Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. All of Devon’s reserves are located within the U.S.

The supplemental information in the tables below excludes amounts for all periods presented related to Devon’s discontinued operations, which consist of Devon’s Canadian operations that were sold in 2019 and its Barnett Shale assets, inclusive of properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas, which were sold in October 2020. Amounts excluded for 2019 and 2018 consisted of 612 MMBoe and 1,104 MMBoe, respectively, of estimated proved reserves and $940 million and $3,042 million, respectively, of discounted future net cash flows, which related to both Devon’s Canadian operations and its Barnett Shale assets. For additional information on these discontinued operations, see Note 19.

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

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

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.

	Year Ended December 31,
	2020			2019			2018
Oil, gas and NGL sales	$	2,695		$	3,809		$	4,085
Production expenses		(1,123	)		(1,197	)		(1,153	)
Exploration expenses		(167	)		(58	)		(128	)
Depreciation, depletion and amortization		(1,207	)		(1,398	)		(1,134	)
Asset dispositions		—			37			276
Asset impairments		(2,664	)		—			(109	)
Accretion of asset retirement obligations		(20	)		(21	)		(26	)
Income tax expense		—			(270	)		(416	)
Results of operations	$	(2,486	)	$	902		$	1,395
Depreciation, depletion and amortization per Boe	$	9.90		$	11.72		$	10.51


	Oil (MMBbls)			Gas (Bcf) ⁽¹⁾			NGL (MMBbls)			Combined (MMBoe)
Proved developed and undeveloped reserves:
December 31, 2017		254			1,810			231			787
Revisions due to prices		12			7			2			15
Revisions other than price		(10	)		(102	)		(27	)		(53	)
Extensions and discoveries		93			358			54			206
Production		(47	)		(206	)		(26	)		(108	)
Sale of reserves		(6	)		(65	)		(7	)		(24	)
December 31, 2018		296			1,802			227			823
Revisions due to prices		(7	)		(86	)		(6	)		(28	)
Revisions other than price		(13	)		(50	)		(9	)		(31	)
Extensions and discoveries		76			269			39			160
Purchase of reserves		3			7			1			6
Production		(55	)		(219	)		(28	)		(119	)
Sale of reserves		(24	)		(102	)		(13	)		(54	)
December 31, 2019		276			1,621			211			757
Revisions due to prices		(26	)		(209	)		(17	)		(78	)
Revisions other than price		18			119			17			55
Extensions and discoveries		71			188			33			135
Purchase of reserves		1			19			3			7
Production		(57	)		(221	)		(28	)		(122	)
Sale of reserves		(1	)		(5	)		(1	)		(2	)
December 31, 2020		282			1,512			218			752

Proved developed reserves:
December 31, 2017		175			1,455			168			585
December 31, 2018		196			1,427			166			600
December 31, 2019		198			1,344			167			589
December 31, 2020		194			1,244			173			574
Proved developed-producing reserves:
December 31, 2017		163			1,384			160			554
December 31, 2018		188			1,394			162			582
December 31, 2019		191			1,327			165			578
December 31, 2020		190			1,223			171			564
Proved undeveloped reserves:
December 31, 2017		79			355			63			202
December 31, 2018		100			375			61			223
December 31, 2019		78			277			44			168
December 31, 2020		88			268			45			178

Reserves decreased 78 MMBoe in 2020 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs.

Reserves decreased 28 MMBoe in 2019 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs. Reserves increased 15 MMBoe in 2018 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.

2020 – Total revisions other than price (55 MMBoe) were primarily due to well performance exceeding previous estimates (75 MMBoe) and the removal of proved undeveloped locations as noted below (-20 MMBoe). The most significant well performance revisions were attributable to the Delaware Basin (40 MMBoe) and the STACK region of the Anadarko Basin (22 MMBoe).

2019 – Total revisions other than price in 2019 were primarily due to changes in previously adopted development plans in the STACK region of the Anadarko Basin (-9 MMBoe) and in the Delaware Basin (-6 MMBoe). An additional downward revision of 5 MMBoe was the result of reduced recovery estimates attributable to continued evaluation of analogous offset well performance primarily in the STACK region of the Anadarko Basin.

2018 – Total revisions other than price primarily related to Devon’s development programs evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK region of the Anadarko Basin.

Each year, Devon’s proved reserves extensions and discoveries consist of adding proved undeveloped reserves to locations classified as undeveloped at year-end and adding proved developed reserves from successful development wells drilled on locations outside the areas classified as proved at the previous year-end. Therefore, it is not uncommon for Devon’s total proved extensions and discoveries to differ from the extensions and discoveries for Devon’s proved undeveloped reserves. Furthermore, because annual additions are classified according to reserve determinations made at the previous year-end and because Devon operates a multi-basin portfolio with assets at varying stages of maturity, extensions and discoveries for proved developed and proved undeveloped reserves can differ significantly in any particular year.

2020 – Of the 135 MMBoe of additions from extensions and discoveries, 117 MMBoe were in the Delaware Basin, 8 MMBoe were in the STACK region of the Anadarko Basin, 5 MMBoe in the Powder River Basin and 5 MMBoe in Eagle Ford.

2019 – Of the 160 MMBoe of additions from extensions and discoveries, 77 MMBoe were in the Delaware Basin, 37 MMBoe were in the STACK region of the Anadarko Basin, 28 MMBoe in the Powder River Basin and 18 MMBoe in Eagle Ford. In 2019, there were no additions related to infill drilling activities.

2018 – Approximately 85% of the additions were through focused efforts in the STACK region of the Anadarko Basin (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.

The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK region of the Anadarko Basin.

During 2020, 2019 and 2018, Devon had U.S. non-core asset divestitures. For additional information on these divestitures, see Note 2.

The following table presents the changes in Devon’s total proved undeveloped reserves during 2020 (MMBoe).

Total proved undeveloped reserves increased 6% from 2019 to 2020 with the year-end 2020 balance representing 24% of total proved reserves. Over 87% of the 105 MMBoe in extensions and discoveries were the result of Devon’s focus on drilling and development activities in the Delaware Basin. This continued development in the Delaware Basin also led to the conversion of 68 MMBoe, or 40% of the 2019 proved undeveloped reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $448 million for 2020. Proved undeveloped reserves revisions other than price were primarily due to changes in previously adopted development plans in the STACK region of the Anadarko Basin (-12 MMBoe) and the Delaware Basin (-8 MMBoe).

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

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 2020 estimates, Devon’s future realized prices were assumed to be $37.35 per Bbl of oil, $1.37 per Mcf of gas and $10.76 per Bbl of NGLs. Of the $1.7 billion of future development costs as of the end of 2020, $0.6 billion, $0.4 billion and $0.2 billion are estimated to be spent in 2021, 2022 and 2023, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $1.7 billion of future development costs are $0.3 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,
	2020			2019			2018
Beginning balance	$	5,398		$	7,150		$	5,954
Net changes in prices and production costs		(3,277	)		(2,323	)		1,533
Oil, gas and NGL sales, net of production costs		(1,572	)		(2,612	)		(2,932	)
Changes in estimated future development costs		402			303			(273	)
Extensions and discoveries, net of future development costs		988			1,690			2,944
Purchase of reserves		23			43			—
Sales of reserves in place		(7	)		(481	)		(120	)
Revisions of quantity estimates		147			(359	)		(152	)
Previously estimated development costs incurred during the period		537			857			787
Accretion of discount		285			506			648
Net change in income taxes and other		548			624			(1,239	)
Ending balance	$	3,472		$	5,398		$	7,150