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,	2012

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	29,	2012,	was	approximately	$23.3	billion,	based	upon the	closing	price	of	$57.99	per	share	as	reported	by	the	New	York	Stock	Exchange	on	such	date.	On	February	6,	2013,	406.0	million	shares	of	common	stock	were outstanding.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

Proxy	statement	for	the	2013	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 | 15 |
| Item\t1B.\t\tUnresolved\tStaff\tComments | 19 |
| Item\t3.\t\t\t\t\tLegal\tProceedings | 19 |
| Item\t4.\t\t\t\t\tMine\tSafety\tDisclosures | 19 |
| PART\tII |  |
| Item\t5.\t\t\t\t\t\tMarket\tfor\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 20 |
| Item\t6.\t\t\t\t\tSelected\tFinancial\tData | 22 |
| Item\t7.\t\t\t\t\t\tManagement's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 23 |
| Item\t7A.\t\tQuantitative\tand\tQualitative\tDisclosures\tabout\tMarket\tRisk | 44 |
| Item\t8.\t\t\t\t\tFinancial\tStatements\tand\tSupplementary\tData | 46 |
| Item\t9.\t\t\t\t\t\tChanges\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | \t102 |
| Item\t9A.\t\tControls\tand\tProcedures | \t102 |
| Item\t9B.\t\tOther\tInformation | \t102 |
| PART\tIII |  |
| Item\t10.\t\t\tDirectors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | \t103 |
| Item\t11.\t\t\tExecutive\tCompensation | \t103 |
| Item\t12.\t\t\t\tSecurity\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | \t103 |
| Item\t13.\t\t\tCertain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | \t103 |
| Item\t14.\t\t\tPrincipal\tAccountant\tFees\tand\tServices | \t103 |
| PART\tIV |  |
| Item\t15.\t\t\t\t\t\t\t\tExhibits\tand\tFinancial\tStatement\tSchedules | \t104 |
| Signatures | \t109 |

# INFORMATION	REGARDING	FORWARD-LOOKING	STATEMENTS

This	report	includes	forward-looking	statements	regarding	our	expectations	and	plans,	as	well	as	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,	2012	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;	political	or	regulatory	events;	general	economic	and	financial	market conditions;	and	other	factors	discussed	in	this	report.

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

# Items	1	and	2.	Business	and	Properties

# General

Devon	Energy	Corporation	("Devon")	is	a	leading	independent	energy	company	engaged	primarily	in	the	exploration,	development	and	production	of	oil,	natural gas	and	NGLs.	Our	operations	are	concentrated	in	various	North	American	onshore	areas	in	the	U.S.	and	Canada.	We	also	own	natural	gas	pipelines,	plants	and	treatment facilities	in	many	of	our	producing	areas,	making	us	one	of	North	America's	larger	processors	of	natural	gas.

Devon	pioneered	the	commercial	development	of	natural	gas	from	shale	and	coalbed	formations,	and	we	are	a	proven	leader	in	using	steam	to	produce	bitumen from	the	Canadian	oil	sands.	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, 2012,	we	had	approximately	5,700	employees.

Devon	files	or	furnishes	annual	reports	on	Form	10-K,	quarterly	reports	on	Form	10-Q	and	current	reports	on	Form	8-K	as	well	as	any	amendments	to	these reports	with	the	U.S.	Securities	and	Exchange	Commission	("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

We	strive	to	maximize	long-term	value	for	our	shareholders	by	delivering	strong	full-cycle	margins	on	our	assets	and	top-quartile	per	share	returns.	In	pursuit	of this	objective,	we	focus	on	growing	cash	flow	per	share,	adjusted	for	debt,	which	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:

•exercising	capital	allocation	and	investment	discipline;

•focusing	on	high-return	projects;

•	 maintaining	a	low	cost	structure;

•preserving	financial	strength	and	flexibility;	and

•balancing	our	production	and	resource	mix	between	oil,	natural	gas	and	NGLs.

We	hold	14	million	net	acres,	of	which	roughly	two-thirds	are	undeveloped,	providing	us	with	a	platform	for	future	growth.	An	important	factor	in	determining the	direction	of	our	growth	strategy,	particularly	our	capital	allocation,	is	the	current	and	forecasted	pricing	applicable	to	our	production.	Our	industry	had	been operating	in	an	environment	that	had	involved	depressed	North	American	gas	prices	contrasted	with	more	robust	prices	for	oil	and	NGLs.	Consequently,	with	a production	profile	that	is	approximately	60%	gas,	we	have	focused	our	recent	capital	programs	on	higher-margin,	liquids-based	resource	capture	and	development.	With recent	changes	in	market	conditions	that	have	led	to	challenged	prices	for	NGLs	and	Canadian	heavy	oil,	we	are	refining	our	capital	allocations	as	needed	and	evaluating other	investment	opportunities	to	maximize	and	accelerate	growth	in	cash	flow	per	debt-adjusted	share.

# Oil	and	Gas	Properties

# Property	Profiles

The	locations	of	our	key	properties	are	presented	on	the	following	map.	These	properties	include	those	that	currently	have	significant	proved	reserves	and production,	as	well	as	properties	that	do	not	currently	have	significant	levels	of	proved	reserves	or	production	but	are	expected	to	be	the	source	of	significant	future growth	in	proved	reserves	and	production.

The	following	table	outlines	a	summary	of	key	data	in	each	of	our	operating	areas	for	2012.	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	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 | Total<br>Net	Acres | Wells<br>Drilled |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | (In\tthousands) |  |
| U.S. |  |  |  |  |  |  |  |  |
| Barnett\tShale | \t 1,058 | 35.7% | 23.7% | \t227.5 | 33.3% | 21.3% | 620 | 322 |
| Cana-Woodford\tShale | 427 | 14.4% | 41.4% | 48.3 | 7.1% | 30.0% | 260 | 164 |
| Permian\tBasin | 227 | 7.6% | 79.6% | 61.6 | 9.0% | 77.1% | 1,530 | 241 |
| Gulf\tCoast/East\tTexas | 221 | 7.5% | 25.0% | 61.3 | 9.0% | 23.7% | 1,660 | 50 |
| Rocky\tMountains | 157 | 5.3% | 37.1% | 58.7 | 8.6% | 28.1% | 1,165 | 16 |
| Granite\tWash | 51 | 1.7% | 41.0% | 18.7 | 2.7% | 45.5% | 65 | 48 |
| Mississippian | 6 | 0.2% | 61.5% | 1.0 | 0.2% | 76.8% | 545 | 35 |
| Other | 89 | 3.1% | 32.6% | 22.5 | 3.3% | 29.2% | 1,155 | 71 |
| Total\tU.S. | \t 2,236 | 75.5% | 34.7% | \t499.7 | 73.2% | 31.5% | 7,000 | 947 |
| Canada |  |  |  |  |  |  |  |  |
| Canadian\tOil\tSands | 528 | 17.8% | 100.0% | 47.6 | 7.0% | \t100.0% | 90 | 16 |
| Lloydminster | 38 | 1.3% | 86.9% | 37.0 | 5.4% | 82.5% | 2,740 | 173 |
| Other | 161 | 5.4% | 32.4% | 98.0 | 14.4% | 20.2% | 4,245 | 72 |
| Total\tCanada | 727 | 24.5% | 84.3% | \t182.6 | 26.8% | 53.6% | 7,075 | 261 |
| Devon | \t 2,963 | \t100.0% | 46.9% | \t682.3 | \t100.0% | 37.4% | \t 14,075 | \t1,208 |

Barnett	Shale	—	This	is	our	largest	property	both	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.

We	are	the	largest	producer	in	the	Barnett	Shale.	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.	We	have	drilled	in	excess	of	5,000	wells	in	the Barnett	Shale	since	2002,	yet	we	still	have	several	thousand	remaining	drilling	locations.	In	2013,	we	plan	to	drill	approximately	150	wells,	focused	in	the	areas	with	the highest	liquids	content.

In	addition,	we	have	a	significant	processing	plant	and	gathering	system	in	north	Texas	to	service	these	properties.	Our	Bridgeport	plant	is	one	of	the	largest processing	plants	in	the	U.S.,	currently	with	650	MMcf	per	day	of	total	capacity,	and	an	additional	140	MMcf	expansion	expected	in	2013	to	accommodate	increasing demand	from	our	liquids-rich	drilling.	These	midstream	assets	also	include	an	extensive	pipeline	system	and	a	15	MBbls	per	day	NGL	fractionator.

Cana-Woodford	Shale	—	Our	acreage	is	located	primarily	in	Oklahoma's	Canadian,	Blaine,	Caddo	and	Dewey	counties.	The	Cana-Woodford	Shale	is	a	non- conventional	reservoir	and	produces	natural	gas,	NGLs	and	condensate.

The	Cana-Woodford	Shale	is	a	leading	growth	area	for	us	and	has	rapidly	emerged	as	one	of	the	most	economic	shale	plays	in	North	America.	We	are	the	largest leaseholder	and	the	largest	producer	in	the	Cana-Woodford	Shale.	During	2012,	we	increased	our	production	by	45	percent.	We	have	several	thousand	remaining	drilling locations.	In	2013,	we	plan	to	drill	approximately	150	wells.

In	addition,	we	have	a	significant	processing	plant	and	gathering	system	to	service	these	properties.	Our	Cana	plant	currently	has	200	MMcf	per	day	of	total capacity,	and	an	additional	150	MMcf	expansion	expected	in	2013	to	accommodate	increasing	demand	from	our	liquids-rich	drilling.

Permian	Basin	—	Our	acreage	is	located	in	various	counties	in	west	Texas	and	southeast	New	Mexico.	These	properties	have	been	a	legacy	asset	for	us	and continue	to	offer	both	exploration	and	low-risk	development	opportunities.	We	entered	into	a	joint	venture	arrangement	with	Sumitomo	in	2012,	covering	approximately 650,000	net	acres	in	the	Cline	Shale	and	Midland-Wolfcamp	Shale	and	further	strengthening	the	capital	efficiency	of	our	exploration	programs.	In	addition	to	the	Cline and	Wolfcamp	Shale	activity,	our	current	drilling	activity	continues	to	target	conventional	and	non-conventional	oil	and	liquids-rich	gas	targets	within	the	Conventional Delaware,	Bone	Spring,	Midland-Wolfcamp,	Wolfberry	and	Avalon	Shale	plays.	In	2013,	we	plan	to	drill	approximately	300	wells.

Gulf	Coast/East	Texas—	Our	acreage	is	located	primarily	in	Harrison,	Marion,	Panola	and	Shelby	counties	in	the	Carthage/Groesbeck	areas	of	east	Texas.	These wells	produce	natural	gas	and	NGLs	from	conventional	reservoirs.	In	2013,	we	plan	to	drill	approximately	10	wells,	focused	in	the	areas	with	the	highest	liquids	content.

Rocky	Mountains—	These	leases	are	primarily	concentrated	in	the	Washakie	area	in	Wyoming's	Carbon	and	Sweetwater	counties.	The	Washakie	wells	produce natural	gas	and	NGLs	from	conventional	reservoirs.	Targeting	the	Almond	and	Lewis	formations,	we	have	been	among	the	most	active	drillers	in	the	Washakie	area	for many	years.	In	2013,	we	plan	to	drill	approximately	25	wells,	focused	in	the	areas	with	the	highest	liquids	content.

In	recent	years	we	also	have	acquired	a	significant	acreage	position	in	the	DJ	Basin.	This	acquired	acreage,	along	with	our	legacy	Powder	River	Basin	acreage, primarily	targets	oil	in	the	Niobrara	formation.	These	acres	are	principally	located	in	eastern	Wyoming	and	are	being	explored	using	3D	seismic	to	identify	appropriate drilling	zones.	Furthermore,	in	early	2012,	we	entered	into	a	joint	venture	arrangement	with	Sinopec	to	explore	and	develop	the	Niobrara	and	other	new	venture properties.

Granite	Wash	—	Our	acreage	is	concentrated	in	the	Texas	Panhandle	and	western	Oklahoma.	These	properties	produce	liquids	and	natural	gas	from	conventional reservoirs.	Our	legacy	land	position	in	the	Granite	Wash	is	held	by	production	and	provides	some	of	the	best	economics	in	our	portfolio.	High	initial	production	rates and	strong	liquids	yields	contribute	to	the	superior	full-cycle	rates	of	return.	In	2013,	we	plan	to	drill	approximately	50	wells.

Mississippian	—	These	properties	represent	some	of	our	newest	assets,	with	most	of	our	position	acquired	since	2011.	Located	in	northern	Oklahoma	and southern	Kansas,	these	acres	target	oil	in	the	Mississippian	Lime	and	Woodford	Shale	and	are	being	explored	and	developed	under	our	joint	venture	arrangement	with Sinopec	and	independently	by	us	on	the	acreage	outside	of	our	area	of	mutual	interest	with	Sinopec.	In	2013,	we	plan	to	drill	approximately	400	wells.

# Canada

Canadian	Oil	Sands	—	We	are	the	first	and	only	U.S.-based	independent	energy	company	to	develop	and	operate	a	bitumen	oil	sands	project	in	Canada.	We currently	have	two	main	projects,	Jackfish	and	Pike,	located	in	Alberta,	Canada.

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. The	first	phase	of	Jackfish	is	fully	operational	with	a

gross	facility	capacity	of	35	MBbls	per	day.	Jackfish	production	increased	37	percent	in	2012	as	the	second	phase	of	Jackfish,	which	came	on-line	in	the	second	quarter of	2011,	continued	to	increase	production.	Construction	of	a	third	phase	began	in	2012	with	plant	startup	expected	by	year-end	2014.	We	expect	each	phase	to	maintain a	flat	production	profile	for	greater	than	20	years	at	an	average	net	production	rate	of	approximately	25-30	MBbls	per	day.

Our	Pike	oil	sands	acreage	is	situated	directly	to	the	south	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,	2012.	We	filed	a	regulatory	application	in	2012	for	the	first	phase of	this	project,	with	gross	capacity	of	105	MBbls	per	day,	in	which	we	hold	a	50	percent	interest.

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	Jackfish,	and	eventually	our	Pike,	heavy	oil	production	with	condensate	or	other	blend-stock	and	transport	the	combined	product	to	the	Edmonton area	for	sale.	The	Access	Pipeline	system	is	currently	undergoing	a	capacity	expansion	that	we	anticipate	will	be	completed	in	late	2014.	This	expansion,	in	which	we have	a	50%	interest,	is	expected	to	create	adequate	capacity	to	transport	our	anticipated	Jackfish	and	Pike	heavy	oil	production	to	the	Edmonton	market hub.	Additionally,	it	will	increase	the	transport	capacity	of	condensate	diluent	available	at	our	thermal	oil	facilities.

Lloydminster	—	Our	Lloydminster	properties	are	located	to	the	south	and	east	of	Jackfish	in	eastern	Alberta	and	western	Saskatchewan.	Lloydminster	produces heavy	oil	by	conventional	means,	without	the	need	for	steam	injection.

The	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.	We	have	drilled	approximately	2,500	wells	in	the	area	since	2003.	In	2013,	we	plan	to	drill	approximately	155	wells.

# 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 2012	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	herein.	Reserve	estimates	filed	with	the	DOE	are	based	upon	the	same	underlying	technical	and	economic	assumptions	as	the	estimates	of	our	reserves included	herein.	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	and	gas,	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	twelve	years,	including	the	past	five	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	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	2012,	we	engaged	two	such	firms	to	audit	92	percent	of our	proved	reserves.	LaRoche	Petroleum	Consultants,	Ltd.	audited	91	percent	of	our	2012	U.S.	reserves,	and	Deloitte	audited	93	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	separately	with	our	senior	reserves	engineering personnel	and	our	independent	petroleum	consultants	at	those	meetings.	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.

# Production,	Production	Prices	and	Production	Costs

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

| Year	Ended	December	31, | Oil	(MMBbls) | Bitumen	(MMBbls) | Gas	(Bcf) | NGLs	(MMBbls) | Total	(MMBoe) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2012 |  |  |  |  |  |
| Barnett\tShale | 1 | — | 393 | 17 | 83 |
| Jackfish | — | 17 | — | — | 17 |
| U.S. | 21 | — | 752 | 36 | 183 |
| Canada | 15 | 17 | 186 | 4 | 67 |
| Total\tNorth\tAmerica | 36 | 17 | 938 | 40 | 250 |
| 2011 |  |  |  |  |  |
| Barnett\tShale | 1 | — | 367 | 16 | 78 |
| Jackfish | — | 13 | — | — | 13 |
| U.S. | 17 | — | 740 | 33 | 173 |
| Canada | 15 | 13 | 213 | 4 | 67 |
| Total\tNorth\tAmerica | 32 | 13 | 953 | 37 | 240 |
| 2010 |  |  |  |  |  |
| Barnett\tShale | 1 | — | 335 | 13 | 70 |
| Jackfish | — | 9 | — | — | 9 |
| U.S. | 16 | — | 716 | 28 | 163 |
| Canada | 16 | 9 | 214 | 4 | 65 |
| Total\tNorth\tAmerica | 32 | 9 | 930 | 32 | 228 |

| Year	Ended	December	31, | Oil	(Per	Bbl) | Average	Sales	Price<br>Bitumen	(Per	Bbl) | Gas	(Per	Mcf) | NGLs	(Per	Bbl) | Production	Cost<br>(Per	Boe) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2012 |  |  |  |  |  |
| Barnett\tShale | $91.45 | $— | $2.23 | $27.57 | $3.91 |
| Jackfish | $— | $47.75 | $— | $— | $19.48 |
| U.S. | $88.68 | $— | $2.32 | $28.49 | $5.79 |
| Canada | $68.08 | $47.75 | $2.49 | $48.63 | $15.18 |
| Total\tNorth\tAmerica | $80.35 | $47.75 | $2.36 | $30.42 | $8.30 |
| 2011 |  |  |  |  |  |
| Barnett\tShale | $94.23 | $— | $3.30 | $39.00 | $3.97 |
| Jackfish | $— | $58.16 | $— | $— | $17.28 |
| U.S. | $91.19 | $— | $3.50 | $39.47 | $5.35 |
| Canada | $74.32 | $58.16 | $3.87 | $55.99 | $13.82 |
| Total\tNorth\tAmerica | $83.16 | $58.16 | $3.58 | $41.10 | $7.71 |
| 2010 |  |  |  |  |  |
| Barnett\tShale | $77.40 | $— | $3.55 | $29.97 | $3.87 |
| Jackfish | $— | $52.51 | $— | $— | $16.81 |
| U.S. | $75.81 | $— | $3.76 | $30.86 | $5.47 |
| Canada | $62.00 | $52.51 | $4.11 | $46.60 | $12.37 |
| Total\tNorth\tAmerica | $68.75 | $52.51 | $3.84 | $32.61 | $7.42 |

# Drilling	Statistics

The	following	table	summarizes	our	development	and	exploratory	drilling	results.

|  | Development	Wells^		(1) | Development	Wells^		(1) | Exploratory	Wells		^(1) | Exploratory	Wells		^(1) |  | Total	Wells	^(1) |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31, | Productive | Dry | Productive | Dry | Productive | Dry | Total |
| 2012 |  |  |  |  |  |  |  |
| U.S. | 668.2 | 1.0 | 24.6 | \t 4.9 | 692.8 | 5.9 | 698.7 |
| Canada | 209.3 | 4.0 | 27.3 | \t 1.0 | 236.6 | 5.0 | 241.6 |
| Total\tNorth\tAmerica | 877.5 | 5.0 | 51.9 | \t 5.9 | 929.4 | \t10.9 | 940.3 |
| 2011 |  |  |  |  |  |  |  |
| U.S. | 721.2 | 5.5 | 18.8 | \t 4.0 | 740.0 | 9.5 | 749.5 |
| Canada | 247.6 | 1.5 | 19.1 | \t 1.0 | 266.7 | 2.5 | 269.2 |
| Total\tNorth\tAmerica | 968.8 | 7.0 | 37.9 | \t 5.0 | 1,006.7 | \t12.0 | \t1,018.7 |
| 2010 |  |  |  |  |  |  |  |
| U.S. | 855.7 | 5.3 | 23.4 | \t 1.5 | 879.1 | 6.8 | 885.9 |
| Canada | 267.8 | \t — | 41.9 | \t 1.0 | 309.7 | 1.0 | 310.7 |
| Total\tNorth\tAmerica | 1,123.5 | 5.3 | 65.3 | \t 2.5 | 1,188.8 | 7.8 | \t1,196.6 |

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

The	following	table	presents	the	February	1,	2013,	results	of	our	wells	that	were	in	progress	on	December	31,	2012.

(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	on	the	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	25,000	of	our	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	area.	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,	2012.	The	acreage	in	the	table	includes	1.4	million, 0.8	million	and	1.6	million	net	acres	subject	to	leases	that	are	scheduled	to	expire	during	2013,	2014	and	2015,	respectively.

|  | Developed |  | Undeveloped | Undeveloped |  |  | Total |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t(1)\nGross | \t(2)\nNet | \t(1)\nGross | Net | (2) | \t(1)\nGross |  | \t(2)\nNet |
|  |  |  | (In\tthousands) | (In\tthousands) |  |  |  |  |
| U.S. | 3,195 | \t2,210 | 7,830 | \t4,790 | \t4,790 | \t11,025 | \t11,025 | 7,000 |
| Canada | 3,665 | \t2,270 | 6,635 | \t4,805 | \t4,805 | \t10,300 | \t10,300 | 7,075 |
| Total\tNorth\tAmerica | 6,860 | \t4,480 | \t14,465 | \t9,595 | \t9,595 | \t21,325 | \t21,325 | \t14,075 |

(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	on	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.

# Marketing	and	Midstream	Activities

Our	marketing	and	midstream	operations	provide	gathering,	compression,	treating,	processing,	fractionation	and	marketing	services	to	us	and	other	third-parties. We	generate	revenues	from	these	operations	by	collecting	service	fees	and	selling	processed	gas	and	NGLs.	The	expenses	associated	with	these	operations	primarily consist	of	the	costs	to	operate	our	gathering	systems,	plants	and	related	facilities,	as	well	as	purchases	of	gas	and	NGLs.

# 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	2	to	the	financial	statements	included	in	"Item	8.

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

As	of	January	2013,	our	production	was	sold	under	the	following	contracts.

|  | Short-Term |  | Long-Term |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Variable | Fixed | Variable | Fixed |
| Oil\tand\tbitumen | 76% | \t— | 24% | \t— |
| Natural\tgas | 73% | \t— | 27% | \t— |
| NGLs | 78% | 14% | 1% | 7% |

# 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, 2012,	we	were	committed	to	deliver	the	following	fixed	quantities	of	production.

|  | Total | Less	Than	1	Year | 1-3	Years | 3-5	Years | 5		Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Oil\tand\tbitumen\t(MMBbls) | 124 | 14 | 30 | 31 | 49 |
| Natural\tgas\t(Bcf) | \t\t\t\t\t1,175 | \t\t\t\t\t\t\t\t623 | \t\t\t\t\t\t\t\t\t374 | \t\t\t\t\t\t\t\t\t133 | 45 |
| NGLs\t(MMBbls) | 10 | 5 | 3 | 2 | \t\t\t\t\t\t\t\t\t— |
| Total\t(MMBoe) | 330 | 123 | 95 | 55 | 57 |

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

# Competition

See	"Item	1A.	Risk	Factors."

# Public	Policy	and	Government	Regulation

The	oil	and	natural	gas	industry	is	subject	to	regulation	throughout	the	world.	Laws,	rules,	regulations	and	other	policy	implementation	actions	affecting	the	oil and	natural	gas	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	the	oil	and	natural	gas	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	oil	and	natural	gas	companies	of	similar	size	and	financial	strength.	The	following	are	significant	areas of	government	control	and	regulation	affecting	our	operations.

# Exploration	and	Production	Regulation

Our	oil	and	gas	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;

•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;	and

•transportation	of	production.

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	oil	and	gas	production.	Royalties	payable	on	production	from	lands	other	than	Crown lands	are	determined	by	negotiations	between	the	parties.	Crown	royalties	are	determined	by	government	regulation	and	are	generally	calculated	as	a	percentage	of	the value	of	the	gross	production,	with	the	royalty	rate	dependent	in	part	upon	prescribed	reference	prices,	well	productivity,	geographical	location	and	the	type	and	quality of	the	petroleum	product	produced.	Occasionally	the	federal	and	provincial	governments	of	Canada	also	have	established	incentive	programs,	such	as	royalty	rate reductions,	royalty	holidays,	and	tax	credits,	for	the	purpose	of	encouraging	oil	and	gas	exploration	or	enhanced	recovery	projects.	These	incentives	generally	increase our	revenues,	earnings	and	cash	flow.

# 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	("NEB").	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	yet	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	the	oil	and	gas	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;

•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, 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	production	to	downstream	markets.	Such	midstream systems	include	the	systems	we	operate,	as	well	as	systems	operated	by	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	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	U.S.	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	–	The	U.S.	Department	of	the	Interior	is	considering	the	possibility	of	additional	regulation	of	hydraulic	fracturing	on	federal	and	Indian lands.	Currently,	regulation	of	hydraulic	fracturing	is	conducted	primarily	at	the	state	level	through	permitting	and	other	compliance	requirements.	We	lease	federal	and Indian	lands	and	would	be	affected	by	the	Interior	Department	proposal	if	it	were	to	become	law.

