Common stock, par value (in dollars per share)

^[1]

$ 1,503

$ 1,539

$ 0.1

Common stock, shares authorized (in shares)

1,000.0

Treasury stock common shares

0.3

Common stock, shares issued (in shares)

636.0

653.0

CDM [Member]

Summary Of Significant Accounting Policies

$ 136

$ 109

[1]	$136 million and $109 million related to CDM in 2023 and 2022, respectively.

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net earnings	$ 3,782	$ 6,037	$ 2,833
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation, depletion and amortization	2,554	2,223	2,158
Leasehold impairments	5	12	4
Amortization of liabilities	(16)	(31)	(27)
Total (gains) losses on commodity derivatives	(118)	658	1,544
Cash settlements on commodity derivatives	47	(1,356)	(1,462)
Gains on asset dispositions	(30)	(44)	(168)
Deferred income tax expense	376	1,179	49
Share-based compensation	93	88	99
Early retirement of debt	0	0	(30)
Other	(5)	(10)	15
Changes in assets and liabilities, net	(144)	(226)	(116)
Net cash from operating activities	6,544	8,530	4,899
Cash flows from investing activities:
Capital expenditures	(3,883)	(2,542)	(1,989)
Acquisitions of property and equipment	(64)	(2,583)	(18)
Divestitures of property and equipment	26	39	79
WPX acquired cash	0	0	344
Distributions from investments	32	39	35
Contributions to investments and other	(53)	(76)	(25)
Net cash from investing activities	(3,942)	(5,123)	(1,574)
Cash flows from financing activities:
Repayments of long-term debt	(242)	0	(1,243)
Early retirement of debt	0	0	(59)
Repurchases of common stock	(979)	(718)	(589)
Dividends paid on common stock	(1,858)	(3,379)	(1,315)
Contributions from noncontrolling interests	37	0	4
Distributions to noncontrolling interests	(45)	(30)	(21)
Acquisition of noncontrolling interests	0	0	(24)
Shares exchanged for tax withholdings and other	(97)	(86)	(45)
Net cash from financing activities	(3,184)	(4,213)	(3,292)
Effect of exchange rate changes on cash	3	(11)	1
Net change in cash, cash equivalents and restricted cash	(579)	(817)	34
Cash, cash equivalents and restricted cash at beginning of period	1,454	2,271	2,237
Cash, cash equivalents and restricted cash at end of period	875	1,454	2,271
Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	853	1,314	2,099
Restricted cash	22	140	172
Total cash, cash equivalents and restricted cash	$ 875	$ 1,454	$ 2,271

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earning [Member]	Other Comprehensive Earnings (Loss) [Member]	Treasury Stock, Common [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2020	$ 3,019	$ 38	$ 2,766	$ 208	$ (127)		$ 134
Balance, shares at Dec. 31, 2020		382
Net earnings	2,833			2,813			20
Other comprehensive earnings (loss), net of tax	(5)				(5)
Restricted stock grants, net of cancellations, shares		6
Common stock repurchased	(633)					$ (633)
Common stock retired		$ (1)	(632)			633
Common stock retired, shares		(16)
Common stock dividends	(1,329)			(1,329)
Common stock issued	5,432	$ 29	5,403
Common stock issued, Shares		290
Share-based compensation	99		99
Share-based compensation, shares		1
Contributions from noncontrolling interests	3						3
Distributions to noncontrolling interests	(20)						(20)
Balance at Dec. 31, 2021	9,399	$ 66	7,636	1,692	(132)		137
Balance, shares at Dec. 31, 2021		663
Net earnings	6,037			6,015			22
Other comprehensive earnings (loss), net of tax	16				16
Restricted stock grants, net of cancellations, value	4	$ 1	3
Restricted stock grants, net of cancellations, shares		2
Common stock repurchased	(808)					(808)
Common stock retired		$ (2)	(806)			808
Common stock retired, shares		(13)
Common stock dividends	(3,410)			(3,410)
Share-based compensation	88		88
Share-based compensation, shares		1
Distributions to noncontrolling interests	(30)						(30)
Balance at Dec. 31, 2022	11,296	$ 65	6,921	4,297	(116)		129
Balance, shares at Dec. 31, 2022		653
Net earnings	3,782			3,747			35
Other comprehensive earnings (loss), net of tax	(8)				(8)
Restricted stock grants, net of cancellations, shares		2
Common stock repurchased	(1,089)		(8)			(1,081)
Common stock retired		$ (1)	(1,067)			1,068
Common stock retired, shares		(20)
Common stock dividends	(1,849)			(1,849)
Share-based compensation	93		93
Share-based compensation, shares		1
Contributions from noncontrolling interests	37						37
Distributions to noncontrolling interests	(45)						(45)
Balance at Dec. 31, 2023	$ 12,217	$ 64	$ 5,939	$ 6,195	$ (124)	$ (13)	$ 156
Balance, shares at Dec. 31, 2023		636

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Devon, entities in which it holds a controlling interest and VIEs for which Devon is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments in non-controlled entities over which Devon does not have the ability to exercise significant influence are initially recognized at cost and subsequently adjusted for contributions and distributions.

Variable Interest Entity

In 2019, Devon and an affiliate of QL Capital Partners, LP (“QLCP”) formed CDM, a joint venture in the Delaware Basin. Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon.

Devon, through its controlling interest in CDM, has the power to direct the activities that significantly affect the economic performance of CDM and the obligation to absorb losses or the right to receive benefits that could be significant to CDM; therefore, Devon is considered the primary beneficiary and consolidates CDM. CDM maintains its own capital structure that is separate from Devon. During 2023, 2022 and 2021, QLCP distributions from CDM were approximately $45 million, $30 million and $20 million, respectively. During 2023 and 2021 QLCP contributions to CDM were approximately $37 million and $3 million, respectively.

The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in and disclosed parenthetically, if material, on Devon's consolidated balance sheets.

Investments

Devon has an interest in Catalyst, which is a joint venture established among WPX, an affiliate of Howard Energy Partners, LLC (“HEP”) and certain other investors, to develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the arrangement, Devon and a holding company owned by the other joint venture investors each have a 50% voting interest in the joint venture legal entity, and HEP serves as the operator. Through 2038, Devon’s production from 50,000 net acres in the Stateline area of the Delaware Basin has been dedicated to Catalyst subject to fixed-fee oil gathering and natural gas processing agreements. Devon accounts for the investment in Catalyst as an equity method investment. Devon's share of the

earnings are reflected as a component of other, net in the accompanying consolidated statements of comprehensive earnings.

In the second quarter of 2023, Devon made an investment in the Water JV, a joint venture entity formed with an affiliate of WaterBridge NDB LLC (“WaterBridge”), for the purpose of providing increased capacity and flexibility in disposing of produced water in the Delaware Basin and Eagle Ford. Under terms of the arrangement, Devon contributed water infrastructure assets and committed to a water gathering and disposal dedication to the Water JV through 2038, in exchange for a 30% voting interest in the joint venture legal entity. WaterBridge contributed water infrastructure assets to the Water JV, in exchange for a 70% voting interest in the joint venture legal entity and is serving as the operator. At closing of the Water JV, Devon recognized a $64 million gain in asset dispositions in the consolidated statements of comprehensive earnings, which represented the excess of the estimated fair value of Devon's interest in the Water JV over the carrying value of the water infrastructure assets Devon contributed to the Water JV. Devon accounts for the investment in the Water JV as an equity method investment. Devon's investment in the Water JV is shown within investments on the consolidated balance sheets and Devon's share of the Water JV earnings are reflected as a component of other, net in the accompanying consolidated statements of comprehensive earnings.

During 2023 and 2022, Devon made investments in Matterhorn. Matterhorn is a joint venture entity and was formed for the purpose of constructing a natural gas pipeline that will transport natural gas from the Permian Basin to the Katy, Texas area. Devon’s investment in Matterhorn does not give it the ability to exercise significant influence over Matterhorn.

Devon has other investments largely focused on midstream, new technologies and energy transition initiatives. Devon does not have the ability to exercise significant influence over these investments. The following table presents Devon's investments that are shown on the consolidated balance sheet.


		Carrying Amount
Investments	% Interest	December 31, 2023		December 31, 2022
Catalyst	50%	$	311	$	339
Water JV	30%		216		—
Matterhorn	12.5%		90		54
Other	Various		49		47
Total		$	666	$	440

As of December 31, 2023, Devon’s $311 million investment in Catalyst exceeded the underlying equity in net assets by approximately $112 million. The basis difference results primarily from intangible assets associated with Devon’s acreage dedication and is amortized over the remaining 14-year term of the associated oil gathering and natural gas processing agreements. As of December 31, 2023, Devon's $216 million investment in the Water JV exceeded the underlying equity in net assets by approximately $27 million. The basis difference results primarily from acreage dedicated to the Water JV's water systems and services and is amortized over the remaining 14-year term of those water system services.

Devon's investments provided certain gathering, processing and marketing services to Devon in the ordinary course of business. The impact from these services on Devon’s consolidated statement of comprehensive earnings and consolidated balance sheet for the years ended and as of December 31, 2023 and 2022, respectively, relate primarily to Catalyst and are summarized below.


	Year ended December 31,
	2023		2022		2021
Oil, gas and NGL sales	$	213	$	405	$	264
Production expenses	$	93	$	55	$	42
Accounts receivable	$	11	$	14	$	22

In February 2024, Devon committed to invest approximately $90 million in a geothermal technology company and expects to fund the commitment throughout 2024.

Segment Information

Devon’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of these operations.

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

proved reserves and related present value of future net revenues;

•

evaluation of suspended well costs;

•

the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories;

•

derivative financial instruments;

•

the fair value of reporting units and related assessment of goodwill for impairment;

•

income taxes;

•

asset retirement obligations;

•

obligations related to employee pension and postretirement benefits;

•

legal and environmental risks and exposures;

•

the fair value of contingent earnout payments; and

•

general credit risk associated with receivables and other assets.

Revenue Recognition

Upstream Revenues

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract-specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of comprehensive earnings.

Devon acts as a principal in sales transactions when control of the product is retained prior to delivery to the ultimate third-party customer or acts as an agent when services are rendered on behalf of the principal in the transactions. A control-based assessment is performed to identify whether Devon is a principal or an agent in the transaction, which determines whether revenue and the related expenses are presented on a gross or net basis, respectively.

Oil sales

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point where the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Natural gas and NGL sales

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated statements of comprehensive earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Marketing Revenues

Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract-specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

Midstream Revenues

Devon’s reported midstream revenue primarily relates to its interest in CDM. CDM provides gathering, compression and dehydration services to Devon and other producers’ natural gas production. An evaluation is performed to determine whether CDM is a principal or agent in these transactions. Under the terms of these gathering, compression and dehydration contracts, CDM has concluded it is the agent as title to the gas production remains with the CDM affiliate producer or a third-party producer. Revenue is recognized on a net basis since CDM is strictly providing a service. Costs to maintain CDM’s assets are presented as marketing and midstream expenses in the consolidated statements of comprehensive earnings. Revenue is recognized for sales at the time the gathering, compression and dehydration service has been rendered or performed.

Satisfaction of Performance Obligations and Revenue Recognition

Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2023. Devon’s product sales and marketing contracts do not give rise to contract assets.

Disaggregation of Revenue

The following table presents revenue from contracts with customers that are disaggregated based on the type of good.


	Year Ended December 31,
	2023		2022		2021
Oil	$	8,879	$	10,281	$	6,996
Gas		703		1,948		1,104
NGL		1,209		1,853		1,431
Oil, gas and NGL sales		10,791		14,082		9,531

Oil		3,018		3,305		2,451
Gas		572		1,163		718
NGL		759		1,277		1,050
Marketing and midstream revenues		4,349		5,745		4,219
Total revenues from contracts with customers	$	15,140	$	19,827	$	13,750

Customers

For the year ended December 31, 2023, sales to two customers accounted for approximately 14% and 10% of Devon's sales revenue. For the year ended December 31, 2022, sales to one customer accounted for approximately 15% of Devon's sales revenue. For the year ended December 31, 2021 sales to two customers accounted for approximately 19% and 12% of Devon's sales revenue.

If any one of Devon’s major customers were to stop purchasing our production, the Company believes there are a number of other purchasers to whom the company could sell Devon’s production. If multiple significant customers were to discontinue purchasing Devon’s production abruptly, the Company believes it would have the resources needed to access alternative customers or markets and avoid or materially mitigate associated sales disruptions.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices and interest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2023, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2023, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties. Given Devon's current credit ratings and the terms of the underlying contracts, Devon is not currently required to post collateral to its counterparties with respect to its open derivative positions, and would not be required to post any such collateral as a result of any change to the amount of Devon's net liability for such positions.

General and Administrative Expenses

G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon.

Share-Based Compensation

Devon grants share-based awards to members of its Board of Directors, management and employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated statements of comprehensive earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 5, certain share-based awards were accelerated and recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is significant negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.

Net Earnings Per Share Attributable to Devon

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Devon applies the two-class method to stock awards deemed to be participating securities. The two-class method requires allocating net earnings to both common shares and participating securities based on their respective rights to receive dividends. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of unvested restricted stock awards and unvested performance share units.

Cash, Cash Equivalents and Restricted Cash

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Devon also considers cash balances subject to legal and contractual restrictions as restricted cash. As of December 31, 2022 and 2021, Devon's restricted cash also included $120 million and $160 million, respectively, associated with retained obligations related to previously disposed assets. As of December 31, 2023, the cash balances associated with these obligations are no longer considered restricted cash.

Accounts Receivable

Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables. Devon does not require collateral security for joint interest receivables.

Devon records an allowance for credit losses based on a forward-looking “expected loss” model. Credit risk is assessed by class of account type, which includes cash equivalents and oil and gas, marketing and midstream, joint interest and other accounts receivable. These classes are further evaluated using a probability-weighted scenario assessment based on historical losses and a probability of future default. This evaluation is supported by an assessment of risk factors such as the age of the receivable, current macro-economic conditions, credit rating of the counterparty and our historical loss rate.

Inventory

Devon’s inventories primarily consist of oil and NGL inventory and equipment inventory. Oil and NGL inventory are recorded at weighted average cost and carried at the lower of cost or net realizable value. Equipment inventory is valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

Property and Equipment

Oil and Gas Property and Equipment

Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.

Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.

Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually.

Proved properties are assessed for impairment when events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying statements of comprehensive earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

Devon capitalizes interest costs incurred that are attributable to material unproved oil and gas properties and major development projects of oil and gas properties.

Other Property and Equipment

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major corporate construction projects are also capitalized.

Asset Retirement Obligations

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet unless the associated asset has already been disposed. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Leases

Devon establishes right-of-use assets and lease liabilities on the balance sheet for all leases with a term longer than 12 months. Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of the reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. The fair value of the reporting unit is estimated based upon market capitalization, comparable transactions of similar companies and premiums paid.

Devon performed impairment tests of goodwill in the fourth quarters of 2023, 2022 and 2021. No impairment was required as a result of the annual tests in these time periods.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

•

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

•

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

•

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Noncontrolling Interests

Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.

Recently Issued Accounting Standards Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures. ASU 2023-09 intends to provide investors with enhanced information about an entity’s income taxes by requiring disclosure of items such as disaggregation of the effective tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective for annual reporting periods beginning after December 15, 2024, with early adoption permitted for annual financial statements that have not yet been issued. Devon is evaluating the impact this ASU will have on the disclosures that accompany its consolidated financial statements.

In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures. Under this ASU, the scope and frequency of segment disclosures is increased to provide investors with additional detail about information utilized by an entity’s “Chief Operating Decision Maker.” This ASU is effective for Devon beginning with our 2024 annual reporting and interim periods beginning in 2025. Devon is evaluating the impact this ASU will have on the disclosures that accompany its consolidated financial statements.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2023

Business Combinations [Abstract]

Acquisition and Divestitures

Acquisitions and Divestitures

WPX Merger

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX was an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock were issued in the Merger, and holders of WPX common stock instead received cash in lieu of fractional shares of Devon common stock, if any. Based on the closing price of Devon’s common stock on January 7, 2021, the total value of Devon common stock issued to holders of WPX common stock as part of this transaction was approximately $5.4 billion. The Merger was structured as a tax-free reorganization for U.S. federal income tax purposes.

Acquisitions

In the third quarter of 2022, Devon completed its acquisition of producing properties and leasehold interests located in the Eagle Ford and Williston Basin for cash consideration of approximately $1.7 billion and $830 million, respectively, net of purchase price adjustments. The total estimated proved reserves associated with these Eagle Ford and Williston Basin assets were approximately 87 MMBoe and 66 MMBoe, respectively. Each of these acquisitions were accounted for as asset acquisitions as substantially all of the fair value was concentrated in a group of similar assets. Each of the acquisitions resulted in the purchase of producing properties and leasehold interests in a defined geographical and geological area, and substantially all of the assets have similar risk characteristics.

Contingent Earnout Payments

Devon is entitled to contingent earnout payments associated with the sale of its Barnett Shale assets in 2020 with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commenced on January 1, 2021 and has a term of four years. Devon received $20 million in contingent earnout payments related to this transaction in the first quarter of 2024 and $65 million in the first quarter of 2023 and 2022. Devon could also receive up to an additional $65 million in contingent earnout payments for the remaining performance period depending on future commodity prices. The valuation of the future contingent earnout payment included within other current assets and other long-term assets in the December 31, 2023 consolidated balance sheet was approximately $20 million and $35 million, respectively. These values were derived utilizing a Monte Carlo valuation model and qualify as a level 3 fair value measurement.

Devon also received $4 million in contingent earnout payments in the first quarter of 2023 and 2022 related to the sale of non-core assets in the Rockies. Devon completed the sale of these non-core assets in 2021 for proceeds of $9 million, net of purchase price adjustments, and recognized a $35 million gain related to the sale.

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2023, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.


	Price Swaps				Price Collars
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q1-Q4 2024		27,486	$	77.74		60,238	$	65.71	$	84.89


	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q1-Q4 2024	Midland Sweet		62,500	$	1.17
Q1-Q4 2024	NYMEX Roll		26,000	$	0.82
Q1-Q4 2025	Midland Sweet		53,000	$	0.97

As of December 31, 2023, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.


