24.	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.

Included in this note are disclosures of Devon’s results of operations for oil and gas producing activities and standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. In conjunction with Devon’s oil and gas accounting policy change discussed in Note 1, Devon also modified its treatment of certain “production support” costs in these two disclosures. Production support costs consisted of labor, supervision, materials and supplies for oil and gas production monitoring and support activities, including information technology, accounting and certain other administrative support functions. These costs are included in G&A expenses in the accompanying consolidated comprehensive statements of earnings. Devon used a method to allocate these costs to its country-based results of operations and standardized measure disclosures. In 2016 and 2015, Devon’s results of operations disclosures included production support costs of $168 million and $224 million, respectively, and its standardized measure disclosures included estimated future production support costs of $2.8 billion and $2.7 billion, respectively.

Devon’s 2016 and 2015 disclosures have been revised to exclude these amounts.

Based on research conducted by Devon, diversity of practice has existed across peer companies regarding the treatment of production support costs in results of operations and standardized measure disclosures. Devon’s research of public filings indicates most companies exclude such costs from results of operations and standardized measure disclosures, but some companies appear to include such costs in their disclosures. Considering the apparent diversity of practice, Devon is making this disclosure change for two primary reasons. First, by converting to the successful efforts method of accounting and making this disclosure change, Devon’s results of operations and standardized measure disclosures will be most comparable to the vast majority of its peers. Second, allocating these costs to more granular common operating fields as opposed to country-based full cost pools is cost prohibitive and not materially important to investors and stakeholders, considering such allocated costs represented approximately 4% of Devon’s 2016 and 2015 oil, gas and NGL sales.

Costs Incurred

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

	Year Ended December 31, 2017
	U.S.		Canada		Total
Property acquisition costs:
Proved properties	$	2	$	—	$	2
Unproved properties		50		4		54
Exploration costs		590		87		677
Development costs		1,036		225		1,261
Costs incurred	$	1,678	$	316	$	1,994

	Year Ended December 31, 2016
	U.S.		Canada		Total
Property acquisition costs:
Proved properties	$	237	$	—	$	237
Unproved properties		1,356		2		1,358
Exploration costs		282		78		360
Development costs		875		54		929
Costs incurred	$	2,750	$	134	$	2,884

	Year Ended December 31, 2015
	U.S.		Canada		Total
Property acquisition costs:
Proved properties	$	193	$	2	$	195
Unproved properties		635		81		716
Exploration costs		432		120		552
Development costs		2,982		351		3,333
Costs incurred	$	4,242	$	554	$	4,796

Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. Additionally, 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 $69 million, $61 million and $52 million in 2017, 2016 and 2015, respectively.

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, 2017
	U.S.			Canada			Total
Oil, gas and NGL sales	$	3,746		$	1,404		$	5,150
Production expenses		(1,232	)		(591	)		(1,823	)
Exploration expenses		(346	)		(34	)		(380	)
Depreciation, depletion and amortization		(1,050	)		(369	)		(1,419	)
Asset dispositions		211			1			212
Accretion of asset retirement obligations		(38	)		(24	)		(62	)
Income tax expense		—			(104	)		(104	)
Results of operations	$	1,291		$	283		$	1,574
Depreciation, depletion and amortization per Boe	$	6.97		$	7.73		$	7.15

	December 31, 2016
	U.S.			Canada			Total
Oil, gas and NGL sales	$	3,198		$	984		$	4,182
Production expenses		(1,311	)		(492	)		(1,803	)
Exploration expenses		(176	)		(39	)		(215	)
Depreciation, depletion and amortization		(1,066	)		(380	)		(1,446	)
Asset dispositions		946			1			947
Asset impairments		(435	)		—			(435	)
Accretion of asset retirement obligations		(49	)		(26	)		(75	)
Income tax expense		—			(13	)		(13	)
Results of operations	$	1,107		$	35		$	1,142
Depreciation, depletion and amortization per Boe	$	6.11		$	7.75		$	6.47

	December 31, 2015
	U.S.			Canada			Total
Oil, gas and NGL sales	$	4,356		$	1,026		$	5,382
Production expenses		(1,853	)		(586	)		(2,439	)
Exploration expenses		(323	)		(128	)		(451	)
Depreciation, depletion and amortization		(3,051	)		(423	)		(3,474	)
Asset dispositions		32			(39	)		(7	)
Asset impairments		(16,061	)		(15	)		(16,076	)
Accretion of asset retirement obligations		(47	)		(28	)		(75	)
Income tax benefit		5,783			50			5,833
Results of operations	$	(11,164	)	$	(143	)	$	(11,307	)
Depreciation, depletion and amortization per Boe	$	14.79		$	10.08		$	13.99

Proved Reserves

The following table presents Devon’s estimated proved reserves by product and by country.