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.	Recently,	the	U.S.	President	and	other	policy	makers	have	proposed	provisions	that	would,	if	enacted,	make	significant changes	to	U.S.	tax	laws	applicable	to	us.	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	U.S.	and	Canada	are	increasingly	focusing	on	whether	the	emissions	of	greenhouse	gases,	such	as	carbon	dioxide	and methane,	are	contributing	to	harmful	climatic	changes.	Policymakers	at	both	the	U.S.	federal	and	state	levels	have	introduced	legislation	and	proposed	new	regulations that	are	designed	to	quantify	and	limit	the	emission	of	greenhouse	gases	through	inventories,	limitations	and/or

taxes	on	greenhouse	gas	emissions.	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	feedstocks	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.	There	is	no	assurance	that	changes	in	or	additions	to	public	policy	regarding	the protection	of	the	environment	will	not	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.

# 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	6,	2013,	there	were	11,695	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	2012	and	2011,	as	well	as	the	quarterly dividends	per	share	paid	during	2012	and	2011.	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 |
| :--- | :--- | :--- | :--- |
| 2012: |  |  |  |
| Quarter\tEnded\tDecember\t31,\t2012 | $63.00 | $50.89 | $0.20 |
| Quarter\tEnded\tSeptember\t30,\t2012 | $63.95 | $54.56 | $0.20 |
| Quarter\tEnded\tJune\t30,\t2012 | $73.14 | $54.01 | $0.20 |
| Quarter\tEnded\tMarch\t31,\t2012 | $76.34 | $62.13 | $0.20 |
| 2011: |  |  |  |
| Quarter\tEnded\tDecember\t31,\t2011 | $69.55 | $50.74 | $0.17 |
| Quarter\tEnded\tSeptember\t30,\t2011 | $84.52 | $55.14 | $0.17 |
| Quarter\tEnded\tJune\t30,\t2011 | $92.69 | $75.50 | $0.17 |
| Quarter\tEnded\tMarch\t31,\t2011 | $93.55 | $76.96 | $0.16 |

# 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	the	group	of	companies	included	in	the	Crude	Petroleum	and	Natural	Gas Standard	Industrial	Classification	code	("the	SIC	Code").	The	graph	was	prepared	assuming	$100	was	invested	on	December	31,	2007	in	Devon's	common	stock,	the S&P	500	Index	and	the	SIC	Code	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	2012.	Such	purchases 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.

| Period | Total	Number	of<br>Shares	Purchased | Average	Price	Paid<br>per	Share |
| :--- | :--- | :--- |
| October\t1\t-\tOctober\t31 | 6,000 | $60.15 |
| November\t1\t-\tNovember\t30 | 406,725 | $52.72 |
| December\t1\t-\tDecember\t31 | 459,320 | $52.24 |
| Total | 872,045 | $52.52 |

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	57,000	shares	of	our common	stock	in	2012,	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.	Eligible	Canadian	employees	purchased	approximately	22,900	shares	of our	common	stock	in	2012,	at	then-prevailing	stock	prices,	that	they	held	through	their	ownership	in	the	Canadian	Plan.	We	acquired	the	shares	sold	under	the	Canadian Plan	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.

# 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, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 | 2009 | 2008 |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Revenues | $9,502 | $11,454 | $9,940 | $8,015 | $13,858 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations^\t(1) | $(185) | $2,134 | $2,333 | $(2,753) | $(3,039) |
| Earnings\t(loss)\tper\tshare\tfrom\tcontinuing\toperations\t-\tBasic | $(0.47) | $5.12 | $5.31 | $(6.20) | $(6.86) |
| Earnings\t(loss)\tper\tshare\tfrom\tcontinuing\toperations\t-\tDiluted | $(0.47) | $5.10 | $5.29 | $(6.20) | $(6.86) |
| Cash\tdividends\tper\tcommon\tshare | $0.80 | $0.67 | $0.64 | $0.64 | $0.64 |
| Weighted\taverage\tcommon\tshares\toutstanding\t-\tBasic | 405 | 417 | 440 | 444 | 444 |
| Weighted\taverage\tcommon\tshares\toutstanding\t-\tDiluted | 405 | 418 | 441 | 444 | 444 |
| Total\tassets^\t(1) | $43,326 | $41,117 | $32,927 | $29,686 | $31,908 |
| Long-term\tdebt | $8,455 | $5,969 | $3,819 | $5,847 | $5,661 |
| Stockholders'\tequity | $21,278 | $21,430 | $19,253 | $15,570 | $17,060 |

# 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	2012	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.

2012	was	a	year	of	mixed	results	for	Devon.	We	grew	our	production	4%	and	closed	two	significant	joint	venture	transactions	with	a	combined	value	of approximately	$4.0	billion.	Furthermore,	with	a	focus	on	development	of	higher-margin	oil	and	bitumen	properties	in	our	portfolio,	we	increased	our	oil	and	bitumen production	20%	in	2012	and	are	positioned	to	deliver	similar	oil	and	bitumen	growth	in	2013.	However,	this	growth	was	overshadowed	by	the	effects	of	declining commodity	prices,	which	negatively	impacted	a	number	of	our	2012	financial	performance	measures,	as	well	as	our	year-end	proved	reserves.	Key	measures	of	our 2012	performance	are	summarized	below,	which	exclude	amounts	from	our	discontinued	operations.

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | Change | 2011 | Change | 2010 |
|  |  | ($\tin\tmillions,\texcept\tper\tshare\tamounts) | ($\tin\tmillions,\texcept\tper\tshare\tamounts) | ($\tin\tmillions,\texcept\tper\tshare\tamounts) |  |
| Net\tearnings\t(loss) | $(185) | -109% | $2,134 | -9% | $2,333 |
| Adjusted\tearnings^\t(1) | $1,322 | -48% | $2,536 | +0% | $2,536 |
| Earnings\t(loss)\tper\tshare | $(0.47) | -109% | $5.10 | -4% | $5.29 |
| Adjusted\tearnings\tper\tshare^\t(1) | $3.26 | -46% | $6.07 | +6% | $5.75 |
| Production\t(MBoe/d) | \t 682.3 | +4% | \t 657.7 | +5% | \t 623.6 |
| Realized\tprice\tper\tBoe | $28.65 | -17% | $34.64 | +9% | $31.91 |
| Operating\tmargin\tper\tBoe\t^(2) | $19.41 | -23% | $25.15 | +1% | $24.89 |
| Operating\tcash\tflow | $4,930 | -21% | $6,246 | +24% | $5,022 |
| Adjusted\toperating\tcash\tflow^\t(1) | $4,892 | -21% | $6,225 | +7% | $5,840 |
| Capitalized\tcosts | $8,474 | +9% | $7,795 | +13% | $6,920 |
| Shareholder\tdistributions\t^(3) | $324 | -88% | $2,610 | +80% | $1,449 |
| Reserves\t(MMBoe) | \t 2,963 | -1% | \t 3,005 | +5% | \t 2,873 |

(1) Adjusted	earnings,	adjusted	earnings	per	share	and	adjusted	operating	cash	flow	are	not	financial	measures	prepared	in	accordance	with	accounting	principles generally	accepted	in	the	U.S.	(GAAP).	For	a	description	of	adjusted	earnings,	adjusted	earnings	per	share	and	adjusted	operating	cash	flow	as	well	as reconciliations	to	the	comparable	GAAP	measures,	see	"Non-GAAP	Measures"	in	this	Item	7.

(2) Computed	as	revenues	from	commodity	sales,	commodity	derivatives	settlements,	and	marketing	and	midstream	operations,	less	expenses	for	lease	operations, marketing	and	midstream	operations,	general	and	administration,	taxes	other	than	income	taxes	and	interest,	with	the	result	divided	by	total	production.

(3) Includes	common	stock	dividends	and	share	repurchases.

Our	2012	net	loss	resulted	from	noncash	asset	impairments,	which	reduced	our	earnings	by	$2.0	billion	($1.3	billion	after	tax).	Excluding	the	asset	impairments and	other	items	typically	excluded	by	securities	analysts,	our	adjusted	earnings	were	$1.3	billion,	or	$3.26	per	diluted	share.	This	compares	to	adjusted	earnings	of	$2.5 billion,	or	$6.07	per	diluted	share	in	2011.

In	spite	of	growing	our	production,	our	2012	adjusted	earnings,	adjusted	cash	flow,	operating	margin	and	proved	reserves	declined	largely	due	to	the	effects	of lower	commodity	prices.	In	virtually	all	our	operating	areas,	we	realized	lower	prices	in	2012	due	to	either	declines	in	benchmarks	or	widening	price	differentials.	The most	significant	price	declines	were	associated	with	our	gas	and	NGL	production,	for	which	we	experienced	realized	price	decreases	of	34%	and	26%,	respectively.	With increasing	focus	on	oil	and	bitumen	production	growth,	which	generally	require	a	higher	cost	to	produce	per	unit	than	our	gas	projects,	we	were	also	impacted	by	upward pressure	on	operating	costs.

We	replaced	152%	of	our	2012	production	from	proved	reserve	extensions,	discoveries	and	revisions	other	than	price.	Yet,	our	proved	reserves	decreased	1% overall	due	to	significant	downward	revisions	resulting	from	lower	gas	and	NGL	prices.

# Business	and	Industry	Outlook

During	2012,	natural	gas	traded	at	prices	we	have	not	experienced	for	a	decade.	These	low	prices	are	the	result	of	a	significant	imbalance	between	supply	and demand	in	North	America.	On	the	supply	side,	new	technologies,	particularly	hydraulic	fracturing	and	horizontal	drilling,	have	enabled	natural	gas	producers	to	bring	on line	meaningful	new	supplies	of	natural	gas	around	North	America.	On	the	demand	side,	the	past	winter	was	one	of	the	warmest	on	record,	which	reduced	demand	for natural	gas.	Consequently,	North	America	has	an	unusually	high	amount	of	gas	in	storage	that	will	continue	to	oversupply	the	market.	However,	there	are	some favorable	trends.	Utilities	around	the	country	are	switching	from	coal	to	natural	gas	at	a	meaningful	rate.	New	petro-chemical	plants	are	being	built	and	other	industries are	expanding	in	the	U.S.	Looking	to	2013,	increased	demand	should	cause	natural	gas	prices	to	stabilize	or	possibly	to	increase	moderately	from	2012	levels.

As	a	result	of	the	low	natural	gas	prices,	we	and	other	producers	have	been	focused	on	growing	oil,	bitumen	and	liquids-rich	gas	production.	Similar	to	natural gas,	regional	imbalances	between	supply	and	demand	of	these	liquids	have	caused	price	declines.	In	2012,	the	most	negative	impact	to	us	from	these	imbalances	related to	our	U.S.	NGLs	and	our	Canadian	heavy	oil.	The	NGL	imbalances	have	largely	resulted	from	increased	liquids-rich	gas	production	without	corresponding	increases	in either	NGL	pipeline	delivery	systems	or	consumer	demand.	We	expect	NGL	prices	will	remain	challenged	for	2013	and,	perhaps	longer,	due	to	the	long-lead	time associated	with	the	construction	of	new	petrochemical	capacity.	Our	Canadian	heavy	oil	production	has	recently	been	impacted	by	pipeline	outages	and	refinery downtime.	With	increasing	industry	heavy	oil	production	and	current	pipeline	capacity,	the	pipeline	outages	and	refinery	downtimes	had	greater	impacts	to	producers' realized	prices	during	2012.	Like	other	producers,	we	are	beginning	to	use	rail	to	deliver	a	portion	of	our	heavy	oil	to	downstream	markets.	We	are	also	optimistic	the U.S.	government	will	approve	construction	of	the	Keystone	XL	pipeline.	Provided	the	pipeline	outages	are	not	recurring	and	industry's	planned	refinery	expansions occur	during	the	first	half	of	2013,	the	downward	pressures	on	Canadian	heavy	oil	prices	should	be	relatively	temporary	in	nature.

While	we	are	optimistic	about	the	long-term	future	of	prices,	we	expect	benchmark	prices	will	continue	to	be	volatile	and	in	some	cases	will	be	challenged	in 2013.	We	are	most	optimistic	about	oil	prices	and	believe	our	oil	properties	largely	represent	the	highest-return	assets	in	our	portfolio.	Therefore,	our	near-term	focus will	be	on	these	properties.	We	also	realize	that	we	possess	a	great	deal	of	financial	strength,	flexibility	and	liquidity.	We	will	use	these	resources	to	develop	our portfolio	of	properties	and	explore	other	opportunities	to	maximize	shareholder	value,	including	monetization	of	our	existing	assets	or	entering	into	new	ventures	or acquisitions.

# Results	of	Operations

All	amounts	in	this	document	related	to	our	International	operations	are	presented	as	discontinued.	Therefore,	the	production,	revenue	and	expense	amounts presented	in	this	"Results	of	Operations"	section	exclude	amounts	related	to	our	International	assets	unless	otherwise	noted.

Even	though	we	divested	our	U.S.	Offshore	operations	in	2010,	these	properties	do	not	qualify	as	discontinued	operations	under	accounting	rules.	As	such, financial	and	operating	data	provided	in	this	document	that	pertain	to	our	continuing	operations	include	amounts	related	to	our	U.S.	Offshore	operations.	To	facilitate comparisons	of	our	ongoing	operations	subsequent	to	the	planned	divestitures,	we	have	presented	amounts	related	to	our	U.S.	Offshore	assets	separate	from	those	of	our North	American	Onshore	assets	where	appropriate.

# Production,	Prices	and	Revenues

|  | 2012 | Change | Year	Ended	December	31,<br>2011 | Change | 2010 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Oil\t(MBbls/d) |  |  |  |  |  |
| U.S.\tOnshore | 58.7 | +28% | 46.0 | +24% | 37.0 |
| Canada | 39.8 | -5% | 41.7 | -6% | 44.2 |
| North\tAmerica\tOnshore | 98.5 | +12% | 87.7 | +8% | 81.2 |
| U.S.\tOffshore | — | \t N/M | — | -100% | 5.2 |
| Total | 98.5 | +12% | 87.7 | +1% | 86.4 |
| Bitumen\t(MBbls/d) |  |  |  |  |  |
| Canada | 47.6 | +37% | 34.8 | +41% | 24.7 |
| Gas\t(MMcf/d) |  |  |  |  |  |
| U.S.\tOnshore | \t2,054.5 | +1% | \t2,026.6 | +6% | \t1,913.8 |
| Canada | 508.3 | -13% | 583.1 | -1% | 586.9 |
| North\tAmerica\tOnshore | \t2,562.8 | -2% | \t2,609.7 | +4% | \t2,500.7 |
| U.S.\tOffshore | — | \t N/M | — | -100% | 46.0 |
| Total | \t2,562.8 | -2% | \t2,609.7 | +2% | \t2,546.7 |
| NGLs\t(MBbls/d) |  |  |  |  |  |
| U.S.\tOnshore | 98.6 | +9% | 90.4 | +17% | 77.3 |
| Canada | 10.5 | +6% | 9.9 | +2% | 9.8 |
| North\tAmerica\tOnshore | 109.1 | +9% | 100.3 | +15% | 87.1 |
| U.S.\tOffshore | — | \t N/M | — | -100% | 0.9 |
| Total | 109.1 | +9% | 100.3 | +14% | 88.0 |
| Combined\t(MBoe/d) |  |  |  |  |  |
| U.S.\tOnshore | 499.7 | +5% | 474.1 | +9% | 433.3 |
| Canada | 182.6 | -1% | 183.6 | +4% | 176.5 |
| North\tAmerica\tOnshore | 682.3 | +4% | 657.7 | +8% | 609.8 |
| U.S.\tOffshore | — | \t N/M | — | -100% | 13.8 |
| Total | 682.3 | +4% | 657.7 | +5% | 623.6 |

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012^\t(1) | Change | 2011\t^(1) | Change | 2010\t^(1) |
| Oil\t(per\tBbl) |  |  |  |  |  |
| U.S.\tOnshore | $88.68 | -3% | $91.19 | +21% | $75.53 |
| Canada | $68.08 | -8% | $74.32 | +20% | $62.00 |
| North\tAmerica\tOnshore | $80.35 | -3% | $83.16 | +22% | $68.17 |
| U.S.\tOffshore | $— | \t N/M | $— | -100% | $77.81 |
| Total | $80.35 | -3% | $83.16 | +21% | $68.75 |
| Bitumen\t(per\tBbl) |  |  |  |  |  |
| Canada | $47.75 | -18% | $58.16 | +11% | $52.51 |
| Gas\t(per\tMcf) |  |  |  |  |  |
| U.S.\tOnshore | $2.32 | -34% | $3.50 | -6% | $3.73 |
| Canada | $2.49 | -36% | $3.87 | -6% | $4.11 |
| North\tAmerica\tOnshore | $2.36 | -34% | $3.58 | -6% | $3.82 |
| U.S.\tOffshore | $— | \t N/M | $— | -100% | $5.12 |
| Total | $2.36 | -34% | $3.58 | -7% | $3.84 |
| NGLs\t(per\tBbl) |  |  |  |  |  |
| U.S.\tOnshore | $28.49 | -28% | $39.47 | +28% | $30.78 |
| Canada | $48.63 | -13% | $55.99 | +20% | $46.60 |
| North\tAmerica\tOnshore | $30.42 | -26% | $41.10 | +26% | $32.55 |
| U.S.\tOffshore | $— | \t N/M | $— | -100% | $38.22 |
| Total | $30.42 | -26% | $41.10 | +26% | $32.61 |
| Combined\t(per\tBoe) |  |  |  |  |  |
| U.S.\tOnshore | $25.59 | -18% | $31.31 | +10% | $28.42 |
| Canada | $37.01 | -14% | $43.23 | +11% | $39.11 |
| North\tAmerica\tOnshore | $28.65 | -17% | $34.64 | +10% | $31.52 |
| U.S.\tOffshore | $— | \t N/M | $— | -100% | $49.06 |
| Total | $28.65 | -17% | $34.64 | +9% | $31.91 |

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

# 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) |  |  |
| 2010\tsales | $2,169 | $474 | $3,572 | $1,047 | $7,262 |
| Change\tdue\tto\tvolumes | 30 | 193 | 88 | 147 | 458 |
| Change\tdue\tto\tprices | 461 | 72 | (249) | 311 | 595 |
| 2011\tsales | \t 2,660 | 739 | 3,411 | \t 1,505 | 8,315 |
| Change\tdue\tto\tvolumes | 337 | 273 | (52) | 137 | 695 |
| Change\tdue\tto\tprices | (101) | (181) | (1,148) | (427) | (1,857) |
| 2012\tsales | $2,896 | $831 | $2,211 | $1,215 | $7,153 |

Volumes	2012	vs.	2011	–	Upstream	sales	increased	$695	million	due	to	a	4	percent	increase	in	production.	Oil	and	bitumen	production	were	the	largest	drivers	of the	increase,	accounting	for	nearly	90	percent	of	the	higher	sales.	As	a	result	of	continued	development	of	our	liquids-rich	properties	in	the	Permian	Basin,	our	oil	sales increased	$337	million.	Bitumen	sales	increased	$273	million	due	to	development	of	our	Jackfish	thermal	heavy	oil	projects	in	Canada.	Additionally,	our	NGL	sales increased	$137	million	as	a	result	of	continued	drilling	in	the	liquids-rich	gas	portions	of	the	Barnett	Shale,	Cana-Woodford	Shale	and	Granite	Wash.	These	increases were	partially	offset	by	a	slight	decrease	in	our	2012	gas	production,	resulting	in	a	$52	million	decline	in	sales.

Volumes	2011	vs.	2010	–	Upstream	sales	increased	$458	million	due	to	a	5	percent	increase	in	production.	Bitumen	and	NGL	volume	increases	resulted	in	$340 million	higher	sales.	Additional	volumes	for	both	of	these	products	were	primarily	due	to	the	same	reasons	discussed	in	our	2012	vs.	2011	comparison	above. Additionally,	we	saw	slight	increases	in	our	oil	and	gas	volumes	which	resulted	in	$118	million	higher	sales.

Production	information	for	our	key	properties	is	summarized	below:

•Permian	Basin	production	increased	26	percent	compared	to	the	prior	year	and	44	percent	since	2010.	Oil	production	accounted	for	nearly	60	percent	of	our 62,000	Boe	per	day	produced	in	the	Permian	Basin	during	2012.	The	2012	increase	in	total	production	was	driven	by	a	30	percent	increase	in	oil production.

•	 Barnett	Shale	production	increased	7	percent	compared	to	the	prior	year	and	18	percent	since	2010.	Liquids	production	accounted	for	21	percent	of	our	1.4 Bcfe	per	day	produced	in	the	Barnett	Shale	during	2012.	The	2012	increase	in	total	production	was	driven	by	a	7	percent	increase	in	liquids	production.

•	 Cana-Woodford	Shale	production	increased	45	percent	compared	to	the	prior	year	and	168	percent	since	2010.	Liquids	production	accounted	for	30	percent of	our	290	MMcfe	per	day	produced	in	Cana	during	2012.	The	2012	increase	in	total	production	was	driven	by	a	67	percent	increase	in	liquids	production.

•	 Canadian	Oil	Sands	production	increased	37	percent	compared	to	the	prior	year	and	92	percent	since	2010.	Bitumen	production	accounted	for	all	of	our 48,000	Boe	per	day	produced	in	2012.

•	 Granite	Wash	production	increased	14	percent	compared	to	the	prior	year	and	68	percent	since	2010.	Liquids	production	accounted	for	46	percent	of	our 19,000	Boe	per	day	produced	in	Granite	Wash	during	2012.	The	2012	increase	in	production	was	driven	by	a	20	percent	increase	in	liquids	production.

•	 By	the	end	of	2012,	Mississippian	production	was	up	to	almost	3,000	Boe	per	day.	We	drilled	our	first	35	wells	in	2012.	Oil	production	accounted	for	63 percent	of	our	total	production	in	2012.

•	 Gulf	Coast/East	Texas	production	decreased	14	percent	in	2012.	Although	total	production	was	down,	oil	production	increased	8	percent	in	2012.	Liquids production	accounted	for	nearly	25	percent	of	our	368	MMcfe	per	day	produced	in	Gulf	Coast/East	Texas	during	2012.

•	 Rocky	Mountain	production	decreased	9	percent	in	2012.	Although	total	production	was	down,	oil	production	increased	17	percent	in	2012.	Liquids production	accounted	for	28	percent	of	our	352	MMcfe	per	day	produced	in	the	Rocky	Mountains	during	2012.

•Lloydminster	production	decreased	6	percent	in	2012.	Oil	production	accounted	for	82	percent	of	our	37,000	Boe	per	day	produced	at	Lloydminster	during 2012.

Prices	2012	vs.	2011	–	Upstream	sales	decreased	$1.9	billion	due	to	a	17	percent	decrease	in	our	realized	price	without	hedges.	Our	gas	sales	were	the	most significantly	impacted	with	a	$1.1	billion	decrease	in	sales.	The	change	in	our	gas	price	was	largely	due	to	fluctuations	of	the	North	American	regional	index	prices	upon which	our	gas	sales	are	based.	We	also	experienced	declines	in	our	NGL,	bitumen	and	oil	sales	due	to	our	realized	price.	The	largest	contributors	to	the	lower	liquids prices	were	lower	NGL	prices	at	the	Mont	Belvieu,	Texas	hub	and	wider	bitumen	differentials	to	the	NYMEX	West	Texas	Intermediate	index	price.

Prices	2011	vs.	2010	–	Upstream	sales	increased	$595	million	due	to	a	9	percent	increase	in	our	realized	price	without	hedges.	Our	realized	price	for	oil,	bitumen and	NGLs	increased	primarily	due	to	an	increase	in	the	average	index	price	for	which	each	product	is	sold.	Our	realized	price	for	gas	decreased	primarily	due	to fluctuations	of	the	North	American	regional	index	prices	upon	which	our	gas	sales	are	based.

# 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	unrealized	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	unrealized	gains	and	losses.

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- | :--- |
|  | 2012 | 2012 | 2011 | 2010 |
|  |  |  | (In\tmillions) |  |
| Cash\tsettlements: |  |  |  |  |
| Gas\tderivatives | $610 | $610 | $416 | $888 |
| Oil\tderivatives | 259 | 259 | (26) | \t — |
| NGL\tderivatives | 1 | 1 | 2 | \t — |
| Total\tcash\tsettlements | 870 | 870 | \t 392 | \t 888 |
| Unrealized\tgains\t(losses)\ton\tfair\tvalue\tchanges: |  |  |  |  |
| Gas\tderivatives | (330) | (330) | \t 305 | 12 |
| Oil\tderivatives | 150 | 150 | \t 185 | (91) |
| NGL\tderivatives | 3 | 3 | (1) | 2 |
| Total\tunrealized\tgains\t(losses)\ton\tfair\tvalue\tchanges | (177) | (177) | \t 489 | (77) |
| Oil,\tgas\tand\tNGL\tderivatives | $693 | $693 | $881 | $811 |
|  | Year\tEnded\tDecember\t31,\t2012 | Year\tEnded\tDecember\t31,\t2012 |  |  |
| Oil | Bitumen | Gas | NGLs |  |

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	2	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	call	options	for	2012	and	2014 and	oil	call	options	for	2011	through	2014.	The	call	options	give	counterparties	the	right	to	purchase	production	at	a	predetermined	price.

In	addition	to	cash	settlements,	we	also	recognize	unrealized	changes	in	the	fair	values	of	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	$693	million,	$881	million	and	$811 million	during	2012,	2011	and	2010,	respectively.