	Price Swaps				Price Collars
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q1-Q4 2024		187,426	$	3.30		40,527	$	3.78	$	7.05
Q1-Q4 2025		32,904	$	3.22		—	$	—	$	—


	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q1-Q4 2024	El Paso Natural Gas		34,863	$	(0.91	)
Q1-Q4 2024	Houston Ship Channel		110,000	$	(0.24	)
Q1-Q4 2024	WAHA		44,973	$	(0.58	)

As of December 31, 2023, Devon had the following open NGL derivative positions. Devon's NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.


		Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q1-Q4 2024	Natural Gasoline		3,000	$	69.11
Q1-Q4 2024	Normal Butane		3,350	$	37.58
Q1-Q4 2024	Propane		3,000	$	32.20

Financial Statement Presentation

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the consolidated balance sheets. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets. The table below presents a summary of these positions as of December 31, 2023 and 2022.


	December 31, 2023									December 31, 2022
	Gross Fair Value			Amounts Netted			Net Fair Value			Gross Fair Value			Amounts Netted			Net Fair Value			Balance Sheet Classification
Commodity derivatives:
Short-term derivative asset	$	213		$	(5	)	$	208		$	138		$	(19	)	$	119		Other current assets
Long-term derivative asset		—			—			—			12			—			12		Other long-term assets
Short-term derivative liability		(7	)		5			(2	)		(22	)		19			(3	)	Other current liabilities
Long-term derivative liability		(7	)		—			(7	)		—			—			—		Other long-term liabilities
Total derivative asset	$	199		$	—		$	199		$	128		$	—		$	128

Share-Based Compensation

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation

In 2022, Devon's stockholders approved the 2022 Plan, which replaced the 2017 Plan. From the effective date of the 2022 Plan, no further awards may be made under the 2017 Plan; however, awards previously granted will continue to be governed by the terms of the respective award documents. The 2022 Plan authorizes the grant of nonqualified and incentive stock options, restricted stock awards or units and stock appreciation rights to eligible employees. Restricted stock awards or restricted stock units granted under the 2022 Plan may be subject to performance-based conditions. The 2022 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2022 Plan, options and stock appreciation rights represent one share and other awards represent 1.74 shares.

The vesting for certain share-based awards was accelerated in 2021 in conjunction with the reduction of workforce activities described in Note 5 and is included in restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

The table below presents the share-based compensation expense included in Devon’s accompanying consolidated statements of comprehensive earnings.


	Year Ended December 31,
	2023		2022		2021
G&A	$	92	$	87	$	77
Exploration expenses		1		1		1
Restructuring and transaction costs		—		—		21
Total	$	93	$	88	$	99
Related income tax benefit	$	34	$	34	$	13

The following table presents a summary of Devon’s unvested restricted stock awards and units and performance share units granted under the plans.


	Restricted Stock Awards & Units					Performance Share Units
	Awards/Units			Weighted Average Grant-Date Fair Value		Units				Weighted Average Grant-Date Fair Value
	(Thousands, except fair value data)
Unvested at 12/31/22		5,788		$	29.11		1,841			$	31.33
Granted		1,298		$	62.24		743		(1)	$	51.38
Vested		(2,926	)	$	25.25		(1,037	)		$	27.89
Forfeited		(127	)	$	43.89		—			$	—
Unvested at 12/31/23		4,033		$	42.10		1,547		(2)	$	43.25

(1)

These grants also include the impact of performance share units granted in prior year that vested higher than 100% target due to Devon's TSR performance compared to applicable peers.

(2)

A maximum of 3.1 million common shares could be awarded based upon Devon’s final TSR ranking.

The following table presents the aggregate fair value of awards and units that vested during the indicated period.


	2023		2022		2021
Restricted Stock Awards and Units	$	172	$	180	$	115
Performance-Based Restricted Stock Awards	$	—	$	—	$	1
Performance Share Units	$	66	$	62	$	15

The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2023.


	Restricted Stock		Performance
	Awards/Units		Share Units
Unrecognized compensation cost	$	93	$	18
Weighted average period for recognition (years)		2.5		1.7

Restricted Stock Awards and Units

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from one to four years. Dividends declared during the vesting period with respect to restricted stock awards and units will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period.

Performance Share Units

Performance share units are granted to certain members of Devon’s management and employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of peer companies over the specified three-year performance period. Subject to certain limits, the vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group as of the end of the performance period.

At vesting, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.


	2023			2022			2021
Grant-date fair value	$	81.70		$	68.68		$	18.08
Risk-free interest rate		4.15	%		1.81	%		0.18	%
Volatility factor		61.43	%		70.1	%		67.8	%
Contractual term (years)		2.89			2.89			2.89

Restructuring and Transaction Costs

12 Months Ended

Dec. 31, 2023

Restructuring and Related Activities [Abstract]

Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring and transaction costs.


	Year Ended December 31,
	2023		2022		2021
Restructuring costs	$	—	$	—	$	210
Transaction costs		—		—		48
Total costs	$	—	$	—	$	258

In conjunction with the Merger closing, Devon recognized $210 million of restructuring expense in 2021 related to employee severance and termination benefits, settlements and curtailments from defined retirement benefits and contract terminations. Of these expenses, $66 million related to non-cash charges which primarily consisted of settlements and curtailments of defined retirement benefits of $41 million and the accelerated vesting of share-based grants of $21 million. Additionally, in conjunction primarily with the Merger closing, Devon recognized $48 million of transaction costs primarily comprised of bank, legal and accounting fees.

The following table summarizes Devon’s restructuring liabilities. The remaining restructuring liability as of December 31, 2023 primarily relates to obligations associated with an abandoned Canadian firm transportation agreement.


	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
Balance as of December 31, 2021	$	38		$	111		$	149
Changes related to prior years' restructurings		(4	)		(30	)		(34	)
Balance as of December 31, 2022	$	34		$	81		$	115
Changes related to prior years' restructurings		(21	)		(9	)		(30	)
Balance as of December 31, 2023	$	13		$	72		$	85

Other, Net

12 Months Ended

Dec. 31, 2023

Other Expenses [Abstract]

Other, Net

6.

Other, Net

The following table summarizes Devon’s other expenses (income) presented in the accompanying consolidated comprehensive statements of earnings.


	Year Ended December 31,
	2023		2022			2021
Estimated future obligation under a performance guarantee	$	—	$	(144	)	$	(18	)
Ukraine charitable pledge		—		20			—
Asset retirement obligation accretion		29		25			28
Severance and other non-income tax refunds		—		(5	)		(39	)
Other		9		9			(14	)
Total	$	38	$	(95	)	$	(43	)

Devon has guaranteed performance through 2026 for a minimum volume commitment associated with assets divested in 2018. Due to improved commodity prices, market conditions, and performance by the purchaser of the assets, the purchaser was able to fully satisfy the performance obligation due in 2023 and 2022, as well as reimburse Devon for shortfall payments previously made on the purchasers’ behalf in 2021 and 2020. Additionally, at March 31, 2022, Devon reduced the estimated future exposure of the performance guarantee. The effect of these cash collections and liability revisions resulted in a $144 million benefit in 2022.

During 2022, Devon paid approximately $20 million for humanitarian relief for the Ukrainian people and surrounding countries supporting refugees.

During 2022 and 2021, Devon received severance and other non-income tax refunds of $5 million and $39 million, respectively, related to prior periods.

Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

7.

Income Taxes

Income Tax Expense

The following table presents Devon’s income tax components.


	Year Ended December 31,
	2023			2022			2021
Current income tax expense (benefit):
U.S. federal	$	441		$	501		$	10
Various states		27			65			9
Canada		(3	)		(7	)		(3	)
Total current income tax expense		465			559			16
Deferred income tax expense:
U.S. federal		365			1,090			18
Various states		11			82			22
Canada		—			7			9
Total deferred income tax expense		376			1,179			49
Total income tax expense	$	841		$	1,738		$	65

Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:


	Year Ended December 31,
	2023			2022			2021
Earnings before income taxes	$	4,623		$	7,775		$	2,898

U.S. statutory income tax rate		21	%		21	%		21	%
State income taxes		1	%		1	%		1	%
Income tax credits		(3	%)		0	%		0	%
Other		(1	%)		0	%		2	%
Deferred tax asset valuation allowance		0	%		0	%		(22	%)
Effective income tax rate		18	%		22	%		2	%

2023

In 2023, Devon recognized income tax credits associated with its qualified research activities. This includes actual credits generated in the 2018-2022 tax years as well as estimated credits for the 2023 tax year.

2021

Prior to 2021, Devon maintained a valuation allowance against all U.S. federal deferred tax assets. Devon recognized approximately $250 million of deferred tax liabilities to account for the Merger. The recognition of these deferred tax liabilities caused a decrease to Devon’s net deferred tax assets and a corresponding decrease to the valuation allowance Devon had recognized on its U.S. federal deferred tax assets.

Due to significant increases in commodity pricing and projections of future income, in the fourth quarter of 2021, Devon reassessed its evaluation of the realizability of deferred tax assets in future years and determined that a U.S. federal valuation allowance was no longer necessary. As such, Devon removed its remaining $84 million U.S. federal valuation allowance.

Deferred Tax Assets and Liabilities

The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities.


	December 31,
	2023			2022
Deferred tax assets:
Capital loss carryforwards	$	542		$	523
Net operating loss carryforwards		447			526
Accrued liabilities		194			209
Asset retirement obligation		148			119
Other, including tax credits		25			14
Total deferred tax assets before valuation allowance		1,356			1,391
Less: valuation allowance		(826	)		(814	)
Net deferred tax assets		530			577
Deferred tax liabilities:
Property and equipment		(2,304	)		(1,969	)
Fair value of derivative financial instruments		(50	)		(33	)
Other		(14	)		(38	)
Total deferred tax liabilities		(2,368	)		(2,040	)
Net deferred tax liability	$	(1,838	)	$	(1,463	)

At December 31, 2023, Devon has recognized $447 million of deferred tax assets related to various net operating loss carryforwards available to offset future taxable income. Devon has $139 million of U.S. federal net operating loss carryforwards, of which $117 million expires between 2030 and 2036, and $22 million does not expire. Devon has $5 million of Canadian net operating loss carryforwards, all of which are covered by a valuation allowance. Devon also has $303 million of state net operating loss carryforwards primarily expiring between 2024 and 2040, $264 million of which are covered by a valuation allowance.

Devon’s remaining $139 million U.S. federal net operating losses were acquired from WPX as a result of the Merger. These net operating losses are subject to limitation pursuant to Section 382 of the Internal Revenue Code of 1986, which relates to limitations upon the 50% or greater change of ownership of an entity during any three-year period. The Company anticipates utilizing these net operating losses prior to their expiration.

Devon's remaining Canadian deferred tax assets of $557 million, primarily made up of $542 million of capital losses, are fully covered by a valuation allowance.

Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.


	December 31,
	2023		2022
	(Millions)
Balance at beginning of year	$	73	$	36
Tax positions taken in prior periods		10		51
Settlements		—		(14	)
Balance at end of year	$	83	$	73

Devon's 2023 unrecognized tax benefit balance includes $4 million of interest. At December 31, 2023 and December 31, 2022, there were $83 million and $73 million, respectively, of current unrecognized tax benefits that if recognized would affect the annual effective tax rate. Deferred unrecognized tax benefits of $42 million at December 31, 2021 are not included in the table above but are accounted for in Devon’s deferred tax disclosure above. Due to utilization of tax attributes in 2022, $42 million of Devon’s deferred unrecognized tax benefits were reclassified as current unrecognized tax benefits.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.


Jurisdiction		Tax Years Open
U.S. federal		2015-2023
Various U.S. states		2019-2023
Canada		2006-2023

Certain statute of limitation expirations are scheduled to occur in the next twelve months. Devon is currently in various stages of the audit and administrative review process for certain open tax years.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

Other Comprehensive Income (Loss), Net of Tax [Abstract]

Net Earnings Per Share

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Net Earnings Per Share

The following table reconciles net earnings available to common shareholders and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings per share.


	Year Ended December 31,
	2023		2022		2021
Net earnings available to common shareholders - basic and diluted	$	3,747	$	5,958	$	2,783
Common shares:
Average common shares outstanding - basic		639		651		663
Dilutive effect of potential common shares issuable		3		2		2
Average common shares outstanding - diluted		642		653		665
Net earnings per share available to common shareholders:
Basic	$	5.86	$	9.15	$	4.20
Diluted	$	5.84	$	9.12	$	4.19

Other Comprehensive Earnings (Loss)

12 Months Ended

Dec. 31, 2023

Other Comprehensive Earnings (Loss)

9.

Other Comprehensive Earnings (Loss)

Components of other comprehensive earnings (loss) consist of the following:


	Year Ended December 31,
	2023			2022			2021
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits	$	(116	)	$	(132	)	$	(127	)
Net actuarial gain (loss) and prior service cost arising in current year		(15	)		15			(35	)
Recognition of net actuarial loss and prior service cost in earnings (1)		5			6			3
Settlement of pension benefits (2)		—			—			19
Other (3)		—			—			7
Income tax benefit (expense)		2			(5	)		1
Accumulated other comprehensive loss, net of tax	$	(124	)	$	(116	)	$	(132	)

(1)

Recognition of net actuarial loss and prior service cost are included in the computation of net periodic benefit cost, which is a component of other, net in the accompanying consolidated statements of comprehensive earnings. See Note 16 for additional details.

(2)

In 2021, the Merger triggered settlement payments to certain plan participants, and the expense associated with this settlement is recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

(3)

Other includes a remeasurement of the pension obligation due to the Merger, which was partially offset by a change in mortality assumption.

Supplemental Information To Statements Of Cash Flows

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Elements [Abstract]

Supplemental Information To Statements Of Cash Flows

Supplemental Information to Statements of Cash Flows


	Year Ended December 31,
	2023			2022			2021
Changes in assets and liabilities, net:
Accounts receivable	$	191		$	(142	)	$	(526	)
Other current assets		95			(119	)		30
Other long-term assets		(36	)		90			12
Accounts payable and revenues and royalties payable		(335	)		152			539
Other current liabilities		(50	)		(97	)		(18	)
Other long-term liabilities		(9	)		(110	)		(153	)
Total	$	(144	)	$	(226	)	$	(116	)
Supplementary cash flow data:
Interest paid	$	378		$	370		$	404
Income taxes paid (refunded)	$	400		$	438		$	(116	)

Devon's non-cash investing activities for 2023 included approximately $150 million of contributions of other property and equipment for the formation of the Water JV.

As of December 31, 2023, 2022 and 2021, Devon had approximately $348 million, $413 million and $205 million, respectively, of accrued capital expenditures included in total property and equipment, net and accounts payable on the consolidated balance sheets.

Accounts Receivable

12 Months Ended

Dec. 31, 2023

Accounts Receivable, after Allowance for Credit Loss [Abstract]

Accounts Receivable

Components of accounts receivable include the following:


	December 31, 2023			December 31, 2022
Oil, gas and NGL sales	$	965		$	1,153
Joint interest billings		251			162
Marketing and midstream revenues		342			428
Other		22			33
Gross accounts receivable		1,580			1,776
Allowance for doubtful accounts		(7	)		(9	)
Net accounts receivable	$	1,573		$	1,767

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Property, Plant and Equipment

Capitalized Costs

The following table presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.


	December 31, 2023			December 31, 2022
Property and equipment:
Proved	$	46,659		$	42,734
Unproved and properties under development		1,279			1,548
Total oil and gas		47,938			44,282
Less accumulated DD&A		(30,113	)		(27,715	)
Oil and gas property and equipment, net		17,825			16,567
Other property and equipment		2,289			2,280
Less accumulated DD&A		(786	)		(741	)
Other property and equipment, net (1)		1,503			1,539
Property and equipment, net	$	19,328		$	18,106

(1)

$136 million and $109 million related to CDM in 2023 and 2022, respectively.

Suspended Exploratory Well Costs

The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2023.


	Year Ended December 31,
	2023			2022			2021
	(Millions)
Beginning balance	$	126		$	66		$	18
Acquired WPX costs		—			—			34
Additions pending determination of proved reserves		522			462			206
Charges to exploration expense		(1	)		(1	)		(2	)
Reclassifications to proved properties		(511	)		(401	)		(190	)
Ending balance	$	136		$	126		$	66

Devon had no projects with material suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling as of December 31, 2023, 2022 and 2021.

Debt And Related Expenses

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt and Related Expenses

See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon unless otherwise noted in the table below.


	December 31, 2023			December 31, 2022
8.25% due August 1, 2023 (1)	$	—		$	242
5.25% due September 15, 2024 (1)		472			472
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027 (2)		73			73
5.25% due October 15, 2027 (1)		390			390
5.875% due June 15, 2028 (1)		325			325
4.50% due January 15, 2030 (1)		585			585
7.875% due September 30, 2031		675			675
7.95% due April 15, 2032		366			366
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net premium on debentures and notes		64			103
Debt issuance costs		(30	)		(26	)
Total debt	$	6,155		$	6,440
Less amount classified as short-term debt		483			251
Total long-term debt	$	5,672		$	6,189

(1)

These instruments were assumed by Devon in January 2021 in conjunction with the Merger. Approximately $35 million of these instruments remain the unsecured and unsubordinated obligation of WPX, a wholly-owned subsidiary of Devon.

(2)

This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rate of this note at the time assumed was $169 million and 6.5%, respectively. This instrument is the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

Debt maturities as of December 31, 2023, excluding debt issuance costs, premiums and discounts, are as follows:


	Total
2024	$	472
2025		485
2026		—
2027		463
2028		325
Thereafter		4,376
Total	$	6,121

On or after the dates in the following schedule, Devon has the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture documents, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture documents governing the notes to be redeemed. At any time prior to the dates in the following schedule, Devon has the option to redeem some or all of the notes at a specified “make whole” premium as described in such documents. Other than with respect to the notes identified in the schedule below, Devon's senior notes generally include more limited redemption provisions, such as "par call" rights near the maturity date or “make whole” redemption rights.