										Bitumen												NGL
	Oil (MMBbls)									(MMBbls)			Gas (Bcf)									(MMBbls)			Combined (MMBoe) ⁽¹⁾
	U.S.			Canada			Total			Canada			U.S.			Canada			Total			U.S.			U.S.			Canada			Total
Proved developed and undeveloped reserves:
December 31, 2014		351			23			374			521			7,651			36			7,687			578			2,205			549			2,754
Revisions due to prices		(53	)		4			(49	)		103			(1,412	)		(9	)		(1,421	)		(119	)		(408	)		106			(302	)
Revisions other than price		(52	)		2			(50	)		(84	)		(3	)		(6	)		(9	)		(6	)		(59	)		(83	)		(142	)
Extensions and discoveries		51			3			54			11			171			—			171			24			104			14			118
Purchase of reserves		5			—			5			—			17			—			17			1			9			—			9
Production		(60	)		(10	)		(70	)		(31	)		(579	)		(8	)		(587	)		(50	)		(206	)		(42	)		(248	)
Sale of reserves		—			—			—			—			(37	)		—			(37	)		—			(7	)		—			(7	)
December 31, 2015		242			22			264			520			5,808			13			5,821			428			1,638			544			2,182
Revisions due to prices		(18	)		(2	)		(20	)		23			(103	)		—			(103	)		(13	)		(48	)		21			(27	)
Revisions other than price		(2	)		3			1			(19	)		628			10			638			48			151			(14	)		137
Extensions and discoveries		36			2			38			—			280			—			280			42			124			2			126
Purchase of reserves		8			—			8			—			33			—			33			7			20			—			20
Production		(47	)		(8	)		(55	)		(40	)		(510	)		(7	)		(517	)		(42	)		(174	)		(49	)		(223	)
Sale of reserves		(25	)		—			(25	)		—			(521	)		—			(521	)		(45	)		(157	)		—			(157	)
December 31, 2016		194			17			211			484			5,615			16			5,631			425			1,554			504			2,058
Revisions due to prices		12			(1	)		11			(37	)		398			1			399			32			111			(38	)		73
Revisions other than price		6			2			8			(10	)		—			2			2			(10	)		(5	)		(7	)		(12	)
Extensions and discoveries		90			4			94			12			403			—			403			63			221			16			237
Production		(42	)		(7	)		(49	)		(40	)		(433	)		(6	)		(439	)		(36	)		(150	)		(48	)		(198	)
Sale of reserves		(3	)		—			(3	)		—			(9	)		—			(9	)		(1	)		(6	)		—			(6	)
December 31, 2017		257			15			272			409			5,974			13			5,987			473			1,725			427			2,152

Proved developed reserves:
December 31, 2014		255			23			278			137			6,948			36			6,984			486			1,900			165			2,065
December 31, 2015		203			22			225			219			5,694			13			5,707			411			1,563			243			1,806
December 31, 2016		160			17			177			190			5,361			16			5,377			387			1,439			210			1,649
December 31, 2017		178			15			193			200			5,619			13			5,632			410			1,524			218			1,742
Proved developed-producing reserves:
December 31, 2014		224			19			243			137			6,746			34			6,780			467			1,815			162			1,977
December 31, 2015		192			19			211			219			5,546			13			5,559			393			1,509			240			1,749
December 31, 2016		143			13			156			190			5,243			16			5,259			370			1,386			207			1,593
December 31, 2017		165			12			177			197			5,512			13			5,525			397			1,481			212			1,693
Proved undeveloped reserves:
December 31, 2014		96			—			96			384			703			—			703			92			305			384			689
December 31, 2015		39			—			39			301			114			—			114			17			75			301			376
December 31, 2016		34			—			34			294			254			—			254			38			115			294			409
December 31, 2017		79			—			79			209			355			—			355			63			201			209			410

(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 2017 (MMBoe).

