
| December\t31,\t2012 | 2,236 | 727 | 2,963 |
| 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 | 2,205 | 758 | 2,963 |
| 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 | 2,205 | 549 | 2,754 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 1,875 | 348 | 2,223 |
| December\t31,\t2012 | 1,829 | 294 | 2,123 |
| December\t31,\t2013 | 1,947 | 315 | 2,262 |
| December\t31,\t2014 | 1,900 | 165 | 2,065 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 1,746 | 323 | 2,069 |
| December\t31,\t2012 | 1,743 | 278 | 2,021 |
| December\t31,\t2013 | 1,857 | 297 | 2,154 |
| December\t31,\t2014 | 1,815 | 162 | 1,977 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |
| December\t31,\t2011 | 403 | 379 | 782 |
| December\t31,\t2012 | 407 | 433 | 840 |
| December\t31,\t2013 | 258 | 443 | 701 |
| December\t31,\t2014 | 305 | 384 | 689 |

(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	natural	gas	liquids	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	2014	(in	MMBoe).

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2013 | \t258 | 443 | \t701 |
| Extensions\tand\tdiscoveries | \t153 | 8 | \t161 |
| Revisions\tdue\tto\tprices | (1) | (34) | \t (35) |
| Revisions\tother\tthan\tprice | \t (61) | 18 | \t (43) |
| Sale\tof\treserves | (4) | (2) | (6) |
| Conversion\tto\tproved\tdeveloped\treserves | \t (40) | (49) | \t (89) |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2014 | \t305 | 384 | \t689 |

At	December	31,	2014,	Devon	had	689	MMBoe	of	proved	undeveloped	reserves.	This	represents	a	2	percent	decrease	as	compared	to	2013	and	represents	25 percent	of	total	proved	reserves.	Drilling	and	development	activities	increased	Devon's	proved	undeveloped	reserves	161	MMBoe	and	resulted	in	the	conversion	of	89 MMBoe,	or	13	percent,	of	the	2013	proved	undeveloped	reserves	to	proved	developed	reserves.	Costs	incurred	related	to	the	development	and	conversion	of	Devon's proved	undeveloped	reserves	were	approximately	$1.0	billion	for	2014.	Additionally,	revisions	other	than	price	decreased	Devon's	proved	undeveloped	reserves	43 MMBoe	primarily	due	to	evaluations	of	certain	U.S.	onshore	dry-gas	areas,	which	Devon	does	not	expect	to	develop	in	the	next	five	years.	The	largest	revisions,	which were	approximately	69	MMBoe,	relate	to	the	dry-gas	areas	in	the	Barnett	Shale	in	north	Texas.

A	significant	amount	of	Devon's	proved	undeveloped	reserves	at	the	end	of	2014	related	to	its	Jackfish	operations.	At	December	31,	2014	and	2013,	Devon's Jackfish	proved	undeveloped	reserves	were	384	MMBoe	and	441	MMBoe,	respectively.	Development	schedules	for	the	Jackfish	reserves	are	primarily	controlled	by	the need	to	keep	the	processing	plants	at	their	35,000	barrel	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	though	the	year	2031.

# Price	Revisions

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.

2012	–	Reserves	decreased	171	MMBoe	primarily	due	to	lower	gas	prices.	Of	this	decrease,	100	MMBoe	related	to	the	Barnett	Shale	and	25	MMBoe	related	to the	Rocky	Mountain	area.

# Revisions	Other	Than	Price

Total	revisions	other	than	price	for	2014,	2013	and	2012	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

2014	–	Of	the	211	MMBoe	of	extensions	and	discoveries,	70	MMBoe	related	to	the	Permian	Basin	in	west	Texas	and	southeast	New	Mexico,	54	MMBoe	related to	the	Eagle	Ford	in	south	Texas,	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	in	north	Oklahoma.

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.

2012	–	Of	the	449	MMBoe	of	extensions	and	discoveries,	151	MMBoe	related	to	the	Cana-Woodford	Shale,	95	MMBoe	related	to	the	Barnett	Shale,	72	MMBoe related	to	the	Permian	Basin,	67	MMBoe	related	to	Jackfish,	16	MMBoe	related	to	the	Rocky	Mountain	area	and	18	MMBoe	related	to	the	Granite	Wash	area.

The	2012	extensions	and	discoveries	included	229	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	including	134	MMBoe	at	the	Cana- Woodford	Shale	and	82	MMBoe	at	the	Barnett	Shale.

# Purchase	of	Reserves

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

# Sale	of	Reserves

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

# Standardized	Measure

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

|  |  | Year	Ended	December	31,	2014 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| 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 |
|  |  | (In\tmillions) |  |
| 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 |

|  |  | Year	Ended	December	31,	2012 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Future\tcash\tinflows | $55,297 | $33,570 | $88,867 |
| Future\tcosts: |  |  |  |
| Development | (6,556) | (6,211) | (12,767) |
| Production | (24,265) | (16,611) | (40,876) |
| Future\tincome\ttax\texpense | (6,542) | (1,992) | (8,534) |
| Future\tnet\tcash\tflow | 17,934 | 8,756 | 26,690 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (9,036) | (4,433) | (13,469) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $8,898 | $4,323 | $13,221 |

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	2014	estimates,	Devon's	future	realized	prices	were	assumed	to	be	$87.14	per	barrel	of	oil,	$57.25	per	barrel	of bitumen,	$3.94	per	Mcf	of	gas	and	$25.05	per	barrel	of	natural	gas	liquids.	Of	the	$10.8	billion	of	future	development	costs	as	of	the	end	of	2014,	$2.2	billion,	$1.9 billion	and	$1.0	billion	are	estimated	to	be	spent	in	2015,	2016	and	2017,	respectively.

