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.

Costs Incurred

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

	Year Ended December 31, 2016
	U.S.		Canada		Total
	(Millions)
Property acquisition costs:
Proved properties	$	237	$	—	$	237
Unproved properties		1,356		2		1,358
Exploration costs		345		49		394
Development costs		1,034		109		1,143
Costs incurred	$	2,972	$	160	$	3,132

	Year Ended December 31, 2015
	U.S.		Canada		Total
	(Millions)
Property acquisition costs:
Proved properties	$	193	$	2	$	195
Unproved properties		634		83		717
Exploration costs		478		109		587
Development costs		3,269		402		3,671
Costs incurred	$	4,574	$	596	$	5,170

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

Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.

Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $244 million, $372 million and $376 million in 2016, 2015 and 2014, 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 $64 million, $54 million and $45 million in 2016, 2015 and 2014, respectively.

Capitalized Costs

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

	December 31, 2016
	U.S.			Canada			Total
	(Millions)
Proved properties	$	61,401		$	14,247		$	75,648
Unproved properties		2,092			1,345			3,437
Total oil and gas properties		63,493			15,592			79,085
Accumulated DD&A		(57,323	)		(13,107	)		(70,430	)
Net capitalized costs	$	6,170		$	2,485		$	8,655

	December 31, 2015
	U.S.			Canada			Total
	(Millions)
Proved properties	$	64,443		$	13,747		$	78,190
Unproved properties		1,352			1,232			2,584
Total oil and gas properties		65,795			14,979			80,774
Accumulated DD&A		(58,312	)		(11,185	)		(69,497	)
Net capitalized costs	$	7,483		$	3,794		$	11,277

The following table presents a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2016.

	Costs Incurred In
	2016		2015		2014		Prior to 2014		Total
	(Millions)
Acquisition costs	$	1,176	$	579	$	246	$	464	$	2,465
Exploration costs		107		134		89		206		536
Development costs		12		—		23		150		185
Capitalized interest		63		52		37		99		251
Total oil and gas properties not subject to amortization	$	1,358	$	765	$	395	$	919	$	3,437

Included in the $3.4 billion of oil and gas properties not subject to amortization are approximately $2.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada, the assets acquired in the STACK play during 2016 and the Powder River Basin assets acquired in 2015. Devon continues to assess its Pike development timeline with its 50% partner. Based on the development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired STACK and Powder River Basin 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 DD&A and after giving effect to permanent differences.

	December 31, 2016
	U.S.			Canada			Total
	(Millions)
Oil, gas and NGL sales	$	3,198		$	984		$	4,182
Lease operating expenses		(1,123	)		(459	)		(1,582	)
General and administrative expenses		(148	)		(20	)		(168	)
Production and property taxes		(200	)		(31	)		(231	)
Depreciation, depletion and amortization		(817	)		(326	)		(1,143	)
Gains on asset sales		1,351			—			1,351
Asset impairments		(2,809	)		(1,291	)		(4,100	)
Accretion of asset retirement obligations		(49	)		(25	)		(74	)
Income tax benefit		—			245			245
Results of operations	$	(597	)	$	(923	)	$	(1,520	)
Depreciation, depletion and amortization per Boe	$	4.68		$	6.65		$	5.11

	December 31, 2015
	U.S.			Canada			Total
	(Millions)
Oil, gas and NGL sales	$	4,356		$	1,026		$	5,382
Lease operating expenses		(1,551	)		(553	)		(2,104	)
General and administrative expenses		(196	)		(28	)		(224	)
Production and property taxes		(309	)		(33	)		(342	)
Depreciation, depletion and amortization		(2,107	)		(474	)		(2,581	)
Asset impairments		(17,992	)		(1,257	)		(19,249	)
Accretion of asset retirement obligations		(47	)		(27	)		(74	)
Income tax benefit		5,547			314			5,861
Results of operations	$	(12,299	)	$	(1,032	)	$	(13,331	)
Depreciation, depletion and amortization per Boe	$	10.21		$	11.30		$	10.40

	December 31, 2014
	U.S.			Canada			Total
	(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	)
Gains on asset sales		—			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)	During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.

