22.Supplemental Information on Oil and Gas Operations (Unaudited)

Supplemental unaudited information regarding Devon's oil and gas activities is presented in this note. The information is provided separately by country. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon's discontinued operations.

Costs Incurred

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


	Year Ended December 31, 2014
	U.S.		Canada		Total

	(In millions)
Property acquisition costs:
Proved properties	$	5,210	$	-	$	5,210
Unproved properties		1,176		1		1,177
Exploration costs		270		52		322
Development costs		4,400		1,063		5,463
Costs incurred	$	11,056	$	1,116	$	12,172

	Year Ended December 31, 2013
	U.S.		Canada		Total

	(In millions)
Property acquisition costs:
Proved properties	$	19	$	3	$	22
Unproved properties		213		3		216
Exploration costs		443		152		595
Development costs		3,838		1,251		5,089
Costs incurred	$	4,513	$	1,409	$	5,922

	Year Ended December 31, 2012
	U.S.		Canada		Total

	(In millions)
Property acquisition costs:
Proved properties	$	2	$	71	$	73
Unproved properties		1,135		32		1,167
Exploration costs		351		315		666
Development costs		4,408		1,691		6,099
Costs incurred	$	5,896	$	2,109	$	8,005

Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions at closing have not been netted against the costs incurred. At December 31, 2014, our partners’ remaining commitments to fund our future costs associated with these joint venture transactions totaled approximately $250 million.

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $376 million, $368 million and $359 million in the years 2014, 2013 and 2012, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $45 million, $42 million and $36 million in the years 2014, 2013 and 2012, respectively.

Capitalized Costs

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


	December 31, 2014
	U.S.		Canada		Total

	(In millions)
Proved properties	$	59,849	$	15,889	$	75,738
Unproved properties		1,460		1,292		2,752
Total oil & gas properties		61,309		17,181		78,490
Accumulated DD&A		(38,213)		(11,347)		(49,560)
Net capitalized costs	$	23,096	$	5,834	$	28,930

	December 31, 2013
	U.S.		Canada		Total

	(In millions)
Proved properties	$	51,366	$	22,629	$	73,995
Unproved properties		1,277		1,514		2,791
Total oil & gas properties		52,643		24,143		76,786
Accumulated DD&A		(35,848)		(16,613)		(52,461)
Net capitalized costs	$	16,795	$	7,530	$	24,325

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


	Costs Incurred In
	2014		2013		2012		Prior to 2012		Total

	(In millions)
Acquisition costs	$	973	$	127	$	140	$	650	$	1,890
Exploration costs		111		76		68		107		362
Development costs		103		48		121		69		341
Capitalized interest		43		38		30		48		159
Total oil and gas properties not subject to amortization	$	1,230	$	289	$	359	$	874	$	2,752

Included in the $2.8 billion of oil and gas properties not subject to amortization are approximately $2.2 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the Eagle Ford in Texas. Based on Devon’s development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and developing the newly acquired Eagle Ford properties over the next four to five years.

Results of Operations

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


	December 31, 2014
	U.S.		Canada		Total

	(In millions)
Oil, gas and NGL sales	$	7,867	$	2,043	$	9,910
Lease operating expenses		(1,559)		(773)		(2,332)
General and administrative expenses		(153)		(57)		(210)
Production and property taxes		(466)		(37)		(503)
Depreciation, depletion and amortization		(2,365)		(531)		(2,896)
Gain on sale of assets		-		1,077		1,077
Accretion of asset retirement obligations		(49)		(39)		(88)
Income tax expense		(1,199)		(568)		(1,767)
Results of operations(1)	$	2,076	$	1,115	$	3,191
Depreciation, depletion and amortization per Boe	$	11.41	$	13.80	$	11.79

(1) In the fourth quarter of 2014, Devon recognized a $1.9 billion Canadian goodwill impairment that is not reflected in
this table.
	December 31, 2013
	U.S.		Canada		Total