Future	development	costs	include	not	only	development	costs	but	also	future	asset	retirement	costs.	Included	as	part	of	the	$10.8	billion	of	future	development costs	are	$1.5	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2014 | 2013 | 2012 |
|  |  | (In\tmillions) |  |
| Beginning\tbalance | $15,741 | $13,221 | $17,844 |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | 2,561 | 3,018 | (9,889) |
| Oil,\tbitumen,\tgas\tand\tNGL\tsales,\tnet\tof\tproduction\tcosts | (6,865) | (5,613) | (4,388) |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (768) | 399 | (1,094) |
| Extensions\tand\tdiscoveries,\tnet\tof\tfuture\tdevelopment\tcosts | 4,836 | 4,047 | 4,669 |
| Purchase\tof\treserves | 6,422 | 14 | 18 |
| Sales\tof\treserves\tin\tplace | (2,384) | (44) | (25) |
| Revisions\tof\tquantity\testimates | (746) | (1,040) | 162 |
| Previously\testimated\tdevelopment\tcosts\tincurred\tduring\tthe\tperiod | 1,933 | 1,986 | 1,321 |
| Accretion\tof\tdiscount | 1,746 | 1,940 | 1,420 |
| Other,\tprimarily\tchanges\tin\ttiming\tand\tforeign\texchange\trates | (107) | (583) | 113 |
| Net\tchange\tin\tincome\ttaxes | (1,895) | (1,604) | 3,070 |
| Ending\tbalance | $20,474 | $15,741 | $13,221 |

# 23. Supplemental	Quarterly	Financial	Information	(Unaudited)

Following	is	a	summary	of	Devon's	unaudited	interim	results	of	operations.

|  | First | Second | Third | Fourth | Full |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Quarter | Quarter | Quarter | Quarter | Year |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | $3,725 | $4,510 | $5,336 | $5,995 | $19,566 |
| Earnings\t(loss)\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 |

|  | First<br>Quarter | Second<br>Quarter | Third<br>Quarter | Fourth<br>Quarter | Full<br>Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Operating\trevenues | $1,971 | $3,088 | $2,714 | $2,624 | $10,397 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | $(1,962) | $997 | $639 | $475 | $149 |
| Net\tearnings\t(loss)\tattributable\tto\tDevon | $(1,339) | $683 | $429 | $207 | $(20) |
| Basic\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $(3.34) | $1.69 | $1.06 | $0.51 | $(0.06) |
| Diluted\tnet\tearnings\t(loss)\tper\tshare\tattributable\tto\tDevon | $(3.34) | $1.68 | $1.05 | $0.51 | $(0.06) |

# Net	Earnings	(Loss)	Attributable	to	Devon

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

The	first	quarter	of	2013	includes	U.S.	and	Canadian	property	and	equipment	impairments	totaling	$1.9	billion	($1.3	billion	after	income	taxes,	or	$3.25	per diluted	share).

# 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,	2014	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	18,	2015,	management	concluded	that	its	internal	control	over	financial reporting	was	effective	as	of	December	31,	2014.

The	effectiveness	of	our	internal	control	over	financial	reporting	as	of	December	31,	2014	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,	2014,	as	stated	in	their	report,	which	is	included	under "Item	8.	Financial	Statements	and	Supplementary	Data"	in	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	2014	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	30,	2015.

# 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	30,	2015.

# 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

4.12 Third	Supplemental	Indenture,	dated	January	23,	2006	to	Indenture	dated	as	of	July	8,	1998	among	Devon	OEI	Operating,	Inc.	as	Issuer,	Devon Energy	Production	Company,	L.P.	as	Successor	Guarantor,	and	Wells	Fargo	Bank	Minnesota,	N.A.,	as	Trustee,	relating	to	the	8.25%	Senior Notes	due	2018	(incorporated	by	reference	to	Exhibit	4.23	of	Registrant's	Form	10-K	for	the	year	ended	December	31,	2005;	File	No.	001- 32318).

10.3 First	Amendment	to	Credit	Agreement	dated	February	3,	2014,	to	the	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	February	7,	2014;	File	No.	001-32318).

10.27 Form	of	Notice	of	Grant	of	Performance	Restricted	Stock	Award	and	Award	Agreement	under	the	2009	Long-Term	Incentive	Plan	(as	amended and	restated	June	6,	2012)	between	Registrant	and	David	A.	Hager,	R.	Alan	Marcum,	Thomas	L.	Mitchell,	John	Richels,	Frank	W.	Rudolph, Darryl	G.	Smette,	Lyndon	C.	Taylor	and	Tony	D.	Vaughn	for	performance	based	restricted	stock	awarded	(incorporated	by	reference	to	Exhibit 10.25	to	Registrant's	Form	10-K	filed	February	28,	2014;	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.

# By:		/s/	JOHN	RICHELS

John	Richels

# 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: what percentage increase occurred from oct 24 , 2017 to oct 24 , 2018 of senior credit facility maturity?
Answer: 446%