		Optional Redemption
5.25% due October 15, 2027		October 15, 2022
5.875% due June 15, 2028		June 15, 2023
4.50% due January 15, 2030		January 15, 2025

Retirement of Senior Notes

On August 1, 2023, Devon repaid the $242 million of 8.25% senior notes at maturity.

During 2021, Devon redeemed approximately $1.2 billion of senior notes, resulting in $30 million of gains on early retirement of debt, consisting of $89 million of non-cash premium accelerations, partially offset by $59 million of cash retirement costs. The gain on early retirement is included in financing costs, net in the consolidated statements of comprehensive earnings.

Credit Lines

During 2023, Devon amended and restated its 2018 Senior Credit Facility to provide for a new $3.0 billion revolving 2023 Senior Credit Facility with a financial covenant and other terms similar to the 2018 Senior Credit Facility. As of December 31, 2023, Devon had $3 million in outstanding letters of credit under the 2023 Senior Credit Facility. There were no borrowings under the 2023 Senior Credit Facility as of December 31, 2023. The 2023 Senior Credit Facility matures on March 24, 2028, with the option to extend the maturity date by three additional one-year periods, subject to lender consent. Amounts borrowed under the 2023 Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The 2023 Senior Credit Facility currently provides for an annual facility fee of approximately $5 million.

The 2023 Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. For example, total capitalization is adjusted to add back certain noncash financial write-downs, such as asset impairments. As of December 31, 2023, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 22%.

Commercial Paper

Devon’s 2023 Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. As of December 31, 2023, Devon had no outstanding commercial paper borrowings.

Net Financing Costs

The following schedule includes the components of net financing costs.


	Year Ended December 31,
	2023			2022			2021
Interest based on debt outstanding	$	369		$	370		$	388
Gain on early retirement of debt		—			—			(30	)
Interest income		(55	)		(38	)		(2	)
Other		(6	)		(23	)		(27	)
Total net financing costs	$	308		$	309		$	329

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Section S99
-Paragraph 1
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Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Leases

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Leases

Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. During 2023, Devon's financing lease right-of-use assets and the associated liabilities increased primarily from an amendment of lease terms. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation. Devon’s financing lease arrangement contains various covenants, including covenants similar to the 2023 Senior Credit Facility.

The following table presents Devon’s right-of-use assets and lease liabilities.


	December 31, 2023						December 31, 2022
	Finance		Operating		Total		Finance		Operating		Total
Right-of-use assets	$	246	$	21	$	267	$	203	$	21	$	224
Lease liabilities:
Current lease liabilities (1)	$	21	$	12	$	33	$	8	$	13	$	21
Long-term lease liabilities		286		9		295		249		8		257
Total lease liabilities (2)	$	307	$	21	$	328	$	257	$	21	$	278

(1)

Current lease liabilities are included in other current liabilities on the consolidated balance sheets.

(2)

Devon has entered into certain leases of equipment related to the exploration, development and production of oil and gas that had terms not yet commenced as of December 31, 2023 and are therefore excluded from the amounts shown above.

The following table presents Devon’s total lease cost.


		Year Ended December 31,
		2023			2022			2021
Operating lease cost	Property and equipment; LOE; G&A	$	13		$	22		$	25
Short-term lease cost (1)	Property and equipment; LOE; G&A		193			140			89
Financing lease cost:
Amortization of right-of-use assets	DD&A		9			8			8
Interest on lease liabilities	Net financing costs		15			11			11
Variable lease cost	G&A		5			—			(4	)
Lease income	G&A		(10	)		(8	)		(8	)
Net lease cost		$	225		$	173		$	121

(1)

Short-term lease cost excludes leases with terms of one month or less.

The following table presents Devon’s additional lease information.


	Year Ended December 31,
	2023						2022
	Finance			Operating			Finance			Operating
Cash outflows for lease liabilities:
Operating cash flows	$	15		$	13		$	8		$	14
Investing cash flows	$	—		$	1		$	—		$	9
Right-of-use assets obtained in exchange for new lease liabilities	$	—		$	13		$	—		$	20
Weighted average remaining lease term (years)		9.4			2.2			5.0			1.7
Weighted average discount rate		6.1	%		4.9	%		4.2	%		2.8	%

The following table presents Devon’s maturity analysis as of December 31, 2023 for leases expiring in each of the next 5 years and thereafter.


	Finance			Operating			Total
2024	$	21		$	12		$	33
2025		21			6			27
2026		21			4			25
2027		21			—			21
2028		21			—			21
Thereafter(1)		372			—			372
Total lease payments		477			22			499
Less: interest		(170	)		(1	)		(171	)
Present value of lease liabilities	$	307		$	21		$	328

(1)

Devon has one real estate lease that contains a residual value guarantee. Under the lease terms, the residual value guarantee stipulates that if the lessor were to sell the leased property and receive sale proceeds less than 90% of the lease liability at the time of sale, Devon would be required to make a shortfall payment to the lessor for the difference.

Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of December 31, 2023 for each of the next 5 years and thereafter.


	Operating
	Lease Income
2024	$	11
2025		13
2026		13
2027		13
2028		14
Thereafter		61
Total	$	125

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligations

The following table presents the changes in asset retirement obligations.


	Year Ended December 31,
	2023			2022
Asset retirement obligations as of beginning of period	$	529		$	485
Liabilities incurred and assumed through acquisitions		110			73
Liabilities settled and divested		(30	)		(19	)
Revision of estimated obligation		27			(35	)
Accretion expense on discounted obligation		29			25
Asset retirement obligations as of end of period		665			529
Less current portion		22			18
Asset retirement obligations, long-term	$	643		$	511

Devon's asset retirement obligations recorded during 2023 include a potential obligation to decommission two California offshore oil and gas production platforms and related facilities pursuant to an order of the Department of the Interior, Bureau of Safety and Environmental Enforcement. For additional information, see Note 18.

Devon also increased its asset retirement obligations during 2023 by approximately $27 million primarily due to inflation-driven increases in current cost estimates.

During 2022, Devon increased its asset retirement obligations by approximately $38 million due to asset acquisitions in the Eagle Ford and Williston Basin. During this same time period, Devon reduced its asset retirement obligations by $35 million primarily due to extended retirement dates for oil and gas assets, partially offset by inflation-driven increases to current settlement costs.

Retirement Plans

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Retirement Plans

Defined Contribution Plans

Devon sponsors defined contribution plans covering its employees. Such plans include its 401(k) plan and enhanced contribution plan. Devon makes matching contributions and additional retirement contributions, with the matching contributions being primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by the U.S. government. Devon contributed $38 million, $37 million and $33 million to these plans in 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees and effective, as of December 31, 2020, Devon’s benefits committee approved a freeze of all future benefit accruals under the plans.

Benefits are primarily funded from assets held in the plans’ trusts.

Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 90% fixed income and 10% equity. See the following discussion for Devon’s pension assets by asset class.

Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities do not consistently trade actively in an established market. The fair values of these Level 2 securities are estimated based upon rates available for securities with similar terms and maturity when active trading is not available and were $418 million and $384 million at December 31, 2023 and 2022, respectively.

Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These equity securities can be sold on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $44 million and $49 million at December 31, 2023 and 2022, respectively.

Other – Devon’s other securities include short-term investment funds that invest both long and short term using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers and were $14 million and $25 million at December 31, 2023 and 2022, respectively.

Defined Postretirement Plans

Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

Benefit Obligations and Funded Status

The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with Devon’s defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2023 and 2022.


	Pension Benefits						Postretirement Benefits
	2023			2022			2023			2022
Change in benefit obligation:
Benefit obligation at beginning of year	$	629		$	880		$	7		$	12
Interest cost		34			19			—			—
Actuarial loss (gain)		46			(215	)		1			(4	)
Participant contributions		—			—			1			1
Benefits paid		(54	)		(55	)		(2	)		(2	)
Benefit obligation at end of year		655			629			7			7
Change in plan assets:
Fair value of plan assets at beginning of year		458			671			—			—
Actual return on plan assets		58			(172	)		—			—
Employer contributions		14			14			1			1
Participant contributions		—			—			1			1
Benefits paid		(54	)		(55	)		(2	)		(2	)
Fair value of plan assets at end of year		476			458			—			—
Funded status at end of year	$	(179	)	$	(171	)	$	(7	)	$	(7	)
Amounts recognized in balance sheet:
Other current liabilities	$	(13	)	$	(14	)	$	(1	)	$	(1	)
Other long-term liabilities		(166	)		(157	)		(6	)		(6	)
Net amount	$	(179	)	$	(171	)	$	(7	)	$	(7	)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	$	198		$	189		$	(14	)	$	(15	)
Prior service cost		—			—			1			1
Total	$	198		$	189		$	(13	)	$	(14	)

Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2023, and December 31, 2022, as presented in the table below.


	December 31,
	2023		2022
Projected and accumulated benefit obligation	$	655	$	629
Fair value of plan assets	$	476	$	458

The following table presents the components of net periodic benefit cost and other comprehensive earnings.


	Pension Benefits									Postretirement Benefits
	2023			2022			2021			2023			2022			2021
Net periodic benefit cost:
Interest cost	$	34		$	19		$	18		$	—		$	—		$	—
Expected return on plan assets		(27	)		(31	)		(34	)		—			—			—
Recognition of net actuarial loss (gain) (1)		6			6			4			(1	)		(1	)		(1	)
Total net periodic benefit cost (2)		13			(6	)		(12	)		(1	)		(1	)		(1	)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		16			(11	)		28			—			(4	)		(1	)
Prior service cost arising in current year		—			—			—			—			—			1
Recognition of net actuarial (loss) gain, including settlement expense, in net periodic benefit cost		(6	)		(6	)		(23	)		1			1			1
Total other comprehensive loss (earnings)		10			(17	)		5			1			(3	)		1
Total	$	23		$	(23	)	$	(7	)	$	—		$	(4	)	$	—

(1)

These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.

(2)

The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other, net in the accompanying consolidated statements of comprehensive earnings.

Assumptions


	Pension Benefits			Postretirement Benefits
	2023	2022	2021	2023	2022	2021
Assumptions to determine benefit obligations:
Discount rate	5.01%	5.78%	2.71%	4.96%	5.71%	2.34%
Assumptions to determine net periodic benefit cost:
Discount rate - service cost	N/A	N/A	N/A	5.81%	2.83%	2.51%
Discount rate - interest cost	5.61%	2.18%	2.11%	5.49%	1.57%	1.01%
Expected return on plan assets	6.21%	4.80%	5.00%	N/A	N/A	N/A

Discount rate – Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.

Mortality rate – Devon utilized the Society of Actuaries produced mortality tables.

Other assumptions – For measurement of the 2023 benefit obligation for the other postretirement medical plans, a 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2024. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2031 and remain at that level thereafter.

Expected Cash Flows

Devon expects benefit plan payments to average approximately $52 million a year for the next five years and $244 million total for the five years thereafter. Of these payments to be paid in 2024, $15 million is expected to be funded from Devon’s available cash, cash equivalents and other assets.

The entire disclosure for retirement benefits.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Stockholders' Equity Note [Abstract]

Stockholders' Equity

12 Months Ended

Dec. 31, 2023

Stockholders' Equity

Stockholders’ Equity

The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Share Repurchase Program

In November 2021, Devon announced a new share repurchase program of $1.0 billion with a December 31, 2022 expiration date. In 2022, the Board of Directors authorized expansions of the share repurchase program to $2.0 billion and extended the expiration date to May 4, 2023. In May 2023, the Board of Directors authorized a further expansion to $3.0 billion and extended the expiration date to December 31, 2024. The table below provides information regarding purchases of Devon’s common stock that were made under the share repurchase program (shares in thousands).


	Total Number of Shares Purchased		Dollar Value of Shares Purchased		Average Price Paid per Share
$3.0 Billion Plan
2021		13,983	$	589	$	42.15
2022		11,708		718		61.36
2023		19,350		992		51.23
Total plan		45,041	$	2,299	$	51.05

Dividends

Devon pays a quarterly dividend which is comprised of a fixed dividend and a variable dividend. The variable dividend is dependent on quarterly cash flows, among other factors. Devon has raised its fixed quarterly dividend multiple times over the past four calendar years from $0.11 per share in 2021 to $0.22 per share beginning in the first quarter of 2024. The following table summarizes the dividends Devon has paid on its common stock in 2023, 2022 and 2021, respectively.


	Fixed		Variable		Total		Rate Per Share
2023:
First quarter	$	133	$	463	$	596	$	0.89
Second quarter		128		334		462	$	0.72
Third quarter		127		185		312	$	0.49
Fourth quarter		127		361		488	$	0.77
Total year-to-date	$	515	$	1,343	$	1,858
2022:
First quarter	$	109	$	558	$	667	$	1.00
Second quarter		105		725		830	$	1.27
Third quarter		117		890		1,007	$	1.55
Fourth quarter		117		758		875	$	1.35
Total year-to-date	$	448	$	2,931	$	3,379
2021:
First quarter	$	76	$	127	$	203	$	0.30
Second quarter		75		154		229	$	0.34
Third quarter		74		255		329	$	0.49
Fourth quarter		73		481		554	$	0.84
Total year-to-date	$	298	$	1,017	$	1,315

In February 2024, Devon raised its fixed quarterly dividend by 10%, to $0.22 per share, and announced a cash dividend in the amount of $0.44 per share payable in the first quarter of 2024. The dividend consists of a $0.22 per share fixed quarterly dividend and a $0.22 per share variable quarterly dividend and will total approximately $280 million.

Noncontrolling Interests

The noncontrolling interests’ share of CDM’s net earnings and the contributions from and distributions to the noncontrolling interests are presented as components of equity.

The entire disclosure for equity.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies

Devon is party to various legal actions arising in connection with its business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Royalty Matters

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits,

including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, paid royalty proceeds in an untimely manner without including required interest, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims.

Environmental and Climate Change Matters

Devon’s business is subject to numerous federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon believes that it is in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.

Beginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon denies the allegations in these lawsuits and intends to vigorously defend against these claims.

The State of Delaware and various municipalities and other governmental and private parties in California have filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctive relief. Although Devon cannot predict the ultimate outcome of these matters, Devon denies the allegations asserted in these lawsuits and intends to vigorously defend against these claims.

Other Indemnifications and Legacy Matters

Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities, undertaking other restorative actions or performing requirements under surface agreements in existence at the time of disposition.

In November 2020, the Department of the Interior, Bureau of Safety and Environmental Enforcement ordered several oil and gas operators, including Devon, to perform decommissioning and reclamation activities on two California offshore oil and gas production platforms and related facilities. The current operator and owner of the platforms contends that it does not have the financial ability to perform these obligations and relinquished the related federal lease in October 2020. In response to the apparent insolvency of the current operator, the government has ordered the former operators and alleged former lease record title owners to decommission the platforms and related facilities. The government contends that an alleged corporate predecessor of Devon owned a partial interest in the subject lease and platforms. Devon denies any obligation to decommission the subject platforms and has appealed the order. In the third quarter of 2023, Devon settled certain defense and indemnity claims against a third party

related to these potential decommissioning obligations. Pursuant to that settlement agreement, Devon received a settlement payment in the fourth quarter of 2023 which Devon believes will offset any potential decommissioning liability it may incur related to the subject platforms. Although Devon continues to pursue its appeal of the government's order and deny any obligation to decommission the subject platforms, in conjunction with the third-party settlement, Devon recorded an increase to its asset retirement obligations in 2023.

Commitments

The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2023.


Year Ending December 31,	Drilling and Facility Obligations(1)		Operational Agreements(1)		Office and Equipment Leases and Other
2024	$	190	$	523	$	103
2025		25		550		83
2026		19		514		58
2027		23		384		42
2028		35		362		37
Thereafter		4		1,132		432
Total	$	296	$	3,465	$	755

(1)

Total costs incurred under take-or-pay and throughput obligations were approximately $750 million, $650 million and $500 million in 2023, 2022 and 2021, respectively.

Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value.

Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.

Devon leases certain office space and equipment under financing and operating lease arrangements.

Fair Value Measurements

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, restricted cash, accounts receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at December 31, 2023 and December 31, 2022, as applicable. Therefore, such financial assets and liabilities are not presented in the following table.


							Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2			Level 3
	Amount			Value			Inputs		Inputs			Inputs
December 31, 2023 assets (liabilities):
Cash equivalents	$	306		$	306		$	306	$	—		$	—
Commodity derivatives	$	208		$	208		$	—	$	208		$	—
Commodity derivatives	$	(9	)	$	(9	)	$	—	$	(9	)	$	—
Debt	$	(6,155	)	$	(6,090	)	$	—	$	(6,090	)	$	—
Contingent earnout payments	$	55		$	55		$	—	$	—		$	55
December 31, 2022 assets (liabilities):
Cash equivalents	$	708		$	708		$	708	$	—		$	—
Commodity derivatives	$	131		$	131		$	—	$	131		$	—
Commodity derivatives	$	(3	)	$	(3	)	$	—	$	(3	)	$	—
Debt	$	(6,440	)	$	(6,231	)	$	—	$	(6,231	)	$	—
Contingent earnout payments	$	157		$	157		$	—	$	—		$	157

The following methods and assumptions were used to estimate the fair values in the table above.

Level 1 Fair Value Measurements

Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates the carrying value.

Level 2 Fair Value Measurements

Commodity derivatives – The fair value of commodity derivatives is estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt – Devon’s debt instruments do not consistently trade actively in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity when active trading is not available.

Level 3 Fair Value Measurements

Contingent Earnout Payments – Devon has the right to receive contingent consideration related to the Barnett asset divestiture based on future oil and gas prices. These values were derived using a Monte Carlo valuation model and qualify as a level 3 fair value measurement. For additional information, see Note 2.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information on Oil and Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2023

Supplemental Information on Oil and Gas Operations (Unaudited)

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.