# Marketing	and	Midstream	Revenues	and	Operating	Costs	and	Expenses

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | Change | 2011 | Change | 2010 |
|  |  |  | ($\tin\tmillions) |  |  |
| Revenues | $1,656 | -27% | $2,258 | +21% | $1,867 |
| Operating\tcosts\tand\texpenses | \t 1,246 | -27% | \t 1,716 | +26% | \t 1,357 |
| Operating\tprofit | $410 | -24% | $542 | +6% | $510 |

2012	vs.	2011	Marketing	and	midstream	operating	profit	decreased	$132	million	primarily	due	to	lower	natural	gas	and	NGL	prices.

2011	vs.	2010	Marketing	and	midstream	operating	profit	increased	$32	million	primarily	due	to	higher	natural	gas	throughput	and	higher	NGL	prices.

|  | 2012 | Change | Year	Ended	December	31,<br>2011 | Change | 2010 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| LOE\t($\tin\tmillions): |  |  |  |  |  |
| U.S.\tOnshore | $1,059 | +14% | $925 | +11% | $832 |
| Canada | \t 1,015 | +10% | 926 | +16% | 797 |
| North\tAmerica\tOnshore | \t 2,074 | +12% | \t 1,851 | +14% | \t 1,629 |
| U.S.\tOffshore | — | \t N/M | — | -100% | 60 |
| Total | $2,074 | +12% | $1,851 | +10% | $1,689 |
| LOE\tper\tBoe: |  |  |  |  |  |
| U.S.\tOnshore | $5.79 | +8% | $5.35 | +2% | $5.26 |
| Canada | $15.18 | +10% | $13.82 | +12% | $12.37 |
| North\tAmerica\tOnshore | $8.30 | +8% | $7.71 | +5% | $7.32 |
| U.S.\tOffshore | $— | \t N/M | $— | -100% | $12.00 |
| Total | $8.30 | +8% | $7.71 | +4% | $7.42 |

2012	vs.	2011	LOE	increased	$0.59	per	Boe	largely	because	of	our	oil	production	growth,	particularly	at	our	Jackfish	thermal	heavy	oil	projects	in	Canada	and	in the	Permian	Basin	in	the	U.S.	Such	oil	projects	generally	require	a	higher	cost	to	produce	per	unit	than	our	gas	projects.	We	also	experienced	inflationary	pressures	on costs	in	certain	operating	areas,	which	increased	LOE	per	Boe.

2011	vs.	2010	LOE	increased	$0.29	per	Boe.	LOE	increased	$0.39	per	Boe,	excluding	the	U.S.	Offshore	operations	that	were	sold	in	the	second	quarter	of	2010. The	largest	contributor	to	the	higher	North	America	Onshore	unit	cost	is	our	oil	production	growth,	particularly	at	our	Jackfish	thermal	heavy	oil	projects	in	Canada.	We also	experienced	inflationary	pressures	on	costs	in	certain	operating	areas.	Additionally,	LOE	per	Boe	increased	$0.15	due	to	a	$36	million	increase	from	changes	in	the exchange	rate	between	the	U.S.	and	Canadian	dollars.

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

|  | 2012 | Change | Year	Ended	December	31,<br>2011 | Change | 2010 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| DD&amp;A\t($\tin\tmillions): |  |  |  |  |  |
| Oil\t&amp;\tgas\tproperties | $2,526 | +27% | $1,987 | +19% | $1,675 |
| Other\tproperties | 285 | +9% | 261 | +2% | 255 |
| Total | $2,811 | +25% | $2,248 | +17% | $1,930 |
| DD&amp;A\tper\tBoe: |  |  |  |  |  |
| Oil\t&amp;\tgas\tproperties | $10.12 | +22% | $8.28 | +13% | $7.36 |
| Other\tproperties | 1.14 | +5% | 1.09 | -3% | 1.12 |
| Total | $11.26 | +20% | $9.37 | +10% | $8.48 |

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,	then	the	DD&A	rate	per	unit	of	production	will	change	inversely. However,	when	the	depletable	base	changes,	then	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.

2012	vs.	2011	Oil	and	gas	property	DD&A	increased	$460	million	due	to	a	22	percent	increase	in	the	DD&A	rate	and	$79	million	due	to	our	4	percent	increase	in production.	The	largest	contributors	to	the	higher	rate	were	our	2012	drilling	and	development	activities.

2011	vs.	2010	Oil	and	gas	property	DD&A	increased	$221	million	due	to	a	13	percent	increase	in	the	DD&A	rate	and	$91	million	due	to	our	5	percent	increase	in production.	The	largest	contributors	to	the	higher	rate	were	our	2011	drilling	and	development	activities	and	changes	in	the	exchange	rate	between	the	U.S.	and	Canadian dollars.	These	increases	were	partially	offset	by	the	divestiture	of	our	U.S.	Offshore	properties	in	the	second	quarter	of	2010.

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

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | Change | 2011 | Change | 2010 |
|  |  |  | ($\tin\tmillions) |  |  |
| Gross\tG&amp;A | $1,171 | +13% | $1,036 | +5% | $987 |
| Capitalized\tG&amp;A | (359) | +7% | (337) | +8% | (311) |
| Reimbursed\tG&amp;A | (120) | +5% | (114) | +1% | (113) |
| Net\tG&amp;A | $692 | +18% | $585 | +4% | $563 |
| Net\tG&amp;A\tper\tBoe | $2.77 | +14% | $2.44 | -1% | $2.47 |

2012	vs.	2011	Net	G&A	and	net	G&A	per	Boe	increased	largely	due	to	higher	employee	compensation	and	benefits.	Employee	costs	increased	primarily	from	an expansion	of	our	workforce	as	part	of	growing	production	operations	at	certain	of	our	key	areas,	including	Jackfish,	the	Permian	Basin	and	the	Cana-Woodford	Shale.

2011	vs.	2010	Net	G&A	increased	primarily	due	to	higher	employee	compensation	and	benefits,	while	net	G&A	per	Boe	slightly	declined	as	we	grew	production at	a	higher	rate	than	G&A.

# Taxes	Other	Than	Income	Taxes

|  |  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | Change | 2011 | Change | 2010 |
|  |  |  | ($\tin\tmillions) |  |  |
| Production | $ 224 | -10% | $ 248 | +18% | $ 210 |
| Ad\tvalorem\tand\tother | 190 | +8% | 176 | +4% | 170 |
| Taxes\tother\tthan\tincome\ttaxes | $ 414 | -3% | $ 424 | +12% | $ 380 |
| Percentage\tof\toil,\tgas\tand\tNGL\trevenue: |  |  |  |  |  |
| Production | \t 3.13% | +5% | \t 2.98% | +3% | \t 2.90% |
| Ad\tvalorem\tand\tother | \t 2.65% | +25% | \t 2.12% | -9% | \t 2.34% |
| Total | \t 5.78% | +13% | \t 5.10% | -3% | \t 5.24% |

2012	vs.	2011	Taxes	other	than	income	taxes	decreased	primarily	due	to	a	decrease	in	our	U.S.	Onshore	revenues,	on	which	the	majority	of	our	production	taxes are	assessed.

2011	vs.	2010	Taxes	other	than	income	taxes	increased	primarily	due	to	an	increase	in	our	U.S.	Onshore	revenues,	on	which	the	majority	of	our	production	taxes are	assessed.

# Interest	Expense

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | Change | 2011 | Change | 2010 |
|  |  |  | ($\tin\tmillions) |  |  |
| Interest\tbased\ton\tdebt\toutstanding | $440 | +6% | $414 | +2% | $408 |
| Capitalized\tinterest | (48) | -33% | (72) | -5% | (76) |
| Early\tretirement\tof\tdebt | — | \t N/M | \t — | -100% | 19 |
| Other | 14 | +33% | 10 | -17% | 12 |
| Interest\texpense | $406 | +15% | $352 | -3% | $363 |

2012	vs.	2011	Interest	expense	increased	primarily	due	to	additional	debt	borrowings	and	lower	capitalized	interest,	partially	offset	by	lower	weighted	average interest	rates.	Borrowings	were	primarily	used	to	fund	capital	expenditures	in	excess	of	our	operating	cash	flow	and	2012	divestiture	proceeds.

2011	vs.	2010	Interest	expense	decreased	primarily	due	to	costs	associated	with	the	early	retirement	of	our	$350	million	notes	in	2010.	This	was	partially	offset	by higher	interest	resulting	from	increased	debt	balances	in	2011.

# Restructuring	Costs

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Office\tconsolidation: |  |  |  |
| Employee\tseverance\tand\tretention | $ 77 | $ — | $ — |
| Lease\tobligations\tand\tother | 3 | \t — | — |
| Total | 80 | \t — | — |
| Offshore\tdivestitures: |  |  |  |
| Employee\tseverance | (3) | 8 | (27) |
| Lease\tobligations\tand\tother | (3) | (10) | 84 |
| Total | (6) | (2) | 57 |
| Restructuring\tcosts\t(1) | $ 74 | $(2) | $57 |

(1) Restructuring	costs	related	to	our	discontinued	operations	totaled	$(2)	million	and	$(4)	million	in	2011	and	2010,	respectively.	These	costs	primarily	consist	of employee	severance	and	are	not	included	in	the	table.	There	were	no	costs	related	to	discontinued	operations	in	2012.

# Office	Consolidation

In	October	2012,	we	announced	plans	to	consolidate	our	U.S.	personnel	into	a	single	operations	group	centrally	located	at	our	corporate	headquarters	in Oklahoma	City.	As	a	result,	we	are	in	the	process	of	closing	our	office	in	Houston	and	transferring	operational	responsibilities	for	assets	in	South	Texas,	East	Texas	and Louisiana	to	Oklahoma	City.	This	initiative	is	expected	to	be	substantially	complete	by	the	end	of	the	first	quarter	2013.

Employee	severance	–	In	the	fourth	quarter	of	2012,	we	recognized	$77	million	of	estimated	employee	severance	costs	associated	with	the	office	consolidation. This	amount	was	based	on	estimates	of	the	number	employees	that	would	ultimately	be	impacted	by	the	office	consolidation	and	included	amounts	related	to	cash severance	costs	and	accelerated	vesting	of	share-based	grants.

Lease	obligations	and	other	–	As	of	December	31,	2012,	we	incurred	$3	million	of	restructuring	costs	related	to	certain	office	space	that	is	subject	to	non- cancellable	operating	lease	agreements	and	that	we	ceased	using	as	a	part	of	the	office	consolidation.	In	2013	we	expect	to	incur	approximately	$25	million	of	additional restructuring	costs	that	represent	the	present	value	of	our	future	obligations	under	the	leases,	net	of	anticipated	sublease	income.	Our	estimate	of	lease	obligations	was based	upon	certain	key	estimates	that	could	change	over	the	term	of	the	leases.	These	estimates	include	the	estimated	sublease	income	that	we	may	receive	over	the	term of	the	leases,	as	well	as	the	amount	of	variable	operating	costs	that	we	will	be	required	to	pay	under	the	leases.

# Divestiture	of	Offshore	Assets

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

Employee	severance	–	This	amount	was	originally	based	on	estimates	of	the	number	of	employees	that	would	ultimately	be	impacted	by	the	offshore	divestitures and	included	amounts	related	to	cash	severance	costs	and	accelerated	vesting	of	share-based	grants.	As	the	divestiture	program	progressed,	we	decreased	our	overall estimate	of	employee	severance	costs.	More	offshore	employees	than	previously	estimated	received	comparable	positions	with	either	the	purchaser	of	the	properties	or	in our	U.S.	Onshore	operations.

Lease	obligations	and	other	–	As	a	result	of	the	divestitures,	we	ceased	using	certain	office	space	that	was	subject	to	non-cancellable	operating	lease arrangements.	Consequently,	in	2010	we	recognized	$70	million	of	restructuring	costs	that	represented	the	present	value	of	our	future	obligations	under	the	leases,	net	of anticipated	sublease	income.	Our	estimate	of	lease	obligations	was	based	upon	certain	key	estimates	that	could	change	over	the	term	of	the	leases.	These	estimates include	the	estimated	sublease	income	that	we	may	receive	over	the	term	of	the	leases,	as	well	as	the	amount	of	variable	operating	costs	that	we	will	be	required	to	pay under	the	leases.	In	addition,	we	recognized	$13	million	of	asset	impairment	charges	for	leasehold	improvements	and	furniture	associated	with	the	office	space	that	we ceased	using.

# Asset	Impairments

|  | Year	Ended	December	31,	2012<br>								Gross | Net	of	Taxes |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| U.S.\toil\tand\tgas\tassets | $1,793 | $1,142 |
| Canada\toil\tand\tgas\tassets | 163 | 122 |
| Midstream\tassets | 68 | 44 |
| Total\tasset\timpairments | $2,024 | $1,308 |

# 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	to the	financial	statements	under	"Item	8.	Consolidated	Financial	Statements"	of	this	report.

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	have	reduced	proved	reserve	values.

If	pricing	conditions	do	not	improve,	we	may	incur	full	cost	ceiling	impairments	related	to	our	oil	and	gas	property	and	equipment	in	2013.

# Midstream	Impairments

Due	to	declining	natural	gas	production	resulting	from	low	natural	gas	and	NGL	prices,	we	determined	that	the	carrying	amounts	of	certain	of	our	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.

# Other,	net

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Accretion\tof\tasset\tretirement\tobligations | $110 | $92 | $92 |
| Interest\trate\tderivatives | 15 | 11 | (14) |
| Foreign\tcurrency\tderivatives | 18 | (16) | \t — |
| Foreign\texchange\tloss\t(gain) | (15) | 25 | (7) |
| Interest\tincome | (36) | (21) | (13) |
| Other | (14) | (101) | (25) |
| Other,\tnet | $78 | $(10) | $33 |

2012	vs.	2011	Other,	net	increased	primarily	due	to	$88	million	of	excess	insurance	recoveries	received	in	2011	related	to	certain	weather	and	operational	claims.

2011	vs.	2010	Other,	net	decreased	primarily	due	to	excess	insurance	recoveries	received	in	2011	as	discussed	above.	The	remainder	of	the	variance	primarily relates	to	the	net	effect	of	interest	rate	derivatives	due	to	changes	in	the	related	interest	rates	upon	which	the	instruments	are	based.

# Income	Taxes

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

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
| Total\tincome\ttax\texpense\t(benefit)\t(in\tmillions) | $(132) | $2,156 | $1,235 |
| U.S.\tstatutory\tincome\ttax\trate | (35%) | 35% | 35% |
| State\tincome\ttaxes | 6% | 1% | 1% |
| Taxation\ton\tCanadian\toperations | (6%) | (2%) | (1%) |
| Assumed\trepatriations | 0% | 17% | 4% |
| Other | (7%) | (1%) | (4%) |
| Effective\tincome\ttax\trate | (42%) | 50% | 35% |

In	the	table	above,	the	"other"	effect	is	primarily	comprised	of	permanent	tax	differences	for	which	the	dollar	amounts	do	not	increase	or	decrease	as	our	pre-tax earnings	do.	Generally,	such	items	typically	have	an	insignificant	impact	on	our	effective	income	tax	rate.	However,	these	items	have	a	more	noticeable	impact	to	our rate	for	the	year	ended	December	31,	2012	because	of	the	relatively	small	pre-tax	loss	for	that	period.

During	2011	and	2010,	pursuant	to	the	completed	and	planned	divestitures	of	our	International	assets	located	outside	North	America,	a	portion	of	our	foreign earnings	were	no	longer	deemed	to	be	indefinitely	reinvested.	Accordingly,	we	recognized	deferred	income	tax	expense	of	$725	million	and	$144	million	during	2011 and	2010,	respectively,	related	to	assumed	repatriations	of	earnings	from	our	foreign	subsidiaries.

# Earnings	(Loss)	From	Discontinued	Operations

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Operating\tearnings | $— | $38 | $567 |
| Gain\t(loss)\ton\tsale\tof\toil\tand\tgas\tproperties | (16) | \t 2,552 | \t 1,818 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | (16) | \t 2,590 | \t 2,385 |
| Income\ttax\texpense | 5 | 20 | 168 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | $ (21) | $2,570 | $2,217 |

The	earnings	(loss)	in	each	period	were	primarily	driven	by	gains	(losses)	on	the	sales	of	our	oil	and	gas	assets	in	each	period.	The	following	table	presents	gains and	losses	on	our	divestiture	transactions	by	year.

|  | Gross | Net	of	Taxes | Gross | Net	of	Taxes | Gross | Net	of	Taxes |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) | (In\tmillions) |  |  |
| Angola | $ (16) | $(21) | $— | $— | $— | $— |
| Brazil | \t — | — | \t 2,548 | 2,548 | — | — |
| Azerbaijan | \t — | — | — | — | \t 1,543 | 1,524 |
| China\t-\tPanyu | \t — | — | — | — | 308 | 235 |
| Other | \t — | — | 4 | 4 | (33) | (27) |
| Total | $ (16) | $(21) | $2,552 | $2,552 | $1,818 | $1,732 |

# 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, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Operating\tcash\tflow\t-\tcontinuing\toperations | $4,930 | $6,246 | $5,022 |
| Debt\tactivity,\tnet | 1,921 | 4,187 | (1,782) |
| Divestitures\tof\tproperty\tand\tequipment | 1,539 | 3,380 | 7,002 |
| Capital\texpenditures | (8,225) | (7,534) | (6,476) |
| Shareholder\tdistributions | (324) | (2,610) | (1,449) |
| Other | 81 | (46) | 107 |
| Net\tchange\tin\tcash\tand\tshort-term\tinvestments | $(78) | $3,623 | $2,424 |
| Cash\tand\tshort-term\tinvestments\tat\tend\tof\tperiod | $6,980 | $7,058 | $3,435 |

# Operating	Cash	Flow	–	Continuing	Operations

Net	cash	provided	by	operating	activities	("operating	cash	flow")	continued	to	be	a	significant	source	of	capital	and	liquidity	in	2012.	Our	operating	cash	flow decreased	21	percent	during	2012	primarily	due	to	lower	commodity	prices	and	higher	expenses,	partially	offset	by	additional	cash	flow	from	our	production	growth	and higher	realized	gains	from	our	commodity	derivatives.

During	2012	our	operating	cash	flow	funded	approximately	three-fourths	of	our	cash	payments	for	capital	expenditures,	net	of	divestitures	proceeds.	Leveraging our	liquidity,	we	used	debt	to	fund	the	remainder	of	our	cash-based	capital	expenditures.

# Debt	Activity,	Net

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.

During	2011,	we	increased	our	commercial	paper	borrowings	by	$3.7	billion	and	received	$0.5	billion	from	new	debt	issuances,	net	of	debt	maturities.	Proceeds were	primarily	used	to	fund	capital	expenditures	and	common	stock	repurchases	in	excess	of	operating	cash	flow.

During	2010,	we	repaid	$1.4	billion	of	commercial	paper	borrowings	and	redeemed	our	$350	million	notes,	primarily	with	proceeds	received	from	our	U.S. Offshore	divestitures.

# Divestitures	of	Property	and	Equipment

During	2012,	we	closed	joint	venture	transactions	with	Sinopec	and	Sumitomo.	Sinopec	paid	approximately	$900	million	in	cash	and	received	a	33.3	percent interest	in	five	of	our	new	ventures	exploration	plays	in	the	U.S.	Sinopec	is	also	funding	approximately	$1.6	billion	of	our	share	of	future	exploration,	development	and drilling	costs	associated	with	these	plays.	Sumitomo	paid	approximately	$400	million	and	received	a	30	percent	interest	in	the	Cline	and	Midland-Wolfcamp	Shale	plays in	Texas.	Additionally,	Sumitomo	is	funding	approximately	$1.0	billion	of	our	share	of	future	exploration,	development	and	drilling	costs	associated	with	these	plays.	At December	31,	2012,	Sinopec's	and	Sumitomo's	remaining	commitment	to	fund	our	share	of	future	costs	associated	with	these	plays	was	approximately	$2.3	billion.

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.

In	2011	and	2010,	our	divestitures	primarily	related	to	the	divestitures	of	our	offshore	assets.

# Capital	Expenditures

The	amounts	in	the	table	below	reflect	cash	payments	for	capital	expenditures,	including	cash	paid	for	capital	expenditures	incurred	in	prior	periods.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| U.S.\tOnshore | $5,719 | $5,128 | $3,689 |
| Canada | \t 1,606 | \t 1,571 | \t 1,826 |
| North\tAmerica\tOnshore | \t 7,325 | \t 6,699 | \t 5,515 |
| U.S.\tOffshore | — | — | 376 |
| Total\toil\tand\tgas | \t 7,325 | \t 6,699 | \t 5,891 |
| Midstream | 504 | 333 | 236 |
| Other | 396 | 502 | 349 |
| Total\tcontinuing\toperations | $8,225 | $7,534 | $6,476 |

Our	capital	expenditures	consist	of	amounts	related	to	our	oil	and	gas	exploration	and	development	operations,	our	midstream	operations	and	other	corporate activities.	The	vast	majority	of	our	capital	expenditures	are	for	the	acquisition,	drilling	and	development	of	oil	and	gas	properties,	which	totaled	$7.3	billion,	$6.7	billion and	$5.9	billion	in	2012,	2011	and	2010,	respectively.	The	increases	in	exploration	and	development	capital	spending	in	2012	and	2011	were	primarily	due	to	new venture	acreage	acquisitions	and	increased	drilling	and	development.	With	rising	oil	prices	and	proceeds	from	our	offshore	divestitures,	we	have	increased	our	onshore North	American	acreage	positions	and	associated	exploration	and	development	activities	to	drive	near-term	growth	of	our	liquids,	particularly	oil,	production.

Capital	expenditures	for	our	midstream	operations	are	primarily	for	the	construction	and	expansion	of	natural	gas	processing	plants,	natural	gas	gathering	systems and	oil	pipelines.	Our	midstream	capital	expenditures	are	largely	impacted	by	oil	and	gas	drilling	activities.	Therefore,	the	increase	in	development	drilling	also increased	midstream	capital	activities.

Capital	expenditures	related	to	other	activities	decreased	in	2012.	This	decrease	is	largely	driven	by	the	construction	of	our	new	headquarters	in	Oklahoma	City being	substantially	complete	in	early	2012.

# Shareholder	Distributions

The	following	table	summarizes	our	share	repurchases	and	our	common	stock	dividends	(amounts	and	shares	in	millions).

|  |  | 2012 |  |  | 2011 |  |  | 2010 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Amount | Shares | Per\tShare | Amount | Shares | Per\tShare | Amount | Shares | Per\tShare |
| Repurchases | N/A | \t N/A | N/A | $2,332 | \t 31.3 | $74.54 | $1,168 | \t 17.9 | $65.28 |
| Dividends | $324 | \t N/A | $0.80 | $278 | \t N/A | $0.67 | $281 | \t N/A | $0.64 |

In	connection	with	our	offshore	divestitures,	we	conducted	a	$3.5	billion	share	repurchase	program	that	we	completed	in	the	fourth	quarter	of	2011.	Under	the program,	we	repurchased	49.2	million	shares,	representing	11	percent	of	our	outstanding	shares,	at	an	average	price	of	$71.18	per	share.

# 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	revolving	lines	of	credit	and	a	commercial	paper	program,

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

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	lower	commodity prices,	our	operating	cash	flow	from	continuing	operations	decreased	21	percent	to	$4.9	billion	in	2012.	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.	We expect	this	volatility	to	continue	throughout	2013.

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,	2012	are	presented	in	Note	2	to	the	financial	statements	under	"Item	8.	Financial Statements	and	Supplementary	Data"	of	this	report.

Commodity	prices	can	also	affect	our	operating	cash	flow	through	an	indirect	effect	on	operating	expenses.	Significant	commodity	price	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,	2012,	we	had	total	debt	of	$11.6	billion	with	an overall	weighted	average	borrowing	rate	of	4.0	percent.	We	have	derivative	financial	instruments	in	place	that	reduce	our	weighted-average	interest	rate	to	3.8	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.

# Credit	Availability

We	have	a	$3.0	billion	syndicated,	unsecured	revolving	line	of	credit	(the	"Senior	Credit	Facility").	The	Senior	Credit	Facility	has	an	initial	maturity	date	of October	24,	2017.	However,	prior	to	the	maturity	date,	we	have	the	option	to	extend	the	maturity	for	up	to	two	additional	one-year	periods,	subject	to	the	approval	of	the lenders.

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,	2012,	we	had	$2.9	billion	of	available	capacity	under	our syndicated,	unsecured	Senior	Credit	Facility,	net	of	letters	of	credit	outstanding.

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	impairments.	As	of	December	31,	2012,	we	were	in	compliance	with	this	covenant.	Our	debt-to-capitalization	ratio	at December	31,	2012,	as	calculated	pursuant	to	the	terms	of	the	agreement,	was	25.4	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	$5.0	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,	2012,	we	had	$3.2 billion	of	borrowings	under	our	commercial	paper	program.

At	the	end	of	2012,	we	held	approximately	$7.0	billion	of	cash	and	short-term	investments.	Included	in	this	total	was	$6.5	billion	of	cash	and	short-term investments	held	by	our	foreign	subsidiaries.	We	do	not	currently	expect	to	repatriate	the	$6.5	billion	to	the	U.S.	This	expectation	is	based	on	planned	investments	to develop	and	grow	our	Canadian	business,	our	current	forecasts	for	both	our	U.S.	and	Canadian	operations,	currently	favorable	borrowing	conditions	in	the	U.S.,	and existing	U.S.	income	tax	laws	pertaining	to	repatriations	of	foreign	earnings.	Therefore,	with	limited	cash	and	short-term	investments	in	the	U.S.,	we	expect	to	continue funding	our	U.S.	business	with	a	combination	of	our	U.S.-based	operating	cash	flow	and	borrowings.	We	do	not	expect	near-term	borrowing	increases	will	have	a material	negative	effect	on	our	overall	liquidity	or	financial	condition.

