APA (APA) 10-K 28 Feb 25 2024 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2024	Jan. 31, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-40144
Entity Registrant Name	APA CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	86-1430562
Entity Address, Address Line One	2000 W. Sam Houston Pkwy. S., Suite 200
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042-3643
City Area Code	713
Local Phone Number	296-6000
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 10,887,671,670
Entity Common Stock, Shares Outstanding		364,064,316
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the registrant’s 2025 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Entity Central Index Key	0001841666

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas
Auditor Firm ID	42

STATEMENT OF CONSOLIDATED OPERA

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
REVENUES AND OTHER:
Derivative instrument gains (losses), net		$ (10)	$ 99	$ (114)
Gain on divestitures, net		289	8	1,180
Losses on previously sold Gulf of America properties		(273)	(212)	(157)
Other, net		(6)	18	148
Total revenues and other		9,737	8,192	12,132
OPERATING EXPENSES:
Lease operating expenses	[1]	1,690	1,436	1,444
Taxes other than income		270	207	268
Exploration		313	195	305
General and administrative		372	351	483
Transaction, reorganization, and separation		168	15	26
Depreciation, depletion, and amortization		2,266	1,540	1,233
Asset retirement obligation accretion		148	116	117
Impairments		1,129	61	0
Financing costs, net		367	312	379
Total operating expenses		8,202	5,309	6,398
NET INCOME BEFORE INCOME TAXES		1,535	2,883	5,734
Current income tax provision		1,153	1,338	1,507
Deferred income tax provision (benefit)		(736)	(1,662)	145
NET INCOME INCLUDING NONCONTROLLING INTERESTS		1,118	3,207	4,082
Net loss attributable to Altus Preferred Unit limited partners		0	0	(70)
NET INCOME ATTRIBUTABLE TO COMMON STOCK		$ 804	$ 2,855	$ 3,674
NET INCOME PER COMMON SHARE:
Basic (in USD per share)		$ 2.28	$ 9.26	$ 11.05
Diluted (in USD per share)		$ 2.27	$ 9.25	$ 11.02
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)		353	308	332
Diluted (in shares)		353	309	333
Noncontrolling interest - Egypt
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		$ 314	$ 352	$ 464
Noncontrolling interest - Altus
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		0	0	14
Oil and gas
REVENUES AND OTHER:
Total revenues		9,737	8,279	11,075
Oil and gas, excluding purchased
REVENUES AND OTHER:
Total revenues	[1]	8,196	7,385	9,220
OPERATING EXPENSES:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	432	334	367
Purchased oil and gas costs
REVENUES AND OTHER:
Total revenues	[1]	1,541	894	1,855
OPERATING EXPENSES:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	$ 1,047	$ 742	$ 1,776
[1] (1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

STATEMENT OF CONSOLIDATED COMPR

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 1,118	$ 3,207	$ 4,082
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Pension and postretirement benefit plan	(3)	1	(8)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	1,115	3,208	4,074
Comprehensive loss attributable to Altus Preferred Unit limited partners	0	0	(70)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	801	2,856	3,666
Noncontrolling interest - Egypt
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	314	352	464
Noncontrolling interest - Altus
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	$ 0	$ 0	$ 14

STATEMENT OF CONSOLIDATED CASH

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$ 1,118	$ 3,207	$ 4,082
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	8	(51)	67
Gain on divestitures, net	(289)	(8)	(1,180)
Exploratory dry hole expense and unproved leasehold impairments	236	114	207
Depreciation, depletion, and amortization	2,266	1,540	1,233
Asset retirement obligation accretion	148	116	117
Impairments	1,129	61	0
Provision for (benefit from) deferred income taxes	(736)	(1,662)	145
(Gain) loss from extinguishment of debt	0	(9)	67
Losses on previously sold Gulf of America properties	273	212	157
Other	2	26	(73)
Changes in operating assets and liabilities:
Receivables	(104)	(157)	(93)
Inventories	(11)	13	(1)
Drilling advances and other current assets	(56)	269	(15)
Deferred charges and other long-term assets	11	270	69
Accounts payable	81	(84)	(4)
Accrued expenses	(221)	(400)	303
Deferred credits and noncurrent liabilities	(235)	(328)	(138)
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,620	3,129	4,943
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,851)	(2,313)	(1,770)
Acquisition of Delaware Basin properties	0	(24)	(591)
Leasehold and property acquisitions	(60)	(20)	(37)
Proceeds from asset divestitures	1,609	29	778
Proceeds from sale of Kinetik shares	428	228	224
Deconsolidation of Altus cash and cash equivalents	0	0	(143)
Other, net	(50)	(38)	28
NET CASH USED IN INVESTING ACTIVITIES	(924)	(2,138)	(1,511)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) commercial paper and revolving credit facilities, net	(40)	(194)	24
Proceeds from term loan facility	1,500	0	0
Payments on term loan facility	(600)	0	0
Payment on Callon Credit Agreement	(472)	0	0
Payments on fixed-rate debt	(1,641)	(65)	(1,493)
Distributions to noncontrolling interest	(268)	(238)	(362)
Dividends paid to APA common stockholders	(353)	(308)	(207)
Treasury stock activity, net	(246)	(329)	(1,423)
Other, net	(38)	(15)	(28)
NET CASH USED IN FINANCING ACTIVITIES	(2,158)	(1,149)	(3,489)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	538	(158)	(57)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	87	245	302
CASH AND CASH EQUIVALENTS AT END OF PERIOD	625	87	245
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	372	329	322
Income taxes paid, net of refunds	$ 1,097	$ 1,271	$ 1,431

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
CURRENT ASSETS:
Cash and cash equivalents	$ 625	$ 87
Receivables, net of allowance of $123 and $114	1,959	1,610
Other current assets (Note 5)	820	765
Total current assets	3,404	2,462
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:	44,698	44,860
Gathering, processing, and transmission facilities	433	448
Other	562	634
Less: Accumulated depreciation, depletion, and amortization	(33,047)	(35,904)
Property and equipment, net	12,646	10,038
OTHER ASSETS:
Equity method interests (Note 6)	0	437
Decommissioning security for sold Gulf of America properties (Note 11)	21	21
Deferred tax asset (Note 10)	2,703	1,758
Deferred charges and other	616	528
Assets	19,390	15,244
CURRENT LIABILITIES:
Accounts payable	1,224	658
Current debt	53	2
Other current liabilities (Note 7)	1,678	1,744
Total current liabilities	2,955	2,404
LONG-TERM DEBT (Note 9)	5,991	5,186
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 10)	14	371
Asset retirement obligation (Note 8)	2,591	2,362
Decommissioning contingency for sold Gulf of America properties (Note 11)	929	764
Other	548	466
Total deferred credits and other noncurrent liabilities	4,082	3,963
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 491,579,646 and 420,595,901 shares issued, respectively	307	263
Paid-in capital	13,153	11,126
Accumulated deficit	(2,155)	(2,959)
Treasury stock, at cost, 126,182,497 and 117,020,000 shares, respectively	(6,037)	(5,790)
Accumulated other comprehensive income	12	15
APA SHAREHOLDERS’ EQUITY	5,280	2,655
TOTAL EQUITY	6,362	3,691
TOTAL LIABILITIES AND EQUITY	19,390	15,244
Noncontrolling interest - Egypt
EQUITY:
Noncontrolling interest	$ 1,082	$ 1,036

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Receivables, allowance	$ 123	$ 114
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	860,000,000	860,000,000
Common stock, shares issued (in shares)	491,579,646	420,595,901
Treasury stock, shares (in shares)	126,182,497	117,020,000

STATEMENT OF CONSOLIDATED CHANG

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	Noncontrolling interest - Egypt	Noncontrolling interest - Altus	APA SHAREHOLDERS’ EQUITY	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	Noncontrolling Interests	Noncontrolling Interests Noncontrolling interest - Egypt	Noncontrolling Interests Noncontrolling interest - Altus	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Beginning balance at Dec. 31, 2021													$ 712
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners													(70)
Deconsolidation of Altus			$ (72)									$ (72)	(642)
Ending balance at Dec. 31, 2022													0
Beginning balance at Dec. 31, 2021	$ (717)			$ (1,595)	$ 262	$ 11,645	$ (9,488)	$ (4,036)	$ 22	$ 878
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	3,674			3,674			3,674
Net income attributable to noncontrolling interest		$ 464	14								$ 464	14
Distributions to noncontrolling interest		(362)									(362)
Common dividends	(245)			(245)		(245)
Common stock activity, net	(6)			(6)		(6)
Deconsolidation of Altus			(72)									$ (72)	(642)
Treasury stock activity, net	(1,423)			(1,423)				(1,423)
Compensation expense	26			26		26
Other	(8)			(8)					(8)
Ending balance at Dec. 31, 2022	1,345			423	262	11,420	(5,814)	(5,459)	14	922
Ending balance at Dec. 31, 2023													0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	2,855			2,855			2,855
Net income attributable to noncontrolling interest		352	0								352
Distributions to noncontrolling interest		(238)									(238)
Common dividends	(308)			(308)		(308)
Common stock activity, net	(13)			(13)	1	(14)
Treasury stock activity, net	(331)			(331)				(331)
Compensation expense	23			23		23
Other	6			6		5			1
Ending balance at Dec. 31, 2023	3,691			2,655	263	11,126	(2,959)	(5,790)	15	1,036
Ending balance at Dec. 31, 2024													$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	804			804			804
Net income attributable to noncontrolling interest		314	$ 0								314
Distributions to noncontrolling interest		$ (268)									$ (268)
Common dividends	(352)			(352)		(352)
Issuance of common stock	2,414			2,414	44	2,370
Treasury stock activity, net	(247)			(247)				(247)
Compensation expense	26			26		26
Other	(20)			(20)		(17)			(3)
Ending balance at Dec. 31, 2024	$ 6,362			$ 5,280	$ 307	$ 13,153	$ (2,155)	$ (6,037)	$ 12	$ 1,082

STATEMENT OF CONSOLIDATED CHA_2

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares	3 Months Ended		12 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.125	$ 1	$ 1	$ 0.75

NATURE OF OPERATIONS

NATURE OF OPERATIONS	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of operations	Nature of Operations

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below. Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. During the quarter ended March 31, 2024 and each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail. Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 10—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of America (refer to Note 11—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 17—Supplemental Oil and Gas Disclosures (Unaudited) ). Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). Refer to Note 4—Derivative Instruments and Hedging Activities , Note 9—Debt and Financing Costs , and Note 12—Retirement and Deferred Compensation Plans for further detail regarding the Company’s fair value measurements recorded on a recurring basis. The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment or when allocating the purchase price for acquired assets and liabilities in a business combination. During 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. As a result, in the third quarter of 2024 the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea. Accordingly, the Company recognized impairments of $796 million on certain proved properties in the North Sea, which were written down to their estimated fair values as of September 30, 2024. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.” On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired, and liabilities assumed be recognized at their fair values as of the acquisition date, using various Level 3 fair value measurements. Material assets and liabilities acquired are discussed further below: • The most significant assumptions relate to the estimated fair values assigned to proved oil and natural gas properties. The fair value of proved oil and natural gas properties as of the acquisition date were estimated using the income approach, where fair value was determined based on the expected future cash flows from estimated proved oil, natural gas, and NGL reserves and related discounted future net cash flows as of that date. Significant inputs to the fair value estimate included estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted-average cost of capital discount rate. • The fair value of unproved properties was estimated mainly using the market approach, based on acreage costs in areas where Callon acreage was acquired. • The fair value of most other current assets and current liabilities were determined to be equivalent to the carrying value due to their short-term nature. • The fair value of debt was based on the estimated cost to retire Callon’s debt instruments. • Estimated deferred taxes were based on available information concerning the fair values assigned to acquired assets and liabilities and their respective tax basis and tax-related carryforwards at the acquisition date. Refer to Note 2 — Acquisitions and Divestitures for further detail regarding the Company’s fair value measurements recorded related to the Callon acquisition. Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail. For the years ended December 31, 2023 and 2022, the Company recorded $11 million and no asset impairments, respectively, in connection with fair value assessments. Revenue Recognition The Company’s oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third parties to provide flexibility to fulfill sales obligations and commitments. Under these commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title. APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Refer to Note 16—Business Segment Information for a disaggregation of revenue by product and reporting segment. Payment Terms and Contract Balances Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.7 billion and $1.5 billion as of December 31, 2024 and 2023, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout 2024, and management believes that the Company will be able to collect the total balance of its receivables from this customer. In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period. Cash and Cash Equivalents The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2024 and 2023, the Company had $625 million and $87 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2024 and 2023. Accounts Receivable and Allowance for Credit Losses Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2024 2023 2022 (In millions) Allowance for credit loss at beginning of year $ 114 $ 117 $ 109 Additional provisions for the year 9 16 9 Uncollectible accounts written off, net of recoveries — (19) (1) Allowance for credit loss at end of year $ 123 $ 114 $ 117 Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. During 2024, the Company recorded $18 million of inventory impairments, including $13 million in the North Sea and $5 million in the U.S. The Company also recorded other impairments during 2023 of approximately $50 million in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date. Oil and Gas Property The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations. The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2024 2023 2022 (In millions) Proved properties: U.S. $ 315 $ — $ — Egypt — — — North Sea 796 — — Total proved properties $ 1,111 $ — $ — Unproved properties: U.S. $ 34 $ 10 $ 20 Egypt — — 4 North Sea — 11 — Other International 1 1 — Total unproved properties $ 35 $ 22 $ 24 Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost. Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $796 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million. Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail. For the years ended December 31, 2023, and 2022, the Company recorded no impairments of proved properties. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $433 million and $448 million at December 31, 2024 and 2023, respectively, with accumulated depreciation for these assets totaling $364 million and $373 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. For the years ended December 31, 2024, 2023, and 2022, the Company recorded no impairments of GPT facilities. Other Property and Equipment Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $183 million and $217 million at December 31, 2024 and 2023, respectively. Asset Retirement Costs and Obligations The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets. Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation. Equity Method Interests The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company. Refer to Note 6—Equity Method Interests for further details of the Company’s equity method interests. Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Commitments and Contingencies Accruals for loss contingencies arising from claims, assessments, litigation, environmental, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 11—Commitments and Contingencies . Derivative Instruments and Hedging Activities The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 4—Derivative Instruments and Hedging Activities for further information. Income Taxes The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. Refer to Note 10—Income Taxes for further information. Earnings Per Share The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. Stock-Based Compensation The Company grants various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on the Company’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s stock-based compensation plans and related accounting policies are defined and described more fully in Note 13—Capital Stock . Treasury Stock The Company follows the weighted-average-cost method of ac

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2024 Activity Callon Petroleum Company Acquisition On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt. The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024. The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction based on the value of APA common stock on the day of closing, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE. In addition to the equity consideration provided, APA transferred approximately $24 million in other consideration upon close of the transaction. Upon completing the acquisition, APA repaid all of Callon’s debt, refinancing a portion by borrowing $1.5 billion under its unsecured committed term loan facility. Refer to Note 9—Debt and Financing Costs for further detail. Recording of Assets Acquired and Liabilities Assumed The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. (In millions) Current assets $ 287 Property and equipment 4,502 Deferred tax asset 565 Other assets 12 Total assets acquired $ 5,366 Current liabilities $ 632 Long-term debt 2,113 Asset retirement obligation 136 Other long-term obligations 48 Total liabilities assumed $ 2,929 Net assets acquired $ 2,437 The following unaudited pro forma combined results for the years ended December 31, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, and estimated tax impacts of the pro forma adjustments. For the Year Ended December 31, 2024 2023 (In millions) Revenues $ 10,300 $ 10,578 Net income attributable to common stock 909 4,021 Net income per common share – basic 2.45 10.66 Net income per common share – diluted 2.45 10.63 From the date of the acquisition through December 31, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $1.2 billion and $262 million, respectively. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated. The unaudited pro forma results are also not intended to be a projection of future results and do not include any future cost savings or other synergies that may result from the Callon acquisition or any estimated costs that have not yet been incurred. U.S. Divestitures On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $1.1 billion and associated asset retirement obligation of $224 million for total cash proceeds of $869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf. The effective date of the transaction is July 1, 2024. As a result of the transaction, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $315 million to the carrying value of the associated oil and gas properties during the third quarter of 2024. During the fourth quarter of 2024, the Company recorded a loss of $5 million upon closing of the transaction. During 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $255 million and the assumption of asset retirement obligations of $42 million. The Company recognized a $50 million loss during 2024 in association with this sale. During 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $394 million subject to post-closing adjustments. The Company recognized a gain of $321 million during 2024 in association with this sale. Additionally, during 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $91 million, recognizing a gain of approximately $22 million upon closing of these transactions. Sale of Kinetik Shares On March 18, 2024, the Company sold its remaining Kinetik Class A Common Stock (Kinetik Shares) for cash proceeds of $428 million. Refer to Note 6—Equity Method Interests for further detail. Leasehold and Property Acquisitions During 2024, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $60 million. 2023 Activity Sale of Kinetik Shares In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $228 million. Refer to Note 6—Equity Method Interests for further detail. Leasehold and Property Acquisitions During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $20 million. U.S. Divestitures During 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $29 million, recognizing an aggregate gain of approximately $8 million upon closing of these transactions. 2022 Activity During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations. During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million. During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million, recognizing an aggregate gain of approximately $36 million, upon closing of these transactions. During 2022, the Company completed the sale of certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million. The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s $193 million net effect of deconsolidating ALTM’s balance sheet and the $802 million fair value of the Company’s approximate 20 percent retained ownership in the combined entity. During the first quarter of 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 6—Equity Method Interests for further detail.

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	CAPITALIZED EXPLORATORY WELL COSTS The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2024, 2023, and 2022. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. For the Year Ended December 31, 2024 2023 2022 (In millions) Capitalized well costs at beginning of year $ 586 $ 474 $ 321 Additions pending determination of proved reserves 240 265 287 Reclassifications to proved properties (506) (135) (110) Charged to exploration expense (83) (18) (24) Capitalized well costs at end of year $ 237 $ 586 $ 474 The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31: 2024 2023 2022 (In millions) Exploratory well costs capitalized for a period of one year or less $ 107 $ 156 $ 215 Exploratory well costs capitalized for a period greater than one year 130 430 259 Capitalized well costs at end of year $ 237 $ 586 $ 474 Number of projects with exploratory well costs capitalized for a period greater than one year 12 33 21 Projects with exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Exploratory well costs capitalized for a period greater than one year since completion of drilling were $130 million at December 31, 2024, with $115 million related to Suriname exploration and appraisal. Ongoing analysis of well results and appraisal activity is continuing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is being performed. Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2023 totaled $52 million. These expenses pertained to projects in Suriname and Egypt. The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2024, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2023 2022 2021 and Prior (In millions) Suriname $ 115 $ 60 $ — $ 55 Egypt 15 15 — — $ 130 $ 75 $ — $ 55

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Objectives and Strategies The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices. The Company elected not to designate any of its derivative contracts as cash flow hedges. Embedded Derivatives As a result of the Callon acquisition, the Company assumed an earn-out obligation from Callon, where the Company could be required to pay up to $25 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for the 2025 calendar year. The Company determined that the earn-out obligation is not clearly and closely related to the underlying agreements and therefore bifurcated this embedded feature and recorded the derivative at fair value. The Company uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing an option pricing model method provided by a reputable third party. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered a Level 2 fair value measurement. Derivative Activity Recorded in the Consolidated Balance Sheet All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: For the Year Ended December 31, 2024 2023 (In millions) Current Assets: Other current assets $ — $ 6 Total derivative assets $ — $ 6 Deferred Credits and Other Noncurrent Liabilities: Other $ 18 $ — Total derivative liabilities $ 18 $ — Derivative Activity Recorded in the Statement of Consolidated Operations The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: For the Year Ended December 31, 2024 2023 2022 (In millions) Realized: Commodity derivative instruments $ 2 $ 48 $ (34) Contingent consideration arrangements (4) — — Foreign currency derivative instruments — — (13) Realized gains (losses), net (2) 48 (47) Unrealized: Commodity derivative instruments (6) 51 (36) Contingent consideration arrangements (2) — — Preferred Units embedded derivative — — (31) Unrealized gains (losses), net (8) 51 (67) Derivative instrument gains (losses), net $ (10) $ 99 $ (114) Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2024
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS The following table provides detail of the Company’s other current assets as of December 31: 2024 2023 (In millions) Inventories $ 425 $ 453 Drilling advances 184 88 Prepaid assets and other 54 46 Current decommissioning security for sold Gulf of America assets 157 178 Total Other current assets $ 820 $ 765

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
EQUITY METHOD INTERESTS	EQUITY METHOD INTERESTS As of December 31, 2023, the Company held 13.1 million Kinetik Shares, which were recorded at fair value of $437 million and reflected separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option for measuring its equity method interest in Kinetik. The fair value of the Company’s interest in Kinetik was determined using observable share prices on a major exchange, a Level 1 fair value measurement. On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. Prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $9 million during 2024, and gains of $41 million and $72 million during 2023 and 2022, respectively. These gains and losses are recorded in the statement of consolidated operations and reflected in “Other, net” under “Revenues and other.” The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors: For the Year Ended December 31, 2024 2023 2022 (In millions) Natural gas and NGLs sales $ 13 $ 92 $ 18 Purchased oil and gas sales 22 29 — $ 35 $ 121 $ 18 Gathering, processing, and transmission costs $ 23 $ 108 $ 93 Purchased oil and gas costs 23 80 — Lease operating expenses 2 7 — $ 48 $ 195 $ 93

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
OTHER CURRENT LIABILITIES	OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities as of December 31: 2024 2023 (In millions) Accrued operating expenses $ 204 $ 162 Accrued exploration and development 460 371 Accrued compensation and benefits 223 390 Accrued interest 93 93 Accrued income taxes 221 138 Current asset retirement obligation 103 76 Current operating lease liability 118 116 Current decommissioning contingency for sold Gulf of America properties 88 60 Other 168 338 Total Other current liabilities $ 1,678 $ 1,744