	U.S.			Canada			Total
Proved undeveloped reserves as of December 31, 2016		115			294			409
Extensions and discoveries		116			12			128
Revisions due to prices		—			(27	)		(27	)
Revisions other than price		(21	)		(6	)		(27	)
Conversion to proved developed reserves		(9	)		(64	)		(73	)
Proved undeveloped reserves as of December 31, 2017		201			209			410

Total proved undeveloped reserves remained consistent from 2016 to 2017 with the year-end 2017 balance representing 19% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 128 MMBoe increase in extensions and discoveries. Continued development primarily at Jackfish led to the conversion of 73 MMBoe, or 18%, of the 2016 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $237 million for 2017.

A significant amount of Devon’s proved undeveloped reserves at the end of 2017 related to its Jackfish operations. At December 31, 2017 and 2016, Devon’s Jackfish proved undeveloped reserves were 209 MMBoe and 294 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 five 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 2028. At the end of 2017, approximately 196 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 88 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 increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing its royalties, which decreases its after-royalty volumes.

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

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.

Extensions and Discoveries

2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.

The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities, which was primarily related to the STACK.

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.

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.

Sale of Reserves

2017 – Related to Devon’s non-core asset divestitures in the U.S. as discussed further in Note 3.

2016 – Related to Devon’s non-core upstream asset divestitures discussed further in Note 3.

Standardized Measure

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

	Year Ended December 31, 2017
	U.S.			Canada			Total
Future cash inflows	$	34,701		$	13,602		$	48,303
Future costs:
Development		(3,316	)		(1,853	)		(5,169	)
Production		(15,526	)		(5,986	)		(21,512	)
Future income tax expense		—			(988	)		(988	)
Future net cash flow		15,859			4,775			20,634
10% discount to reflect timing of cash flows		(7,541	)		(1,756	)		(9,297	)
Standardized measure of discounted future net cash flows	$	8,318		$	3,019		$	11,337

	Year Ended December 31, 2016
	U.S.			Canada			Total
Future cash inflows	$	22,847		$	9,672		$	32,519
Future costs:
Development		(2,784	)		(2,201	)		(4,985	)
Production		(11,934	)		(6,049	)		(17,983	)
Future income tax expense		—			(121	)		(121	)
Future net cash flow		8,129			1,301			9,430
10% discount to reflect timing of cash flows		(3,524	)		(466	)		(3,990	)
Standardized measure of discounted future net cash flows	$	4,605		$	835		$	5,440

	Year Ended December 31, 2015
	U.S.			Canada			Total
Future cash inflows	$	27,398		$	13,047		$	40,445
Future costs:
Development		(3,306	)		(2,759	)		(6,065	)
Production		(14,938	)		(6,501	)		(21,439	)
Future income tax expense		—			(580	)		(580	)
Future net cash flow		9,154			3,207			12,361
10% discount to reflect timing of cash flows		(3,230	)		(1,248	)		(4,478	)
Standardized measure of discounted future net cash flows	$	5,924		$	1,959		$	7,883

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 2017 estimates, Devon’s future realized prices were assumed to be $47.86 per Bbl of oil, $31.86 per Bbl of bitumen, $2.43 per Mcf of gas and $16.25 per Bbl of NGLs. Of the $5.2 billion of future development costs as of the end of 2017, $0.9 billion, $0.8 billion and $0.5 billion are estimated to be spent in 2018, 2019 and 2020, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.2 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,
	2017			2016			2015
Beginning balance	$	5,440		$	7,883		$	21,583
Net changes in prices and production costs		5,218			(2,027	)		(21,330	)
Oil, bitumen, gas and NGL sales, net of production costs		(3,327	)		(2,379	)		(2,943	)
Changes in estimated future development costs		789			112			1,313
Extensions and discoveries, net of future development costs		2,497			674			1,102
Purchase of reserves		2			224			93
Sales of reserves in place		(3	)		(577	)		(77	)
Revisions of quantity estimates		(318	)		(21	)		(1,312	)
Previously estimated development costs incurred during the period		559			663			2,158
Accretion of discount		1,034			537			702
Foreign exchange and other		(7	)		74			(1,148	)
Net change in income taxes		(547	)		277			7,742
Ending balance	$	11,337		$	5,440		$	7,883