Costs Incurred

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


	Year Ended December 31,
	2023		2022		2021
Property acquisition costs:
Proved properties	$	2	$	1,760	$	7,017
Unproved properties		63		803		2,381
Exploration costs		534		472		212
Development costs		3,160		2,132		1,643
Costs incurred	$	3,759	$	5,167	$	11,253

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.

Results of Operations

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

Proved Reserves

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.

Price Revisions

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.

Revisions Other Than Price

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).

Extensions and Discoveries

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.

Purchase of Reserves

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.

Sale of Reserves

During 2021, Devon had U.S. non-core asset divestitures. For additional information on these divestitures, see Note 2.

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2023 (MMBoe).


	Total
Proved undeveloped reserves as of December 31, 2022		396
Extensions and discoveries		177
Revisions due to prices		(4	)
Revisions other than price		(12	)
Conversion to proved developed reserves		(165	)
Proved undeveloped reserves as of December 31, 2023		392

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).

Standardized Measure

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


	Year Ended December 31,
	2023			2022			2021
Future cash inflows	$	75,734		$	108,361		$	66,321
Future costs:
Development		(5,241	)		(5,176	)		(3,689	)
Production		(31,648	)		(35,264	)		(22,975	)
Future income tax expense		(6,644	)		(13,216	)		(6,423	)
Future net cash flow		32,201			54,705			33,234
10% discount to reflect timing of cash flows		(12,888	)		(23,391	)		(13,933	)
Standardized measure of discounted future net cash flows	$	19,313		$	31,314		$	19,301

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

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Devon, entities in which it holds a controlling interest and VIEs for which Devon is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments in non-controlled entities over which Devon does not have the ability to exercise significant influence are initially recognized at cost and subsequently adjusted for contributions and distributions.

Variable Interest Entity

In 2019, Devon and an affiliate of QL Capital Partners, LP (“QLCP”) formed CDM, a joint venture in the Delaware Basin. Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon.

Devon, through its controlling interest in CDM, has the power to direct the activities that significantly affect the economic performance of CDM and the obligation to absorb losses or the right to receive benefits that could be significant to CDM; therefore, Devon is considered the primary beneficiary and consolidates CDM. CDM maintains its own capital structure that is separate from Devon. During 2023, 2022 and 2021, QLCP distributions from CDM were approximately $45 million, $30 million and $20 million, respectively. During 2023 and 2021 QLCP contributions to CDM were approximately $37 million and $3 million, respectively.

The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in and disclosed parenthetically, if material, on Devon's consolidated balance sheets.

Investments

Devon has an interest in Catalyst, which is a joint venture established among WPX, an affiliate of Howard Energy Partners, LLC (“HEP”) and certain other investors, to develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the arrangement, Devon and a holding company owned by the other joint venture investors each have a 50% voting interest in the joint venture legal entity, and HEP serves as the operator. Through 2038, Devon’s production from 50,000 net acres in the Stateline area of the Delaware Basin has been dedicated to Catalyst subject to fixed-fee oil gathering and natural gas processing agreements. Devon accounts for the investment in Catalyst as an equity method investment. Devon's share of the

earnings are reflected as a component of other, net in the accompanying consolidated statements of comprehensive earnings.

In the second quarter of 2023, Devon made an investment in the Water JV, a joint venture entity formed with an affiliate of WaterBridge NDB LLC (“WaterBridge”), for the purpose of providing increased capacity and flexibility in disposing of produced water in the Delaware Basin and Eagle Ford. Under terms of the arrangement, Devon contributed water infrastructure assets and committed to a water gathering and disposal dedication to the Water JV through 2038, in exchange for a 30% voting interest in the joint venture legal entity. WaterBridge contributed water infrastructure assets to the Water JV, in exchange for a 70% voting interest in the joint venture legal entity and is serving as the operator. At closing of the Water JV, Devon recognized a $64 million gain in asset dispositions in the consolidated statements of comprehensive earnings, which represented the excess of the estimated fair value of Devon's interest in the Water JV over the carrying value of the water infrastructure assets Devon contributed to the Water JV. Devon accounts for the investment in the Water JV as an equity method investment. Devon's investment in the Water JV is shown within investments on the consolidated balance sheets and Devon's share of the Water JV earnings are reflected as a component of other, net in the accompanying consolidated statements of comprehensive earnings.

During 2023 and 2022, Devon made investments in Matterhorn. Matterhorn is a joint venture entity and was formed for the purpose of constructing a natural gas pipeline that will transport natural gas from the Permian Basin to the Katy, Texas area. Devon’s investment in Matterhorn does not give it the ability to exercise significant influence over Matterhorn.

Devon has other investments largely focused on midstream, new technologies and energy transition initiatives. Devon does not have the ability to exercise significant influence over these investments. The following table presents Devon's investments that are shown on the consolidated balance sheet.


		Carrying Amount
Investments	% Interest	December 31, 2023		December 31, 2022
Catalyst	50%	$	311	$	339
Water JV	30%		216		—
Matterhorn	12.5%		90		54
Other	Various		49		47
Total		$	666	$	440

As of December 31, 2023, Devon’s $311 million investment in Catalyst exceeded the underlying equity in net assets by approximately $112 million. The basis difference results primarily from intangible assets associated with Devon’s acreage dedication and is amortized over the remaining 14-year term of the associated oil gathering and natural gas processing agreements. As of December 31, 2023, Devon's $216 million investment in the Water JV exceeded the underlying equity in net assets by approximately $27 million. The basis difference results primarily from acreage dedicated to the Water JV's water systems and services and is amortized over the remaining 14-year term of those water system services.

Devon's investments provided certain gathering, processing and marketing services to Devon in the ordinary course of business. The impact from these services on Devon’s consolidated statement of comprehensive earnings and consolidated balance sheet for the years ended and as of December 31, 2023 and 2022, respectively, relate primarily to Catalyst and are summarized below.


	Year ended December 31,
	2023		2022		2021
Oil, gas and NGL sales	$	213	$	405	$	264
Production expenses	$	93	$	55	$	42
Accounts receivable	$	11	$	14	$	22

In February 2024, Devon committed to invest approximately $90 million in a geothermal technology company and expects to fund the commitment throughout 2024.

Segment Information

Devon’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of these operations.

Use Of Estimates

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

proved reserves and related present value of future net revenues;

•

evaluation of suspended well costs;

•

the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories;

•

derivative financial instruments;

•

the fair value of reporting units and related assessment of goodwill for impairment;

•

income taxes;

•

asset retirement obligations;

•

obligations related to employee pension and postretirement benefits;

•

legal and environmental risks and exposures;

•

the fair value of contingent earnout payments; and

•

general credit risk associated with receivables and other assets.

Revenue Recognition

Upstream Revenues

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract-specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of comprehensive earnings.

Devon acts as a principal in sales transactions when control of the product is retained prior to delivery to the ultimate third-party customer or acts as an agent when services are rendered on behalf of the principal in the transactions. A control-based assessment is performed to identify whether Devon is a principal or an agent in the transaction, which determines whether revenue and the related expenses are presented on a gross or net basis, respectively.

Oil sales

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point where the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Natural gas and NGL sales

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated statements of comprehensive earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Marketing Revenues

Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract-specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

Midstream Revenues

Devon’s reported midstream revenue primarily relates to its interest in CDM. CDM provides gathering, compression and dehydration services to Devon and other producers’ natural gas production. An evaluation is performed to determine whether CDM is a principal or agent in these transactions. Under the terms of these gathering, compression and dehydration contracts, CDM has concluded it is the agent as title to the gas production remains with the CDM affiliate producer or a third-party producer. Revenue is recognized on a net basis since CDM is strictly providing a service. Costs to maintain CDM’s assets are presented as marketing and midstream expenses in the consolidated statements of comprehensive earnings. Revenue is recognized for sales at the time the gathering, compression and dehydration service has been rendered or performed.

Satisfaction of Performance Obligations and Revenue Recognition

Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2023. Devon’s product sales and marketing contracts do not give rise to contract assets.

Disaggregation of Revenue

The following table presents revenue from contracts with customers that are disaggregated based on the type of good.


	Year Ended December 31,
	2023		2022		2021
Oil	$	8,879	$	10,281	$	6,996
Gas		703		1,948		1,104
NGL		1,209		1,853		1,431
Oil, gas and NGL sales		10,791		14,082		9,531

Oil		3,018		3,305		2,451
Gas		572		1,163		718
NGL		759		1,277		1,050
Marketing and midstream revenues		4,349		5,745		4,219
Total revenues from contracts with customers	$	15,140	$	19,827	$	13,750

Customers

For the year ended December 31, 2023, sales to two customers accounted for approximately 14% and 10% of Devon's sales revenue. For the year ended December 31, 2022, sales to one customer accounted for approximately 15% of Devon's sales revenue. For the year ended December 31, 2021 sales to two customers accounted for approximately 19% and 12% of Devon's sales revenue.

If any one of Devon’s major customers were to stop purchasing our production, the Company believes there are a number of other purchasers to whom the company could sell Devon’s production. If multiple significant customers were to discontinue purchasing Devon’s production abruptly, the Company believes it would have the resources needed to access alternative customers or markets and avoid or materially mitigate associated sales disruptions.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices and interest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2023, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2023, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties. Given Devon's current credit ratings and the terms of the underlying contracts, Devon is not currently required to post collateral to its counterparties with respect to its open derivative positions, and would not be required to post any such collateral as a result of any change to the amount of Devon's net liability for such positions.

General And Administrative Expenses

General and Administrative Expenses

G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon.

Share-Based Compensation

Devon grants share-based awards to members of its Board of Directors, management and employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated statements of comprehensive earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 5, certain share-based awards were accelerated and recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is significant negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.

Net Earnings Per Share Attributable to Devon

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Devon applies the two-class method to stock awards deemed to be participating securities. The two-class method requires allocating net earnings to both common shares and participating securities based on their respective rights to receive dividends. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of unvested restricted stock awards and unvested performance share units.

Cash, Cash Equivalents, and Restricted Cash

Cash, Cash Equivalents and Restricted Cash

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Devon also considers cash balances subject to legal and contractual restrictions as restricted cash. As of December 31, 2022 and 2021, Devon's restricted cash also included $120 million and $160 million, respectively, associated with retained obligations related to previously disposed assets. As of December 31, 2023, the cash balances associated with these obligations are no longer considered restricted cash.

Accounts Receivable

Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables. Devon does not require collateral security for joint interest receivables.

Devon records an allowance for credit losses based on a forward-looking “expected loss” model. Credit risk is assessed by class of account type, which includes cash equivalents and oil and gas, marketing and midstream, joint interest and other accounts receivable. These classes are further evaluated using a probability-weighted scenario assessment based on historical losses and a probability of future default. This evaluation is supported by an assessment of risk factors such as the age of the receivable, current macro-economic conditions, credit rating of the counterparty and our historical loss rate.

Inventory

Devon’s inventories primarily consist of oil and NGL inventory and equipment inventory. Oil and NGL inventory are recorded at weighted average cost and carried at the lower of cost or net realizable value. Equipment inventory is valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

Property And Equipment

Property and Equipment

Oil and Gas Property and Equipment

Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.

Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.

Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually.

Proved properties are assessed for impairment when events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying statements of comprehensive earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

Devon capitalizes interest costs incurred that are attributable to material unproved oil and gas properties and major development projects of oil and gas properties.

Other Property and Equipment

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major corporate construction projects are also capitalized.

Asset Retirement Obligations

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet unless the associated asset has already been disposed. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Leases

Devon establishes right-of-use assets and lease liabilities on the balance sheet for all leases with a term longer than 12 months. Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of the reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. The fair value of the reporting unit is estimated based upon market capitalization, comparable transactions of similar companies and premiums paid.

Devon performed impairment tests of goodwill in the fourth quarters of 2023, 2022 and 2021. No impairment was required as a result of the annual tests in these time periods.

Commitments And Contingencies

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

•

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

•

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

•

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Noncontrolling Interests

Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.

Recently Issued Accounting Standards Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures. ASU 2023-09 intends to provide investors with enhanced information about an entity’s income taxes by requiring disclosure of items such as disaggregation of the effective tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective for annual reporting periods beginning after December 15, 2024, with early adoption permitted for annual financial statements that have not yet been issued. Devon is evaluating the impact this ASU will have on the disclosures that accompany its consolidated financial statements.

In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures. Under this ASU, the scope and frequency of segment disclosures is increased to provide investors with additional detail about information utilized by an entity’s “Chief Operating Decision Maker.” This ASU is effective for Devon beginning with our 2024 annual reporting and interim periods beginning in 2025. Devon is evaluating the impact this ASU will have on the disclosures that accompany its consolidated financial statements.

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of Components of Investment

The following table presents Devon's investments that are shown on the consolidated balance sheet.


		Carrying Amount
Investments	% Interest	December 31, 2023		December 31, 2022
Catalyst	50%	$	311	$	339
Water JV	30%		216		—
Matterhorn	12.5%		90		54
Other	Various		49		47
Total		$	666	$	440

Schedule Of Additional Investment Information

Devon's investments provided certain gathering, processing and marketing services to Devon in the ordinary course of business. The impact from these services on Devon’s consolidated statement of comprehensive earnings and consolidated balance sheet for the years ended and as of December 31, 2023 and 2022, respectively, relate primarily to Catalyst and are summarized below.


	Year ended December 31,
	2023		2022		2021
Oil, gas and NGL sales	$	213	$	405	$	264
Production expenses	$	93	$	55	$	42
Accounts receivable	$	11	$	14	$	22

I

Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good

The following table presents revenue from contracts with customers that are disaggregated based on the type of good.


	Year Ended December 31,
	2023		2022		2021
Oil	$	8,879	$	10,281	$	6,996
Gas		703		1,948		1,104
NGL		1,209		1,853		1,431
Oil, gas and NGL sales		10,791		14,082		9,531

Oil		3,018		3,305		2,451
Gas		572		1,163		718
NGL		759		1,277		1,050
Marketing and midstream revenues		4,349		5,745		4,219
Total revenues from contracts with customers	$	15,140	$	19,827	$	13,750

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Open Derivative Positions

Commodity Derivatives

As of December 31, 2023, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.


	Price Swaps				Price Collars
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q1-Q4 2024		27,486	$	77.74		60,238	$	65.71	$	84.89


	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q1-Q4 2024	Midland Sweet		62,500	$	1.17
Q1-Q4 2024	NYMEX Roll		26,000	$	0.82
Q1-Q4 2025	Midland Sweet		53,000	$	0.97

As of December 31, 2023, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.


	Price Swaps				Price Collars
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q1-Q4 2024		187,426	$	3.30		40,527	$	3.78	$	7.05
Q1-Q4 2025		32,904	$	3.22		—	$	—	$	—


	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q1-Q4 2024	El Paso Natural Gas		34,863	$	(0.91	)
Q1-Q4 2024	Houston Ship Channel		110,000	$	(0.24	)
Q1-Q4 2024	WAHA		44,973	$	(0.58	)

As of December 31, 2023, Devon had the following open NGL derivative positions. Devon's NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.


		Price Swaps
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q1-Q4 2024	Natural Gasoline		3,000	$	69.11
Q1-Q4 2024	Normal Butane		3,350	$	37.58
Q1-Q4 2024	Propane		3,000	$	32.20

Schedule of Derivative Financial Instruments Included in the Consolidated Balance Sheets

The table below presents a summary of these positions as of December 31, 2023 and 2022.


	December 31, 2023									December 31, 2022
	Gross Fair Value			Amounts Netted			Net Fair Value			Gross Fair Value			Amounts Netted			Net Fair Value			Balance Sheet Classification
Commodity derivatives:
Short-term derivative asset	$	213		$	(5	)	$	208		$	138		$	(19	)	$	119		Other current assets
Long-term derivative asset		—			—			—			12			—			12		Other long-term assets
Short-term derivative liability		(7	)		5			(2	)		(22	)		19			(3	)	Other current liabilities
Long-term derivative liability		(7	)		—			(7	)		—			—			—		Other long-term liabilities
Total derivative asset	$	199		$	—		$	199		$	128		$	—		$	128

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Schedule of Share-Based Compensation Expense Included in the Consolidated Statements of Comprehensive Earnings

The table below presents the share-based compensation expense included in Devon’s accompanying consolidated statements of comprehensive earnings.


	Year Ended December 31,
	2023		2022		2021
G&A	$	92	$	87	$	77
Exploration expenses		1		1		1
Restructuring and transaction costs		—		—		21
Total	$	93	$	88	$	99
Related income tax benefit	$	34	$	34	$	13

Summary of Unvested Restricted Stock Awards, Performance-Based Restricted Stock Awards and Performance Share Units

The following table presents a summary of Devon’s unvested restricted stock awards and units and performance share units granted under the plans.


	Restricted Stock Awards & Units					Performance Share Units
	Awards/Units			Weighted Average Grant-Date Fair Value		Units				Weighted Average Grant-Date Fair Value
	(Thousands, except fair value data)
Unvested at 12/31/22		5,788		$	29.11		1,841			$	31.33
Granted		1,298		$	62.24		743		(1)	$	51.38
Vested		(2,926	)	$	25.25		(1,037	)		$	27.89
Forfeited		(127	)	$	43.89		—			$	—
Unvested at 12/31/23		4,033		$	42.10		1,547		(2)	$	43.25

(1)

These grants also include the impact of performance share units granted in prior year that vested higher than 100% target due to Devon's TSR performance compared to applicable peers.

(2)

A maximum of 3.1 million common shares could be awarded based upon Devon’s final TSR ranking.

Schedule of Share Based Compensation Arrangement by Share Based Payment Award Aggregate Fair Value of Awards and Units

The following table presents the aggregate fair value of awards and units that vested during the indicated period.


	2023		2022		2021
Restricted Stock Awards and Units	$	172	$	180	$	115
Performance-Based Restricted Stock Awards	$	—	$	—	$	1
Performance Share Units	$	66	$	62	$	15

Summary of Unrecognized Compensation Cost and Weighted Average Period for Recognition

The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2023.


	Restricted Stock		Performance
	Awards/Units		Share Units
Unrecognized compensation cost	$	93	$	18
Weighted average period for recognition (years)		2.5		1.7

Summary of Performance Share Units Grant-Date Fair Values and their Related Assumptions

The following table presents the assumptions related to performance share units granted.