If	we	were	to	repatriate	a	portion	or	all	of	the	cash	and	short-term	investments	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	materially	decrease	the	amount	of	cash	and	short-term	investments	ultimately available	to	fund	our	business.

# Debt	Ratings

We	receive	debt	ratings	from	the	major	ratings	agencies	in	the	U.S.	In	determining	our	debt	ratings,	the	agencies	consider	a	number	of	qualitative	and	quantitative items	including,	but	not	limited	to,	commodity	pricing	levels,	our	liquidity,	asset	quality,	reserve	mix,	debt	levels,	cost	structure,	planned	asset	sales,	near-term	and long-term	production	growth	opportunities	and	capital	allocation	challenges.	Our	current	debt	ratings	are	BBB+	with	a	stable	outlook	by	both	Fitch	and	Standard	& Poor's,	and	Baa1	with	a	stable	outlook	by	Moody's.

There	are	no	"rating	triggers"	in	any	of	our	contractual	obligations	that	would	accelerate	scheduled	maturities	should	our	debt	rating	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	would	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	would	increase	the	fully-drawn	borrowing	costs	from	LIBOR	plus	112.5	basis	points	to	a	new	rate	of	LIBOR	plus	125	basis	points.	A	ratings downgrade	could	also	adversely	impact	our	ability	to	economically	access	debt	markets	in	the	future.	As	of	December	31,	2012,	we	were	not	aware	of	any	potential ratings	downgrades	being	contemplated	by	the	rating	agencies.

Our	2013	capital	expenditures	are	expected	to	range	from	$6.4	billion	to	$7.0	billion,	including	$5.3	billion	to	$5.8	billion	for	our	oil	and	gas	operations,	which include	capitalized	G&A	and	interest.	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	2013	capital	expenditures	until	later	periods	or	accelerate	capital	expenditures planned	for	periods	beyond	2013	to	achieve	the	desired	balance	between	sources	and	uses	of	liquidity.	Based	upon	current	price	expectations	for	2013,	our	existing commodity	hedging	contracts,	available	cash	balances	and	credit	availability,	we	anticipate	having	adequate	capital	resources	to	fund	our	2013	capital	expenditures.

Additionally,	our	financial	and	operational	flexibility	has	been	further	enhanced	by	the	joint	venture	transactions	that	we	entered	into	in	2012	with	Sinopec	and Sumitomo.	Pursuant	to	the	joint	venture	agreements,	Sinopec	and	Sumitomo	are	subject	to	drilling	carries	with	remaining	commitments	that	totaled	$2.3	billion	at	the end	of	2012.	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	is	allowing	us	to	accelerate	the	de-risking	and	commercialization	of	the	joint	venture	properties without	diverting	capital	from	our	core	development	projects.	We	expect	the	remaining	carries	will	be	realized	by	the	end	of	2014.

# Contractual	Obligations

A	summary	of	our	contractual	obligations	as	of	December	31,	2012,	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) | $11,664 | $3,189 | $500 | $1,250 | $6,725 |
| Interest\texpense\t(2) | 7,662 | 456 | 870 | 837 | 5,499 |
| Purchase\tobligations\t(3) | 6,995 | 826 | 1,723 | 1,705 | 2,741 |
| Operational\tagreements\t(4) | 3,496 | 391 | 797 | 682 | 1,626 |
| Asset\tretirement\tobligations\t(5) | 2,095 | 99 | 134 | 140 | 1,722 |
| Drilling\tand\tfacility\tobligations\t(6) | 950 | 777 | 173 | — | — |
| Lease\tobligations\t(7) | 312 | 50 | 65 | 56 | 141 |
| Other\t(8) | 339 | 122 | 149 | 53 | 15 |
| Total\tNorth\tAmerica | $33,513 | $5,910 | $4,411 | $4,723 | $18,469 |

(1) Debt	amounts	represent	scheduled	maturities	of	our	debt	obligations	at	December	31,	2012,	excluding	$20	million	of	net	discounts	included	in	the	carrying	value of	debt.

(2) Interest	expense	represents	the	scheduled	cash	payments	on	long-term,	fixed-rate	debt.

(3) Purchase	obligation	amounts	represent	contractual	commitments	primarily	to	purchase	condensate	at	market	prices	for	use	at	our	heavy	oil	projects	in	Canada.	We have	entered	into	these	agreements	because	condensate	is	an	integral	part	of	the	heavy	oil	production	and	transportation	processes.	Any	disruption	in	our	ability	to obtain	condensate	could	negatively	affect	our	ability	to	produce	and	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.

(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,	2012	balance	sheet.

(6) Drilling	and	facility	obligations	represent	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	$216	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	2012,	92	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	two	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	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.

# 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.	Our 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	U.S.	Treasury	bill	rates.	These	pricing	and	discounting	variables	are	sensitive	to	the	period	of	the	contract	and	market	volatility	as	well	as changes	in	forward	prices	and	regional	price	differentials.

We	periodically	enter	into	interest	rate	swaps	to	manage	our	exposure	to	interest	rate	volatility.	Under	the	terms	of	our	interest-rate	swaps,	we	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	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	commodity	derivative	contracts	are	held	with	fifteen separate	counterparties,	and	our	interest	rate	derivative	contracts	are	held	with	four	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.

# Goodwill

The	annual	impairment	test,	which	we	conduct	as	of	October	31	each	year,	includes	an	assessment	of	qualitative	factors	and	requires	us	to	estimate	the	fair	values of	our	own	assets	and	liabilities.	Because	quoted	market	prices	are	not	available	for	our	reporting	units,	we	must	estimate	the	fair	values	to	conduct	the	goodwill impairment	test.	The	most	significant	judgments	involved	in	estimating	the	fair	values	of	our	reporting	units	relate	to	the	valuation	of	our	property	and	equipment.	We develop	estimated	fair	values	of	our	property	and	equipment	by	performing	various	quantitative	analyses	using	information	related	to	comparable	companies, comparable	transactions	and	premiums	paid.

In	our	comparable	companies	analysis,	we	review	the	public	stock	market	trading	multiples	for	selected	publicly	traded	independent	exploration	and	production companies	with	financial	and	operating	characteristics	that	are	comparable	to	our	respective	reporting	units.	Such	characteristics	are	market	capitalization,	location	of proved	reserves	and	the	characterization	of	the	operations.	In	our	comparable	transactions	analysis,	we	review	certain	acquisition	multiples	for	selected	independent exploration	and	production	company	transactions	and	oil	and	gas	asset	packages	announced	recently.	In	our	premiums	paid	analysis,	we	use	a	sample	of	selected transactions	of	all	publicly	traded	companies	announced	recently.	We	then	review	the	premiums	paid	to	the	price	of	the	target	one	day	and	one	month	prior	to	the announcement	of	the	transaction.	We	use	this	information	to	determine	the	median	premiums	paid.

We	then	use	the	comparable	company	multiples,	comparable	transaction	multiples,	transaction	premiums	and	other	data	to	develop	valuation	estimates	of	our property	and	equipment.	We	also	use	market	and	other	data	to	develop	valuation	estimates	of	the	other	assets	and	liabilities	included	in	our	reporting	units.	At October	31,	2012,	the	date	of	our	last	impairment	test,	the	fair	values	of	our	U.S.	and	Canadian	reporting	units	exceeded	their	related	carrying	values.

A	lower	goodwill	value	decreases	the	likelihood	of	an	impairment	charge.	However,	unfavorable	changes	in	reserves	or	in	our	price	forecast	could	result	in	a goodwill	impairment	charge.	A	goodwill	impairment	charge	would	have	no	effect	on	liquidity	or	capital	resources.	However,	it	would	adversely	affect	our	results	of operations	in	that	period.

Due	to	the	inter-relationship	of	the	various	estimates	involved	in	assessing	goodwill	for	impairment,	it	is	impractical	to	provide	quantitative	analyses	of	the	effects of	potential	changes	in	these	estimates,	other	than	to	note	the	historical	average	changes	in	our	reserve	estimates.

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.	We	also	assess	factors	relative	to	whether	our	foreign	earnings	are	considered	permanently	reinvested. Changes	in	any	of	these	factors	could	require	recognition	of	additional	deferred,	or	even	current,	U.S.	income	tax	expense.	The	accruals	for	deferred	tax	assets	and liabilities	are	subject	to	a	significant	amount	of	judgment	by	management	and	are	reviewed	and	adjusted	routinely	based	on	changes	in	facts	and	circumstances.	Material changes	to	our	tax	accruals	may	occur	in	the	future	based	on	the	progress	of	ongoing	audits,	changes	in	legislation	or	resolution	of	pending	matters.

# Non-GAAP	Measures

We	make	reference	to	"adjusted	earnings",	"adjusted	earnings	per	share"	and	"adjusted	cash	flow"	in	"Overview	of	2012	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.	Adjusted	earnings represents	net	earnings	excluding	certain	non-cash	or	non-recurring	items	that	are	typically	excluded	by	securities	analysts	in	their	published	estimates	of	our	financial results.	Adjusted	cash	flow	represents	cash	flow	from	operating	activities	excluding	certain	balance	sheet	changes	and	non-recurring	items	that	are	typically	excluded	by securities	analysts	in	their	published	estimates	of	our	financial	results.	We	believe	these	non-GAAP	measures	facilitate	comparisons	of	our	performance	to	earnings	and cash	flow	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.	The	tables	below	exclude	amounts	related	to	our	discontinued	operations.

# Adjusted	Earnings	and	Adjusted	Earnings	Per	Share

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

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2012 | \t\t\t\t2011 | \t\t\t\t2010 |
|  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Earnings\t(loss)\t(GAAP) | $(185) | $2,134 | $2,333 |
| Adjustments\t(net\tof\ttaxes): |  |  |  |
| Asset\timpairments | 1,308 | — | — |
| Oil,\tgas\tand\tNGL\tderivatives | 112 | (310) | 50 |
| Restructuring\tcosts | 49 | (2) | 36 |
| Interest\trate\tand\tother\tfinancial\tinstruments | 21 | 72 | 19 |
| Income\ttax\taccrual\tadjustment | 17 | (42) | (58) |
| U.S.\tincome\ttaxes\ton\tforeign\tearnings | — | 744 | 144 |
| Insurance\tproceeds | — | (60) | — |
| Additional\tinterest\tcosts\ton\tdebt\tretirement | — | — | 12 |
| Adjusted\tearnings\t(Non-GAAP) | $1,322 | $2,536 | $2,536 |

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2012 | \t\t\t\t2011 | \t\t\t\t2010 |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Diluted\tearnings\tper\tshare\t(GAAP) | $(0.47) | $5.10 | $5.29 |
| Adjustments\t(net\tof\ttaxes): |  |  |  |
| Asset\timpairments | 3.23 | — | — |
| Oil,\tgas\tand\tNGL\tderivatives | 0.28 | (0.74) | 0.11 |
| Restructuring\tcosts | 0.13 | — | 0.08 |
| Interest\trate\tand\tother\tfinancial\tinstruments | 0.05 | 0.17 | 0.04 |
| Income\ttax\taccrual\tadjustment | 0.04 | (0.10) | (0.13) |
| U.S.\tincome\ttaxes\ton\tforeign\tearnings | — | 1.78 | 0.33 |
| Insurance\tproceeds | — | (0.14) | — |
| Additional\tinterest\tcosts\ton\tdebt\tretirement | — | — | 0.03 |
| Adjusted\tearnings\tper\tshare\t(Non-GAAP) | $3.26 | $6.07 | $5.75 |

# Adjusted	Cash	Flow

Below	is	a	reconciliation	of	our	adjusted	cash	flow	to	its	comparable	GAAP	measure.

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Cash\tflow\tfrom\toperating\tactivities\t(GAAP) | $4,930 | $6,246 | $5,022 |
| Adjustments\t(net\tof\ttaxes): |  |  |  |
| Changes\tin\tassets\tand\tliabilities | (19) | 275 | 282 |
| Cash\tflow\tfrom\toperating\tactivities\tbefore\tbalance\tsheet\tchanges\t(Non-GAAP) | \t 4,911 | \t 6,521 | \t 5,304 |
| Income\ttax\taccrual\tadjustment | (44) | (244) | (329) |
| Restructuring\tcosts | 25 | (3) | 64 |
| Insurance\tproceeds | — | (67) | — |
| Current\ttaxes\ton\tdivestitures | — | 18 | 783 |
| Current\ttaxes\ton\tdebt\tretirement | — | — | 18 |
| Adjusted\tcash\tflow\t(Non-GAAP) | $4,892 | $6,225 | $5,840 |

# 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	and	NGL	production.	Pricing	for	oil,	gas	and	NGL	production	has	been	volatile	and unpredictable	for	several	years	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,	gas	and	NGL	derivative	financial	instruments	as	of	December	31,	2012	are	presented in	Note	2	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,	2012,	a	10 percent	increase	and	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 | $(162) |  | $156 |
| Oil\tderivatives | $(214) |  | $229 |
| NGL\tderivatives | $(2) |  | $2 |

# Interest	Rate	Risk

At	December	31,	2012,	we	had	total	debt	of	$11.6	billion.	Our	long-term	debt	of	$8.4	billion	bears	fixed	interest	rates	averaging	5.4	percent.	The	remaining	$3.2 billion	of	commercial	paper	borrowings	bears	interest	at	fixed	rates	which	averaged	0.37	percent.	Our	commercial	paper	borrowings	typically	have	maturity	rates between	1	and	90	days.

As	of	December	31,	2012,	we	had	open	interest	rate	swap	positions	that	are	presented	in	Note	2	to	the	financial	statements	under	"Item	8.	Financial	Statements and	Supplementary	Data"	of	this	report.	The	fair	values	of	our	interest	rate	swaps	are	largely	determined	by	estimates	of	the	forward	curves	of	the	Federal	Funds	rate.	A 10	percent	change	in	these	forward	curves	would	not	have	materially	impacted	our	balance	sheet	at	December	31,	2012.

# 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,	2012	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	short-term	intercompany	loans	with	Canadian	subsidiaries	that	are	sometimes	based	in	Canadian	dollars.	Additionally,	at	December	31,	2012,	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.	The	value	of	the	intercompany	loans increases	or	decreases	from	the	remeasurement	of	the	loans	into	the	U.S.	dollar	functional	currency.	Based	on	the	amount	of	the	intercompany	loans	as	of	December	31, 2012,	a	10	percent	change	in	the	foreign	currency	exchange	rates	would	not	materially	impact	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 | 47 |
| :--- | :--- |
| Consolidated\tFinancial\tStatements |  |
| Consolidated\tComprehensive\tStatements\tof\tEarnings | 48 |
| Consolidated\tStatements\tof\tCash\tFlows | 49 |
| Consolidated\tBalance\tSheets | 50 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | 51 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 52 |

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,	2012	and	2011,	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,	2012. We	also	have	audited	Devon	Energy	Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2012,	based	on	criteria	established	in	Internal	Control	– Integrated	Framework	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,	2012	and	2011,	and	the	results	of	its	operations	and	its	cash	flows	for	each	of	the	years	in	the	three-year	period	ended	December	31, 2012,	in	conformity	with	U.S.	generally	accepted	accounting	principles.	Also	in	our	opinion,	Devon	Energy	Corporation	maintained,	in	all	material	respects,	effective internal	control	over	financial	reporting	as	of	December	31,	2012,	based	on	criteria	established	in	Internal	Control	–	Integrated	Framework	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

| Oil,	gas	and	NGL	sales | $7,153 | $8,315 | $7,262 |
| :--- | :--- | :--- | :--- |
| Oil,\tgas\tand\tNGL\tderivatives | 693 | 881 | 811 |
| Marketing\tand\tmidstream\trevenues | 1,656 | 2,258 | 1,867 |
| Total\trevenues | 9,502 | 11,454 | 9,940 |
| Expenses\tand\tother,\tnet: |  |  |  |
| Lease\toperating\texpenses | 2,074 | 1,851 | 1,689 |
| Marketing\tand\tmidstream\toperating\tcosts\tand\texpenses | 1,246 | 1,716 | 1,357 |
| Depreciation,\tdepletion\tand\tamortization | 2,811 | 2,248 | 1,930 |
| General\tand\tadministrative\texpenses | 692 | 585 | 563 |
| Taxes\tother\tthan\tincome\ttaxes | 414 | 424 | 380 |
| Interest\texpense | 406 | 352 | 363 |
| Restructuring\tcosts | 74 | (2) | 57 |
| Asset\timpairments | 2,024 | — | — |
| Other,\tnet | 78 | (10) | 33 |
| Total\texpenses\tand\tother,\tnet | 9,819 | 7,164 | 6,372 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | (317) | 4,290 | 3,568 |
| Current\tincome\ttax\texpense\t(benefit) | 52 | (143) | 516 |
| Deferred\tincome\ttax\texpense\t(benefit) | (184) | 2,299 | 719 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | (185) | 2,134 | 2,333 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations,\tnet\tof\ttax | (21) | 2,570 | 2,217 |
| Net\tearnings\t(loss) | $(206) | $4,704 | $4,550 |
| Basic\tnet\tearnings\t(loss)\tper\tshare: |  |  |  |
| Basic\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $(0.47) | $5.12 | $5.31 |
| Basic\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | (0.05) | 6.17 | 5.04 |
| Basic\tnet\tearnings\t(loss)\tper\tshare | $(0.52) | $11.29 | $10.35 |
| Diluted\tnet\tearnings\t(loss)\tper\tshare: |  |  |  |
| Diluted\tearnings\t(loss)\tfrom\tcontinuing\toperations\tper\tshare | $(0.47) | $5.10 | $5.29 |
| Diluted\tearnings\t(loss)\tfrom\tdiscontinued\toperations\tper\tshare | (0.05) | 6.15 | 5.02 |
| Diluted\tnet\tearnings\t(loss)\tper\tshare | $(0.52) | $11.25 | $10.31 |
| Comprehensive\tearnings\t(loss): |  |  |  |
| Net\tearnings\t(loss) | $(206) | $4,704 | $4,550 |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax: |  |  |  |
| Foreign\tcurrency\ttranslation | 194 | (191) | 377 |
| Pension\tand\tpostretirement\tplans | 2 | 6 | (2) |
| Other\tcomprehensive\tearnings\t(loss),\tnet\tof\ttax | 196 | (185) | 375 |
| Comprehensive\tearnings\t(loss) | $(10) | $4,519 | $4,925 |

See	accompanying	notes	to	consolidated	financial	statements.

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Cash\tflows\tfrom\toperating\tactivities: |  |  |  |
| Net\tearnings\t(loss) | $(206) | $4,704 | $4,550 |
| (Earnings)\tloss\tfrom\tdiscontinued\toperations,\tnet\tof\ttax | 21 | (2,570) | (2,217) |
| Adjustments\tto\treconcile\tearnings\tfrom\tcontinuing\toperations\tto\tnet\tcash\tfrom\toperating\tactivities: |  |  |  |
| Depreciation,\tdepletion\tand\tamortization | 2,811 | 2,248 | 1,930 |
| Asset\timpairments | 2,024 | — | — |
| Deferred\tincome\ttax\texpense\t(benefit) | (184) | 2,299 | 719 |
| Unrealized\tchange\tin\tfair\tvalue\tof\tfinancial\tinstruments | 205 | (401) | 107 |
| Other\tnoncash\tcharges | 240 | 241 | 215 |
| Net\tdecrease\t(increase)\tin\tworking\tcapital | (50) | 185 | (273) |
| Decrease\t(increase)\tin\tlong-term\tother\tassets | (36) | 33 | 32 |
| Increase\t(decrease)\tin\tlong-term\tother\tliabilities | 105 | (493) | (41) |
| Cash\tfrom\toperating\tactivities\t-\tcontinuing\toperations | 4,930 | 6,246 | 5,022 |
| Cash\tfrom\toperating\tactivities\t-\tdiscontinued\toperations | 26 | (22) | 456 |
| Net\tcash\tfrom\toperating\tactivities | 4,956 | 6,224 | 5,478 |
| Cash\tflows\tfrom\tinvesting\tactivities: |  |  |  |
| Capital\texpenditures | (8,225) | (7,534) | (6,476) |
| Proceeds\tfrom\tproperty\tand\tequipment\tdivestitures | 1,468 | 129 | 4,310 |
| Purchases\tof\tshort-term\tinvestments | (4,106) | (6,691) | (145) |
| Redemptions\tof\tshort-term\tinvestments | 3,266 | 5,333 | — |
| Other | 14 | (29) | 2 |
| Cash\tfrom\tinvesting\tactivities\t-\tcontinuing\toperations | (7,583) | (8,792) | (2,309) |
| Cash\tfrom\tinvesting\tactivities\t-\tdiscontinued\toperations | 57 | 3,146 | 2,197 |
| Net\tcash\tfrom\tinvesting\tactivities | (7,526) | (5,646) | (112) |
| Cash\tflows\tfrom\tfinancing\tactivities: |  |  |  |
| Proceeds\tfrom\tborrowings\tof\tlong-term\tdebt,\tnet\tof\tissuance\tcosts | 2,458 | 2,221 | — |
| Net\tshort-term\tborrowings\t(repayments) | (537) | 3,726 | (1,432) |
| Debt\trepayments | — | (1,760) | (350) |
| Credit\tfacility\tborrowings | 750 | — | — |
| Credit\tfacility\trepayments | (750) | — | — |
| Proceeds\tfrom\tstock\toption\texercises | 27 | 101 | 111 |
| Repurchases\tof\tcommon\tstock | — | (2,332) | (1,168) |
| Dividends\tpaid\ton\tcommon\tstock | (324) | (278) | (281) |
| Excess\ttax\tbenefits\trelated\tto\tshare-based\tcompensation | 5 | 13 | 16 |
| Net\tcash\tfrom\tfinancing\tactivities | 1,629 | 1,691 | (3,104) |
| Effect\tof\texchange\trate\tchanges\ton\tcash | 23 | (4) | 17 |
| Net\tchange\tin\tcash\tand\tcash\tequivalents | (918) | 2,265 | 2,279 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 5,555 | 3,290 | 1,011 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $4,637 | $5,555 | $3,290 |

# CONSOLIDATED	BALANCE	SHEETS

| Cash	and	cash	equivalents | $4,637 | $5,555 |
| :--- | :--- | :--- |
| Short-term\tinvestments | 2,343 | 1,503 |
| Accounts\treceivable | 1,245 | 1,379 |
| Other\tcurrent\tassets | 746 | 868 |
| Total\tcurrent\tassets | 8,971 | 9,305 |
| Property\tand\tequipment,\tat\tcost: |  |  |
| Oil\tand\tgas,\tbased\ton\tfull\tcost\taccounting: |  |  |
| Subject\tto\tamortization | 69,410 | 61,696 |
| Not\tsubject\tto\tamortization | 3,308 | 3,982 |
| Total\toil\tand\tgas | 72,718 | 65,678 |
| Other | 5,630 | 5,098 |
| Total\tproperty\tand\tequipment,\tat\tcost | 78,348 | 70,776 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | (51,032) | (46,002) |
| Property\tand\tequipment,\tnet | 27,316 | 24,774 |
| Goodwill | 6,079 | 6,013 |
| Other\tlong-term\tassets | 960 | 1,025 |
| Total\tassets | $43,326 | $41,117 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $1,451 | $1,471 |
| Revenues\tand\troyalties\tpayable | 750 | 678 |
| Short-term\tdebt | 3,189 | 3,811 |
| Other\tcurrent\tliabilities | 613 | 778 |
| Total\tcurrent\tliabilities | 6,003 | 6,738 |
| Long-term\tdebt | 8,455 | 5,969 |
| Asset\tretirement\tobligations | 1,996 | 1,496 |
| Other\tlong-term\tliabilities | 901 | 721 |
| Deferred\tincome\ttaxes | 4,693 | 4,763 |
| Stockholders'\tequity: |  |  |
| respectively | 41 | 40 |
| Additional\tpaid-in\tcapital | 3,688 | 3,507 |
| Retained\tearnings | 15,778 | 16,308 |
| Accumulated\tother\tcomprehensive\tearnings | 1,771 | 1,575 |
| Total\tstockholders'\tequity | 21,278 | 21,430 |
| Commitments\tand\tcontingencies\t(Note\t18) |  |  |
| Total\tliabilities\tand\tstockholders'\tequity | $43,326 | $41,117 |

# CONSOLIDATED	STATEMENTS	OF	STOCKHOLDERS'	EQUITY

|  | Common	Stock<br>Shares | Amount | Additional<br>Paid-In<br>Capital | Retained<br>Earnings | Accumulated<br>Other<br>Comprehensive<br>Earnings | Treasury<br>Stock | Total<br>Stockholders'<br>Equity |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (In\tmillions) |  |  |  |
| Balance\tas\tof\tDecember\t31,\t2009 | 447 | $45 | $6,527 | $7,613 | $1,385 | $— | $15,570 |
| Net\tearnings | \t — | — | — | 4,550 | — | — | 4,550 |
| Other\tcomprehensive\tearnings,\tnet\tof\ttax | \t — | — | — | — | 375 | — | 375 |
| Stock\toption\texercises | 2 | — | 117 | — | — | (6) | 111 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 2 | — | — | — | — | — | — |
| Common\tstock\trepurchased | \t — | — | — | — | — | (1,246) | (1,246) |
| Common\tstock\tretired | (19) | (2) | (1,217) | — | — | 1,219 | — |
| Common\tstock\tdividends | \t — | — | — | (281) | — | — | (281) |
| Share-based\tcompensation | \t — | — | 158 | — | — | — | 158 |
| Share-based\tcompensation\ttax\tbenefits | \t — | — | 16 | — | — | — | 16 |
| Balance\tas\tof\tDecember\t31,\t2010 | 432 | 43 | 5,601 | \t 11,882 | 1,760 | (33) | 19,253 |
| Net\tearnings | \t — | — | — | 4,704 | — | — | 4,704 |
| Other\tcomprehensive\tloss,\tnet\tof\ttax | \t — | — | — | — | (185) | — | (185) |
| Stock\toption\texercises | 2 | — | 112 | — | — | (11) | 101 |
| Restricted\tstock\tgrants,\tnet\tof\tcancellations | 1 | — | — | — | — | — | — |
| Common\tstock\trepurchased | \t — | — | — | — | — | (2,337) | (2,337) |
| Common\tstock\tretired | (31) | (3) | (2,378) | — | — | 2,381 | — |
| Common\tstock\tdividends | \t — | — | — | (278) | — | — | (278) |
| Share-based\tcompensation | \t — | — | 159 | — | — | — | 159 |
| Share-based\tcompensation\ttax\tbenefits | \t — | — | 13 | — | — | — | 13 |
| Balance\tas\tof\tDecember\t31,\t2011 | 404 | 40 | 3,507 | \t 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 | $15,778 | $1,771 | $— | $21,278 |

# 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	in	many	of	its	producing	areas,	making	it	one	of	North	America's	larger	processors	of	natural	gas.