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATION	ASSET RETIREMENT OBLIGATION The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2024 and 2023: For the Year Ended December 31, 2024 2023 (In millions) Asset retirement obligation at beginning of the year $ 2,438 $ 1,995 Liabilities incurred 15 14 Liabilities acquired 136 — Liabilities divested (272) — Liabilities settled (70) (43) Accretion expense 148 116 Revisions in estimated liabilities 299 356 Asset retirement obligation at end of the year 2,694 2,438 Less current portion (103) (76) Asset retirement obligation, long-term $ 2,591 $ 2,362 The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
DEBT AND FINANCING COSTS	DEBT AND FINANCING COSTS Overview The debt of APA and Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. As of December 31, 2024, (i) all indentures of Apache for the notes and debentures described below placed certain restrictions on Apache, including limits on Apache’s ability to incur debt secured by certain liens, and (ii) certain of those indentures also restricted Apache’s ability to enter into certain sale and leaseback transactions and gave holders the option to require Apache to repurchase outstanding notes and debentures upon certain changes in control. Each indenture of APA and Apache restricts it from issuing or guaranteeing certain secured indebtedness. None of the indentures contain prepayment obligations in the event of a decline in credit ratings. During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility. During 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations. The following table presents the carrying value of the Company’s debt as of December 31, 2024 and 2023: December 31, 2024 2023 (In millions) 4.625% notes due 2025 (1) $ 51 $ 51 7.7% notes due 2026 78 78 7.95% notes due 2026 132 132 4.875% notes due 2027 (1) 108 108 4.375% notes due 2028 (1) 325 325 7.75% notes due 2029 (1)(2) 235 235 4.25% notes due 2030 (1) 516 516 6.0% notes due 2037 (1) 443 443 5.1% notes due 2040 (1) 1,333 1,333 5.25% notes due 2042 (1) 399 399 4.75% notes due 2043 (1) 428 428 4.25% notes due 2044 (1) 211 211 7.375% debentures due 2047 150 150 5.35% notes due 2049 (1) 387 387 7.625% debentures due 2096 39 39 Apache notes and debentures before unamortized discount and debt issuance costs (3) 4,835 4,835 Commercial paper 323 — Term loan facility 900 — Syndicated credit facilities (4) 10 372 Apache finance lease obligations 30 32 Unamortized discount (25) (26) Debt issuance costs (29) (25) Total debt 6,044 5,188 Current maturities (53) (2) Long-term debt $ 5,991 $ 5,186 (1) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable. (2) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (3) The fair values of Apache’s notes and debentures were $4.4 billion and $4.3 billion as of December 31, 2024 and 2023, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (4) The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates. Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2024 are as follows: (In millions) 2025 $ 51 2026 210 2027 108 2028 325 2029 235 Thereafter 3,906 Notes and debentures, excluding discounts and debt issuance costs $ 4,835 Financing Costs, Net The following table presents the components of the Company’s financing costs, net: For the Year Ended December 31, 2024 2023 2022 (In millions) Interest expense $ 402 $ 351 $ 332 Amortization of debt issuance costs 6 4 8 Capitalized interest (29) (24) (18) Loss (gain) on extinguishment of debt — (9) 67 Interest income (12) (10) (10) Financing costs, net $ 367 $ 312 $ 379 Unsecured 2022 Committed Bank Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that remained in effect as of December 31, 2024, but were replaced on January 15, 2025, as detailed below under “Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities.” As of December 31, 2024: • One agreement was denominated in US dollars (the 2022 USD Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million was committed). • The second agreement was denominated in pounds sterling (the 2022 GBP Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. As of December 31, 2024, there were $10 million of borrowings under the 2022 USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the 2022 USD Agreement, and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the 2022 USD Agreement. The Company was in compliance with the terms of the 2022 Agreements as of December 31, 2024. Uncommitted Lines of Credit Each of the Company and Apache from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2024 and 2023, there were no outstanding borrowings under these facilities. As of December 31, 2024, there were £640 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million in letters of credit outstanding under these facilities. Commercial Paper Program In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (the CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed revolving credit facilities for general corporate purposes, which as of December 31, 2024, included the $1.8 billion 2022 USD Agreement. Payment of the CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion. The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance. As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding. Unsecured Committed Term Loan Facility On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement. Of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion. On April 1, 2024 (the Closing Date), APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire. As of December 31, 2024, $900 million in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. Borrowings under the Term Loan Credit Agreement bear interest at one of two rate options selected by APA, being either (i) an alternate base rate (as defined), plus a margin (Term Base Rate Margin) varying from 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, or (ii) an adjusted term SOFR rate (as defined), plus a margin (Term Applicable Margin) varying from 1.375% to 2.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 1.625% to 2.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date. Margins are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2024, Apache’s Long-Term Debt Rating applied, and the Term Base Rate Margin was 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin was 1.75% for 3-Year Tranche Loans. APA is subject to representations and warranties, covenants, and events of default under the Term Loan Credit Agreement, such as: • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2024, APA’s debt-to-capital ratio as calculated under the Term Loan Credit Agreement was 19 percent. • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U.S. and Canada. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $2.5 billion as of December 31, 2024. • Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold. • Lenders may accelerate payment maturity and terminate lending commitments for nonpayment and other breaches; if APA or certain subsidiaries default on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of APA or certain subsidiaries. The Term Loan Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings. The Company was in compliance with the terms of the Term Loan Credit Agreement as of December 31, 2024. Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities On January 15, 2025, the Company terminated commitments under the 2022 Agreements and in replacement thereof, entered into two unsecured syndicated credit agreements for general corporate purposes on terms substantially the same as those of the 2022 Agreements: • One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company’s two, one-year extension options. • The second agreement is denominated in pounds sterling (the 2025 GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company’s two, one-year extension options. Apache has guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion. Letters of credit are available under each 2025 Agreement for credit support needs of APA and its subsidiaries, including in respect of North Sea decommissioning obligations. As of January 15, 2025, letters of credit aggregating approximately £253 million originally issued under the 2022 GBP Agreement were deemed issued and outstanding under the 2025 GBP Agreement. All borrowings under the 2025 USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin varying from 0.0% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.00% to 1.675% (Applicable Margin). All borrowings under the 2025 GBP Agreement bear interest with respect to any business day at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average with respect to such business day published by the Bank of England, plus the Applicable Margin. Each 2025 Agreement also requires the borrower to pay quarterly (i) a facility fee on total commitments at a per annum rate that varies from 0.125% to 0.325% and (ii) a commission on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). APA’s Long-Term Debt Rating currently applies, and the Base Rate Margin is 0.30%, the Applicable Margin is 1.30%, and the facility fee is 0.20%. Borrowers under each 2025 Agreement, which include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default, such as: • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65% at the end of any fiscal quarter. • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada; Liens on assets also are permitted if debt secured thereby does not exceed 15% of APA’s consolidated net tangible assets. • Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold. • Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries. The 2025 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings. Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA’s cash tender offers. In settling these offerings pursuant to their respective terms: • A PA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA’s exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA’s 6.10% Notes due 2035 and $500 million aggregate principal amount of APA’s 6.75% Notes due 2055. • In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration. • APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. • Net proceeds from the sale of the notes in APA’s new notes offering, after deducting the initial purchasers’ discounts and estimated offering expenses, were approximately $839 million and used to fund in part APA’s purchase of Apache notes in APA’s cash tender offers. • Each series of APA notes and debentures issued in settlement of the exchange and tender offers has the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged. • Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering are fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than $1 billion. • APA entered into two registration rights agreements, one covering notes and debentures issued in APA’s exchange and tender offers and one covering notes issued in APA’s new notes offering (each a Registration Rights Agreement). These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA and Apache to use their commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA and guaranteed, if applicable, by Apache containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions or any increase in annual interest rate) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue on the principal amount of such registrable securities at a rate of 0.25% per annum for the first 90-day period beginning on the day immediately following such registration default (which rate will be increased by an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum). To the extent Apache’s guarantee of the registrable securities is terminated in accordance with the terms of such guarantee, the registered notes will not be guaranteed by Apache, the exchange offer and registration requirements with respect thereto will be the sole obligation of the Company, and Apache will automatically be released from all obligations under the applicable Registration Rights Agreement. The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA’s exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA’s exchange or tender offers): January 10, 2025 APA Apache (In millions) 4.625% notes due 2025 $ — $ 51 7.7% notes due March 2026 (1)(5)(6) 58 21 7.95% notes due April 2026 (1)(5)(6) 56 76 4.875% notes due 2027 (4)(5)(6) 39 69 4.375% notes due 2028 (4)(5)(6) 239 86 7.75% notes due 2029 (2)(5)(6) 164 72 4.25% notes due 2030 (4)(5)(6) 374 142 6.0% notes due 2037 (1)(5)(6) 341 102 5.1% notes due 2040 (1)(5)(6) 539 225 5.25% notes due 2042 (1)(5)(6) 209 65 4.75% notes due 2043 (3)(5)(6) 153 79 4.25% notes due 2044 (3)(5)(6) 77 24 7.375% debentures due 2047 (1)(5)(6) 126 24 5.35% notes due 2049 (4)(5)(6) 330 57 7.625% debentures due 2096 (1)(5)(6) 37 2 6.1% notes due 2035 (7) 350 — 6.75% notes due 2055 (7) 500 — Total $ 3,592 $ 1,095 (1) The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture). (2) The Apache 2029 notes were issued under the Indenture, dated as of November 23, 1999, between Apache (as successor to Apache Finance Canada Corporation), and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture). (3) The Apache 2043 notes and the Apache 2044 notes were issued under the Senior Indenture, dated as of May 19, 2011, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture). (4) The Apache 2027 notes, the Apache 2028 notes, the Apache 2030 notes, and the Apache 2049 notes were issued under the Indenture, dated as of August 14, 2018, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture). (5) In connection with APA’s exchange and tender offers, Apache solicited the consents of the holders of these Apache notes and debentures to amend the applicable Apache Indenture to remove certain restrictive and reporting covenants. The Apache notes and debentures are senior unsecured obligations of Apache. Apache received consents sufficient to approve the proposed amendments to the Apache Indentures with respect to the Apache March 2026 notes, the Apache 2028 notes, the Apache 2029 notes, the Apache 2030 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2043 notes, the Apache 2044 notes, the Apache 2047 debentures, the Apache 2049 notes, and the Apache 2096 debentures. As a result, Apache and the respective trustee for the Apache Indentures entered into supplemental indentures on January 10, 2025, implementing the proposed amendments effective as of that date. (6) The APA March 2026 notes, the APA April 2026 notes, the APA 2027 notes, the APA 2028 notes, the APA 2029 notes, the APA 2030 notes, the APA 2037 notes, the APA 2040 notes, the APA 2042 notes, the APA 2043 notes, the APA 2044 notes, the APA 2047 debentures, the APA 2049 notes, and the APA 2096 debentures were issued under the Indenture, dated as of June 30, 2021, between the Company, as issuer, and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee. These APA notes and debentures were issued in APA’s exchange and tender offers for Apache’s notes and debentures. (7) The APA 2035 notes and the APA 2055 notes were issued under the Indenture, dated as of December 11, 2024, between the Company, as issuer, and Regions Bank, as trustee. These APA notes were issued in APA’s new notes offering to fund in part its purchase of Apache notes in APA’s cash tender offers. Subsequent Event—Open Market Repurchases of Apache Indenture Debt In the first quarter of 2025 through the date of this filing, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $55 million for an aggregate purchase price of $50 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $7 million. The Company recognized a $6 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Net income before income taxes was composed of the following: For the Year Ended December 31, 2024 2023 2022 (In millions) U.S. $ 705 $ 627 $ 2,675 Foreign 830 2,256 3,059 Total $ 1,535 $ 2,883 $ 5,734 The total income tax provision (benefit) consisted of the following: For the Year Ended December 31, 2024 2023 2022 (In millions) Current income taxes: Federal $ 76 $ 2 $ 1 State 2 6 11 Foreign 1,075 1,330 1,495 1,153 1,338 1,507 Deferred income taxes: Federal (96) (1,708) — State 3 (32) — Foreign (643) 78 145 (736) (1,662) 145 Total $ 417 $ (324) $ 1,652 The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below: For the Year Ended December 31, 2024 2023 2022 (In millions) Income tax expense at U.S. statutory rate $ 322 $ 605 $ 1,204 State income tax, less federal effect (1) 2 (23) 9 Taxes related to foreign operations 45 752 745 Tax credits (3) — (4) Net change in tax contingencies 2 5 1 Valuation allowances (1) — (1,842) (646) Tax adjustments attributable to BCP Business Combination — — 126 Stock compensation 17 (2) 7 Legal reserve 14 — — Remeasurement of U.K. deferred tax liability — 174 208 Transaction costs 5 — — All other, net 13 7 2 $ 417 $ (324) $ 1,652 (1) The change in state valuation allowance is included as a component of state income tax. The net deferred income tax (asset) liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax (asset) liability consisted of the following as of December 31: 2024 2023 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,487 $ 2,050 Capital losses 14 8 Foreign net operating losses 55 43 Tax credits and other tax incentives 105 26 Foreign tax credits 2,204 2,204 Accrued expenses and liabilities 76 129 Asset retirement obligation 952 850 Property and equipment 45 38 Equity investments 1 8 Net interest expense limitation 287 125 Lease liability 114 71 Decommissioning contingency for sold Gulf of America properties 232 210 Total deferred tax assets 6,572 5,762 Valuation allowance (2,623) (2,630) Net deferred tax assets 3,949 3,132 Deferred tax liabilities: Property and equipment 1,060 1,573 Right-of-use asset 111 69 Decommissioning security for sold Gulf of America properties 40 44 Other 49 59 Total deferred tax liabilities 1,260 1,745 Net deferred income tax asset $ (2,689) $ (1,387) Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2024 2023 (In millions) Assets: Other assets Deferred tax asset $ 2,703 $ 1,758 Liabilities: Deferred credits and other noncurrent liabilities Deferred tax liability 14 371 Net deferred income tax asset $ (2,689) $ (1,387) On April 1, 2024, the Company completed its acquisition of Callon in an all-stock transaction. The Company’s deferred tax asset increased by approximately $565 million as part of the assets assumed through the Callon acquisition. Refer to Note 2— Acquisitions and Divestitures for further detail. On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate, effective for the period of May 26, 2022 through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. As a result, the Company recorded a deferred tax expense of $174 million and $208 million related to the remeasurement of the U.K. deferred tax liability in 2023 and 2022, respectively. On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. In 2024, the Company accrued tax expense of $74 million, which results in a tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years. In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, the Company does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements. On January 14, 2022, Apache Midstream LLC, a wholly owned subsidiary of Apache, exchanged 12.5 million Common Units in Altus Midstream LP for 12.5 million shares of ALTM Class A Common Stock, in a taxable exchange. On February 22, 2022, as a result of the BCP Business Combination, the Company deconsolidated ALTM. On March 11, 2022, the Company sold four million of its Kinetik Shares, and on March 18, 2024, the remaining Kinetik Shares were sold. In 2022, the Company recorded tax expense of $126 million associated with the BCP Business Combination. The tax impact of the BCP Business Combination was fully offset by a change in valuation allowance. Refer to Note 2— Acquisitions and Divestitures for further detail. Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be “more likely than not.” The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. In 2024, 2023, and 2022, the Company’s valuation allowance decreased by $7 million, $2.3 billion and $1.0 billion, respectively, as detailed in the table below: 2024 2023 2022 (In millions) Balance at beginning of year $ 2,630 $ 4,918 $ 5,902 State (1) (51) (63) (111) U.S. 26 (2,235) (706) Foreign 18 10 (167) Balance at end of year $ 2,623 $ 2,630 $ 4,918 (1) Reported as a component of state income taxes. On December 31, 2024, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 10,345 2028 - Indefinite State 6,586 Various Foreign 153 2025 - Indefinite The Company has a U.S. net operating loss carryforward of $10.3 billion, which includes $2.1 billion of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $6.6 billion, foreign net operating losses of $153 million, and a net interest expense carryover of $1.3 billion under Section 163(j) of the Code with indefinite carryover. The Company has recorded a valuation allowance against some of the U.S. net operating losses, a majority of the state net operating losses, the foreign net operating losses, and the U.S. capital loss because it is more likely than not that these net operating losses and the capital loss carryforward will not be realized. The Company believes it is more likely than not that the deferred tax assets related to the remaining U.S. and state net operating losses, and the net interest expense carryover will be utilized prior to their expiration. On December 31, 2024, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,204 2025-2026 The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized. The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2024 2023 2022 (In millions) Balance at beginning of year $ 93 $ 89 $ 116 Additions based on tax positions related to prior year 1 4 — Additions based on tax positions related to the current year — — — Reductions for tax positions of prior years (5) — (27) Balance at end of year $ 89 $ 93 $ 89 The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2024, 2023, and 2022, the Company recorded tax expense of $2 million, $2 million, and $1 million, respectively, for interest and penalties. At December 31, 2024, 2023, and 2022, the Company had an accrued liability for interest and penalties of $9 million, $7 million, and $5 million, respectively. The Company and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. The Company’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2022

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Legal Matters The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of December 31, 2024, the Company has an accrued liability of approximately $20 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity. Louisiana Restoration Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims. Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The consideration paid by the Company in the settlement did not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which was filed by the City of New Orleans against the Company and a number of oil and gas operators. Apollo Exploration Lawsuit In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation , Cause No. CV50538 in the 385 th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings. Australian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims. Delaware Litigation On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company is vigorously defending the suit. Kulp Minerals Lawsuit On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation , Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit. Environmental Matters As of December 31, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $2 million. The Company is not aware of any environmental claims existing as of December 31, 2024, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties. Potential Decommissioning Obligations on Sold Properties In 2013, Apache sold its Gulf of America (GOA) Shelf operations and properties and its GOA operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOA Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOA Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOA Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOA Assets. By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOA Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOA Assets. On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation , Cause No. 2023-38238 in the 281 st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the $148 million in Bonds and $350 million in Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281 st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the $350 million in Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refused to honor such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction. The parties settled their dispute in the first quarter of 2025, which resulted in, among other things, mutual releases, the retention by Apache of all amounts drawn on the Letters of Credit, and payment to Apache of $140 million under the Bonds. As of December 31, 2024, the Company recorded an asset of $178 million representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs. Of the total asset recorded as of December 31, 2024, $21 million is reflected under the caption “Decommissioning security for sold Gulf of America properties,” and $157 million is reflected under “Other current assets” in the Company’s consolidated balance sheet. As of December 31, 2024, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $1.0 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company recorded contingent liabilities in the amounts of $1.0 billion and $824 million as of December 31, 2024, and December 31, 2023, respectively. Of the total liability recorded as of December 31, 2024, $929 million is reflected under the caption “Decommissioning contingency for sold Gulf of America properties” and $88 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected well decommissioning spread rates, derrick barge rates, and planned abandonment logistics, could result in a liability in excess of the amount accrued. The Company recognized $273 million of “Losses on previously sold Gulf of America properties” during 2024 to reflect the net impact of an increase in estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The loss includes $67 million related to properties previously sold to third parties other than Fieldwood for which the Company received BSSE orders to decommission during the year, as well as an increase to the estimated net liability the Company expects to incur for decommissioning Legacy GOA Assets. The Company also recognized losses on previously sold Gulf of America properties of $212 million and $157 million during 2023 and 2022, respectively, in the Company’s statement of consolidated operations. Leases and Contractual Obligations The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, the Company records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable. Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $170 million, $168 million, and $145 million for the years ended 2024, 2023, and 2022, respectively. As allowed under the standard, the Company accounts for non-lease and lease components as a single lease component for all asset classes and has elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases were $85 million, $71 million, and $62 million in 2024, 2023, and 2022, respectively. In 2024 these costs primarily related to short term drilling rigs in the U.S. and decommissioning work in the Gulf of America. In 2023 these costs primarily related to decommissioning work in the Gulf of America. In 2022, these costs were primarily related to drilling activities in Block 58 offshore Suriname. Finance lease assets are included in “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “ Current debt Long-term debt The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2024: Operating Leases Finance Lease Weighted average remaining lease term 6.9 years 8.7 years Weighted average discount rate 5.8 % 4.4 % At December 31, 2024, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2025 $ 122 $ 3 $ 244 2026 61 4 245 2027 48 4 173 2028 42 4 166 2029 35 4 148 Thereafter 159 18 142 Total future minimum payments 467 37 $ 1,118 Less: imputed interest (94) (7) N/A Total lease liabilities 373 30 N/A Current portion 118 2 N/A Non-current portion $ 255 $ 28 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $245 million, $182 million, and $183 million in 2024, 2023, and 2022, respectively. (5) Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation. The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $48 million, $74 million, and $90 million in 2024, 2023, and 2022, respectively.

RETIREMENT AND DEFERRED COMPENS

RETIREMENT AND DEFERRED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
RETIREMENT AND DEFERRED COMPENSATION PLANS	RETIREMENT AND DEFERRED COMPENSATION PLANS The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan. Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership of APA, immediate and full vesting occurs. The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $46 million, $44 million, and $40 million for 2024, 2023, and 2022, respectively. The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003. Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare. The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2024, 2023, and 2022, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans. 2024 2023 2022 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 118 $ 15 $ 108 $ 15 $ 211 $ 20 Service cost 1 1 1 1 2 1 Interest cost 6 1 5 1 3 — Foreign currency exchange rates (2) — 6 — (21) — Actuarial losses (gains) (11) — 3 — (79) (5) Plan settlements — (1) — — — — Benefits paid (5) (2) (5) (3) (8) (3) Retiree contributions — 1 — 1 — 2 Projected benefit obligation at end of year 107 15 118 15 108 15 Change in Plan Assets Fair value of plan assets at beginning of year 150 — 137 — 254 — Actual return (loss) on plan assets (8) — 8 — (87) — Foreign currency exchange rates (3) — 8 — (26) — Employer contributions 2 1 2 1 4 2 Plan settlements — — — — — — Benefits paid (5) (2) (5) (3) (8) (4) Retiree contributions — 1 — 2 — 2 Fair value of plan assets at end of year 136 — 150 — 137 — Funded status at end of year $ 29 $ (15) $ 32 $ (15) $ 29 $ (15) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (13) 32 (13) 29 (13) $ 29 $ (15) $ 32 $ (15) $ 29 $ (15) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (16) $ 14 $ (12) $ 16 $ (10) $ 18 Weighted Average Assumptions used as of December 31 Discount rate 5.60 % 5.49 % 4.80 % 5.00 % 5.00 % 5.29 % Salary increases 4.70 % N/A 4.60 % N/A 4.70 % N/A Expected return on assets 5.70 % N/A 4.80 % N/A 4.70 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.50 % Ultimate in 2032 N/A 5.25 % N/A 5.25 % N/A 5.25 % As of December 31, 2024, 2023, and 2022, the accumulated benefit obligation for the U.K. Pension Plan was $102 million, $112 million, and $89 million, respectively. The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets under a cash flow driven investment strategy. The Company intends to invest in primarily low risk debt securities that will provide a reasonable rate of return focused on cash flow timing such that the benefits promised to members are provided when due. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of allocations for the Company's plan asset holdings are summarized below: Percentage of 2024 2023 Asset Category Global equities — % — % Multi-asset credit 62 % 59 % Nominal bonds 4 % 6 % Inflation-linked bonds 33 % 33 % Cash 1 % 2 % Total 100 % 100 % The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2024 and 2023 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets as follows: December 31, 2024 2023 (In millions) Asset Category Global equities $ — $ — Multi-asset credit 84 88 Nominal bonds 6 9 Inflation-linked bonds 45 50 Cash 1 3 Total $ 136 $ 150 The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 2.5 percent per year. The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31 as follows: 2024 2023 2022 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 1 $ 1 $ 1 $ 1 $ 2 $ 1 Interest cost 6 1 5 1 3 — Expected return on assets (7) — (7) — (4) — Amortization of loss — (2) — (2) — (1) Settlement loss — — — — — — Net periodic benefit cost $ — $ (1) $ (1) $ — $ 1 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 4.80 % 5.00 % 5.00 % 5.29 % 1.80 % 2.57 % Salary increases 4.60 % N/A 4.70 % N/A 4.90 % N/A Expected return on assets 4.80 % N/A 4.70 % N/A 1.90 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.50 % N/A 6.25 % Ultimate in 2030 N/A 5.25 % N/A 5.25 % N/A 5.00 % The Company expects to contribute approximately $2 million to its pension plan and $2 million to its postretirement benefit plan in 2025. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2025 $ 5 $ 2 2026 5 1 2027 6 1 2028 6 1 2029 6 1 Years 2030-2034 35 7

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
CAPITAL STOCK	CAPITAL STOCK Common Stock Outstanding The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 Balance, beginning of year 303,575,901 311,559,149 346,930,765 Shares issued for stock-based compensation plans: Treasury shares issued — 2,016 1,996 Common shares issued 70,983,745 725,914 791,381 Treasury shares acquired (9,162,497) (8,711,178) (36,164,993) Balance, end of year 365,397,149 303,575,901 311,559,149 Net Income per Common Share The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Income Shares Per Share Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 804 353 $ 2.28 $ 2,855 308 $ 9.26 $ 3,674 332 $ 11.05 Effect of Dilutive Securities: Stock compensation awards $ — — $ (0.01) $ — 1 $ (0.01) $ — 1 $ (0.03) Diluted: Income attributable to common stock $ 804 353 $ 2.27 $ 2,855 309 $ 9.25 $ 3,674 333 $ 11.02 The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 2.0 million, 1.9 million, and 2.4 million for the years ended December 31, 2024, 2023, and 2022, respectively. Stock Repurchase Program During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock. During 2024, the Company repurchased 9.2 million shares at an average price of $26.83 per share, and as of December 31, 2024, the Company had remaining authorization to repurchase 34.8 million shares. During 2023, the Company repurchased 8.7 million shares at an average price of $37.81 per share. During 2022, the Company repurchased 36.2 million shares at an average price of $39.34 per share. Subsequent to year-end 2024 and through the date of this filing on February 28, 2025, the Company repurchased 3.9 million shares at an average price of $23.13 per share. As of February 28, 2025, the Company had remaining authorization to repurchase up to 30.9 million shares. The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions. Common Stock Dividend The Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 per share to $0.25 per share in the third quarter of 2022. For the years ended December 31, 2024, 2023, and 2022, the Company declared common stock dividends totaling $1.00 per share, $1.00 per share, and $0.75 per share, respectively. Stock Compensation Plans The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2024, 7.9 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash. Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In millions) Stock-settled and cash-settled compensation expensed: Lease operating expenses $ 16 $ 27 $ 82 Exploration 4 7 29 General and administrative 29 50 193 Total stock-settled and cash-settled compensation expensed 49 84 304 Stock-settled and cash-settled compensation capitalized 9 13 44 Total stock-settled and cash-settled compensation costs $ 58 $ 97 $ 348 Stock Options As of December 31, 2024, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted. The following table summarizes stock option activity for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Shares Weighted Average Exercise Price Shares Weighted Average Exercise Price Shares Weighted Average Exercise Price (In thousands, except exercise price amounts) Outstanding, beginning of year 1,465 $ 48.48 2,078 $ 57.71 3,012 $ 63.79 Exercised — — (12) 42.38 (99) 42.09 Forfeited — — — — (2) 49.10 Expired (49) 43.91 (601) 80.53 (833) 81.56 Outstanding, end of year (1) 1,416 48.64 1,465 48.48 2,078 57.71 Expected to vest — — — — — — Exercisable, end of year (1) 1,416 48.64 1,465 48.48 2,078 57.71 (1) As of December 31, 2024, options exercisable and outstanding had a weighted average remaining contractual life of 2.1 years and no aggregate intrinsic value. During the years ended December 31, 2024, there were no options issued or exercised. During the years ended December 31, 2023 and 2022, there were no options issued and 12,183, and 98,646 options, respectively, exercised. In January 2025, the Company issued 1,662,239 options to purchase shares of the Company’s common stock to eligible employees under the Omnibus Plans, at an average fair value of $9.51 per share. The total compensation cost of $16 million is estimated to be recognized over a three-year vesting period of these options. Restricted Stock Units and Restricted Stock Phantom Units The Company has restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either the Company’s common stock or, prior to the BCP Business Combination, in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. For the years ended December 31, 2024, 2023, and 2022, compensation costs charged to expense for the restricted stock units and restricted stock phantom units were $53 million, $73 million, and $153 million, respectively. As of December 31, 2024, 2023, and 2022, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $9 million, $11 million, and $22 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 1,480 $ 30.69 1,885 $ 23.08 2,073 $ 19.98 Granted 897 33.48 661 41.60 847 29.90 Assumed awards from Callon acquisition 1,498 35.43 — — — — Vested (3) (2,295) 31.83 (975) 23.31 (978) 22.39 Forfeited (165) 35.48 (69) 32.44 (57) 23.49 Expired — — (22) 27.81 — — Non-vested, end of year (1)(2) 1,415 35.07 1,480 30.69 1,885 23.08 (1) As of December 31, 2024, there was $18 million of total unrecognized compensation cost related to 1,257,784 unvested stock-settled restricted stock units. (2) As of December 31, 2024, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years. (3) The grant date fair values of the stock-settled awards vested during 2024, 2023, and 2022 were $73 million, $23 million, and $22 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In thousands) Non-vested, beginning of year 4,478 5,709 6,402 Adjustment from ALTM transaction (1) — — 143 Granted (2) 2,369 1,972 2,568 Vested (2,568) (2,851) (2,970) Forfeited (362) (340) (434) Expired — (12) — Non-vested, end of year (3) 3,917 4,478 5,709 (1) Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price. (2) Restricted stock phantom units granted during 2024, 2023, and 2022 included 2,369,605, 1,972,116, and 2,512,602 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 included 55,546 awards based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022. (3) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2024 was approximately $34 million. In January 2025, the Company awarded 693,761 restricted stock units and 2,300,091 restricted stock phantom units based on APA’s weighted-average per-share market price of $23.68 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $16 million and $54 million, respectively, and was calculated based on the per-share fair market value of a share of the Company’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. Performance Program To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of cash-settled conditional restricted stock phantom units to eligible employees. APA has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2024, are as described below: • In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. A total of 1,051,688 phantom units were outstanding as of December 31, 2024. The results for the performance period yielded a payout of 118 percent of target. • In January 2022, the Company’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. A total of 998,570 phantom units were outstanding as of December 31, 2024. The results for the performance period yielded a payout of 118 percent of target. • In January 2023, the Company’s Board of Directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 822,200 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 718,288 phantom units were outstanding as of December 31, 2024, from which a minimum of zero to a maximum of 1,436,576 units could be awarded. • In January 2024, the Company’s Board of Directors approved the 2024 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 645,318 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 571,498 phantom units were outstanding as of December 31, 2024, from which a minimum of zero to a maximum of 1,142,996 units could be awarded. Eligible employees also received cash incentives as part of the 2024 Performance Program, which totaled $13 million as of December 31, 2024. The ultimate payout will range from zero to $26 million at the end of a three-year performance period. Compensation costs related to the conditional cash-settled awards are recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the cash-settled performance programs were a net benefit of $13 million during 2024 and expenses of $2 million and $143 million during 2023 and 2022, respectively. Capitalized compensation costs under the cash-settled performance programs were a net benefit of approximately $1 million during 2024 and expenses of approximately $100 thousand and $21 million during 2023 and 2022, respectively. The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In thousands) Non-vested, beginning of year 4,629 4,835 4,531 Granted 834 1,536 1,676 Assumed awards from Callon acquisition 2,934 — — Vested (4,222) (1,593) (656) Forfeited (203) (99) (106) Expired — (50) (610) Non-vested, end of year (1) 3,972 4,629 4,835 (1) As of December 31, 2024, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $12 million. In January 2025, the Company’s Board of Directors approved the 2025 Performance Program, pursuant to the 2016 Plan. A portion of the award is based upon measurement of TSR similar to prior year awards, and the remaining portion of the award is based on performance and financial objectives as defined in the 2025 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 985,553 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,971,106 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. These phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. The cash incentives totaled $16 million, with the ultimate payout ranging from zero to $32 million. Final payout of the awards will be determined at the end of a three-year performance period.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME Components of accumulated other comprehensive income include the following: As of December 31, 2024 2023 2022 (In millions) Pension and postretirement benefit plan ( Note 12 ) $ 12 $ 15 $ 14 Accumulated other comprehensive income $ 12 $ 15 $ 14

