Apache 10-K 22 Feb 24 2023 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2023	Jan. 31, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4300
Entity Registrant Name	APACHE CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0747868
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		1,000
Documents Incorporated by Reference [Text Block]	Portions of APA Corporation’s proxy statement relating to its 2024 annual meeting of stockholders (the APA Proxy Statement) have been incorporated by reference into Part III hereof.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0000006769
Entity Public Float			$ 0

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
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 ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUES AND OTHER:
Derivative instrument gains (losses), net		$ 0	$ (107)	$ 94
Gain on divestitures, net		8	1,180	67
Losses on previously sold Gulf of Mexico properties		(212)	(157)	(446)
Other, net		26	139	228
Total revenues and other		7,795	11,938	7,928
OPERATING EXPENSES:
Lease operating expenses	[1]	1,397	1,435	1,241
Taxes other than income		192	256	204
Exploration		153	146	127
General and administrative		325	462	357
Transaction, reorganization, and separation		15	26	22
Depreciation, depletion, and amortization		1,399	1,177	1,360
Asset retirement obligation accretion		116	117	113
Impairments		61	0	208
Financing costs, net		165	313	472
Total operating expenses		4,879	6,064	5,948
NET INCOME BEFORE INCOME TAXES		2,916	5,874	1,980
Current income tax provision		1,338	1,507	652
Deferred income tax provision (benefit)		(1,652)	145	(74)
NET INCOME INCLUDING NONCONTROLLING INTERESTS		3,230	4,222	1,402
Net income (loss) attributable to Altus Preferred Unit limited partners		0	(70)	162
NET INCOME ATTRIBUTABLE TO APACHE CORPORATION		2,526	3,536	1,062
Noncontrolling Interest - Sinopec
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		352	464	174
Noncontrolling interest - Altus
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		0	14	4
Noncontrolling Interest - APA Corporation
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		352	278	0
Oil and gas
REVENUES AND OTHER:
Total revenues		7,973	10,883	7,985
Gathering, processing, and transmission costs
REVENUES AND OTHER:
Total revenues	[1]	7,079	9,028	6,498
OPERATING EXPENSES:
Cost of goods and services sold	[1]	314	356	264
Purchased oil and gas sales
REVENUES AND OTHER:
Total revenues	[1]	894	1,855	1,487
OPERATING EXPENSES:
Cost of goods and services sold	[1]	$ 742	$ 1,776	$ 1,580
[1] (1) For related party transactions associated with Kinetik, refer to Note 7—Equity Method Interest for further detail.

STATEMENT OF CONSOLIDATED COMPR

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 3,230	$ 4,222	$ 1,402
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	1	(8)	7
Share of equity method interests other comprehensive income	0	0	1
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	3,231	4,214	1,410
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners	0	(70)	162
COMPREHENSIVE INCOME ATTRIBUTABLE TO APACHE CORPORATION	2,527	3,528	1,070
Noncontrolling Interest - Sinopec
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income ( loss ) attributable to noncontrolling interest	352	464	174
Noncontrolling interest - Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income ( loss ) attributable to noncontrolling interest	0	14	4
Noncontrolling Interest - APA Corporation
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income ( loss ) attributable to noncontrolling interest	$ 352	$ 278	$ 0

STATEMENT OF CONSOLIDATED CASH

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$ 3,230	$ 4,222	$ 1,402
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	0	23	(69)
Gain on divestitures, net	(8)	(1,180)	(67)
Exploratory dry hole expense and unproved leasehold impairments	108	92	86
Depreciation, depletion, and amortization	1,399	1,177	1,360
Asset retirement obligation accretion	116	117	113
Impairments	61	0	208
Provision for (benefit from) deferred income taxes	(1,652)	145	(74)
(Gain) loss from extinguishment of debt	(9)	67	104
Losses on previously sold Gulf of Mexico properties	212	157	446
Other	(85)	(137)	(23)
Changes in operating assets and liabilities:
Receivables	(146)	(55)	(393)
Inventories	13	(1)	(9)
Drilling advances and other current assets	287	(12)	60
Deferred charges and other long-term assets	269	70	(42)
Accounts payable	(86)	12	205
Receivable/payable with APA Corporation	(52)	0	40
Accrued expenses	(401)	293	127
Deferred credits and noncurrent liabilities	(327)	(138)	31
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,929	4,852	3,505
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(1,931)	(1,503)	(934)
Leasehold and property acquisitions	(20)	(37)	(9)
Noncurrent receivable from APA Corporation	(680)	(832)	0
Proceeds from asset divestitures	29	778	256
Proceeds from sale of Kinetik shares	228	224	0
Deconsolidation of Altus cash and cash equivalents	0	(143)	0
Other, net	(38)	28	21
NET CASH USED IN INVESTING ACTIVITIES	(2,412)	(1,485)	(666)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	0	138	392
Proceeds from (payments on) note payable to APA Corporation, net	0	(835)	78
Payments on fixed-rate debt	(65)	(1,493)	(1,795)
Distributions to noncontrolling interest – Sinopec	(238)	(362)	(279)
Distributions to APA Corporation	(315)	(894)	(1,182)
Dividends paid	0	0	(9)
Other, net	0	(15)	(27)
NET CASH USED IN FINANCING ACTIVITIES	(618)	(3,461)	(2,822)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(101)	(94)	17
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	185	279	262
CASH AND CASH EQUIVALENTS AT END OF PERIOD	84	185	279
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	293	322	442
Income taxes paid, net of refunds	1,271	1,431	633
Non-cash financing adjustment: APA’s assumption of Apache’s borrowings on its syndicated credit facility	$ 0	$ 680	$ 0

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 84	$ 185
Other current assets (Note 6)	725	993
Total current assets	2,420	2,602
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:	43,349	41,245
Gathering, processing, and transmission facilities	448	449
Other	634	613
Less: Accumulated depreciation, depletion, and amortization	(35,707)	(34,350)
Property and equipment, net	8,724	7,957
OTHER ASSETS:
Equity method interests (Note 7)	437	624
Decommissioning security for sold Gulf of Mexico properties (Note 12)	21	217
Deferred tax asset (Note 11)	1,747	39
Deferred charges and other	522	532
Assets	16,944	14,255
CURRENT LIABILITIES:
Accounts payable	560	646
Current debt	2	2
Other current liabilities (Note 8)	1,669	2,049
Total current liabilities	2,231	2,697
LONG-TERM DEBT (Note 10)	4,814	4,885
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 11)	371	314
Asset retirement obligation (Note 9)	2,354	1,936
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	764	738
Other	466	443
Total deferred credits and other noncurrent liabilities	3,955	3,431
EQUITY:
Common stock, $0.625 par, 1,000 and 1,000 shares authorized, respectively, 1,000 and 1,000 shares issued, respectively	0	0
Paid-in capital	7,972	8,025
Accumulated deficit	(3,255)	(5,781)
Accumulated other comprehensive income	15	14
EQUITY ATTRIBUTABLE TO APACHE CORPORATION	4,732	2,258
TOTAL EQUITY	5,944	3,242
Liabilities and Equity, Total	16,944	14,255
Nonrelated Party
CURRENT ASSETS:
Receivables, net of allowance	1,559	1,424
Affiliated Entity
CURRENT ASSETS:
Receivables, net of allowance	52	0
OTHER ASSETS:
Noncurrent receivable from APA Corporation (Note 2)	93	869
Note receivable from APA Corporation (Note 2)	2,980	1,415
Noncontrolling Interest - Sinopec
EQUITY:
Noncontrolling interest	1,036	922
Noncontrolling Interest - APA Corporation
EQUITY:
Noncontrolling interest	$ 176	$ 62

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Receivables, allowance	$ 114	$ 117
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares issued (in shares)	1,000	1,000

STATEMENT OF CONSOLIDATED CHANG

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners	Noncontrolling Interest - APA Corporation	Noncontrolling Interest - Sinopec	Noncontrolling interest - Altus	Noncontrolling Interest - Egypt	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income (Loss)	PARENT COMPANY EQUITY (DEFICIT)	Noncontrolling Interests	Noncontrolling Interests Noncontrolling Interest - APA Corporation	Noncontrolling Interests Noncontrolling Interest - Sinopec	Noncontrolling Interests Noncontrolling interest - Altus	Noncontrolling Interests Noncontrolling Interest - Egypt
Beginning balance at Dec. 31, 2020	$ 608
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income (loss) attributable to Altus Preferred Unit limited partners	162
Distributions payable to Altus Preferred Unit limited partners	(12)
Distributions paid to Altus Preferred Unit limited partners					$ (46)	$ (279)											$ (279)
Ending balance at Dec. 31, 2021	712
Beginning balance at Dec. 31, 2020	(645)						$ 262	$ 11,735	$ (10,461)	$ (3,189)	$ 14	$ (1,639)	$ 994
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to Apache Corporation	1,062								1,062			1,062
Net income attributable to noncontrolling interest			$ 0	$ 174	4										$ 174	$ 4
Distributions to noncontrolling interest – Egypt					(46)	(279)											(279)
Distributions to APA Corporation	(890)							(890)				(890)
Common dividends	(9)							(9)				(9)
APA Corporation share exchange	0						(262)	(2,927)		3,189
Holding Company Reorganization	839							757	82			839
Other	4							11			8	19	(15)
Ending balance at Dec. 31, 2021	260						0	8,677	(9,317)	0	22	(618)	878
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income (loss) attributable to Altus Preferred Unit limited partners	(70)
Distributions paid to Altus Preferred Unit limited partners						(362)											(362)
Deconsolidation of Altus		$ (642)
Ending balance at Dec. 31, 2022	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to Apache Corporation	3,536								3,536			3,536
Net income attributable to noncontrolling interest			278	464	14									$ 278	464	$ 14
Distributions to noncontrolling interest – Egypt						(362)											(362)
Distributions to APA Corporation	(894)							(678)				(678)	(216)
Deconsolidation of Altus	(72)												(72)
Other	18							26			(8)	18	0
Ending balance at Dec. 31, 2022	3,242						0	8,025	(5,781)	0	14	2,258	984
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions paid to Altus Preferred Unit limited partners						(238)											(238)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to Apache Corporation	2,526								2,526			2,526
Net income attributable to noncontrolling interest			$ 352	$ 352	$ 0									$ 352	$ 352
Distributions to noncontrolling interest – Egypt						$ (238)											$ (238)
Distributions to APA Corporation	(315)							(77)				(77)	(238)
Other	25							24			1	25
Ending balance at Dec. 31, 2023	$ 5,944						$ 0	$ 7,972	$ (3,255)	$ 0	$ 15	$ 4,732	$ 1,212

STATEMENT OF CONSOLIDATED CHA_2

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Parenthetical)	12 Months Ended
	Dec. 31, 2021 $ / shares
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.025

NATURE OF OPERATIONS

NATURE OF OPERATIONS	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS	Nature of Operations Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has oil and gas operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Prior to the BCP Business Combination defined below, Apache’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’s operating and legal structure, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by Apache 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 Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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. Noncontrolling interests represent outside ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. In conjunction with the ratification of a merged concession agreement with the Egyptian General Petroleum Corporation (EGPC) in December 2021, Apache modified partnership agreements for certain consolidated subsidiaries. Apache subsequently determined that one of its limited partnership subsidiaries, which has control over Apache’s Egyptian operations, qualified as a variable interest entity (VIE) under GAAP. Apache continues to consolidate this limited partnership subsidiary because the Company has concluded that it has a controlling financial interest in the Egyptian operations and was determined to be the primary beneficiary of the VIE. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a noncontrolling interest participation in the remaining two-thirds of its consolidated Egypt oil and gas business. Refer to Note 2—Transactions with Parent Affiliate for detail regarding APA’s noncontrolling interest. All noncontrolling interests are reflected as a separate component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination (as defined below), third-party investors owned a minority interest of approximately 21 percent of Altus, which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which Apache consolidated because a wholly owned subsidiary of Apache had a controlling financial interest and was determined to be the primary beneficiary. 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 3—Acquisitions and Divestitures for further detail. During each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. As a result, the Company is considered to have had significant influence over Kinetik for all periods presented and will continue to have such influence until such time as Kinetik appoints a replacement for the Company’s designated director, given that the Company’s current beneficial ownership percentage in Kinetik no longer entitles it to designate a director to the Kinetik board. 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 7—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 3—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 11—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 12—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 19—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). Recurring fair value measurements are presented in further detail in Note 5—Derivative Instruments and Hedging Activities , Note 7—Equity Method Interests , Note 10—Debt and Financing Costs , Note 13—Retirement and Deferred Compensation Plans , and Note 14—Redeemable Noncontrolling Interest — Altus . The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. 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. For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in a pipeline investment as part of Altus’ review of the fair value of its assets in relation to the BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 3—Acquisitions and Divestitures for further detail on the BCP Business Combination. Revenue Recognition Upstream The Company’s upstream 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 Apache-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. The Company’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 18—Business Segment Information for a disaggregation of revenue by product and reporting segment. Altus Midstream Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which were fully eliminated upon consolidation. 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 $1.4 billion and $1.3 billion as of December 31, 2023 and 2022, 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. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the EGPC for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. 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, 2023 and 2022, the Company had $84 million and $185 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2023 and 2022. 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, 2023 2022 2021 (In millions) Allowance for credit loss at beginning of year $ 117 $ 109 $ 95 Additional provisions for the year 16 9 19 Uncollectible accounts written off, net of recoveries (19) (1) (5) Allowance for credit loss at end of year $ 114 $ 117 $ 109 Receivable from / Payable to APA Receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Cash will be transferred to Apache or paid to APA over time in order to manage affiliate balances for cash management purposes. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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 2023, the Company recorded $50 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions 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 unproved properties: For the Year Ended December 31, 2023 2022 2021 (In millions) Unproved properties: U.S. $ 10 $ 20 $ 22 Egypt — 4 8 North Sea 11 — 1 Total unproved properties $ 21 $ 24 $ 31 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. For the years ended December 31, 2023, 2022, and 2021, 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 3—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $448 million and $449 million at December 31, 2023 and 2022, respectively, with accumulated depreciation for these assets totaling $373 million and $367 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 Apache-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, 2023, 2022, and 2021, 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 $217 million and $206 million at December 31, 2023 and 2022, 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 7—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. Prior to the deconsolidation of Altus on February 22, 2022, in the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the BCP Business Combination, determined the fair value of a pipeline investment was below carrying value. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in the pipeline. 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 12—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 5—Derivative Instruments and Hedging Activities for further information. Income Taxes Apache 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. Apache is a directly owned subsidiary of APA and is included in APA and its subsidiaries’ U.S. Federal income tax return. The Company’s financial statements recognize the current and deferred income tax consequences that result from Apache’s activities during the current period pursuant to the provisions of ASC Topic 740 “Income Taxes” as if the Company were a separate taxpayer rather than a member of APA’s consolidated income tax return group. Refer to Note 11—Income Taxes for further information. Stock-Based Compensation Prior to consummation of the Holding Company Reorganization, Apache granted 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 APA’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, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock . Transaction, Reorganization, and Separation (TRS) The Company recorded TRS costs in 2023, 2022, and 2021 totaling $15 million, $26 million, and $22 million, respectively, including $7 million, $15 million, and $17 million, respectively, related to ongoing consulting and separation costs in international operations associated with the redesign of the Company’s organizational structure and operations. New Pronouncements Issued But Not Yet Adopted In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, “Segment Reporting (Topic 280),” which expands disclosures about a public entity’s reportable segments and requires more enhanced information about a reportable segment’s expenses, interim segment profit or loss, and how a public entity’s chief operating decision maker uses reported segment profit or loss information in assessing segment performance and allocating resources. The amendments do not change or remove existing disclosure requirements or how a public entity identifies its operating s

TRANSACTIONS WITH PARENT AFFILI

TRANSACTIONS WITH PARENT AFFILIATE	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
TRANSACTIONS WITH PARENT AFFILIATE	TRANSACTIONS WITH PARENT AFFILIATE Apache is a direct, wholly owned subsidiary of APA. Apache holds assets in the U.S., Egypt, and the U.K. and provides administrative and support operations for certain APA subsidiaries with interests in the U.S., Suriname, and other international locations. The Company incurred $22 million, $18 million, and $17 million during 2023, 2022, and 2021, respectively, in reimbursable corporate overhead charges in connection with these administration and support operations. Notes Receivable from APA Corporation On March 1, 2021, Apache sold to APA all of the equity in the three Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The purchase price is payable pursuant to a senior promissory note made by APA payable to Apache, dated March 1, 2021. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the three subsidiaries sold by Apache to APA. APA allowed interest accrued from March 1, 2021 through August 31, 2023, totaling $158 million, to PIK pursuant to the note. As of December 31, 2023 and 2022, approximately $1.5 billion and $1.4 billion, respectively, were in principal outstanding under this note. In April 2022, Apache made a promissory note payable to APA in the original principal amount of $680 million. Apache made the note in consideration for APA’s assumption under its U.S. dollar denominated syndicated facility on April, 29, 2022 of Apache’s borrowings outstanding upon the simultaneous termination of its 2018 syndicated facility, as described in Note 1 0 —Debt and Financing Costs . The non-interest-bearing note was fully repaid during 2022. APA also made a senior promissory note payable to Apache, dated March 31, 2023, pursuant to which Apache may loan and APA may borrow, repay, and reborrow up to $1.5 billion in aggregate principal amount outstanding at any time. The note has a five-year term, maturing March 31, 2028. The note bears interest at a rate per annum of 6.0 percent, payable semi-annually; however, APA may allow accrued interest to convert to principal, subject to the aggregate maximum principal amount of the note. As of December 31, 2023, there were $1.5 billion in borrowings outstanding under this note. The note is intended to facilitate cash management of APA and Apache. These notes are both reflected in “Notes receivable from APA Corporation” on the Company’s consolidated balance sheet. The Company recognized interest income on these notes totaling $109 million, $63 million, and $51 million during 2023, 2022, and 2021, respectively. The interest income related to these notes is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Noncontrolling Interest – APA Corporation In the fourth quarter of 2021, in conjunction with the ratification of a new merged concession agreement (MCA) with the EGPC, Apache entered into an agreement with APA under which the historical value of existing concessions prior to ratifying the MCA was retained by Apache, with any excess value from the MCA terms being allocated to APA. Sinopec owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business, and 50 percent of the remaining net income and distributable cash flow for the Company’s Egyptian operations was allocated to APA in 2023. Apache consolidates its Egyptian operations, with APA’s noncontrolling interest reflected as a separate component in the Company’s consolidated balance sheet. The Company recorded net income attributable to APA’s noncontrolling interest of $352 million and $278 million during 2023 and 2022, respectively. The Company also distributed $238 million and $216 million during 2023 and 2022, respectively, of cash to APA in association with its noncontrolling interest. Accounts Receivable from / Accounts Payable to APA In connection with the Company’s role as service provider to APA, Apache is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company on behalf of APA. All reimbursements are based on actual costs incurred, and no market premium is applied by the Company to APA. The Company also collects third-party receivables on behalf of APA. As of December 31, 2023, the Company had accounts receivable from APA in connection with these services totaling $52 million, which is reflected in “Accounts receivable from APA Corporation” on the Company’s consolidated balance sheet. As of December 31, 2023 and 2022, the Company also had receivables from APA totaling $93 million and $869 million, respectively, which were incorporated into the senior promissory note dated March 31, 2023 discussed above during 2024 and 2023, respectively. These balances are reflected in “Noncurrent receivable from APA Corporation.” Other Transactions with APA Corporation From time to time, the Company may, at its discretion, make distributions of capital to APA. During 2023 and 2022, the Company made capital distributions totaling $77 million and $678 million, respectively, primarily in support of dividend payments and capital transactions completed by APA during the respective periods.