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	accounts	of	Devon	and	its	wholly	owned	and	controlled	subsidiaries	are	included	in	the	accompanying	financial	statements.	All	significant	intercompany accounts	and	transactions	have	been	eliminated	in	consolidation.

# 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;

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

•asset	retirement	obligations;

•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	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

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	–	(Continued)

priced	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	2012,	2011	and	2010,	no	purchaser	accounted	for	more	than	10	percent	of	Devon's	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	and	interest	rate	risk.	Devon	does not	intend	to	hold	or	issue	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.	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's	interest	rate	swaps	include	contracts	in	which	Devon receives	a	fixed	rate	and	pays	a	variable	rate	on	a	total	notional	amount.	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,	2012,	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,	2012,	Devon	held	$63	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 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

Devon	grants	stock	options,	restricted	stock	awards	and	other	types	of	share-based	awards	to	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 comprehensive	statements	of	earnings	over	the	applicable	requisite	service	periods.	As	a	result	of	Devon's	strategic	repositioning	announced	in	2009	and	the consolidation	of	its	U.S.	operations	announced	in	October	2012,	certain	share	based	awards	were	accelerated	and	recognized	as	a	component	of	restructuring	expense	in the	accompanying	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	cancelled	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	bases. 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	permanently	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	Common	Share

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	U.S.	and	Canadian	treasury	securities	and	other	marketable	securities.	During	2012	and	2011,	Devon	invested	a	portion of	its	joint	venture	proceeds	and	a	portion	of	the	International	offshore	divestiture	proceeds	into	such	securities,	causing	short-term	investments	to	increase.

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.	Such	debt	securities	totaled	$64	million	and	$84	million	at	December	31,	2012	and	2011,	respectively	and	are	included	in	other	long-term	assets	in	the accompanying	balance	sheet.	Devon	has	the	ability	to	hold	the	securities	until	maturity	and	does	not	believe	the	values	of	its	long-term	securities	are	impaired.

# 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.

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,	2012,	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.

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.

Depreciation	of	midstream	pipelines	are	provided	on	a	unit-of-production	basis.	Depreciation	and	amortization	of	other	property	and	equipment,	including corporate	and	other	midstream	assets	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	at	least annually.	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	2012,	2011	and	2010.	Based	on	these	assessments,	no	impairment	of	goodwill	was required.

The	table	below	provides	a	summary	of	Devon's	goodwill,	by	assigned	reporting	unit.	The	increase	in	Devon's	goodwill	from	2011	to	2012	was	due	to	changes	in the	exchange	rate	between	the	U.S.	dollar	and	the	Canadian	dollar.

|  | 2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| U.S. | $3,046 | $3,046 |
| Canada | 3,033 | 2,967 |
| Total | $6,079 | $6,013 |

# 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

As	a	result	of	the	November	2009	plan	to	divest	Devon's	offshore	assets,	all	amounts	related	to	Devon's	International	operations	are	classified	as	discontinued operations.	The	Gulf	of	Mexico	properties	that	were	divested	in	2010	do	not	qualify	as	discontinued	operations	under	accounting	rules.	As	such,	amounts	in	these

notes	and	the	accompanying	financial	statements	that	pertain	to	continuing	operations	include	amounts	related	to	Devon's	offshore	Gulf	of	Mexico	operations.

# Foreign	Currency	Translation	Adjustments

The	U.S.	dollar	is	the	functional	currency	for	Devon's	consolidated	operations	except	its	Canadian	subsidiaries,	which	use	the	Canadian	dollar	as	the	functional currency.	Assets	and	liabilities	of	the	Canadian	subsidiaries	are	translated	to	U.S.	dollars	using	the	applicable	exchange	rate	as	of	the	end	of	a	reporting	period.

Revenues,	expenses	and	cash	flow	are	translated	using	an	average	exchange	rate	during	the	reporting	period.	Translation	adjustments	have	no	effect	on	net	income	and are	included	in	accumulated	other	comprehensive	earnings	in	stockholders'	equity.

# Commodity	Derivatives

As	of	December	31,	2012,	Devon	had	the	following	open	oil	derivative	positions.	Devon's	oil	derivatives	settle	against	the	average	of	the	prompt	month	NYMEX West	Texas	Intermediate	futures	price.

|  | Price	Swaps | 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\t2013 | \t31,000 | $104.13 | \t45,753 | $91.19 | $115.97 | \t10,000 | $120.00 |
| Q1-Q4\t2014 | 4,000 | $100.49 | 2,000 | $90.00 | $111.13 | \t10,000 | $120.00 |

|  | Basis	Swaps |  |  |
| :--- | :--- | :--- | :--- |
| Period | Index | Volume\t(Bbls/d) | Weighted\tAverage\nDifferential\tto\tWTI\n($/Bbl) |
| Q1-Q2\t2013 | Western\tCanadian\tSelect | 3,000 | $(19.58) |

As	of	December	31,	2012,	Devon	had	the	following	open	natural	gas	derivative	positions.	The	first	table	presents	Devon's	natural	gas	swaps	and	collars	that	settle against	the	Inside	FERC	first	of	the	month	Henry	Hub	index.	The	second	table	presents	Devon's	natural	gas	swaps	and	collars	that	settle	against	the	AECO	index.

|  |  | Price	Swaps |  | Price	Collars |  | Call	Options	Sold |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  |  |  |  | Weighted |
|  |  | Weighted |  | Weighted\tAverage | Weighted\tAverage |  | Average |
| Period | Volume\n(MMBtu/d) | Average\t\tPrice\n($/MMBtu) | Volume\n(MMBtu/d) | Floor\tPrice\n($/MMBtu) | Ceiling\tPrice\n($/MMBtu) | Volume\n(MMBtu/d) | Price\n($/MMBtu) |
| Q1-Q4\t2013 | \t 560,000 | $4.18 | \t 461,370 | $3.53 | $4.33 | — | — |
| Q1-Q4\t2014 | \t 250,000 | $4.09 | — | — | — | \t 250,000 | $5.00 |

|  |  | Price	Swaps |
| :--- | :--- | :--- |
| Period | Volume\n(MMBtu/d) | Weighted\tAverage\nPrice\t($/MMBtu) |
| Q1-Q4\t2013 | 28,435 | $3.64 |

| Period | Index | Volume<br>(MMBtu/d) | Differential	to	Henry	Hub<br>($/MMBtu) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2013 | El\tPaso\tNatural\tGas | 20,000 | $(0.12) |
| Q1-Q4\t2013 | Panhandle\tEastern\tPipeline | 20,000 | $(0.17) |

As	of	December	31,	2012,	Devon	had	the	following	open	NGL	derivative	positions.	Devon's	NGL	swaps	settle	against	the	average	of	the	prompt	month	OPIS Mont	Belvieu,	Texas	hub.

| Period | Pay | Volume<br>(Bbls/d) | Weighted	Average<br>Differential	to	WTI<br>($/Bbl) |
| :--- | :--- | :--- | :--- |
| Q1-Q4\t2013 | Natural\tGasoline | 500 | $(6.80) |

# Interest	Rate	Derivatives

As	of	December	31,	2012,	Devon	had	the	following	open	interest	rate	derivative	positions:

# Foreign	Currency	Derivatives

As	of	December	31,	2012,	Devon	had	the	following	open	foreign	currency	derivative	positions:

|  | Forward	Contract |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Currency | Contract\nType | CAD\nNotional | Weighted\tAverage\nFixed\tRate\tReceived | Expiration |
|  |  | (In\tmillions) | (CAD-USD) |  |
| Canadian\tDollar | Sell | $755 | 1.005 | March\t2013 |

# Financial	Statement	Presentation

The	following	table	presents	the	cash	settlements	and	unrealized	gains	and	losses	on	fair	value	changes	included	in	the	accompanying	comprehensive	statements of	earnings	associated	with	derivative	financial	instruments.

|  | Comprehensive	Statement	of	Earnings	Caption | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |
| Cash\tsettlements: |  |  |  |  |
| Commodity\tderivatives | Oil,\tgas\tand\tNGL\tderivatives | $870 | $392 | $888 |
| Interest\trate\tderivatives | Other,\tnet | 14 | 77 | 44 |
| Foreign\tcurrency\tderivatives | Other,\tnet | (19) | 16 | \t — |
| Total\tcash\tsettlements |  | 865 | \t 485 | 932 |
| Unrealized\tgains\t(losses): |  |  |  |  |
| Commodity\tderivatives | Oil,\tgas\tand\tNGL\tderivatives | (177) | \t 489 | (77) |
| Interest\trate\tderivatives | Other,\tnet | (29) | (88) | (30) |
| Foreign\tcurrency\tderivatives | Other,\tnet | 1 | \t — | \t — |
| Total\tunrealized\tgains\t(losses) | Total\tunrealized\tgains\t(losses) | (205) | \t 401 | (107) |
| Net\tgain\trecognized\ton\tcomprehensive\tstatements\tof\tearnings | Net\tgain\trecognized\ton\tcomprehensive\tstatements\tof\tearnings | $660 | $886 | $825 |

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

|  | Balance	Sheet	Caption | December	31,<br>				2012 | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Asset\tderivatives: |  |  |  |
| Commodity\tderivatives | Other\tcurrent\tassets | $379 | $611 |
| Commodity\tderivatives | Other\tlong-term\tassets | 22 | 17 |
| Interest\trate\tderivatives | Other\tcurrent\tassets | 23 | 30 |
| Interest\trate\tderivatives | Other\tlong-term\tassets | — | 22 |
| Foreign\tcurrency\tderivatives | Other\tcurrent\tassets | 1 | — |
| Total\tasset\tderivatives | Total\tasset\tderivatives | $425 | $680 |
| Liability\tderivatives: |  |  |  |
| Commodity\tderivatives | Other\tcurrent\tliabilities | $3 | $82 |
| Commodity\tderivatives | Other\tlong-term\tliabilities | 29 | — |
| Total\tliability\tderivatives | Total\tliability\tderivatives | $32 | $82 |

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,	Canadian	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	also	has	stock	options outstanding	that	were	assumed	as	part	of	its	2003	acquisition	of	Ocean	Energy.

The	following	table	presents	the	effects	of	share-based	compensation	included	in	Devon's	accompanying	comprehensive	statements	of	earnings.	The	vesting	for certain	share-based	awards	was	accelerated	as	part	of	Devon's	strategic	repositioning	announced	in	2009	and	the	consolidation	of	its	U.S.	operations	announced	in October	2012.	The	associated	expense	for	these	accelerated	awards	is	included	in	restructuring	costs	in	the	accompanying	comprehensive	statements	of	earnings.	See Note	4	for	further	details.

|  | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Gross\tgeneral\tand\tadministrative\texpense | $179 | $181 | $188 |
| Share-based\tcompensation\texpense\tcapitalized\tpursuant\tto\tthe\tfull\tcost\tmethod\tof\taccounting\tfor\toil |  |  |  |
| and\tgas\tproperties | $56 | $56 | $58 |
| Related\tincome\ttax\tbenefit | $31 | $33 | $40 |

# 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	U.S.	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.	All	such	amounts	represent	the	weighted-average	amounts	for	each	year.

|  | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
| Grant-date\tfair\tvalue | $22.20 | $23.11 | $25.41 |
| Volatility\tfactor | 42.5% | 46.0% | 45.3% |
| Dividend\tyield | 1.2% | 1.0% | 1.0% |
| Risk-free\tinterest\trate | 1.1% | 0.8% | 1.1% |
| Expected\tterm\t(in\tyears) | 6.0 | 4.2 | 4.5 |

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

|  |  | Weighted	Average |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Options | Exercise\nPrice | Remaining\nTerm | Intrinsic\nValue |
|  | (In\tthousands) |  | (In\tyears) | (In\tmillions) |
| Outstanding\tat\tDecember\t31,\t2011 | 10,543 | $66.35 |  |  |
| Granted | 18 | $60.09 |  |  |
| Exercised | (1,390) | $35.16 |  |  |
| Expired | (1,058) | $85.98 |  |  |
| Forfeited | (285) | $68.90 |  |  |
| Outstanding\tat\tDecember\t31,\t2012 | 7,828 | $69.12 | 4.24 | $0 |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2012 | 7,742 | $69.14 | 4.22 | $0 |
| Exercisable\tat\tDecember\t31,\t2012 | 5,695 | $69.35 | 3.47 | $0 |

The	aggregate	intrinsic	value	of	stock	options	that	were	exercised	during	2012,	2011	and	2010	was	$34	million,	$81	million	and	$47	million,	respectively.	As	of December	31,	2012,	Devon's	unrecognized	compensation	cost	related	to	unvested	stock	options	was	$39	million.	Such	cost	is	expected	to	be	recognized	over	a weighted-average	period	of	2.4	years.

# Restricted	Stock	Awards	and	Units

These	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<br>&amp;	Units | Average<br>Grant-Date<br>Fair	Value |
| :--- | :--- | :--- |
|  | (In\tthousands) |  |
| Unvested\tat\tDecember\t31,\t2011 | 5,224 | $67.85 |
| Granted | 2,870 | $53.22 |
| Vested | (2,101) | $68.34 |
| Forfeited | (253) | $67.32 |
| Unvested\tat\tDecember\t31,\t2012 | 5,740 | $61.75 |

The	aggregate	fair	value	of	restricted	stock	awards	and	units	that	vested	during	2012,	2011	and	2010	was	$112	million,	$145	million	and	$184	million, respectively.	As	of	December	31,	2012,	Devon's	unrecognized	compensation	cost	related	to	unvested	restricted	stock	awards	and	units	was	$314	million.	Such	cost	is expected	to	be	recognized	over	a	weighted-average	period	of	2.9	years.

# Performance	Based	Restricted	Stock	Awards

In	December	2012	and	2011,	certain	members	of	Devon's	senior	management	were	granted	performance	based	share	awards.	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,\t2011 | 184 | $65.10 |
| Granted | 224 | $52.60 |
| Unvested\tat\tDecember\t31,\t2012 | 408 | $58.25 |

As	of	December	31,	2012,	Devon's	unrecognized	compensation	cost	related	to	these	awards	was	$8	million.	Such	cost	is	expected	to	be	recognized	over	a weighted-average	period	of	2.3	years.

# Performance	Share	Units

In	December	2012	and	2011,	certain	members	of	Devon's	management	were	granted	performance	share	units.	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	U.S.	Treasury	rates	as	of	the	grant	date;	(ii)	a	volatility	assumption	based	on	the	historical	realized	price	volatility	of	Devon	and	the	designated	peer	group;	and (iii)	an	estimated	ranking	of	Devon	among	the	designated	peer	group.	The	fair	value	of	the	unit	on	the	date	of	grant	is	expensed	over	the	applicable	vesting	period.	The following	table	presents	a	summary	of	the	grant-date	fair	values	of	performance	share	units	granted	and	the	related	assumptions.

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| Grant-date\tfair\tvalue | $61.27\t-\t$63.48 | $80.24\t-\t$83.15 |
| Risk-free\tinterest\trate | 0.26%\t-\t0.36% | 0.28%\t-\t0.43% |
| Volatility\tfactor | 30.3% | 41.8% |
| Contractual\tterm\t(in\tyears) | 3.0 | 3.0 |

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

|  | Performance<br>Share	Units | Grant-Date<br>Fair	Value |
| :--- | :--- | :--- |
|  | (In\tthousands) |  |
| Unvested\tat\tDecember\t31,\t2011 | 171 | $81.70 |
| Granted | 707 | $63.37 |
| Unvested\tat\tDecember\t31,\t2012\t(1) | 878 | $66.93 |

(1) A	maximum	of	1.8	million	common	shares	could	be	awarded	based	upon	Devon's	final	TSR	ranking.

As	of	December	31,	2012,	Devon's	unrecognized	compensation	cost	related	to	unvested	units	was	$40	million.	Such	cost	is	expected	to	be	recognized	over	a weighted-average	period	of	2.5	years.

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	is	in	the	process	of	closing	its	office	in	Houston	and	transferring	operational	responsibilities	for	assets	in	South Texas,	East	Texas	and	Louisiana	to	Oklahoma	City.	This	initiative	is	expected	to	be	substantially	complete	by	the	end	of	the	first	quarter	2013.

Including	the	$80	million	recognized	in	December	of	2012,	Devon	estimates	that	it	will	incur	approximately	$135	million	in	restructuring	costs	in	connection	with this	plan.	This	estimate	includes	approximately	$85	million	of	employee	severance	and	relocation	costs,	$35	million	of	contract	termination	and	other	costs	and	$15 million	of	employee	retention	costs.	Approximately	$25	million	of	employee	costs	relates	to	accelerated	vesting	of	stock	awards,	which	are	non-cash	charges.	Devon expects	to	recognize	the	remainder	of	the	restructuring	costs	during	2013.

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	comprehensive	statements	of	earnings.	Restructuring	costs	relating	to	Devon's discontinued	operations	totaled	$(2)	million	and	$(4)	million	in	2011	and	2010,	respectively.	These	costs	primarily	related	to	cash	severance	and	share-based	awards	and are	not	included	in	the	schedule	below.	There	were	no	costs	related	to	discontinued	operations	in	2012.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Office\tconsolidation: |  |  |  |
| Employee\tseverance | $ 77 | $ — | $ — |
| Lease\tobligations | 3 | \t — | — |
| Total | 80 | \t — | — |
| Offshore\tdivestitures: |  |  |  |
| Employee\tseverance | (3) | 8 | (27) |
| Lease\tobligations\tand\tother | (3) | (10) | 84 |
| Total | (6) | (2) | 57 |
| Restructuring\tcosts | $ 74 | $(2) | $57 |

Employee	severance	and	retention	-	In	the	fourth	quarter	of	2012,	Devon	recognized	$77	million	of	estimated	employee	severance	costs	associated	with	the	office consolidation.	This	amount	was	based	on	estimates	of	the	number	employees	that	would	ultimately	be	impacted	by	office	consolidation	and	included	amounts	related	to cash	severance	costs	and	accelerated	vesting	of	share-based	grants.

Lease	obligations	and	other	-	As	of	December	31,	2012,	Devon	incurred	$3	million	of	restructuring	costs	related	to	certain	office	space	that	is	subject	to	non- cancellable	operating	lease	agreements	and	that	it	ceased	using	as	a	part	of	the	office	consolidation.	In	2013	Devon	expects	to	incur	approximately	$25	million	of additional	restructuring	costs	that	represent	the	present	value	of	its	future	obligations	under	the	leases,	net	of	anticipated	sublease	income.	Devon's	estimate	of	lease obligations	was	based	upon	certain	key	estimates	that	could	change	over	the	term	of	the	leases.	These	estimates	include	the	estimated	sublease	income	that	it	may receive	over	the	term	of	the	leases,	as	well	as	the	amount	of	variable	operating	costs	that	it	will	be	required	to	pay	under	the	leases.

Lease	obligations	and	other	-	As	a	result	of	the	divestitures,	Devon	ceased	using	certain	office	space	that	was	subject	to	non-cancellable	operating	lease arrangements.	Consequently,	in	2010	Devon	recognized	$70	million	of	restructuring	costs	that	represented	the	present	value	of	its	future	obligations	under	the	leases,	net of	anticipated	sublease	income.	Devon's	estimate	of	lease	obligations	was	based	upon	certain	key	estimates	that	could	change	over	the	term	of	the	leases.	These estimates	include	the	estimated	sublease	income	that	Devon	may	receive	over	the	term	of	the	leases,	as	well	as	the	amount	of	variable	operating	costs	that	Devon	will	be required	to	pay	under	the	leases.	In	addition,	Devon	recognized	$13	million	of	asset	impairment	charges	for	leasehold	improvements	and	furniture	associated	with	the office	space	that	it	ceased	using.

The	schedule	below	summarizes	Devon's	restructuring	liabilities.	Devon's	restructuring	liabilities	for	cash	severance	related	to	its	discontinued	operations	totaled $16	million	at	December	31,	2010	and	are	not	included	in	the	schedule	below.	There	was	no	liability	related	to	discontinued	operations	at	the	end	of	2012	or	2011.

|  | Other<br>Current<br>Liabilities | Other<br>Long-Term<br>Liabilities | Total |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Balance\tas\tof\tDecember\t31,\t2010 | $31 | $51 | $82 |
| Lease\tobligations\t-\tOffshore | 2 | (35) | (33) |
| Employee\tseverance\t-\tOffshore | (4) | — | (4) |
| Balance\tas\tof\tDecember\t31,\t2011 | 29 | 16 | 45 |
| Employee\tseverance\t–\tOffice\tconsolidation | 49 | — | 49 |
| Lease\tobligations\t-\tOffshore | (17) | (7) | (24) |
| Employee\tseverance\t-\tOffshore | (9) | — | (9) |
| Balance\tas\tof\tDecember\t31,\t2012 | $52 | $9 | $61 |

The	components	of	other,	net	in	the	accompanying	comprehensive	statement	of	earnings	include	the	following:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Accretion\tof\tasset\tretirement\tobligations | $110 | $92 | $92 |
| Interest\trate\tderivatives | 15 | 11 | (14) |
| Foreign\tcurrency\tderivatives | 18 | (16) | \t — |
| Foreign\texchange\tloss\t(gain) | (15) | 25 | (7) |
| Interest\tincome | (36) | (21) | (13) |
| Other | (14) | (101) | (25) |
| Other,\tnet | $78 | $(10) | $33 |

During	2011,	Devon	received	$88	million	of	excess	insurance	recoveries	related	to	certain	weather	and	operational	claims.

# Income	Tax	Expense	(Benefit)

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

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Current\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | $60 | $(143) | $244 |
| Various\tstates | (3) | 20 | 16 |
| Canada\tand\tvarious\tprovinces | (5) | (20) | 256 |
| Total\tcurrent\ttax\texpense\t(benefit) | 52 | (143) | 516 |
| Deferred\tincome\ttax\texpense\t(benefit): |  |  |  |
| U.S.\tfederal | (188) | \t 1,986 | 781 |
| Various\tstates | 34 | 95 | 21 |
| Canada\tand\tvarious\tprovinces | (30) | 218 | (83) |
| Total\tdeferred\ttax\texpense\t(benefit) | (184) | \t 2,299 | 719 |
| Total\tincome\ttax\texpense\t(benefit) | $(132) | $2,156 | $1,235 |

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

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
|  | $(111) | $1,502 | $1,249 |
| Assumed\trepatriations | \t — | 725 | 144 |
| State\tincome\ttaxes | 20 | 70 | 31 |
| Taxation\ton\tCanadian\toperations | (19) | (91) | (60) |
| Other | (22) | (50) | (129) |
| Total\tincome\ttax\texpense\t(benefit) | $(132) | $2,156 | $1,235 |

During	2011	and	2010,	pursuant	to	the	completed	and	planned	divestitures	of	Devon's	International	assets	located	outside	North	America,	a	portion	of	Devon's foreign	earnings	were	no	longer	deemed	to	be	indefinitely	reinvested.	Accordingly,	Devon	recognized	deferred	income	tax	expense	of	$725	million	and	$144	million during	2011	and	2010	respectively,	related	to	assumed	repatriations	of	earnings	from	its	foreign	subsidiaries.