	2023			2022			2021
Grant-date fair value	$	81.70		$	68.68		$	18.08
Risk-free interest rate		4.15	%		1.81	%		0.18	%
Volatility factor		61.43	%		70.1	%		67.8	%
Contractual term (years)		2.89			2.89			2.89

Restructuring and Transaction Costs (Tables)

12 Months Ended

Dec. 31, 2023

Restructuring and Related Activities [Abstract]

Schedule of Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring and transaction costs.


	Year Ended December 31,
	2023		2022		2021
Restructuring costs	$	—	$	—	$	210
Transaction costs		—		—		48
Total costs	$	—	$	—	$	258

Schedule of the Activity and Balances Associated with Restructuring Liabilities

The following table summarizes Devon’s restructuring liabilities. The remaining restructuring liability as of December 31, 2023 primarily relates to obligations associated with an abandoned Canadian firm transportation agreement.


	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
Balance as of December 31, 2021	$	38		$	111		$	149
Changes related to prior years' restructurings		(4	)		(30	)		(34	)
Balance as of December 31, 2022	$	34		$	81		$	115
Changes related to prior years' restructurings		(21	)		(9	)		(30	)
Balance as of December 31, 2023	$	13		$	72		$	85

Other, Net (Tables)

12 Months Ended

Dec. 31, 2023

Other Expenses [Abstract]

Schedule of Other Expenses (Income)

The following table summarizes Devon’s other expenses (income) presented in the accompanying consolidated comprehensive statements of earnings.


	Year Ended December 31,
	2023		2022			2021
Estimated future obligation under a performance guarantee	$	—	$	(144	)	$	(18	)
Ukraine charitable pledge		—		20			—
Asset retirement obligation accretion		29		25			28
Severance and other non-income tax refunds		—		(5	)		(39	)
Other		9		9			(14	)
Total	$	38	$	(95	)	$	(43	)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule Of Income Tax Expense (Benefit)

The following table presents Devon’s income tax components.


	Year Ended December 31,
	2023			2022			2021
Current income tax expense (benefit):
U.S. federal	$	441		$	501		$	10
Various states		27			65			9
Canada		(3	)		(7	)		(3	)
Total current income tax expense		465			559			16
Deferred income tax expense:
U.S. federal		365			1,090			18
Various states		11			82			22
Canada		—			7			9
Total deferred income tax expense		376			1,179			49
Total income tax expense	$	841		$	1,738		$	65

Schedule Of Effective Income Tax Rate Reconciliation

Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:


	Year Ended December 31,
	2023			2022			2021
Earnings before income taxes	$	4,623		$	7,775		$	2,898

U.S. statutory income tax rate		21	%		21	%		21	%
State income taxes		1	%		1	%		1	%
Income tax credits		(3	%)		0	%		0	%
Other		(1	%)		0	%		2	%
Deferred tax asset valuation allowance		0	%		0	%		(22	%)
Effective income tax rate		18	%		22	%		2	%

Schedule Of Deferred Tax Assets And Liabilities

The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities.


	December 31,
	2023			2022
Deferred tax assets:
Capital loss carryforwards	$	542		$	523
Net operating loss carryforwards		447			526
Accrued liabilities		194			209
Asset retirement obligation		148			119
Other, including tax credits		25			14
Total deferred tax assets before valuation allowance		1,356			1,391
Less: valuation allowance		(826	)		(814	)
Net deferred tax assets		530			577
Deferred tax liabilities:
Property and equipment		(2,304	)		(1,969	)
Fair value of derivative financial instruments		(50	)		(33	)
Other		(14	)		(38	)
Total deferred tax liabilities		(2,368	)		(2,040	)
Net deferred tax liability	$	(1,838	)	$	(1,463	)

Schedule Of Changes In Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.


	December 31,
	2023		2022
	(Millions)
Balance at beginning of year	$	73	$	36
Tax positions taken in prior periods		10		51
Settlements		—		(14	)
Balance at end of year	$	83	$	73

Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.


Jurisdiction		Tax Years Open
U.S. federal		2015-2023
Various U.S. states		2019-2023
Canada		2006-2023

Net Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Net Earnings (Loss) Per Share Computations from Continuing Operations

The following table reconciles net earnings available to common shareholders and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings per share.


	Year Ended December 31,
	2023		2022		2021
Net earnings available to common shareholders - basic and diluted	$	3,747	$	5,958	$	2,783
Common shares:
Average common shares outstanding - basic		639		651		663
Dilutive effect of potential common shares issuable		3		2		2
Average common shares outstanding - diluted		642		653		665
Net earnings per share available to common shareholders:
Basic	$	5.86	$	9.15	$	4.20
Diluted	$	5.84	$	9.12	$	4.19

Other Comprehensive Earnings (Loss) (Tables)

12 Months Ended

Dec. 31, 2023

Other Comprehensive Income (Loss), Net of Tax [Abstract]

Components Of Other Comprehensive Earnings (loss)

Components of other comprehensive earnings (loss) consist of the following:


	Year Ended December 31,
	2023			2022			2021
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits	$	(116	)	$	(132	)	$	(127	)
Net actuarial gain (loss) and prior service cost arising in current year		(15	)		15			(35	)
Recognition of net actuarial loss and prior service cost in earnings (1)		5			6			3
Settlement of pension benefits (2)		—			—			19
Other (3)		—			—			7
Income tax benefit (expense)		2			(5	)		1
Accumulated other comprehensive loss, net of tax	$	(124	)	$	(116	)	$	(132	)

(1)

Recognition of net actuarial loss and prior service cost are included in the computation of net periodic benefit cost, which is a component of other, net in the accompanying consolidated statements of comprehensive earnings. See Note 16 for additional details.

(2)

In 2021, the Merger triggered settlement payments to certain plan participants, and the expense associated with this settlement is recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

(3)

Other includes a remeasurement of the pension obligation due to the Merger, which was partially offset by a change in mortality assumption.

Supplemental Information To Statements Of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Elements [Abstract]

Schedule Of Supplemental Information To Statements Of Cash Flows


	Year Ended December 31,
	2023			2022			2021
Changes in assets and liabilities, net:
Accounts receivable	$	191		$	(142	)	$	(526	)
Other current assets		95			(119	)		30
Other long-term assets		(36	)		90			12
Accounts payable and revenues and royalties payable		(335	)		152			539
Other current liabilities		(50	)		(97	)		(18	)
Other long-term liabilities		(9	)		(110	)		(153	)
Total	$	(144	)	$	(226	)	$	(116	)
Supplementary cash flow data:
Interest paid	$	378		$	370		$	404
Income taxes paid (refunded)	$	400		$	438		$	(116	)

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2023

Accounts Receivable, after Allowance for Credit Loss [Abstract]

Schedule Of Components Of Accounts Receivable

Components of accounts receivable include the following:


	December 31, 2023			December 31, 2022
Oil, gas and NGL sales	$	965		$	1,153
Joint interest billings		251			162
Marketing and midstream revenues		342			428
Other		22			33
Gross accounts receivable		1,580			1,776
Allowance for doubtful accounts		(7	)		(9	)
Net accounts receivable	$	1,573		$	1,767

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Table of Property and Equipment, net

The following table presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.


	December 31, 2023			December 31, 2022
Property and equipment:
Proved	$	46,659		$	42,734
Unproved and properties under development		1,279			1,548
Total oil and gas		47,938			44,282
Less accumulated DD&A		(30,113	)		(27,715	)
Oil and gas property and equipment, net		17,825			16,567
Other property and equipment		2,289			2,280
Less accumulated DD&A		(786	)		(741	)
Other property and equipment, net (1)		1,503			1,539
Property and equipment, net	$	19,328		$	18,106

(1)

$136 million and $109 million related to CDM in 2023 and 2022, respectively.

Summary of Changes in Suspended Exploratory Well Costs

The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2023.


	Year Ended December 31,
	2023			2022			2021
	(Millions)
Beginning balance	$	126		$	66		$	18
Acquired WPX costs		—			—			34
Additions pending determination of proved reserves		522			462			206
Charges to exploration expense		(1	)		(1	)		(2	)
Reclassifications to proved properties		(511	)		(401	)		(190	)
Ending balance	$	136		$	126		$	66

Debt And Related Expenses (Tables)

12 Months Ended

Dec. 31, 2023

Schedule Of Debt Instruments and Balances

See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon unless otherwise noted in the table below.


	December 31, 2023			December 31, 2022
8.25% due August 1, 2023 (1)	$	—		$	242
5.25% due September 15, 2024 (1)		472			472
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027 (2)		73			73
5.25% due October 15, 2027 (1)		390			390
5.875% due June 15, 2028 (1)		325			325
4.50% due January 15, 2030 (1)		585			585
7.875% due September 30, 2031		675			675
7.95% due April 15, 2032		366			366
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net premium on debentures and notes		64			103
Debt issuance costs		(30	)		(26	)
Total debt	$	6,155		$	6,440
Less amount classified as short-term debt		483			251
Total long-term debt	$	5,672		$	6,189

(1)

These instruments were assumed by Devon in January 2021 in conjunction with the Merger. Approximately $35 million of these instruments remain the unsecured and unsubordinated obligation of WPX, a wholly-owned subsidiary of Devon.

(2)

This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rate of this note at the time assumed was $169 million and 6.5%, respectively. This instrument is the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

Schedule of Debt Maturities

Debt maturities as of December 31, 2023, excluding debt issuance costs, premiums and discounts, are as follows:


	Total
2024	$	472
2025		485
2026		—
2027		463
2028		325
Thereafter		4,376
Total	$	6,121

Schedule Of Net Financing Cost Components

The following schedule includes the components of net financing costs.


	Year Ended December 31,
	2023			2022			2021
Interest based on debt outstanding	$	369		$	370		$	388
Gain on early retirement of debt		—			—			(30	)
Interest income		(55	)		(38	)		(2	)
Other		(6	)		(23	)		(27	)
Total net financing costs	$	308		$	309		$	329

WPX

Schedule Of Debt Instruments and Balances

the dates in the following schedule, Devon has the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture documents, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture documents governing the notes to be redeemed. At any time prior to the dates in the following schedule, Devon has the option to redeem some or all of the notes at a specified “make whole” premium as described in such documents. Other than with respect to the notes identified in the schedule below, Devon's senior notes generally include more limited redemption provisions, such as "par call" rights near the maturity date or “make whole” redemption rights.


		Optional Redemption
5.25% due October 15, 2027		October 15, 2022
5.875% due June 15, 2028		June 15, 2023
4.50% due January 15, 2030		January 15, 2025

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Schedule of Right-of-use Assets and Lease Liabilities

Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. During 2023, Devon's financing lease right-of-use assets and the associated liabilities increased primarily from an amendment of lease terms. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation. Devon’s financing lease arrangement contains various covenants, including covenants similar to the 2023 Senior Credit Facility.

The following table presents Devon’s right-of-use assets and lease liabilities.


	December 31, 2023						December 31, 2022
	Finance		Operating		Total		Finance		Operating		Total
Right-of-use assets	$	246	$	21	$	267	$	203	$	21	$	224
Lease liabilities:
Current lease liabilities (1)	$	21	$	12	$	33	$	8	$	13	$	21
Long-term lease liabilities		286		9		295		249		8		257
Total lease liabilities (2)	$	307	$	21	$	328	$	257	$	21	$	278

(1)

Current lease liabilities are included in other current liabilities on the consolidated balance sheets.

(2)

Devon has entered into certain leases of equipment related to the exploration, development and production of oil and gas that had terms not yet commenced as of December 31, 2023 and are therefore excluded from the amounts shown above.

Schedule of Total Lease Cost

he following table presents Devon’s total lease cost.


		Year Ended December 31,
		2023			2022			2021
Operating lease cost	Property and equipment; LOE; G&A	$	13		$	22		$	25
Short-term lease cost (1)	Property and equipment; LOE; G&A		193			140			89
Financing lease cost:
Amortization of right-of-use assets	DD&A		9			8			8
Interest on lease liabilities	Net financing costs		15			11			11
Variable lease cost	G&A		5			—			(4	)
Lease income	G&A		(10	)		(8	)		(8	)
Net lease cost		$	225		$	173		$	121

(1)

Short-term lease cost excludes leases with terms of one month or less.

Schedule of Additional Lease Information

The following table presents Devon’s additional lease information.


	Year Ended December 31,
	2023						2022
	Finance			Operating			Finance			Operating
Cash outflows for lease liabilities:
Operating cash flows	$	15		$	13		$	8		$	14
Investing cash flows	$	—		$	1		$	—		$	9
Right-of-use assets obtained in exchange for new lease liabilities	$	—		$	13		$	—		$	20
Weighted average remaining lease term (years)		9.4			2.2			5.0			1.7
Weighted average discount rate		6.1	%		4.9	%		4.2	%		2.8	%

Maturities of Lease Liabilities

The following table presents Devon’s maturity analysis as of December 31, 2023 for leases expiring in each of the next 5 years and thereafter.


	Finance			Operating			Total
2024	$	21		$	12		$	33
2025		21			6			27
2026		21			4			25
2027		21			—			21
2028		21			—			21
Thereafter(1)		372			—			372
Total lease payments		477			22			499
Less: interest		(170	)		(1	)		(171	)
Present value of lease liabilities	$	307		$	21		$	328

(1)

Devon has one real estate lease that contains a residual value guarantee. Under the lease terms, the residual value guarantee stipulates that if the lessor were to sell the leased property and receive sale proceeds less than 90% of the lease liability at the time of sale, Devon would be required to make a shortfall payment to the lessor for the difference.

Schedule of Expected Lease Income

Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of December 31, 2023 for each of the next 5 years and thereafter.


	Operating
	Lease Income
2024	$	11
2025		13
2026		13
2027		13
2028		14
Thereafter		61
Total	$	125

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Summary Of Changes In Asset Retirement Obligations

The following table presents the changes in asset retirement obligations.


	Year Ended December 31,
	2023			2022
Asset retirement obligations as of beginning of period	$	529		$	485
Liabilities incurred and assumed through acquisitions		110			73
Liabilities settled and divested		(30	)		(19	)
Revision of estimated obligation		27			(35	)
Accretion expense on discounted obligation		29			25
Asset retirement obligations as of end of period		665			529
Less current portion		22			18
Asset retirement obligations, long-term	$	643		$	511

Retirement Plans (Tables)

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Schedule of Changes in Defined Benefit Plan Obligations


	Pension Benefits						Postretirement Benefits
	2023			2022			2023			2022
Change in benefit obligation:
Benefit obligation at beginning of year	$	629		$	880		$	7		$	12
Interest cost		34			19			—			—
Actuarial loss (gain)		46			(215	)		1			(4	)
Participant contributions		—			—			1			1
Benefits paid		(54	)		(55	)		(2	)		(2	)
Benefit obligation at end of year		655			629			7			7
Change in plan assets:
Fair value of plan assets at beginning of year		458			671			—			—
Actual return on plan assets		58			(172	)		—			—
Employer contributions		14			14			1			1
Participant contributions		—			—			1			1
Benefits paid		(54	)		(55	)		(2	)		(2	)
Fair value of plan assets at end of year		476			458			—			—
Funded status at end of year	$	(179	)	$	(171	)	$	(7	)	$	(7	)
Amounts recognized in balance sheet:
Other current liabilities	$	(13	)	$	(14	)	$	(1	)	$	(1	)
Other long-term liabilities		(166	)		(157	)		(6	)		(6	)
Net amount	$	(179	)	$	(171	)	$	(7	)	$	(7	)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	$	198		$	189		$	(14	)	$	(15	)
Prior service cost		—			—			1			1
Total	$	198		$	189		$	(13	)	$	(14	)

Schedule of Projected Benefit Obligation And Accumulated Benefit Obligation in Excess of Plan Assets

Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2023, and December 31, 2022, as presented in the table below.


	December 31,
	2023		2022
Projected and accumulated benefit obligation	$	655	$	629
Fair value of plan assets	$	476	$	458

Schedule of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Postretirement Benefit Plans

The following table presents the components of net periodic benefit cost and other comprehensive earnings.


	Pension Benefits									Postretirement Benefits
	2023			2022			2021			2023			2022			2021
Net periodic benefit cost:
Interest cost	$	34		$	19		$	18		$	—		$	—		$	—
Expected return on plan assets		(27	)		(31	)		(34	)		—			—			—
Recognition of net actuarial loss (gain) (1)		6			6			4			(1	)		(1	)		(1	)
Total net periodic benefit cost (2)		13			(6	)		(12	)		(1	)		(1	)		(1	)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year		16			(11	)		28			—			(4	)		(1	)
Prior service cost arising in current year		—			—			—			—			—			1
Recognition of net actuarial (loss) gain, including settlement expense, in net periodic benefit cost		(6	)		(6	)		(23	)		1			1			1
Total other comprehensive loss (earnings)		10			(17	)		5			1			(3	)		1
Total	$	23		$	(23	)	$	(7	)	$	—		$	(4	)	$	—

(1)

These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.

(2)

The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other, net in the accompanying consolidated statements of comprehensive earnings.

Schedule of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost


	Pension Benefits			Postretirement Benefits
	2023	2022	2021	2023	2022	2021
Assumptions to determine benefit obligations:
Discount rate	5.01%	5.78%	2.71%	4.96%	5.71%	2.34%
Assumptions to determine net periodic benefit cost:
Discount rate - service cost	N/A	N/A	N/A	5.81%	2.83%	2.51%
Discount rate - interest cost	5.61%	2.18%	2.11%	5.49%	1.57%	1.01%
Expected return on plan assets	6.21%	4.80%	5.00%	N/A	N/A	N/A

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2023

Stockholders' Equity [Table]

Summary Of Dividends Paid On Common Stock

The following table summarizes the dividends Devon has paid on its common stock in 2023, 2022 and 2021, respectively.