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2023 Activity In December 2023, the Company sold 7.5 million of its shares of Kinetik Class A Common Stock (Kinetik Shares) for cash proceeds of $228 million. Refer to Note 7—Equity Method Interests for further detail. During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $20 million. 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 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 7—Equity Method Interests for further detail. 2021 Activity During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $63 million in connection with the sale. During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions.

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2023
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, 2023, 2022, and 2021. 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, 2023 2022 2021 (In millions) Capitalized well costs at beginning of year $ 50 $ 46 $ 197 Additions pending determination of proved reserves 150 138 62 Divestitures and other — — (163) Reclassifications to proved properties (135) (110) (40) Charged to exploration expense (18) (24) (10) Capitalized well costs at end of year $ 47 $ 50 $ 46 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: 2023 2022 2021 (In millions) Exploratory well costs capitalized for a period of one year or less $ 38 $ 34 $ 13 Exploratory well costs capitalized for a period greater than one year 9 16 33 Capitalized well costs at end of year $ 47 $ 50 $ 46 Number of projects with exploratory well costs capitalized for a period greater than one year 8 10 9 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 $9 million at December 31, 2023. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing. Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2022 totaled $16 million. These expenses pertained to projects in the North Sea and Egypt. The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2023, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2022 2021 2020 and Prior (In millions) Egypt $ 9 $ — $ — $ 9 $ 9 $ — $ — $ 9

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2023
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 may utilize 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 or foreign currency values. In December 2022, counterparty agreements for Apache’s commodity derivative instruments were transferred from Apache to APA. Apache had no outstanding derivative positions as of December 31, 2023 or December 31, 2022. 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, 2023 2022 2021 (In millions) Realized: Commodity derivative instruments $ — $ (72) $ 25 Foreign currency derivative instruments — (13) — Realized gains (losses), net — (85) 25 Unrealized: Commodity derivative instruments — 9 (20) Pipeline capacity embedded derivatives — — 7 Preferred Units embedded derivative — (31) 82 Unrealized gains (losses), net — (22) 69 Derivative instrument gains (losses), net $ — $ (107) $ 94 Derivative instrument gains and losses were 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 were reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” in “Adjustments to reconcile net income to net cash provided by operating activities.”

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 (In millions) Inventories $ 439 $ 425 Drilling advances 68 64 Prepaid assets and other 40 54 Current decommissioning security for sold Gulf of Mexico assets 178 450 Total Other current assets $ 725 $ 993

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
EQUITY METHOD INTERESTS	EQUITY METHOD INTERESTS As of December 31, 2023 and 2022, the Company recorded $437 million and $624 million, respectively, for ownership of its Kinetik Shares. The Company’s Kinetik Shares are treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations. The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million Kinetik Shares as of February 22, 2022. In March 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 3–Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million Kinetik Shares. In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $228 million. The Company has received approximately 2.9 million Kinetik Shares as paid-in-kind dividends through December 31, 2023. As of December 31, 2023, the Company owned 13.1 million Kinetik Shares, representing approximately 9 percent of Kinetik’s outstanding common stock. The Company recorded changes in the fair value of its equity method interest in Kinetik totaling gains of $41 million and $72 million during 2023 and 2022, respectively. The balance of the Company’s equity method interest in Kinetik was also impacted by the sales of Kinetik Shares noted above during 2023 and 2022. The following table represents related party sales and costs associated with Kinetik: For the Year Ended December 31, 2023 2022 (In millions) Natural gas and NGLs sales $ 64 $ 8 Purchased oil and gas sales 29 — $ 93 $ 8 Gathering, processing, and transmission costs $ 99 $ 91 Purchased oil and gas costs 80 — Lease operating expenses 7 — $ 186 $ 91 As of December 31, 2023 and 2022, the Company has recorded accrued costs payable to Kinetik of approximately $27 million and $17 million, respectively, and accrued receivables from Kinetik of approximately $13 million and $8 million, respectively.

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 (In millions) Accrued operating expenses $ 158 $ 139 Accrued exploration and development 307 300 Accrued compensation and benefits 390 514 Accrued interest 92 96 Accrued income taxes 138 90 Current asset retirement obligation 76 55 Current operating lease liability 115 167 Current decommissioning contingency for sold Gulf of Mexico properties 60 450 Other 333 238 Total Other current liabilities $ 1,669 $ 2,049

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022: For the Year Ended December 31, 2023 2022 (In millions) Asset retirement obligation at beginning of the year $ 1,991 $ 2,130 Liabilities incurred 12 4 Liabilities divested — (73) Liabilities settled (45) (39) Accretion expense 116 117 Revisions in estimated liabilities 356 (148) Asset retirement obligation at end of the year 2,430 1,991 Less current portion (76) (55) Asset retirement obligation, long-term $ 2,354 $ 1,936 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. During 2023 and 2022, the Company recorded $12 million and $4 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2023, net abandonment costs were revised upward by approximately $356 million, primarily reflecting changes in estimates of timing, activity costs, and foreign currency exchange rates on service costs in the North Sea. During 2022, net abandonment costs were revised downward by approximately $148 million to reflect changes in estimates of timing and foreign currency exchange rates on service costs, primarily in the North Sea, partially offset by an upward revision in the U.S.

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
DEBT AND FINANCING COSTS	DEBT AND FINANCING COSTS Overview The debt of Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company to repurchase outstanding notes and debentures upon certain changes in control. 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 US dollar-denominated revolving credit facility of APA Corporation described below. On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed in part by Apache’s borrowing under the U.S. dollar-denominated revolving credit facility of APA Corporation described below. 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. On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility. During 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases. During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions. Apache intends to reduce debt outstanding under its indentures from time to time. 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, 2023 and 2022: December 31, 2023 2022 (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% 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) 516 579 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) 211 221 7.375% debentures due 2047 150 150 5.35% notes due 2049 (1) 387 387 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (3) 4,835 4,908 Finance lease obligations 32 34 Unamortized discount (26) (27) Debt issuance costs (25) (28) Total debt 4,816 4,887 Current maturities (2) (2) Long-term debt $ 4,814 $ 4,885 (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 $4.3 billion and $4.2 billion as of December 31, 2023 and 2022, 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). Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2023 are as follows: (In millions) 2024 $ — 2025 51 2026 210 2027 108 2028 325 Thereafter 4,141 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, 2023 2022 2021 (In millions) Interest expense $ 291 $ 312 $ 419 Amortization of debt issuance costs 2 7 8 Capitalized interest — (1) — Loss (gain) on extinguishment of debt (9) 67 104 Interest income (10) (9) (8) Interest income from APA Corporation, net (109) (63) (51) Financing costs, net $ 165 $ 313 $ 472 Debt issuance costs are charged to financing costs over the life of the related debt issuances. Discount amortization of $1 million, $2 million, and $6 million was recorded as interest expense in 2023, 2022, and 2021, respectively. Uncommitted Lines of Credit 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, 2023 and 2022, there were no outstanding borrowings under these facilities. As of December 31, 2023, there were £296 million and $2 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities. Unsecured 2022 Committed Bank Credit Facilities On April 29, 2022, Apache entered into two unsecured guaranties of obligations under two unsecured syndicated credit agreements then entered into by APA Corporation (APA), of which Apache is a wholly owned subsidiary. APA’s new credit agreements are for general corporate purposes and replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility). • One credit agreement is denominated in US dollars (the USD Agreement) and provides 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 currently is committed). APA may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to APA’s two, one-year extension options. • The second credit agreement is denominated in pounds sterling (the 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 April 2027, subject to APA’s two, one-year extension options. In connection with APA’s entry into the USD Agreement and the GBP Agreement (each, a 2022 Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under APA’s USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a 2022 Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under APA’s USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. As of December 31, 2023 and 2022, there were no borrowings by Apache outstanding under the USD Agreement. Apache has guaranteed obligations under each 2022 Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion. As of December 31, 2023, there were $372 million of borrowings under the 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 USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which require such support while Apache’s credit rating by Standard & Poor’s remains below BBB; on March 26, 2020, Standard & Poor’s reduced Apache’s rating from BBB to BB+, which was affirmed in 2023. All borrowings under the 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 ranging from 0.10% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.10% to 1.675% (Applicable Margin). All borrowings under the GBP Agreement bear interest at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average published by the Bank of England, plus the Applicable Margin. Each 2022 Agreement also requires the borrower to pay quarterly a facility fee on total commitments. 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). As of December 31, 2023, Apache’s Long-Term Debt Rating applied, and the Base Rate Margin was 0.40%, the Applicable Margin was 1.40%, and the facility fee was 0.225%. A commission is payable quarterly to lenders under each 2022 Agreement 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. Borrowers under each 2022 Agreement, which may 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 substantially similar to those in the Former Facility, 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. For purposes of this calculation, capital continues to exclude the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2023, APA’s debt-to-capital ratio as calculated under each 2022 Agreement was 20 percent. • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $1.9 billion as of December 31, 2023. • 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. Consistent with the Former Facility, the 2022 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. Apache was in compliance with applicable terms of each 2022 Agreement as of December 31, 2023. Commercial Paper Program On December 13, 2023, APA established a commercial paper program under which APA may from time to time 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 Company has unconditionally guaranteed payment of the CP Notes on an unsecured basis, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under the Company’s existing indentures is less than US$1.0 billion. The CP Notes will be 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. The maturities of the CP Notes may vary but may not exceed 397 days from the date of issuance. As of December 31, 2023, APA had not issued any CP Notes. Subsequent Event On January 30, 2024, Apache entered into an unsecured guaranty of obligations under an unsecured syndicated credit agreement then entered into by APA under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Credit Agreement). Apache’s guaranty is 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. Subject to satisfaction of certain limited conditions, APA may borrow under the Credit Agreement to refinance certain indebtedness of Callon Petroleum Company, a Delaware corporation (Callon), upon or after closing of APA’s pending acquisition of Callon pursuant to the previously announced Agreement and Plan of Merger among APA, Astro Comet Merger Sub Corp., a Delaware corporation and wholly owned subsidiary of APA, and Callon, dated January 3, 2024 (Merger Agreement). Two tranches of term loans would be available to APA for borrowing only on the date of closing of transactions under the Merger Agreement and satisfaction of certain other conditions under the Credit Agreement (Closing Date); of the aggregate $2.0 billion in commitments, $1.5 billion is for term loans that would mature three years after the Closing Date (3-Year Tranche Loans) and $500 million is for term loans that would mature 364 days after the Closing Date (364-Day Tranche Loans). Indebtedness of Callon that APA could refinance by borrowing under the Credit Agreement on the Closing Date includes indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes, and together with the Callon Credit Agreement, Callon’s 2026 Notes, and Callon’s 2028 Notes, the Callon Indebtedness). The Credit Agreement has limited conditions to funding on the Closing Date loans requested by APA in accordance with the Credit Agreement, such as consummation of the transactions under the Merger Agreement, no Company Material Adverse Effect (as defined in the Merger Agreement) has occurred, repayment of all indebtedness outstanding under the Callon Credit Agreement and Callon’s 2026 Notes, and Callon having no other material indebtedness for borrowed money except for Callon’s 2028 Notes and Callon’s 2030 Notes or as permitted under the Credit Agreement or the Merger Agreement. Proceeds of loans made under the Credit Agreement may only be used to refinance the Callon Indebtedness and repay fees and expenses related to transactions under the Credit Agreement and the Merger Agreement. To the extent that borrowings by APA under the Credit Agreement are not so used on or before the date that is 120 days after the Closing Date, APA then must prepay the amount of such unused borrowings. If $400 million or more in aggregate principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes remains outstanding on the date which is 120 days after the Closing Date, Callon then must guarantee APA’s obligations under the Credit Agreement effective until the aggregate outstanding principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes first is less than $400 million. APA may at any time prepay loans under the Credit Agreement. APA may at any time terminate, or from time to time reduce, the lenders’ commitments under the Credit Agreement. Unless previously terminated, the lenders’ commitments automatically terminate on the first to occur of: (i) the Closing Date, after giving effect to funding of each lender’s commitments on the Closing Date, (ii) APA’s acquisition of Callon pursuant to the Merger Agreement without loans being made under the Credit Agreement, (iii) termination of the Merger Agreement in accordance with its terms, and (iv) the Termination Date (as defined in, and may be extended pursuant to, the Merger Agreement). All borrowings under the Credit Agreement would be in U.S. Dollars and bear interest at one of the following two rate options, as selected by APA, plus the indicated margin: • One option is a base rate per annum equal to the greatest of (i) the applicable prime rate, (ii) the greater of the applicable federal funds rate and overnight bank funding rate, plus 0.50%, and (iii) an adjusted secured overnight financing rate published by the Federal Reserve Bank of New York (SOFR) for a one-month interest period plus 1.0%. The margin for this rate option (Term Base Rate Margin) is a rate per annum varying from 0.25% to 1.0% for 364-Day Tranche Loans, 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, in each case, based on the rating for 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. Apache’s Long-Term Debt Rating currently applies. • The second option is an adjusted SOFR rate, plus a margin at a rate per annum varying from 1.25% to 2.0% for 364-Day Tranche Loans, 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, in each case, based on the Long-Term Debt Rating (Term Applicable Margin). For SOFR-based interest rates, APA may select an interest period of one, three, or six months. Currently, the Term Base Rate Margin is 0.625% for 364-Day Tranche Loans and 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin is 1.625% for 364-Day Tranche Loans and 1.75% for 3-Year Tranche Loans. The Credit Agreement provides for a ticking fee payable by APA at a rate of 0.225% per annum on the daily average undrawn aggregate commitments thereunder; the ticking fee accrues during the period beginning on the date that is 90 days after January 3, 2024 to the earlier of (i) termination or expiration of the commitments or (ii) the Closing Date. APA is subject to representations and warranties, covenants, and events of default under the Credit Agreement substantially similar to those in APA’s existing 2022 Agreements. The 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Net income before income taxes was composed of the following: For the Year Ended December 31, 2023 2022 2021 (In millions) U.S. $ 594 $ 2,656 $ 689 Foreign 2,322 3,218 1,291 Total $ 2,916 $ 5,874 $ 1,980 The total income tax provision (benefit) consisted of the following: For the Year Ended December 31, 2023 2022 2021 (In millions) Current income taxes: Federal $ 2 $ 1 $ 16 State 6 11 — Foreign 1,330 1,495 636 1,338 1,507 652 Deferred income taxes: Federal (1,696) — — State (34) — — Foreign 78 145 (74) (1,652) 145 (74) Total $ (314) $ 1,652 $ 578 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, 2023 2022 2021 (In millions) Income tax expense at U.S. statutory rate $ 612 $ 1,234 $ 416 State income tax, less federal effect (1) (25) 9 — Taxes related to foreign operations 753 774 300 Tax credits — (4) (10) Net change in tax contingencies 5 1 16 Valuation allowances (1) (1,838) (705) (111) Tax adjustments attributable to BCP Business Combination — 126 — Remeasurement of U.K. deferred tax liability 174 208 — Tax attributable to Altus Preferred Unit limited partners — — (34) All other, net 5 9 1 $ (314) $ 1,652 $ 578 (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: 2023 2022 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,027 $ 2,035 Capital losses 8 357 Tax credits and other tax incentives 26 26 Foreign tax credits 2,204 2,241 Accrued expenses and liabilities 130 145 Asset retirement obligation 849 672 Equity investments 8 — Net interest expense limitation 74 55 Lease liability 71 113 Decommissioning contingency for sold Gulf of Mexico properties 210 275 Total deferred tax assets 5,607 5,919 Valuation allowance (2,549) (4,831) Net deferred tax assets 3,058 1,088 Deferred tax liabilities: Equity investments — 1 Property and equipment 1,510 1,014 Right-of-use asset 69 110 Decommissioning security for sold Gulf of Mexico properties 44 148 Other 59 90 Total deferred tax liabilities 1,682 1,363 Net deferred income tax (asset) liability $ (1,376) $ 275 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2023 2022 (In millions) Assets: Other assets Deferred tax asset $ 1,747 $ 39 Liabilities: Deferred credits and other noncurrent liabilities Deferred tax liability 371 314 Net deferred income tax (asset) liability $ (1,376) $ 275 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 and is 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. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded a deferred tax expense of $208 million and $174 million related to the remeasurement of the U.K. deferred tax liability in 2022 and 2023, 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 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 is not an applicable corporation in 2023 but will be subject to CAMT beginning on January 1, 2024. The Company is continuing to evaluate the provisions of the IRA and its effects on the Company’s 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. 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 3— Acquisitions and Divestitures for further detail. 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. The Company showed positive income over the three-year period ended December 31, 2023. 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. The remaining U.S. valuation allowance relates primarily to foreign tax credit and capital loss carryforwards. In 2023, 2022, and 2021, the Company’s valuation allowance decreased by $2.3 billion, $1.0 billion, and $116 million, respectively, as detailed in the table below: 2023 2022 2021 (In millions) Balance at beginning of year $ 4,831 $ 5,875 $ 5,991 State (1) (61) (111) 1 U.S. (2,221) (706) (112) Foreign — (227) (5) Balance at end of year $ 2,549 $ 4,831 $ 5,875 (1) Reported as a component of state income taxes. On December 31, 2023, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 7,922 2027 - Indefinite State 6,541 Various The Company has a U.S. net operating loss carryforward of $7.9 billion, which includes $107 million 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 $6.5 billion, and a net interest expense carryover of $345 million under Section 163(j) of the Code with indefinite carryover. In 2023, $1.7 billion of U.S. capital loss carryforward expired unutilized with $34 million remaining, which has a five year carryover period expiring in 2027. 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, 2023, 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 full 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 that 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: 2023 2022 2021 (In millions) Balance at beginning of year $ 89 $ 116 $ 93 Additions based on tax positions related to prior year 4 — 16 Additions based on tax positions related to the current year — — 7 Reductions for tax positions of prior years (8) (27) — Balance at end of year $ 85 $ 89 $ 116 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, 2023, 2022, and 2021, the Company recorded tax expense of $2 million, $1 million, and $1 million, respectively, for interest and penalties. At December 31, 2023, 2022, and 2021, the Company had an accrued liability for interest and penalties of $7 million, $5 million, and $4 million, respectively. In 2023, 2022, and 2021, the Company recorded a $4 million net decrease, a $27 million net decrease, and a $23 million net increase, respectively, in its reserve for uncertain tax positions. On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice. 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, 2023
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, 2023, the Company has an accrued liability of approximately $83 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. Argentine Environmental Claims On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer. 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 settlement is subject to court approval, which the parties hope to receive at some point in the first half of 2024. The consideration to be provided by the Company in the settlement will 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 has been filed by the City of New Orleans against 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. Canadian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al. , No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement was approved by the court on October 26, 2023. California and Delaware Litigation On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. 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 intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit. 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. Shareholder and Derivative Lawsuits On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company intends to vigorously defend this lawsuit. On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases have now been consolidated as In Re APA Corporation Derivative Litigation , Case No. 4:23-cv-00636 in the Southern District of Texas and purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits. Environmental Matters The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition. As of December 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million. On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which will be subject to court approval. The consideration to be provided by the Company in connection with the consent decree will not have a material impact on the Company’s financial position. The Company is not aware of any environmental claims existing as of December 31, 2023, 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 Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and 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 GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets. On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM 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 GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, 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 is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM 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 GOM Assets. As of December 31, 2023, Apache has incurred $819 million in decommissioning costs related to Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs. As of December 31, 2023, $293 million has been reimbursed from Trust A and $336 million has been reimbursed from the Letters of Credit. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to use its available cash to fund the deficit. As of December 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $824 million to $1.2 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 has recorded a contingent liability of $824 million as of December 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $764 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $60 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 decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. As of December 31, 2023, the Company has also recorded a $199 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $21 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $178 million is reflected under “Other current assets.” The Company recognized $212 million, $157 million, and $446 million during 2023, 2022, and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations. On June 21, 2023, the 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. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege 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) which subsequently held that the sureties’ state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is void. Apache has drawn down the entirety of the Letters of Credit and is vigorously pursuing its claims against the sureties. 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, Apache 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, Apache 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 $167 million, $144 million, and $127 million for the years ended 2023, 2022, and 2021, respectively. As allowed under the standard, Apache 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, which are primarily related to decommissioning activities in the Gulf of Mexico, were $71 million in 2023 and not significant in 2022 and 2021. Finance lease assets are included in “Property, Plant, 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, 2023: Operating Leases Finance Lease Weighted average remaining lease term 6.9 years 9.7 years Weighted average discount rate 5.3 % 4.4 % At December 31, 2023, 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) 2024 $ 115 $ 3 $ 250 2025 35 3 197 2026 21 4 766 2027 23 4 143 2028 22 4 141 Thereafter 129 23 208 Total future minimum payments 345 41 $ 1,705 Less: imputed interest (65) (9) N/A Total lease liabilities 280 32 N/A Current portion 115 2 N/A Non-current portion $ 165 $ 30 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 $182 million, $183 million, and $194 million in 2023, 2022, and 2021, 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, 2023, the Company has spent $2.9 billion and believes it will be able to satisfy the remaining obligation within its current exploration and development program. 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 $74 million, $89 million, and $63 million in 2023, 2022, and 2021, respectively.