# 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:

|  | 2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Deferred\ttax\tassets: |  |  |
| Net\toperating\tloss\tcarryforwards | $427 | $222 |
| Asset\tretirement\tobligations | 618 | 447 |
| Pension\tbenefit\tobligations | 129 | 130 |
| Alternative\tminimum\ttax\tcredits | 198 | — |
| Other | 134 | 117 |
| Total\tdeferred\ttax\tassets | 1,506 | 916 |
| Deferred\ttax\tliabilities: |  |  |
| Property\tand\tequipment | (4,970) | (4,475) |
| Fair\tvalue\tof\tfinancial\tinstruments | (141) | (218) |
| Long-term\tdebt | (198) | (185) |
| Taxes\ton\tunremitted\tforeign\tearnings | (936) | (936) |
| Other | (76) | (27) |
| Total\tdeferred\ttax\tliabilities | (6,321) | (5,841) |
| Net\tdeferred\ttax\tliability | $(4,815) | $(4,925) |

Devon	has	recognized	$427	million	of	deferred	tax	assets	related	to	various	carryforwards	available	to	offset	future	income	taxes.	The	carryforwards	consist	of $711	million	of	U.S.	federal	net	operating	loss	carryforwards,	which	expire	in	2031,	$662	million	of	Canadian	net	operating	loss	carryforwards,	which	expire	between 2029	and	2031,	and	$153	million	of	state	net	operating	loss	carryforwards,	which	expire	primarily	between	2013	and	2031.	Devon	expects	the	tax	benefits	from	the	U.S. federal	net	operating	loss	carryforwards	to	be	utilized	between	2013	and	2015.	Devon	expects	the	tax	benefits	from	the	Canadian	and	state	net	operating	loss carryforwards	to	be	utilized	between	2013	and	2017.	Such	expectations	are	based	upon	current	estimates	of	taxable	income	during	these	periods,	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 prior	to	their	expiration.	Devon	has	also	recognized	a	$198	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.

As	of	December	31,	2012,	Devon's	unremitted	foreign	earnings	totaled	approximately	$8.0	billion.	Of	this	amount,	approximately	$5.5	billion	was	deemed	to	be indefinitely	reinvested	into	the	development	and	growth	of	our	Canadian	business.	Therefore,	Devon	has	not	recognized	a	deferred	tax	liability	for	U.S.	income	taxes associated	with	such	earnings.	If	such	earnings	were	to	be	repatriated	to	the	U.S.,	Devon	may	be	subject	to	U.S.	income	taxes	and	foreign	withholding	taxes.	However,	it is	not	practical	to	estimate	the	amount	of	such	additional	taxes	that	may	be	payable	due	to	the	inter-relationship	of	the	various	factors	involved	in	making	such	an estimate.

Devon	has	deemed	the	remaining	$2.5	billion	of	unremitted	earnings	not	to	be	indefinitely	reinvested.	Consequently,	Devon	has	recognized	a	$936	million deferred	tax	liability	associated	with	such	unremitted	earnings	as	of	December	31,	2012.	Although	Devon	has	recognized	this	deferred	tax	liability,	Devon	does	not currently	expect	to	repatriate	its	foreign	earnings.	This	expectation	is	based	on	Devon's	current	forecasts	for	both	its	U.S.	and	Canadian	operations,	currently	favorable borrowing	conditions	in	the	U.S.,	and	existing	U.S.	income	tax	laws	pertaining	to	repatriations	of	foreign	earnings.

# Unrecognized	Tax	Benefits

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

|  | 2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Balance\tat\tbeginning\tof\tyear | $165 | $194 |
| Tax\tpositions\ttaken\tin\tprior\tperiods | (46) | (3) |
| Tax\tpositions\ttaken\tin\tcurrent\tyear | 92 | 27 |
| Accrual\tof\tinterest\trelated\tto\ttax\tpositions\ttaken | 7 | (7) |
| Lapse\tof\tstatute\tof\tlimitations | (3) | (41) |
| Settlements | — | (5) |
| Foreign\tcurrency\ttranslation | 1 | — |
| Balance\tat\tend\tof\tyear | $216 | $165 |

Devon's	unrecognized	tax	benefit	balance	at	December	31,	2012	and	2011,	included	$27	million	and	$20	million	of	interest	and	penalties,	respectively.	If recognized,	$176	million	of	Devon's	unrecognized	tax	benefits	as	of	December	31,	2012	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.

# 7. Earnings	Per	Share

The	following	table	reconciles	earnings	from	continuing	operations	and	common	shares	outstanding	used	in	the	calculations	of	basic	and	diluted	earnings	per

share.

|  |  | Common | Earnings |
| :--- | :--- | :--- | :--- |
|  | Earnings | Shares | per\tShare |
|  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Year\tEnded\tDecember\t31,\t2012: |  |  |  |
| Loss\tfrom\tcontinuing\toperations | $(185) | 404 |  |
| Attributable\tto\tparticipating\tsecurities | (3) | (4) |  |
| Basic\tand\tdiluted\tloss\tper\tshare | $(188) | 400 | $(0.47) |
| Year\tEnded\tDecember\t31,\t2011: |  |  |  |
| Earnings\tfrom\tcontinuing\toperations | $2,134 | 417 |  |
| Attributable\tto\tparticipating\tsecurities | (23) | (5) |  |
| Basic\tearnings\tper\tshare | 2,111 | 412 | $5.12 |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | 2 |  |
| Diluted\tearnings\tper\tshare | $2,111 | 414 | $5.10 |
| Year\tEnded\tDecember\t31,\t2010: |  |  |  |
| Earnings\tfrom\tcontinuing\toperations | $2,333 | 440 |  |
| Attributable\tto\tparticipating\tsecurities | (26) | (5) |  |
| Basic\tearnings\tper\tshare | 2,307 | 435 | $5.31 |
| Dilutive\teffect\tof\tpotential\tcommon\tshares\tissuable | — | 1 |  |
| Diluted\tearnings\tper\tshare | $2,307 | 436 | $5.29 |

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	9	million,	3	million	and	6	million	in	2012,	2011	and	2010,	respectively.

# 8. Other	Comprehensive	Earnings

Components	of	other	comprehensive	earnings	consist	of	the	following:

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Foreign\tcurrency\ttranslation: |  |  |  |
| Beginning\taccumulated\tforeign\tcurrency\ttranslation | $1,802 | $1,993 | $1,616 |
| Change\tin\tcumulative\ttranslation\tadjustment | 203 | (200) | 397 |
| Income\ttax\tbenefit\t(expense) | (9) | 9 | (20) |
| Ending\taccumulated\tforeign\tcurrency\ttranslation | \t 1,996 | \t 1,802 | \t 1,993 |
| Pension\tand\tpostretirement\tbenefit\tplans: |  |  |  |
| Beginning\taccumulated\tpension\tand\tpostretirement\tbenefits | (227) | (233) | (231) |
| Net\tactuarial\tloss\tand\tprior\tservice\tcost\tarising\tin\tcurrent\tyear | (47) | (21) | (33) |
| Income\ttax\tbenefit | 16 | 8 | 11 |
| Recognition\tof\tnet\tactuarial\tloss\tand\tprior\tservice\tcost\tin\tnet\tearnings | 51 | 30 | 31 |
| Income\ttax\texpense | (18) | (11) | (11) |
| Ending\taccumulated\tpension\tand\tpostretirement\tbenefits | (225) | (227) | (233) |
| Accumulated\tother\tcomprehensive\tearnings,\tnet\tof\ttax | $1,771 | $1,575 | $1,760 |

# 9. Supplemental	Information	to	Statements	of	Cash	Flows

|  | 2012 | 2011 | 2010 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Net\tdecrease\t(increase)\tin\tworking\tcapital: |  |  |  |
| Change\tin\taccounts\treceivable | $140 | $(185) | $23 |
| Change\tin\tother\tcurrent\tassets | (128) | 125 | 21 |
| Change\tin\taccounts\tpayable | (8) | 64 | 37 |
| Change\tin\trevenues\tand\troyalties\tpayable | 19 | 144 | 48 |
| Change\tin\tother\tcurrent\tliabilities | (73) | 37 | (402) |
| Net\tdecrease\t(increase)\tin\tworking\tcapital | $(50) | $185 | $(273) |
| Supplementary\tcash\tflow\tdata\t–\ttotal\toperations: |  |  |  |
| Interest\tpaid\t(net\tof\tcapitalized\tinterest) | $334 | $325 | $359 |
| Income\ttaxes\tpaid\t(received) | $100 | $(383) | $955 |

# 10. Short-Term	Investments

The	components	of	short-term	investments	include	the	following:

|  | 2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Canadian\ttreasury,\tagency\tand\tprovincial\tsecurities | $1,865 | $1,155 |
| U.S.\ttreasuries | 429 | 201 |
| Other | 49 | 147 |
| Short-term\tinvestments | $2,343 | $1,503 |

# 11. Accounts	Receivable

The	components	of	accounts	receivable	include	the	following:

|  | 2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tsales | $752 | $928 |
| Joint\tinterest\tbillings | 270 | 247 |
| Marketing\tand\tmidstream\trevenues | 161 | 174 |
| Other | 72 | 39 |
| Gross\taccounts\treceivable | \t 1,255 | \t 1,388 |
| Allowance\tfor\tdoubtful\taccounts | (10) | (9) |
| Net\taccounts\treceivable | $1,245 | $1,379 |

# 12. Other	Current	Assets

The	components	of	other	current	assets	include	the	following:

|  | December	31,<br>2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Derivative\tfinancial\tinstruments | $403 | $641 |
| Inventories | \t 110 | \t 102 |
| Income\ttax\treceivable | \t 119 | 35 |
| Current\tassets\theld\tfor\tsale | 3 | 21 |
| Other | \t 111 | 69 |
| Other\tcurrent\tassets | $746 | $868 |

See	Note	22	for	disclosure	of	Devon's	capitalized	costs	related	to	its	oil	and	gas	exploration	and	development	activities.

# Sinopec	Transaction

In	April	2012,	Devon	closed	its	joint	venture	transaction	with	Sinopec	International	Petroleum	Exploration	&	Production	Corporation.	Pursuant	to	the	agreement, Sinopec	paid	approximately	$900	million	in	cash	and	received	a	33.3	percent	interest	in	five	of	Devon's	new	ventures	exploration	plays	in	the	U.S.	at	closing	of	the transaction.	Additionally,	Sinopec	is	required	to	fund	approximately	$1.6	billion	of	Devon's	share	of	future	exploration,	development	and	drilling	costs	associated	with these	plays.	Devon	recognized	the	cash	proceeds	received	at	closing	as	a	reduction	to	U.S.	oil	and	gas	property	and	equipment.	No	gain	or	loss	was	recognized.

# Sumitomo	Transaction

In	September	2012,	Devon	closed	its	joint	venture	transaction	with	Sumitomo	Corporation.	At	closing,	Sumitomo	paid	approximately	$400	million	in	cash	and received	a	30	percent	interest	in	the	Cline	and	Midland-Wolfcamp	Shale	plays	in	Texas.	Additionally,	Sumitomo	is	required	to	fund	approximately	$1.0	billion	of Devon's	share	of	future	exploration,	development	and	drilling	costs	associated	with	these	plays.	Devon	recognized	the	cash	proceeds	received	at	closing	as	a	reduction	to U.S.	oil	and	gas	property	and	equipment.	No	gain	or	loss	was	recognized.

In	the	third	and	fourth	quarters	of	2012,	Devon	recognized	asset	impairments	related	to	its	oil	and	gas	property	and	equipment	and	its	U.S.	midstream	assets	as presented	below.

|  | Q3	2012 |  |  | Q4	2012 | Year	Ended	December	31,	2012 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross | Net\tof\tTaxes | Gross | Net\tof\tTaxes | Gross | Net\tof\tTaxes |
|  |  |  |  | (In\tmillions) |  |  |
| U.S.\toil\tand\tgas\tassets | $1,106 | $705 | $687 | $437 | $1,793 | $1,142 |
| Canada\toil\tand\tgas\tassets | — | — | \t 163 | 122 | 163 | 122 |
| Midstream\tassets | 22 | 14 | 46 | 30 | 68 | 44 |
| Total\tasset\timpairments | $1,128 | $719 | $896 | $589 | $2,024 | $1,308 |

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.

If	pricing	conditions	do	not	improve,	Devon	may	incur	full	cost	ceiling	impairments	related	to	its	oil	and	gas	property	and	equipment	in	2013.

Due	to	declining	natural	gas	production	resulting	from	low	natural	gas	and	NGL	prices,	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.

# Offshore	Divestitures

In	November	2009,	Devon	announced	plans	to	divest	its	offshore	assets.	In	2012,	Devon	completed	its	planned	divestiture	program.	In	aggregate,	Devon's	U.S. and	International	sales	generated	total	proceeds	of	$10	billion.	Assuming	repatriation	of	a	portion	of	the	foreign	proceeds	under	current	U.S.	tax	law,	the	after-tax proceeds	from	these	transactions	were	approximately	$8	billion.

# 14. Debt	and	Related	Expenses

A	summary	of	Devon's	debt	is	as	follows:

|  | December	31,<br>2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Commercial\tpaper | $3,189 | $3,726 |
| Other\tdebentures\tand\tnotes: |  |  |
| 5.625%\tdue\tJanuary\t15,\t2014 | 500 | 500 |
| Non-interest\tbearing\tpromissory\tnote\tdue\tJune\t29,\t2014 | — | 85 |
| 2.40%\tdue\tJuly\t15,\t2016 | 500 | 500 |
| 1.875%\tdue\tMay\t15,\t2017 | 750 | — |
| 8.25%\tdue\tJuly\t1,\t2018 | 125 | 125 |
| 6.30%\tdue\tJanuary\t15,\t2019 | 700 | 700 |
| 4.00%\tdue\tJuly\t15,\t2021 | 500 | 500 |
| 3.25%\tdue\tMay\t15,\t2022 | 1,000 | — |
| 7.50%\tdue\tSeptember\t15,\t2027 | 150 | 150 |
| 7.875%\tdue\tSeptember\t30,\t2031 | 1,250 | \t 1,250 |
| 7.95%\tdue\tApril\t15,\t2032 | 1,000 | \t 1,000 |
| 5.60%\tdue\tJuly\t15,\t2041 | 1,250 | \t 1,250 |
| 4.75%\tdue\tMay\t15,\t2042 | 750 | — |
| Net\tdiscount\ton\tother\tdebentures\tand\tnotes | (20) | (6) |
| Total\tdebt | \t 11,644 | \t 9,780 |
| Less\tamount\tclassified\tas\tshort-term\tdebt | 3,189 | \t 3,811 |
| Long-term\tdebt | $8,455 | $5,969 |

Debt	maturities	as	of	December	31,	2012,	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	Senior	Credit	Facility	has	an	initial	maturity	date	of October	24,	2017.	However,	prior	to	the	maturity	date,	Devon	has	the	option	to	extend	the	maturity	for	up	to	two	additional	one-year	periods,	subject	to	the	approval	of the	lenders.

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,	2012,	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	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,	2012,	Devon	was	in	compliance	with	this	covenant	with	a	debt-to-capitalization	ratio of	25.4	percent.

# Commercial	Paper

Devon	has	access	to	$5.0	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,	2012,	Devon's weighted	average	borrowing	rate	on	its	commercial	paper	borrowings	was	0.37	percent.

# Other	Debentures	and	Notes

Following	are	descriptions	of	the	various	other	debentures	and	notes	outstanding	at	December	31,	2012,	as	listed	in	the	table	presented	at	the	beginning	of	this note.

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 | $750 | $— | $— | $— |
| 3.25%\tdue\tMay\t15,\t2022 | 1,000 | — | — | — |
| 4.75%\tdue\tMay\t15,\t2042 | 750 | — | — | — |
| 2.40%\tdue\tJuly\t15,\t2016 | — | 500 | — | — |
| 4.00%\tdue\tJuly\t15,\t2021 | — | 500 | — | — |
| 5.60%\tdue\tJuly\t15,\t2041 | — | 1,250 | — | — |
| 5.625%\tdue\tJanuary\t15,\t2014 | — | — | 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,	2012,	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.

The	following	schedule	includes	the	components	of	interest	expense.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Interest\tbased\ton\tdebt\toutstanding | $440 | $414 | $408 |
| Capitalized\tinterest | (48) | (72) | (76) |
| Early\tretirement\tof\tdebt | \t — | \t — | 19 |
| Other | 14 | 10 | 12 |
| Interest\texpense | $406 | $352 | $363 |

The	schedule	below	summarizes	changes	in	Devon's	asset	retirement	obligations.

|  | Year	Ended	December	31,<br>				2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Asset\tretirement\tobligations\tas\tof\tbeginning\tof\tperiod | $1,563 | $1,497 |
| Liabilities\tincurred | 90 | 53 |
| Liabilities\tsettled | (86) | (82) |
| Revision\tof\testimated\tobligation | 420 | 25 |
| Liabilities\tassumed\tby\tothers | (23) | — |
| Accretion\texpense\ton\tdiscounted\tobligation | 110 | 92 |
| Foreign\tcurrency\ttranslation\tadjustment | 21 | (22) |
| Asset\tretirement\tobligations\tas\tof\tend\tof\tperiod | 2,095 | 1,563 |
| Less\tcurrent\tportion | 99 | 67 |
| Asset\tretirement\tobligations,\tlong-term | $1,996 | $1,496 |

During	2012,	Devon	recognized	revisions	to	its	asset	retirement	obligations	totaling	$420	million.	The	primary	factor	contributing	to	this	revision	was	an	overall increase	in	abandonment	cost	estimates	for	certain	of	its	production	operations	facilities.

# 16. 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	$31	million	and	$32	million	at	December	31,	2012	and	2011,	respectively,	and	is	included	in	other	long- term	assets	in	the	accompanying	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	at	December	31,	2012	and

2011.	Devon's	benefit	obligations	and	plan	assets	are	measured	each	year	as	of	December	31.	Devon's	2012	plan	settlements	relate	to	a	plan	amendment	which	removed a	dollar	cap	on	lump	sum	payments	and	revised	optional	forms	of	payment	to	include	a	lump	sum	distribution	feature.	Devon's	2011	pension	plan	contributions	of	$454 million	presented	in	the	table	were	primarily	discretionary.	After	these	contributions,	the	projected	benefit	obligation	for	Devon's	qualified	plans	was	fully	funded	as	of December	31,	2012	and	2011.

|  | Pension	Benefits |  | Postretirement	Benefits |  |
| :--- | :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2012 | 2011 |
|  |  |  | (In\tmillions) |  |
| Change\tin\tbenefit\tobligation: |  |  |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $1,303 | $1,124 | $37 | $43 |
| Service\tcost | 43 | 37 | 1 | 1 |
| Interest\tcost | 60 | 60 | 1 | 2 |
| Actuarial\tloss\t(gain) | 95 | 123 | (4) | (8) |
| Plan\tamendments | 14 | — | — | 5 |
| Plan\tcurtailments | (20) | — | 1 | — |
| Plan\tsettlements | (93) | — | — | (4) |
| Foreign\texchange\trate\tchanges | 1 | (1) | — | — |
| Participant\tcontributions | — | — | 3 | 3 |
| Benefits\tpaid | (43) | (40) | (5) | (5) |
| Benefit\tobligation\tat\tend\tof\tyear | \t 1,360 | \t 1,303 | 34 | 37 |
| Change\tin\tplan\tassets: |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | \t 1,187 | 632 | — | — |
| Actual\treturn\ton\tplan\tassets | 102 | 141 | — | — |
| Employer\tcontributions | 11 | 454 | 2 | 7 |
| Participant\tcontributions | — | — | 3 | 3 |
| Plan\tsettlements | (93) | — | — | (5) |
| Benefits\tpaid | (43) | (40) | (5) | (5) |
| Foreign\texchange\trate\tchanges | 1 | — | — | — |
| Fair\tvalue\tof\tplan\tassets\tat\tend\tof\tyear | \t 1,165 | \t 1,187 | — | — |
| Funded\tstatus\tat\tend\tof\tyear | $(195) | $(116) | $(34) | $(37) |
| Amounts\trecognized\tin\tbalance\tsheet: |  |  |  |  |
| Noncurrent\tassets | $62 | $116 | $— | $— |
| Current\tliabilities | (12) | (10) | (3) | (3) |
| Noncurrent\tliabilities | (245) | (222) | (31) | (34) |
| Net\tamount | $(195) | $(116) | $(34) | $(37) |
| Amounts\trecognized\tin\taccumulated\tother\tcomprehensive\tearnings: |  |  |  |  |
| Net\tactuarial\tloss\t(gain) | $340 | $348 | $(11) | $(9) |
| Prior\tservice\tcost\t(credit) | 25 | 18 | (4) | (5) |
| Total | $365 | $366 | $(15) | $(14) |

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	$8	million	for	2012	and	2011,	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,	2012	and	2011 as	presented	in	the	table	below.

|  | 2012 |  | 2011 |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Projected\tbenefit\tobligation | $257 |  | $232 |
| Accumulated\tbenefit\tobligation | $216 |  | $189 |
| 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<br>Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 |
|  |  |  | (In\tmillions) | (In\tmillions) |  |  |
| Net\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Service\tcost | $43 | $37 | $33 | $1 | $1 | $1 |
| Interest\tcost | 60 | 60 | 58 | 1 | 2 | 3 |
| Expected\treturn\ton\tplan\tassets | (64) | (42) | (36) | \t — | \t — | \t — |
| Curtailment\tand\tsettlement\texpense | 26 | \t — | \t — | 1 | (3) | \t — |
| Recognition\tof\tnet\tactuarial\tloss\t(gain) | 24 | 32 | 27 | (1) | \t — | \t — |
| Recognition\tof\tprior\tservice\tcost | 3 | 3 | 3 | (1) | (2) | 1 |
| Total\tnet\tperiodic\tbenefit\tcost | 92 | 90 | 85 | 1 | (2) | 5 |
| Other\tcomprehensive\tloss\t(earnings): |  |  |  |  |  |  |
| Actuarial\tloss\t(gain)\tarising\tin\tcurrent\tyear | 37 | 23 | 50 | (4) | (7) | 1 |
| Prior\tservice\tcost\t(credit)\tarising\tin\tcurrent\tyear | 14 | \t — | 4 | \t — | 5 | (22) |
| Recognition\tof\tnet\tactuarial\tloss,\tincluding\tsettlement\texpense,\tin\tnet\tperiodic\tbenefit\tcost | (45) | (32) | (27) | 1 | 3 | \t — |
| Recognition\tof\tprior\tservice\tcost,\tincluding\tcurtailment,\tin\tnet\tperiodic\tbenefit\tcost | (8) | (3) | (3) | 1 | 2 | (1) |
| Total\tother\tcomprehensive\tloss\t(earnings) | (2) | (12) | 24 | (2) | 3 | (22) |
| Total\trecognized | $90 | $78 | $109 | $(1) | $1 | $ (17) |

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	2013.

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

# Assumptions

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

|  | 2012 | Pension	Benefits<br>2011 | 2010 | 2012 | Postretirement	Benefits<br>2011 | 2010 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Assumptions\tto\tdetermine\tbenefit\tobligations: |  |  |  |  |  |  |
| Discount\trate | \t3.85% | \t4.65% | \t5.50% | \t3.30% | \t4.25% | \t4.90% |
| Rate\tof\tcompensation\tincrease | \t4.48% | \t4.97% | \t6.94% | \tN/A | \tN/A | \tN/A |
| Assumptions\tto\tdetermine\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |
| Discount\trate | \t4.65% | \t5.50% | \t6.00% | \t4.25% | \t4.90% | \t5.70% |
| Expected\treturn\ton\tplan\tassets | \t5.48% | \t6.48% | \t6.94% | \tN/A | \tN/A | \tN/A |
| Rate\tof\tcompensation\tincrease | \t4.97% | \t6.94% | \t6.95% | \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.

Rate	of	compensation	increase	–	For	measurement	of	the	2012	benefit	obligation	for	the	pension	plans,	a	4.48	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.

Other	assumptions	–	For	measurement	of	the	2012	benefit	obligation	for	the	other	postretirement	medical	plans,	an	8.2	percent	annual	rate	of	increase	in	the	per capita	cost	of	covered	health	care	benefits	was	assumed	for	2013.	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,	2012,	by	$2	million	and	would	change	the	2013	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.

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| 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.

|  |  |  | As	of	December	31,	2012 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Fair\tValue\tMeasurements\tUsing: | Fair\tValue\tMeasurements\tUsing: |  |
|  | Actual\nAllocation | Total | Level\t1\nInputs | Level\t2\nInputs | Level\t3\nInputs |
|  |  |  | ($\tin\tmillions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 39.4% | $459 | $65 | $394 | $— |
| Corporate\tbonds | 26.5% | 308 | 256 | 52 | — |
| Other\tbonds | 2.4% | 28 | 28 | — | — |
| Total\tfixed-income\tsecurities | 68.3% | 795 | 349 | 446 | — |
| Equity\tsecurities:\nGlobal\t(large,\tmid,\tsmall\tcap) | 20.5% | 239 | — | 239 | — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\t&amp;\talternative\tinvestments | 10.3% | 120 | 17 | — | 103 |
| Short-term\tinvestment\tfunds | 0.9% | 11 | — | 11 | — |
| Total\tother\tsecurities | 11.2% | 131 | 17 | 11 | 103 |
| Total\tinvestments | 100.0% | $1,165 | $366 | $696 | $103 |

|  | Actual<br>Allocation | Total | Level	1<br>Inputs | Level	2<br>Inputs | Level	3<br>Inputs |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($\tin\tmillions) |  |  |
| Fixed-income\tsecurities: |  |  |  |  |  |
| U.S.\tTreasury\tobligations | 43.9% | $522 | $27 | $495 | $— |
| Corporate\tbonds | 24.8% | 294 | 265 | 29 | — |
| Other\tbonds | 3.1% | 36 | 36 | — | — |
| Total\tfixed-income\tsecurities | 71.8% | 852 | 328 | 524 | — |
| Equity\tsecurities:\nGlobal\t(large,\tmid,\tsmall\tcap) | 18.0% | 214 | — | 214 | — |
| Other\tsecurities: |  |  |  |  |  |
| Hedge\tfund\t&amp;\talternative\tinvestments | 8.9% | 106 | 16 | — | 90 |
| Short-term\tinvestment\tfunds | 1.3% | 15 | — | 15 | — |
| Total\tother\tsecurities | 10.2% | 121 | 16 | 15 | 90 |
| Total\tinvestments | 100.0% | $1,187 | $344 | $753 | $90 |

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

Fixed-income	securities	–	Devon's	fixed-income	securities	consist	of	U.S.	Treasury	obligations,	bonds	issued	by	investment-grade	companies	from	diverse industries,	and	asset-backed	securities.	These	fixed-income	securities	are	actively	traded	securities	that	can	be	redeemed	upon	demand.	The	fair	values	of	these	Level	1 securities	are	based	upon	quoted	market	prices.