	Fixed		Variable		Total		Rate Per Share
2023:
First quarter	$	133	$	463	$	596	$	0.89
Second quarter		128		334		462	$	0.72
Third quarter		127		185		312	$	0.49
Fourth quarter		127		361		488	$	0.77
Total year-to-date	$	515	$	1,343	$	1,858
2022:
First quarter	$	109	$	558	$	667	$	1.00
Second quarter		105		725		830	$	1.27
Third quarter		117		890		1,007	$	1.55
Fourth quarter		117		758		875	$	1.35
Total year-to-date	$	448	$	2,931	$	3,379
2021:
First quarter	$	76	$	127	$	203	$	0.30
Second quarter		75		154		229	$	0.34
Third quarter		74		255		329	$	0.49
Fourth quarter		73		481		554	$	0.84
Total year-to-date	$	298	$	1,017	$	1,315

Share Repurchase Program [Member]

Stockholders' Equity [Table]

Summary of Repurchases of Common Stock

The table below provides information regarding purchases of Devon’s common stock that were made under the share repurchase program (shares in thousands).


	Total Number of Shares Purchased		Dollar Value of Shares Purchased		Average Price Paid per Share
$3.0 Billion Plan
2021		13,983	$	589	$	42.15
2022		11,708		718		61.36
2023		19,350		992		51.23
Total plan		45,041	$	2,299	$	51.05

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Commitments and Contingencies

The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2023.


Year Ending December 31,	Drilling and Facility Obligations(1)		Operational Agreements(1)		Office and Equipment Leases and Other
2024	$	190	$	523	$	103
2025		25		550		83
2026		19		514		58
2027		23		384		42
2028		35		362		37
Thereafter		4		1,132		432
Total	$	296	$	3,465	$	755

(1)

Total costs incurred under take-or-pay and throughput obligations were approximately $750 million, $650 million and $500 million in 2023, 2022 and 2021, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, restricted cash, accounts receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at December 31, 2023 and December 31, 2022, as applicable. Therefore, such financial assets and liabilities are not presented in the following table.


							Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2			Level 3
	Amount			Value			Inputs		Inputs			Inputs
December 31, 2023 assets (liabilities):
Cash equivalents	$	306		$	306		$	306	$	—		$	—
Commodity derivatives	$	208		$	208		$	—	$	208		$	—
Commodity derivatives	$	(9	)	$	(9	)	$	—	$	(9	)	$	—
Debt	$	(6,155	)	$	(6,090	)	$	—	$	(6,090	)	$	—
Contingent earnout payments	$	55		$	55		$	—	$	—		$	55
December 31, 2022 assets (liabilities):
Cash equivalents	$	708		$	708		$	708	$	—		$	—
Commodity derivatives	$	131		$	131		$	—	$	131		$	—
Commodity derivatives	$	(3	)	$	(3	)	$	—	$	(3	)	$	—
Debt	$	(6,440	)	$	(6,231	)	$	—	$	(6,231	)	$	—
Contingent earnout payments	$	157		$	157		$	—	$	—		$	157

Supplemental Information on Oil and Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Costs Incurred

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


	Year Ended December 31,
	2023		2022		2021
Property acquisition costs:
Proved properties	$	2	$	1,760	$	7,017
Unproved properties		63		803		2,381
Exploration costs		534		472		212
Development costs		3,160		2,132		1,643
Costs incurred	$	3,759	$	5,167	$	11,253

Results Of Operations


	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

Proved Reserves

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.

Proved Undeveloped Reserves


	Total
Proved undeveloped reserves as of December 31, 2022		396
Extensions and discoveries		177
Revisions due to prices		(4	)
Revisions other than price		(12	)
Conversion to proved developed reserves		(165	)
Proved undeveloped reserves as of December 31, 2023		392

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves

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


	Year Ended December 31,
	2023			2022			2021
Future cash inflows	$	75,734		$	108,361		$	66,321
Future costs:
Development		(5,241	)		(5,176	)		(3,689	)
Production		(31,648	)		(35,264	)		(22,975	)
Future income tax expense		(6,644	)		(13,216	)		(6,423	)
Future net cash flow		32,201			54,705			33,234
10% discount to reflect timing of cash flows		(12,888	)		(23,391	)		(13,933	)
Standardized measure of discounted future net cash flows	$	19,313		$	31,314		$	19,301

Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves

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

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) a Customer	Dec. 31, 2022 USD ($) Customer	Dec. 31, 2021 USD ($) Customer	Feb. 28, 2024 USD ($)	Jun. 30, 2023
Summary Of Significant Accounting Policies [Line Items]
Gain on asset dispositions	$ 30	$ 44	$ 168
Number of customers \| Customer	2	1	2
Derivative collateral held	$ 0
Cash collateral posted	0
Restricted cash	22	$ 140	$ 172
Goodwill, Impairment Loss	$ 0	0	0
Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Commitment to make future contributions, Amount				$ 90
Barnett Shale [Member]
Summary Of Significant Accounting Policies [Line Items]
Restricted cash		$ 120	$ 160
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, useful life	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, useful life	60 years
Customer Concentration Risk [Member] \| One Customer [Member] \| Consolidated Sales Revenue [Member]
Summary Of Significant Accounting Policies [Line Items]
Concentration risk percentage	14.00%	15.00%	19.00%
Customer Concentration Risk [Member] \| Two Customer [Member] \| Consolidated Sales Revenue [Member]
Summary Of Significant Accounting Policies [Line Items]
Concentration risk percentage	10.00%		12.00%
Upstream Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days allowed for payment from end of production month	30 days
Marketing Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days allowed for payment of invoiced amount	30 days
CDM [Member] \| QL Capital Partners, LP [Member]
Summary Of Significant Accounting Policies [Line Items]
Cash Contributed	$ 37		$ 3
Cash distribution from entities	$ 45	$ 30	$ 20
WPX and Howard Energy Partners [Member]
Summary Of Significant Accounting Policies [Line Items]
Voting interest in the join venture legal entity	50.00%
Water JV [Member]
Summary Of Significant Accounting Policies [Line Items]
Voting interest in the join venture legal entity	70.00%				30.00%
Investment in Catalyst	$ 216
Net assets	27
Gain on asset dispositions	$ 64
Catalyst [Member]
Summary Of Significant Accounting Policies [Line Items]
Area of land \| a	50,000
Investment in Catalyst	$ 311
Net assets	$ 112

Summary Of Significant Accounting Policies (Schedule of Components of Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Summary Of Significant Accounting Policies [Line Items]
Investments	$ 666	$ 440
Catalyst [Member]
Summary Of Significant Accounting Policies [Line Items]
% Interest	50.00%
Investments	$ 311	339
Water JV [Member]
Summary Of Significant Accounting Policies [Line Items]
% Interest	30.00%
Investments	$ 216	0
Matterhorn [Member]
Summary Of Significant Accounting Policies [Line Items]
% Interest	12.50%
Investments	$ 90	54
Other [Member]
Summary Of Significant Accounting Policies [Line Items]
Investments	$ 49	$ 47

Summary Of Significant Accounting Policies (Schedule Of Additional Investment Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary Of Significant Accounting Policies [Line Items]
Oil, gas and NGL sales	$ 15,140	$ 19,827	$ 13,750
Accounts receivable	1,573	1,767
Catalyst [Member]
Summary Of Significant Accounting Policies [Line Items]
Oil, gas and NGL sales	213	405	264
Production expenses	93	55	42
Accounts receivable	$ 11	$ 14	$ 22

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Section S99
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 30
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (a)
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-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-4

Summary of Significant Accounting Policies (Schedule of Revenue from Contracts with Customers Disaggregated Based on Type of Good) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	$ 15,140	$ 19,827	$ 13,750
Oil, Gas and NGL Sales [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	10,791	14,082	9,531
Oil, Gas and NGL Sales [Member] \| Gas [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	703	1,948	1,104
Oil, Gas and NGL Sales [Member] \| NGL [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	1,209	1,853	1,431
Oil, Gas and NGL Sales [Member] \| Oil [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	8,879	10,281	6,996
Marketing and Midstream Revenues [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	4,349	5,745	4,219
Marketing and Midstream Revenues [Member] \| Gas [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	572	1,163	718
Marketing and Midstream Revenues [Member] \| NGL [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	759	1,277	1,050
Marketing and Midstream Revenues [Member] \| Oil [Member]
Disaggregation Of Revenue [Line Items]
Oil, gas and NGL sales	$ 3,018	$ 3,305	$ 2,451

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 924
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-Publisher FASB
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-Topic 280
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-Section 50
-Paragraph 32
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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-Section 50
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-4

Acquisitions and Divestitures (Narrative) (Details) $ in Millions	3 Months Ended				12 Months Ended
	Mar. 31, 2024 USD ($)	Mar. 31, 2023 USD ($)	Sep. 30, 2022 USD ($) MMBoe	Mar. 31, 2022 USD ($)	Dec. 31, 2023 USD ($) MMBoe $ / MMBTU $ / bbl	Dec. 31, 2022 USD ($) MMBoe	Dec. 31, 2021 MMBoe
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Common Stock Shares Issued					$ 64	$ 65
Total estimated proved reserves \| MMBoe					1	3	7
Potential additional contingent earnout payment					$ 65
Barnett Shale [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Contingent earnout payments		$ 65		$ 65
Henry Hub gas price for contingent earnout payment upside \| $ / MMBTU					2.75
WTI oil price for contingent earnout payment upside \| $ / bbl					50
Barnett Shale [Member] \| Subsequent Event
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Additional contingent earnout payment	$ 20
Other Current Assets
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Contingent earnout payments					$ 20
Other Noncurrent Assets
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Contingent earnout payments					35
Non Core Assets
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Contingent earnout payments		$ 4		$ 4
Proceeds from sale of business					9
Gain related to sale of assets					$ 35
Devon and WPX Agreement [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Date of agreement					Jan. 07, 2021
Conversion of common stock into right to received per share					0.00005165
Common Stock Shares Issued					$ 5,400
Eagle Ford Acquisition [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Cash consideration			$ 1,700
Williston Acquisition [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Cash consideration			$ 830
Eagle Ford [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Total estimated proved reserves \| MMBoe			87
Williston Basin [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations And Disposition [Line Items]
Total estimated proved reserves \| MMBoe			66

Derivative Financial Instruments (Schedule of Open Oil Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl bbl
NYMEX West Texas Intermediate Price Swaps Oil Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	27,486
Weighted Average Price Swap	77.74
NYMEX West Texas Intermediate Price Collars Oil Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	60,238
Weighted Average Floor Price	65.71
Weighted Average Ceiling Price	84.89
Midland Sweet Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	62,500
Weighted Average Differential To WTI	1.17
Midland Sweet Q1-Q4 2025 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	53,000
Weighted Average Differential To WTI	0.97
NYMEX Roll Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	26,000
Weighted Average Differential To WTI	0.82

Derivative Financial Instruments (Schedule of Open Natural Gas Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2023 MMBTU $ / Customer
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	187,426
Weighted Average Price Swap	3.3
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2025 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	32,904
Weighted Average Price Swap	3.22
FERC Henry Hub Prices Collars Natural Gas Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	40,527
Weighted Average Floor Price	3.78
Weighted Average Ceiling Price	7.05
EI Paso Natural Gas Basis Swaps Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	34,863
Weighted Average Differential To Henry Hub	(0.91)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	110,000
Weighted Average Differential To Henry Hub	(0.24)
WAHA Natural Gas Basis Swaps Q1-Q4 2024 [Member]
Derivative [Line Items]
Volume Per Day (MMBtu/d) \| MMBTU	44,973
Weighted Average Differential To Henry Hub	(0.58)

Derivative Financial Instruments - (Schedule Of Open NGL Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl bbl
Q1-Q4 2024 Natural Gasoline [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	3,000
Weighted Average Price Swap \| $ / bbl	69.11
Q1-Q4 2024 Normal Butane [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	3,350
Weighted Average Price Swap \| $ / bbl	37.58
Q1-Q4 2024 Propane [Member]
Derivative [Line Items]
Volume Per Day (Bbls/d) \| bbl	3,000
Weighted Average Price Swap \| $ / bbl	32.2

Derivative Financial Instruments (Schedule of Derivative Financial Instruments Included in the Consolidated Balance Sheets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivatives Fair Value [Line Items]
Gross Fair Value	$ 199	$ 128
Amounts Netted	0	0
Net Fair Value	199	128
Short-term Derivative Asset [Member]
Derivatives Fair Value [Line Items]
Gross Fair Value	213	138
Amounts Netted	(5)	(19)
Net Fair Value	$ 208	119
Balance Sheet Classification	Other current assets
Long-term Derivative Asset [Member]
Derivatives Fair Value [Line Items]
Gross Fair Value	$ 0	12
Amounts Netted	0	0
Net Fair Value	$ 0	12
Balance Sheet Classification	Other long-term assets
Short-term Derivative Liability [Member]
Derivatives Fair Value [Line Items]
Gross Fair Value	$ 7	(22)
Amounts Netted	(5)	19
Net Fair Value	$ 2	(3)
Balance Sheet Classification	Other current liabilities
Long-term Derivative Liability [Member]
Derivatives Fair Value [Line Items]
Gross Fair Value	$ 7	0
Amounts Netted	0	0
Net Fair Value	$ 7	$ 0
Balance Sheet Classification	Other long-term liabilities

Share-Based Compensation (Narrative) (Details) - shares	12 Months Ended
Share-Based Compensation (Narrative) (Details) - shares	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Awards [Member] \| Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Vesting period	1 year
Restricted Stock Awards [Member] \| Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Vesting period	4 years
Performance Share Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Comparison period of peer companies for performance awards	3 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	100.00%
Performance Share Units [Member] \| Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	0.00%
Performance Share Units [Member] \| Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	200.00%
2022 Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, options and stock appreciation rights		1
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, other awards		1.74

Share-Based Compensation (Schedule of Share-Based Compensation Expense Included in the Consolidated Statements of Comprehensive Earnings) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-based compensation expense	$ 93	$ 88	$ 99
Related income tax benefit	34	34	13
G&A [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-based compensation expense	92	87	77
Exploration Expenses [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-based compensation expense	1	1	1
Restructuring and Transaction Costs [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Restructuring and transaction costs	$ 0	$ 0	$ 21

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Restricted Stock Awards [Member]

Share-Based Compensation (Summary of Unvested Restricted Stock Awards, Performance-Based Restricted Stock Awards and Performance Share Units) (Details)
shares in Thousands

12 Months Ended

Dec. 31, 2023

$ / shares

shares

Share Based Compensation Arrangement By Share Based Payment Award Line Items

Unvested at December 31, 2022 | shares

5,788

Granted, awards and units | shares

1,298

Vested, awards and units | shares

(2,926)

Forfeited, awards and units | shares

(127)

Unvested at December 31, 2023 | shares

4,033

Unvested weighted average grant-date fair value at December 31, 2022 | $ / shares

$ 29.11

Granted, weighted average grant-date fair value | $ / shares

62.24

Vested, weighted average grant-date fair value | $ / shares

25.25

Forfeited, weighted average grant-date fair value | $ / shares

43.89

Unvested weighted average grant-date fair value at December 31, 2023 | $ / shares

$ 42.1

Performance Share Units [Member]

Share Based Compensation Arrangement By Share Based Payment Award Line Items

Unvested at December 31, 2022 | shares

1,841

Granted, awards and units | shares

743

^[1]

Vested, awards and units | shares

(1,037)

Forfeited, awards and units | shares

0

Unvested at December 31, 2023 | shares

1,547

^[2]

Unvested weighted average grant-date fair value at December 31, 2022 | $ / shares

$ 31.33

Granted, weighted average grant-date fair value | $ / shares

51.38

Vested, weighted average grant-date fair value | $ / shares

27.89

Forfeited, weighted average grant-date fair value | $ / shares

0

Unvested weighted average grant-date fair value at December 31, 2023 | $ / shares

$ 43.25

[1]	These grants also include the impact of performance share units granted in prior year that vested higher than 100% target due to Devon's TSR performance compared to applicable peers.
[2]	A maximum of 3.1 million common shares could be awarded based upon Devon’s final TSR ranking

Share-Based Compensation (Summary of Unvested Restricted Stock Awards, Performance-Based Restricted Stock Awards and Performance Share Units) (Parenthetical) (Details) - Performance Share Units [Member] shares in Millions	12 Months Ended
	Dec. 31, 2023 shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	100.00%
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	200.00%
Maximum common shares that could be awarded based upon total shareholder return	3.1

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Share-Based Compensation (Schedule of Aggregate Fair Value of Restricted Stock, Performance-Based Restricted Stock and Performance Shares, Awards and Units, that Vested During the Period) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Awards and Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Aggregate fair value of awards and units, vested	$ 172	$ 180	$ 115
Performance-Based Restricted Stock Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Aggregate fair value of awards and units, vested	0	0	1
Performance Share Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Aggregate fair value of awards and units, vested	$ 66	$ 62	$ 15

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-Topic 718
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-Topic 718
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-Topic 718
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Subparagraph (f)(2)(iv)
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Share-Based Compensation (Summary of Unrecognized Compensation Cost and Weighted Average Period for Recognition) (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)
Restricted Stock Units (RSUs) [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost	$ 93
Weighted average period for recognition (years)	2 years 6 months
Performance Share Units [Member]
Unrecognized Compensation And Weighted Average Recognition [Line Items]
Unrecognized compensation cost	$ 18
Weighted average period for recognition (years)	1 year 8 months 12 days

Share-Based Compensation (Summary of Performance Share Units Grant-Date Fair Values and their Related Assumptions) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Performance Share Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Grant-date fair value	$ 51.38
Risk-free interest rate	4.15%	1.81%	0.18%
Volatility factor	61.43%	70.10%	67.80%
Contractual term (years)	2 years 10 months 20 days	2 years 10 months 20 days	2 years 10 months 20 days
Including Performance Factor Shares Granted [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Grant-date fair value	$ 81.7	$ 68.68	$ 18.08

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Restructuring and Transaction Costs (Schedule of Restructuring and Transaction Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restructuring Cost And Reserve [Line Items]
Restructuring costs	$ 0	$ 0	$ 258
Restructuring Costs [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring costs	0	0	210
Transaction Costs [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring costs	$ 0	$ 0	$ 48