RETIREMENT AND DEFERRED COMPENS

RETIREMENT AND DEFERRED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2023
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 $44 million, $40 million, and $31 million for 2023, 2022, and 2021, 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, 2023, 2022, and 2021, 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. 2023 2022 2021 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 108 $ 15 $ 211 $ 20 $ 233 $ 20 Service cost 1 1 2 1 3 1 Interest cost 5 1 3 — 3 — Foreign currency exchange rates 6 — (21) — (2) — Actuarial losses (gains) 3 — (79) (5) (5) 1 Plan settlements — — — — (17) — Benefits paid (5) (3) (8) (3) (4) (4) Retiree contributions — 1 — 2 — 2 Projected benefit obligation at end of year 118 15 108 15 211 20 Change in Plan Assets Fair value of plan assets at beginning of year 137 — 254 — 262 — Actual return (loss) on plan assets 8 — (87) — 11 — Foreign currency exchange rates 8 — (26) — (3) — Employer contributions 2 1 4 2 5 2 Plan settlements — — — — (17) — Benefits paid (5) (3) (8) (4) (4) (4) Retiree contributions — 2 — 2 — 2 Fair value of plan assets at end of year 150 — 137 — 254 — Funded status at end of year $ 32 $ (15) $ 29 $ (15) $ 43 $ (20) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 32 (13) 29 (13) 43 (18) $ 32 $ (15) $ 29 $ (15) $ 43 $ (20) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (12) $ 16 $ (10) $ 18 $ 1 $ 14 Weighted Average Assumptions used as of 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 % As of December 31, 2023, 2022, and 2021, the accumulated benefit obligation for the U.K. Pension Plan was $112 million, $89 million, and $205 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 2023 2022 Asset Category Global equities — % 6 % Multi-asset credit 59 % 40 % Nominal bonds 6 % 24 % Inflation-linked bonds 33 % 28 % Cash 2 % 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, 2023 and 2022 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2023 and 2022: December 31, 2023 2022 (In millions) Asset Category Global equities $ — $ 9 Multi-asset credit 88 55 Nominal bonds 9 32 Inflation-linked bonds 50 39 Cash 3 2 Total $ 150 $ 137 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 3.5 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, 2023, 2022, and 2021: 2023 2022 2021 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 1 $ 1 $ 2 $ 1 $ 3 $ 1 Interest cost 5 1 3 — 3 — Expected return on assets (7) — (4) — (4) — Amortization of loss — (2) — (1) — (1) Settlement loss — — — — — — Net periodic benefit cost $ (1) $ — $ 1 $ — $ 2 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 5.00 % 5.29 % 1.80 % 2.57 % 1.40 % 2.06 % Salary increases 4.70 % N/A 4.90 % N/A 4.50 % N/A Expected return on assets 4.70 % N/A 1.90 % N/A 1.50 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.00 % Ultimate in 2030 N/A 5.25 % N/A 5.00 % 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 2024. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2024 $ 5 $ 2 2025 5 2 2026 5 1 2027 6 1 2028 6 1 Years 2029-2033 34 6

REDEMABLE NONCONTROLLING INTERE

REDEMABLE NONCONTROLLING INTEREST - ALTUS	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
REDEMABLE NONCONTROLLING INTEREST - ALTUS	REDEEMABLE NONCONTROLLING INTEREST — ALTUS Preferred Units Issuance On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Classification Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto. Measurement Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Accordingly, prior to the deconsolidation of Altus on February 22, 2022, the Company recorded a net loss attributable to Altus Preferred Unit limited partners totaling $70 million and net income attributable to Altus Preferred Unit limited partners totaling $162 million during 2022 and 2021, respectively. Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization and subsequent activity, Apache recorded various intercompany activities during the quarter ended March 31, 2021 as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail. Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache. Net Income (Loss) per Common Share Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly owned subsidiary of APA. Stock Compensation Plans Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting. 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, 2023, 9.4 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 APA’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, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In millions) Stock-settled and cash-settled compensation expensed: Lease operating expenses $ 27 $ 82 $ 39 Exploration 4 13 5 General and administrative 50 193 108 Total stock-settled and cash-settled compensation expensed 81 288 152 Stock-settled and cash-settled compensation capitalized 13 43 18 Total stock-settled and cash-settled compensation costs $ 94 $ 331 $ 170 Stock Options As of December 31, 2023, APA had outstanding options to purchase shares of APA’s 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, 2023, 2022, and 2021: 2023 2022 2021 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 2,078 $ 57.71 3,012 $ 63.79 3,537 $ 72.10 Exercised (12) 42.38 (99) 42.09 — — Forfeited — — (2) 49.10 — — Expired (601) 80.53 (833) 81.56 (525) 119.83 Outstanding, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 Expected to vest — — — — — — Exercisable, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 (1) As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000. During the years ended December 31, 2023, 2022, and 2021, there were no options issued and 12,183, 98,646, and no options, respectively, exercised. Restricted Stock Units and Restricted Stock Phantom Units Prior to consummation of the Holding Company Reorganization, the Company had 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 APA’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, 2023, 2022, and 2021, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $70 million, $145 million, and $91 million, respectively. As of December 31, 2023, 2022, and 2021, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $11 million, $22 million, and $15 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021: 2023 2022 2021 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 1,885 $ 23.08 2,073 $ 19.98 1,552 $ 28.43 Granted 661 41.60 847 29.90 1,506 16.46 Vested (3) (975) 23.31 (978) 22.39 (857) 29.13 Forfeited (69) 32.44 (57) 23.49 (128) 19.78 Expired (22) 27.81 — — — — Non-vested, end of year (1)(2) 1,480 30.69 1,885 23.08 2,073 19.98 (1) As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units. (2) As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years. (3) The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 5,709 6,402 4,423 Adjustment from ALTM transaction (1) — 143 — Granted (2) 1,972 2,568 4,441 Vested (2,851) (2,970) (2,049) Forfeited (340) (434) (413) Expired (12) — — Non-vested, end of year (3) 4,478 5,709 6,402 (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 2023, 2022, and 2021 included 1,972,116, 2,512,602, and 4,375,546 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 and 2021 included 55,546 and 65,327 awards, respectively, 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, 2023 was approximately $54 million. In January 2024, APA awarded 819,836 restricted stock units and 2,356,255 restricted stock phantom units based on APA’s weighted-average per-share market price of $33.73 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 $28 million and $80 million, respectively, and was calculated based on the per-share fair market value of a share of APA’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, APA 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, 2023, are as described below: • In January 2020, APA’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 999,896 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 155 percent of target. • In January 2021, APA’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 1,803,083 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 118 percent of target. • In January 2022, APA’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. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 1,040,100 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 2,080,200 units could be awarded. • In January 2023, APA’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 784,977 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 1,569,954 units could be awarded. Compensation expense related to the conditional cash-settled awards is 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 expenses of $2 million, $136 million, and $56 million during 2023, 2022, and 2021, respectively. Capitalized compensation costs under the cash-settled performance programs were expenses of approximately $100 thousand, $21 million, and $3 million during 2023, 2022, and 2021, respectively. The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 4,835 4,531 3,417 Granted 1,536 1,676 1,782 Vested (1,593) (656) (76) Forfeited (99) (106) (240) Expired (50) (610) (352) Non-vested, end of year (1) 4,629 4,835 4,531 (1) As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million. In January 2024, APA’s Board of Directors approved the 2024 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 2024 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 644,399 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,288,798 units. These phantom units represent a hypothetical interest in APA’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 APA’s common stock, a Level 1 fair value measurement. The cash incentives totaled $14 million, with the ultimate payout ranging from zero to $28 million. Final payout of the awards will be determined at the end of a three-year performance period.

CAPITAL STOCK AND EQUITY

CAPITAL STOCK AND EQUITY	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
CAPITAL STOCK AND EQUITY	REDEEMABLE NONCONTROLLING INTEREST — ALTUS Preferred Units Issuance On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Classification Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto. Measurement Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Accordingly, prior to the deconsolidation of Altus on February 22, 2022, the Company recorded a net loss attributable to Altus Preferred Unit limited partners totaling $70 million and net income attributable to Altus Preferred Unit limited partners totaling $162 million during 2022 and 2021, respectively. Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization and subsequent activity, Apache recorded various intercompany activities during the quarter ended March 31, 2021 as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail. Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache. Net Income (Loss) per Common Share Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly owned subsidiary of APA. Stock Compensation Plans Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting. 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, 2023, 9.4 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 APA’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, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In millions) Stock-settled and cash-settled compensation expensed: Lease operating expenses $ 27 $ 82 $ 39 Exploration 4 13 5 General and administrative 50 193 108 Total stock-settled and cash-settled compensation expensed 81 288 152 Stock-settled and cash-settled compensation capitalized 13 43 18 Total stock-settled and cash-settled compensation costs $ 94 $ 331 $ 170 Stock Options As of December 31, 2023, APA had outstanding options to purchase shares of APA’s 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, 2023, 2022, and 2021: 2023 2022 2021 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 2,078 $ 57.71 3,012 $ 63.79 3,537 $ 72.10 Exercised (12) 42.38 (99) 42.09 — — Forfeited — — (2) 49.10 — — Expired (601) 80.53 (833) 81.56 (525) 119.83 Outstanding, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 Expected to vest — — — — — — Exercisable, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 (1) As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000. During the years ended December 31, 2023, 2022, and 2021, there were no options issued and 12,183, 98,646, and no options, respectively, exercised. Restricted Stock Units and Restricted Stock Phantom Units Prior to consummation of the Holding Company Reorganization, the Company had 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 APA’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, 2023, 2022, and 2021, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $70 million, $145 million, and $91 million, respectively. As of December 31, 2023, 2022, and 2021, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $11 million, $22 million, and $15 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021: 2023 2022 2021 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 1,885 $ 23.08 2,073 $ 19.98 1,552 $ 28.43 Granted 661 41.60 847 29.90 1,506 16.46 Vested (3) (975) 23.31 (978) 22.39 (857) 29.13 Forfeited (69) 32.44 (57) 23.49 (128) 19.78 Expired (22) 27.81 — — — — Non-vested, end of year (1)(2) 1,480 30.69 1,885 23.08 2,073 19.98 (1) As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units. (2) As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years. (3) The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 5,709 6,402 4,423 Adjustment from ALTM transaction (1) — 143 — Granted (2) 1,972 2,568 4,441 Vested (2,851) (2,970) (2,049) Forfeited (340) (434) (413) Expired (12) — — Non-vested, end of year (3) 4,478 5,709 6,402 (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 2023, 2022, and 2021 included 1,972,116, 2,512,602, and 4,375,546 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 and 2021 included 55,546 and 65,327 awards, respectively, 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, 2023 was approximately $54 million. In January 2024, APA awarded 819,836 restricted stock units and 2,356,255 restricted stock phantom units based on APA’s weighted-average per-share market price of $33.73 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 $28 million and $80 million, respectively, and was calculated based on the per-share fair market value of a share of APA’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, APA 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, 2023, are as described below: • In January 2020, APA’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 999,896 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 155 percent of target. • In January 2021, APA’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 1,803,083 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 118 percent of target. • In January 2022, APA’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. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 1,040,100 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 2,080,200 units could be awarded. • In January 2023, APA’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 784,977 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 1,569,954 units could be awarded. Compensation expense related to the conditional cash-settled awards is 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 expenses of $2 million, $136 million, and $56 million during 2023, 2022, and 2021, respectively. Capitalized compensation costs under the cash-settled performance programs were expenses of approximately $100 thousand, $21 million, and $3 million during 2023, 2022, and 2021, respectively. The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 4,835 4,531 3,417 Granted 1,536 1,676 1,782 Vested (1,593) (656) (76) Forfeited (99) (106) (240) Expired (50) (610) (352) Non-vested, end of year (1) 4,629 4,835 4,531 (1) As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million. In January 2024, APA’s Board of Directors approved the 2024 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 2024 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 644,399 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,288,798 units. These phantom units represent a hypothetical interest in APA’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 APA’s common stock, a Level 1 fair value measurement. The cash incentives totaled $14 million, with the ultimate payout ranging from zero to $28 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 (LOSS)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME Components of accumulated other comprehensive income include the following: As of December 31, 2023 2022 2021 (In millions) Pension and postretirement benefit plan ( Note 13 ) $ 15 $ 14 $ 22 Accumulated other comprehensive income $ 15 $ 14 $ 22