MAJOR CUSTOMERS

MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2024
Risks and Uncertainties [Abstract]
MAJOR CUSTOMERS	MAJOR CUSTOMERS The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2024, sales to EGPC accounted for approximately 17 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During each of 2023 and 2022, sales to EGPC accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. Management does not believe that the loss of any single customer would have a material adverse effect on the results of operations.

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
BUSINESS SEGMENT INFORMATION	BUSINESS SEGMENT INFORMATION As of December 31, 2024, the Company’s consolidated subsidiaries are engaged in exploration, development and/or production activities across four operating segments: Egypt, North Sea, Suriname, and the U.S. The Company’s business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operating a midstream energy asset network in the Permian Basin of West Texas. The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company’s Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is primarily associated with operating income from each segment and the resulting free cash flow, amongst other metrics. The Company concluded that the most comparable measure under U.S. GAAP is operating income. Financial information for each segment is presented below: U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2024 Oil revenues $ 3,572 $ 2,620 $ 774 $ — $ 6,966 Natural gas revenues 126 313 145 — 584 Natural gas liquids revenues 617 — 29 — 646 Oil, natural gas, and natural gas liquids production revenues 4,315 2,933 948 — 8,196 Purchased oil and gas sales 1,541 — — — 1,541 5,856 2,933 948 — 9,737 Operating Expenses: Lease operating expenses (5) 820 464 406 — 1,690 Gathering, processing, and transmission (5) 354 25 53 — 432 Purchased oil and gas costs 1,047 — — — 1,047 Taxes other than income (5) 270 — — — 270 Exploration (4) 134 112 1 66 313 Depreciation, depletion, and amortization (5) 1,340 625 301 — 2,266 Asset retirement obligation accretion 42 — 106 — 148 Impairments 320 — 809 — 1,129 4,327 1,226 1,676 66 7,295 Operating Income (Loss) $ 1,529 $ 1,707 $ (728) $ (66) 2,442 Other Income (Expense): Gain on divestitures, net 289 Losses on previously sold Gulf of America properties (273) Derivative instrument losses, net (10) Other (6) General and administrative (372) Transaction, reorganization, and separation (168) Financing costs, net (367) Income Before Income Taxes $ 1,535 Total Assets (3) $ 13,870 $ 3,606 $ 1,324 $ 590 $ 19,390 Net Property and Equipment $ 9,109 $ 2,271 $ 712 $ 554 $ 12,646 Additions to Net Property and Equipment $ 6,609 $ 765 $ 41 $ 84 $ 7,499 U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2023 Oil revenues $ 2,241 $ 2,683 $ 1,073 $ — $ 5,997 Natural gas revenues 297 346 237 — 880 Natural gas liquids revenues 480 — 28 — 508 Oil, natural gas, and natural gas liquids production revenues 3,018 3,029 1,338 — 7,385 Purchased oil and gas sales 894 — — — 894 3,912 3,029 1,338 — 8,279 Operating Expenses: Lease operating expenses (5) 593 474 369 — 1,436 Gathering, processing, and transmission (5) 249 33 52 — 334 Purchased oil and gas costs 742 — — — 742 Taxes other than income (5) 207 — — — 207 Exploration (4) 14 119 19 43 195 Depreciation, depletion, and amortization (5) 745 524 271 — 1,540 Asset retirement obligation accretion 40 — 76 — 116 Impairments 11 — 50 — 61 2,601 1,150 837 43 4,631 Operating Income (Loss) $ 1,311 $ 1,879 $ 501 $ (43) 3,648 Other Income (Expense): Gain on divestitures, net 8 Losses on previously sold Gulf of America properties (212) Derivative instrument gains, net 99 Other 18 General and administrative (351) Transaction, reorganization, and separation (15) Financing costs, net (312) Income Before Income Taxes $ 2,883 Total Assets (3) $ 9,221 $ 3,503 $ 1,970 $ 550 $ 15,244 Net Property and Equipment $ 5,689 $ 2,209 $ 1,628 $ 512 $ 10,038 Additions to Net Property and Equipment $ 1,255 $ 834 $ 131 $ 93 $ 2,313 U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2022 Oil revenues $ 2,458 $ 3,145 $ 1,232 $ — $ 6,835 Natural gas revenues 918 370 281 — 1,569 Natural gas liquids revenues 768 6 45 (3) 816 Oil, natural gas, and natural gas liquids production revenues 4,144 3,521 1,558 (3) 9,220 Purchased oil and gas sales 1,850 — — 5 1,855 5,994 3,521 1,558 2 11,075 Operating Expenses: Lease operating expenses (5) 515 526 404 (1) 1,444 Gathering, processing, and transmission (5) 315 22 43 (13) 367 Purchased oil and gas costs 1,776 — — — 1,776 Taxes other than income (5) 265 — — 3 268 Exploration (4) 24 84 35 162 305 Depreciation, depletion, and amortization (5) 593 400 238 2 1,233 Asset retirement obligation accretion 34 — 82 1 117 3,522 1,032 802 154 5,510 Operating Income (Loss) $ 2,472 $ 2,489 $ 756 $ (152) 5,565 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of America properties (157) Derivative instrument losses, net (114) Other 148 General and administrative (483) Transaction, reorganization, and separation (26) Financing costs, net (379) Income Before Income Taxes $ 5,734 Total Assets (3) $ 7,574 $ 3,148 $ 1,911 $ 514 $ 13,147 Net Property and Equipment $ 5,226 $ 1,976 $ 1,386 $ 424 $ 9,012 Additions to Net Property and Equipment $ 1,439 $ 695 $ 210 $ 263 $ 2,607 (1) Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2024, 2023, and 2022 of: For the Year Ended December 31, 2024 2023 2022 (In millions) Oil $ 686 $ 729 $ 989 Natural gas 83 95 117 Natural gas liquids — — 2 (2) Includes a noncontrolling interest in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the year 2022. (3) Intercompany balances are excluded from total assets. (4) Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities. (5) Represents significant segment expense categories that align with the segment-level information that is regularly provided to the CODM. The remaining expenses that comprise the Other Income (Loss) amount by segment are deemed to be other segment expense categories necessary to arrive at the segment profit or loss. (6) Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported. For 2022, the Company’s midstream business results are also included in this category as the midstream operating segment has not met the quantitative thresholds to be separately reported.

SUPPLEMENTAL OIL AND GAS DISCLO

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)	SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) Oil and Gas Operations The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2024 Oil and gas production revenues $ 4,315 $ 2,933 $ 948 $ — $ 8,196 Operating cost: Depreciation, depletion, and amortization (2) 1,314 621 300 — 2,235 Asset retirement obligation accretion 42 — 106 — 148 Lease operating expenses 820 464 406 — 1,690 Gathering, processing, and transmission 354 25 53 — 432 Exploration expenses 134 112 1 66 313 Impairments related to oil and gas properties 315 — 796 — 1,111 Production taxes (3) 268 — — — 268 Income tax 235 770 (536) — 469 3,482 1,992 1,126 66 6,666 Results of operations $ 833 $ 941 $ (178) $ (66) $ 1,530 2023 Oil and gas production revenues $ 3,018 $ 3,029 $ 1,338 $ — $ 7,385 Operating cost: Depreciation, depletion, and amortization (2) 709 521 270 — 1,500 Asset retirement obligation accretion 40 — 76 — 116 Lease operating expenses 593 474 369 — 1,436 Gathering, processing, and transmission 249 33 52 — 334 Exploration expenses 14 119 19 43 195 Production taxes (3) 204 — — — 204 Income tax 254 828 414 — 1,496 2,063 1,975 1,200 43 5,281 Results of operations $ 955 $ 1,054 $ 138 $ (43) $ 2,104 2022 Oil and gas production revenues $ 4,144 $ 3,521 $ 1,558 $ — $ 9,223 Operating cost: Depreciation, depletion, and amortization (2) 564 390 232 — 1,186 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 515 526 404 — 1,445 Gathering, processing, and transmission 315 22 43 — 380 Exploration expenses 24 84 35 162 305 Production taxes (3) 263 — — — 263 Income tax 510 1,100 495 — 2,105 2,225 2,122 1,291 162 5,800 Results of operations $ 1,919 $ 1,399 $ 267 $ (162) $ 3,423 (1) Includes a noncontrolling interest in Egypt. (2) Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 16—Business Segment Information . (3) Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 16—Business Segment Information . Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United Egypt (2) North Sea Other Total (2) (In millions) 2024 Acquisitions: Proved $ 3,606 $ 3 $ — $ — $ 3,609 Unproved 955 — — — 955 Exploration 150 227 1 61 439 Development 2,067 559 186 47 2,859 Costs incurred (1) $ 6,778 $ 789 $ 187 $ 108 $ 7,862 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ 3 $ — $ — $ 26 $ 29 Asset retirement costs 171 — 145 — 316 2023 Acquisitions: Proved $ 1 $ 4 $ — $ — $ 5 Unproved 20 — — — 20 Exploration 31 226 44 131 432 Development 1,148 646 468 — 2,262 Costs incurred (1) $ 1,200 $ 876 $ 512 $ 131 $ 2,719 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ — $ — $ — $ 24 $ 24 Asset retirement costs (4) — 375 — 371 2022 Acquisitions: Proved $ 596 $ 3 $ — $ — $ 599 Unproved 66 — — — 66 Exploration 4 169 61 311 545 Development 848 568 (57) — 1,359 Costs incurred (1) $ 1,514 $ 740 $ 4 $ 311 $ 2,569 (1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ 1 $ 17 $ 18 Asset retirement costs 79 — (215) — (136) (2) Includes a noncontrolling interest in Egypt. Capitalized Costs The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities: United Egypt (1) North Other Total (1) (In millions) 2024 Proved properties $ 19,246 $ 14,458 $ 9,661 $ 434 $ 43,799 Unproved properties 711 67 — 121 899 19,957 14,525 9,661 555 44,698 Accumulated DD&A (11,053) (12,299) (8,952) — (32,304) $ 8,904 $ 2,226 $ 709 $ 555 $ 12,394 2023 Proved properties $ 20,758 $ 13,777 $ 9,472 $ — $ 44,007 Unproved properties 267 71 3 512 853 21,025 13,848 9,475 512 44,860 Accumulated DD&A (15,587) (11,678) (7,849) — (35,114) $ 5,438 $ 2,170 $ 1,626 $ 512 $ 9,746 (1) Includes a noncontrolling interest in Egypt. Oil and Gas Reserve Information Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, the Company uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Crude Oil and Condensate United Egypt (1) North Suriname Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2021 180,968 106,646 77,073 — 364,687 December 31, 2022 177,708 108,050 82,580 — 368,338 December 31, 2023 179,542 102,305 61,076 — 342,923 December 31, 2024 184,744 95,990 30,436 — 311,170 Proved undeveloped reserves: December 31, 2021 18,168 11,003 5,757 — 34,928 December 31, 2022 22,239 8,557 2,873 — 33,669 December 31, 2023 30,948 5,254 — — 36,202 December 31, 2024 107,283 7,621 — 73,637 188,541 Total proved reserves: Balance December 31, 2021 199,136 117,649 82,830 — 399,615 Extensions, discoveries and other additions 9,776 7,580 2,616 — 19,972 Purchases of minerals in-place 16,362 — — — 16,362 Revisions of previous estimates 7,793 22,433 11,898 — 42,124 Production (25,695) (31,055) (11,891) — (68,641) Sales of minerals in-place (7,425) — — — (7,425) Balance December 31, 2022 199,947 116,607 85,453 — 402,007 Extensions, discoveries and other additions 43,613 12,979 301 — 56,893 Purchases of minerals in-place 20 — — — 20 Revisions of previous estimates (3,520) 10,505 (12,002) — (5,017) Production (28,795) (32,532) (12,676) — (74,003) Sales of minerals in-place (775) — — — (775) Balance December 31, 2023 210,490 107,559 61,076 — 379,125 Extensions, discoveries and other additions 100,778 18,115 — 73,637 192,530 Purchases of minerals in-place 124,112 — — — 124,112 Revisions of previous estimates (9,642) 10,521 (21,000) — (20,121) Production (47,043) (32,584) (9,640) — (89,267) Sales of minerals in-place (86,668) — — — (86,668) Balance December 31, 2024 292,027 103,611 30,436 73,637 499,711 (1) Includes proved reserves of 35 MMbbls, 36 MMbbls, 39 MMbbls, and 39 MMbbls as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 158,745 — 2,230 160,975 December 31, 2023 153,486 — 1,460 154,946 December 31, 2024 153,523 — 744 154,267 Proved undeveloped reserves: December 31, 2021 16,380 30 275 16,685 December 31, 2022 19,004 — 76 19,080 December 31, 2023 18,401 — — 18,401 December 31, 2024 54,674 — — 54,674 Total proved reserves: Balance December 31, 2021 180,552 476 2,334 183,362 Extensions, discoveries and other additions 5,456 — 45 5,501 Purchases of minerals in-place 10,985 — — 10,985 Revisions of previous estimates 9,991 (407) 333 9,917 Production (22,895) (69) (406) (23,370) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 177,749 — 2,306 180,055 Extensions, discoveries and other additions 25,711 — 371 26,082 Purchases of minerals in-place 21 — — 21 Revisions of previous estimates (8,568) — (764) (9,332) Production (22,993) — (453) (23,446) Sales of minerals in-place (33) — — (33) Balance December 31, 2023 171,887 — 1,460 173,347 Extensions, discoveries and other additions 62,988 — — 62,988 Purchases of minerals in-place 51,406 — — 51,406 Revisions of previous estimates (20,167) — (277) (20,444) Production (27,039) — (439) (27,478) Sales of minerals in-place (30,878) — — (30,878) Balance December 31, 2024 208,197 — 744 208,941 (1) Includes proved reserves of 159 Mbbls as of December 31, 2021, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,166,218 399,502 66,292 1,632,012 December 31, 2023 1,003,956 377,144 46,839 1,427,939 December 31, 2024 866,460 332,905 28,028 1,227,393 Proved undeveloped reserves: December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 210,862 1,068 2,304 214,234 December 31, 2023 99,495 2,612 — 102,107 December 31, 2024 307,775 27,499 — 335,274 Total proved reserves: Balance December 31, 2021 1,421,902 474,725 83,279 1,979,906 Extensions, discoveries and other additions 38,157 10,191 1,643 49,991 Purchases of minerals in-place 70,584 — — 70,584 Revisions of previous estimates 92,599 45,725 (3,431) 134,893 Production (172,752) (130,071) (12,895) (315,718) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,377,080 400,570 68,596 1,846,246 Extensions, discoveries and other additions 158,118 14,188 3,335 175,641 Purchases of minerals in-place 136 — — 136 Revisions of previous estimates (266,664) 83,907 (6,739) (189,496) Production (165,083) (118,909) (18,353) (302,345) Sales of minerals in-place (136) — — (136) Balance December 31, 2023 1,103,451 379,756 46,839 1,530,046 Extensions, discoveries and other additions 354,267 60,366 — 414,633 Purchases of minerals in-place 279,615 — — 279,615 Revisions of previous estimates (224,118) 26,792 (4,176) (201,502) Production (176,941) (106,510) (14,635) (298,086) Sales of minerals in-place (162,039) — — (162,039) Balance December 31, 2024 1,174,235 360,404 28,028 1,562,667 (1) Includes proved reserves of 120 Bcf, 127 Bcf, 134 Bcf, and 158 Bcf as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves United Egypt (1) North Suriname Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2021 551,384 184,563 91,825 — 827,772 December 31, 2022 530,823 174,633 95,859 — 801,315 December 31, 2023 500,354 165,162 70,343 — 735,859 December 31, 2024 482,677 151,474 35,852 — 670,003 Proved undeveloped reserves: December 31, 2021 65,288 12,683 7,219 — 85,190 December 31, 2022 76,386 8,735 3,333 — 88,454 December 31, 2023 65,931 5,690 — — 71,621 December 31, 2024 213,253 12,204 — 73,637 299,094 Total proved reserves: Balance December 31, 2021 616,672 197,246 99,044 — 912,962 Extensions, discoveries and other additions 21,592 9,278 2,935 — 33,805 Purchases of minerals in-place 39,110 — — — 39,110 Revisions of previous estimates 33,217 29,647 11,659 — 74,523 Production (77,382) (52,803) (14,446) — (144,631) Sales of minerals in-place (26,000) — — — (26,000) Balance December 31, 2022 607,209 183,368 99,192 — 889,769 Extensions, discoveries and other additions 95,677 15,344 1,228 — 112,249 Purchases of minerals in-place 64 — — — 64 Revisions of previous estimates (56,532) 24,490 (13,889) — (45,931) Production (79,302) (52,350) (16,188) — (147,840) Sales of minerals in-place (831) — — — (831) Balance December 31, 2023 566,285 170,852 70,343 — 807,480 Extensions, discoveries and other additions 222,811 28,176 — 73,637 324,624 Purchases of minerals in-place 222,121 — — — 222,121 Revisions of previous estimates (67,162) 14,986 (21,973) — (74,149) Production (103,572) (50,336) (12,518) — (166,426) Sales of minerals in-place (144,553) — — — (144,553) Balance December 31, 2024 695,930 163,678 35,852 73,637 969,097 (1) Includes total proved reserves of 55 MMboe, 57 MMboe, 61 MMboe, and 66 MMboe as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt. During 2024, the Company added approximately 325 MMboe from extensions, discoveries, and other additions. The Company recorded 223 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin targeting the Wolfcamp, Bone Spring and Spraberry producing horizons. International operations contributed 102 MMboe of exploration and development adds, with Egypt contributing 28 MMboe from onshore exploration and appraisal and 74 MMboe from the Suriname final investment decision (FID). The Company realized combined downward revision of previously estimated reserves of 74 MMboe. Negative revision related to pricing and interest totaled 99 MMboe, driven primarily by depressed Permian Basin gas pricing. This downward revision was partially offset by engineering and performance upward revisions totaling 25 MMboe. The U.S. and Egypt contributed upward revision of 47 MMboe, offset by negative revision of 22 MMboe in the North Sea. During 2023, the Company added approximately 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 27 MMboe in the Delaware Basin, and 2 MMboe in the Texas Gulf Coast. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 16 MMboe of exploration and development adds, with Egypt contributing 15 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 1 MMboe from the North Sea. The Company had combined downward revisions of previously estimated reserves of 46 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, partially offset by engineering and performance upward revisions of 37 MMboe. During 2022, the Company added approximately 34 MMboe from extensions, discoveries, and other additions. The Company recorded 22 MMboe of exploration and development adds in the U.S., comprising 9 MMboe in the Permian Basin, 8 MMboe in the Texas Gulf Coast, and 5 MMboe in the Delaware Basin. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 12 MMboe of exploration and development adds, with Egypt contributing 9 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 3 MMboe from the North Sea. The Company had combined upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with Egypt accounting for an increase of 43 MMboe, primarily the result of PSC modernization in Egypt. The North Sea contributed 9 MMboe of upward revisions from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 39 MMboe of proved reserves during 2022, primarily in the Delaware Basin. The Company also sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets. Approximately 11 percent of the Company’s year-end 2024 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 17, under “Future Net Cash Flows.” Future Net Cash Flows Future cash inflows as of December 31, 2024, 2023, and 2022 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs. The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2024, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. United Egypt (1) North Suriname Total (1) (In millions) 2024 Cash inflows $ 27,534 $ 9,342 $ 2,828 $ 5,881 $ 45,585 Production costs (9,665) (1,716) (1,399) (1,436) (14,216) Development costs (4,124) (1,517) (2,538) (1,096) (9,275) Income tax expense (921) (1,923) 85 (822) (3,581) Net cash flows 12,824 4,186 (1,024) 2,527 18,513 10 percent discount rate (4,317) (872) 535 (2,280) (6,934) Discounted future net cash flows (2) $ 8,507 $ 3,314 $ (489) $ 247 $ 11,579 2023 Cash inflows $ 21,417 $ 9,921 $ 5,761 $ — $ 37,099 Production costs (8,328) (1,690) (2,773) — (12,791) Development costs (2,238) (1,235) (2,461) — (5,934) Income tax expense (949) (2,222) (946) — (4,117) Net cash flows 9,902 4,774 (419) — 14,257 10 percent discount rate (3,749) (943) 476 — (4,216) Discounted future net cash flows (2) $ 6,153 $ 3,831 $ 57 $ — $ 10,041 2022 Cash inflows $ 31,577 $ 12,819 $ 10,147 $ — $ 54,543 Production costs (10,763) (2,086) (3,241) — (16,090) Development costs (1,733) (1,471) (2,297) — (5,501) Income tax expense (1,575) (2,729) (2,631) — (6,935) Net cash flows 17,506 6,533 1,978 — 26,017 10 percent discount rate (6,811) (1,400) (204) — (8,415) Discounted future net cash flows (2) $ 10,695 $ 5,133 $ 1,774 $ — $ 17,602 (1) Includes discounted future net cash flows of approximately $1.1 billion , $1.3 billion, and $1.7 billion as of December 31, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $14.4 billion , $13.6 billion, and $22.6 billion as of December 31, 2024, 2023, and 2022, respectively. The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2024 2023 2022 (In millions) Sales, net of production costs $ (5,806) $ (5,408) $ (7,131) Net change in prices and production costs 269 (7,089) 8,690 Discoveries and improved recovery, net of related costs 3,557 1,869 1,142 Change in future development costs (695) (413) (343) Previously estimated development costs incurred during the period 793 825 669 Revision of quantities (428) (262) 2,646 Purchases of minerals in-place 4,166 1 911 Accretion of discount 1,357 2,260 1,489 Change in income taxes 737 1,467 (2,467) Sales of minerals in-place (1,865) (18) (363) Change in production rates and other (547) (793) (1) $ 1,538 $ (7,561) $ 5,242

