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.

Acquisition costs for 2022 in the table above pertain primarily to the Eagle Ford and Williston 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, is not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated using statutory income tax rates, and then giving effect to permanent differences associated with oil and gas producing activities.


	Year Ended December 31,
	2023			2022			2021
Oil, gas and NGL sales	$	10,791		$	14,082		$	9,531
Production expenses		(2,928	)		(2,797	)		(2,131	)
Exploration expenses		(20	)		(29	)		(14	)
Depreciation, depletion and amortization		(2,464	)		(2,119	)		(2,050	)
Asset dispositions		(33	)		43			170
Accretion of asset retirement obligations		(29	)		(25	)		(28	)
Income tax expense		(1,044	)		(2,041	)		(1,238	)
Results of operations	$	4,273		$	7,114		$	4,240
Depreciation, depletion and amortization per Boe	$	10.27		$	9.52		$	9.83

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, 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
Revisions due to prices		(25	)		(189	)		(22	)		(78	)
Revisions other than price		(12	)		58			1			(1	)
Extensions and discoveries		147			525			87			322
Production		(117	)		(385	)		(59	)		(240	)
Sale of reserves		—			(2	)		—			(1	)
December 31, 2023		786			3,182			500			1,817

Proved developed reserves:
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
December 31, 2023		603			2,560			395			1,425
Proved developed-producing reserves:
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
December 31, 2023		586			2,505			386			1,390
Proved undeveloped reserves:
December 31, 2020		88			268			45			178
December 31, 2021		165			517			89			340
December 31, 2022		197			580			102			396
December 31, 2023		183			622			105			392

(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 decreased 78 MMBoe in 2023 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs.

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.

2023 – Total revisions other than price (-1 MMBoe) are the result of upward revisions due to well performance exceeding previous estimates on developed properties (11 MMBoe), which were offset by downward revisions to proved undeveloped reserves (-12 MMBoe) as noted below. In total, we recorded modest upward revisions in the Delaware Basin (7 MMboe), Eagle Ford (5 MMBoe), Anadarko Basin (4 MMBoe) and Powder River Basin (2 MMBoe) which were offset by downward revisions in the Williston Basin (-19 MMboe) due to reduced well performance compared to previous estimates.

2022 – Total revisions other than price (-49 MMBoe) were driven by higher operating costs across all areas of operation and revisions to proved undeveloped reserves. 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 (-10 MMBoe). The upward revisions were driven by the Delaware Basin (23 MMBoe), Williston Basin (12 MMBoe) and Anadarko Basin (12 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.

2023 – Of the 322 MMBoe of additions from extensions and discoveries, 212 MMBoe were in the Delaware Basin, 33 MMBoe were in the Anadarko Basin, 32 MMBoe were in Eagle Ford, 26 MMBoe were in the Powder River Basin and 19 MMBoe were in the Williston Basin.

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.

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 2021, 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 2023 (MMBoe).

Total proved undeveloped reserves decreased 1% from 2022 to 2023 with the year-end 2023 balance representing 22% of total proved reserves. Approximately 59% of the 177 MMBoe in extensions and discoveries were the result of Devon’s drilling and development activities in the Delaware Basin, followed by the Anadarko Basin (14%), Eagle Ford (12%), Powder River Basin (11%) and Williston Basin (4%). Development in the Delaware Basin accounted for approximately 78% of the 165 MMBoe of proved undeveloped reserves being converted to proved developed reserves in 2023. Costs incurred in 2023 to develop and convert Devon’s proved undeveloped reserves were approximately $1.5 billion. Proved undeveloped reserves revisions other than price (-12 MMBoe) were due to changes in previously adopted development plans (-8 MMBoe) in the Williston Basin (-5 MMBoe), Delaware Basin (-2 MMBoe) and Powder River Basin (-1 MMBoe), combined with modest downward revisions (-4 MMBoe) caused by continued evaluation of well performance in the Delaware Basin (-2 MMBoe), Williston Basin (-1 MMBoe) and Eagle Ford (-1 MMBoe).

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 2023 estimates, Devon’s future realized prices were assumed to be $76.29 per Bbl of oil, $1.74 per Mcf of gas and $20.43 per Bbl of NGLs. Of the $5.2 billion of future development costs as of the end of 2023, $1.8 billion, $1.0 billion and $0.8 billion are estimated to be spent in 2024, 2025 and 2026, 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 $0.9 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,
	2023			2022			2021
Beginning balance	$	31,314		$	19,301		$	3,472
Net changes in prices and production costs		(16,797	)		14,081			8,274
Oil, gas and NGL sales, net of production costs		(7,863	)		(11,285	)		(7,400	)
Changes in estimated future development costs		218			(216	)		(414	)
Extensions and discoveries, net of future development costs		5,222			7,279			3,877
Purchase of reserves		—			4,185			12,460
Sales of reserves in place		(9	)		(20	)		(12	)
Revisions of quantity estimates		(747	)		(874	)		838
Previously estimated development costs incurred during the period		1,567			956			663
Accretion of discount		2,972			2,059			1,218
Net change in income taxes and other		3,436			(4,152	)		(3,675	)
Ending balance	$	19,313		$	31,314		$	19,301