MAJOR CUSTOMERS

MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2023
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 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. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs revenues. Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
BUSINESS SEGMENT INFORMATION	BUSINESS SEGMENT INFORMATION As of December 31, 2023, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below: Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2023 Oil revenues $ 2,683 $ 1,073 $ 2,003 $ — $ — $ 5,759 Natural gas revenues 346 237 277 — — 860 Natural gas liquids revenues — 28 432 — — 460 Oil, natural gas, and natural gas liquids production revenues 3,029 1,338 2,712 — — 7,079 Purchased oil and gas sales — — 894 — — 894 3,029 1,338 3,606 — — 7,973 Operating Expenses: Lease operating expenses 474 369 554 — — 1,397 Gathering, processing, and transmission 33 52 229 — — 314 Purchased oil and gas costs — — 742 — — 742 Taxes other than income — — 192 — — 192 Exploration 119 19 14 — 1 153 Depreciation, depletion, and amortization 524 271 604 — — 1,399 Asset retirement obligation accretion — 76 40 — — 116 Impairments — 50 11 — — 61 1,150 837 2,386 — 1 4,374 Operating Income (Loss) $ 1,879 $ 501 $ 1,220 $ — $ (1) 3,599 Other Income (Expense): Gain on divestitures, net 8 Losses on previously sold Gulf of Mexico properties (212) Other 26 General and administrative (325) Transaction, reorganization, and separation (15) Financing costs, net (165) Income Before Income Taxes $ 2,916 Total Assets (3) $ 3,503 $ 1,970 $ 11,471 $ — $ — $ 16,944 Net Property and Equipment $ 2,209 $ 1,628 $ 4,887 $ — $ — $ 8,724 Additions to Net Property and Equipment $ 834 $ 131 $ 946 $ — $ — $ 1,911 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2022 Oil revenues $ 3,145 $ 1,232 $ 2,323 $ — $ — $ 6,700 Natural gas revenues 370 281 894 — — 1,545 Natural gas liquids revenues 6 45 735 — (3) 783 Oil, natural gas, and natural gas liquids production revenues 3,521 1,558 3,952 — (3) 9,028 Purchased oil and gas sales — — 1,850 5 — 1,855 Midstream service affiliate revenues — — — 16 (16) — 3,521 1,558 5,802 21 (19) 10,883 Operating Expenses: Lease operating expenses 526 404 506 — (1) 1,435 Gathering, processing, and transmission 22 43 304 5 (18) 356 Purchased oil and gas costs — — 1,776 — — 1,776 Taxes other than income — — 253 3 — 256 Exploration 84 35 24 — 3 146 Depreciation, depletion, and amortization 400 238 537 2 — 1,177 Asset retirement obligation accretion — 82 34 1 — 117 1,032 802 3,434 11 (16) 5,263 Operating Income (Loss) $ 2,489 $ 756 $ 2,368 $ 10 $ (3) 5,620 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of Mexico properties (157) Derivative instrument losses, net (107) Other 139 General and administrative (462) Transaction, reorganization, and separation (26) Financing costs, net (313) Income Before Income Taxes $ 5,874 Total Assets (3) $ 3,148 $ 1,911 $ 9,196 $ — $ — $ 14,255 Net Property and Equipment $ 1,976 $ 1,386 $ 4,595 $ — $ — $ 7,957 Additions to Net Property and Equipment $ 695 $ 210 $ 752 $ — $ — $ 1,657 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2021 Oil revenues $ 1,806 $ 929 $ 1,850 $ — $ — $ 4,585 Natural gas revenues 270 183 754 — — 1,207 Natural gas liquids revenues 9 24 676 — (3) 706 Oil, natural gas, and natural gas liquids production revenues 2,085 1,136 3,280 — (3) 6,498 Purchased oil and gas sales — — 1,476 11 — 1,487 Midstream service affiliate revenues — — — 127 (127) — 2,085 1,136 4,756 138 (130) 7,985 Operating Expenses: Lease operating expenses 469 383 391 — (2) 1,241 Gathering, processing, and transmission 12 39 309 32 (128) 264 Purchased oil and gas costs — — 1,575 5 — 1,580 Taxes other than income — — 190 14 — 204 Exploration 63 34 28 — 2 127 Depreciation, depletion, and amortization 524 270 554 12 — 1,360 Asset retirement obligation accretion — 79 30 4 — 113 Impairments 26 22 — 160 — 208 1,094 827 3,077 227 (128) 5,097 Operating Income (Loss) $ 991 $ 309 $ 1,679 $ (89) $ (2) 2,888 Other Income (Expense): Gain on divestitures, net 67 Losses on previously sold Gulf of Mexico properties (446) Derivative instrument gains, net 94 Other 228 General and administrative (357) Transaction, reorganization, and separation (22) Financing costs, net (472) Income Before Income Taxes $ 1,980 Total Assets (3) $ 2,796 $ 2,199 $ 7,700 $ 1,698 $ — $ 14,393 Net Property and Equipment $ 1,720 $ 1,646 $ 4,507 $ 187 $ — $ 8,060 Additions to Net Property and Equipment $ 319 $ 159 $ 523 $ 3 $ — $ 1,004 (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, 2023, 2022, and 2021 of: For the Year Ended December 31, 2023 2022 2021 (In millions) Oil $ 729 $ 989 $ 420 Natural gas 95 117 47 Natural gas liquids — 2 2 (2) Includes noncontrolling interests in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the years 2022 and 2021. (3) Intercompany balances are excluded from total assets.

SUPPLEMENTAL OIL AND GAS DISCLO

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)	12 Months Ended
	Dec. 31, 2023
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. Apache 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) 2023 Oil and gas production revenues $ 2,712 $ 3,029 $ 1,338 $ — $ 7,079 Operating cost: Depreciation, depletion, and amortization (2) 568 521 270 — 1,359 Asset retirement obligation accretion 40 — 76 — 116 Lease operating expenses 554 474 369 — 1,397 Gathering, processing, and transmission 229 33 52 — 314 Exploration expenses 14 119 19 1 153 Production taxes (3) 189 — — — 189 Income tax 235 828 414 — 1,477 1,829 1,975 1,200 1 5,005 Results of operations $ 883 $ 1,054 $ 138 $ (1) $ 2,074 2022 Oil and gas production revenues $ 3,952 $ 3,521 $ 1,558 $ — $ 9,031 Operating cost: Depreciation, depletion, and amortization (2) 508 390 232 — 1,130 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 506 526 404 — 1,436 Gathering, processing, and transmission 304 22 43 — 369 Exploration expenses 24 84 35 3 146 Production taxes (3) 252 — — — 252 Income tax 488 1,100 495 — 2,083 2,116 2,122 1,291 3 5,532 Results of operations $ 1,836 $ 1,399 $ 267 $ (3) $ 3,499 2021 Oil and gas production revenues $ 3,280 $ 2,085 $ 1,136 $ — $ 6,501 Operating cost: Depreciation, depletion, and amortization (2) 511 477 267 — 1,255 Asset retirement obligation accretion 30 — 79 — 109 Lease operating expenses 391 469 383 — 1,243 Gathering, processing, and transmission 309 12 39 — 360 Exploration expenses 28 63 34 2 127 Production taxes (3) 188 — — — 188 Income tax 383 479 134 — 996 1,840 1,500 936 2 4,278 Results of operations $ 1,440 $ 585 $ 200 $ (2) $ 2,223 (1) Includes noncontrolling interests 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 18—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 18—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) 2023 Acquisitions: Proved $ — $ 4 $ — $ — $ 4 Unproved 19 — — — 19 Exploration 5 226 44 1 276 Development 864 646 468 — 1,978 Costs incurred (1) $ 888 $ 876 $ 512 $ 1 $ 2,277 (1) Includes asset retirement costs: Asset retirement costs $ (7) $ — $ 375 $ — $ 368 2022 Acquisitions: Proved $ 19 $ 3 $ — $ — $ 22 Unproved 28 — — — 28 Exploration 4 169 61 3 237 Development 775 568 (57) — 1,286 Costs incurred (1) $ 826 $ 740 $ 4 $ 3 $ 1,573 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ — $ — $ 1 $ — $ 1 Asset retirement costs 76 — (215) — (139) 2021 Acquisitions: Proved $ — $ (157) $ — $ — $ (157) Unproved 9 20 — — 29 Exploration 6 86 39 30 161 Development 545 404 135 1 1,085 Costs incurred (1) $ 560 $ 353 $ 174 $ 31 $ 1,118 (1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ — $ — $ — Asset retirement costs 130 — 19 — 149 Egypt PSC modernization impacts – Proved and Unproved — (145) — — (145) (2) Includes noncontrolling interests in Egypt. In 2021, in connection with Apache’s agreement to enter into a new merged concession agreement with EGPC, the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments. 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) 2023 Proved properties $ 19,809 $ 13,777 $ 9,472 $ — $ 43,058 Unproved properties 217 71 3 — 291 20,026 13,848 9,475 — 43,349 Accumulated DD&A (15,390) (11,678) (7,849) — (34,917) $ 4,636 $ 2,170 $ 1,626 $ — $ 8,432 2022 Proved properties $ 18,990 $ 13,014 $ 8,945 $ — $ 40,949 Unproved properties 208 77 11 — 296 19,198 13,091 8,956 — 41,245 Accumulated DD&A (14,846) (11,157) (7,573) — (33,576) $ 4,352 $ 1,934 $ 1,383 $ — $ 7,669 (1) 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, Apache 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. Apache 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 Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2020 206,936 95,981 86,566 389,483 December 31, 2021 180,968 106,646 77,073 364,687 December 31, 2022 168,817 108,050 82,580 359,447 December 31, 2023 167,911 102,305 61,076 331,292 Proved undeveloped reserves: December 31, 2020 25,516 11,228 7,273 44,017 December 31, 2021 18,168 11,003 5,757 34,928 December 31, 2022 16,221 8,557 2,873 27,651 December 31, 2023 29,012 5,254 — 34,266 Total proved reserves: Balance December 31, 2020 232,452 107,209 93,839 433,500 Extensions, discoveries and other additions 17,869 13,390 2,288 33,547 Purchases of minerals in-place 126 — — 126 Revisions of previous estimates (4,479) 22,727 (60) 18,188 Production (27,450) (25,677) (13,237) (66,364) Sales of minerals in-place (19,382) — — (19,382) 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 522 — — 522 Revisions of previous estimates 7,170 22,433 11,898 41,501 Production (24,141) (31,055) (11,891) (67,087) Sales of minerals in-place (7,425) — — (7,425) Balance December 31, 2022 185,038 116,607 85,453 387,098 Extensions, discoveries and other additions 37,353 12,979 301 50,633 Revisions of previous estimates 1,062 10,505 (12,002) (435) Production (25,755) (32,532) (12,676) (70,963) Sales of minerals in-place (775) — — (775) Balance December 31, 2023 196,923 107,559 61,076 365,558 (1) Includes proved reserves of 53 MMbbls, 62 MMbbls, 39 MMbbls, and 36 MMbbls as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2020 150,599 716 2,053 153,368 December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 152,999 — 2,230 155,229 December 31, 2023 145,618 — 1,460 147,078 Proved undeveloped reserves: December 31, 2020 15,141 126 320 15,587 December 31, 2021 16,380 30 275 16,685 December 31, 2022 15,398 — 76 15,474 December 31, 2023 16,413 — — 16,413 Total proved reserves: Balance December 31, 2020 165,740 842 2,373 168,955 Extensions, discoveries and other additions 21,055 7 81 21,143 Purchases of minerals in-place 191 — — 191 Revisions of previous estimates 22,724 (180) 318 22,862 Production (24,175) (193) (438) (24,806) Sales of minerals in-place (4,983) — — (4,983) 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 233 — — 233 Revisions of previous estimates 10,355 (407) 333 10,281 Production (21,859) (69) (406) (22,334) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 168,397 — 2,306 170,703 Extensions, discoveries and other additions 20,827 — 371 21,198 Revisions of previous estimates (6,343) — (764) (7,107) Production (20,817) — (453) (21,270) Sales of minerals in-place (33) — — (33) Balance December 31, 2023 162,031 — 1,460 163,491 (1) Includes proved reserves of 159 Mbbls and 281 Mbbls as of December 31, 2021 and 2020, respectively, attributable to noncontrolling interests in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2020 1,052,756 409,035 68,159 1,529,950 December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,128,066 399,502 66,292 1,593,860 December 31, 2023 953,578 377,144 46,839 1,377,561 Proved undeveloped reserves: December 31, 2020 76,504 12,572 8,341 97,417 December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 188,976 1,068 2,304 192,348 December 31, 2023 86,800 2,612 — 89,412 Total proved reserves: Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 Extensions, discoveries and other additions 227,684 50,209 3,684 281,577 Purchases of minerals in-place 839 — — 839 Revisions of previous estimates 279,610 99,143 17,171 395,924 Production (192,523) (96,234) (14,076) (302,833) Sales of minerals in-place (22,968) — — (22,968) 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 1,592 — — 1,592 Revisions of previous estimates 96,381 45,725 (3,431) 138,675 Production (167,580) (130,071) (12,895) (310,546) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,317,042 400,570 68,596 1,786,208 Extensions, discoveries and other additions 125,654 14,188 3,335 143,177 Revisions of previous estimates (249,257) 83,907 (6,739) (172,089) Production (152,925) (118,909) (18,353) (290,187) Sales of minerals in-place (136) — — (136) Balance December 31, 2023 1,040,378 379,756 46,839 1,466,973 (1) Includes proved reserves of 188 Bcf, 224 Bcf, 158 Bcf, and 141 Bcf as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2020 532,994 164,870 99,979 797,843 December 31, 2021 551,384 184,563 91,825 827,772 December 31, 2022 509,827 174,633 95,859 780,319 December 31, 2023 472,459 165,162 70,343 707,964 Proved undeveloped reserves: December 31, 2020 53,408 13,449 8,983 75,840 December 31, 2021 65,288 12,683 7,219 85,190 December 31, 2022 63,115 8,735 3,333 75,183 December 31, 2023 59,891 5,690 — 65,581 Total proved reserves: Balance December 31, 2020 586,402 178,319 108,962 873,683 Extensions, discoveries and other additions 76,871 21,765 2,983 101,619 Purchases of minerals in-place 457 — — 457 Revisions of previous estimates 64,847 39,071 3,120 107,038 Production (83,712) (41,909) (16,021) (141,642) Sales of minerals in-place (28,193) — — (28,193) 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 1,020 — — 1,020 Revisions of previous estimates 33,588 29,647 11,659 74,894 Production (73,930) (52,803) (14,446) (141,179) Sales of minerals in-place (26,000) — — (26,000) Balance December 31, 2022 572,942 183,368 99,192 855,502 Extensions, discoveries and other additions 79,123 15,344 1,228 95,695 Revisions of previous estimates (46,824) 24,490 (13,889) (36,223) Production (72,060) (52,350) (16,188) (140,598) Sales of minerals in-place (831) — — (831) Balance December 31, 2023 532,350 170,852 70,343 773,545 (1) Includes total proved reserves of 84 MMboe, 99 MMboe, 66 MMboe, and 59 MMboe as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. During 2023, the Company added approximately 96 MMboe from extensions, discoveries, and other additions. The Company recorded 79 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 10 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 36 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, offset by engineering and performance upward revisions of 47 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 1 MMboe of proved reserves and sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets. During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the new merged concession agreement in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets. The impact of the consolidated PSC to proved reserves based on the modernized terms was an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. As of December 31, 2021, approximately 96 percent of the Company’s Egypt reserves were consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt. Approximately 10 percent of the Company’s year-end 2023 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 18, under “Future Net Cash Flows.” Future Net Cash Flows Future cash inflows as of December 31, 2023, 2022, and 2021 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, 2023, 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 Total (1) (In millions) 2023 Cash inflows $ 20,063 $ 9,921 $ 5,761 $ 35,745 Production costs (7,861) (1,690) (2,773) (12,324) Development costs (2,182) (1,235) (2,461) (5,878) Income tax expense (936) (2,222) (946) (4,104) Net cash flows 9,084 4,774 (419) 13,439 10 percent discount rate (3,534) (943) 476 (4,001) Discounted future net cash flows (2) $ 5,550 $ 3,831 $ 57 $ 9,438 2022 Cash inflows $ 29,490 $ 12,819 $ 10,147 $ 52,456 Production costs (10,221) (2,086) (3,241) (15,548) Development costs (1,598) (1,471) (2,297) (5,366) Income tax expense (1,389) (2,729) (2,631) (6,749) Net cash flows 16,282 6,533 1,978 24,793 10 percent discount rate (6,422) (1,400) (204) (8,026) Discounted future net cash flows (2) $ 9,860 $ 5,133 $ 1,774 $ 16,767 2021 Cash inflows $ 22,852 $ 9,337 $ 6,832 $ 39,021 Production costs (8,323) (1,712) (2,343) (12,378) Development costs (1,632) (1,402) (2,533) (5,567) Income tax expense (134) (1,887) (768) (2,789) Net cash flows 12,763 4,336 1,188 18,287 10 percent discount rate (5,294) (983) 350 (5,927) Discounted future net cash flows (2) $ 7,469 $ 3,353 $ 1,538 $ 12,360 (1) Includes discounted future net cash flows of approximately $1.8 billion , $2.5 billion, and $1.6 billion as of December 31, 2023, 2022, and 2021, respectively, attributable to noncontrolling interests in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $13.0 billion , $21.7 billion, and $14.9 billion as of December 31, 2023, 2022, and 2021, respectively. The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2023 2022 2021 (In millions) Sales, net of production costs $ (5,176) $ (6,970) $ (4,707) Net change in prices and production costs (6,699) 8,627 9,376 Discoveries and improved recovery, net of related costs 1,633 1,132 1,749 Change in future development costs (415) (347) (839) Previously estimated development costs incurred during the period 707 669 545 Revision of quantities (127) 2,621 1,983 Purchases of minerals in-place — 17 1 Accretion of discount 2,167 1,489 626 Change in income taxes 1,374 (2,371) (1,583) Sales of minerals in-place (18) (363) (116) Change in production rates and other (775) (97) 13 $ (7,329) $ 4,407 $ 7,048