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, 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
Revisions due to prices		(53	)		4			(49	)
Revisions other than price		(52	)		2			(50	)
Extensions and discoveries		51			3			54
Purchase of reserves		5			—			5
Production		(60	)		(10	)		(70	)
December 31, 2015		242			22			264
Revisions due to prices		(18	)		(2	)		(20	)
Revisions other than price		(2	)		3			1
Extensions and discoveries		36			2			38
Purchase of reserves		8			—			8
Production		(47	)		(8	)		(55	)
Sale of reserves		(25	)		—			(25	)
December 31, 2016		194			17			211
Proved developed reserves as of:
December 31, 2013		194			56			250
December 31, 2014		255			23			278
December 31, 2015		203			22			225
December 31, 2016		160			17			177
Proved developed-producing reserves as of:
December 31, 2013		178			51			229
December 31, 2014		224			19			243
December 31, 2015		192			19			211
December 31, 2016		143			13			156
Proved undeveloped reserves as of:
December 31, 2013		35			—			35
December 31, 2014		96			—			96
December 31, 2015		39			—			39
December 31, 2016		34			—			34


	Bitumen (MMBbls)
	U.S.		Canada			Total
Proved developed and undeveloped reserves:
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
Revisions due to prices		—		103			103
Revisions other than price		—		(84	)		(84	)
Extensions and discoveries		—		11			11
Production		—		(31	)		(31	)
December 31, 2015		—		520			520
Revisions due to prices		—		23			23
Revisions other than price		—		(19	)		(19	)
Production		—		(40	)		(40	)
December 31, 2016		—		484			484
Proved developed reserves as of:
December 31, 2013		—		111			111
December 31, 2014		—		137			137
December 31, 2015		—		219			219
December 31, 2016		—		190			190
Proved developed-producing reserves as of:
December 31, 2013		—		111			111
December 31, 2014		—		137			137
December 31, 2015		—		219			219
December 31, 2016		—		190			190
Proved undeveloped reserves as of:
December 31, 2013		—		441			441
December 31, 2014		—		384			384
December 31, 2015		—		301			301
December 31, 2016		—		294			294


	Gas (Bcf)
	U.S.			Canada			Total
Proved developed and undeveloped reserves:
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
Revisions due to prices		(1,412	)		(9	)		(1,421	)
Revisions other than price		(3	)		(6	)		(9	)
Extensions and discoveries		171			—			171
Purchase of reserves		17			—			17
Production		(579	)		(8	)		(587	)
Sale of reserves		(37	)		—			(37	)
December 31, 2015		5,808			13			5,821
Revisions due to prices		(103	)		—			(103	)
Revisions other than price		628			10			638
Extensions and discoveries		280			—			280
Purchase of reserves		33			—			33
Production		(510	)		(7	)		(517	)
Sale of reserves		(521	)		—			(521	)
December 31, 2016		5,615			16			5,631
Proved developed reserves as of:
December 31, 2013		7,707			752			8,459
December 31, 2014		6,948			36			6,984
December 31, 2015		5,694			13			5,707
December 31, 2016		5,361			16			5,377
Proved developed-producing reserves as of:
December 31, 2013		7,425			680			8,105
December 31, 2014		6,746			34			6,780
December 31, 2015		5,546			13			5,559
December 31, 2016		5,243			16			5,259
Proved undeveloped reserves as of:
December 31, 2013		843			6			849
December 31, 2014		703			—			703
December 31, 2015		114			—			114
December 31, 2016		254			—			254


	Natural Gas Liquids (MMBbls)
	U.S.			Canada			Total
Proved developed and undeveloped reserves:
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
Revisions due to prices		(119	)		—			(119	)
Revisions other than price		(6	)		—			(6	)
Extensions and discoveries		24			—			24
Purchase of reserves		1			—			1
Production		(50	)		—			(50	)
December 31, 2015		428			—			428
Revisions due to prices		(13	)		—			(13	)
Revisions other than price		48			—			48
Extensions and discoveries		42			—			42
Purchase of reserves		7			—			7
Production		(42	)		—			(42	)
Sale of reserves		(45	)		—			(45	)
December 31, 2016		425			—			425
Proved developed reserves as of:
December 31, 2013		468			23			491
December 31, 2014		486			—			486
December 31, 2015		411			—			411
December 31, 2016		387			—			387
Proved developed-producing reserves as of:
December 31, 2013		442			21			463
December 31, 2014		467			—			467
December 31, 2015		393			—			393
December 31, 2016		370			—			370
Proved undeveloped reserves as of:
December 31, 2013		84			—			84
December 31, 2014		92			—			92
December 31, 2015		17			—			17
December 31, 2016		38			—			38


	Total (MMBoe) ⁽¹⁾
	U.S.			Canada			Total
Proved developed and undeveloped reserves:
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
Revisions due to prices		(408	)		106			(302	)
Revisions other than price		(59	)		(83	)		(142	)
Extensions and discoveries		104			14			118
Purchase of reserves		9			—			9
Production		(206	)		(42	)		(248	)
Sale of reserves		(7	)		—			(7	)
December 31, 2015		1,638			544			2,182
Revisions due to prices		(48	)		21			(27	)
Revisions other than price		151			(14	)		137
Extensions and discoveries		124			2			126
Purchase of reserves		20			—			20
Production		(174	)		(49	)		(223	)
Sale of reserves		(157	)		—			(157	)
December 31, 2016		1,554			504			2,058
Proved developed reserves as of:
December 31, 2013		1,947			315			2,262
December 31, 2014		1,900			165			2,065
December 31, 2015		1,563			243			1,806
December 31, 2016		1,439			210			1,649
Proved developed-producing reserves as of:
December 31, 2013		1,857			297			2,154
December 31, 2014		1,815			162			1,977
December 31, 2015		1,509			240			1,749
December 31, 2016		1,386			207			1,593
Proved undeveloped reserves as of:
December 31, 2013		258			443			701
December 31, 2014		305			384			689
December 31, 2015		75			301			376
December 31, 2016		115			294			409

(1)

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

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2016 (MMBoe).


