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 related to Devon’s discontinued operations. For additional information on these discontinued operations, see Note 19.

Acquisition costs for 2022 in the table above pertain primarily to the Eagle Ford and Willison Basin acquisitions which closed in the third quarter of 2022. Acquisition costs for 2021 primarily relate to the Merger. Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.

The following table includes revenues and expenses associated with Devon’s oil and gas producing activities. It does 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,
	2022			2021			2020
Oil, gas and NGL sales	$	14,082		$	9,531		$	2,695
Production expenses		(2,797	)		(2,131	)		(1,123	)
Exploration expenses		(29	)		(14	)		(167	)
Depreciation, depletion and amortization		(2,119	)		(2,050	)		(1,207	)
Asset dispositions		43			170			—
Asset impairments		—			—			(2,664	)
Accretion of asset retirement obligations		(25	)		(28	)		(20	)
Income tax expense		(2,041	)		(1,238	)		—
Results of operations	$	7,114		$	4,240		$	(2,486	)
Depreciation, depletion and amortization per Boe	$	9.52		$	9.83		$	9.90

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



	Oil (MMBbls)			Gas (Bcf) (1)			NGL (MMBbls)			Combined (MMBoe)
Proved developed and undeveloped reserves:
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
Revisions due to prices		15			61			8			34
Revisions other than price		(55	)		13			3			(49	)
Extensions and discoveries		127			449			76			278
Purchase of reserves		106			137			24			153
Production		(109	)		(356	)		(54	)		(223	)
Sale of reserves		—			(7	)		(1	)		(3	)
December 31, 2022		793			3,175			493			1,815

Proved developed reserves:
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
December 31, 2022		596			2,595			391			1,419
Proved developed-producing reserves:
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
December 31, 2022		585			2,553			387			1,397
Proved undeveloped reserves:
December 31, 2019		78			277			44			168
December 31, 2020		88			268			45			178
December 31, 2021		165			517			89			340
December 31, 2022		197			580			102			396

(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. NGL reserves are converted to Boe on a one-to-one basis with oil. The conversion rates are not necessarily indicative of the relationship of oil, natural gas and NGL prices.

Reserves increased 34 MMBoe in 2022 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.

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.

2022 – Total revisions other than price (-49 MMBoe) were driven by higher operating costs across all areas of operation and the revisions to proved undeveloped reserves noted below. These downward revisions were partially offset by upward revisions due to well performance exceeding previous estimates primarily in the Delaware Basin. In total, after accounting for these compensating factors, we recorded negative revisions across each of our operating areas with the most significant changes being located in the Delaware Basin (-33 MMBoe), followed by the Powder River Basin (-5 MMBoe) and the Anadarko Basin (-4 MMBoe).

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).

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.

2022 – Of the 278 MMBoe of additions from extensions and discoveries, 255 MMBoe were in the Delaware Basin, 7 MMBoe were in the Powder River Basin, 6 MMBoe were in Eagle Ford, 5 MMBoe were in the Anadarko Basin and 5 MMBoe were in the Williston Basin.

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.

During 2022, Devon had reserve additions due to the acquisitions of 66 MMBoe in the Williston Basin and 87 MMBoe in the Eagle Ford. For additional information on these asset additions, see Note 2.

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 2022, 2021 and 2020, 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 2022 (MMBoe).

Total proved undeveloped reserves increased 16% from 2021 to 2022 with the year-end 2022 balance representing 22% of total proved reserves. Approximately 97% of the 176 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 more than 80% of the 127 MMBoe of proved undeveloped reserves being converted to proved developed reserves in 2022. Costs incurred in 2022 to develop and convert Devon’s proved undeveloped reserves were approximately $866 million. Of the 44 MMBoe of purchased reserves, 51% relate to the Williston Basin and 49% to the Eagle Ford. Proved undeveloped reserves revisions other than price (-39 MMBoe) were due to changes in previously adopted development plans (-22 MMBoe) in the Delaware Basin (-9 MMBoe), Anadarko Basin (-7 MMBoe) and Powder River Basin (-6 MMBoe), combined with additional downward revisions (-17 MMBoe) caused by both continued evaluation of well performance and higher operating costs.

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 2022 estimates, Devon’s future realized prices were assumed to be $93.53 per Bbl of oil, $5.41 per Mcf of gas and $34.58

per Bbl of NGLs. Of the $5.2 billion of future development costs as of the end of 2022, $1.7 billion, $1.2 billion and $0.7 billion are estimated to be spent in 2023, 2024 and 2025, 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 $0.8 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,
	2022			2021			2020
Beginning balance	$	19,301		$	3,472		$	5,398
Net changes in prices and production costs		14,081			8,274			(3,277	)
Oil, gas and NGL sales, net of production costs		(11,285	)		(7,400	)		(1,572	)
Changes in estimated future development costs		(216	)		(414	)		402
Extensions and discoveries, net of future development costs		7,279			3,877			988
Purchase of reserves		4,185			12,460			23
Sales of reserves in place		(20	)		(12	)		(7	)
Revisions of quantity estimates		(874	)		838			147
Previously estimated development costs incurred during the period		956			663			537
Accretion of discount		2,059			1,218			285
Net change in income taxes and other		(4,152	)		(3,675	)		548
Ending balance	$	31,314		$	19,301		$	3,472