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income attributable to Apache Corporation	$ 2,526	$ 3,536	$ 1,062

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
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

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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. Noncontrolling interests represent outside ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. In conjunction with the ratification of a merged concession agreement with the Egyptian General Petroleum Corporation (EGPC) in December 2021, Apache modified partnership agreements for certain consolidated subsidiaries. Apache subsequently determined that one of its limited partnership subsidiaries, which has control over Apache’s Egyptian operations, qualified as a variable interest entity (VIE) under GAAP. Apache continues to consolidate this limited partnership subsidiary because the Company has concluded that it has a controlling financial interest in the Egyptian operations and was determined to be the primary beneficiary of the VIE. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a noncontrolling interest participation in the remaining two-thirds of its consolidated Egypt oil and gas business. Refer to Note 2—Transactions with Parent Affiliate for detail regarding APA’s noncontrolling interest. All noncontrolling interests are reflected as a separate component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination (as defined below), third-party investors owned a minority interest of approximately 21 percent of Altus, which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which Apache consolidated because a wholly owned subsidiary of Apache had a controlling financial interest and was determined to be the primary beneficiary. 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 3—Acquisitions and Divestitures for further detail. During each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. As a result, the Company is considered to have had significant influence over Kinetik for all periods presented and will continue to have such influence until such time as Kinetik appoints a replacement for the Company’s designated director, given that the Company’s current beneficial ownership percentage in Kinetik no longer entitles it to designate a director to the Kinetik board. 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 7—Equity Method Interests for further detail.
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 3—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 11—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 12—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 19—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 Upstream The Company’s upstream 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 Apache-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. The Company’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 18—Business Segment Information for a disaggregation of revenue by product and reporting segment. Altus Midstream Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which were fully eliminated upon consolidation. 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 $1.4 billion and $1.3 billion as of December 31, 2023 and 2022, 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. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the EGPC for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. 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
Receivable from / Payable to APA	Receivable from / Payable to APA
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. During 2023, the Company recorded $50 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.
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 unproved properties: For the Year Ended December 31, 2023 2022 2021 (In millions) Unproved properties: U.S. $ 10 $ 20 $ 22 Egypt — 4 8 North Sea 11 — 1 Total unproved properties $ 21 $ 24 $ 31 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. For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of proved properties.
Gathering, Processing, and Transmission (GPT) Facilities	Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $448 million and $449 million at December 31, 2023 and 2022, respectively, with accumulated depreciation for these assets totaling $373 million and $367 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 Apache-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, 2023, 2022, and 2021, 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 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	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 7—Equity Method Interests for further details of the Company’s equity method interests.
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 Apache 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.
Stock-Based Compensation	Stock-Based Compensation Prior to consummation of the Holding Company Reorganization, Apache granted 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 APA’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, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock .
New Pronouncements Issued But Not Yet Adopted	New Pronouncements Issued But Not Yet Adopted In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, “Segment Reporting (Topic 280),” which expands disclosures about a public entity’s reportable segments and requires more enhanced information about a reportable segment’s expenses, interim segment profit or loss, and how a public entity’s chief operating decision maker uses reported segment profit or loss information in assessing segment performance and allocating resources. The amendments do not change or remove existing disclosure requirements or how a public entity identifies its operating segments, aggregates those operating segments, or applies the quantitative thresholds to determine its reportable segments. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted, and the amendments are required to be applied on a retrospective basis. The Company is currently assessing the impact of adopting this standard and does not believe this will have a material impact on its financial statements. 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. Retrospective application is also permitted. 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, 2023
Accounting Policies [Abstract]
Schedule of Allowance for Doubtful Accounts	The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2023 2022 2021 (In millions) Allowance for credit loss at beginning of year $ 117 $ 109 $ 95 Additional provisions for the year 16 9 19 Uncollectible accounts written off, net of recoveries (19) (1) (5) Allowance for credit loss at end of year $ 114 $ 117 $ 109
Schedule of Non-cash Impairments of Proved and Unproved Properties	The following table represents non-cash impairment charges of the carrying value of the Company’s unproved properties: For the Year Ended December 31, 2023 2022 2021 (In millions) Unproved properties: U.S. $ 10 $ 20 $ 22 Egypt — 4 8 North Sea 11 — 1 Total unproved properties $ 21 $ 24 $ 31

CAPITALIZED EXPLORATORY WELL _2

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023, 2022, and 2021. 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, 2023 2022 2021 (In millions) Capitalized well costs at beginning of year $ 50 $ 46 $ 197 Additions pending determination of proved reserves 150 138 62 Divestitures and other — — (163) Reclassifications to proved properties (135) (110) (40) Charged to exploration expense (18) (24) (10) Capitalized well costs at end of year $ 47 $ 50 $ 46
Schedule of Aging of Capitalized Exploratory Well Costs	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: 2023 2022 2021 (In millions) Exploratory well costs capitalized for a period of one year or less $ 38 $ 34 $ 13 Exploratory well costs capitalized for a period greater than one year 9 16 33 Capitalized well costs at end of year $ 47 $ 50 $ 46 Number of projects with exploratory well costs capitalized for a period greater than one year 8 10 9
Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year	The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2023, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2022 2021 2020 and Prior (In millions) Egypt $ 9 $ — $ — $ 9 $ 9 $ — $ — $ 9

DERIVATIVE INSTRUMENTS AND HE_2

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations	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, 2023 2022 2021 (In millions) Realized: Commodity derivative instruments $ — $ (72) $ 25 Foreign currency derivative instruments — (13) — Realized gains (losses), net — (85) 25 Unrealized: Commodity derivative instruments — 9 (20) Pipeline capacity embedded derivatives — — 7 Preferred Units embedded derivative — (31) 82 Unrealized gains (losses), net — (22) 69 Derivative instrument gains (losses), net $ — $ (107) $ 94

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 (In millions) Inventories $ 439 $ 425 Drilling advances 68 64 Prepaid assets and other 40 54 Current decommissioning security for sold Gulf of Mexico assets 178 450 Total Other current assets $ 725 $ 993

EQUITY METHOD INTERESTS (Tables

EQUITY METHOD INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Method Investment Information	The following table represents related party sales and costs associated with Kinetik: For the Year Ended December 31, 2023 2022 (In millions) Natural gas and NGLs sales $ 64 $ 8 Purchased oil and gas sales 29 — $ 93 $ 8 Gathering, processing, and transmission costs $ 99 $ 91 Purchased oil and gas costs 80 — Lease operating expenses 7 — $ 186 $ 91

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 (In millions) Accrued operating expenses $ 158 $ 139 Accrued exploration and development 307 300 Accrued compensation and benefits 390 514 Accrued interest 92 96 Accrued income taxes 138 90 Current asset retirement obligation 76 55 Current operating lease liability 115 167 Current decommissioning contingency for sold Gulf of Mexico properties 60 450 Other 333 238 Total Other current liabilities $ 1,669 $ 2,049

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligation	The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2023 and 2022: For the Year Ended December 31, 2023 2022 (In millions) Asset retirement obligation at beginning of the year $ 1,991 $ 2,130 Liabilities incurred 12 4 Liabilities divested — (73) Liabilities settled (45) (39) Accretion expense 116 117 Revisions in estimated liabilities 356 (148) Asset retirement obligation at end of the year 2,430 1,991 Less current portion (76) (55) Asset retirement obligation, long-term $ 2,354 $ 1,936

DEBT AND FINANCING COSTS (Table

DEBT AND FINANCING COSTS (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the carrying value of the Company’s debt as of December 31, 2023 and 2022: December 31, 2023 2022 (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% 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) 516 579 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) 211 221 7.375% debentures due 2047 150 150 5.35% notes due 2049 (1) 387 387 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (3) 4,835 4,908 Finance lease obligations 32 34 Unamortized discount (26) (27) Debt issuance costs (25) (28) Total debt 4,816 4,887 Current maturities (2) (2) Long-term debt $ 4,814 $ 4,885 (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)
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, 2023 are as follows: (In millions) 2024 $ — 2025 51 2026 210 2027 108 2028 325 Thereafter 4,141 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, 2023 2022 2021 (In millions) Interest expense $ 291 $ 312 $ 419 Amortization of debt issuance costs 2 7 8 Capitalized interest — (1) — Loss (gain) on extinguishment of debt (9) 67 104 Interest income (10) (9) (8) Interest income from APA Corporation, net (109) (63) (51) Financing costs, net $ 165 $ 313 $ 472

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Income Before Income Taxes	Net income before income taxes was composed of the following: For the Year Ended December 31, 2023 2022 2021 (In millions) U.S. $ 594 $ 2,656 $ 689 Foreign 2,322 3,218 1,291 Total $ 2,916 $ 5,874 $ 1,980
Schedule of Total Provision (Benefit) for Income Taxes	The total income tax provision (benefit) consisted of the following: For the Year Ended December 31, 2023 2022 2021 (In millions) Current income taxes: Federal $ 2 $ 1 $ 16 State 6 11 — Foreign 1,330 1,495 636 1,338 1,507 652 Deferred income taxes: Federal (1,696) — — State (34) — — Foreign 78 145 (74) (1,652) 145 (74) Total $ (314) $ 1,652 $ 578
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, 2023 2022 2021 (In millions) Income tax expense at U.S. statutory rate $ 612 $ 1,234 $ 416 State income tax, less federal effect (1) (25) 9 — Taxes related to foreign operations 753 774 300 Tax credits — (4) (10) Net change in tax contingencies 5 1 16 Valuation allowances (1) (1,838) (705) (111) Tax adjustments attributable to BCP Business Combination — 126 — Remeasurement of U.K. deferred tax liability 174 208 — Tax attributable to Altus Preferred Unit limited partners — — (34) All other, net 5 9 1 $ (314) $ 1,652 $ 578 (1) The change in state valuation allowance is included as a component of state income tax.
Schedule of Net Deferred Tax Liability	The net deferred income tax (asset) liability consisted of the following as of December 31: 2023 2022 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,027 $ 2,035 Capital losses 8 357 Tax credits and other tax incentives 26 26 Foreign tax credits 2,204 2,241 Accrued expenses and liabilities 130 145 Asset retirement obligation 849 672 Equity investments 8 — Net interest expense limitation 74 55 Lease liability 71 113 Decommissioning contingency for sold Gulf of Mexico properties 210 275 Total deferred tax assets 5,607 5,919 Valuation allowance (2,549) (4,831) Net deferred tax assets 3,058 1,088 Deferred tax liabilities: Equity investments — 1 Property and equipment 1,510 1,014 Right-of-use asset 69 110 Decommissioning security for sold Gulf of Mexico properties 44 148 Other 59 90 Total deferred tax liabilities 1,682 1,363 Net deferred income tax (asset) liability $ (1,376) $ 275 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2023 2022 (In millions) Assets: Other assets Deferred tax asset $ 1,747 $ 39 Liabilities: Deferred credits and other noncurrent liabilities Deferred tax liability 371 314 Net deferred income tax (asset) liability $ (1,376) $ 275
Summary of Valuation Allowance	In 2023, 2022, and 2021, the Company’s valuation allowance decreased by $2.3 billion, $1.0 billion, and $116 million, respectively, as detailed in the table below: 2023 2022 2021 (In millions) Balance at beginning of year $ 4,831 $ 5,875 $ 5,991 State (1) (61) (111) 1 U.S. (2,221) (706) (112) Foreign — (227) (5) Balance at end of year $ 2,549 $ 4,831 $ 5,875 (1) Reported as a component of state income taxes.
Schedule of Net Operating Losses	On December 31, 2023, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 7,922 2027 - Indefinite State 6,541 Various
Schedule of Foreign Tax Credit Carryforward	On December 31, 2023, 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: 2023 2022 2021 (In millions) Balance at beginning of year $ 89 $ 116 $ 93 Additions based on tax positions related to prior year 4 — 16 Additions based on tax positions related to the current year — — 7 Reductions for tax positions of prior years (8) (27) — Balance at end of year $ 85 $ 89 $ 116
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, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Lease Cost	The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2023: Operating Leases Finance Lease Weighted average remaining lease term 6.9 years 9.7 years Weighted average discount rate 5.3 % 4.4 %
Schedule of Operating Lease, Liability, Maturity	At December 31, 2023, 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) 2024 $ 115 $ 3 $ 250 2025 35 3 197 2026 21 4 766 2027 23 4 143 2028 22 4 141 Thereafter 129 23 208 Total future minimum payments 345 41 $ 1,705 Less: imputed interest (65) (9) N/A Total lease liabilities 280 32 N/A Current portion 115 2 N/A Non-current portion $ 165 $ 30 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 $182 million, $183 million, and $194 million in 2023, 2022, and 2021, respectively. (5)
Schedule of Finance Lease, Liability, Maturity	At December 31, 2023, 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) 2024 $ 115 $ 3 $ 250 2025 35 3 197 2026 21 4 766 2027 23 4 143 2028 22 4 141 Thereafter 129 23 208 Total future minimum payments 345 41 $ 1,705 Less: imputed interest (65) (9) N/A Total lease liabilities 280 32 N/A Current portion 115 2 N/A Non-current portion $ 165 $ 30 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 $182 million, $183 million, and $194 million in 2023, 2022, and 2021, respectively. (5)
Schedule of Long-term Purchase Commitment	At December 31, 2023, 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) 2024 $ 115 $ 3 $ 250 2025 35 3 197 2026 21 4 766 2027 23 4 143 2028 22 4 141 Thereafter 129 23 208 Total future minimum payments 345 41 $ 1,705 Less: imputed interest (65) (9) N/A Total lease liabilities 280 32 N/A Current portion 115 2 N/A Non-current portion $ 165 $ 30 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 $182 million, $183 million, and $194 million in 2023, 2022, and 2021, respectively. (5)