Devon's	fixed	income	securities	also	include	commingled	funds	that	primarily	invest	in	long-term	bonds	and	U.S.	Treasury	securities.	These	fixed	income securities	can	be	redeemed	on	demand	but	are	not	actively	traded.	The	fair	values	of	these	Level	2	securities	are	based	upon	the	net	asset	values	provided	by	the investment	managers.

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

Other	securities	–	Devon's	other	securities	include	commingled,	short-term	investment	funds.	These	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\t2013\tcontributions | $11 |  | $3 |
| Benefit\tpayments: |  |  |  |
| 2013 | $60 |  | $3 |
| 2014 | $61 |  | $3 |
| 2015 | $63 |  | $3 |
| 2016 | $65 |  | $3 |
| 2017 | $67 |  | $3 |
| 2018\tto\t2022 | $386 |  | $14 |

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	2013,	the	$11	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

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.	The	following	table	presents	Devon's	expense	related	to	these	defined	contribution	plans.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| 401(k)\tand\tenhanced\tcontribution\tplans | $36 | $33 | $32 |
| Canadian\tpension\tand\tsavings\tplans | 23 | 21 | 17 |
| Total | $59 | $54 | $49 |

# 17. Stockholders'	Equity

The	authorized	capital	stock	of	Devon	consists	of	1	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.

Devon's	Board	of	Directors	has	designated	2.9	million	shares	of	the	preferred	stock	as	Series	A	Junior	Participating	Preferred	Stock	(the	"Series	A	Junior Preferred	Stock").	At	December	31,	2012,	there	were	no	shares	of	Series	A	Junior	Preferred	Stock	issued	or	outstanding.	The	Series	A	Junior	Preferred	Stock	is	entitled to	receive	cumulative	quarterly	dividends	per	share	equal	to	the	greater	of	$1.00	or	100	times	the	aggregate	per	share	amount	of	all	dividends	(other	than	stock dividends)	declared	on	common	stock	since	the	immediately	preceding	quarterly	dividend	payment	date	or,	with	respect	to	the	first	payment	date,	since	the	first	issuance of	Series	A	Junior	Preferred	Stock.	Holders	of	the	Series	A	Junior	Preferred	Stock	are	entitled	to	100	votes	per	share	on	all	matters	submitted	to	a	vote	of	the stockholders.	Devon,	at	its	option,	may	redeem	shares	of	the	Series	A	Junior	Participating	Preferred	Stock	in	whole	at	any	time	and	in	part	from	time	to	time,	at	a redemption	price	equal	to	100	times	the	current	per	share	market	price	of	Devon's	common	stock	on	the	date	of	the	mailing	of	the	notice	of	redemption.	The	Series	A Junior	Preferred	Stock	ranks	prior	to	the	common	stock	but	junior	to	all	other	classes	of	Preferred	Stock.

# Stock	Repurchases

In	fourth	quarter	of	2011,	Devon	completed	its	2010	repurchase	program.	In	total,	Devon	repurchased	49.2	million	shares	for	$3.5	billion,	or	$71.18	per	share.

# Dividends

Devon	paid	common	stock	dividends	of	$324	million,	$278	million	and	$281	million	in	2012,	2011	and	2010	respectively.	The	quarterly	cash	dividend	was	$0.16 per	share	in	2010	and	the	first	quarter	of	2011.	Devon	increased	the	dividend	rate	to	$0.17	per	share	in	the	second	quarter	of	2011	and	further	increased	the	dividend	rate to	$0.20	per	share	in	the	first	quarter	of	2012.

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's	largest	exposure for	such	matters	relates	to	royalties	in	New	Mexico.	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.

# Chief	Redemption	Matters

In	2006,	Devon	acquired	Chief	Holdings	LLC	("Chief")	from	the	owners	of	Chief,	including	Trevor	Rees-Jones,	the	majority	owner	of	Chief.	In	2008,	a	former owner	of	Chief	filed	a	petition	against	Rees-Jones,	as	the	former	majority	owner	of	Chief,	and	Devon,	as	Chief's	successor	pursuant	to	the	2006	acquisition.	The	petition claimed,	among	other	things,	violations	of	the	Texas	Securities	Act,	fraud	and	breaches	of	Rees-Jones'	fiduciary	responsibility	to	the	former	owner	in	connection	with Chief's	2004	redemption	of	the	owner's	minority	ownership	stake	in	Chief.

On	June	20,	2011,	a	court	issued	a	judgment	against	Rees-Jones	for	$196	million,	of	which	$133	million	of	the	judgment	was	also	issued	against	Devon.	Devon does	not	have	a	legal	right	of	set	off	with	respect	to	the	judgment.	Therefore,	it	has	recorded	a	$133	million	long-term	liability	relating	to	the	judgment	with	an	offsetting $133	million	long-term	receivable	relating	to	its	right	to	be	indemnified	by	Rees-Jones	and	certain	other	parties	pursuant	to	the	indemnification	agreement.	Both	Rees- Jones	and	Devon	appealed	the	judgment.

In	December	2012,	the	plaintiffs	and	Rees-Jones	reached	an	agreement	in	principle	to	settle	all	claims	related	to	the	2004	redemption.	Under	the	terms	of	the agreement,	Rees-Jones	and	Devon	will	receive	full	releases	for	all	of	the	plaintiffs'	claims	related	to	the	Chief	redemption.	All	settlement	payments	will	be	funded entirely	by	Rees-Jones.	The	settlement	is	contingent	upon	the	execution	of	a	formal	settlement	agreement	and	release,	which	is	currently	being	negotiated	by	the	parties. Devon	does	not	expect	to	have	any	net	exposure	as	a	result	of	this	matter.

# 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,	2012.

| Year	Ending	December	31, | Purchase<br>Obligations | and<br>Facility<br>Obligations | Operational<br>Agreements | Office	and<br>Equipment<br>Leases |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |  |
| 2013 | $826 | $777 | $391 | $50 |
| 2014 | 862 | 173 | 406 | 34 |
| 2015 | 861 | — | 391 | 31 |
| 2016 | 861 | — | 340 | 29 |
| 2017 | 844 | — | 342 | 27 |
| Thereafter | 2,741 | — | 1,626 | 141 |
| Total | $6,995 | $950 | $3,496 | $312 |

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	production	and	transportation	processes.	Any	disruption	in Devon's	ability	to	obtain	condensate	could	negatively	affect	its	ability	to	produce	and	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.

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	$42	million,	$42	million	and	$57	million	in	2012,	2011	and	2010,	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	payables	and	accrued	expenses	included	in	the	accompanying	balance	sheets	approximated fair	value	at	December	31,	2012	and	December	31,	2011.	Therefore,	such	financial	assets	and	liabilities	are	not	presented	in	the	following	tables.	Additionally, information	regarding	the	fair	values	of	Devon's	midstream	and	pension	plan	assets	is	provided	in	Note	13	and	Note	16,	respectively.

|  |  |  | Fair	Value	Measurements	Using: | Fair	Value	Measurements	Using: | Fair	Value	Measurements	Using: |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Carrying\nAmount | Total\tFair\nValue | Level\t1\nInputs | Level\t2\nInputs | Level\t3\nInputs |
|  |  |  | (In\tmillions) |  |  |
| December\t31,\t2012\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $4,149 | $4,149 | $200 | $3,949 | $\t— |
| Short-term\tinvestments | $2,343 | $2,343 | $429 | $1,914 | $— |
| Long-term\tinvestments | $64 | $64 | $\t— | $— | $64 |
| Commodity\tderivatives | $401 | $401 | $ — | $401 | $— |
| Commodity\tderivatives | $(32) | $(32) | $ — | $(32) | $— |
| Interest\trate\tderivatives | $23 | $23 | $ — | $23 | $— |
| Foreign\tcurrency\tderivatives | $1 | $1 | $ — | $1 | $— |
| Debt | $(11,644) | $(13,435) | $ — | $ (13,435) | $— |

|  |  |  | Fair	Value	Measurements	Using | Fair	Value	Measurements	Using | Fair	Value	Measurements	Using |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Carrying\nAmount | Total\tFair\nValue | Level\t1\nInputs | Level\t2\nInputs | Level\t3\nInputs |
|  |  |  | (In\tmillions) |  |  |
| December\t31,\t2011\tassets\t(liabilities): |  |  |  |  |  |
| Cash\tequivalents | $5,123 | $5,123 | $929 | $4,194 | $\t— |
| Short-term\tinvestments | $1,503 | $1,503 | $201 | $1,302 | $ — |
| Long-term\tinvestments | $84 | $84 | $\t— | $— | $84 |
| Commodity\tderivatives | $628 | $628 | $ — | $628 | $ — |
| Commodity\tderivatives | $(82) | $(82) | $ — | $(82) | $ — |
| Interest\trate\tderivatives | $52 | $52 | $ — | $52 | $ — |
| Debt | $(9,780) | $(11,380) | $ — | $(11,295) | $(85) |

# Level	1	Fair	Value	Measurements

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

Cash	equivalents	and	short-term	investments	—	Amounts	consist	primarily	of	Canadian	agency	and	provincial	securities	and	commercial	paper	investments.	The fair	value	is	based	upon	quotes	from	independent	third	parties,	which	approximate	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	fixed-rate	debt	are	estimated	based	on	rates	available	for debt	with	similar	terms	and	maturity.	The	fair	value	of	Devon's	variable-rate	commercial	paper	and	credit	facility	borrowings	are	the	carrying	values.

Long-term	investments	—	Devon's	long-term	investments	presented	in	the	tables	above	consisted	entirely	of	auction	rate	securities.	Due	to	auction	failures	and the	lack	of	an	active	market	for	Devon's	auction	rate	securities,	quoted	market	prices	for	these	securities	were	not	available.	Therefore,	Devon	used	valuation	techniques that	rely	on	unobservable	inputs	to	estimate	the	fair	values	of	its	long-term	auction	rate	securities.	These	inputs	were	based	on	continued	receipts	of	principal	at	par,	the collection	of	all	accrued	interest	to	date,	the	probability	of	full	repayment	of	the	securities	considering	the	U.S.	government	guarantees	substantially	all	of	the	underlying student	loans,	and	the	AAA	credit	rating	of	the	securities.	As	a	result	of	using	these	inputs,	Devon	concluded	the	estimated	fair	values	of	its	long-term	auction	rate securities	approximated	the	par	values	as	of	December	31,	2012	and	December	31,	2011.

Debt	—	Devon's	Level	3	debt	consisted	of	a	non-interest	bearing	promissory	note.	Due	to	the	lack	of	an	active	market,	quoted	marked	prices	for	this	note,	or similar	notes,	were	not	available.	Therefore,	Devon	used	valuation	techniques	that	relied	on	unobservable	inputs	to	estimate	the	fair	value	of	its	promissory	note.	The fair	value	of	this	debt	was	estimated	using	internal	discounted	cash	flow	calculations	based	upon	estimated	future	payment	schedules	and	a	3.125	percent	interest	rate.	As a	result	of	using	these	inputs,	Devon	concluded	the	estimated	fair	value	of	its	non-interest	bearing	promissory	note	approximated	the	carrying	value	as	of	December	31, 2011.

Included	below	is	a	summary	of	the	changes	in	Devon's	Level	3	fair	value	measurements.

|  | Year	Ended	December	31,<br>2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Long-term\tinvestments\tbalance\tat\tbeginning\tof\tperiod | $84 | $94 |
| Redemptions\tof\tprincipal | (20) | (10) |
| Long-term\tinvestments\tbalance\tat\tend\tof\tperiod | $64 | $84 |

|  | Year	Ended	December	31,<br>2012 | 2011 |
| :--- | :--- | :--- |
|  | (In\tmillions) |  |
| Debt\tbalance\tat\tbeginning\tof\tperiod | $(85) | $(144) |
| Foreign\texchange\ttranslation\tadjustment | (1) | 1 |
| Accretion\tof\tpromissory\tnote | 3 | (5) |
| Redemptions\tof\tprincipal | 83 | 63 |
| Debt\tbalance\tat\tend\tof\tperiod | $\t— | $(85) |

# 20. Discontinued	Operations

In	March	2012,	Devon	received	$71	million	and	recognized	a	loss	of	$16	million	upon	closing	the	divestiture	of	its	operations	in	Angola,	which	completed Devon's	offshore	divestiture	program	that	was

announced	in	November	2009.	In	aggregate,	Devon's	U.S.	and	International	offshore	divestitures	generated	total	proceeds	of	approximately	$10	billion,	or	$8	billion after-tax,	assuming	repatriation	of	a	substantial	portion	of	the	foreign	proceeds	under	current	U.S.	tax	law.

Revenues	related	to	Devon's	discontinued	operations	totaled	$43	million	and	$693	million	during	2011	and	2010,	respectively.	Devon	did	not	have	revenues related	to	its	discontinued	operations	during	2012.	The	following	table	presents	the	earnings	(loss)	from	Devon's	discontinued	operations.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Operating\tearnings | $— | $38 | $567 |
| Gain\t(loss)\ton\tsale\tof\toil\tand\tgas\tproperties | (16) | \t 2,552 | \t 1,818 |
| Earnings\t(loss)\tbefore\tincome\ttaxes | (16) | \t 2,590 | \t 2,385 |
| Income\ttax\texpense | 5 | 20 | 168 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | $ (21) | $2,570 | $2,217 |

The	following	table	presents	the	main	classes	of	assets	and	liabilities	associated	with	Devon's	discontinued	operations	at	December	31,	2011.

# 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	segments	are	all	primarily engaged	in	oil	and	gas	producing	activities,	and	certain	information	regarding	such	activities	for	each	segment	is	included	in	Note	22.	Revenues	are	all	from	external customers.

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
|  |  | (In\tmillions) |  |
| Year\tEnded\tDecember\t31,\t2012: |  |  |  |
| Oil,\tgas\tand\tNGL\tsales | $4,679 | $2,474 | $7,153 |
| Oil,\tgas\tand\tNGL\tderivatives | $681 | $12 | $693 |
| Marketing\tand\tmidstream\trevenues | $1,542 | $114 | $1,656 |
| Depreciation,\tdepletion\tand\tamortization | $1,824 | $987 | $2,811 |
| Interest\texpense | $343 | $63 | $406 |
| Asset\timpairments | $1,861 | $163 | $2,024 |
| Loss\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $(263) | $(54) | $(317) |
| Income\ttax\tbenefit | $(97) | $(35) | $(132) |
| Loss\tfrom\tcontinuing\toperations | $(166) | $(19) | $(185) |
| Property\tand\tequipment,\tnet | $18,361 | $8,955 | $27,316 |
| Total\tassets | $24,256 | $19,070 | $43,326 |
| Capital\texpenditures | $6,511 | $1,963 | $8,474 |
| Year\tEnded\tDecember\t31,\t2011: |  |  |  |
| Oil,\tgas\tand\tNGL\tsales | $5,418 | $2,897 | $8,315 |
| Oil,\tgas\tand\tNGL\tderivative | $881 | $— | $881 |
| Marketing\tand\tmidstream\trevenues | $2,059 | $199 | $2,258 |
| Depreciation,\tdepletion\tand\tamortization | $1,439 | $809 | $2,248 |
| Interest\texpense | $204 | $148 | $352 |
| Earnings\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $3,477 | $813 | $4,290 |
| Income\ttax\texpense | $1,958 | $198 | $2,156 |
| Earnings\tfrom\tcontinuing\toperations | $1,519 | $615 | $2,134 |
| Property\tand\tequipment,\tnet | $16,989 | $7,785 | $24,774 |
| Total\tassets\t(1) | $22,622 | $18,342 | $40,964 |
| Capital\texpenditures | $6,101 | $1,694 | $7,795 |
| Year\tEnded\tDecember\t31,\t2010: |  |  |  |
| Oil,\tgas\tand\tNGL\tsales | $4,742 | $2,520 | $7,262 |
| Oil,\tgas\tand\tNGL\tderivatives | $809 | $2 | $811 |
| Marketing\tand\tmidstream\trevenues | $1,742 | $125 | $1,867 |
| Depreciation,\tdepletion\tand\tamortization | $1,229 | $701 | $1,930 |
| Interest\texpense | $159 | $204 | $363 |
| Earnings\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $2,943 | $625 | $3,568 |
| Income\ttax\texpense | $1,062 | $173 | $1,235 |
| Earnings\tfrom\tcontinuing\toperations | $1,881 | $452 | $2,333 |
| Property\tand\tequipment,\tnet | $12,379 | $7,273 | $19,652 |
| Total\tassets\t(1) | $18,320 | $13,185 | $31,505 |
| Capital\texpenditures | $4,935 | $1,985 | $6,920 |

(1) Amounts	in	the	table	above	do	not	include	assets	held	for	sale	related	to	Devon's	discontinued	operations,	which	totaled	$153	million	and	$1.4	billion	in	2011	and 2010,	respectively.

# 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	and continent.	Additionally,	the	costs	incurred	and	reserves

information	for	the	U.S.	is	segregated	between	Devon's	onshore	and	offshore	operations.	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.

|  | U.S.<br>Onshore | U.S.<br>Offshore | Total<br>U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Property\tacquisition\tcosts: |  |  |  |  |  |
| Proved\tproperties | $2 | $— | $2 | $71 | $73 |
| Unproved\tproperties | 1,135 | — | \t 1,135 | 43 | \t 1,178 |
| Exploration\tcosts | 351 | — | 351 | 304 | 655 |
| Development\tcosts | 4,408 | — | \t 4,408 | \t 1,691 | \t 6,099 |
| Costs\tincurred | $5,896 | $\t— | $5,896 | $2,109 | $8,005 |
|  |  | Year\tEnded\tDecember\t31,\t2011 | Year\tEnded\tDecember\t31,\t2011 |  |  |
|  | U.S. | U.S. | Total |  |  |

|  | Onshore | Offshore | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Property\tacquisition\tcosts: |  |  |  |  |  |
| Proved\tproperties | $34 | $\t— | $34 | $14 | $48 |
| Unproved\tproperties | 851 | — | 851 | 88 | 939 |
| Exploration\tcosts | 272 | — | 272 | 266 | 538 |
| Development\tcosts | 4,130 | — | \t 4,130 | \t 1,288 | \t 5,418 |
| Costs\tincurred | $5,287 | $— | $5,287 | $1,656 | $6,943 |
|  |  | Year\tEnded\tDecember\t31,\t2010 | Year\tEnded\tDecember\t31,\t2010 |  |  |
|  | U.S. | U.S. | Total |  |  |

|  | Onshore | Offshore | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (In\tmillions) |  |  |
| Property\tacquisition\tcosts: |  |  |  |  |  |
| Proved\tproperties | $29 | $\t— | $29 | $4 | $33 |
| Unproved\tproperties | 592 | 2 | 594 | 590 | \t 1,184 |
| Exploration\tcosts | 339 | 89 | 428 | 260 | 688 |
| Development\tcosts | 3,126 | 297 | \t 3,423 | \t 1,216 | \t 4,639 |
| Costs\tincurred | $4,086 | $388 | $4,474 | $2,070 | $6,544 |

Costs	incurred	in	the	tables	above	include	additions	and	revisions	to	Devon's	asset	retirement	obligations.	The	proceeds	received	from	our	joint	venture transactions	have	not	been	netted	against	the	costs	incurred.	At	December	31,	2012	the	remaining	commitment	to	fund	our	future	costs	associated	with	these	joint venture	transactions	was	approximately	$2.3	billion.

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

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	$36	million,	$45	million	and	$37	million	in	the	years	2012,	2011	and 2010,	respectively.

# Capitalized	Costs

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

|  |  | December	31,	2012 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Proved\tproperties | $46,570 | $22,840 | $69,410 |
| Unproved\tproperties | 1,703 | 1,605 | 3,308 |
| Total\toil\t&amp;\tgas\tproperties | 48,273 | 24,445 | 72,718 |
| Accumulated\tDD&amp;A | (33,098) | (16,039) | (49,137) |
| Net\tcapitalized\tcosts | $15,175 | $8,406 | $23,581 |

|  |  | December	31,	2011 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Proved\tproperties | $41,397 | $20,299 | $61,696 |
| Unproved\tproperties | 2,347 | 1,635 | 3,982 |
| Total\toil\t&amp;\tgas\tproperties | 43,744 | 21,934 | 65,678 |
| Accumulated\tDD&amp;A | (29,742) | (14,585) | (44,327) |
| Net\tcapitalized\tcosts | $14,002 | $7,349 | $21,351 |

The	following	is	a	summary	of	Devon's	oil	and	gas	properties	not	subject	to	amortization	as	of	December	31,	2012.

|  |  |  |  | Prior	to |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 | 2010 | Total |
|  |  |  | (In\tmillions) |  |  |
| Acquisition\tcosts | $928 | $115 | $788 | $660 | $2,491 |
| Exploration\tcosts | 228 | \t 142 | 48 | 1 | 419 |
| Development\tcosts | 227 | 70 | \t — | 10 | 307 |
| Capitalized\tinterest | 35 | 36 | 20 | — | 91 |
| Total\toil\tand\tgas\tproperties\tnot\tsubject\tto\tamortization | $1,418 | $363 | $856 | $671 | $3,308 |

The	following	tables	include	revenues	and	expenses	directly	associated	with	Devon's	oil	and	gas	producing	activities,	including	general	and	administrative expenses	directly	related	to	such	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.

|  |  | Year	Ended	December	31,	2012 |  |
| :--- | :--- | :--- | :--- |
|  | 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) |
| Depreciation,\tdepletion\tand\tamortization | (1,563) | (963) | (2,526) |
| General\tand\tadministrative\texpenses | (159) | (137) | (296) |
| Taxes\tother\tthan\tincome\ttaxes | (340) | (55) | (395) |
| Asset\timpairments | (1,793) | (163) | (1,956) |
| Accretion\tof\tasset\tretirement\tobligations | (40) | (69) | (109) |
| Income\ttax\t(expense)\tbenefit | 99 | (3) | 96 |
| Results\tof\toperations | $(176) | $69 | $(107) |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $8.55 | $14.41 | $10.12 |

|  |  | Year	Ended	December	31,	2011 |  |
| :--- | :--- | :--- | :--- |
|  | U.S | Canada | Total |
|  |  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tsales | $5,418 | $2,897 | $8,315 |
| Lease\toperating\texpenses | (925) | (926) | (1,851) |
| Depreciation,\tdepletion\tand\tamortization | (1,201) | (786) | (1,987) |
| General\tand\tadministrative\texpenses | (132) | (119) | (251) |
| Taxes\tother\tthan\tincome\ttaxes | (357) | (45) | (402) |
| Accretion\tof\tasset\tretirement\tobligations | (34) | (57) | (91) |
| Income\ttax\texpense | (1,005) | (250) | (1,255) |
| Results\tof\toperations | $1,764 | $714 | $2,478 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $6.94 | $11.74 | $8.28 |

|  |  | Year	Ended	December	31,	2010 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Oil,\tgas\tand\tNGL\tsales | $4,742 | $2,520 | $7,262 |
| Lease\toperating\texpenses | (892) | (797) | (1,689) |
| Depreciation,\tdepletion\tand\tamortization | (998) | (677) | (1,675) |
| General\tand\tadministrative\texpenses | (133) | (83) | (216) |
| Taxes\tother\tthan\tincome\ttaxes | (319) | (40) | (359) |
| Accretion\tof\tasset\tretirement\tobligations | (42) | (50) | (92) |
| Income\ttax\texpense | (849) | (246) | (1,095) |
| Results\tof\toperations | $1,509 | $627 | $2,136 |
| Depreciation,\tdepletion\tand\tamortization\tper\tBoe | $6.11 | $10.51 | $7.36 |