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	The Company maintains a cybersecurity program that establishes safeguards for protecting the confidentiality, integrity, and availability of the Company’s data, technology, and information systems, and the material risks associated with the threats identified from time to time under the cybersecurity program are incorporated into the Company’s corporate risk register. The program includes general controls for managing changes in and access to the Company’s information technology environment, cybersecurity awareness and training programs to help employees identify and mitigate against cybersecurity threats, cybersecurity incident response plans and third-party incident response retainers to help expedite the Company’s response in the event of a cybersecurity incident, and guidelines regarding system vulnerability management, third-party threat intelligence, endpoint detection and response solutions, and network security measures. The program also establishes protocols for identifying and managing material risks related to cybersecurity threats associated with the Company’s use of third-party service providers. The Company monitors and oversees the material risks related to vulnerabilities, threats, and incidents impacting its third-party service providers via onboarding reviews, threat intelligence reports, and annual assessments. As an example of the Company’s efforts to manage third-party cybersecurity risks, when third parties are engaged to provide software-as-a-service offerings, the Company’s standard licensing terms require such third parties to utilize safeguards to protect the Company’s data, in compliance with applicable standards from the International Organization for Standardization (ISO) regarding security techniques, and to notify the Company within 24 hours of becoming aware of a cybersecurity incident impacting the Company’s data.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	The Company maintains
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The standing Cybersecurity Committee of the Company’s Board of Directors assists with oversight of the Company’s cybersecurity program and the material risks associated with the threats identified under the program. Given the Cybersecurity Committee’s chair’s previous military experience in positions relevant to information security and his NACD-sponsored CERT Certificate in Cybersecurity Oversight from Carnegie Mellon University’s Software Engineering Institute, the committee benefits from his perspectives, skills, and training when reviewing and managing the Company’s exposure to cybersecurity risks.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The standing Cybersecurity Committee of the Company’s Board of Directors assists with oversight of the Company’s cybersecurity program and the material risks associated with the threats identified under the program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Board of Directors
Cybersecurity Risk Role of Management [Text Block]	The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee’s discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company’s internal control over financial reporting. APA’s Executive Vice President, Administration, is primarily responsible for identifying, assessing, and managing the material risks associated with cybersecurity threats and the incidents identified from time to time thereunder. He manages the Company’s Information Security Team, which comprises cybersecurity professionals responsible for the day-to-day operation of the Company’s cybersecurity program and managing the Company’s threat intelligence, vulnerability management, forensics, and security architecture systems. APA’s Executive Vice President, Administration, has 35 years of experience managing data and technology in the energy industry, including serving as the Company’s CIO from 2015-2020. He receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The Executive Vice President, Administration, reports directly to APA’s Chief Executive Officer and presents all relevant information to the Cybersecurity Committee.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee’s discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company’s internal control over financial reporting.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	APA’s Executive Vice President, Administration, has 35 years of experience managing data and technology in the energy industry, including serving as the Company’s CIO from 2015-2020. He receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The Executive Vice President, Administration, reports directly to APA’s Chief Executive Officer and presents all relevant information to the Cybersecurity Committee.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	The Cybersecurity Committee receives regular reports from Company management regarding the Company’s cybersecurity systems and programs, and the committee from time to time also receives updates from external cybersecurity specialists on cybersecurity trends and incidents, including those that may be particularly relevant to the Company’s industry or operations. In addition, in exercising its oversight responsibilities, the Cybersecurity Committee has full access to Company management and may inquire into any matter that it considers to be of material concern to the committee or the full Board of Directors.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. During the quarter ended March 31, 2024 and each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors.
Use of Estimates	Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 10—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of America (refer to Note 11—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 17—Supplemental Oil and Gas Disclosures (Unaudited) ).
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Revenue Recognition	Revenue Recognition The Company’s oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third parties to provide flexibility to fulfill sales obligations and commitments. Under these commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title. APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Refer to Note 16—Business Segment Information for a disaggregation of revenue by product and reporting segment. Payment Terms and Contract Balances Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.7 billion and $1.5 billion as of December 31, 2024 and 2023, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout 2024, and management believes that the Company will be able to collect the total balance of its receivables from this customer. In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Cash and Cash Equivalents	Cash and Cash Equivalents
Accounts Receivable and Allowance for Credit Losses	Accounts Receivable and Allowance for Credit Losses Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity.
Inventories	Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
Property and Equipment	Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date. Other Property and Equipment
Oil and Gas Property	Oil and Gas Property The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations. The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2024 2023 2022 (In millions) Proved properties: U.S. $ 315 $ — $ — Egypt — — — North Sea 796 — — Total proved properties $ 1,111 $ — $ — Unproved properties: U.S. $ 34 $ 10 $ 20 Egypt — — 4 North Sea — 11 — Other International 1 1 — Total unproved properties $ 35 $ 22 $ 24 Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost. Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $796 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million. Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail. For the years ended December 31, 2023, and 2022, the Company recorded no impairments of proved properties.
Gathering, Processing, and Transmission (GPT) Facilities	Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $433 million and $448 million at December 31, 2024 and 2023, respectively, with accumulated depreciation for these assets totaling $364 million and $373 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. For the years ended December 31, 2024, 2023, and 2022, the Company recorded no impairments of GPT facilities.
Asset Retirement Costs and Obligations	Asset Retirement Costs and Obligations The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.
Capitalized Interest	Capitalized Interest
Equity Method Interests	Equity Method Interests The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company. Refer to Note 6—Equity Method Interests for further details of the Company’s equity method interests. Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
Commitments and Contingencies	Commitments and Contingencies
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.
Income Taxes	Income Taxes
Earnings Per Share	Earnings Per Share The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.
Stock-Based Compensation	Stock-Based Compensation
Treasury Stock	Treasury Stock The Company follows the weighted-average-cost method of accounting for treasury stock transactions.
New Pronouncements Issued But Not Yet Adopted	New Pronouncements Issued But Not Yet Adopted In December 2023, the FASB issued ASU 2023-09 “Improvements to Income Tax Disclosures (Topic 740),” which requires enhanced disclosures primarily related to existing rate reconciliation and income taxes paid information. This update is effective for the Company beginning in the first quarter of 2025 and is applied on a prospective basis. The Company does not believe this will have a material impact on its financial statements.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Schedule of Allowance for Credit Losses	The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2024 2023 2022 (In millions) Allowance for credit loss at beginning of year $ 114 $ 117 $ 109 Additional provisions for the year 9 16 9 Uncollectible accounts written off, net of recoveries — (19) (1) Allowance for credit loss at end of year $ 123 $ 114 $ 117
Schedule of Non-cash Impairment Charges of Proved and Unproved Properties	The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2024 2023 2022 (In millions) Proved properties: U.S. $ 315 $ — $ — Egypt — — — North Sea 796 — — Total proved properties $ 1,111 $ — $ — Unproved properties: U.S. $ 34 $ 10 $ 20 Egypt — — 4 North Sea — 11 — Other International 1 1 — Total unproved properties $ 35 $ 22 $ 24

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
Schedule of Assets Acquired and Liabilities Assumed	The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. (In millions) Current assets $ 287 Property and equipment 4,502 Deferred tax asset 565 Other assets 12 Total assets acquired $ 5,366 Current liabilities $ 632 Long-term debt 2,113 Asset retirement obligation 136 Other long-term obligations 48 Total liabilities assumed $ 2,929 Net assets acquired $ 2,437
Schedule of Pro Forma Adjustment	The following unaudited pro forma combined results for the years ended December 31, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, and estimated tax impacts of the pro forma adjustments. For the Year Ended December 31, 2024 2023 (In millions) Revenues $ 10,300 $ 10,578 Net income attributable to common stock 909 4,021 Net income per common share – basic 2.45 10.66 Net income per common share – diluted 2.45 10.63

CAPITALIZED EXPLORATORY WELL _2

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
Schedule of Capitalized Exploratory Well Costs, Roll Forward	The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2024, 2023, and 2022. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. For the Year Ended December 31, 2024 2023 2022 (In millions) Capitalized well costs at beginning of year $ 586 $ 474 $ 321 Additions pending determination of proved reserves 240 265 287 Reclassifications to proved properties (506) (135) (110) Charged to exploration expense (83) (18) (24) Capitalized well costs at end of year $ 237 $ 586 $ 474
Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging	The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31: 2024 2023 2022 (In millions) Exploratory well costs capitalized for a period of one year or less $ 107 $ 156 $ 215 Exploratory well costs capitalized for a period greater than one year 130 430 259 Capitalized well costs at end of year $ 237 $ 586 $ 474 Number of projects with exploratory well costs capitalized for a period greater than one year 12 33 21
Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year	The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2024, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2023 2022 2021 and Prior (In millions) Suriname $ 115 $ 60 $ — $ 55 Egypt 15 15 — — $ 130 $ 75 $ — $ 55

DERIVATIVE INSTRUMENTS AND HE_2

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations	The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: For the Year Ended December 31, 2024 2023 (In millions) Current Assets: Other current assets $ — $ 6 Total derivative assets $ — $ 6 Deferred Credits and Other Noncurrent Liabilities: Other $ 18 $ — Total derivative liabilities $ 18 $ — The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: For the Year Ended December 31, 2024 2023 2022 (In millions) Realized: Commodity derivative instruments $ 2 $ 48 $ (34) Contingent consideration arrangements (4) — — Foreign currency derivative instruments — — (13) Realized gains (losses), net (2) 48 (47) Unrealized: Commodity derivative instruments (6) 51 (36) Contingent consideration arrangements (2) — — Preferred Units embedded derivative — — (31) Unrealized gains (losses), net (8) 51 (67) Derivative instrument gains (losses), net $ (10) $ 99 $ (114)

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2024
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of Other Current Assets	The following table provides detail of the Company’s other current assets as of December 31: 2024 2023 (In millions) Inventories $ 425 $ 453 Drilling advances 184 88 Prepaid assets and other 54 46 Current decommissioning security for sold Gulf of America assets 157 178 Total Other current assets $ 820 $ 765

EQUITY METHOD INTERESTS (Tables

EQUITY METHOD INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Sales and Costs Associated With Equity Method Interests	The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors: For the Year Ended December 31, 2024 2023 2022 (In millions) Natural gas and NGLs sales $ 13 $ 92 $ 18 Purchased oil and gas sales 22 29 — $ 35 $ 121 $ 18 Gathering, processing, and transmission costs $ 23 $ 108 $ 93 Purchased oil and gas costs 23 80 — Lease operating expenses 2 7 — $ 48 $ 195 $ 93

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
Schedule of Other Current Liabilities	The following table provides detail of the Company’s other current liabilities as of December 31: 2024 2023 (In millions) Accrued operating expenses $ 204 $ 162 Accrued exploration and development 460 371 Accrued compensation and benefits 223 390 Accrued interest 93 93 Accrued income taxes 221 138 Current asset retirement obligation 103 76 Current operating lease liability 118 116 Current decommissioning contingency for sold Gulf of America properties 88 60 Other 168 338 Total Other current liabilities $ 1,678 $ 1,744

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes to Asset Retirement Obligation	The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2024 and 2023: For the Year Ended December 31, 2024 2023 (In millions) Asset retirement obligation at beginning of the year $ 2,438 $ 1,995 Liabilities incurred 15 14 Liabilities acquired 136 — Liabilities divested (272) — Liabilities settled (70) (43) Accretion expense 148 116 Revisions in estimated liabilities 299 356 Asset retirement obligation at end of the year 2,694 2,438 Less current portion (103) (76) Asset retirement obligation, long-term $ 2,591 $ 2,362

DEBT AND FINANCING COSTS (Table

DEBT AND FINANCING COSTS (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the carrying value of the Company’s debt as of December 31, 2024 and 2023: December 31, 2024 2023 (In millions) 4.625% notes due 2025 (1) $ 51 $ 51 7.7% notes due 2026 78 78 7.95% notes due 2026 132 132 4.875% notes due 2027 (1) 108 108 4.375% notes due 2028 (1) 325 325 7.75% notes due 2029 (1)(2) 235 235 4.25% notes due 2030 (1) 516 516 6.0% notes due 2037 (1) 443 443 5.1% notes due 2040 (1) 1,333 1,333 5.25% notes due 2042 (1) 399 399 4.75% notes due 2043 (1) 428 428 4.25% notes due 2044 (1) 211 211 7.375% debentures due 2047 150 150 5.35% notes due 2049 (1) 387 387 7.625% debentures due 2096 39 39 Apache notes and debentures before unamortized discount and debt issuance costs (3) 4,835 4,835 Commercial paper 323 — Term loan facility 900 — Syndicated credit facilities (4) 10 372 Apache finance lease obligations 30 32 Unamortized discount (25) (26) Debt issuance costs (29) (25) Total debt 6,044 5,188 Current maturities (53) (2) Long-term debt $ 5,991 $ 5,186 (1) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable. (2) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (3) The fair values of Apache’s notes and debentures were $4.4 billion and $4.3 billion as of December 31, 2024 and 2023, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (4) The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates. The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA’s exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA’s exchange or tender offers): January 10, 2025 APA Apache (In millions) 4.625% notes due 2025 $ — $ 51 7.7% notes due March 2026 (1)(5)(6) 58 21 7.95% notes due April 2026 (1)(5)(6) 56 76 4.875% notes due 2027 (4)(5)(6) 39 69 4.375% notes due 2028 (4)(5)(6) 239 86 7.75% notes due 2029 (2)(5)(6) 164 72 4.25% notes due 2030 (4)(5)(6) 374 142 6.0% notes due 2037 (1)(5)(6) 341 102 5.1% notes due 2040 (1)(5)(6) 539 225 5.25% notes due 2042 (1)(5)(6) 209 65 4.75% notes due 2043 (3)(5)(6) 153 79 4.25% notes due 2044 (3)(5)(6) 77 24 7.375% debentures due 2047 (1)(5)(6) 126 24 5.35% notes due 2049 (4)(5)(6) 330 57 7.625% debentures due 2096 (1)(5)(6) 37 2 6.1% notes due 2035 (7) 350 — 6.75% notes due 2055 (7) 500 — Total $ 3,592 $ 1,095 (1) The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture). (2) The Apache 2029 notes were issued under the Indenture, dated as of November 23, 1999, between Apache (as successor to Apache Finance Canada Corporation), and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture). (3) The Apache 2043 notes and the Apache 2044 notes were issued under the Senior Indenture, dated as of May 19, 2011, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture). (4) The Apache 2027 notes, the Apache 2028 notes, the Apache 2030 notes, and the Apache 2049 notes were issued under the Indenture, dated as of August 14, 2018, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture). (5) In connection with APA’s exchange and tender offers, Apache solicited the consents of the holders of these Apache notes and debentures to amend the applicable Apache Indenture to remove certain restrictive and reporting covenants. The Apache notes and debentures are senior unsecured obligations of Apache. Apache received consents sufficient to approve the proposed amendments to the Apache Indentures with respect to the Apache March 2026 notes, the Apache 2028 notes, the Apache 2029 notes, the Apache 2030 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2043 notes, the Apache 2044 notes, the Apache 2047 debentures, the Apache 2049 notes, and the Apache 2096 debentures. As a result, Apache and the respective trustee for the Apache Indentures entered into supplemental indentures on January 10, 2025, implementing the proposed amendments effective as of that date. (6) The APA March 2026 notes, the APA April 2026 notes, the APA 2027 notes, the APA 2028 notes, the APA 2029 notes, the APA 2030 notes, the APA 2037 notes, the APA 2040 notes, the APA 2042 notes, the APA 2043 notes, the APA 2044 notes, the APA 2047 debentures, the APA 2049 notes, and the APA 2096 debentures were issued under the Indenture, dated as of June 30, 2021, between the Company, as issuer, and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee. These APA notes and debentures were issued in APA’s exchange and tender offers for Apache’s notes and debentures. (7) The APA 2035 notes and the APA 2055 notes were issued under the Indenture, dated as of December 11, 2024, between the Company, as issuer, and Regions Bank, as trustee. These APA notes were issued in APA’s new notes offering to fund in part its purchase of Apache notes in APA’s cash tender offers.
Schedule of Maturities of Long-Term Debt	Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2024 are as follows: (In millions) 2025 $ 51 2026 210 2027 108 2028 325 2029 235 Thereafter 3,906 Notes and debentures, excluding discounts and debt issuance costs $ 4,835
Schedule of Components of Financing Costs, Net	The following table presents the components of the Company’s financing costs, net: For the Year Ended December 31, 2024 2023 2022 (In millions) Interest expense $ 402 $ 351 $ 332 Amortization of debt issuance costs 6 4 8 Capitalized interest (29) (24) (18) Loss (gain) on extinguishment of debt — (9) 67 Interest income (12) (10) (10) Financing costs, net $ 367 $ 312 $ 379

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Net Income Before Income Taxes	Net income before income taxes was composed of the following: For the Year Ended December 31, 2024 2023 2022 (In millions) U.S. $ 705 $ 627 $ 2,675 Foreign 830 2,256 3,059 Total $ 1,535 $ 2,883 $ 5,734
Schedule of Total Provision for Income Taxes	The total income tax provision (benefit) consisted of the following: For the Year Ended December 31, 2024 2023 2022 (In millions) Current income taxes: Federal $ 76 $ 2 $ 1 State 2 6 11 Foreign 1,075 1,330 1,495 1,153 1,338 1,507 Deferred income taxes: Federal (96) (1,708) — State 3 (32) — Foreign (643) 78 145 (736) (1,662) 145 Total $ 417 $ (324) $ 1,652
Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense	A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below: For the Year Ended December 31, 2024 2023 2022 (In millions) Income tax expense at U.S. statutory rate $ 322 $ 605 $ 1,204 State income tax, less federal effect (1) 2 (23) 9 Taxes related to foreign operations 45 752 745 Tax credits (3) — (4) Net change in tax contingencies 2 5 1 Valuation allowances (1) — (1,842) (646) Tax adjustments attributable to BCP Business Combination — — 126 Stock compensation 17 (2) 7 Legal reserve 14 — — Remeasurement of U.K. deferred tax liability — 174 208 Transaction costs 5 — — All other, net 13 7 2 $ 417 $ (324) $ 1,652 (1) The change in state valuation allowance is included as a component of state income tax.
Schedule of Net Deferred Tax (Asset) Liability	The net deferred income tax (asset) liability consisted of the following as of December 31: 2024 2023 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,487 $ 2,050 Capital losses 14 8 Foreign net operating losses 55 43 Tax credits and other tax incentives 105 26 Foreign tax credits 2,204 2,204 Accrued expenses and liabilities 76 129 Asset retirement obligation 952 850 Property and equipment 45 38 Equity investments 1 8 Net interest expense limitation 287 125 Lease liability 114 71 Decommissioning contingency for sold Gulf of America properties 232 210 Total deferred tax assets 6,572 5,762 Valuation allowance (2,623) (2,630) Net deferred tax assets 3,949 3,132 Deferred tax liabilities: Property and equipment 1,060 1,573 Right-of-use asset 111 69 Decommissioning security for sold Gulf of America properties 40 44 Other 49 59 Total deferred tax liabilities 1,260 1,745 Net deferred income tax asset $ (2,689) $ (1,387) Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2024 2023 (In millions) Assets: Other assets Deferred tax asset $ 2,703 $ 1,758 Liabilities: Deferred credits and other noncurrent liabilities Deferred tax liability 14 371 Net deferred income tax asset $ (2,689) $ (1,387)
Schedule of Valuation Allowance	In 2024, 2023, and 2022, the Company’s valuation allowance decreased by $7 million, $2.3 billion and $1.0 billion, respectively, as detailed in the table below: 2024 2023 2022 (In millions) Balance at beginning of year $ 2,630 $ 4,918 $ 5,902 State (1) (51) (63) (111) U.S. 26 (2,235) (706) Foreign 18 10 (167) Balance at end of year $ 2,623 $ 2,630 $ 4,918 (1) Reported as a component of state income taxes.
Schedule of Net Operating Losses	On December 31, 2024, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 10,345 2028 - Indefinite State 6,586 Various Foreign 153 2025 - Indefinite
Schedule of Foreign Tax Credit Carryforward	On December 31, 2024, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,204 2025-2026
Schedule of Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2024 2023 2022 (In millions) Balance at beginning of year $ 93 $ 89 $ 116 Additions based on tax positions related to prior year 1 4 — Additions based on tax positions related to the current year — — — Reductions for tax positions of prior years (5) — (27) Balance at end of year $ 89 $ 93 $ 89
Schedule of Key Jurisdictions of Company's Earliest Open Tax Years	The Company’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2022

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of Weighted Average Lease Term And Discount Rate	The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2024: Operating Leases Finance Lease Weighted average remaining lease term 6.9 years 8.7 years Weighted average discount rate 5.8 % 4.4 %
Schedule of Operating Lease, Liability, Maturity	At December 31, 2024, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2025 $ 122 $ 3 $ 244 2026 61 4 245 2027 48 4 173 2028 42 4 166 2029 35 4 148 Thereafter 159 18 142 Total future minimum payments 467 37 $ 1,118 Less: imputed interest (94) (7) N/A Total lease liabilities 373 30 N/A Current portion 118 2 N/A Non-current portion $ 255 $ 28 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $245 million, $182 million, and $183 million in 2024, 2023, and 2022, respectively. (5) Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation.
Schedule of Finance Lease, Liability, Maturity	At December 31, 2024, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2025 $ 122 $ 3 $ 244 2026 61 4 245 2027 48 4 173 2028 42 4 166 2029 35 4 148 Thereafter 159 18 142 Total future minimum payments 467 37 $ 1,118 Less: imputed interest (94) (7) N/A Total lease liabilities 373 30 N/A Current portion 118 2 N/A Non-current portion $ 255 $ 28 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $245 million, $182 million, and $183 million in 2024, 2023, and 2022, respectively. (5) Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation.
Schedule of Long-term Purchase Commitment	At December 31, 2024, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2025 $ 122 $ 3 $ 244 2026 61 4 245 2027 48 4 173 2028 42 4 166 2029 35 4 148 Thereafter 159 18 142 Total future minimum payments 467 37 $ 1,118 Less: imputed interest (94) (7) N/A Total lease liabilities 373 30 N/A Current portion 118 2 N/A Non-current portion $ 255 $ 28 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $245 million, $182 million, and $183 million in 2024, 2023, and 2022, respectively. (5) Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation.