RETIREMENT AND DEFERRED COMPE_2

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023, 2022, and 2021, 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. 2023 2022 2021 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 108 $ 15 $ 211 $ 20 $ 233 $ 20 Service cost 1 1 2 1 3 1 Interest cost 5 1 3 — 3 — Foreign currency exchange rates 6 — (21) — (2) — Actuarial losses (gains) 3 — (79) (5) (5) 1 Plan settlements — — — — (17) — Benefits paid (5) (3) (8) (3) (4) (4) Retiree contributions — 1 — 2 — 2 Projected benefit obligation at end of year 118 15 108 15 211 20 Change in Plan Assets Fair value of plan assets at beginning of year 137 — 254 — 262 — Actual return (loss) on plan assets 8 — (87) — 11 — Foreign currency exchange rates 8 — (26) — (3) — Employer contributions 2 1 4 2 5 2 Plan settlements — — — — (17) — Benefits paid (5) (3) (8) (4) (4) (4) Retiree contributions — 2 — 2 — 2 Fair value of plan assets at end of year 150 — 137 — 254 — Funded status at end of year $ 32 $ (15) $ 29 $ (15) $ 43 $ (20) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 32 (13) 29 (13) 43 (18) $ 32 $ (15) $ 29 $ (15) $ 43 $ (20) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (12) $ 16 $ (10) $ 18 $ 1 $ 14 Weighted Average Assumptions used as of 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 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 2023 2022 Asset Category Global equities — % 6 % Multi-asset credit 59 % 40 % Nominal bonds 6 % 24 % Inflation-linked bonds 33 % 28 % Cash 2 % 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 tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2023 and 2022: December 31, 2023 2022 (In millions) Asset Category Global equities $ — $ 9 Multi-asset credit 88 55 Nominal bonds 9 32 Inflation-linked bonds 50 39 Cash 3 2 Total $ 150 $ 137
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, 2023, 2022, and 2021: 2023 2022 2021 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 1 $ 1 $ 2 $ 1 $ 3 $ 1 Interest cost 5 1 3 — 3 — Expected return on assets (7) — (4) — (4) — Amortization of loss — (2) — (1) — (1) Settlement loss — — — — — — Net periodic benefit cost $ (1) $ — $ 1 $ — $ 2 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 5.00 % 5.29 % 1.80 % 2.57 % 1.40 % 2.06 % Salary increases 4.70 % N/A 4.90 % N/A 4.50 % N/A Expected return on assets 4.70 % N/A 1.90 % N/A 1.50 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.00 % Ultimate in 2030 N/A 5.25 % N/A 5.00 % 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) 2024 $ 5 $ 2 2025 5 2 2026 5 1 2027 6 1 2028 6 1 Years 2029-2033 34 6

CAPITAL STOCK AND EQUITY (Table

CAPITAL STOCK AND EQUITY (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
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, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In millions) Stock-settled and cash-settled compensation expensed: Lease operating expenses $ 27 $ 82 $ 39 Exploration 4 13 5 General and administrative 50 193 108 Total stock-settled and cash-settled compensation expensed 81 288 152 Stock-settled and cash-settled compensation capitalized 13 43 18 Total stock-settled and cash-settled compensation costs $ 94 $ 331 $ 170
Schedule of Stock Options Activities	The following table summarizes stock option activity for the years ended December 31, 2023, 2022, and 2021: 2023 2022 2021 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 2,078 $ 57.71 3,012 $ 63.79 3,537 $ 72.10 Exercised (12) 42.38 (99) 42.09 — — Forfeited — — (2) 49.10 — — Expired (601) 80.53 (833) 81.56 (525) 119.83 Outstanding, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 Expected to vest — — — — — — Exercisable, end of year (1) 1,465 48.48 2,078 57.71 3,012 63.79 (1) As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000.
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, 2023, 2022, and 2021: 2023 2022 2021 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 1,885 $ 23.08 2,073 $ 19.98 1,552 $ 28.43 Granted 661 41.60 847 29.90 1,506 16.46 Vested (3) (975) 23.31 (978) 22.39 (857) 29.13 Forfeited (69) 32.44 (57) 23.49 (128) 19.78 Expired (22) 27.81 — — — — Non-vested, end of year (1)(2) 1,480 30.69 1,885 23.08 2,073 19.98 (1) As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units. (2) As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years. (3) The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 5,709 6,402 4,423 Adjustment from ALTM transaction (1) — 143 — Granted (2) 1,972 2,568 4,441 Vested (2,851) (2,970) (2,049) Forfeited (340) (434) (413) Expired (12) — — Non-vested, end of year (3) 4,478 5,709 6,402 (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 2023, 2022, and 2021 included 1,972,116, 2,512,602, and 4,375,546 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 and 2021 included 55,546 and 65,327 awards, respectively, 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, 2023 was approximately $54 million. The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021: For the Year Ended December 31, 2023 2022 2021 (In thousands) Non-vested, beginning of year 4,835 4,531 3,417 Granted 1,536 1,676 1,782 Vested (1,593) (656) (76) Forfeited (99) (106) (240) Expired (50) (610) (352) Non-vested, end of year (1) 4,629 4,835 4,531 (1) As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million.

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Schedule of Components of Accumulated Other Comprehensive Income (Loss)	Components of accumulated other comprehensive income include the following: As of December 31, 2023 2022 2021 (In millions) Pension and postretirement benefit plan ( Note 13 ) $ 15 $ 14 $ 22 Accumulated other comprehensive income $ 15 $ 14 $ 22

BUSINESS SEGMENT INFORMATION (T

BUSINESS SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Financial Segment Information	Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2023 Oil revenues $ 2,683 $ 1,073 $ 2,003 $ — $ — $ 5,759 Natural gas revenues 346 237 277 — — 860 Natural gas liquids revenues — 28 432 — — 460 Oil, natural gas, and natural gas liquids production revenues 3,029 1,338 2,712 — — 7,079 Purchased oil and gas sales — — 894 — — 894 3,029 1,338 3,606 — — 7,973 Operating Expenses: Lease operating expenses 474 369 554 — — 1,397 Gathering, processing, and transmission 33 52 229 — — 314 Purchased oil and gas costs — — 742 — — 742 Taxes other than income — — 192 — — 192 Exploration 119 19 14 — 1 153 Depreciation, depletion, and amortization 524 271 604 — — 1,399 Asset retirement obligation accretion — 76 40 — — 116 Impairments — 50 11 — — 61 1,150 837 2,386 — 1 4,374 Operating Income (Loss) $ 1,879 $ 501 $ 1,220 $ — $ (1) 3,599 Other Income (Expense): Gain on divestitures, net 8 Losses on previously sold Gulf of Mexico properties (212) Other 26 General and administrative (325) Transaction, reorganization, and separation (15) Financing costs, net (165) Income Before Income Taxes $ 2,916 Total Assets (3) $ 3,503 $ 1,970 $ 11,471 $ — $ — $ 16,944 Net Property and Equipment $ 2,209 $ 1,628 $ 4,887 $ — $ — $ 8,724 Additions to Net Property and Equipment $ 834 $ 131 $ 946 $ — $ — $ 1,911 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2022 Oil revenues $ 3,145 $ 1,232 $ 2,323 $ — $ — $ 6,700 Natural gas revenues 370 281 894 — — 1,545 Natural gas liquids revenues 6 45 735 — (3) 783 Oil, natural gas, and natural gas liquids production revenues 3,521 1,558 3,952 — (3) 9,028 Purchased oil and gas sales — — 1,850 5 — 1,855 Midstream service affiliate revenues — — — 16 (16) — 3,521 1,558 5,802 21 (19) 10,883 Operating Expenses: Lease operating expenses 526 404 506 — (1) 1,435 Gathering, processing, and transmission 22 43 304 5 (18) 356 Purchased oil and gas costs — — 1,776 — — 1,776 Taxes other than income — — 253 3 — 256 Exploration 84 35 24 — 3 146 Depreciation, depletion, and amortization 400 238 537 2 — 1,177 Asset retirement obligation accretion — 82 34 1 — 117 1,032 802 3,434 11 (16) 5,263 Operating Income (Loss) $ 2,489 $ 756 $ 2,368 $ 10 $ (3) 5,620 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of Mexico properties (157) Derivative instrument losses, net (107) Other 139 General and administrative (462) Transaction, reorganization, and separation (26) Financing costs, net (313) Income Before Income Taxes $ 5,874 Total Assets (3) $ 3,148 $ 1,911 $ 9,196 $ — $ — $ 14,255 Net Property and Equipment $ 1,976 $ 1,386 $ 4,595 $ — $ — $ 7,957 Additions to Net Property and Equipment $ 695 $ 210 $ 752 $ — $ — $ 1,657 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2021 Oil revenues $ 1,806 $ 929 $ 1,850 $ — $ — $ 4,585 Natural gas revenues 270 183 754 — — 1,207 Natural gas liquids revenues 9 24 676 — (3) 706 Oil, natural gas, and natural gas liquids production revenues 2,085 1,136 3,280 — (3) 6,498 Purchased oil and gas sales — — 1,476 11 — 1,487 Midstream service affiliate revenues — — — 127 (127) — 2,085 1,136 4,756 138 (130) 7,985 Operating Expenses: Lease operating expenses 469 383 391 — (2) 1,241 Gathering, processing, and transmission 12 39 309 32 (128) 264 Purchased oil and gas costs — — 1,575 5 — 1,580 Taxes other than income — — 190 14 — 204 Exploration 63 34 28 — 2 127 Depreciation, depletion, and amortization 524 270 554 12 — 1,360 Asset retirement obligation accretion — 79 30 4 — 113 Impairments 26 22 — 160 — 208 1,094 827 3,077 227 (128) 5,097 Operating Income (Loss) $ 991 $ 309 $ 1,679 $ (89) $ (2) 2,888 Other Income (Expense): Gain on divestitures, net 67 Losses on previously sold Gulf of Mexico properties (446) Derivative instrument gains, net 94 Other 228 General and administrative (357) Transaction, reorganization, and separation (22) Financing costs, net (472) Income Before Income Taxes $ 1,980 Total Assets (3) $ 2,796 $ 2,199 $ 7,700 $ 1,698 $ — $ 14,393 Net Property and Equipment $ 1,720 $ 1,646 $ 4,507 $ 187 $ — $ 8,060 Additions to Net Property and Equipment $ 319 $ 159 $ 523 $ 3 $ — $ 1,004 (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, 2023, 2022, and 2021 of: For the Year Ended December 31, 2023 2022 2021 (In millions) Oil $ 729 $ 989 $ 420 Natural gas 95 117 47 Natural gas liquids — 2 2 (2) Includes noncontrolling interests in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the years 2022 and 2021. (3) Intercompany balances are excluded from total assets.

SUPPLEMENTAL OIL AND GAS DISC_2

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
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. Apache 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) 2023 Oil and gas production revenues $ 2,712 $ 3,029 $ 1,338 $ — $ 7,079 Operating cost: Depreciation, depletion, and amortization (2) 568 521 270 — 1,359 Asset retirement obligation accretion 40 — 76 — 116 Lease operating expenses 554 474 369 — 1,397 Gathering, processing, and transmission 229 33 52 — 314 Exploration expenses 14 119 19 1 153 Production taxes (3) 189 — — — 189 Income tax 235 828 414 — 1,477 1,829 1,975 1,200 1 5,005 Results of operations $ 883 $ 1,054 $ 138 $ (1) $ 2,074 2022 Oil and gas production revenues $ 3,952 $ 3,521 $ 1,558 $ — $ 9,031 Operating cost: Depreciation, depletion, and amortization (2) 508 390 232 — 1,130 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 506 526 404 — 1,436 Gathering, processing, and transmission 304 22 43 — 369 Exploration expenses 24 84 35 3 146 Production taxes (3) 252 — — — 252 Income tax 488 1,100 495 — 2,083 2,116 2,122 1,291 3 5,532 Results of operations $ 1,836 $ 1,399 $ 267 $ (3) $ 3,499 2021 Oil and gas production revenues $ 3,280 $ 2,085 $ 1,136 $ — $ 6,501 Operating cost: Depreciation, depletion, and amortization (2) 511 477 267 — 1,255 Asset retirement obligation accretion 30 — 79 — 109 Lease operating expenses 391 469 383 — 1,243 Gathering, processing, and transmission 309 12 39 — 360 Exploration expenses 28 63 34 2 127 Production taxes (3) 188 — — — 188 Income tax 383 479 134 — 996 1,840 1,500 936 2 4,278 Results of operations $ 1,440 $ 585 $ 200 $ (2) $ 2,223 (1) Includes noncontrolling interests 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 18—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 18—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) 2023 Acquisitions: Proved $ — $ 4 $ — $ — $ 4 Unproved 19 — — — 19 Exploration 5 226 44 1 276 Development 864 646 468 — 1,978 Costs incurred (1) $ 888 $ 876 $ 512 $ 1 $ 2,277 (1) Includes asset retirement costs: Asset retirement costs $ (7) $ — $ 375 $ — $ 368 2022 Acquisitions: Proved $ 19 $ 3 $ — $ — $ 22 Unproved 28 — — — 28 Exploration 4 169 61 3 237 Development 775 568 (57) — 1,286 Costs incurred (1) $ 826 $ 740 $ 4 $ 3 $ 1,573 (1) Includes capitalized interest and asset retirement costs: Capitalized interest $ — $ — $ 1 $ — $ 1 Asset retirement costs 76 — (215) — (139) 2021 Acquisitions: Proved $ — $ (157) $ — $ — $ (157) Unproved 9 20 — — 29 Exploration 6 86 39 30 161 Development 545 404 135 1 1,085 Costs incurred (1) $ 560 $ 353 $ 174 $ 31 $ 1,118 (1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ — $ — $ — Asset retirement costs 130 — 19 — 149 Egypt PSC modernization impacts – Proved and Unproved — (145) — — (145) (2) Includes noncontrolling interests 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) 2023 Proved properties $ 19,809 $ 13,777 $ 9,472 $ — $ 43,058 Unproved properties 217 71 3 — 291 20,026 13,848 9,475 — 43,349 Accumulated DD&A (15,390) (11,678) (7,849) — (34,917) $ 4,636 $ 2,170 $ 1,626 $ — $ 8,432 2022 Proved properties $ 18,990 $ 13,014 $ 8,945 $ — $ 40,949 Unproved properties 208 77 11 — 296 19,198 13,091 8,956 — 41,245 Accumulated DD&A (14,846) (11,157) (7,573) — (33,576) $ 4,352 $ 1,934 $ 1,383 $ — $ 7,669 (1)
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 Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2020 206,936 95,981 86,566 389,483 December 31, 2021 180,968 106,646 77,073 364,687 December 31, 2022 168,817 108,050 82,580 359,447 December 31, 2023 167,911 102,305 61,076 331,292 Proved undeveloped reserves: December 31, 2020 25,516 11,228 7,273 44,017 December 31, 2021 18,168 11,003 5,757 34,928 December 31, 2022 16,221 8,557 2,873 27,651 December 31, 2023 29,012 5,254 — 34,266 Total proved reserves: Balance December 31, 2020 232,452 107,209 93,839 433,500 Extensions, discoveries and other additions 17,869 13,390 2,288 33,547 Purchases of minerals in-place 126 — — 126 Revisions of previous estimates (4,479) 22,727 (60) 18,188 Production (27,450) (25,677) (13,237) (66,364) Sales of minerals in-place (19,382) — — (19,382) 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 522 — — 522 Revisions of previous estimates 7,170 22,433 11,898 41,501 Production (24,141) (31,055) (11,891) (67,087) Sales of minerals in-place (7,425) — — (7,425) Balance December 31, 2022 185,038 116,607 85,453 387,098 Extensions, discoveries and other additions 37,353 12,979 301 50,633 Revisions of previous estimates 1,062 10,505 (12,002) (435) Production (25,755) (32,532) (12,676) (70,963) Sales of minerals in-place (775) — — (775) Balance December 31, 2023 196,923 107,559 61,076 365,558 (1) Includes proved reserves of 53 MMbbls, 62 MMbbls, 39 MMbbls, and 36 MMbbls as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2020 150,599 716 2,053 153,368 December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 152,999 — 2,230 155,229 December 31, 2023 145,618 — 1,460 147,078 Proved undeveloped reserves: December 31, 2020 15,141 126 320 15,587 December 31, 2021 16,380 30 275 16,685 December 31, 2022 15,398 — 76 15,474 December 31, 2023 16,413 — — 16,413 Total proved reserves: Balance December 31, 2020 165,740 842 2,373 168,955 Extensions, discoveries and other additions 21,055 7 81 21,143 Purchases of minerals in-place 191 — — 191 Revisions of previous estimates 22,724 (180) 318 22,862 Production (24,175) (193) (438) (24,806) Sales of minerals in-place (4,983) — — (4,983) 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 233 — — 233 Revisions of previous estimates 10,355 (407) 333 10,281 Production (21,859) (69) (406) (22,334) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 168,397 — 2,306 170,703 Extensions, discoveries and other additions 20,827 — 371 21,198 Revisions of previous estimates (6,343) — (764) (7,107) Production (20,817) — (453) (21,270) Sales of minerals in-place (33) — — (33) Balance December 31, 2023 162,031 — 1,460 163,491 (1) Includes proved reserves of 159 Mbbls and 281 Mbbls as of December 31, 2021 and 2020, respectively, attributable to noncontrolling interests in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2020 1,052,756 409,035 68,159 1,529,950 December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,128,066 399,502 66,292 1,593,860 December 31, 2023 953,578 377,144 46,839 1,377,561 Proved undeveloped reserves: December 31, 2020 76,504 12,572 8,341 97,417 December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 188,976 1,068 2,304 192,348 December 31, 2023 86,800 2,612 — 89,412 Total proved reserves: Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 Extensions, discoveries and other additions 227,684 50,209 3,684 281,577 Purchases of minerals in-place 839 — — 839 Revisions of previous estimates 279,610 99,143 17,171 395,924 Production (192,523) (96,234) (14,076) (302,833) Sales of minerals in-place (22,968) — — (22,968) 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 1,592 — — 1,592 Revisions of previous estimates 96,381 45,725 (3,431) 138,675 Production (167,580) (130,071) (12,895) (310,546) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,317,042 400,570 68,596 1,786,208 Extensions, discoveries and other additions 125,654 14,188 3,335 143,177 Revisions of previous estimates (249,257) 83,907 (6,739) (172,089) Production (152,925) (118,909) (18,353) (290,187) Sales of minerals in-place (136) — — (136) Balance December 31, 2023 1,040,378 379,756 46,839 1,466,973 (1) Includes proved reserves of 188 Bcf, 224 Bcf, 158 Bcf, and 141 Bcf as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2020 532,994 164,870 99,979 797,843 December 31, 2021 551,384 184,563 91,825 827,772 December 31, 2022 509,827 174,633 95,859 780,319 December 31, 2023 472,459 165,162 70,343 707,964 Proved undeveloped reserves: December 31, 2020 53,408 13,449 8,983 75,840 December 31, 2021 65,288 12,683 7,219 85,190 December 31, 2022 63,115 8,735 3,333 75,183 December 31, 2023 59,891 5,690 — 65,581 Total proved reserves: Balance December 31, 2020 586,402 178,319 108,962 873,683 Extensions, discoveries and other additions 76,871 21,765 2,983 101,619 Purchases of minerals in-place 457 — — 457 Revisions of previous estimates 64,847 39,071 3,120 107,038 Production (83,712) (41,909) (16,021) (141,642) Sales of minerals in-place (28,193) — — (28,193) 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 1,020 — — 1,020 Revisions of previous estimates 33,588 29,647 11,659 74,894 Production (73,930) (52,803) (14,446) (141,179) Sales of minerals in-place (26,000) — — (26,000) Balance December 31, 2022 572,942 183,368 99,192 855,502 Extensions, discoveries and other additions 79,123 15,344 1,228 95,695 Revisions of previous estimates (46,824) 24,490 (13,889) (36,223) Production (72,060) (52,350) (16,188) (140,598) Sales of minerals in-place (831) — — (831) Balance December 31, 2023 532,350 170,852 70,343 773,545 (1) Includes total proved reserves of 84 MMboe, 99 MMboe, 66 MMboe, and 59 MMboe as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests 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, 2023, 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 Total (1) (In millions) 2023 Cash inflows $ 20,063 $ 9,921 $ 5,761 $ 35,745 Production costs (7,861) (1,690) (2,773) (12,324) Development costs (2,182) (1,235) (2,461) (5,878) Income tax expense (936) (2,222) (946) (4,104) Net cash flows 9,084 4,774 (419) 13,439 10 percent discount rate (3,534) (943) 476 (4,001) Discounted future net cash flows (2) $ 5,550 $ 3,831 $ 57 $ 9,438 2022 Cash inflows $ 29,490 $ 12,819 $ 10,147 $ 52,456 Production costs (10,221) (2,086) (3,241) (15,548) Development costs (1,598) (1,471) (2,297) (5,366) Income tax expense (1,389) (2,729) (2,631) (6,749) Net cash flows 16,282 6,533 1,978 24,793 10 percent discount rate (6,422) (1,400) (204) (8,026) Discounted future net cash flows (2) $ 9,860 $ 5,133 $ 1,774 $ 16,767 2021 Cash inflows $ 22,852 $ 9,337 $ 6,832 $ 39,021 Production costs (8,323) (1,712) (2,343) (12,378) Development costs (1,632) (1,402) (2,533) (5,567) Income tax expense (134) (1,887) (768) (2,789) Net cash flows 12,763 4,336 1,188 18,287 10 percent discount rate (5,294) (983) 350 (5,927) Discounted future net cash flows (2) $ 7,469 $ 3,353 $ 1,538 $ 12,360 (1) Includes discounted future net cash flows of approximately $1.8 billion , $2.5 billion, and $1.6 billion as of December 31, 2023, 2022, and 2021, respectively, attributable to noncontrolling interests in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $13.0 billion , $21.7 billion, and $14.9 billion as of December 31, 2023, 2022, and 2021, 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, 2023 2022 2021 (In millions) Sales, net of production costs $ (5,176) $ (6,970) $ (4,707) Net change in prices and production costs (6,699) 8,627 9,376 Discoveries and improved recovery, net of related costs 1,633 1,132 1,749 Change in future development costs (415) (347) (839) Previously estimated development costs incurred during the period 707 669 545 Revision of quantities (127) 2,621 1,983 Purchases of minerals in-place — 17 1 Accretion of discount 2,167 1,489 626 Change in income taxes 1,374 (2,371) (1,583) Sales of minerals in-place (18) (363) (116) Change in production rates and other (775) (97) 13 $ (7,329) $ 4,407 $ 7,048