	(In millions)
Oil, gas and NGL sales	$	5,964	$	2,558	$	8,522
Lease operating expenses		(1,257)		(1,011)		(2,268)
General and administrative expenses		(125)		(77)		(202)
Production and property taxes		(380)		(59)		(439)
Depreciation, depletion and amortization		(1,640)		(825)		(2,465)
Asset impairments		(1,110)		(843)		(1,953)
Accretion of asset retirement obligations		(47)		(64)		(111)
Income tax benefit (expense)		(510)		88		(422)
Results of operations	$	895	$	(233)	$	662
Depreciation, depletion and amortization per Boe	$	8.69	$	12.87	$	9.75

	December 31, 2012
	U.S.		Canada		Total

	(In millions)
Oil, gas and NGL sales	$	4,679	$	2,474	$	7,153
Lease operating expenses		(1,059)		(1,015)		(2,074)
General and administrative expenses		(159)		(137)		(296)
Production and property taxes		(340)		(55)		(395)
Depreciation, depletion and amortization		(1,563)		(963)		(2,526)
Asset impairments		(1,793)		(163)		(1,956)
Accretion of asset retirement obligations		(40)		(69)		(109)
Income tax benefit (expense)		99		(3)		96
Results of operations	$	(176)	$	69	$	(107)
Depreciation, depletion and amortization per Boe	$	8.55	$	14.41	$	10.12

Proved Reserves

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



	Oil (MMBbls)
	U.S.		Canada		Total

Proved developed and undeveloped reserves:
December 31, 2011		168		80		248
Revisions due to prices		(1)		(5)		(6)
Revisions other than price		(6)		(2)		(8)
Extensions and discoveries		65		7		72
Production		(21)		(15)		(36)
December 31, 2012		205		65		270
Revisions due to prices		1		(1)		-
Revisions other than price		(18)		-		(18)
Extensions and discoveries		69		7		76
Purchase of reserves		1		-		1
Production		(28)		(15)		(43)
Sale of reserves		(1)		-		(1)
December 31, 2013		229		56		285
Revisions due to prices		(1)		-		(1)
Revisions other than price		(38)		1		(37)
Extensions and discoveries		94		5		99
Purchase of reserves		132		-		132
Production		(48)		(10)		(58)
Sale of reserves		(17)		(29)		(46)
December 31, 2014		351		23		374

Proved developed reserves as of:
December 31, 2011		146		73		219
December 31, 2012		166		62		228
December 31, 2013		194		56		250
December 31, 2014		255		23		278
Proved developed-producing reserves as of:
December 31, 2011		139		65		204
December 31, 2012		155		56		211
December 31, 2013		178		51		229
December 31, 2014		224		19		243
Proved undeveloped reserves as of:
December 31, 2011		22		7		29
December 31, 2012		39		3		42
December 31, 2013		35		-		35
December 31, 2014		96		-		96



	Bitumen (MMBbls)
	U.S.		Canada		Total

Proved developed and undeveloped reserves:
December 31, 2011		-		457		457
Revisions due to prices		-		14		14
Revisions other than price		-		7		7
Extensions and discoveries		-		67		67
Production		-		(17)		(17)
December 31, 2012		-		528		528
Revisions due to prices		-		(11)		(11)
Revisions other than price		-		16		16
Extensions and discoveries		-		38		38
Production		-		(19)		(19)
December 31, 2013		-		552		552
Revisions due to prices		-		(37)		(37)
Revisions other than price		-		18		18
Extensions and discoveries		-		8		8
Production		-		(20)		(20)
December 31, 2014		-		521		521

Proved developed reserves as of:
December 31, 2011		-		90		90
December 31, 2012		-		99		99
December 31, 2013		-		111		111
December 31, 2014		-		137		137
Proved developed-producing reserves as of:
December 31, 2011		-		90		90
December 31, 2012		-		99		99
December 31, 2013		-		111		111
December 31, 2014		-		137		137
Proved undeveloped reserves as of:
December 31, 2011		-		367		367
December 31, 2012		-		429		429
December 31, 2013		-		441		441
December 31, 2014		-		384		384