RETIREMENT AND DEFERRED COMPE_2

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
Schedule of Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans	The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2024, 2023, and 2022, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans. 2024 2023 2022 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 118 $ 15 $ 108 $ 15 $ 211 $ 20 Service cost 1 1 1 1 2 1 Interest cost 6 1 5 1 3 — Foreign currency exchange rates (2) — 6 — (21) — Actuarial losses (gains) (11) — 3 — (79) (5) Plan settlements — (1) — — — — Benefits paid (5) (2) (5) (3) (8) (3) Retiree contributions — 1 — 1 — 2 Projected benefit obligation at end of year 107 15 118 15 108 15 Change in Plan Assets Fair value of plan assets at beginning of year 150 — 137 — 254 — Actual return (loss) on plan assets (8) — 8 — (87) — Foreign currency exchange rates (3) — 8 — (26) — Employer contributions 2 1 2 1 4 2 Plan settlements — — — — — — Benefits paid (5) (2) (5) (3) (8) (4) Retiree contributions — 1 — 2 — 2 Fair value of plan assets at end of year 136 — 150 — 137 — Funded status at end of year $ 29 $ (15) $ 32 $ (15) $ 29 $ (15) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (13) 32 (13) 29 (13) $ 29 $ (15) $ 32 $ (15) $ 29 $ (15) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (16) $ 14 $ (12) $ 16 $ (10) $ 18 Weighted Average Assumptions used as of December 31 Discount rate 5.60 % 5.49 % 4.80 % 5.00 % 5.00 % 5.29 % Salary increases 4.70 % N/A 4.60 % N/A 4.70 % N/A Expected return on assets 5.70 % N/A 4.80 % N/A 4.70 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.50 % Ultimate in 2032 N/A 5.25 % N/A 5.25 % N/A 5.25 %
Schedule of Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset	A breakout of allocations for the Company's plan asset holdings are summarized below: Percentage of 2024 2023 Asset Category Global equities — % — % Multi-asset credit 62 % 59 % Nominal bonds 4 % 6 % Inflation-linked bonds 33 % 33 % Cash 1 % 2 % Total 100 % 100 %
Schedule of Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets	The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets as follows: December 31, 2024 2023 (In millions) Asset Category Global equities $ — $ — Multi-asset credit 84 88 Nominal bonds 6 9 Inflation-linked bonds 45 50 Cash 1 3 Total $ 136 $ 150
Schedule of Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans	The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31 as follows: 2024 2023 2022 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 1 $ 1 $ 1 $ 1 $ 2 $ 1 Interest cost 6 1 5 1 3 — Expected return on assets (7) — (7) — (4) — Amortization of loss — (2) — (2) — (1) Settlement loss — — — — — — Net periodic benefit cost $ — $ (1) $ (1) $ — $ 1 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 4.80 % 5.00 % 5.00 % 5.29 % 1.80 % 2.57 % Salary increases 4.60 % N/A 4.70 % N/A 4.90 % N/A Expected return on assets 4.80 % N/A 4.70 % N/A 1.90 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.50 % N/A 6.25 % Ultimate in 2030 N/A 5.25 % N/A 5.25 % N/A 5.00 %
Schedule of Expected Future Benefit Payment	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2025 $ 5 $ 2 2026 5 1 2027 6 1 2028 6 1 2029 6 1 Years 2030-2034 35 7

CAPITAL STOCK (Tables)

CAPITAL STOCK (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Schedule of Common Stock Outstanding	The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 Balance, beginning of year 303,575,901 311,559,149 346,930,765 Shares issued for stock-based compensation plans: Treasury shares issued — 2,016 1,996 Common shares issued 70,983,745 725,914 791,381 Treasury shares acquired (9,162,497) (8,711,178) (36,164,993) Balance, end of year 365,397,149 303,575,901 311,559,149
Schedule of Reconciliation of Components of Basic and Diluted Net Income (Loss) Per Common Share	The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Income Shares Per Share Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 804 353 $ 2.28 $ 2,855 308 $ 9.26 $ 3,674 332 $ 11.05 Effect of Dilutive Securities: Stock compensation awards $ — — $ (0.01) $ — 1 $ (0.01) $ — 1 $ (0.03) Diluted: Income attributable to common stock $ 804 353 $ 2.27 $ 2,855 309 $ 9.25 $ 3,674 333 $ 11.02
Schedule of Description of Stock Based Compensation Plans and Related Costs	The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In millions) Stock-settled and cash-settled compensation expensed: Lease operating expenses $ 16 $ 27 $ 82 Exploration 4 7 29 General and administrative 29 50 193 Total stock-settled and cash-settled compensation expensed 49 84 304 Stock-settled and cash-settled compensation capitalized 9 13 44 Total stock-settled and cash-settled compensation costs $ 58 $ 97 $ 348
Schedule of Stock Options Activities	The following table summarizes stock option activity for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Shares Weighted Average Exercise Price Shares Weighted Average Exercise Price Shares Weighted Average Exercise Price (In thousands, except exercise price amounts) Outstanding, beginning of year 1,465 $ 48.48 2,078 $ 57.71 3,012 $ 63.79 Exercised — — (12) 42.38 (99) 42.09 Forfeited — — — — (2) 49.10 Expired (49) 43.91 (601) 80.53 (833) 81.56 Outstanding, end of year (1) 1,416 48.64 1,465 48.48 2,078 57.71 Expected to vest — — — — — — Exercisable, end of year (1) 1,416 48.64 1,465 48.48 2,078 57.71 (1) As of December 31, 2024, options exercisable and outstanding had a weighted average remaining contractual life of 2.1 years and no aggregate intrinsic value.
Schedule of Restricted Stock and Restricted Stock Units Activity	The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 1,480 $ 30.69 1,885 $ 23.08 2,073 $ 19.98 Granted 897 33.48 661 41.60 847 29.90 Assumed awards from Callon acquisition 1,498 35.43 — — — — Vested (3) (2,295) 31.83 (975) 23.31 (978) 22.39 Forfeited (165) 35.48 (69) 32.44 (57) 23.49 Expired — — (22) 27.81 — — Non-vested, end of year (1)(2) 1,415 35.07 1,480 30.69 1,885 23.08 (1) As of December 31, 2024, there was $18 million of total unrecognized compensation cost related to 1,257,784 unvested stock-settled restricted stock units. (2) As of December 31, 2024, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years. (3) The grant date fair values of the stock-settled awards vested during 2024, 2023, and 2022 were $73 million, $23 million, and $22 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In thousands) Non-vested, beginning of year 4,478 5,709 6,402 Adjustment from ALTM transaction (1) — — 143 Granted (2) 2,369 1,972 2,568 Vested (2,568) (2,851) (2,970) Forfeited (362) (340) (434) Expired — (12) — Non-vested, end of year (3) 3,917 4,478 5,709 (1) Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price. (2) Restricted stock phantom units granted during 2024, 2023, and 2022 included 2,369,605, 1,972,116, and 2,512,602 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 included 55,546 awards based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022. (3) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2024 was approximately $34 million. The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022: For the Year Ended December 31, 2024 2023 2022 (In thousands) Non-vested, beginning of year 4,629 4,835 4,531 Granted 834 1,536 1,676 Assumed awards from Callon acquisition 2,934 — — Vested (4,222) (1,593) (656) Forfeited (203) (99) (106) Expired — (50) (610) Non-vested, end of year (1) 3,972 4,629 4,835 (1) As of December 31, 2024, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $12 million.

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Schedule of Components of Accumulated Other Comprehensive Income (loss)	Components of accumulated other comprehensive income include the following: As of December 31, 2024 2023 2022 (In millions) Pension and postretirement benefit plan ( Note 12 ) $ 12 $ 15 $ 14 Accumulated other comprehensive income $ 12 $ 15 $ 14

BUSINESS SEGMENT INFORMATION (T

BUSINESS SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Financial Segment Information	Financial information for each segment is presented below: U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2024 Oil revenues $ 3,572 $ 2,620 $ 774 $ — $ 6,966 Natural gas revenues 126 313 145 — 584 Natural gas liquids revenues 617 — 29 — 646 Oil, natural gas, and natural gas liquids production revenues 4,315 2,933 948 — 8,196 Purchased oil and gas sales 1,541 — — — 1,541 5,856 2,933 948 — 9,737 Operating Expenses: Lease operating expenses (5) 820 464 406 — 1,690 Gathering, processing, and transmission (5) 354 25 53 — 432 Purchased oil and gas costs 1,047 — — — 1,047 Taxes other than income (5) 270 — — — 270 Exploration (4) 134 112 1 66 313 Depreciation, depletion, and amortization (5) 1,340 625 301 — 2,266 Asset retirement obligation accretion 42 — 106 — 148 Impairments 320 — 809 — 1,129 4,327 1,226 1,676 66 7,295 Operating Income (Loss) $ 1,529 $ 1,707 $ (728) $ (66) 2,442 Other Income (Expense): Gain on divestitures, net 289 Losses on previously sold Gulf of America properties (273) Derivative instrument losses, net (10) Other (6) General and administrative (372) Transaction, reorganization, and separation (168) Financing costs, net (367) Income Before Income Taxes $ 1,535 Total Assets (3) $ 13,870 $ 3,606 $ 1,324 $ 590 $ 19,390 Net Property and Equipment $ 9,109 $ 2,271 $ 712 $ 554 $ 12,646 Additions to Net Property and Equipment $ 6,609 $ 765 $ 41 $ 84 $ 7,499 U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2023 Oil revenues $ 2,241 $ 2,683 $ 1,073 $ — $ 5,997 Natural gas revenues 297 346 237 — 880 Natural gas liquids revenues 480 — 28 — 508 Oil, natural gas, and natural gas liquids production revenues 3,018 3,029 1,338 — 7,385 Purchased oil and gas sales 894 — — — 894 3,912 3,029 1,338 — 8,279 Operating Expenses: Lease operating expenses (5) 593 474 369 — 1,436 Gathering, processing, and transmission (5) 249 33 52 — 334 Purchased oil and gas costs 742 — — — 742 Taxes other than income (5) 207 — — — 207 Exploration (4) 14 119 19 43 195 Depreciation, depletion, and amortization (5) 745 524 271 — 1,540 Asset retirement obligation accretion 40 — 76 — 116 Impairments 11 — 50 — 61 2,601 1,150 837 43 4,631 Operating Income (Loss) $ 1,311 $ 1,879 $ 501 $ (43) 3,648 Other Income (Expense): Gain on divestitures, net 8 Losses on previously sold Gulf of America properties (212) Derivative instrument gains, net 99 Other 18 General and administrative (351) Transaction, reorganization, and separation (15) Financing costs, net (312) Income Before Income Taxes $ 2,883 Total Assets (3) $ 9,221 $ 3,503 $ 1,970 $ 550 $ 15,244 Net Property and Equipment $ 5,689 $ 2,209 $ 1,628 $ 512 $ 10,038 Additions to Net Property and Equipment $ 1,255 $ 834 $ 131 $ 93 $ 2,313 U.S. Egypt (1) North Sea Intersegment Eliminations & Other (6) Total (2) (In millions) 2022 Oil revenues $ 2,458 $ 3,145 $ 1,232 $ — $ 6,835 Natural gas revenues 918 370 281 — 1,569 Natural gas liquids revenues 768 6 45 (3) 816 Oil, natural gas, and natural gas liquids production revenues 4,144 3,521 1,558 (3) 9,220 Purchased oil and gas sales 1,850 — — 5 1,855 5,994 3,521 1,558 2 11,075 Operating Expenses: Lease operating expenses (5) 515 526 404 (1) 1,444 Gathering, processing, and transmission (5) 315 22 43 (13) 367 Purchased oil and gas costs 1,776 — — — 1,776 Taxes other than income (5) 265 — — 3 268 Exploration (4) 24 84 35 162 305 Depreciation, depletion, and amortization (5) 593 400 238 2 1,233 Asset retirement obligation accretion 34 — 82 1 117 3,522 1,032 802 154 5,510 Operating Income (Loss) $ 2,472 $ 2,489 $ 756 $ (152) 5,565 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of America properties (157) Derivative instrument losses, net (114) Other 148 General and administrative (483) Transaction, reorganization, and separation (26) Financing costs, net (379) Income Before Income Taxes $ 5,734 Total Assets (3) $ 7,574 $ 3,148 $ 1,911 $ 514 $ 13,147 Net Property and Equipment $ 5,226 $ 1,976 $ 1,386 $ 424 $ 9,012 Additions to Net Property and Equipment $ 1,439 $ 695 $ 210 $ 263 $ 2,607 (1) Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2024, 2023, and 2022 of: For the Year Ended December 31, 2024 2023 2022 (In millions) Oil $ 686 $ 729 $ 989 Natural gas 83 95 117 Natural gas liquids — — 2 (2) Includes a noncontrolling interest in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the year 2022. (3) Intercompany balances are excluded from total assets. (4) Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities. (5) Represents significant segment expense categories that align with the segment-level information that is regularly provided to the CODM. The remaining expenses that comprise the Other Income (Loss) amount by segment are deemed to be other segment expense categories necessary to arrive at the segment profit or loss. (6) Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported. For 2022, the Company’s midstream business results are also included in this category as the midstream operating segment has not met the quantitative thresholds to be separately reported.

SUPPLEMENTAL OIL AND GAS DISC_2

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
Schedule of Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities	The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2024 Oil and gas production revenues $ 4,315 $ 2,933 $ 948 $ — $ 8,196 Operating cost: Depreciation, depletion, and amortization (2) 1,314 621 300 — 2,235 Asset retirement obligation accretion 42 — 106 — 148 Lease operating expenses 820 464 406 — 1,690 Gathering, processing, and transmission 354 25 53 — 432 Exploration expenses 134 112 1 66 313 Impairments related to oil and gas properties 315 — 796 — 1,111 Production taxes (3) 268 — — — 268 Income tax 235 770 (536) — 469 3,482 1,992 1,126 66 6,666 Results of operations $ 833 $ 941 $ (178) $ (66) $ 1,530 2023 Oil and gas production revenues $ 3,018 $ 3,029 $ 1,338 $ — $ 7,385 Operating cost: Depreciation, depletion, and amortization (2) 709 521 270 — 1,500 Asset retirement obligation accretion 40 — 76 — 116 Lease operating expenses 593 474 369 — 1,436 Gathering, processing, and transmission 249 33 52 — 334 Exploration expenses 14 119 19 43 195 Production taxes (3) 204 — — — 204 Income tax 254 828 414 — 1,496 2,063 1,975 1,200 43 5,281 Results of operations $ 955 $ 1,054 $ 138 $ (43) $ 2,104 2022 Oil and gas production revenues $ 4,144 $ 3,521 $ 1,558 $ — $ 9,223 Operating cost: Depreciation, depletion, and amortization (2) 564 390 232 — 1,186 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 515 526 404 — 1,445 Gathering, processing, and transmission 315 22 43 — 380 Exploration expenses 24 84 35 162 305 Production taxes (3) 263 — — — 263 Income tax 510 1,100 495 — 2,105 2,225 2,122 1,291 162 5,800 Results of operations $ 1,919 $ 1,399 $ 267 $ (162) $ 3,423 (1) Includes a noncontrolling interest in Egypt. (2) Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 16—Business Segment Information . (3) Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 16—Business Segment Information .
Schedule of Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities	Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United Egypt (2) North Sea Other Total (2) (In millions) 2024 Acquisitions: Proved $ 3,606 $ 3 $ — $ — $ 3,609 Unproved 955 — — — 955 Exploration 150 227 1 61 439 Development 2,067 559 186 47 2,859 Costs incurred (1) $ 6,778 $ 789 $ 187 $ 108 $ 7,862 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ 3 $ — $ — $ 26 $ 29 Asset retirement costs 171 — 145 — 316 2023 Acquisitions: Proved $ 1 $ 4 $ — $ — $ 5 Unproved 20 — — — 20 Exploration 31 226 44 131 432 Development 1,148 646 468 — 2,262 Costs incurred (1) $ 1,200 $ 876 $ 512 $ 131 $ 2,719 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ — $ — $ — $ 24 $ 24 Asset retirement costs (4) — 375 — 371 2022 Acquisitions: Proved $ 596 $ 3 $ — $ — $ 599 Unproved 66 — — — 66 Exploration 4 169 61 311 545 Development 848 568 (57) — 1,359 Costs incurred (1) $ 1,514 $ 740 $ 4 $ 311 $ 2,569 (1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ 1 $ 17 $ 18 Asset retirement costs 79 — (215) — (136) (2) Includes a noncontrolling interest in Egypt. The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities: United Egypt (1) North Other Total (1) (In millions) 2024 Proved properties $ 19,246 $ 14,458 $ 9,661 $ 434 $ 43,799 Unproved properties 711 67 — 121 899 19,957 14,525 9,661 555 44,698 Accumulated DD&A (11,053) (12,299) (8,952) — (32,304) $ 8,904 $ 2,226 $ 709 $ 555 $ 12,394 2023 Proved properties $ 20,758 $ 13,777 $ 9,472 $ — $ 44,007 Unproved properties 267 71 3 512 853 21,025 13,848 9,475 512 44,860 Accumulated DD&A (15,587) (11,678) (7,849) — (35,114) $ 5,438 $ 2,170 $ 1,626 $ 512 $ 9,746 (1) Includes a noncontrolling interest in Egypt.
Schedule of Proved Reserve Data	There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Crude Oil and Condensate United Egypt (1) North Suriname Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2021 180,968 106,646 77,073 — 364,687 December 31, 2022 177,708 108,050 82,580 — 368,338 December 31, 2023 179,542 102,305 61,076 — 342,923 December 31, 2024 184,744 95,990 30,436 — 311,170 Proved undeveloped reserves: December 31, 2021 18,168 11,003 5,757 — 34,928 December 31, 2022 22,239 8,557 2,873 — 33,669 December 31, 2023 30,948 5,254 — — 36,202 December 31, 2024 107,283 7,621 — 73,637 188,541 Total proved reserves: Balance December 31, 2021 199,136 117,649 82,830 — 399,615 Extensions, discoveries and other additions 9,776 7,580 2,616 — 19,972 Purchases of minerals in-place 16,362 — — — 16,362 Revisions of previous estimates 7,793 22,433 11,898 — 42,124 Production (25,695) (31,055) (11,891) — (68,641) Sales of minerals in-place (7,425) — — — (7,425) Balance December 31, 2022 199,947 116,607 85,453 — 402,007 Extensions, discoveries and other additions 43,613 12,979 301 — 56,893 Purchases of minerals in-place 20 — — — 20 Revisions of previous estimates (3,520) 10,505 (12,002) — (5,017) Production (28,795) (32,532) (12,676) — (74,003) Sales of minerals in-place (775) — — — (775) Balance December 31, 2023 210,490 107,559 61,076 — 379,125 Extensions, discoveries and other additions 100,778 18,115 — 73,637 192,530 Purchases of minerals in-place 124,112 — — — 124,112 Revisions of previous estimates (9,642) 10,521 (21,000) — (20,121) Production (47,043) (32,584) (9,640) — (89,267) Sales of minerals in-place (86,668) — — — (86,668) Balance December 31, 2024 292,027 103,611 30,436 73,637 499,711 (1) Includes proved reserves of 35 MMbbls, 36 MMbbls, 39 MMbbls, and 39 MMbbls as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 158,745 — 2,230 160,975 December 31, 2023 153,486 — 1,460 154,946 December 31, 2024 153,523 — 744 154,267 Proved undeveloped reserves: December 31, 2021 16,380 30 275 16,685 December 31, 2022 19,004 — 76 19,080 December 31, 2023 18,401 — — 18,401 December 31, 2024 54,674 — — 54,674 Total proved reserves: Balance December 31, 2021 180,552 476 2,334 183,362 Extensions, discoveries and other additions 5,456 — 45 5,501 Purchases of minerals in-place 10,985 — — 10,985 Revisions of previous estimates 9,991 (407) 333 9,917 Production (22,895) (69) (406) (23,370) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 177,749 — 2,306 180,055 Extensions, discoveries and other additions 25,711 — 371 26,082 Purchases of minerals in-place 21 — — 21 Revisions of previous estimates (8,568) — (764) (9,332) Production (22,993) — (453) (23,446) Sales of minerals in-place (33) — — (33) Balance December 31, 2023 171,887 — 1,460 173,347 Extensions, discoveries and other additions 62,988 — — 62,988 Purchases of minerals in-place 51,406 — — 51,406 Revisions of previous estimates (20,167) — (277) (20,444) Production (27,039) — (439) (27,478) Sales of minerals in-place (30,878) — — (30,878) Balance December 31, 2024 208,197 — 744 208,941 (1) Includes proved reserves of 159 Mbbls as of December 31, 2021, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,166,218 399,502 66,292 1,632,012 December 31, 2023 1,003,956 377,144 46,839 1,427,939 December 31, 2024 866,460 332,905 28,028 1,227,393 Proved undeveloped reserves: December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 210,862 1,068 2,304 214,234 December 31, 2023 99,495 2,612 — 102,107 December 31, 2024 307,775 27,499 — 335,274 Total proved reserves: Balance December 31, 2021 1,421,902 474,725 83,279 1,979,906 Extensions, discoveries and other additions 38,157 10,191 1,643 49,991 Purchases of minerals in-place 70,584 — — 70,584 Revisions of previous estimates 92,599 45,725 (3,431) 134,893 Production (172,752) (130,071) (12,895) (315,718) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,377,080 400,570 68,596 1,846,246 Extensions, discoveries and other additions 158,118 14,188 3,335 175,641 Purchases of minerals in-place 136 — — 136 Revisions of previous estimates (266,664) 83,907 (6,739) (189,496) Production (165,083) (118,909) (18,353) (302,345) Sales of minerals in-place (136) — — (136) Balance December 31, 2023 1,103,451 379,756 46,839 1,530,046 Extensions, discoveries and other additions 354,267 60,366 — 414,633 Purchases of minerals in-place 279,615 — — 279,615 Revisions of previous estimates (224,118) 26,792 (4,176) (201,502) Production (176,941) (106,510) (14,635) (298,086) Sales of minerals in-place (162,039) — — (162,039) Balance December 31, 2024 1,174,235 360,404 28,028 1,562,667 (1) Includes proved reserves of 120 Bcf, 127 Bcf, 134 Bcf, and 158 Bcf as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves United Egypt (1) North Suriname Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2021 551,384 184,563 91,825 — 827,772 December 31, 2022 530,823 174,633 95,859 — 801,315 December 31, 2023 500,354 165,162 70,343 — 735,859 December 31, 2024 482,677 151,474 35,852 — 670,003 Proved undeveloped reserves: December 31, 2021 65,288 12,683 7,219 — 85,190 December 31, 2022 76,386 8,735 3,333 — 88,454 December 31, 2023 65,931 5,690 — — 71,621 December 31, 2024 213,253 12,204 — 73,637 299,094 Total proved reserves: Balance December 31, 2021 616,672 197,246 99,044 — 912,962 Extensions, discoveries and other additions 21,592 9,278 2,935 — 33,805 Purchases of minerals in-place 39,110 — — — 39,110 Revisions of previous estimates 33,217 29,647 11,659 — 74,523 Production (77,382) (52,803) (14,446) — (144,631) Sales of minerals in-place (26,000) — — — (26,000) Balance December 31, 2022 607,209 183,368 99,192 — 889,769 Extensions, discoveries and other additions 95,677 15,344 1,228 — 112,249 Purchases of minerals in-place 64 — — — 64 Revisions of previous estimates (56,532) 24,490 (13,889) — (45,931) Production (79,302) (52,350) (16,188) — (147,840) Sales of minerals in-place (831) — — — (831) Balance December 31, 2023 566,285 170,852 70,343 — 807,480 Extensions, discoveries and other additions 222,811 28,176 — 73,637 324,624 Purchases of minerals in-place 222,121 — — — 222,121 Revisions of previous estimates (67,162) 14,986 (21,973) — (74,149) Production (103,572) (50,336) (12,518) — (166,426) Sales of minerals in-place (144,553) — — — (144,553) Balance December 31, 2024 695,930 163,678 35,852 73,637 969,097 (1) Includes total proved reserves of 55 MMboe, 57 MMboe, 61 MMboe, and 66 MMboe as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt.
Schedule of Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense	The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2024, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. United Egypt (1) North Suriname Total (1) (In millions) 2024 Cash inflows $ 27,534 $ 9,342 $ 2,828 $ 5,881 $ 45,585 Production costs (9,665) (1,716) (1,399) (1,436) (14,216) Development costs (4,124) (1,517) (2,538) (1,096) (9,275) Income tax expense (921) (1,923) 85 (822) (3,581) Net cash flows 12,824 4,186 (1,024) 2,527 18,513 10 percent discount rate (4,317) (872) 535 (2,280) (6,934) Discounted future net cash flows (2) $ 8,507 $ 3,314 $ (489) $ 247 $ 11,579 2023 Cash inflows $ 21,417 $ 9,921 $ 5,761 $ — $ 37,099 Production costs (8,328) (1,690) (2,773) — (12,791) Development costs (2,238) (1,235) (2,461) — (5,934) Income tax expense (949) (2,222) (946) — (4,117) Net cash flows 9,902 4,774 (419) — 14,257 10 percent discount rate (3,749) (943) 476 — (4,216) Discounted future net cash flows (2) $ 6,153 $ 3,831 $ 57 $ — $ 10,041 2022 Cash inflows $ 31,577 $ 12,819 $ 10,147 $ — $ 54,543 Production costs (10,763) (2,086) (3,241) — (16,090) Development costs (1,733) (1,471) (2,297) — (5,501) Income tax expense (1,575) (2,729) (2,631) — (6,935) Net cash flows 17,506 6,533 1,978 — 26,017 10 percent discount rate (6,811) (1,400) (204) — (8,415) Discounted future net cash flows (2) $ 10,695 $ 5,133 $ 1,774 $ — $ 17,602 (1) Includes discounted future net cash flows of approximately $1.1 billion , $1.3 billion, and $1.7 billion as of December 31, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $14.4 billion , $13.6 billion, and $22.6 billion as of December 31, 2024, 2023, and 2022, respectively.
Schedule of Principal Sources of Change In Discounted Future Net Cash Flows	The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2024 2023 2022 (In millions) Sales, net of production costs $ (5,806) $ (5,408) $ (7,131) Net change in prices and production costs 269 (7,089) 8,690 Discoveries and improved recovery, net of related costs 3,557 1,869 1,142 Change in future development costs (695) (413) (343) Previously estimated development costs incurred during the period 793 825 669 Revision of quantities (428) (262) 2,646 Purchases of minerals in-place 4,166 1 911 Accretion of discount 1,357 2,260 1,489 Change in income taxes 737 1,467 (2,467) Sales of minerals in-place (1,865) (18) (363) Change in production rates and other (547) (793) (1) $ 1,538 $ (7,561) $ 5,242

NATURE OF OPERATIONS (Details)

NATURE OF OPERATIONS (Details)	12 Months Ended
	Dec. 31, 2024 Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)		3 Months Ended	12 Months Ended
	Apr. 01, 2024	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Schedule Of Significant Accounting Policies [Line Items]
Impairments			$ 1,129,000,000	$ 61,000,000	$ 0
Receivables from contracts with customers, net of allowance for doubtful accounts			1,700,000,000	1,500,000,000
Cash and cash equivalent			625,000,000	87,000,000
Restricted cash			0	0
Inventory write-downs			18,000,000
Inventory and other, impairments				50,000,000
Gathering, processing, and transmission facilities			433,000,000	448,000,000
GPT facilities, accumulated depreciation			364,000,000	373,000,000
Other property and equipment			183,000,000	217,000,000
Transaction, reorganization, and separation			168,000,000	15,000,000	26,000,000
Callon Acquisition
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation			147,000,000
Employee Severance
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation			76,000,000
Other Restructuring
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation			71,000,000
Ongoing consulting and separation costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation				7,000,000	15,000,000
Callon Petroleum Company
Schedule Of Significant Accounting Policies [Line Items]
Consideration transferred	$ 4,500,000,000
Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties			1,111,000,000	0	0
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment			$ 0	0	0
Other Property and Equipment | Minimum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities			3 years
Other Property and Equipment | Maximum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities			20 years
Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties			$ 35,000,000	22,000,000	24,000,000
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Inventory write-downs			13,000,000
North Sea | Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impaired, fair value		$ 263,000,000
North Sea | Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties		796,000,000		0	0
North Sea | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties			0	11,000,000	0
Permian Region | Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties		$ 315,000,000
United States
Schedule Of Significant Accounting Policies [Line Items]
Inventory write-downs			5,000,000
United States | Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties			315,000,000	0	0
United States | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments on proved properties			$ 34,000,000	$ 10,000,000	$ 20,000,000
Apache Egypt | Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners			33.33%