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Restructuring and Transaction Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs	$ 0	$ 0	$ 258
Merger Integration [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs			210
Noncash restructuring costs			21
Transaction Costs [Member]
Restructuring Cost And Reserve [Line Items]
Underwriting, bank, legal and accounting fees			48
Reduction of workforce [Member]
Restructuring Cost And Reserve [Line Items]
Noncash restructuring costs			66
Reduction of workforce [Member] \| Defined Benefit Settlements [Member]
Restructuring Cost And Reserve [Line Items]
Restructuring and transaction costs			$ 41

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Restructuring and Transaction Costs (Schedule of the Activity and Balances Associated with Restructuring Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Restructuring Cost And Reserve [Line Items]
Beginning balance	$ 115	$ 149
Ending balance	85	115
Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Changes related to prior years' restructurings	(30)	(34)
Other Current Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	34	38
Ending balance	13	34
Other Current Liabilities [Member] \| Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Changes related to prior years' restructurings	(21)	(4)
Other Long-Term Liabilities [Member]
Restructuring Cost And Reserve [Line Items]
Beginning balance	81	111
Ending balance	72	81
Other Long-Term Liabilities [Member] \| Prior years' restructurings [Member]
Restructuring Cost And Reserve [Line Items]
Changes related to prior years' restructurings	$ (9)	$ (30)

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Other, Net (Summary of Other Expenses (Income)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Expenses [Abstract]
Estimated future obligation under a performance guarantee	$ 0	$ (144)	$ (18)
Ukraine charitable pledge	0	20	0
Asset retirement obligation accretion	29	25	28
Severance and other non-income tax refunds	0	(5)	(39)
Other	9	9	(14)
Total	$ 38	$ (95)	$ (43)

Other, Net (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Other, Net (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Expenses [Abstract]
Estimated future obligation under a performance guarantee	$ 0	$ (144)	$ (18)
Ukraine charitable pledge	0	20	0
Severance and other non-income tax refunds	$ 0	$ 5	$ 39

Income Taxes (Schedule Of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax expense (benefit):
United States Federal, current income tax expense	$ 441	$ 501	$ 10
Various states, current income tax expense	27	65	9
Canada, current income tax expense	(3)	(7)	(3)
Total current income tax expense	465	559	16
Deferred income tax expense:
United States Federal, deferred income tax expense	365	1,090	18
Various states, deferred income tax expense	11	82	22
Canada,deferred income tax expense	0	7	9
Total deferred income tax expense	376	1,179	49
Total income tax expense	$ 841	$ 1,738	$ 65

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Earnings before income taxes	$ 4,623	$ 7,775	$ 2,898
U.S. statutory income tax rate	21.00%	21.00%	21.00%
State income taxes	1.00%	1.00%	1.00%
Income tax credits	(3.00%)	0.00%	0.00%
Other	(1.00%)	0.00%	2.00%
Deferred tax asset valuation allowance	0.00%	0.00%	(22.00%)
Effective income tax rate	18.00%	22.00%	2.00%

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(11))
-Publisher FASB
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479557/942-235-S99-1

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 25
-Paragraph 1
-SubTopic 20
-Topic 940
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481913/940-20-25-1

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(10))
-Publisher FASB
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

Pension and postretirement benefit plans:

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Mar. 31, 2021
Income Tax [Line Items]
Federal valuation allowance amount removed	$ 826	$ 814
Valuation allowance against deferred tax assets, percent	50.00%
Net operating loss carryforwards, deferred tax assets	$ 447	526
Net operating loss carryforwards	22
Capital loss carryforwards	542	523
Unrecognized tax benefits, interest expense (benefit)	4
Unrecognized tax benefit that would impact effective tax rate	83	73
Deferred unrecognized tax benefits			$ 42
Current unrecognized tax benefits		$ 42
United States Federal [Member]
Income Tax [Line Items]
Federal valuation allowance amount removed	264
Net operating loss carryforwards	139
United States Federal [Member] \| Expires between 2030 and 2037 [Member]
Income Tax [Line Items]
Net operating loss carryforwards	117
Various U.S. States [Member]
Income Tax [Line Items]
Net operating loss carryforwards	303
Canada [Member]
Income Tax [Line Items]
Net operating loss carryforwards	5
Capital loss carryforwards	$ 557
WPX Merger [Member]
Income Tax [Line Items]
Deferred income taxes				$ 250
WPX Merger [Member] \| United States Federal [Member]
Income Tax [Line Items]
Federal valuation allowance amount removed			$ 84

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Capital loss carryforwards	$ 542	$ 523
Deferred tax assets, net operating loss carryforwards	447	526
Deferred tax assets, accrued liabilities	194	209
Deferred tax assets, asset retirement obligations	148	119
Other, including tax credits	25	14
Total deferred tax assets before valuation allowance	1,356	1,391
Less: valuation allowance	(826)	(814)
Net deferred tax assets	530	577
Deferred tax liabilities, property and equipment	(2,304)	(1,969)
Deferred tax liabilities, fair value of derivative financial instruments	(50)	(33)
Deferred tax liabilities, other	(14)	(38)
Total deferred tax liabilities	(2,368)	(2,040)
Net deferred tax liability	$ (1,838)	$ (1,463)

Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Unrecognized tax benefits, Balance at beginning of year	$ 73	$ 36
Tax positions taken in prior periods	10	51
Settlements	0	(14)
Unrecognized tax benefits, Balance at end of year	$ 83	$ 73

Income Taxes (Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities) (Details)	12 Months Ended
	Dec. 31, 2023
Minimum [Member] \| United States Federal [Member]
Tax years open	2015
Maximum [Member] \| United States Federal [Member]
Tax years open	2023
Various U.S. States [Member] \| Minimum [Member]
Tax years open	2019
Various U.S. States [Member] \| Maximum [Member]
Tax years open	2023
Canada [Member] \| Minimum [Member]
Tax years open	2006
Canada [Member] \| Maximum [Member]
Tax years open	2023

Net Earnings Per Share (Net Earnings (Loss) Per Share Computations from Continuing Operations) (Details) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Net earnings available to common shareholders - basic	$ 3,747	$ 5,958	$ 2,783
Net earnings available to common shareholders - diluted	$ 3,747	$ 5,958	$ 2,783
Common shares:
Average common shares outstanding - basic	639	651	663
Dilutive effect of potential common shares issuable	3	2	2
Average common shares outstanding - diluted	642	653	665
Net earnings per share available to common shareholders:
Basic	$ 5.86	$ 9.15	$ 4.2
Diluted	$ 5.84	$ 9.12	$ 4.19

Other Comprehensive Earnings (loss) (Components Of Other Comprehensive Earnings (loss)) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Beginning accumulated pension and postretirement benefits

$ (116)

$ (132)

$ (127)

Net actuarial gain (loss) and prior service cost arising in current year

(15)

15

(35)

Recognition of net actuarial loss and prior service cost in earnings

^[1]

5

6

3

Settlement of pension benefits

^[2]

0

19

Other

^[3]

0

7

Income tax benefit (expense)

2

(5)

1

Accumulated other comprehensive loss, net of tax

$ (124)

$ (116)

$ (132)

[1]	Recognition of net actuarial loss and prior service cost are included in the computation of net periodic benefit cost, which is a component of other, net in the accompanying consolidated statements of comprehensive earnings. See Note 16 for additional details.
[2]	In 2021, the Merger triggered settlement payments to certain plan participants, and the expense associated with this settlement is recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.
[3]	Other includes a remeasurement of the pension obligation due to the Merger, which was partially offset by a change in mortality assumption.

Amount, after tax, of accumulated increase (decrease) in equity from transaction and other event and circumstance from nonowner source.

Unproved and properties under development

Supplemental Information to Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in assets and liabilities, net:
Accounts receivable	$ 191	$ (142)	$ (526)
Other current assets	95	(119)	30
Other long-term assets	(36)	90	12
Accounts payable and revenues and royalties payable	(335)	152	539
Other current liabilities	(50)	(97)	(18)
Other long-term liabilities	(9)	(110)	(153)
Total	(144)	(226)	(116)
Supplementary cash flow data - total operations:
Interest paid	378	370	404
Income taxes paid (refunded)	$ 400	$ 438	$ (116)

Supplemental Information to Statements Of Cash Flows (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Accrued capital expenditures	$ 348	$ 413	$ 205
Non-Cash Investing Activities Contributions Of Other Propoerty And Equipment	$ 150

Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Joint interest billings	$ 251	$ 162
Other	22	33
Gross accounts receivable	1,580	1,776
Allowance for doubtful accounts	(7)	(9)
Net accounts receivable	1,573	1,767
Oil, Gas and NGL Sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	965	1,153
Marketing and Midstream Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Gross accounts receivable	$ 342	$ 428

Property, Plant and Equipment (Schedule of Property and Equipment, net) (Details) - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Property and equipment:

Proved

$ 46,659

$ 42,734

1,279

1,548

Total oil and gas

47,938

44,282

Less accumulated DD&A

(30,113)

(27,715)

Oil and gas property and equipment, net

17,825

16,567

Other property and equipment

2,289

2,280

Less accumulated DD&A

(786)

(741)

Total property and equipment, net

^[1]

1,503

1,539

$ 19,328

$ 18,106

[1]	$136 million and $109 million related to CDM in 2023 and 2022, respectively.

Property, Plant and Equipment (Schedule of Property and Equipment, net) (Parenthetical) (Details) - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Property Plant And Equipment [Line Items]

Property Plant And Equipment [Line Items]

^[1]

$ 1,503

$ 1,539

CDM [Member]

$ 136

$ 109

[1]	$136 million and $109 million related to CDM in 2023 and 2022, respectively.

Property, Plant and Equipment (Summary of Changes in Suspended Exploratory Well Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Beginning balance	$ 126	$ 66	$ 18
Acquired WPX costs	0	0	34
Additions pending determination of proved reserves	522	462	206
Charges to exploration expense	(1)	(1)	(2)
Reclassifications to proved properties	(511)	(401)	(190)
Ending balance	$ 136	$ 126	$ 66

Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Net premium on debentures and notes

$ 6,121

64

$ 103

Debt issuance costs

(30)

(26)

Total debt

6,155

6,440

Less amount classified as short-term debt

483

251

Long-term debt

5,672

6,189

8.25% due August 1, 2023 [Member]

^[1]

$ 0

$ 242

Aug. 01, 2023

5.25% due September 15, 2024 [Member]

8.25%

^[1]

$ 472

Sep. 15, 2024

5.85% due December 15, 2025 [Member]

5.25%

$ 485

Dec. 15, 2025

7.50% due September 15, 2027 [Member]

5.85%

^[2]

$ 73

Sep. 15, 2027

5.25% due October 15, 2027 [Member]

7.50%

^[1]

$ 390

Oct. 15, 2027

5.875% due June 15, 2028 [Member]

5.25%

^[1]

$ 325

Jun. 15, 2028

4.50% due January 15, 2030 [Member]

5.875%

^[1]

$ 585

Jan. 15, 2030

7.875% due September 30, 2031 [Member]

4.50%

$ 675

Sep. 30, 2031

7.95% due April 15, 2032 [Member]

7.875%

$ 366

Apr. 15, 2032

5.60% due July 15, 2041 [Member]

7.95%

$ 1,250

Jul. 15, 2041

4.75% due May 15, 2042 [Member]

5.60%

$ 750

May 15, 2042

5.00% due June 15, 2045 [Member]

4.75%

$ 750

Jun. 15, 2045

5.00%

[1]

These instruments were assumed by Devon in January 2021 in conjunction with the Merger. Approximately $35 million of these instruments remain the unsecured and unsubordinated obligation of WPX, a wholly-owned subsidiary of Devon.

[2]

This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rate of this note at the time assumed was $169 million and 6.5%, respectively. This instrument is the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

Debt And Related Expenses (Schedule Of Debt Instruments and Balances) (Parenthetical) (Details) - USD ($) $ in Millions	1 Months Ended
	Apr. 30, 2003	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, gross		$ 6,121
WPX
Debt Instrument [Line Items]
Long-term debt, gross			$ 35
Ocean Energy [Member]
Debt Instrument [Line Items]
Fair value of notes assumed	$ 169
Effective interest rate of notes	6.50%

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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Debt And Related Expenses (Schedule Of Debt Maturities) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2024	$ 472
2025	485
2026	0
2027	463
2028	325
Thereafter	4,376
Total	$ 6,121

Debt And Related Expenses (Schedule of WPX Debt assumed with the Merger) (Details) - WPX	12 Months Ended
	Dec. 31, 2023
5.25% due October 15, 2027 [Member]
Debt Instrument [Line Items]
Optional Redemption	Oct. 15, 2022
5.875% due June 15, 2028 [Member]
Debt Instrument [Line Items]
Optional Redemption	Jun. 15, 2023
4.50% due January 15, 2030 [Member]
Debt Instrument [Line Items]
Optional Redemption	Jan. 15, 2025

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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1F
-Subparagraph (b)(1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1F

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1F
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1F

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Debt And Related Expenses (Narrative) (Details) $ in Millions		12 Months Ended
	Aug. 01, 2023 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 242	$ 0	$ 1,243
Early retirement of debt		0	0	30
Charge on early retirement of debt, cash retirement costs		0	$ 0	59
Credit Facility, Commitment Fee		5
Commercial paper		0
Commercial Paper [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		3,000
Senior Credit Facility [Member]
Debt Instrument [Line Items]
Credit Facility, borrowing capacity		3,000
Outstanding credit facility borrowings		0
Outstanding letters of credit		$ 3
Debt-to-capitalization ratio		0.22
Senior Credit Facility [Member] \| Maximum [Member]
Debt Instrument [Line Items]
Debt-to-capitalization ratio		0.65
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt				1,200
Early retirement of debt				30
Charge on early retirement of debt, cash retirement costs				59
Charge on early retirement of debt, noncash charges				$ 89
8.25% due August 1, 2023 [Member] \| Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 242
Debt interest rate, stated percentage	8.25%

Debt And Related Expenses (Schedule of Net Financing Cost Components) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Interest based on debt outstanding	$ 369	$ 370	$ 388
Gain on early retirement of debt	0	0	(30)
Interest income	(55)	(38)	(2)
Other	(6)	(23)	(27)
Total net financing costs	$ 308	$ 309	$ 329

Leases (Schedule of Right-of-use Assets and Lease Liabilities) (Details) - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]

Right-of-use assets

Right-of-use assets, finance lease

$ 246

$ 203

Finance lease liabilities:

Finance Lease, Liability, Current

Other current liabilities

Current lease liabilities, finance lease

^[1]

$ 21

$ 8

Finance Lease, Liability, Noncurrent

Long-term lease liabilities

Long-term lease liabilities, finance lease

$ 286

$ 249

Total lease liabilities, finance lease

^[2]

$ 307

$ 257

Operating Lease, Right-of-Use Asset

Right-of-use assets

Right-of-use assets, operating lease

$ 21

Operating lease liabilities:

Operating Lease, Liability, Current

Other current liabilities

Current lease liabilities, operating lease

^[1]

$ 12

$ 13

Operating Lease, Liability, Noncurrent

Long-term lease liabilities

Long-term lease liabilities, operating lease

$ 9

$ 8

Total lease liabilities, operating lease

^[2]

21

Right-of-use assets

267

224

Lease liabilities:

Current lease liabilities

^[1]

33

21

Long-term lease liabilities

295

257

Total lease liabilities

^[2]

$ 328

$ 278

[1]	Current lease liabilities are included in other current liabilities on the consolidated balance sheets.
[2]	Devon has entered into certain leases of equipment related to the exploration, development and production of oil and gas that had terms not yet commenced as of December 31, 2023 and are therefore excluded from the amounts shown above.

Leases (Schedule of Total Lease Cost) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Amortization of right-of-use assets

Operating lease cost

$ 13

$ 22

$ 25

Short-term lease cost

^[1]

193

140

89

9

8

Interest on lease liabilities

15

11

Variable lease cost

(5)

0

(4)

Lease income

(10)

(8)

Net lease cost

$ 225

$ 173

$ 121

[1]	Short-term lease cost excludes leases with terms of one month or less.

Leases (Schedule of Additional Lease Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Cash outflows for lease liabilities:
Operating cash flows, Finance lease	$ 15	$ 8
Investing cash flows, Finance lease	0	0
Right-of-use assets obtained in exchange for new lease liabilities, Finance lease	$ 0	$ 0
Weighted average remaining lease term (years), Finance lease	9 years 4 months 24 days	5 years
Weighted average discount rate, Finance lease	6.10%	4.20%
Operating cash flows, Operating lease	$ 13	$ 14
Investing cash flows, Operating lease	1	9
Right-of-use assets obtained in exchange for new lease liabilities, Operating lease	$ 13	$ 20
Weighted average remaining lease term (years), Operating lease	2 years 2 months 12 days	1 year 8 months 12 days
Weighted average discount rate, Operating lease	4.90%	2.80%

Leases (Maturities of Lease Liabilities) (Details) - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Present value of lease liabilities

$ 21

21

21

21

21

^[1]

372

Total lease payments

477

Less: interest

(170)

^[2]

307

$ 257

12

6

4

0

0

^[1]

0

Total lease payments

22

Less: interest

(1)

Present value of lease liabilities

^[2]

21

33

27

25

21

21

^[1]

372

Total lease payments

499

Less: interest

(171)

Present value of lease liabilities

^[2]

$ 328

$ 278

[1]	Devon has one real estate lease that contains a residual value guarantee. Under the lease terms, the residual value guarantee stipulates that if the lessor were to sell the leased property and receive sale proceeds less than 90% of the lease liability at the time of sale, Devon would be required to make a shortfall payment to the lessor for the difference.
[2]	Devon has entered into certain leases of equipment related to the exploration, development and production of oil and gas that had terms not yet commenced as of December 31, 2023 and are therefore excluded from the amounts shown above.