	Gas (Bcf)
	U.S.		Canada		Total

Proved developed and undeveloped reserves:
December 31, 2011		9,507		979		10,486
Revisions due to prices		(831)		(99)		(930)
Revisions other than price		(287)		(33)		(320)
Extensions and discoveries		1,124		34		1,158
Purchase of reserves		2		-		2
Production		(752)		(186)		(938)
Sale of reserves		(1)		(11)		(12)
December 31, 2012		8,762		684		9,446
Revisions due to prices		405		161		566
Revisions other than price		(299)		67		(232)
Extensions and discoveries		471		19		490
Purchase of reserves		1		-		1
Production		(709)		(165)		(874)
Sale of reserves		(81)		(8)		(89)
December 31, 2013		8,550		758		9,308
Revisions due to prices		191		45		236
Revisions other than price		(299)		4		(295)
Extensions and discoveries		335		8		343
Purchase of reserves		457		-		457
Production		(660)		(41)		(701)
Sale of reserves		(923)		(738)		(1,661)
December 31, 2014		7,651		36		7,687

Proved developed reserves as of:
December 31, 2011		7,957		951		8,908
December 31, 2012		7,391		679		8,070
December 31, 2013		7,707		752		8,459
December 31, 2014		6,948		36		6,984
Proved developed-producing reserves as of:
December 31, 2011		7,409		862		8,271
December 31, 2012		7,091		624		7,715
December 31, 2013		7,425		680		8,105
December 31, 2014		6,746		34		6,780
Proved undeveloped reserves as of:
December 31, 2011		1,550		28		1,578
December 31, 2012		1,371		5		1,376
December 31, 2013		843		6		849
December 31, 2014		703		-		703



	Natural Gas Liquids (MMBbls)
	U.S.		Canada		Total

Proved developed and undeveloped reserves:
December 31, 2011		525		27		552
Revisions due to prices		(19)		(5)		(24)
Revisions other than price		(13)		-		(13)
Extensions and discoveries		114		2		116
Production		(36)		(4)		(40)
December 31, 2012		571		20		591
Revisions due to prices		8		3		11
Revisions other than price		(50)		3		(47)
Extensions and discoveries		64		1		65
Production		(41)		(4)		(45)
December 31, 2013		552		23		575
Revisions due to prices		7		1		8
Revisions other than price		2		-		2
Extensions and discoveries		47		-		47
Purchase of reserves		57		-		57
Production		(50)		(1)		(51)
Sale of reserves		(37)		(23)		(60)
December 31, 2014		578		-		578

Proved developed reserves as of:
December 31, 2011		402		26		428
December 31, 2012		431		20		451
December 31, 2013		468		23		491
December 31, 2014		486		-		486
Proved developed-producing reserves as of:
December 31, 2011		372		24		396
December 31, 2012		406		19		425
December 31, 2013		442		21		463
December 31, 2014		467		-		467
Proved undeveloped reserves as of:
December 31, 2011		123		1		124
December 31, 2012		140		-		140
December 31, 2013		84		-		84
December 31, 2014		92		-		92



	Total (MMBoe) (1)
	U.S.		Canada		Total

Proved developed and undeveloped reserves:
December 31, 2011		2,278		727		3,005
Revisions due to prices		(159)		(12)		(171)
Revisions other than price		(67)		(1)		(68)
Extensions and discoveries		367		82		449
Production		(183)		(67)		(250)
Sale of reserves		-		(2)		(2)
December 31, 2012		2,236		727		2,963
Revisions due to prices		76		18		94
Revisions other than price		(117)		29		(88)
Extensions and discoveries		212		49		261
Purchase of reserves		1		-		1
Production		(189)		(64)		(253)
Sale of reserves		(14)		(1)		(15)
December 31, 2013		2,205		758		2,963
Revisions due to prices		38		(29)		9
Revisions other than price		(86)		21		(65)
Extensions and discoveries		197		14		211
Purchase of reserves		265		-		265
Production		(207)		(39)		(246)
Sale of reserves		(207)		(176)		(383)
December 31, 2014		2,205		549		2,754

Proved developed reserves as of:
December 31, 2011		1,875		348		2,223
December 31, 2012		1,829		294		2,123
December 31, 2013		1,947		315		2,262
December 31, 2014		1,900		165		2,065
Proved developed-producing reserves as of:
December 31, 2011		1,746		323		2,069
December 31, 2012		1,743		278		2,021
December 31, 2013		1,857		297		2,154
December 31, 2014		1,815		162		1,977
Proved undeveloped reserves as of:
December 31, 2011		403		379		782
December 31, 2012		407		433		840
December 31, 2013		258		443		701
December 31, 2014		305		384		689

_______________________

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

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2014 (in MMBoe).



