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 2020 and 2019 related to Devon’s discontinued operations. 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.

Acquisition costs for 2021 in the table above largely pertain to the Merger. 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,
	2021			2020			2019
Oil, gas and NGL sales	$	9,531		$	2,695		$	3,809
Production expenses		(2,131	)		(1,123	)		(1,197	)
Exploration expenses		(14	)		(167	)		(58	)
Depreciation, depletion and amortization		(2,050	)		(1,207	)		(1,398	)
Asset dispositions		170			—			37
Asset impairments		—			(2,664	)		—
Accretion of asset retirement obligations		(28	)		(20	)		(21	)
Income tax expense		(1,238	)		—			(270	)
Results of operations	$	4,240		$	(2,486	)	$	902
Depreciation, depletion and amortization per Boe	$	9.83		$	9.90		$	11.72


	Oil (MMBbls)			Gas (Bcf) ⁽¹⁾			NGL (MMBbls)			Combined (MMBoe)
Proved developed and undeveloped reserves:
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
Revisions due to prices		55			382			36			155
Revisions other than price		(23	)		11			64			43
Extensions and discoveries		112			348			58			228
Purchase of reserves		393			961			110			663
Production		(106	)		(325	)		(48	)		(209	)
Sale of reserves		(4	)		(11	)		(1	)		(7	)
December 31, 2021		709			2,878			437			1,625

Proved developed reserves:
December 31, 2018		196			1,427			166			600
December 31, 2019		198			1,344			167			589
December 31, 2020		194			1,244			173			574
December 31, 2021		544			2,361			348			1,285
Proved developed-producing reserves:
December 31, 2018		188			1,394			162			582
December 31, 2019		191			1,327			165			578
December 31, 2020		190			1,223			171			564
December 31, 2021		533			2,316			341			1,260
Proved undeveloped reserves:
December 31, 2018		100			375			61			223
December 31, 2019		78			277			44			168
December 31, 2020		88			268			45			178
December 31, 2021		165			517			89			340

Reserves increased 155 MMBoe in 2021 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.

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.

2021 – Total revisions other than price (43 MMBoe) were primarily due to well performance exceeding previous estimates modestly across all areas of operation (53 MMBoe) and the removal of proved undeveloped locations as noted below (-10 MMBoe). The upward revisions were driven by the Delaware Basin (23 MMBoe), Williston Basin (12 MMBoe) and Anadarko Basin (12 MMBoe).

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 Anadarko Basin (22 MMBoe).

2019 – Total revisions other than price in 2019 were primarily due to changes in previously adopted development plans in 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 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.

2021 – Of the 228 MMBoe of additions from extensions and discoveries, 209 MMBoe were in the Delaware Basin, 8 MMBoe were in the Anadarko Basin, 6 MMBoe were in the Williston Basin, 3 MMBoe were in Eagle Ford and 2 MMBoe were in the Powder River Basin.

2020 – Of the 135 MMBoe of additions from extensions and discoveries, 117 MMBoe were in the Delaware Basin, 8 MMBoe were in the Anadarko Basin, 5 MMBoe were in the Powder River Basin and 5 MMBoe were 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 Anadarko Basin, 28 MMBoe were in the Powder River Basin and 18 MMBoe were in Eagle Ford. In 2019, there were no additions related to infill drilling activities.

During 2021, Devon had reserve additions due to the Merger of 538 MMBoe in the Delaware Basin and 125 MMBoe in the Williston Basin. For additional information on these asset additions, see Note 2.

During 2021, 2020 and 2019, 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 2021 (MMBoe).

Total proved undeveloped reserves increased 91% from 2020 to 2021 with the year-end 2021 balance representing 21% of total proved reserves. Approximately 92% of the 160 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 accounted for 85% of the 107 MMBoe of proved undeveloped reserves being converted to proved developed reserves in 2021. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $612 million for 2021. Additionally, 98% of the 90 MMBoe of purchased reserves relate to the complementary Delaware Basin assets acquired through the Merger. Purchase of reserves included in the table above reflect proved undeveloped reserves acquired in the Merger that remain undeveloped as of December 31, 2021. Proved undeveloped reserves revisions other than price were primarily due to well performance in the Delaware Basin (14 MMBoe) and Anadarko Basin (6 MMBoe) which was partially offset by changes in previously adopted development plans in the Anadarko Basin (-6 MMBoe) and Delaware Basin (-3 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 2021

estimates, Devon’s future realized prices were assumed to be $64.17 per Bbl of oil, $3.05 per Mcf of gas and $27.60 per Bbl of NGLs. Of the $3.7 billion of future development costs as of the end of 2021, $1.1 billion, $0.7 billion and $0.6 billion are estimated to be spent in 2022, 2023 and 2024, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $3.7 billion of future development costs are $0.5 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,
	2021			2020			2019
Beginning balance	$	3,472		$	5,398		$	7,150
Net changes in prices and production costs		8,274			(3,277	)		(2,323	)
Oil, gas and NGL sales, net of production costs		(7,400	)		(1,572	)		(2,612	)
Changes in estimated future development costs		(414	)		402			303
Extensions and discoveries, net of future development costs		3,877			988			1,690
Purchase of reserves		12,460			23			43
Sales of reserves in place		(12	)		(7	)		(481	)
Revisions of quantity estimates		838			147			(359	)
Previously estimated development costs incurred during the period		663			537			857
Accretion of discount		1,218			285			506
Net change in income taxes and other		(3,675	)		548			624
Ending balance	$	19,301		$	3,472		$	5,398