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 114	$ 117	$ 109
Additional provisions for the year	9	16	9
Uncollectible accounts written off, net of recoveries	0	(19)	(1)
Allowance for credit loss at end of year	$ 123	$ 114	$ 117

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Non-cash Impairment Charges of Proved and Unproved Properties (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 1,111,000,000	$ 0	$ 0
Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		35,000,000	22,000,000	24,000,000
U.S. | Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		315,000,000	0	0
U.S. | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		34,000,000	10,000,000	20,000,000
Egypt | Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	0	0
Egypt | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	0	4,000,000
North Sea | Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 796,000,000		0	0
North Sea | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	11,000,000	0
Other International | Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 1,000,000	$ 1,000,000	$ 0

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - 2024 Activity (Details) shares in Millions				3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2024 USD ($)	Apr. 01, 2024 USD ($) a shares	Mar. 18, 2024 USD ($)	Dec. 31, 2024 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Business Acquisition [Line Items]
Proceeds from asset divestitures							$ 1,609,000,000	$ 29,000,000	$ 778,000,000
Proceeds from sale of Kinetik shares							428,000,000	228,000,000	224,000,000
Payments to acquire leasehold and property							60,000,000
Kinetik
Business Acquisition [Line Items]
Proceeds from sale of Kinetik shares			$ 428,000,000
Disposed of by Sale | Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures							91,000,000	29,000,000	52,000,000
Gain (loss) on sale of oil and gas properties							(22,000,000)	$ (8,000,000)	(36,000,000)
Term Loan Credit Agreement, Three Year Tranche Loans | Unsecured Debt
Business Acquisition [Line Items]
Debt instrument, face amount		$ 1,500,000,000
Permian Region
Business Acquisition [Line Items]
Payments to acquire leasehold and property									$ 37,000,000
Permian Region | Oil and Gas Properties, Proved
Business Acquisition [Line Items]
Impairments					$ 315,000,000
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Carrying value of non-core assets disposed	$ 1,100,000,000			$ 1,100,000,000		$ 1,100,000,000	1,100,000,000
Asset retirement obligation assumed	224,000,000
Gain (loss) on sale of oil and gas properties				5,000,000
Permian Region | Disposed of by Sale | Non-Core Mineral And Royalty Interests
Business Acquisition [Line Items]
Carrying value of non-core assets disposed	71,000,000			71,000,000		71,000,000	71,000,000
Proceeds from asset divestitures							394,000,000
Gain (loss) on sale of oil and gas properties							(321,000,000)
Permian Region | Disposed of by Sale | Oil and Gas Properties, Proved
Business Acquisition [Line Items]
Impairments					$ 315,000,000
Permian Region | Disposal Group, Held-for-Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from asset divestitures	869,000,000
TEXAS | Disposed of by Sale
Business Acquisition [Line Items]
Carrying value of non-core assets disposed	$ 347,000,000			$ 347,000,000		347,000,000	347,000,000
Asset retirement obligation assumed							42,000,000
Proceeds from asset divestitures							255,000,000
Gain (loss) on sale of oil and gas properties							$ 50,000,000
Callon Petroleum Company
Business Acquisition [Line Items]
Consideration transferred		$ 4,500,000,000
Business acquisition, equity interests exchange ratio		1.0425
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares		70
Other consideration transferred		$ 24,000,000
Revenue of acquiree since acquisition date						1,200,000,000
Net income of acquiree since acquisition date						$ 262,000,000
Callon Petroleum Company | Delaware Basin
Business Acquisition [Line Items]
Asset acquired, net acres | a		120,000
Callon Petroleum Company | Midland Basin
Business Acquisition [Line Items]
Asset acquired, net acres | a		25,000

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - Schedule of Assets Acquired and Liabilities Assumed (Details) - Callon Petroleum Company $ in Millions	Apr. 01, 2024 USD ($)
Business Acquisition [Line Items]
Current assets	$ 287
Deferred tax asset	565
Other assets	12
Total assets acquired	5,366
Current liabilities	632
Long-term debt	2,113
Asset retirement obligation	136
Other long-term obligations	48
Total liabilities assumed	2,929
Net assets acquired	2,437
Proved properties:
Business Acquisition [Line Items]
Property and equipment	$ 4,502

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - Schedule of Pro Forma Adjustment (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
Revenues	$ 10,300	$ 10,578
Net income attributable to common stock	$ 909	$ 4,021
Net income per common share – basic (in USD per share)	$ 2.45	$ 10.66
Net income per common share – diluted (in USD per share)	$ 2.45	$ 10.63

ACQUISITIONS AND DIVESTITURES_4

ACQUISITIONS AND DIVESTITURES - 2023 Activity (Details) - USD ($) shares in Millions, $ in Millions		3 Months Ended		12 Months Ended
	Mar. 11, 2022	Dec. 31, 2024	Mar. 31, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Proceeds from asset divestitures				$ 1,609	$ 29	$ 778
Disposed of by Sale | Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures				91	29	52
Gain (loss) on sale of oil and gas properties				$ 22	8	$ 36
Permian Region
Business Acquisition [Line Items]
Payments to acquire oil and gas property					$ 20
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Gain (loss) on sale of oil and gas properties		$ (5)
Kinetik
Business Acquisition [Line Items]
Shares sold (in shares)	4		4		7.5
Aggregate issue price of Preferred Units			$ 224		$ 228

ACQUISITIONS AND DIVESTITURES_5

ACQUISITIONS AND DIVESTITURES - 2022 Activity (Details) - USD ($) shares in Millions, $ in Millions			3 Months Ended			12 Months Ended
	Mar. 11, 2022	Feb. 22, 2022	Dec. 31, 2024	Sep. 30, 2022	Mar. 31, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Feb. 21, 2022
Business Acquisition [Line Items]
Payments to acquire leasehold and property						$ 60
Proceeds from asset divestitures						1,609	$ 29	$ 778
Deconsolidation gain		$ 609
Deconsolidation, net amount of balance sheet		193
Equity method interests			$ 0			0	437
Kinetik
Business Acquisition [Line Items]
Equity method interests		$ 802					$ 437
Shares sold (in shares)	4				4		7.5
Aggregate issue price of Preferred Units					$ 224		$ 228
Apache Midstream LLC | ALTM
Business Acquisition [Line Items]
Ownership percentage by parent									79%
BCP Business Combination | Altus Midstream | ALTM
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners		20%
BCP Business Combination | BCP Business Combination Contributor | Kinetik
Business Acquisition [Line Items]
Ownership percentage by parent		75%
BCP Business Combination | Common Class C | Altus Midstream
Business Acquisition [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares)		50
Disposed of by Sale | Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures						91	29	52
Gain (loss) on sale of oil and gas properties						$ 22	8	36
Disposed of by Sale | Non-Core Mineral Rights
Business Acquisition [Line Items]
Proceeds from asset divestitures								726
Gain (loss) on sale of oil and gas properties								560
Delaware Basin
Business Acquisition [Line Items]
Asset acquisition consideration transferred				$ 615
Payments to acquire oil and gas property				24
Asset acquisition, proved properties amount				581
Asset acquisition, unproved leasehold amount				38
Abandonment obligations				$ 4
Permian Region
Business Acquisition [Line Items]
Payments to acquire oil and gas property							$ 20
Payments to acquire leasehold and property								$ 37
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Gain (loss) on sale of oil and gas properties			$ (5)

CAPITALIZED EXPLORATORY WELL _3

CAPITALIZED EXPLORATORY WELL COSTS - Schedule of Capitalized Exploratory Well Costs, Roll Forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Capitalized Exploratory Well Cost [Roll Forward]
Capitalized well costs at beginning of year	$ 586	$ 474	$ 321
Additions pending determination of proved reserves	240	265	287
Reclassifications to proved properties	(506)	(135)	(110)
Charged to exploration expense	(83)	(18)	(24)
Capitalized well costs at end of year	$ 237	$ 586	$ 474

CAPITALIZED EXPLORATORY WELL _4

CAPITALIZED EXPLORATORY WELL COSTS - Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging (Details) $ in Millions	Dec. 31, 2024 USD ($) Project	Dec. 31, 2023 USD ($) Project	Dec. 31, 2022 USD ($) Project	Dec. 31, 2021 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 107	$ 156	$ 215
Exploratory well costs capitalized for a period greater than one year	130	430	259
Capitalized well costs at end of year	$ 237	$ 586	$ 474	$ 321
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	12	33	21

CAPITALIZED EXPLORATORY WELL _5

CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 130	$ 430	$ 259
Suriname
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 115
Suriname And Egypt
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year		$ 52

CAPITALIZED EXPLORATORY WELL _6

CAPITALIZED EXPLORATORY WELL COSTS - Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 130	$ 430	$ 259
2023
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	75
2022
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
2021 and Prior
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	55
Suriname
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	115
Suriname | 2023
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	60
Suriname | 2022
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Suriname | 2021 and Prior
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	55
Egypt
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	15
Egypt | 2023
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	15
Egypt | 2022
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Egypt | 2021 and Prior
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 0

DERIVATIVE INSTRUMENTS AND HE_3

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details) - Callon Petroleum Company - Average Daily Settlement Price OF WTI Crude Oil Threshold High - Preferred Units embedded derivative $ in Millions	Apr. 01, 2024 USD ($) $ / bbl
Derivative [Line Items]
Earn-out obligation to be paid (up to) | $	$ 25
Crude oil settlement price threshold, contingent consideration liability (in dollars per barrel) | $ / bbl	60

DERIVATIVE INSTRUMENTS AND HE_4

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current Assets: Other current assets	$ 0	$ 6
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Deferred charges and other, Other current assets (Note 5)	Deferred charges and other, Other current assets (Note 5)
Total derivative assets	$ 0	$ 6
Deferred Credits and Other Noncurrent Liabilities: Other	$ 18	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Other current liabilities (Note 7)	Other current liabilities (Note 7)
Total derivative liabilities	$ 18	$ 0

DERIVATIVE INSTRUMENTS AND HE_5

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	$ (2)	$ 48	$ (47)
Unrealized gains (losses), net	(8)	51	(67)
Derivative instrument gains (losses), net	(10)	99	(114)
Commodity derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	2	48	(34)
Unrealized gains (losses), net	(6)	51	(36)
Contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	(4)	0	0
Unrealized gains (losses), net	(2)	0	0
Foreign currency derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	0	(13)
Preferred Units embedded derivative
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ 0	$ (31)

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 425	$ 453
Drilling advances	184	88
Prepaid assets and other	54	46
Current decommissioning security for sold Gulf of America assets	157	178
Total Other current assets	$ 820	$ 765

EQUITY METHOD INTERESTS - Addit

EQUITY METHOD INTERESTS - Additional Information (Details) - USD ($) shares in Millions, $ in Millions		12 Months Ended
	Mar. 18, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Feb. 22, 2022
Schedule of Equity Method Investments [Line Items]
Equity method interests		$ 0	$ 437
Proceeds from sale of Kinetik shares		428	$ 228	$ 224
Kinetik
Schedule of Equity Method Investments [Line Items]
Equity method investment, number of shares (in shares)			13.1
Equity method interests			$ 437		$ 802
Proceeds from sale of Kinetik shares	$ 428
Gain (loss) on changes in fair value of equity method interest		$ (9)	$ 41	$ 72

EQUITY METHOD INTERESTS - Sched

EQUITY METHOD INTERESTS - Schedule of Sales and Costs Associated With Equity Method Interests (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Lease operating expenses	[1]	$ 1,690	$ 1,436	$ 1,444
Total operating expenses		8,202	5,309	6,398
Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		35	121	18
Lease operating expenses		2	7	0
Total operating expenses		48	195	93
Oil and gas, excluding purchased
Schedule of Equity Method Investments [Line Items]
Total revenues	[1]	8,196	7,385	9,220
Costs	[1]	432	334	367
Oil and gas, excluding purchased | Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		13	92	18
Costs		23	108	93
Purchased oil and gas costs
Schedule of Equity Method Investments [Line Items]
Total revenues	[1]	1,541	894	1,855
Costs	[1]	1,047	742	1,776
Purchased oil and gas costs | Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		22	29	0
Costs		$ 23	$ 80	$ 0
[1] (1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Payables and Accruals [Abstract]
Accrued operating expenses	$ 204	$ 162
Accrued exploration and development	460	371
Accrued compensation and benefits	223	390
Accrued interest	93	93
Accrued income taxes	221	138
Current asset retirement obligation	103	76
Current operating lease liability	118	116
Current decommissioning contingency for sold Gulf of America properties	88	60
Other	168	338
Total Other current liabilities	$ 1,678	$ 1,744

ASSET RETIREMENT OBLIGATION - S

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the year	$ 2,438	$ 1,995
Liabilities incurred	15	14
Liabilities acquired	136	0
Liabilities divested	(272)	0
Liabilities settled	(70)	(43)
Accretion expense	148	116	$ 117
Revisions in estimated liabilities	299	356
Asset retirement obligation at end of the year	2,694	2,438	$ 1,995
Less current portion	(103)	(76)
Asset retirement obligation, long-term	$ 2,591	$ 2,362

ASSET RETIREMENT OBLIGATION - A

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 15	$ 14
Revisions in estimated liabilities	$ 299	$ 356

DEBT AND FINANCING COSTS - Over

DEBT AND FINANCING COSTS - Overview (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
(Gain) loss from extinguishment of debt	$ 0	$ (9)	$ 67
Open Market Repurchase | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount		74	15
Debt instrument repurchase program		65	16
Discount (premium) to par of debt repurchase		10	1
(Gain) loss from extinguishment of debt		$ (9)	(1)
Debt Repurchase, Cash Tender Offers | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount			1,100
Debt instrument repurchase program			1,200
(Gain) loss from extinguishment of debt			66
Unamortized debt issuance costs and discount			$ 11

DEBT AND FINANCING COSTS - Sche

DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Long-term debt, gross	$ 4,835
Apache finance lease obligations	30	$ 32
Unamortized discount	(25)	(26)
Debt issuance costs	(29)	(25)
Total debt	6,044	5,188
Current maturities	(53)	(2)
Long-term debt	$ 5,991	5,186
Unsecured Debt | 4.625% notes due 2025
Debt Instrument [Line Items]
Debt interest rate	4.625%
Long-term debt, gross	$ 51	51
Unsecured Debt | 7.7% notes due 2026
Debt Instrument [Line Items]
Debt interest rate	7.70%
Long-term debt, gross	$ 78	78
Unsecured Debt | 7.95% notes due 2026
Debt Instrument [Line Items]
Debt interest rate	7.95%
Long-term debt, gross	$ 132	132
Unsecured Debt | 4.875% notes due 2027
Debt Instrument [Line Items]
Debt interest rate	4.875%
Long-term debt, gross	$ 108	108
Unsecured Debt | 4.375% notes due 2028
Debt Instrument [Line Items]
Debt interest rate	4.375%
Long-term debt, gross	$ 325	325
Unsecured Debt | 7.75% notes due in 2029
Debt Instrument [Line Items]
Debt interest rate	7.75%
Long-term debt, gross	$ 235	235
Unsecured Debt | 4.25% notes due 2030
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 516	516
Unsecured Debt | 6.0% notes due 2037
Debt Instrument [Line Items]
Debt interest rate	6%
Long-term debt, gross	$ 443	443
Unsecured Debt | 5.1% notes due 2040
Debt Instrument [Line Items]
Debt interest rate	5.10%
Long-term debt, gross	$ 1,333	1,333
Unsecured Debt | 5.25% notes due 2042
Debt Instrument [Line Items]
Debt interest rate	5.25%
Long-term debt, gross	$ 399	399
Unsecured Debt | 4.75% notes due 2043
Debt Instrument [Line Items]
Debt interest rate	4.75%
Long-term debt, gross	$ 428	428
Unsecured Debt | 4.25% notes due 2044
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 211	211
Unsecured Debt | 7.375% debentures due 2047
Debt Instrument [Line Items]
Debt interest rate	7.375%
Long-term debt, gross	$ 150	150
Unsecured Debt | 5.35% notes due 2049
Debt Instrument [Line Items]
Debt interest rate	5.35%
Long-term debt, gross	$ 387	387
Unsecured Debt | 7.625% debentures due 2096
Debt Instrument [Line Items]
Debt interest rate	7.625%
Long-term debt, gross	$ 39	39
Unsecured Debt | Notes and debentures before unamortized discount and debt issuance costs
Debt Instrument [Line Items]
Long-term debt, gross	4,835	4,835
Debt instrument, fair value	$ 4,400	4,300
Unsecured Debt | 6.75% notes due 2055
Debt Instrument [Line Items]
Debt interest rate	6.75%
Line of Credit | Commercial paper | Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	$ 323	0
Line of Credit | Term loan facility | Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	900	0
Line of Credit | Syndicated credit facilities | Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	$ 10	$ 372

DEBT AND FINANCING COSTS - Sc_2

DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) $ in Millions	Dec. 31, 2024 USD ($)
Debt Disclosure [Abstract]
2025	$ 51
2026	210
2027	108
2028	325
2029	235
Thereafter	3,906
Notes and debentures, excluding discounts and debt issuance costs	$ 4,835

DEBT AND FINANCING COSTS - Fina

DEBT AND FINANCING COSTS - Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Interest expense	$ 402	$ 351	$ 332
Amortization of debt issuance costs	6	4	8
Capitalized interest	(29)	(24)	(18)
Loss (gain) on extinguishment of debt	0	(9)	67
Interest income	(12)	(10)	(10)
Financing costs, net	$ 367	$ 312	$ 379

DEBT AND FINANCING COSTS - Unse

DEBT AND FINANCING COSTS - Unsecured 2022 Committed Bank Credit Facilities (Details)	Apr. 29, 2022 USD ($) creditAgreement	Dec. 31, 2024 USD ($)	Dec. 31, 2024 GBP (£)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Apr. 29, 2022 GBP (£) creditAgreement
Syndicated credit facilities | Unsecured Debt
Debt Instrument [Line Items]
Number of credit agreements | creditAgreement	2					2
USD Agreement | Line of Credit
Debt Instrument [Line Items]
Number of credit agreements denominated in US dollars | creditAgreement	1					1
Debt instrument, term	5 years
Line of credit facility, committed amount	$ 1,800,000,000
Line of credit outstanding		$ 10,000,000		$ 372,000,000
USD Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity	750,000,000
Current borrowing capacity	$ 150,000,000
Letters of credit outstanding, amount		$ 0		$ 0
GBP Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount | £						£ 1,500,000,000
GBP Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £			£ 303,000,000		£ 348,000,000

DEBT AND FINANCING COSTS - Unco

DEBT AND FINANCING COSTS - Uncommitted Lines of Credit (Details) - Apache credit facility £ in Millions	Dec. 31, 2024 USD ($)	Dec. 31, 2024 GBP (£)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)
Debt Instrument [Line Items]
Letters of credit outstanding, amount	$ 11,000,000	£ 640	$ 2,000,000	£ 416
Line of Credit
Debt Instrument [Line Items]
Line of credit outstanding	$ 0		$ 0

DEBT AND FINANCING COSTS - Comm

DEBT AND FINANCING COSTS - Commercial Paper Program (Details) - USD ($)		1 Months Ended
	Apr. 29, 2022	Dec. 31, 2023	Dec. 31, 2024
USD Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount	$ 1,800,000,000
Commercial paper
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,800,000,000
Debt instrument, term		397 days
Debt instrument guarantee terms, benchmark amount (less than)		$ 1,000,000,000
Short-term debt		$ 0	$ 323,000,000

DEBT AND FINANCING COSTS - Un_2

DEBT AND FINANCING COSTS - Unsecured Committed Term Loan Facility (Details)				12 Months Ended
	May 06, 2024	Apr. 01, 2024 USD ($)	Jan. 30, 2024 USD ($)	Dec. 31, 2024 USD ($)	Apr. 29, 2022
Delayed-Drawn Term Loan | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount			$ 2,000,000,000
Debt instrument guarantee terms, benchmark amount (less than)			1,000,000,000
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,500,000,000
Debt instrument, term	3 years		3 years
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Minimum | Debt Instrument, Redemption, Period One | Adjusted Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Minimum | Debt Instrument, Redemption, Period One | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Minimum | Debt Instrument, Redemption, Period Two | Adjusted Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Minimum | Debt Instrument, Redemption, Period Two | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Maximum | Debt Instrument, Redemption, Period One | Adjusted Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Maximum | Debt Instrument, Redemption, Period One | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	2.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Maximum | Debt Instrument, Redemption, Period Two | Adjusted Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Maximum | Debt Instrument, Redemption, Period Two | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	2.375%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount			$ 500,000,000
Debt instrument, term			364 days	3 years
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | Adjusted Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate				0.75%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate				1.75%
Term Loan Credit Agreement, Three Year Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,500,000,000
Debt instrument, term		3 years		3 years
Line of credit outstanding				$ 900,000,000
Term Loan Credit Agreement, 364-Day Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, term		364 days
Syndicated credit facilities | Revolving Credit Facility
Debt Instrument [Line Items]
Debt covenant, adjusted debt-to-capital ratio					0.60
Debt-to-capital ratio				0.19
Debt covenant, debt secured as percentage of consolidated net tangible assets				15%
Debt covenant, debt secured as percentage of consolidated net tangible assets, threshold amount				$ 2,500,000,000

DEBT AND FINANCING COSTS - Subs

DEBT AND FINANCING COSTS - Subsequent Event — Unsecured 2025 Committed Bank Credit Facilities (Details)	Jan. 15, 2025 USD ($) option creditAgreement	Apr. 29, 2022 USD ($) creditAgreement	Jan. 15, 2025 GBP (£) creditAgreement	Dec. 31, 2024 USD ($)	Dec. 31, 2024 GBP (£)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Jun. 21, 2023 USD ($)	Apr. 29, 2022 GBP (£) creditAgreement
GBP Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term		5 years
Line of credit facility, committed amount | £									£ 1,500,000,000
GBP Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £					£ 303,000,000		£ 348,000,000
USD Agreement | Line of Credit
Debt Instrument [Line Items]
Number of credit agreements denominated in US dollars | creditAgreement		1							1
Debt instrument, term		5 years
Line of credit facility, committed amount		$ 1,800,000,000
USD Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity		750,000,000
Current borrowing capacity		$ 150,000,000
Letters of credit outstanding, amount				$ 0		$ 0
Syndicated credit facilities | Revolving Credit Facility
Debt Instrument [Line Items]
Debt covenant, adjusted debt-to-capital ratio		0.60							0.60
Debt covenant, debt secured as percentage of consolidated net tangible assets, threshold amount				$ 2,500,000,000
Debt covenant, debt secured as percentage of consolidated net tangible assets				15%	15%
Syndicated credit facilities | Unsecured Debt
Debt Instrument [Line Items]
Number of credit agreements | creditAgreement		2							2
Apache
Debt Instrument [Line Items]
Letters of credit outstanding, amount								$ 350,000,000
Subsequent Event | 2025 USD Agreement | Minimum | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1%
Subsequent Event | 2025 USD Agreement | Maximum | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.675%
Subsequent Event | 2025 USD Agreement | Line of Credit
Debt Instrument [Line Items]
Number of credit agreements denominated in US dollars | creditAgreement	1		1
Subsequent Event | USD Agreement | Minimum | Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0%
Subsequent Event | USD Agreement | Maximum | Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.675%
Subsequent Event | Syndicated credit facilities | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility fee, percentage	0.20%
Debt covenant, adjusted debt-to-capital ratio	0.65		0.65
Debt covenant, debt secured as percentage of consolidated net tangible assets	15%		15%
Subsequent Event | Syndicated credit facilities | Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.30%
Subsequent Event | Syndicated credit facilities | Revolving Credit Facility | SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.30%
Subsequent Event | Syndicated credit facilities | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Credit facility fee, percentage	0.125%
Subsequent Event | Syndicated credit facilities | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Credit facility fee, percentage	0.325%
Subsequent Event | APA
Debt Instrument [Line Items]
Number of credit agreements | creditAgreement	2		2
Subsequent Event | APA | 2025 USD Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility maximum borrowing capacity	$ 2,000,000,000
Increase of committed amount	$ 2,500,000,000
Line of credit facility, number of extension options | option	2
Line of credit facility, extension term	1 year
Subsequent Event | APA | 2025 USD Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity	$ 750,000,000
Current borrowing capacity	$ 250,000,000
Subsequent Event | APA | GBP Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility maximum borrowing capacity | £			£ 1,500,000,000
Line of credit facility, extension term	1 year
Subsequent Event | APA | GBP Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, number of extension options | option	2
Subsequent Event | APA | USD Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £			£ 253,000,000
Subsequent Event | Apache | Delayed-Drawn Term Loan | Unsecured Debt
Debt Instrument [Line Items]
Guaranteed obligations, maximum	$ 1,000,000,000