Leases (Maturities of Lease Liabilities) (Details) (Parenthetical)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Lease Liability Shortfall Payment Percentage	90.00%

Leases (Schedule of Expected Lease Income ) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Leases [Abstract]
2024	$ 11
2025	13
2026	13
2027	13
2028	14
Thereafter	61
Total	$ 125

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations as of beginning of period	$ 529	$ 485
Liabilities incurred	110	73
Liabilities settled and divested	(30)	(19)
Revision of estimated obligation	27	(35)
Asset retirement obligation accretion	29	25	$ 28
Asset retirement obligations as of end of period	665	529	$ 485
Less current portion	22	18
Asset retirement obligations	$ 643	$ 511

Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Acquisition [Line Items]
Increase in asset retirement obligations	$ 27	$ 38
Decrease in asset retirement obligations		$ 35

Retirement Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined contribution plans	$ 38	$ 37	$ 33
Expected benefit plan payments for each of the next five years	52
Expected total benefit plan payments for five years after the next five years	244
Benefit plan payments expected to be funded from cash and cash equivalents and other assets for next fiscal year	15
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 476	458	$ 671
Pension Benefits [Member] \| Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations	90.00%
Pension Benefits [Member] \| Fixed Income Securities [Member] \| Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 418	384
Pension Benefits [Member] \| Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target plan asset allocations	10.00%
Fair value of plan assets	$ 44	49
Pension Benefits [Member] \| Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	25
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0
Defined benefit plan health care cost trend rate assumed for next fiscal year	6.60%
Defined benefit plan ultimate health care cost trend rate	5.00%

Retirement Plans (Schedule of Changes In Defined Benefit Plan Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	$ 629	$ 880
Interest cost	34	19	$ 18
Actuarial loss (gain)	(46)	(215)
Participant contributions	0	0
Benefits paid	(54)	(55)
Benefit obligation at end of year	655	629	880
Change in plan assets:
Fair value of plan assets at beginning of year	458	671
Actual return on plan assets	(58)	(172)
Employer contributions	14	14
Participant contributions	0	0
Benefits paid	(54)	(55)
Fair value of plan assets at end of year	476	458	671
Funded status at end of year	(179)	(171)
Amounts recognized in balance sheet:
Other current liabilities	(13)	(14)
Other long-term liabilities	(166)	(157)
Net amount	(179)	(171)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	198	189
Prior service cost	0	0
Total	198	189
Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year	7	12
Actuarial loss (gain)	(1)	(4)
Participant contributions	1	1
Benefits paid	(2)	(2)
Benefit obligation at end of year	7	7	$ 12
Change in plan assets:
Fair value of plan assets at beginning of year	0
Employer contributions	1	1
Participant contributions	1	1
Benefits paid	(2)	(2)
Fair value of plan assets at end of year	0	0
Funded status at end of year	(7)	(7)
Amounts recognized in balance sheet:
Other current liabilities	(1)	(1)
Other long-term liabilities	(6)	(6)
Net amount	(7)	(7)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	(14)	(15)
Prior service cost	1	1
Total	$ (13)	$ (14)

Retirement Plans (Schedule of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Retirement Plans[Abstract]
Projected benefit obligation	$ 655	$ 629
Fair value of plan assets	$ 476	$ 458

Retirement Plans (Schedule of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Other Postretirement Benefit Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net periodic benefit cost:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Gain (Loss) on Hedging Activity	Gain (Loss) on Hedging Activity	Gain (Loss) on Hedging Activity
Pension Benefits [Member]
Net periodic benefit cost:
Interest cost	$ 34	$ 19	$ 18
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(27)	(31)	(34)
Recognition of net actuarial loss (gain)	6	6	4
Total net periodic benefit cost	13	(6)	(12)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year	16	(11)	28
Recognition of net actuarial (loss) gain, including settlement expense, in net periodic benefit cost	(6)	(6)	(23)
Total other comprehensive loss (earnings)	10	(17)	5
Total	23	(23)	(7)
Postretirement Benefits [Member]
Net periodic benefit cost:
Recognition of net actuarial loss (gain)	(1)	(1)	(1)
Total net periodic benefit cost	(1)	(1)	(1)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year	0	(4)	(1)
Prior service cost arising in current year			1
Recognition of net actuarial (loss) gain, including settlement expense, in net periodic benefit cost	1	1	1
Total other comprehensive loss (earnings)	(1)	(3)	$ 1
Total	$ 0	$ (4)

Retirement Plans (Schedule of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	5.01%	5.78%	2.71%
Assumptions to determine net periodic benefit cost:
Discount rate - interest cost	5.61%	2.18%	2.11%
Expected return on plan assets	6.21%	4.80%	5.00%
Postretirement Benefits [Member]
Assumptions to determine benefit obligations:
Discount rate	4.96%	5.71%	2.34%
Assumptions to determine net periodic benefit cost:
Discount rate - service cost	5.81%	2.83%	2.51%
Discount rate - interest cost	5.49%	1.57%	1.01%

Stockholders' Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended			3 Months Ended													12 Months Ended
	May 04, 2023	Feb. 29, 2024	May 31, 2023	Nov. 30, 2021	Mar. 31, 2024	Dec. 30, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2021	Feb. 28, 2024	Dec. 31, 2023	May 31, 2022
Stockholders Equity [Abstract]
Common stock, shares authorized (in shares)										1,000,000,000										1,000,000,000
Common stock, par value (in dollars per share)										$ 0.1										$ 0.1
Preferred Stock, Shares Authorized																				4,500,000
Preferred Stock, Par or Stated Value Per Share																				$ 1
Dividends rate per share						$ 0.77	$ 0.49	$ 0.72	$ 0.89	$ 1.35	$ 1.55	$ 1.27	$ 1	$ 0.84	$ 0.49	$ 0.34	$ 0.3
Fixed Dividend [Member]
Stockholders Equity [Abstract]
Dividends rate per share																		$ 0.11
Subsequent Event
Stockholders Equity [Abstract]
Dividend payable amount																			$ 280
Dividends payable, per share																			$ 0.44
Subsequent Event \| Fixed Dividend [Member]
Stockholders Equity [Abstract]
Percentage of increase to quarterly dividend		10.00%
Dividends rate per share		$ 0.22			$ 0.22
Dividends payable, per share																			0.22
Subsequent Event \| Variable Dividend [Member]
Stockholders Equity [Abstract]
Dividends payable, per share																			$ 0.22
Share Repurchase Program [Member]
Stockholders Equity [Abstract]
Share-repurchase program, authorized amount				$ 1,000																	$ 2,000
Share-repurchase program expiration date	May 04, 2023			Dec. 31, 2022
Three Billion Dollar Share Repurchase Program Open [Member]
Stockholders Equity [Abstract]
Share-repurchase program, authorized amount			$ 3,000
Share-repurchase program expiration date			Dec. 31, 2024

Stockholders' Equity (Summary of Purchases of Common Stock) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
3.0 Billion Dollar Share Repurchase Program Closed Member
Stockholders Equity [Line Items]
Total Number of Shares Purchased	19,350	11,708	13,983
Dollar Value of Shares Purchased	$ 992	$ 718	$ 589
Average Price Paid per Share	$ 51.23	$ 61.36	$ 42.15
Share Repurchase Program Open [Member]
Stockholders Equity [Line Items]
Total Number of Shares Purchased	45,041
Dollar Value of Shares Purchased	$ 2,299
Average Price Paid per Share	$ 51.05

Stockholders' Equity (Summary Of Dividends Paid On Common Stock) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 30, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Stockholders Equity [Line Items]
Dividends amount	$ 488	$ 312	$ 462	$ 596	$ 875	$ 1,007	$ 830	$ 667	$ 554	$ 329	$ 229	$ 203	$ 1,858	$ 3,379	$ 1,315
Dividends rate per share	$ 0.77	$ 0.49	$ 0.72	$ 0.89	$ 1.35	$ 1.55	$ 1.27	$ 1	$ 0.84	$ 0.49	$ 0.34	$ 0.3
Fixed Dividend [Member]
Stockholders Equity [Line Items]
Dividends amount	$ 127	$ 127	$ 128	$ 133	$ 117	$ 117	$ 105	$ 109	$ 73	$ 74	$ 75	$ 76	515	448	$ 298
Dividends rate per share															$ 0.11
Variable Dividend [Member]
Stockholders Equity [Line Items]
Dividends amount	$ 361	$ 185	$ 334	$ 463	$ 758	$ 890	$ 725	$ 558	$ 481	$ 255	$ 154	$ 127	$ 1,343	$ 2,931	$ 1,017

Commitments and Contingencies (Schedule of Commitments and Contingencies) (Details)
$ in Millions

Dec. 31, 2023

USD ($)

Drilling and Facility Obligations [Member]

Long Term Purchase Commitment [Line Items]

2024

$ 190

^[1]

2025

25

^[1]

2026

19

^[1]

2027

23

^[1]

2028

35

^[1]

Thereafter

4

^[1]

Total

296

^[1]

Operational Agreements [Member]

Long Term Purchase Commitment [Line Items]

2024

523

^[1]

2025

550

^[1]

2026

514

^[1]

2027

384

^[1]

2028

362

^[1]

Thereafter

1,132

^[1]

Total

3,465

^[1]

Office and Equipment Leases and Other [Member]

Long Term Purchase Commitment [Line Items]

103

83

58

42

37

432

$ 755

[1]	Total costs incurred under take-or-pay and throughput obligations were approximately $750 million, $650 million and $500 million in 2023, 2022 and 2021, respectively.

Commitments and Contingencies - (Schedule of Commitments and Contingencies) (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Long-Term Purchase Commitment [Line Items]
Cost of take-or-pay and throughput obligations	$ 750	$ 650	$ 500

Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	$ 306	$ 708
Debt	(6,155)	(6,440)
Contingent earnout payments	55	157
Carrying Amount [Member] \| Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	208	131
Derivatives, liabilities	(9)	(3)
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	306	708
Debt	(6,090)	(6,231)
Contingent earnout payments	55	157
Total Fair Value [Member] \| Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	208	131
Derivatives, liabilities	(9)	(3)
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	306	708
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	(6,090)	(6,231)
Level 2 Inputs [Member] \| Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	208	131
Derivatives, liabilities	(9)	(3)
Level 3 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent earnout payments	$ 55	$ 157

Supplemental Information on Oil and Gas Operations (Unaudited) (Costs Incurred) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property acquisition costs:
Proved properties	$ 2	$ 1,760	$ 7,017
Unproved properties	63	803	2,381
Exploration costs	534	472	212
Development costs	3,160	2,132	1,643
Costs incurred	$ 3,759	$ 5,167	$ 11,253

Supplemental Information on Oil and Gas Operations (Unaudited) (Results Of Operations) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / Boe	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
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 \| $ / Boe	10.27	9.52	9.83

Supplemental Information on Oil and Gas Operations (Unaudited) (Proved Developed and Undeveloped Reserves) (Details)
MMcf in Thousands, MMBbls in Thousands

12 Months Ended

Dec. 31, 2023

MMBoe

MMcfe

MMBbls

MMcf

Dec. 31, 2022

MMBoe

MMBbls

MMcf

Dec. 31, 2021

MMBoe

MMBbls

MMcf

Dec. 31, 2020

MMBoe

MMBbls

MMcf

Proved developed and undeveloped reserves, beginning balance | MMBoe

1,815

1,625

752

Proved developed and undeveloped reserves, revisions due to prices | MMBoe

(78)

34

155

Proved developed and undeveloped reserves, revisions other than price | MMBoe

(1)

(49)

43

Proved developed and undeveloped reserves, extensions and discoveries | MMBoe

322

278

228

Proved developed and undeveloped reserves, Purchase of reserves | MMBoe

153

663

Proved developed and undeveloped reserves, production | MMBoe

(240)

(223)

(209)

Proved developed and undeveloped reserves, sale of reserves | MMBoe

(1)

(3)

(7)

Proved developed and undeveloped reserves, ending balance

1,817

1,815

1,625

Proved developed reserves | MMBoe

1,425

1,419

1,285

574

Proved developed producing reserves | MMBoe

1,390

1,397

1,260

564

Proved undeveloped reserves | MMBoe

392

396

340

178

Conversion rate of gas reserves from barrels of oil to Boe

6

Oil [Member]

Proved developed and undeveloped reserves, beginning balance

793

709

282

Proved developed and undeveloped reserves, revisions due to prices

(25)

15

55

Proved developed and undeveloped reserves, revisions other than price

(12)

(55)

(23)

Proved developed and undeveloped reserves, extensions and discoveries

147

127

112

Proved developed and undeveloped reserves, Purchase of reserves

106

393

Proved developed and undeveloped reserves, production

(117)

(109)

(106)

Proved developed and undeveloped reserves, sale of reserves

0

(4)

Proved developed and undeveloped reserves, ending balance

786

793

709

Proved developed reserves

603

596

544

194

Proved developed producing reserves

586

585

533

190

Proved undeveloped reserves

183

197

165

88

Natural Gas [Member]

Proved developed and undeveloped reserves, beginning balance | MMcf

^[1]

3,175,000

2,878,000

1,512,000

Proved developed and undeveloped reserves, revisions due to prices

^[1]

(189,000)

61,000

382,000

Proved developed and undeveloped reserves, revisions other than price | MMcf

^[1]

58,000

13,000

11,000

Proved developed and undeveloped reserves, extensions and discoveries | MMcf

^[1]

525,000

449,000

348,000

Proved developed and undeveloped reserves, Purchase of reserves | MMcf

^[1]

137,000

961,000

Proved developed and undeveloped reserves, production | MMcf

^[1]

(385,000)

(356,000)

(325,000)

Proved developed and undeveloped reserves, sale of reserves | MMcf

^[1]

(2,000)

(7,000)

(11,000)

Proved developed and undeveloped reserves, ending balance

^[1]

3,182,000

3,175,000

2,878,000

Proved developed reserves | MMcf

^[1]

2,560,000

2,595,000

2,361,000

1,244,000

Proved developed producing reserves | MMcf

^[1]

2,505,000

2,553,000

2,316,000

1,223,000

Proved undeveloped reserves | MMcf

^[1]

622,000

580,000

517,000

268,000

Natural Gas Liquids [Member]

Proved developed and undeveloped reserves, beginning balance

493

437

218

Proved developed and undeveloped reserves, revisions due to prices

(22)

8

36

Proved developed and undeveloped reserves, revisions other than price

1

3

64

Proved developed and undeveloped reserves, extensions and discoveries

87

76

58

Proved developed and undeveloped reserves, Purchase of reserves

24

110

Proved developed and undeveloped reserves, production

(59)

(54)

(48)

Proved developed and undeveloped reserves, sale of reserves

0

(1)

Proved developed and undeveloped reserves, ending balance

500

493

437

Proved developed reserves

395

391

348

173

Proved developed producing reserves

386

387

341

171

Proved undeveloped reserves

105

102

89

45

[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.

Supplemental Information on Oil and Gas Operations (Unaudited) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) MMBoe $ / bbl $ / Mcf	Dec. 31, 2022 USD ($) MMBoe	Dec. 31, 2021 USD ($) MMBoe	Dec. 31, 2026 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices	(78)	34	155
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	(1)	(49)	43
Proved developed reserve net energy period increase decrease	11
Proved developed and undeveloped reserves, additional downward revisions other than price(MMBoe)	(12)		10
Proved developed and undeveloped reserves, extensions and discoveries	322	278	228
Proved developed and undeveloped reserves revisions due to change in previously adopted development plans	(8)
Proved developed and undeveloped reserves, Purchase of reserves		153	663
Proved undeveloped reserves increased percentage	1.00%
Proved undeveloped reserves as percentage of entire proved reserves	22.00%
Proved undeveloped reserves due to drilling and development activities (MMBoe)	177
Conversion to proved developed reserves	165
Cost incurred related to development and conversion of proved undeveloped reserves \| $	$ 1,500
Proved Undeveloped Reserves Revisions with Additional Revisions	(4)
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves \| $ / bbl	76.29
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves \| $ / Mcf	1.74
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves \| $ / bbl	20.43
Future development costs \| $	$ 5,241	$ 5,176	$ 3,689
Future dismantlement, abandonment and rehabilitation costs \| $	$ 900
Scenario Forecast [Member]
Reserve Quantities [Line Items]
Future development costs \| $				$ 800	$ 1,000	$ 1,800
Maximum [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)			53
Delaware Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	7	33	23
Proved developed and undeveloped reserves, extensions and discoveries	212	255	209
Proved developed and undeveloped reserves, Purchase of reserves			538
Proved undeveloped reserves percentage	78.00%
Percentage of extensions and discoveries proved undeveloped reserves	59.00%
Proved undeveloped reserves revisions other than price	(2)
Proved Undeveloped Reserves Revisions with Additional Revisions	(2)
Williston Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	(19)		12
Proved developed and undeveloped reserves, extensions and discoveries	19	5	6
Proved developed and undeveloped reserves, Purchase of reserves		66	125
Percentage of extensions and discoveries proved undeveloped reserves	4.00%
Proved undeveloped reserves revisions other than price	(5)
Proved Undeveloped Reserves Revisions with Additional Revisions	(1)
STACK [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	4		12
Proved developed and undeveloped reserves, extensions and discoveries		5	8
Eagle Ford [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	5
Proved developed and undeveloped reserves, extensions and discoveries	32	6	3
Proved developed and undeveloped reserves, Purchase of reserves		87
Percentage of extensions and discoveries proved undeveloped reserves	12.00%
Proved Undeveloped Reserves Revisions with Additional Revisions	(1)
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)	2	5
Proved developed and undeveloped reserves, extensions and discoveries	26	7	2
Percentage of extensions and discoveries proved undeveloped reserves	11.00%
Proved undeveloped reserves revisions other than price	(1)
Anadarko Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions other than price (MMBoe)		4
Proved developed and undeveloped reserves, extensions and discoveries	33
Percentage of extensions and discoveries proved undeveloped reserves	14.00%

Supplemental Information on Oil and Gas Operations (Unaudited) (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2023 MMBoe
Reserve Quantities [Line Items]
Proved undeveloped reserves (MMBoe) beginning balance	396
Extensions and discoveries	177
Revisions due to prices	(4)
Revisions other than price	(12)
Conversion to proved developed reserves	(165)
Proved undeveloped reserves (MMBoe) ending balance	392

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.