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

|  | U.S.<br>Onshore | U.S.<br>Offshore | Oil	(MMBbls)<br>Total<br>U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| December\t31,\t2009 | \t\t\t\t\t139 | \t\t\t\t33 | \t\t\t\t\t172 | \t\t\t\t\t111 | \t\t\t\t\t283 |
| Revisions\tdue\tto\tprices | 4 | 1 | 5 | (3) | 2 |
| Revisions\tother\tthan\tprice | 2 | 2 | 4 | (3) | 1 |
| Extensions\tand\tdiscoveries | 19 | 1 | 20 | 4 | 24 |
| Production | (14) | (2) | (16) | (16) | (32) |
| Sale\tof\treserves | (2) | (35) | (37) | — | (37) |
| December\t31,\t2010 | 148 | — | 148 | 93 | 241 |
| Revisions\tdue\tto\tprices | 2 | — | 2 | 1 | 3 |
| Revisions\tother\tthan\tprice | (1) | — | (1) | (5) | (6) |
| Extensions\tand\tdiscoveries | 36 | — | 36 | 6 | 42 |
| Production | (17) | — | (17) | (15) | (32) |
| December\t31,\t2011 | 168 | — | 168 | 80 | 248 |
| Revisions\tdue\tto\tprices | (1) | — | (1) | (5) | (6) |
| Revisions\tother\tthan\tprice | (6) | — | (6) | (2) | (8) |
| Extensions\tand\tdiscoveries | 65 | — | 65 | 7 | 72 |
| Production | (21) | — | (21) | (15) | (36) |
| December\t31,\t2012 | 205 | — | 205 | 65 | 270 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 119 | 21 | 140 | 97 | 237 |
| December\t31,\t2010 | 131 | — | 131 | 82 | 213 |
| December\t31,\t2011 | 146 | — | 146 | 73 | 219 |
| December\t31,\t2012 | 166 | — | 166 | 62 | 228 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 112 | 12 | 124 | 85 | 209 |
| December\t31,\t2010 | 123 | — | 123 | 72 | 195 |
| December\t31,\t2011 | 139 | — | 139 | 65 | 204 |
| December\t31,\t2012 | 155 | — | 155 | 56 | 211 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 20 | 12 | 32 | 14 | 46 |
| December\t31,\t2010 | 17 | — | 17 | 11 | 28 |
| December\t31,\t2011 | 22 | — | 22 | 7 | 29 |
| December\t31,\t2012 | 39 | — | 39 | 3 | 42 |

|  | U.S.<br>Onshore | U.S.<br>Offshore | Bitumen	(MMBbls)<br>Total<br>U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| December\t31,\t2009 | \t\t\t\t\t— | \t\t\t\t\t— | \t\t\t\t\t— | \t\t\t\t\t403 | \t\t\t\t\t403 |
| Revisions\tdue\tto\tprices | — | — | — | (21) | (21) |
| Revisions\tother\tthan\tprice | — | — | — | 12 | 12 |
| Extensions\tand\tdiscoveries | — | — | — | 55 | 55 |
| Production | — | — | — | (9) | (9) |
| December\t31,\t2010 | — | — | — | 440 | 440 |
| Revisions\tdue\tto\tprices | — | — | — | (16) | (16) |
| Revisions\tother\tthan\tprice | — | — | — | 16 | 16 |
| Extensions\tand\tdiscoveries | — | — | — | 30 | 30 |
| Production | — | — | — | (13) | (13) |
| December\t31,\t2011 | — | — | — | 457 | 457 |
| 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 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | — | — | — | 52 | 52 |
| December\t31,\t2010 | — | — | — | 44 | 44 |
| December\t31,\t2011 | — | — | — | 90 | 90 |
| December\t31,\t2012 | — | — | — | 99 | 99 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | — | — | — | 52 | 52 |
| December\t31,\t2010 | — | — | — | 44 | 44 |
| December\t31,\t2011 | — | — | — | 90 | 90 |
| December\t31,\t2012 | — | — | — | 99 | 99 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | — | — | — | 351 | 351 |
| December\t31,\t2010 | — | — | — | 396 | 396 |
| December\t31,\t2011 | — | — | — | 367 | 367 |
| December\t31,\t2012 | — | — | — | 429 | 429 |

|  | U.S.<br>Onshore | U.S.<br>Offshore | Total<br>U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| December\t31,\t2009 | \t\t\t\t\t8,127 | \t\t\t\t\t342 | \t\t\t\t\t8,469 | \t\t\t\t\t1,288 | \t\t\t\t\t9,757 |
| Revisions\tdue\tto\tprices | 449 | 2 | 451 | 21 | 472 |
| Revisions\tother\tthan\tprice | 105 | (26) | 79 | (17) | 62 |
| Extensions\tand\tdiscoveries | 1,088 | 7 | 1,095 | 131 | 1,226 |
| Purchase\tof\treserves | 12 | — | 12 | 9 | 21 |
| Production | (699) | (17) | (716) | (214) | (930) |
| Sale\tof\treserves | (17) | (308) | (325) | — | (325) |
| December\t31,\t2010 | 9,065 | — | 9,065 | 1,218 | 10,283 |
| Revisions\tdue\tto\tprices | (1) | — | (1) | (60) | (61) |
| Revisions\tother\tthan\tprice | (243) | — | (243) | (38) | (281) |
| Extensions\tand\tdiscoveries | 1,410 | — | 1,410 | 58 | 1,468 |
| Purchase\tof\treserves | 16 | — | 16 | 20 | 36 |
| Production | (740) | — | (740) | (213) | (953) |
| Sale\tof\treserves | — | — | — | (6) | (6) |
| December\t31,\t2011 | 9,507 | — | 9,507 | 979 | 10,486 |
| Revisions\tdue\tto\tprices | (831) | — | (831) | (99) | (930) |
| Revisions\tother\tthan\tprice | (287) | — | (287) | (33) | (320) |
| Extensions\tand\tdiscoveries | 1,124 | — | 1,124 | 34 | 1,158 |
| Purchase\tof\treserves | 2 | — | 2 | — | 2 |
| Production | (752) | — | (752) | (186) | (938) |
| Sale\tof\treserves | (1) | — | (1) | (11) | (12) |
| December\t31,\t2012 | 8,762 | — | 8,762 | 684 | 9,446 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 6,447 | 185 | 6,632 | 1,213 | 7,845 |
| December\t31,\t2010 | 7,280 | — | 7,280 | 1,144 | 8,424 |
| December\t31,\t2011 | 7,957 | — | 7,957 | 951 | 8,908 |
| December\t31,\t2012 | 7,391 | — | 7,391 | 679 | 8,070 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 5,860 | 137 | 5,997 | 1,075 | 7,072 |
| December\t31,\t2010 | 6,702 | — | 6,702 | 1,031 | 7,733 |
| December\t31,\t2011 | 7,409 | — | 7,409 | 862 | 8,271 |
| December\t31,\t2012 | 7,091 | — | 7,091 | 624 | 7,715 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 1,680 | 157 | 1,837 | 75 | 1,912 |
| December\t31,\t2010 | 1,785 | — | 1,785 | 74 | 1,859 |
| December\t31,\t2011 | 1,550 | — | 1,550 | 28 | 1,578 |
| December\t31,\t2012 | 1,371 | — | 1,371 | 5 | 1,376 |

|  |  | Natural	Gas	Liquids	(MMBbls) | Natural	Gas	Liquids	(MMBbls) | Natural	Gas	Liquids	(MMBbls) |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S.\nOnshore | U.S.\nOffshore | Total\nU.S. | Canada | Total |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| December\t31,\t2009 | \t\t\t\t\t385 | 2 | \t\t\t\t\t387 | \t\t\t\t34 | \t\t\t\t\t421 |
| Revisions\tdue\tto\tprices | 14 | \t\t\t\t\t— | 14 | (1) | 13 |
| Revisions\tother\tthan\tprice | 13 | 3 | 16 | (1) | 15 |
| Extensions\tand\tdiscoveries | 68 | — | 68 | 2 | 70 |
| Production | (28) | — | (28) | (4) | (32) |
| Sale\tof\treserves | (3) | (5) | (8) | — | (8) |
| December\t31,\t2010 | 449 | — | 449 | 30 | 479 |
| Revisions\tdue\tto\tprices | 4 | — | 4 | (1) | 3 |
| Revisions\tother\tthan\tprice | 1 | — | 1 | — | 1 |
| Extensions\tand\tdiscoveries | 102 | — | 102 | 2 | 104 |
| Purchase\tof\treserves | 2 | — | 2 | — | 2 |
| Production | (33) | — | (33) | (4) | (37) |
| December\t31,\t2011 | 525 | — | 525 | 27 | 552 |
| Revisions\tdue\tto\tprices | (19) | — | (19) | (5) | (24) |
| Revisions\tother\tthan\tprice | (13) | — | (13) | — | (13) |
| Extensions\tand\tdiscoveries | 114 | — | 114 | 2 | 116 |
| Production | (36) | — | (36) | (4) | (40) |
| December\t31,\t2012 | 571 | — | 571 | 20 | 591 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 293 | 1 | 294 | 32 | 326 |
| December\t31,\t2010 | 353 | — | 353 | 28 | 381 |
| December\t31,\t2011 | 402 | — | 402 | 26 | 428 |
| December\t31,\t2012 | 431 | — | 431 | 20 | 451 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 265 | 1 | 266 | 28 | 294 |
| December\t31,\t2010 | 318 | — | 318 | 26 | 344 |
| December\t31,\t2011 | 372 | — | 372 | 24 | 396 |
| December\t31,\t2012 | 406 | — | 406 | 19 | 425 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 92 | 1 | 93 | 2 | 95 |
| December\t31,\t2010 | 96 | — | 96 | 2 | 98 |
| December\t31,\t2011 | 123 | — | 123 | 1 | 124 |
| December\t31,\t2012 | 140 | — | 140 | — | 140 |

|  | U.S.<br>Onshore | U.S.<br>Offshore | Total	(MMBoe)	(1)<br>Total<br>U.S. | Canada | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| December\t31,\t2009 | \t\t\t\t\t1,878 | \t\t\t\t\t\t\t\t\t92 | \t\t\t\t\t1,970 | \t\t\t\t\t763 | \t\t\t\t\t2,733 |
| Revisions\tdue\tto\tprices | 92 | 1 | 93 | (21) | 72 |
| Revisions\tother\tthan\tprice | 32 | 1 | 33 | 5 | 38 |
| Extensions\tand\tdiscoveries | 269 | 2 | 271 | 83 | 354 |
| Purchase\tof\treserves | 2 | — | 2 | 2 | 4 |
| Production | (158) | (5) | (163) | (65) | (228) |
| Sale\tof\treserves | (8) | (91) | (99) | (1) | (100) |
| December\t31,\t2010 | 2,107 | — | 2,107 | 766 | 2,873 |
| Revisions\tdue\tto\tprices | 6 | — | 6 | (27) | (21) |
| Revisions\tother\tthan\tprice | (41) | — | (41) | 6 | (35) |
| Extensions\tand\tdiscoveries | 374 | — | 374 | 47 | 421 |
| Purchase\tof\treserves | 5 | — | 5 | 3 | 8 |
| Production | (173) | — | (173) | (67) | (240) |
| Sale\tof\treserves | — | — | — | (1) | (1) |
| December\t31,\t2011 | 2,278 | — | 2,278 | 727 | 3,005 |
| Revisions\tdue\tto\tprice | (159) | — | (159) | (12) | (171) |
| Revisions\tother\tthan\tprice | (67) | — | (67) | (1) | (68) |
| Extensions\tand\tdiscoveries | 367 | — | 367 | 82 | 449 |
| Production | (183) | — | (183) | (67) | (250) |
| Sale\tof\treserves | — | — | — | (2) | (2) |
| December\t31,\t2012 | 2,236 | — | 2,236 | 727 | 2,963 |
| Proved\tdeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 1,486 | 53 | 1,539 | 383 | 1,922 |
| December\t31,\t2010 | 1,696 | — | 1,696 | 346 | 2,042 |
| December\t31,\t2011 | 1,875 | — | 1,875 | 348 | 2,223 |
| December\t31,\t2012 | 1,829 | — | 1,829 | 294 | 2,123 |
| Proved\tdeveloped-producing\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 1,354 | 35 | 1,389 | 344 | 1,733 |
| December\t31,\t2010 | 1,557 | — | 1,557 | 314 | 1,871 |
| December\t31,\t2011 | 1,746 | — | 1,746 | 323 | 2,069 |
| December\t31,\t2012 | 1,743 | — | 1,743 | 278 | 2,021 |
| Proved\tundeveloped\treserves\tas\tof: |  |  |  |  |  |
| December\t31,\t2009 | 392 | 39 | 431 | 380 | 811 |
| December\t31,\t2010 | 411 | — | 411 | 420 | 831 |
| December\t31,\t2011 | 403 | — | 403 | 379 | 782 |
| December\t31,\t2012 | 407 | — | 407 | 433 | 840 |

(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	2012	(in	MMBoe).

|  | U.S. | Canada | Total |
| :--- | :--- | :--- | :--- |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2011 | \t403 | 379 | \t782 |
| Extensions\tand\tdiscoveries | \t134 | 68 | \t202 |
| Revisions\tdue\tto\tprices | \t (47) | 9 | \t (38) |
| Revisions\tother\tthan\tprice | \t (10) | (6) | \t (16) |
| Conversion\tto\tproved\tdeveloped\treserves | \t (73) | (17) | \t (90) |
| Proved\tundeveloped\treserves\tas\tof\tDecember\t31,\t2012 | \t407 | 433 | \t840 |

At	December	31,	2012,	Devon	had	840	MMBoe	of	proved	undeveloped	reserves.	This	represents	a	7	percent	increase	as	compared	to	2011	and	represents	28 percent	of	its	total	proved	reserves.	Drilling	and	development	activities	increased	Devon's	proved	undeveloped	reserves	203	MMBoe	and	resulted	in	the	conversion	of	90 MMBoe,	or	12	percent,	of	the	2011	proved	undeveloped	reserves	to	proved	developed	reserves.	Costs	incurred	related	to	the	development	and	conversion	of	Devon's proved	undeveloped	reserves	were	$1.3	billion	for	2012.	Additionally,	revisions	other	than	price	decreased	Devon's	proved	undeveloped	reserves	16	MMBoe	primarily due	to	its	evaluation	of	certain	U.S.	onshore	dry-gas	areas,	which	it	does	not	expect	to	develop	in	the	next	five	years.	The	largest	revisions	relate	to	the	dry-gas	areas	at Carthage	in	east	Texas	and	the	Barnett	Shale	in	north	Texas.

A	significant	amount	of	Devon's	proved	undeveloped	reserves	at	the	end	of	2012	largely	related	to	its	Jackfish	operations.	At	December	31,	2012	and	2011, Devon's	Jackfish	proved	undeveloped	reserves	were	429	MMBoe	and	367	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,	steam-oil	ratios	and	air	quality	discharge	permits.	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

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.

2011	-	Reserves	decreased	21	MMBoe	due	to	lower	gas	prices	and	higher	oil	prices.	The	higher	oil	prices	increased	Devon's	Canadian	royalty	burden,	which reduced	Devon's	oil	reserves.

2010	-	Reserves	increased	72	MMBoe	due	to	higher	gas	prices,	partially	offset	by	the	effect	of	higher	oil	prices.	The	higher	oil	prices	increased	Devon's	Canadian royalty	burden,	which	reduced	Devon's	oil	reserves.	Of	the	72	MMBoe	price	revisions,	43	MMBoe	related	to	the	Barnett	Shale	and	22	MMBoe	related	to	the	Rocky Mountain	area.

# Revisions	Other	Than	Price

Total	revisions	other	than	price	for	2012	and	2011	primarily	related	to	Devon's	evaluation	of	certain	dry	gas	regions	noted	in	the	proved	undeveloped	reserves discussion	above.	Total	revisions	other	than	price	for	2010	primarily	related	to	Devon's	drilling	and	development	in	the	Barnett	Shale.

# Extensions	and	Discoveries

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.

2011	–	Of	the	421	MMBoe	of	extensions	and	discoveries,	162	MMBoe	related	to	the	Cana-Woodford	Shale,	115	MMBoe	related	to	the	Barnett	Shale,	39	MMBoe related	to	the	Permian	Basin,	30	MMBoe	related	to	Jackfish,	19	MMBoe	related	to	the	Rocky	Mountain	area	and	17	MMBoe	related	to	the	Granite	Wash	area.

The	2011	extensions	and	discoveries	included	168	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	including	80	MMBoe	at	the	Cana- Woodford	Shale	and	77	MMBoe	at	the	Barnett	Shale.

2010	–	Of	the	354	MMBoe	of	extensions	and	discoveries,	101	MMBoe	related	to	the	Cana-Woodford	Shale,	87	MMBoe	related	to	the	Barnett	Shale,	55	MMBoe related	to	Jackfish,	19	MMBoe	related	to	the	Permian	Basin,	15	MMBoe	related	to	the	Rocky	Mountain	area	and	14	MMBoe	related	to	the	Carthage	area.

The	2010	extensions	and	discoveries	included	107	MMBoe	related	to	additions	from	Devon's	infill	drilling	activities,	including	43	MMBoe	at	the	Barnett	Shale and	47	MMBoe	at	the	Cana-Woodford	Shale.

# Sale	of	Reserves

The	2010	total	primarily	relates	to	the	divestiture	of	Devon's	Gulf	of	Mexico	properties.

# Standardized	Measure

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

|  |  | 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\tflows | 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 |

|  |  | Year	Ended	December	31,	2011 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Future\tcash\tinflows | $69,305 | $36,786 | $106,091 |
| Future\tcosts: |  |  |  |
| Development | (6,817) | (4,678) | (11,495) |
| Production | (26,217) | (15,063) | (41,280) |
| Future\tincome\ttax\texpense | (11,432) | (3,763) | (15,195) |
| Future\tnet\tcash\tflows | 24,839 | 13,282 | 38,121 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (13,492) | (6,785) | (20,277) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $11,347 | $6,497 | $17,844 |

|  |  | Year	Ended	December	31,	2010 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Future\tcash\tinflows | $58,093 | $35,948 | $94,041 |
| Future\tcosts: |  |  |  |
| Development | (6,220) | (4,526) | (10,746) |
| Production | (24,223) | (12,249) | (36,472) |
| Future\tincome\ttax\texpense | (8,643) | (4,209) | (12,852) |
| Future\tnet\tcash\tflows | 19,007 | 14,964 | 33,971 |
| 10%\tdiscount\tto\treflect\ttiming\tof\tcash\tflows | (10,164) | (7,455) | (17,619) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows | $8,843 | $7,509 | $16,352 |

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	2012,	the	future	realized	prices	averaged	$86.57	per	barrel	of	oil,	$50.24	per	barrel	of	bitumen,	$2.28	per	Mcf	of gas	and	$29.19	per	barrel	of	natural	gas	liquids.	Of	the	$12.8	billion	of	future	development	costs	as	of	the	end	of	2012,	$2.3	billion,	$1.9	billion	and	$0.8	billion	are estimated	to	be	spent	in	2013,	2014	and	2015,	respectively.

Future	development	costs	include	not	only	development	costs,	but	also	future	asset	retirement	costs.	Included	as	part	of	the	$12.8	billion	of	future	development costs	are	$2.6	billion	of	future	asset	retirement	costs.	Future	production	costs	include	general	and	administrative	expenses	directly	related	to	oil	and	gas	producing activities.	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, |  |
| :--- | :--- | :--- | :--- |
|  | 2012 | 2011 | 2010 |
|  |  | (In\tmillions) |  |
| Beginning\tbalance | $17,844 | $16,352 | $11,403 |
| Net\tchanges\tin\tprices\tand\tproduction\tcosts | (9,889) | 1,875 | 7,423 |
| Oil,\tgas\tand\tNGL\tsales,\tnet\tof\tproduction\tcosts | (4,388) | (5,811) | (4,998) |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (1,094) | (440) | (292) |
| Extensions\tand\tdiscoveries,\tnet\tof\tfuture\tdevelopment\tcosts | 4,669 | 3,714 | 3,048 |
| Purchase\tof\treserves | 18 | 57 | 23 |
| Sales\tof\treserves\tin\tplace | (25) | (2) | (815) |
| Revisions\tof\tquantity\testimates | 162 | (228) | 579 |
| Previously\testimated\tdevelopment\tcosts\tincurred\tduring\tthe\tperiod | 1,321 | 1,302 | 1,559 |
| Accretion\tof\tdiscount | 1,420 | 2,248 | 1,487 |
| Other,\tprimarily\tchanges\tin\ttiming\tand\tforeign\texchange\trates | 113 | (294) | (402) |
| Net\tchange\tin\tincome\ttaxes | 3,070 | (929) | (2,663) |
| Ending\tbalance | $13,221 | $17,844 | $16,352 |

The	following	table	presents	Devon's	estimated	pretax	cash	flow	information	related	to	its	proved	reserves.

|  | Year	Ended	December	31,	2012 | Year	Ended	December	31,	2012 |  |
| :--- | :--- | :--- | :--- |
|  | U.S. | Canada | Total |
|  |  | (In\tmillions) |  |
| Pre-tax\tfuture\tnet\trevenue\t(1) |  |  |  |
| Proved\tdeveloped\treserves | $19,982 | $2,717 | $22,699 |
| Proved\tundeveloped\treserves | 4,494 | 8,031 | \t 12,525 |
| Total\tproved\treserves | $24,476 | $10,748 | $35,224 |
| Pre-tax\t10%\tpresent\tvalue\t(1) |  |  |  |
| Proved\tdeveloped\treserves | $10,764 | $2,484 | $13,248 |
| Proved\tundeveloped\treserves | 1,143 | 2,823 | 3,966 |
| Total\tproved\treserves | $11,907 | $5,307 | $17,214 |

(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.

The	present	value	of	after-tax	future	net	revenues	discounted	at	10	percent	per	annum	("standardized	measure")	was	$13.2	billion	at	the	end	of	2012.	Included	as part	of	standardized	measure	were	discounted	future	income	taxes	of	$4.0	billion.	Excluding	these	taxes,	the	present	value	of	Devon's	pre-tax	future	net	revenue ("pre-tax	10	percent	present	value")	was	$17.2	billion.	Devon	believes	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.

# 23. Supplemental	Quarterly	Financial	Information	(Unaudited)

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

|  | First<br>Quarter | Second<br>Quarter | Third<br>Quarter | Fourth<br>Quarter | Full<br>Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) | (In\tmillions,\texcept\tper\tshare\tamounts) |  |
| Revenues | $2,497 | $2,559 | $1,865 | $2,581 | $9,502 |
| Earnings\t(loss)\tfrom\tcontinuing\toperations |  |  |  |  |  |
| before\tincome\ttaxes | $611 | $734 | $(1,161) | $(501) | $(317) |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | $414 | $477 | $(719) | $(357) | $(185) |
| Loss\tfrom\tdiscontinued\toperations | (21) | — | — | — | (21) |
| Net\tearnings\t(loss) | $393 | $477 | $(719) | $(357) | $(206) |
| Basic\tnet\tearnings\t(loss)\tper\tcommon\tshare: |  |  |  |  |  |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | $1.03 | $1.18 | $(1.80) | $(0.89) | $(0.47) |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | (0.06) | — | — | — | (0.05) |
| Net\tearnings\t(loss) | $0.97 | $1.18 | $(1.80) | $(0.89) | $(0.52) |
| Diluted\tnet\tearnings\t(loss)\tper\tcommon\tshare: |  |  |  |  |  |
| Earnings\t(loss)\tfrom\tcontinuing\toperations | $1.03 | $1.18 | $(1.80) | $(0.89) | $(0.47) |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | (0.06) | — | — | — | (0.05) |
| Net\tearnings\t(loss) | $0.97 | $1.18 | $(1.80) | $(0.89) | $(0.52) |

|  |  |  | 2011 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 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) |  |
| Revenues | $2,147 | $3,220 | $3,502 | $2,585 | $11,454 |
| Earnings\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $580 | $1,378 | $1,538 | $794 | $4,290 |
| Earnings\tfrom\tcontinuing\toperations | $389 | $184 | $1,040 | $521 | $2,134 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | 27 | \t 2,559 | (2) | (14) | 2,570 |
| Net\tearnings | $416 | $2,743 | $1,038 | $507 | $4,704 |
| Basic\tnet\tearnings\tper\tcommon\tshare: |  |  |  |  |  |
| Earnings\tfrom\tcontinuing\toperations | $0.91 | $0.44 | $2.51 | $1.29 | $5.12 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | 0.06 | 6.06 | — | (0.04) | 6.17 |
| Net\tearnings | $0.97 | $6.50 | $2.51 | $1.25 | $11.29 |
| Diluted\tnet\tearnings\tper\tcommon\tshare: |  |  |  |  |  |
| Earnings\tfrom\tcontinuing\toperations | $0.91 | $0.43 | $2.50 | $1.29 | $5.10 |
| Earnings\t(loss)\tfrom\tdiscontinued\toperations | 0.06 | 6.05 | — | (0.04) | 6.15 |
| Net\tearnings | $0.97 | $6.48 | $2.50 | $1.25 | $11.25 |

# Earnings	(Loss)	from	Continuing	Operations

The	fourth	quarter	of	2012	includes	U.S.	and	Canadian	asset	impairments	totaling	$0.9	billion	($0.6	billion	after	income	taxes,	or	$1.46	per	diluted	share).

The	third	quarter	of	2012	includes	U.S.	asset	impairments	totaling	$1.1	billion	($0.7	billion	after	income	taxes,	or	$1.78	per	diluted	share).

The	second	quarter	of	2011	includes	deferred	income	taxes	of	$0.7	billion	(or	$1.71	per	diluted	share)	related	to	assumed	repatriations	of	foreign	earnings	that were	no	longer	deemed	to	be	indefinitely	reinvested	in	accordance	with	accounting	principles	generally	accepted	in	the	U.S.

The	second	quarter	of	2011	includes	the	divestiture	of	Devon's	Brazil	operations	and	the	related	gain	was	$2.5	billion	($2.5	billion	after	income	taxes,	or	$6.01 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,	2012	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	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(the	"COSO	Framework").	Based	on	this evaluation	under	the	COSO	Framework,	which	was	completed	on	February	19,	2013,	management	concluded	that	its	internal	control	over	financial	reporting	was effective	as	of	December	31,	2012.

The	effectiveness	of	our	internal	control	over	financial	reporting	as	of	December	31,	2012	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,	2012,	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	2012	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,	2013.

# 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,	2013.

# 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	Accounting	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

# 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.

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 of total debt maturity occurred in 2018 and thereafter?
Calculation:    total_debt_maturity = 6725
percent_2018_2012 = total_debt_maturity / 11664
percent_2018_2012_percent = percent_2018_2012 * 100
answer = percent_2018_2012_percent
Answer: 57.65%