DEBT AND FINANCING COSTS - Su_2

DEBT AND FINANCING COSTS - Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt (Details) - USD ($)	Jan. 10, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Long-term debt, gross		$ 4,835,000,000
Subsequent Event | Apache | Former Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Guaranteed obligations, maximum	$ 1,000,000,000
Unsecured Debt | 6.10% notes due 2035
Debt Instrument [Line Items]
Debt interest rate		6.10%
Unsecured Debt | 6.75% notes due 2055
Debt Instrument [Line Items]
Debt interest rate		6.75%
Unsecured Debt | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	$ 850,000,000
Additional interest accrual, percent	0.25%
Additional interest accrual, maximum, percent	1%
Unsecured Debt | Subsequent Event | 6.10% notes due 2035
Debt Instrument [Line Items]
Debt instrument, face amount	$ 350,000,000
Debt interest rate	6.10%
Unsecured Debt | Subsequent Event | 6.75% notes due 2055
Debt Instrument [Line Items]
Debt instrument, face amount	$ 500,000,000
Debt interest rate	6.75%
Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	$ 3,592,000,000
Debt instrument, face amount	2,500,000,000
Repayments	2,500,000
Debt instrument repurchase program	869,000,000
Net of issuance costs	839,000,000
Unsecured Debt | Subsequent Event | APA | 6.10% notes due 2035
Debt Instrument [Line Items]
Long-term debt, gross	350,000,000
Unsecured Debt | Subsequent Event | APA | 6.75% notes due 2055
Debt Instrument [Line Items]
Long-term debt, gross	500,000,000
Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	1,095,000,000
Debt instrument, face amount	203,000,000
Debt repurchased principle amount	1,000,000,000
Unsecured Debt | Subsequent Event | Apache | 6.10% notes due 2035
Debt Instrument [Line Items]
Long-term debt, gross	0
Unsecured Debt | Subsequent Event | Apache | 6.75% notes due 2055
Debt Instrument [Line Items]
Long-term debt, gross	$ 0

DEBT AND FINANCING COSTS - The

DEBT AND FINANCING COSTS - The Aggregate Principal Amounts of Notes and Debentures Outstanding (Details) - USD ($) $ in Millions	Jan. 10, 2025	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 4,835
Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	$ 3,592
Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	1,095
4.625% notes due 2025 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 51	$ 51
Debt interest rate		4.625%
4.625% notes due 2025 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	0
4.625% notes due 2025 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	51
7.70% notes due March 2026 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	58
7.70% notes due March 2026 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	21
7.95% notes due April 2026 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	56
7.95% notes due April 2026 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	76
4.875% notes due 2027 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 108	108
Debt interest rate		4.875%
4.875% notes due 2027 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	39
4.875% notes due 2027 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	69
4.375% notes due 2028 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 325	325
Debt interest rate		4.375%
4.375% notes due 2028 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	239
4.375% notes due 2028 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	86
7.75% notes due in 2029 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 235	235
Debt interest rate		7.75%
7.75% notes due in 2029 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	164
7.75% notes due in 2029 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	72
4.25% notes due 2030 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 516	516
Debt interest rate		4.25%
4.25% notes due 2030 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	374
4.25% notes due 2030 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	142
6.0% notes due 2037 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 443	443
Debt interest rate		6%
6.0% notes due 2037 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	341
6.0% notes due 2037 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	102
5.1% notes due 2040 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,333	1,333
Debt interest rate		5.10%
5.1% notes due 2040 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	539
5.1% notes due 2040 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	225
5.25% notes due 2042 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 399	399
Debt interest rate		5.25%
5.25% notes due 2042 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	209
5.25% notes due 2042 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	65
4.75% notes due 2043 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 428	428
Debt interest rate		4.75%
4.75% notes due 2043 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	153
4.75% notes due 2043 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	79
4.25% notes due 2044 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 211	211
Debt interest rate		4.25%
4.25% notes due 2044 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	77
4.25% notes due 2044 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	24
7.375% debentures due 2047 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 150	150
Debt interest rate		7.375%
7.375% debentures due 2047 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	126
7.375% debentures due 2047 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	24
5.35% notes due 2049 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 387	387
Debt interest rate		5.35%
5.35% notes due 2049 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	330
5.35% notes due 2049 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	57
7.625% debentures due 2096 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross		$ 39	$ 39
Debt interest rate		7.625%
7.625% debentures due 2096 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	37
7.625% debentures due 2096 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	$ 2
6.10% notes due 2035 | Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate		6.10%
6.10% notes due 2035 | Unsecured Debt | Subsequent Event
Debt Instrument [Line Items]
Debt interest rate	6.10%
6.10% notes due 2035 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	$ 350
6.10% notes due 2035 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	$ 0
6.75% notes due 2055 | Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate		6.75%
6.75% notes due 2055 | Unsecured Debt | Subsequent Event
Debt Instrument [Line Items]
Debt interest rate	6.75%
6.75% notes due 2055 | Unsecured Debt | Subsequent Event | APA
Debt Instrument [Line Items]
Long-term debt, gross	$ 500
6.75% notes due 2055 | Unsecured Debt | Subsequent Event | Apache
Debt Instrument [Line Items]
Long-term debt, gross	$ 0

DEBT AND FINANCING COSTS - Su_3

DEBT AND FINANCING COSTS - Subsequent Event—Open Market Repurchases of Apache Indenture Debt (Details) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 27, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Gain (loss) on debt extinguishment		$ 0	$ 9	$ (67)
Open Market Repurchase | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount			74	15
Debt instrument repurchase program			65	16
Discount (premium) to par of debt repurchase			10	1
Gain (loss) on debt extinguishment			$ 9	$ 1
Open Market Repurchase | Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Debt repurchased principle amount	$ 55
Debt instrument repurchase program	50
Discount to par	7
Gain (loss) on debt extinguishment	$ 6

INCOME TAXES - Schedule of Net

INCOME TAXES - Schedule of Net Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
U.S.	$ 705	$ 627	$ 2,675
Foreign	830	2,256	3,059
NET INCOME BEFORE INCOME TAXES	$ 1,535	$ 2,883	$ 5,734

INCOME TAXES - Schedule of Tota

INCOME TAXES - Schedule of Total Provision for Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current income taxes:
Federal		$ 76	$ 2	$ 1
State		2	6	11
Foreign		1,075	1,330	1,495
Total current income taxes		1,153	1,338	1,507
Deferred income taxes:
Federal	$ (1,700)	(96)	(1,708)	0
State		3	(32)	0
Foreign		(643)	78	145
Total deferred income taxes		(736)	(1,662)	145
Total		$ 417	$ (324)	$ 1,652

INCOME TAXES - Schedule of Reco

INCOME TAXES - Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate	$ 322	$ 605	$ 1,204
State income tax, less federal effect	2	(23)	9
Taxes related to foreign operations	45	752	745
Tax credits	(3)	0	(4)
Net change in tax contingencies	2	5	1
Valuation allowances	0	(1,842)	(646)
Tax adjustments attributable to BCP Business Combination	0	0	126
Stock compensation	17	(2)	7
Legal reserve	14	0	0
Remeasurement of U.K. deferred tax liability	0	174	208
Transaction costs	5	0	0
All other, net	13	7	2
Total	$ 417	$ (324)	$ 1,652

INCOME TAXES - Schedule of Comp

INCOME TAXES - Schedule of Components of Net Deferred Tax (Asset) Liability (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
U.S. and state net operating losses	$ 2,487	$ 2,050
Capital losses	14	8
Foreign net operating losses	55	43
Tax credits and other tax incentives	105	26
Foreign tax credits	2,204	2,204
Accrued expenses and liabilities	76	129
Asset retirement obligation	952	850
Property and equipment	45	38
Equity investments	1	8
Net interest expense limitation	287	125
Lease liability	114	71
Decommissioning contingency for sold Gulf of America properties	232	210
Total deferred tax assets	6,572	5,762
Valuation allowance	(2,623)	(2,630)	$ (4,918)	$ (5,902)
Net deferred tax assets	3,949	3,132
Deferred tax liabilities:
Property and equipment	1,060	1,573
Right-of-use asset	111	69
Decommissioning security for sold Gulf of America properties	40	44
Other	49	59
Total deferred tax liabilities	1,260	1,745
Net deferred income tax asset	$ (2,689)	$ (1,387)

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Assets and Liabilities in the Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Deferred tax asset	$ 2,703	$ 1,758
Deferred tax liability	14	371
Net deferred income tax asset	$ (2,689)	$ (1,387)

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Details) - USD ($) shares in Millions, $ in Millions				3 Months Ended		12 Months Ended
	Aug. 16, 2022	Mar. 11, 2022	Jan. 14, 2022	Dec. 31, 2023	Mar. 31, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Apr. 01, 2024
Income Tax [Line Items]
Accrued tax expense	$ 74
Tax adjustments attributable to BCP Business Combination						$ 0	$ 0	$ 126
Deferred income tax benefit				$ 1,700		96	1,708	0
Net interest expense carryforward						1,300
Tax expense recorded for interest and penalties						2	2	1
Accrued for payment of interest and penalties				$ 7		9	$ 7	5
Kinetik
Income Tax [Line Items]
Shares sold (in shares)		4			4		7.5
Apache Midstream LLC
Income Tax [Line Items]
Stock exchanged during period (in shares)			12.5
ALTM
Income Tax [Line Items]
Stock exchanged during period (in shares)			12.5
Foreign
Income Tax [Line Items]
Remeasurement of deferred tax liability							$ 174	208
Net operating losses						153
Tax credit carryforward, amount						2,204
U.S.
Income Tax [Line Items]
Net operating losses						10,345
Operating loss carryforwards subject to annual limitation						2,100
State
Income Tax [Line Items]
Net operating losses						$ 6,586
Callon Petroleum Company
Income Tax [Line Items]
Deferred tax asset									$ 565
BCP Business Combination
Income Tax [Line Items]
Tax adjustments attributable to BCP Business Combination								$ 126

INCOME TAXES - Schedule of Valu

INCOME TAXES - Schedule of Valuation Allowance Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 2,630	$ 4,918	$ 5,902
Increase (decrease) of valuation allowances	(7)	(2,300)	(1,000)
Balance at end of year	2,623	2,630	4,918
State
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(51)	(63)	(111)
U.S.
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	26	(2,235)	(706)
Foreign
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	$ 18	$ 10	$ (167)

INCOME TAXES - Schedule of Ne_2

INCOME TAXES - Schedule of Net Operating Losses (Details) $ in Millions	Dec. 31, 2024 USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 10,345
State
Schedule Of Income Tax [Line Items]
Net operating losses	6,586
Foreign
Schedule Of Income Tax [Line Items]
Net operating losses	$ 153

INCOME TAXES - Schedule of Fore

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) $ in Millions	Dec. 31, 2024 USD ($)
Foreign
Tax Credit Carryforward [Line Items]
Tax credit carryforward, amount	$ 2,204

INCOME TAXES - Schedule of Key

INCOME TAXES - Schedule of Key Jurisdictions of Company's Earliest Open Tax Years (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Unrecognized Tax Benefits [Roll Forward]
Balance at beginning of year	$ 89	$ 93	$ 89	$ 116
Additions based on tax positions related to prior year	1	4	0
Additions based on tax positions related to the current year	0	0	0
Reductions for tax positions of prior years	(5)	0	(27)
Balance at end of year	$ 89	$ 93	$ 89	$ 116

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions, $ in Millions					12 Months Ended
	Jun. 21, 2023 USD ($) surety	Sep. 10, 2020 defendant	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Dec. 31, 2024 USD ($) bond	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Apr. 05, 2022 letter	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies					$ 20
Undiscounted reserve for environmental remediation					2
Standby loan agreed to provide related to ARO					400
Number of prior letters notifying unable to fund decommissioning obligations | letter								2
Sureties issued bonds directly | surety	2
Sureties issued bonds to issuing bank | surety	2
Decommissioning security for sold properties					178
Decommissioning security for sold Gulf of America properties (Note 11)					21	$ 21
Current decommissioning security for sold Gulf of America assets					157	178
Decommissioning contingency for sold Gulf of America properties (Note 11)					929	764
Current decommissioning contingency for sold Gulf of America properties					88	60
Losses on previously sold Gulf of America properties					273	212	$ 157
Additional decommissioning contingency liability					67
Fixed operating lease expenses					170	168	145
Short-term lease expense					$ 85	$ 71	62
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]					Current debt	Current debt
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]					LONG-TERM DEBT (Note 9)	LONG-TERM DEBT (Note 9)
Depreciation on finance lease asset					$ 2	$ 2	2
Interest on finance lease asset					1	1	2
Variable lease payment					$ 48	74	$ 90
Apache
Commitment And Contingencies [Line Items]
Decommissioning costs reimbursed amount from the bonds	$ 148
Decommissioning costs reimbursed amount from the letters of credit	350
Letters of credit outstanding, amount	350
Proceeds from bonds	$ 140
Gulf Of Mexico Shelf Operations And Properties | Disposed of by Sale
Commitment And Contingencies [Line Items]
Number of bonds held | bond					2
Minimum
Commitment And Contingencies [Line Items]
AROs, estimated liability					$ 1,000
Decommissioning contingency for sold					1,000	$ 824
Maximum
Commitment And Contingencies [Line Items]
AROs, estimated liability					$ 1,400
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages			$ 200
Apollo Exploration Lawsuit | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages				$ 1,100
Australian Operations Divestiture Dispute | Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount										$ 80
Loss contingency estimate of possible loss									$ 200
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants | defendant		25

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Schedule of Weighted Average Lease Term And Discount Rate (Details)	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Operating leases, weighted average remaining lease term	6 years 10 months 24 days
Finance leases, weighted average remaining lease term	8 years 8 months 12 days
Operating leases, weighted average discount rate	5.80%
Finance leases, weighted average discount rate	4.40%

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
2025	$ 122
2026	61
2027	48
2028	42
2029	35
Thereafter	159
Total future minimum payments	467
Less: imputed interest	(94)
Total lease liabilities	373
Current portion	118	$ 116
Non-current portion	$ 255
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities (Note 7)	Other current liabilities (Note 7)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other	Other
Finance Lease
2025	$ 3
2026	4
2027	4
2028	4
2029	4
Thereafter	18
Total future minimum payments	37
Less: imputed interest	(7)
Total lease liabilities	30	$ 32
Current portion	2
Non-current portion	28
Purchase Obligations
2025	244
2026	245
2027	173
2028	166
2029	148
Thereafter	142
Total future minimum payments	1,118
Total costs under take or pay and throughout obligation	245	$ 182	$ 183
Purchase commitment, remaining minimum amount committed	$ 3,500

RETIREMENT AND DEFERRED COMPE_3

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50%
Maximum percentage of compensation contributed by the company	8%
Percentage of additional contribution to money purchase retirement plan	6%
Maximum percentage of eligible compensation contributed by the participating employees	50%
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested	75%
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested	20%
Annual cost of retirement benefit plans	$ 46	$ 44	$ 40
Targeted ongoing funding level of pension plan policy, percent	100%
Outperformance relative to gilts for equities	2.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 102	$ 112	$ 89
Expected contribution towards pension and postretirement plan	2
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

RETIREMENT AND DEFERRED COMPE_4

RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 150
Fair value of plan assets at end of year	136	$ 150
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	118	108	$ 211
Service cost	1	1	2
Interest cost	6	5	3
Foreign currency exchange rates	(2)	6	(21)
Actuarial losses (gains)	(11)	3	(79)
Plan settlements	0	0	0
Benefits paid	(5)	(5)	(8)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	107	118	108
Change in Plan Assets
Fair value of plan assets at beginning of year	150	137	254
Actual return (loss) on plan assets	(8)	8	(87)
Foreign currency exchange rates	(3)	8	(26)
Employer contributions	2	2	4
Plan settlements	0	0	0
Benefits paid	(5)	(5)	(8)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	136	150	137
Funded status at end of year	29	32	29
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	29	32	29
Amounts recognized in Consolidated Balance Sheet	29	32	29
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (16)	$ (12)	$ (10)
Weighted Average Assumptions used as of December 31
Discount rate	5.60%	4.80%	5%
Salary increases	4.70%	4.60%	4.70%
Expected return on assets	5.70%	4.80%	4.70%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 15	$ 15	$ 20
Service cost	1	1	1
Interest cost	1	1	0
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	0	0	(5)
Plan settlements	(1)	0	0
Benefits paid	(2)	(3)	(3)
Retiree contributions	1	1	2
Projected benefit obligation at end of year	15	15	15
Change in Plan Assets
Fair value of plan assets at beginning of year	0	0	0
Actual return (loss) on plan assets	0	0	0
Foreign currency exchange rates	0	0	0
Employer contributions	1	1	2
Plan settlements	0	0	0
Benefits paid	(2)	(3)	(4)
Retiree contributions	1	2	2
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(15)	(15)	(15)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current liability	(13)	(13)	(13)
Amounts recognized in Consolidated Balance Sheet	(15)	(15)	(15)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 14	$ 16	$ 18
Weighted Average Assumptions used as of December 31
Discount rate	5.49%	5%	5.29%
Healthcare cost trend
Initial	6.50%	6.25%	6.50%
Ultimate in 2030	5.25%	5.25%	5.25%

RETIREMENT AND DEFERRED COMPE_5

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	100%	100%
Global equities
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	0%	0%
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	62%	59%
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	4%	6%
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	33%	33%
Cash
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	1%	2%

RETIREMENT AND DEFERRED COMPE_6

RETIREMENT AND DEFERRED COMPENSATION PLANS - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 136	$ 150
Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	3
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84	88
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6	9
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 45	$ 50

RETIREMENT AND DEFERRED COMPE_7

RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.60%	4.70%	4.90%
Expected return on assets	4.80%	4.70%	1.90%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 2
Interest cost	6	5	3
Expected return on assets	(7)	(7)	(4)
Amortization of loss	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	$ 0	$ (1)	$ 1
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	4.80%	5%	1.80%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 1
Interest cost	1	1	0
Expected return on assets	0	0	0
Amortization of loss	(2)	(2)	(1)
Settlement loss	0	0	0
Net periodic benefit cost	$ (1)	$ 0	$ 0
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5%	5.29%	2.57%
Healthcare cost trend
Initial	6.25%	6.50%	6.25%
Ultimate in 2030	5.25%	5.25%	5%

RETIREMENT AND DEFERRED COMPE_8

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2024 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	$ 5
2026	5
2027	6
2028	6
2029	6
Years 2030-2034	35
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	2
2026	1
2027	1
2028	1
2029	1
Years 2030-2034	$ 7

CAPITAL STOCK - Schedule of Com

CAPITAL STOCK - Schedule of Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Movement In Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	303,575,901	311,559,149	346,930,765
Shares issued for stock-based compensation plans:
Treasury shares issued (in shares)	0	2,016	1,996
Common shares issued (in shares)	70,983,745	725,914	791,381
Treasury shares acquired (in shares)	(9,162,497)	(8,711,178)	(36,164,993)
Balance, end of year (in shares)	365,397,149	303,575,901	311,559,149

CAPITAL STOCK - Net Income Per

CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Basic:
Income attributable to common stock	$ 804	$ 2,855	$ 3,674
Income attributable to common stock (in shares)	353	308	332
Income attributable to common stock (in USD per share)	$ 2.28	$ 9.26	$ 11.05
Diluted:
Income attributable to common stock		$ 2,855	$ 3,674
Income attributable to common stock (in shares)	353	309	333
Income attributable to common stock (in USD per share)	$ 2.27	$ 9.25	$ 11.02
Stock compensation awards
Effect of Dilutive Securities:
Stock compensation awards	$ 0	$ 0	$ 0
Stock compensation awards (in shares)	0	1	1
Stock compensation awards (in USD per share)	$ (0.01)	$ (0.01)	$ (0.03)

CAPITAL STOCK - Additional Info

CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended				12 Months Ended			14 Months Ended
	Jan. 31, 2025	Sep. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Feb. 28, 2025	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive (in shares)						2,000,000	1,900,000	2,400,000
Additional number of shares authorized to be repurchased (in shares)		40,000,000	40,000,000
Treasury shares acquired (in shares)						9,162,497	8,711,178	36,164,993
Treasure stock acquired, average price (in USD per share)						$ 26.83	$ 37.81	$ 39.34
Remaining authorized repurchase amount (in shares)						34,800,000
Common stock, dividends, per share (in USD per share)				$ 0.25	$ 0.125	$ 1	$ 1	$ 0.75
Shares authorized and available for grant (in shares)						7,900,000
Shares issued in the period (in shares)						0	0	0
Exercised (in shares)						0	12,183	98,646
Common stock issued (in shares)			2,078,000			1,416,000	1,465,000	2,078,000		3,012,000
Total stock-settled and cash-settled compensation expensed						$ 49	$ 84	$ 304
Stock-settled and cash-settled compensation capitalized						$ 9	13	44
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury shares acquired (in shares)									3,900,000
Treasure stock acquired, average price (in USD per share)									$ 23.13
Remaining authorized repurchase amount (in shares)									30,900,000
Period in which stock options become exercisable	3 years
Expected term	3 years
Weighted average grant date fair value per share (in USD per share)	$ 23.68
Subsequent Event | Omnibus Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued (in shares)	1,662,239
Weighted average grant date fair value (in dollars per share)	$ 9.51
Total stock-settled and cash-settled compensation expensed	$ 16
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable						3 years
Period in which stock options expires after grant date						10 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed						$ 53	73	153
Stock-settled and cash-settled compensation capitalized						$ 9	$ 11	$ 22
Awards granted during period (in shares)						897,000	661,000	847,000
Weighted average grant date fair value per share (in USD per share)						$ 33.48	$ 41.60	$ 29.90
Restricted Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	693,761
Total compensation cost related to non-vested awards not yet recognized	$ 16
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)						2,369,000	1,972,000	2,568,000
Total compensation cost related to non-vested awards not yet recognized						$ 34
Phantom Units | 2024 performance program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed						$ 13
Award performance period						3 years
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,300,091
Total compensation cost related to non-vested awards not yet recognized	$ 54
Award, remeasurement basis (in shares)	1

CAPITAL STOCK - Schedule of Sto

CAPITAL STOCK - Schedule of Stock-settled and Cash-settled Compensation Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 49	$ 84	$ 304
Stock-settled and cash-settled compensation capitalized	9	13	44
Total stock-settled and cash-settled compensation costs	58	97	348
Lease operating expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	16	27	82
Exploration
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	4	7	29
General and administrative
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 29	$ 50	$ 193

CAPITAL STOCK - Schedule of S_2

CAPITAL STOCK - Schedule of Stock Options Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Shares Under Option
Outstanding, beginning of year (in shares)	1,465,000	2,078,000	3,012,000
Exercised (in shares)	0	(12,183)	(98,646)
Forfeited (in shares)	0	0	(2,000)
Expired (in shares)	(49,000)	(601,000)	(833,000)
Outstanding, end of year, (in shares)	1,416,000	1,465,000	2,078,000
Expected to vest (in shares)	0	0	0
Exercisable, end of year (in shares)	1,416,000	1,465,000	2,078,000
Weighted Average Exercise Price
Outstanding, beginning of year (in USD per share)	$ 48.48	$ 57.71	$ 63.79
Exercised (in USD per share)	0	42.38	42.09
Forfeited (in USD per share)	0	0	49.10
Expired (in USD per share)	43.91	80.53	81.56
Outstanding, end of year (in USD per share)	48.64	48.48	57.71
Expected to vest (in USD per share)	0	0	0
Exercisable, end of year (in USD per share)	$ 48.64	$ 48.48	$ 57.71
Weighted average remaining contractual life for options outstanding	2 years 1 month 6 days
Weighted average remaining contractual life for exercisable	2 years 1 month 6 days
Aggregate intrinsic value for options outstanding exercisable	$ 0
Aggregate intrinsic value for options outstanding	$ 0

CAPITAL STOCK - Schedule of Res

CAPITAL STOCK - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Units
Assumed Awards from Callon acquisition (in shares)	1,498,000	0	0
Weighted Average  Grant-Date  Fair Value
Assumed Awards from Callon acquisition (in USD per share)	$ 35.43	$ 0	$ 0
Total fair value of restricted stock awards vested	$ 73	$ 23	$ 22
Restricted Stock
Units
Non-vested, beginning balance (in shares)	1,480,000	1,885,000	2,073,000
Granted (in shares)	897,000	661,000	847,000
Vested (in shares)	(2,295,000)	(975,000)	(978,000)
Forfeited (in shares)	(165,000)	(69,000)	(57,000)
Expired (in shares)	0	(22,000)	0
Non-vested, ending balance (in shares)	1,415,000	1,480,000	1,885,000
Weighted Average  Grant-Date  Fair Value
Non-vested Beginning Balance (in USD per share)	$ 30.69	$ 23.08	$ 19.98
Granted (in USD per share)	33.48	41.60	29.90
Vested (in USD per share)	31.83	23.31	22.39
Forfeited (in USD per share)	35.48	32.44	23.49
Expired (in USD per share)	0	27.81	0
Non-vested Ending Balance (in USD per share)	$ 35.07	$ 30.69	$ 23.08
Weighted-average remaining life of unvested restricted stock units	9 months 18 days
Phantom Units
Units
Non-vested, beginning balance (in shares)	4,478,000	5,709,000	6,402,000
Adjustment from ALTM transaction (in shares)	0	0	143,000
Granted (in shares)	2,369,000	1,972,000	2,568,000
Vested (in shares)	(2,568,000)	(2,851,000)	(2,970,000)
Forfeited (in shares)	(362,000)	(340,000)	(434,000)
Expired (in shares)	0	(12,000)	0
Non-vested, ending balance (in shares)	3,917,000	4,478,000	5,709,000
Weighted Average  Grant-Date  Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 34
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted (in shares)	2,369,605	1,972,116	2,512,602
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock
Units
Granted (in shares)			55,546
Stock Settled Restricted Stock Units
Units
Non-vested, beginning balance (in shares)
Non-vested, ending balance (in shares)	1,257,784
Weighted Average  Grant-Date  Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 18