NATURE OF OPERATIONS (Details)

NATURE OF OPERATIONS (Details)	12 Months Ended
	Dec. 31, 2023 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
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 27, 2021
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments		$ 61,000,000	$ 0	$ 208,000,000
Equity method investment impairment	$ 160,000,000			160,000,000
Receivables from contracts with customer, net		1,400,000,000	1,300,000,000
Cash and cash equivalent		84,000,000	185,000,000
Restricted cash		0	0
Inventory write-down		50,000,000
Gathering, processing, and transmission facilities		448,000,000	449,000,000
GPT facilities, accumulated depreciation		373,000,000	367,000,000
Tangible asset impairment charges		0	0	0
Other property and equipment		217,000,000	206,000,000
Transaction, reorganization, and separation		15,000,000	26,000,000	22,000,000
Ongoing Consulting And Separation Costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation		7,000,000	15,000,000	17,000,000
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property 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
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment		$ 21,000,000	24,000,000	31,000,000
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Inventory and other				26,000,000
Egypt | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment		0	4,000,000	8,000,000
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Inventory and other				22,000,000
North Sea | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment		11,000,000	0	1,000,000
United States | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment		$ 10,000,000	$ 20,000,000	$ 22,000,000
Apache Egypt
Schedule Of Significant Accounting Policies [Line Items]
Noncontrolling interest, ownership percentage by parent					66.67%
Apache Egypt | Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners		33.33%
Altus | Third-party investors
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners		21%

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Credit Loss Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 117	$ 109	$ 95
Additional provisions for the year	16	9	19
Uncollectible accounts written off, net of recoveries	(19)	(1)	(5)
Allowance for credit loss at end of year	$ 114	$ 117	$ 109

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - Oil and Gas Properties, Unproved - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment	$ 21	$ 24	$ 31
U.S.
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment	10	20	22
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment	0	4	8
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impairment	$ 11	$ 0	$ 1

TRANSACTIONS WITH PARENT AFFI_2

TRANSACTIONS WITH PARENT AFFILIATE (Details)			12 Months Ended			30 Months Ended
	Mar. 31, 2023 USD ($)	Mar. 01, 2021 subsidiary	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Aug. 31, 2023 USD ($)	Apr. 30, 2022 USD ($)
Related Party Transaction [Line Items]
Distributions to APA Corporation			$ (315,000,000)	$ (894,000,000)	$ (890,000,000)
Payments of capital distribution			77,000,000	678,000,000
Noncontrolling Interest - APA Corporation
Related Party Transaction [Line Items]
Comprehensive income attributable to noncontrolling interest – APA Corporation			352,000,000	278,000,000	0
Noncontrolling Interests
Related Party Transaction [Line Items]
Distributions to APA Corporation			(238,000,000)	(216,000,000)
Noncontrolling Interests | Noncontrolling Interest - APA Corporation
Related Party Transaction [Line Items]
Comprehensive income attributable to noncontrolling interest – APA Corporation			352,000,000	$ 278,000,000
Net Income And Distributable Cash Flow For Egyptian Operations | Sinopec
Related Party Transaction [Line Items]
Ownership percentage by noncontrolling owners				50%
Affiliated Entity
Related Party Transaction [Line Items]
Reimbursable costs charged to parent			22,000,000	$ 18,000,000	17,000,000
Note receivable from APA Corporation (Note 2)			2,980,000,000	1,415,000,000
Interest income			109,000,000	63,000,000	$ 51,000,000
Current receivable from APA Corporation			52,000,000	0
Noncurrent receivable from APA Corporation (Note 2)			93,000,000	869,000,000
Affiliated Entity | Promissory Note April 2022
Related Party Transaction [Line Items]
Debt, principal amount							$ 680,000,000
Affiliated Entity | Senior Promissory Note Dated March 31, 2023
Related Party Transaction [Line Items]
Notes receivable, term	5 years
Note receivable, interest rate	6%
Note receivable from APA Corporation (Note 2)			1,500,000,000
Receivable with Imputed Interest, Face Amount	$ 1,500,000,000
Holding Company Reorganization | Affiliated Entity
Related Party Transaction [Line Items]
Number of subsidiaries | subsidiary		3
Notes receivable, term		7 years
Note receivable, interest rate		4.50%
Note receivable, accrued interest converted to principal, term		5 years 6 months
Accrued interest converted to principal						$ 158,000,000
Note receivable from APA Corporation (Note 2)			$ 1,500,000,000	$ 1,400,000,000

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - 2023 Activity (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended		3 Months Ended	12 Months Ended
	Mar. 11, 2022	Dec. 31, 2023	Mar. 31, 2022	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Shares sold (in shares)			4
Aggregate issue price of preferred units			$ 224
Leasehold and property acquisitions amount					$ 20	$ 37	$ 9
Proceeds from asset divestitures					29	778	256
Disposed of by Sale | Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures					29	52
Gain (loss) on sale of non-core assets					8	$ 36
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount					$ 20		$ 9
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from asset divestitures				$ 176
Gain (loss) on sale of non-core assets				$ 63
Kinetik
Business Acquisition [Line Items]
Shares sold (in shares)	4	7.5	4
Aggregate issue price of preferred units		$ 228

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - 2022 Activity (Details) - USD ($) shares in Millions, $ in Millions			1 Months Ended		12 Months Ended
	Mar. 11, 2022	Feb. 22, 2022	Dec. 31, 2023	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 21, 2022
Business Acquisition [Line Items]
Proceeds from asset divestitures					$ 29	$ 778	$ 256
Gain on deconsolidation of ALTM		$ 609
Net effect of deconsolidating balance sheet		193
Equity method interests			$ 437		437	624
Shares sold (in shares)				4
Proceeds from sale of stock				$ 224
Kinetik
Business Acquisition [Line Items]
Equity method interests		$ 802
Shares sold (in shares)	4		7.5	4
Proceeds from sale of stock			$ 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 | Class C Common Stock | 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					29	52
Gain (loss) on sale of non-core assets					$ 8	36
Disposed of by Sale | Non-Core Mineral Rights
Business Acquisition [Line Items]
Proceeds from asset divestitures						726
Gain (loss) on sale of non-core assets						560
Permian Basin | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from asset divestitures						$ 37

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - 2021 Activity (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Proceeds from asset divestitures		$ 29	$ 778	$ 256
Leasehold and property acquisitions amount		20	$ 37	9
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount		$ 20		9
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Net Property and Equipment	$ 157
Proceeds from asset divestitures	176
Asset retirement obligation assumed	44
Gain (loss) on sale of non-core assets	$ 63
Permian Region | Disposed of by Sale | Other Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures				80
Gain (loss) on sale of non-core assets				$ 4

CAPITALIZED EXPLORATORY WELL _3

CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized well costs at beginning of year	$ 50	$ 46	$ 197
Additions pending determination of proved reserves	150	138	62
Divestitures and other	0	0	(163)
Reclassifications to proved properties	(135)	(110)	(40)
Charged to exploration expense	(18)	(24)	(10)
Capitalized well costs at end of year	$ 47	$ 50	$ 46

CAPITALIZED EXPLORATORY WELL _4

CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2023 USD ($) Project	Dec. 31, 2022 USD ($) Project	Dec. 31, 2021 USD ($) Project	Dec. 31, 2020 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 38	$ 34	$ 13
Exploratory well costs capitalized for a period greater than one year	9	16	33
Capitalized exploratory well costs	$ 47	$ 50	$ 46	$ 197
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	8,000,000	10,000,000	9,000,000

CAPITALIZED EXPLORATORY WELL _5

CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 9	$ 16	$ 33
North Sea
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year		$ 16

CAPITALIZED EXPLORATORY WELL _6

CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 9	$ 16	$ 33
2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
2020 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
Egypt
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
Egypt | 2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Egypt | 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Egypt | 2020 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 9

DERIVATIVE INSTRUMENTS AND HE_3

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ (23)	$ 69
Derivative instrument gains (losses), net	0	(107)	94
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	(85)	25
Unrealized gains (losses), net	0	(22)	69
Derivative instrument gains (losses), net	0	(107)	94
Commodity derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	(72)	25
Unrealized gains (losses), net	0	9	(20)
Foreign currency derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	(13)	0
Pipeline capacity embedded derivatives | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	0	0	7
Preferred Units embedded derivative | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ (31)	$ 82

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 439	$ 425
Drilling advances	68	64
Prepaid assets and other	40	54
Current decommissioning security for sold Gulf of Mexico assets	178	450
Total Other current assets	$ 725	$ 993

EQUITY METHOD INTERESTS - Addit

EQUITY METHOD INTERESTS - Additional Information (Details) shares in Millions, $ in Millions		1 Months Ended		3 Months Ended	12 Months Ended
	Mar. 11, 2022 shares	Dec. 31, 2023 USD ($) shares	Mar. 31, 2022 USD ($) shares	Jun. 30, 2022 shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($)	Feb. 22, 2022 USD ($) shares
Schedule of Equity Method Investments [Line Items]
Equity method interests		$ 437			$ 437	$ 624
Shares sold (in shares) | shares			4
Aggregate issue price of preferred units			$ 224
Accounts payable		$ 560			$ 560	646
Kinetik
Schedule of Equity Method Investments [Line Items]
Stock split conversion ratio				2
Kinetik
Schedule of Equity Method Investments [Line Items]
Equity method interests							$ 802
Equity method investment, number of shares (in share) | shares		13.1		17.7	13.1		12.9
Shares sold (in shares) | shares	4	7.5	4
Dividends paid-in-kind (in shares) | shares					2.9
Aggregate issue price of preferred units		$ 228
Interest percentage		9%			9%
Gain on changes in fair value of equity method interest					$ 41	72
Accounts payable		$ 27			27	17
Receivables		$ 13			$ 13	$ 8

EQUITY METHOD INTERESTS - Sales

EQUITY METHOD INTERESTS - Sales and Costs Associated with Equity Method Interest (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Lease operating expenses	[1]	$ 1,397	$ 1,435	$ 1,241
Total operating expenses		4,879	6,064	5,948
Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		93	8
Lease operating expenses		7	0
Total operating expenses		186	91
Gathering, processing, and transmission costs
Schedule of Equity Method Investments [Line Items]
Total revenues	[1]	7,079	9,028	6,498
Cost of goods and services sold	[1]	314	356	264
Gathering, processing, and transmission costs | Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		64	8
Cost of goods and services sold		99	91
Purchased oil and gas sales
Schedule of Equity Method Investments [Line Items]
Total revenues	[1]	894	1,855	1,487
Cost of goods and services sold	[1]	742	1,776	$ 1,580
Purchased oil and gas sales | Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		29	0
Cost of goods and services sold		$ 80	$ 0
[1] (1) For related party transactions associated with Kinetik, refer to Note 7—Equity Method Interest for further detail.