	U.S.			Canada			Total
Proved undeveloped reserves as of December 31, 2015		75			301			376
Extensions and discoveries		78			—			78
Revisions due to prices		(8	)		10			2
Revisions other than price		(1	)		(4	)		(5	)
Sale of reserves		(1	)		—			(1	)
Conversion to proved developed reserves		(28	)		(13	)		(41	)
Proved undeveloped reserves as of December 31, 2016		115			294			409

Proved undeveloped reserves increased 9% from 2015 to 2016, and the year-end 2016 balance represents 20% of total proved reserves. Drilling and development activities in the STACK and Delaware Basin increased Devon’s proved undeveloped reserves by 78 MMBoe. Continued development of Devon’s Eagle Ford and Jackfish properties led to the conversion of 41 MMBoe, or 11%, of the 2015 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $586 million for 2016.

A significant amount of Devon’s proved undeveloped reserves at the end of 2016 related to its Jackfish operations. At December 31, 2016 and 2015, Devon’s Jackfish proved undeveloped reserves were 294 MMBoe and 301 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5 years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through 2029. At the end of 2016, approximately 199 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 119 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.

Price Revisions

Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower commodity prices for oil, bitumen and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes.

In 2014, price revisions increased Devon’s total proved reserves less than 1% due to higher commodity prices.

Revisions Other Than Price

Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale). Revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish were primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 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

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

The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 73 MMBoe related to STACK.

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

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

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

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

Purchase of Reserves

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

2015 – Primarily related to Devon’s acquisition in the Powder River Basin.

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

Sale of Reserves

2016 – The 157 MMBoe of reserves sales related to Devon’s non-core upstream asset divestitures discussed further in Note 2.

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

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

Standardized Measure

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

	Year Ended December 31, 2016
	U.S.			Canada			Total
	(Millions)
Future cash inflows	$	22,847		$	9,672		$	32,519
Future costs:
Development		(2,784	)		(2,201	)		(4,985	)
Production		(14,484	)		(6,287	)		(20,771	)
Future income tax expense		—			(57	)		(57	)
Future net cash flow		5,579			1,127			6,706
10% discount to reflect timing of cash flows		(2,128	)		(380	)		(2,508	)
Standardized measure of discounted future net cash flows	$	3,451		$	747		$	4,198

	Year Ended December 31, 2015
	U.S.			Canada			Total
	(Millions)
Future cash inflows	$	27,398		$	13,047		$	40,445
Future costs:
Development		(3,306	)		(2,759	)		(6,065	)
Production		(17,251	)		(6,891	)		(24,142	)
Future income tax expense		—			(475	)		(475	)
Future net cash flow		6,841			2,922			9,763
10% discount to reflect timing of cash flows		(1,973	)		(1,102	)		(3,075	)
Standardized measure of discounted future net cash flows	$	4,868		$	1,820		$	6,688

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

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 2016 estimates, Devon’s future realized prices were assumed to be $37.37 per Bbl of oil, $15.74 per Bbl of bitumen, $1.98 per Mcf of gas and $9.91 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2016, $0.4 billion, $0.8 billion and $0.5 billion are estimated to be spent in 2017, 2018 and 2019, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.0 billion of future development costs are $1.3 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,
	2016			2015			2014
	(Millions)
Beginning balance	$	6,688		$	20,474		$	15,741
Net changes in prices and production costs		(2,128	)		(20,756	)		2,561
Oil, bitumen, gas and NGL sales, net of production costs		(2,163	)		(2,704	)		(6,865	)
Changes in estimated future development costs		112			1,313			(768	)
Extensions and discoveries, net of future development costs		660			1,129			4,836
Purchase of reserves		222			95			6,422
Sales of reserves in place		(560	)		(79	)		(2,384	)
Revisions of quantity estimates		(32	)		(1,451	)		(746	)
Previously estimated development costs incurred during the period		663			2,158			1,933
Accretion of discount		403			567			1,746
Foreign exchange and other		105			(1,254	)		(107	)
Net change in income taxes		228			7,196			(1,895	)
Ending balance	$	4,198		$	6,688		$	20,474