	U.S.		Canada		Total

Proved undeveloped reserves as of December 31, 2013		258		443		701
Extensions and discoveries		153		8		161
Revisions due to prices		(1)		(34)		(35)
Revisions other than price		(61)		18		(43)
Sale of reserves		(4)		(2)		(6)
Conversion to proved developed reserves		(40)		(49)		(89)
Proved undeveloped reserves as of December 31, 2014		305		384		689

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

A significant amount of Devon’s proved undeveloped reserves at the end of 2014 related to its Jackfish operations. At December 31, 2014 and 2013, Devon’s Jackfish proved undeveloped reserves were 384 MMBoe and 441 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5 years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.

Price Revisions

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

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

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

Revisions Other Than Price

Total revisions other than price for 2014, 2013 and 2012 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale and Barnett Shale.

Extensions and Discoveries

2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe related to the Permian Basin in west Texas and southeast New Mexico, 54 MMBoe related to the Eagle Ford in south Texas, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend in north Oklahoma.

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

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

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

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

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

Purchase of Reserves

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

Sale of Reserves

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

Standardized Measure

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


	Year Ended December 31, 2014
	U.S.		Canada		Total

	(In millions)
Future cash inflows	$	75,847	$	31,371	$	107,218
Future costs:
Development		(7,168)		(3,619)		(10,787)
Production		(29,740)		(14,232)		(43,972)
Future income tax expense		(11,021)		(3,026)		(14,047)
Future net cash flow		27,918		10,494		38,412
10% discount to reflect timing of cash flows		(12,819)		(5,119)		(17,938)
Standardized measure of discounted future net cash flows	$	15,099	$	5,375	$	20,474

	Year Ended December 31, 2013
	U.S.		Canada		Total

	(In millions)
Future cash inflows	$	61,983	$	33,305	$	95,288
Future costs:
Development		(5,448)		(5,308)		(10,756)
Production		(26,663)		(15,709)		(42,372)
Future income tax expense		(9,046)		(2,327)		(11,373)
Future net cash flow		20,826		9,961		30,787
10% discount to reflect timing of cash flows		(10,346)		(4,700)		(15,046)
Standardized measure of discounted future net cash flows	$	10,480	$	5,261	$	15,741

	Year Ended December 31, 2012
	U.S.		Canada		Total

	(In millions)
Future cash inflows	$	55,297	$	33,570	$	88,867
Future costs:
Development		(6,556)		(6,211)		(12,767)
Production		(24,265)		(16,611)		(40,876)
Future income tax expense		(6,542)		(1,992)		(8,534)
Future net cash flow		17,934		8,756		26,690
10% discount to reflect timing of cash flows		(9,036)		(4,433)		(13,469)
Standardized measure of discounted future net cash flows	$	8,898	$	4,323	$	13,221

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2014 estimates, Devon’s future realized prices were assumed to be $87.14 per barrel of oil, $57.25 per barrel of bitumen, $3.94 per Mcf of gas and $25.05 per barrel of natural gas liquids. Of the $10.8 billion of future development costs as of the end of 2014, $2.2 billion, $1.9 billion and $1.0 billion are estimated to be spent in 2015, 2016 and 2017, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $10.8 billion of future development costs are $1.5 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.

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


	Year Ended December 31,
	2014		2013		2012

	(In millions)
Beginning balance	$	15,741	$	13,221	$	17,844
Net changes in prices and production costs		2,561		3,018		(9,889)
Oil, bitumen, gas and NGL sales, net of production costs		(6,865)		(5,613)		(4,388)
Changes in estimated future development costs		(768)		399		(1,094)
Extensions and discoveries, net of future development costs		4,836		4,047		4,669
Purchase of reserves		6,422		14		18
Sales of reserves in place		(2,384)		(44)		(25)
Revisions of quantity estimates		(746)		(1,040)		162
Previously estimated development costs incurred during the period		1,933		1,986		1,321
Accretion of discount		1,746		1,940		1,420
Other, primarily changes in timing and foreign exchange rates		(107)		(583)		113
Net change in income taxes		(1,895)		(1,604)		3,070
Ending balance	$	20,474	$	15,741	$	13,221