CAPITAL STOCK - Performance Pro

CAPITAL STOCK - Performance Program Narrative (Details) - USD ($)	1 Months Ended			12 Months Ended
	Jan. 31, 2025	Jan. 31, 2024	Jan. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jan. 31, 2022	Jan. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)				7,900,000
Compensation expense				$ 49,000,000	$ 84,000,000	$ 304,000,000
Stock-settled and cash-settled compensation capitalized				$ 9,000,000	$ 13,000,000	$ 44,000,000
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				2,369,000	1,972,000	2,568,000
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,300,091
Award, remeasurement basis (in shares)	1
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period				3 years
Compensation expense				$ 13,000,000	$ 2,000,000	$ 143,000,000
Stock-settled and cash-settled compensation capitalized				$ 1,000,000	$ 100,000	$ 21,000,000
Performance Program | Vesting, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage				50%
Performance Program | Vesting, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage				50%
2021 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)								1,959,856
Number of awards outstanding (in shares)				1,051,688
Shares paid out as percentage of target				118%
2022 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)							1,093,034
Number of awards outstanding (in shares)				998,570
Shares paid out as percentage of target				118%
2023 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)			822,200
Number of awards outstanding (in shares)				718,288
2023 Performance Program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			0%
Shares authorized and available for grant (in shares)				0
2023 Performance Program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			200%
Shares authorized and available for grant (in shares)				1,436,576
2024 performance program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period				3 years
Number of awards authorized (in shares)		645,318
Number of awards outstanding (in shares)				571,498
Compensation expense				$ 13,000,000
2024 performance program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		0%
Shares authorized and available for grant (in shares)				0
Compensation expense				$ 0
2024 performance program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		200%
Shares authorized and available for grant (in shares)				1,142,996
Compensation expense				$ 26,000,000
2025 Performance Program | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period	3 years
Compensation expense	$ 16,000,000
Award, remeasurement basis (in shares)	1
2025 Performance Program | Minimum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 0
2025 Performance Program | Maximum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 32,000,000
2025 Performance Program | Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	985,553
2025 Performance Program | Phantom Units | Minimum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	0
2025 Performance Program | Phantom Units | Maximum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	1,971,106

CAPITAL STOCK - Schedule of Per

CAPITAL STOCK - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Units
Assumed Awards from Callon acquisition (in shares)	1,498	0	0
Employee-related liabilities, current	$ 223	$ 390
Performance Program | Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	4,629	4,835	4,531
Granted (in shares)	834	1,536	1,676
Assumed Awards from Callon acquisition (in shares)	2,934	0	0
Vested (in shares)	(4,222)	(1,593)	(656)
Forfeited (in shares)	(203)	(99)	(106)
Expired, Shares (in shares)	0	(50)	(610)
Non-vested, ending balance (in shares)	3,972	4,629	4,835
Employee-related liabilities, current	$ 12

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 6,362	$ 3,691	$ 1,345	$ (717)
Pension and postretirement benefit plan (Note 12)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	12	15	14
Accumulated other comprehensive income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 12	$ 15	$ 14	$ 22

MAJOR CUSTOMERS (Details)

MAJOR CUSTOMERS (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Customer Concentration Risk | Oil and Gas Production Revenues | Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	17%	15%	15%

BUSINESS SEGMENT INFORMATION -

BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2024 segment
Segment Reporting [Abstract]
Number of operating segments	4

BUSINESS SEGMENT INFORMATION _2

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Expenses:
Lease operating expenses	[1]	$ 1,690	$ 1,436	$ 1,444
Taxes other than income		270	207	268
Exploration		313	195	305
Depreciation, depletion, and amortization		2,266	1,540	1,233
Asset retirement obligation accretion		148	116	117
Impairments		1,129	61	0
Total operating expenses		7,295	4,631	5,510
Operating Income (Loss)		2,442	3,648	5,565
Other Income (Expense):
Gain on divestitures, net		289	8	1,180
Losses on previously sold Gulf of America properties		(273)	(212)	(157)
Derivative instrument gains (losses), net		(10)	99	(114)
Other		(6)	18	148
General and administrative		(372)	(351)	(483)
Transaction, reorganization, and separation		(168)	(15)	(26)
Financing costs, net		(367)	(312)	(379)
NET INCOME BEFORE INCOME TAXES		1,535	2,883	5,734
Total Assets		19,390	15,244	13,147
Net Property and Equipment		12,646	10,038	9,012
Additions to Net Property and Equipment		7,499	2,313	2,607
Operating Segments | Egypt
Operating Expenses:
Lease operating expenses		464	474	526
Taxes other than income		0	0	0
Exploration		112	119	84
Depreciation, depletion, and amortization		625	524	400
Asset retirement obligation accretion		0	0	0
Impairments		0	0
Total operating expenses		1,226	1,150	1,032
Operating Income (Loss)		1,707	1,879	2,489
Other Income (Expense):
Total Assets		3,606	3,503	3,148
Net Property and Equipment		2,271	2,209	1,976
Additions to Net Property and Equipment		765	834	695
Operating Segments | North Sea
Operating Expenses:
Lease operating expenses		406	369	404
Taxes other than income		0	0	0
Exploration		1	19	35
Depreciation, depletion, and amortization		301	271	238
Asset retirement obligation accretion		106	76	82
Impairments		809	50
Total operating expenses		1,676	837	802
Operating Income (Loss)		(728)	501	756
Other Income (Expense):
Total Assets		1,324	1,970	1,911
Net Property and Equipment		712	1,628	1,386
Additions to Net Property and Equipment		41	131	210
Operating Segments | U.S.
Operating Expenses:
Lease operating expenses		820	593	515
Taxes other than income		270	207	265
Exploration		134	14	24
Depreciation, depletion, and amortization		1,340	745	593
Asset retirement obligation accretion		42	40	34
Impairments		320	11
Total operating expenses		4,327	2,601	3,522
Operating Income (Loss)		1,529	1,311	2,472
Other Income (Expense):
Total Assets		13,870	9,221	7,574
Net Property and Equipment		9,109	5,689	5,226
Additions to Net Property and Equipment		6,609	1,255	1,439
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	2
Operating Expenses:
Lease operating expenses		0	0	(1)
Taxes other than income		0	0	3
Exploration		66	43	162
Depreciation, depletion, and amortization		0	0	2
Asset retirement obligation accretion		0	0	1
Impairments		0	0
Total operating expenses		66	43	154
Operating Income (Loss)		(66)	(43)	(152)
Other Income (Expense):
Total Assets		590	550	514
Net Property and Equipment		554	512	424
Additions to Net Property and Equipment		84	93	263
Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Total revenues	[1]	8,196	7,385	9,220
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	432	334	367
Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		2,933	3,029	3,521
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		25	33	22
Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		948	1,338	1,558
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		53	52	43
Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		4,315	3,018	4,144
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		354	249	315
Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	(3)
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	(13)
Purchased oil and gas costs
Segment Reporting Information [Line Items]
Total revenues	[1]	1,541	894	1,855
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	1,047	742	1,776
Purchased oil and gas costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0
Purchased oil and gas costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0
Purchased oil and gas costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		1,541	894	1,850
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		1,047	742	1,776
Purchased oil and gas costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	5
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0
Oil and gas
Segment Reporting Information [Line Items]
Total revenues		9,737	8,279	11,075
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		2,933	3,029	3,521
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		948	1,338	1,558
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		5,856	3,912	5,994
Oil revenues
Other Income (Expense):
Revenue from non-customers		686	729	989
Oil revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Total revenues		6,966	5,997	6,835
Oil revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		2,620	2,683	3,145
Oil revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		774	1,073	1,232
Oil revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		3,572	2,241	2,458
Oil revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural gas revenues
Other Income (Expense):
Revenue from non-customers		83	95	117
Natural gas revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Total revenues		584	880	1,569
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		313	346	370
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		145	237	281
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		126	297	918
Natural gas revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural gas liquids revenues
Other Income (Expense):
Revenue from non-customers		0	0	2
Natural gas liquids revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Total revenues		646	508	816
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		0	0	6
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		29	28	45
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		617	480	768
Natural gas liquids revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		$ 0	$ 0	$ (3)
[1] (1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

SUPPLEMENTAL OIL AND GAS DISC_3

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - Oil and Gas, Exploration and Production - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	$ 8,196	$ 7,385	$ 9,223
Depreciation, depletion, and amortization	2,235	1,500	1,186
Asset retirement obligation accretion	148	116	116
Lease operating expenses	1,690	1,436	1,445
Gathering, processing, and transmission	432	334	380
Exploration expenses	313	195	305
Impairments related to oil and gas properties	1,111
Production taxes	268	204	263
Income tax	469	1,496	2,105
Operating costs	6,666	5,281	5,800
Results of operations	1,530	2,104	3,423
United States
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	4,315	3,018	4,144
Depreciation, depletion, and amortization	1,314	709	564
Asset retirement obligation accretion	42	40	34
Lease operating expenses	820	593	515
Gathering, processing, and transmission	354	249	315
Exploration expenses	134	14	24
Impairments related to oil and gas properties	315
Production taxes	268	204	263
Income tax	235	254	510
Operating costs	3,482	2,063	2,225
Results of operations	833	955	1,919
Egypt
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	2,933	3,029	3,521
Depreciation, depletion, and amortization	621	521	390
Asset retirement obligation accretion	0	0	0
Lease operating expenses	464	474	526
Gathering, processing, and transmission	25	33	22
Exploration expenses	112	119	84
Impairments related to oil and gas properties	0
Production taxes	0	0	0
Income tax	770	828	1,100
Operating costs	1,992	1,975	2,122
Results of operations	941	1,054	1,399
North Sea
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	948	1,338	1,558
Depreciation, depletion, and amortization	300	270	232
Asset retirement obligation accretion	106	76	82
Lease operating expenses	406	369	404
Gathering, processing, and transmission	53	52	43
Exploration expenses	1	19	35
Impairments related to oil and gas properties	796
Production taxes	0	0	0
Income tax	(536)	414	495
Operating costs	1,126	1,200	1,291
Results of operations	(178)	138	267
Other International
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	0	0	0
Depreciation, depletion, and amortization	0	0	0
Asset retirement obligation accretion	0	0	0
Lease operating expenses	0	0	0
Gathering, processing, and transmission	0	0	0
Exploration expenses	66	43	162
Impairments related to oil and gas properties	0
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	66	43	162
Results of operations	$ (66)	$ (43)	$ (162)

SUPPLEMENTAL OIL AND GAS DISC_4

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Proved	$ 3,609	$ 5
Proved			$ 599
Unproved	955	20	66
Exploration	439	432	545
Development	2,859	2,262
Development			1,359
Costs incurred	7,862	2,719	2,569
Capitalized interest	29	24	18
Asset retirement costs	316	371	(136)
United States
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Proved	3,606	1
Proved			596
Unproved	955	20	66
Exploration	150	31	4
Development	2,067	1,148
Development			848
Costs incurred	6,778	1,200	1,514
Capitalized interest	3	0	0
Asset retirement costs	171	(4)	79
Egypt
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Proved	3	4
Proved			3
Unproved	0	0	0
Exploration	227	226	169
Development	559	646
Development			568
Costs incurred	789	876	740
Capitalized interest	0	0	0
Asset retirement costs	0	0	0
North Sea
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	1	44	61
Development	186	468
Development			(57)
Costs incurred	187	512	4
Capitalized interest	0	0	1
Asset retirement costs	145	375	(215)
Other International
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	61	131	311
Development	47	0
Development			0
Costs incurred	108	131	311
Capitalized interest	26	24	17
Asset retirement costs	$ 0	$ 0	$ 0

SUPPLEMENTAL OIL AND GAS DISC_5

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	$ 43,799	$ 44,007
Unproved properties	899	853
Capitalized costs, gross	44,698	44,860
Accumulated DD&A	(32,304)	(35,114)
Capitalized costs, net	12,394	9,746
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	19,246	20,758
Unproved properties	711	267
Capitalized costs, gross	19,957	21,025
Accumulated DD&A	(11,053)	(15,587)
Capitalized costs, net	8,904	5,438
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	14,458	13,777
Unproved properties	67	71
Capitalized costs, gross	14,525	13,848
Accumulated DD&A	(12,299)	(11,678)
Capitalized costs, net	2,226	2,170
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	9,661	9,472
Unproved properties	0	3
Capitalized costs, gross	9,661	9,475
Accumulated DD&A	(8,952)	(7,849)
Capitalized costs, net	709	1,626
Other International
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	434	0
Unproved properties	121	512
Capitalized costs, gross	555	512
Accumulated DD&A	0	0
Capitalized costs, net	$ 555	$ 512

SUPPLEMENTAL OIL AND GAS DISC_6

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2024 MBoe MBbls MMcf	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf	Dec. 31, 2021 MBoe MMcf MBbls
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	670,003	735,859	801,315	827,772
Proved undeveloped reserves	299,094	71,621	88,454	85,190
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	807,480	889,769	912,962
Extensions, discoveries and other additions	324,624	112,249	33,805
Purchases of minerals in-place	222,121	64	39,110
Revisions of previous estimates	(74,149)	(45,931)	74,523
Production	(166,426)	(147,840)	(144,631)
Sales of minerals in-place	(144,553)	(831)	(26,000)
Ending balance	969,097	807,480	889,769
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	482,677	500,354	530,823	551,384
Proved undeveloped reserves	213,253	65,931	76,386	65,288
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	566,285	607,209	616,672
Extensions, discoveries and other additions	222,811	95,677	21,592
Purchases of minerals in-place	222,121	64	39,110
Revisions of previous estimates	(67,162)	(56,532)	33,217
Production	(103,572)	(79,302)	(77,382)
Sales of minerals in-place	(144,553)	(831)	(26,000)
Ending balance	695,930	566,285	607,209
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	151,474	165,162	174,633	184,563
Proved undeveloped reserves	12,204	5,690	8,735	12,683
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	170,852	183,368	197,246
Extensions, discoveries and other additions	28,176	15,344	9,278
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	14,986	24,490	29,647
Production	(50,336)	(52,350)	(52,803)
Sales of minerals in-place	0	0	0
Ending balance	163,678	170,852	183,368
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	35,852	70,343	95,859	91,825
Proved undeveloped reserves	0	0	3,333	7,219
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	70,343	99,192	99,044
Extensions, discoveries and other additions	0	1,228	2,935
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(21,973)	(13,889)	11,659
Production	(12,518)	(16,188)	(14,446)
Sales of minerals in-place	0	0	0
Ending balance	35,852	70,343	99,192
Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	0	0	0	0
Proved undeveloped reserves	73,637	0	0	0
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	0	0
Extensions, discoveries and other additions	73,637	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	0
Production	0	0	0
Sales of minerals in-place	0	0	0
Ending balance	73,637	0	0
Noncontrolling Interests | Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) | MBoe	55	57	61	66
Crude Oil and Condensate
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	311,170	342,923	368,338	364,687
Proved undeveloped reserves	188,541	36,202	33,669	34,928
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	379,125	402,007	399,615
Extensions, discoveries and other additions	192,530	56,893	19,972
Purchases of minerals in-place	124,112	20	16,362
Revisions of previous estimates	(20,121)	(5,017)	42,124
Production	(89,267)	(74,003)	(68,641)
Sales of minerals in-place	(86,668)	(775)	(7,425)
Ending balance	499,711	379,125	402,007
Crude Oil and Condensate | United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	184,744	179,542	177,708	180,968
Proved undeveloped reserves	107,283	30,948	22,239	18,168
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	210,490	199,947	199,136
Extensions, discoveries and other additions	100,778	43,613	9,776
Purchases of minerals in-place	124,112	20	16,362
Revisions of previous estimates	(9,642)	(3,520)	7,793
Production	(47,043)	(28,795)	(25,695)
Sales of minerals in-place	(86,668)	(775)	(7,425)
Ending balance	292,027	210,490	199,947
Crude Oil and Condensate | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	95,990	102,305	108,050	106,646
Proved undeveloped reserves	7,621	5,254	8,557	11,003
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	107,559	116,607	117,649
Extensions, discoveries and other additions	18,115	12,979	7,580
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	10,521	10,505	22,433
Production	(32,584)	(32,532)	(31,055)
Sales of minerals in-place	0	0	0
Ending balance	103,611	107,559	116,607
Crude Oil and Condensate | North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	30,436	61,076	82,580	77,073
Proved undeveloped reserves	0	0	2,873	5,757
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	61,076	85,453	82,830
Extensions, discoveries and other additions	0	301	2,616
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(21,000)	(12,002)	11,898
Production	(9,640)	(12,676)	(11,891)
Sales of minerals in-place	0	0	0
Ending balance	30,436	61,076	85,453
Crude Oil and Condensate | Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	0	0	0	0
Proved undeveloped reserves	73,637	0	0	0
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	0	0
Extensions, discoveries and other additions	73,637	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	0
Production	0	0	0
Sales of minerals in-place	0	0	0
Ending balance	73,637	0	0
Crude Oil and Condensate | Noncontrolling Interests | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	35,000	36,000	39,000	39,000
Natural Gas Liquids
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	154,267	154,946	160,975	166,677
Proved undeveloped reserves	54,674	18,401	19,080	16,685
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	173,347	180,055	183,362
Extensions, discoveries and other additions	62,988	26,082	5,501
Purchases of minerals in-place	51,406	21	10,985
Revisions of previous estimates	(20,444)	(9,332)	9,917
Production	(27,478)	(23,446)	(23,370)
Sales of minerals in-place	(30,878)	(33)	(6,340)
Ending balance	208,941	173,347	180,055
Natural Gas Liquids | United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	153,523	153,486	158,745	164,172
Proved undeveloped reserves	54,674	18,401	19,004	16,380
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	171,887	177,749	180,552
Extensions, discoveries and other additions	62,988	25,711	5,456
Purchases of minerals in-place	51,406	21	10,985
Revisions of previous estimates	(20,167)	(8,568)	9,991
Production	(27,039)	(22,993)	(22,895)
Sales of minerals in-place	(30,878)	(33)	(6,340)
Ending balance	208,197	171,887	177,749
Natural Gas Liquids | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	0	0	0	446
Proved undeveloped reserves	0	0	0	30
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	0	476
Extensions, discoveries and other additions	0	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	(407)
Production	0	0	(69)
Sales of minerals in-place	0	0	0
Ending balance	0	0	0
Natural Gas Liquids | North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	744	1,460	2,230	2,059
Proved undeveloped reserves	0	0	76	275
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	1,460	2,306	2,334
Extensions, discoveries and other additions	0	371	45
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(277)	(764)	333
Production	(439)	(453)	(406)
Sales of minerals in-place	0	0	0
Ending balance	744	1,460	2,306
Natural Gas Liquids | Noncontrolling Interests | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves				159
Natural Gas
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves | MMcf	1,227,393	1,427,939	1,632,012	1,778,442
Proved undeveloped reserves | MMcf	335,274	102,107	214,234	201,464
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,530,046	1,846,246	1,979,906
Extensions, discoveries and other additions | MMcf	414,633	175,641	49,991
Purchases of minerals in-place	279,615	136	70,584
Revisions of previous estimates	(201,502)	(189,496)	134,893
Production	(298,086)	(302,345)	(315,718)
Sales of minerals in-place	(162,039)	(136)	(73,410)
Ending balance | MMcf	1,562,667	1,530,046	1,846,246
Natural Gas | United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves | MMcf	866,460	1,003,956	1,166,218	1,237,461
Proved undeveloped reserves | MMcf	307,775	99,495	210,862	184,441
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,103,451	1,377,080	1,421,902
Extensions, discoveries and other additions | MMcf	354,267	158,118	38,157
Purchases of minerals in-place | MMcf	279,615	136	70,584
Revisions of previous estimates | MMcf	(224,118)	(266,664)	92,599
Production | MMcf	(176,941)	(165,083)	(172,752)
Sales of minerals in-place | MMcf	(162,039)	(136)	(73,410)
Ending balance | MMcf	1,174,235	1,103,451	1,377,080
Natural Gas | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves | MMcf	332,905	377,144	399,502	464,826
Proved undeveloped reserves | MMcf	27,499	2,612	1,068	9,899
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	379,756	400,570	474,725
Extensions, discoveries and other additions | MMcf	60,366	14,188	10,191
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	26,792	83,907	45,725
Production	(106,510)	(118,909)	(130,071)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	360,404	379,756	400,570
Natural Gas | North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves | MMcf	28,028	46,839	66,292	76,155
Proved undeveloped reserves | MMcf	0	0	2,304	7,124
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	46,839	68,596	83,279
Extensions, discoveries and other additions | MMcf	0	3,335	1,643
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(4,176)	(6,739)	(3,431)
Production	(14,635)	(18,353)	(12,895)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	28,028	46,839	68,596
Natural Gas | Noncontrolling Interests | Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves | MMcf	120,000	127,000	134,000	158,000

SUPPLEMENTAL OIL AND GAS DISC_7

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) - MBoe MBoe in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	325	112	34
Revision of previous estimate	74	46	75
Percentage of estimated proved developed reserves classified as proved not producing	11%
Changes in Product Prices
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate	25	83	5
Changes in Engineering and Performance
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate		37	70
Production Sharing Contracts Modernization Impact
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate			43
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	223
Revision of previous estimate	47
United States | Changes in Engineering and Performance
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate			18
International Regions
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	102	16	12
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	28	15	9
Revision of previous estimate	47
Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	74
Permian Basin
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		67	9
Revision of previous estimate	99
Sale of mineral in place			26
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		1	3
Revision of previous estimate	22
North Sea | Other Revisions
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate			9
North America
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		96	22
Texas Gulf Coast
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		27	8
Delaware Basin
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		2	5
Purchase of mineral in place			39

SUPPLEMENTAL OIL AND GAS DISC_8

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	$ 45,585	$ 37,099	$ 54,543
Production costs	(14,216)	(12,791)	(16,090)
Development costs	(9,275)	(5,934)	(5,501)
Income tax expense	(3,581)	(4,117)	(6,935)
Net cash flows	18,513	14,257	26,017
10 percent discount rate	(6,934)	(4,216)	(8,415)
Discounted future net cash flows	$ 11,579	10,041	17,602
Estimated future net cash flow before income tax expenses	10%
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum	$ 14,400	13,600	22,600
United States
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	27,534	21,417	31,577
Production costs	(9,665)	(8,328)	(10,763)
Development costs	(4,124)	(2,238)	(1,733)
Income tax expense	(921)	(949)	(1,575)
Net cash flows	12,824	9,902	17,506
10 percent discount rate	(4,317)	(3,749)	(6,811)
Discounted future net cash flows	8,507	6,153	10,695
Egypt
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	9,342	9,921	12,819
Production costs	(1,716)	(1,690)	(2,086)
Development costs	(1,517)	(1,235)	(1,471)
Income tax expense	(1,923)	(2,222)	(2,729)
Net cash flows	4,186	4,774	6,533
10 percent discount rate	(872)	(943)	(1,400)
Discounted future net cash flows	3,314	3,831	5,133
Egypt | Noncontrolling Interests
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Discounted future net cash flows	1,100	1,300	1,700
North Sea
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	2,828	5,761	10,147
Production costs	(1,399)	(2,773)	(3,241)
Development costs	(2,538)	(2,461)	(2,297)
Income tax expense	85	(946)	(2,631)
Net cash flows	(1,024)	(419)	1,978
10 percent discount rate	535	476	(204)
Discounted future net cash flows	(489)	57	1,774
Suriname
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	5,881	0	0
Production costs	(1,436)	0	0
Development costs	(1,096)	0	0
Income tax expense	(822)	0	0
Net cash flows	2,527	0	0
10 percent discount rate	(2,280)	0	0
Discounted future net cash flows	$ 247	$ 0	$ 0

SUPPLEMENTAL OIL AND GAS DISC_9

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Sales, net of production costs	$ (5,806)	$ (5,408)	$ (7,131)
Net change in prices and production costs	269	(7,089)	8,690
Discoveries and improved recovery, net of related costs	3,557	1,869	1,142
Change in future development costs	(695)	(413)	(343)
Previously estimated development costs incurred during the period	793	825	669
Revision of quantities	(428)	(262)	2,646
Purchases of minerals in-place	4,166	1	911
Accretion of discount	1,357	2,260	1,489
Change in income taxes	737	1,467	(2,467)
Sales of minerals in-place	(1,865)	(18)	(363)
Change in production rates and other	(547)	(793)	(1)
Change in the discounted future net cash flows, Total	$ 1,538	$ (7,561)	$ 5,242