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Accrued operating expenses	$ 158	$ 139
Accrued exploration and development	307	300
Accrued compensation and benefits	390	514
Accrued interest	92	96
Accrued income taxes	138	90
Current asset retirement obligation	76	55
Current operating lease liability	115	167
Current decommissioning contingency for sold Gulf of Mexico properties	60	450
Other	333	238
Total Other current liabilities	$ 1,669	$ 2,049

ASSET RETIREMENT OBLIGATION - S

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the year	$ 1,991	$ 2,130
Liabilities incurred	12	4
Liabilities divested	0	(73)
Liabilities settled	(45)	(39)
Accretion expense	116	117	$ 113
Revisions in estimated liabilities	356	(148)
Asset retirement obligation at end of the year	2,430	1,991	$ 2,130
Less current portion	(76)	(55)
Asset retirement obligation, long-term	$ 2,354	$ 1,936

ASSET RETIREMENT OBLIGATION - A

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 12	$ 4
Revisions in estimated liabilities	$ 356	$ (148)

DEBT AND FINANCING COSTS - Over

DEBT AND FINANCING COSTS - Overview (Details) - USD ($) $ in Millions			12 Months Ended
	Oct. 17, 2022	Jan. 18, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
(Gain) loss from extinguishment of debt			$ (9)	$ 67	$ 104
2.625% notes due 2023 | Senior Notes
Debt Instrument [Line Items]
Current maturities	$ 123
Debt interest rate	2.625%
Redemption price, percentage of principal amount redeemed	100%
Senior Notes | 3.25% notes due 2022
Debt Instrument [Line Items]
Current maturities		$ 213
Debt interest rate		3.25%
Redemption price, percentage of principal amount redeemed		100%
Open Market Repurchase | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount			74	15	22
Debt instrument repurchase program			65	16	20
Premium (discount) to par of debt repurchase			10	1	2
(Gain) loss from extinguishment of debt			$ (9)	1	(1)
Cash Tender Offers | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount				1,100	1,700
Debt instrument repurchase program				1,200	1,800
(Gain) loss from extinguishment of debt				66	105
Unamortized debt issuance costs and discount				$ 11	$ 11

DEBT AND FINANCING COSTS - Sche

DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 4,835
Finance lease obligations	32	$ 34
Unamortized discount	(26)	(27)
Debt issuance costs	(25)	(28)
Total debt	4,816	4,887
Current maturities	(2)	(2)
Long-term debt	4,814	4,885
Notes and debentures before unamortized discount and debt issuance costs
Debt Instrument [Line Items]
Debt, fair value	4,300	4,200
Unsecured Debt | 4.625% notes due 2025
Debt Instrument [Line Items]
Long-term debt, gross	$ 51	51
Debt interest rate	4.625%
Unsecured Debt | 7.7% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross	$ 78	78
Debt interest rate	7.70%
Unsecured Debt | 7.95% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross	$ 132	132
Debt interest rate	7.95%
Unsecured Debt | 4.875% notes due 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 108	108
Debt interest rate	4.875%
Unsecured Debt | 4.375% notes due 2028
Debt Instrument [Line Items]
Long-term debt, gross	$ 325	325
Debt interest rate	4.375%
Unsecured Debt | 7.75% notes due in 2029
Debt Instrument [Line Items]
Long-term debt, gross	$ 235	235
Debt interest rate	7.75%
Unsecured Debt | 4.25% notes due 2030
Debt Instrument [Line Items]
Long-term debt, gross	$ 516	579
Debt interest rate	4.25%
Unsecured Debt | 6.0% notes due 2037
Debt Instrument [Line Items]
Long-term debt, gross	$ 443	443
Debt interest rate	6%
Unsecured Debt | 5.1% notes due 2040
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,333	1,333
Debt interest rate	5.10%
Unsecured Debt | 5.25% notes due 2042
Debt Instrument [Line Items]
Long-term debt, gross	$ 399	399
Debt interest rate	5.25%
Unsecured Debt | 4.75% notes due 2043
Debt Instrument [Line Items]
Long-term debt, gross	$ 428	428
Debt interest rate	4.75%
Unsecured Debt | 4.25% notes due 2044
Debt Instrument [Line Items]
Long-term debt, gross	$ 211	221
Debt interest rate	4.25%
Unsecured Debt | 7.375% debentures due 2047
Debt Instrument [Line Items]
Long-term debt, gross	$ 150	150
Debt interest rate	7.375%
Unsecured Debt | 5.35% notes due 2049
Debt Instrument [Line Items]
Long-term debt, gross	$ 387	387
Debt interest rate	5.35%
Unsecured Debt | 7.625% debentures due 2096
Debt Instrument [Line Items]
Long-term debt, gross	$ 39	39
Debt interest rate	7.625%
Unsecured Debt | Notes and debentures before unamortized discount and debt issuance costs
Debt Instrument [Line Items]
Long-term debt, gross	$ 4,835	$ 4,908

DEBT AND FINANCING COSTS - Sc_2

DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2024	$ 0
2025	51
2026	210
2027	108
2028	325
Thereafter	4,141
Notes and debentures, excluding discounts and debt issuance costs	$ 4,835

DEBT AND FINANCING COSTS - Comp

DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Interest expense	$ 291	$ 312	$ 419
Amortization of debt issuance costs	2	7	8
Capitalized interest	0	(1)	0
Loss (gain) on extinguishment of debt	(9)	67	104
Interest income	(10)	(9)	(8)
Interest income from APA Corporation, net	(109)	(63)	(51)
Financing costs, net	165	313	472
Discount of debt amortization	$ 1	$ 2	$ 6

DEBT AND FINANCING COSTS - Unco

DEBT AND FINANCING COSTS - Uncommitted Lines of Credit (Details) - Uncommitted Lines of Credit - Line of Credit £ in Millions	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 GBP (£)
Debt Instrument [Line Items]
Line of credit outstanding	$ 0		$ 0
Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount	$ 2,000,000	£ 296	$ 17,000,000	£ 199

DEBT AND FINANCING COSTS - Unse

DEBT AND FINANCING COSTS - Unsecured 2022 Committed Bank Credit Facilities (Details)		12 Months Ended
	Apr. 29, 2022 USD ($) option credit_agreement	Dec. 31, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Dec. 31, 2022 GBP (£)	Apr. 29, 2022 GBP (£) credit_agreement
Syndicated Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility fee, percentage		0.225%
Debt covenant, adjusted debt-to-capital ratio	0.60					0.60
Debt-to-capital ratio			0.20	0.20
Debt covenant, debt secured as percentage of consolidated net tangible assets			15%	15%
Debt covenant, debt secured as percentage of consolidated net tangible assets, threshold amount			$ 1,900,000,000
Syndicated Credit Facility | Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Margin percentage		0.40%
Syndicated Credit Facility | Revolving Credit Facility | SOFR
Debt Instrument [Line Items]
Margin percentage		1.40%
Syndicated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Line of credit facility, covenant benchmark amount	$ 1,000,000,000
Syndicated Credit Facility | Unsecured Debt
Debt Instrument [Line Items]
Number of syndicated credit agreements | credit_agreement	2					2
USD agreement | Minimum | Base Rate
Debt Instrument [Line Items]
Margin percentage	0.10%
USD agreement | Minimum | SOFR
Debt Instrument [Line Items]
Margin percentage	1.10%
USD agreement | Maximum | Base Rate
Debt Instrument [Line Items]
Margin percentage	0.675%
USD agreement | Maximum | SOFR
Debt Instrument [Line Items]
Margin percentage	1.675%
USD agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount	$ 1,800,000,000
Line of credit facility, increased committed amount	$ 2,300,000,000
Line of credit facility, number of extension options | option	2
Debt extension term	1 year
Debt, principal amount	$ 300,000,000
Line of credit outstanding		$ 0	0
USD agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	750,000,000
Line of credit facility, current borrowing capacity	$ 150,000,000
GBP agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount | £						£ 1,500,000,000
Debt extension term	1 year
GBP agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, number of extension options | option	2
Former facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, terminated amount	$ 4,000,000,000
APA Corp
Debt Instrument [Line Items]
Number of syndicated credit agreements | credit_agreement	2					2
APA Corp | USD agreement | Line of Credit
Debt Instrument [Line Items]
Line of credit outstanding		566,000,000	372,000,000
APA Corp | USD agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount		$ 20,000,000	$ 0
APA Corp | GBP agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £				£ 348,000,000	£ 652,000,000

DEBT AND FINANCING COSTS - Comm

DEBT AND FINANCING COSTS - Commercial Paper Program (Details) - Commercial paper	Dec. 13, 2023 USD ($)
Debt Instrument [Line Items]
Debt, principal amount	$ 1,800,000,000
Debt instrument guarantee terms, benchmark amount	$ 1,000,000,000
Debt instrument, term	397 days

DEBT AND FINANCING COSTS - Subs

DEBT AND FINANCING COSTS - Subsequent Event (Details) - Subsequent Event	Jan. 30, 2024 USD ($) debt_tranche option
Delayed-Drawn Term Loan | Unsecured Debt
Debt Instrument [Line Items]
Debt, principal amount	$ 2,000,000,000
Debt instrument guarantee terms, benchmark amount	$ 1,000,000,000
Debt instrument, number of tranches | debt_tranche	2
Debt instrument, interest rate options | option	2
Credit facility fee, percentage	0.225%
Debt instrument, ticking fee accrual terms, period	90 days
Delayed-Drawn Term Loan | Unsecured Debt | SOFR | Term Base Rate Margin
Debt Instrument [Line Items]
Margin percentage	1%
Delayed-Drawn Term Loan | Unsecured Debt | Greater of the applicable federal funds rate and overnight bank funding rate | Term Base Rate Margin
Debt Instrument [Line Items]
Margin percentage	0.50%
Delayed-Drawn Term Loan | Senior Notes | Callon Petroleum Company
Debt Instrument [Line Items]
Debt, guarantee terms, aggregate outstanding principal amount of acquiree's Notes, benchmark amount	$ 400,000,000
Debt instrument, guarantee terms, aggregate outstanding principal amount of acquiree's notes, period after closing date	120 days
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt, principal amount	$ 1,500,000,000
Debt instrument, term	3 years
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.75%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Term Applicable Margin
Debt Instrument [Line Items]
Debt, margin rate	1.75%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Debt Instrument Maturity, Tranche One | Minimum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Debt Instrument Maturity, Tranche One | Maximum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Debt Instrument Maturity, Tranche Two | Minimum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | Debt Instrument Maturity, Tranche Two | Maximum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | SOFR | Debt Instrument Maturity, Tranche One | Minimum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | SOFR | Debt Instrument Maturity, Tranche One | Maximum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	2.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | SOFR | Debt Instrument Maturity, Tranche Two | Minimum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	1.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt | SOFR | Debt Instrument Maturity, Tranche Two | Maximum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	2.375%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt
Debt Instrument [Line Items]
Debt, principal amount	$ 500,000,000
Debt instrument, term	364 days
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.625%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | Term Applicable Margin
Debt Instrument [Line Items]
Debt, margin rate	1.625%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | Minimum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.25%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | Maximum | Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | SOFR | Minimum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	1.25%
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt | SOFR | Maximum | Term Applicable Margin
Debt Instrument [Line Items]
Margin percentage	2%
6.375% Senior Notes Due 2026 | Senior Notes | Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	6.375%
8.00% Senior Notes Due 2028 | Senior Notes | Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	8%
7.500% Senior Notes Due 2030 | Senior Notes | Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	7.50%

INCOME TAXES - Income Before In

INCOME TAXES - Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
U.S.	$ 594	$ 2,656	$ 689
Foreign	2,322	3,218	1,291
NET INCOME BEFORE INCOME TAXES	$ 2,916	$ 5,874	$ 1,980

INCOME TAXES - Total Provision

INCOME TAXES - Total Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income taxes:
Federal	$ 2	$ 1	$ 16
State	6	11	0
Foreign	1,330	1,495	636
Total current income taxes	1,338	1,507	652
Deferred income taxes:
Federal	(1,696)	0	0
State	(34)	0	0
Foreign	78	145	(74)
Total deferred income taxes	(1,652)	145	(74)
Total	$ (314)	$ 1,652	$ 578

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate	$ 612	$ 1,234	$ 416
State income tax, less federal effect	(25)	9	0
Taxes related to foreign operations	753	774	300
Tax credits	0	(4)	(10)
Net change in tax contingencies	5	1	16
Valuation allowances	(1,838)	(705)	(111)
Tax adjustments attributable to BCP Business Combination	0	126	0
Remeasurement of U.K. deferred tax liability	174	208	0
Tax attributable to Altus Preferred Unit limited partners	0	0	(34)
All other, net	5	9	1
Total	$ (314)	$ 1,652	$ 578

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax (Asset) Liability (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
U.S. and state net operating losses	$ 2,027	$ 2,035
Capital losses	8	357
Tax credits and other tax incentives	26	26
Foreign tax credits	2,204	2,241
Accrued expenses and liabilities	130	145
Asset retirement obligation	849	672
Equity investments	8	0
Net interest expense limitation	74	55
Lease liability	71	113
Decommissioning contingency for sold Gulf of Mexico properties	210	275
Total deferred tax assets	5,607	5,919
Valuation allowance	(2,549)	(4,831)	$ (5,875)	$ (5,991)
Net deferred tax assets	3,058	1,088
Deferred tax liabilities:
Equity investments	0	1
Property and equipment	1,510	1,014
Right-of-use asset	69	110
Decommissioning security for sold Gulf of Mexico properties	44	148
Other	59	90
Total deferred tax liabilities	1,682	1,363
Net deferred income tax (asset)	$ (1,376)
Net deferred income tax liability		$ (275)

INCOME TAXES - Net Deferred T_2

INCOME TAXES - Net Deferred Tax Assets and Liabilities in the Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Deferred tax asset (Note 11)	$ 1,747	$ 39
Deferred tax liability (Note 11)	371	314
Net deferred income tax (asset)	$ (1,376)
Net deferred income tax liability		$ 275

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Details) - USD ($) shares in Millions, $ in Millions			1 Months Ended		12 Months Ended
	Mar. 11, 2022	Jan. 14, 2022	Dec. 31, 2023	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred Tax Expense [Line Items]
Shares sold (in shares)				4
Tax adjustments attributable to BCP Business Combination					$ 0	$ 126	$ 0
Pre-tax book cumulative loss incurred period					3 years
Deferred income tax benefit					$ 1,696	0	0
Net interest expense carryforward			$ 345		345
Capital losses			8		8	357
Tax expense recorded for interest and penalties					2	1	1
Accrued for payment of interest and penalties			7		7	5	4
Increase (decrease) of reserve for uncertain tax positions					(4)	(27)	$ 23
Canada
Deferred Tax Expense [Line Items]
Deferred tax expense, remeasurement of deferred tax liability					174	$ 208
Tax credit carryforward, amount			2,204		2,204
U.S.
Deferred Tax Expense [Line Items]
Operating loss carryforwards			7,922		7,922
Operating loss carryforwards subject to annual limitation			107		$ 107
Capital loss carryforward carryover period					5 years
U.S. | Capital Loss Carryforward
Deferred Tax Expense [Line Items]
Tax credit carryforward, expired amount					$ 1,700
Tax credit carryforward, amount			34		34
State
Deferred Tax Expense [Line Items]
Operating loss carryforwards			$ 6,541		6,541
BCP Business Combination
Deferred Tax Expense [Line Items]
Tax adjustments attributable to BCP Business Combination					$ 126
Kinetik
Deferred Tax Expense [Line Items]
Shares sold (in shares)	4		7.5	4
Apache Midstream LLC
Deferred Tax Expense [Line Items]
Stock exchanged during period (in shares)		12.5
Altus
Deferred Tax Expense [Line Items]
Stock exchanged during period (in shares)		12.5

INCOME TAXES - Summary of Valua

INCOME TAXES - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 4,831	$ 5,875	$ 5,991
Increase (decrease) of valuation allowances	(2,300)	(1,000)	(116)
Balance at end of year	2,549	4,831	5,875
U.S.
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(2,221)	(706)	(112)
State
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(61)	(111)	1
Foreign
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	$ 0	$ (227)	$ (5)

INCOME TAXES - Net Operating Lo

INCOME TAXES - Net Operating Losses (Details) $ in Millions	Dec. 31, 2023 USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 7,922
State
Schedule Of Income Tax [Line Items]
Net operating losses	$ 6,541

INCOME TAXES - Schedule of Fore

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) $ in Millions	Dec. 31, 2023 USD ($)
Canada
Tax Credit Carryforward [Line Items]
Tax credit carryforward, amount	$ 2,204

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 89	$ 116	$ 93
Additions based on tax positions related to prior year	4	0	16
Additions based on tax positions related to the current year	0	0	7
Reductions for tax positions of prior years	(8)	(27)	0
Balance at end of year	$ 85	$ 89	$ 116

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions							12 Months Ended
	Sep. 10, 2020 defendant	Sep. 11, 2019 USD ($) plaintiff	Dec. 20, 2017 action	Jul. 17, 2017 action defendant	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Dec. 31, 2023 USD ($) bond letter_of_credit	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2013 USD ($) netProfitInterest	Jun. 21, 2023 surety	Apr. 05, 2022 letter	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)	Mar. 12, 2014 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies							$ 83,000,000
Environmental tax and royalty obligations															$ 100,000,000
Retain right of obligations							45,000,000
Maximum cost considered to be recognized for additional reserve							300,000
Undiscounted reserve for environmental remediation							5,000,000
Decommissioning costs incurred							819,000,000
Decommissioning costs reimbursed amount from trust							293,000,000
Decommissioning costs reimbursed from letters of credit							336,000,000
Standby loan agreed to provide related to ARO (up to)							400,000,000
Current decommissioning contingency for sold Gulf of Mexico properties							824,000,000
Decommissioning contingency for sold Gulf of Mexico properties, total							764,000,000	$ 738,000,000
Current decommissioning contingency for sold Gulf of Mexico properties							60,000,000	450,000,000
Decommissioning security for sold properties							199,000,000
Trust account for disposal group, number of net profits interests							21,000,000	217,000,000
Current decommissioning security for sold Gulf of Mexico assets							178,000,000	450,000,000
Losses on previously sold Gulf of Mexico properties							212,000,000	157,000,000	$ 446,000,000
Number of plaintiff, sureties issued bonds directly | surety											2
Number of plaintiff, sureties issued bonds to issuing bank | surety											2
Fixed operating lease expenses							167,000,000	144,000,000	127,000,000
Short-term lease cost							$ 71,000,000	$ 0	0
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 10)	LONG-TERM DEBT (Note 10)
Depreciation on finance lease asset							$ 2,000,000	$ 2,000,000	2,000,000
Interest on finance lease asset							1,000,000	2,000,000	2,000,000
Variable lease payment							74,000,000	$ 89,000,000	$ 63,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages					$ 200,000,000
Canadian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 60,000,000
Number of plaintiffs | plaintiff		4
Litigation settlement, amount awarded to other party							$ 7,000,000
California Litigation
Commitment And Contingencies [Line Items]
Number of actions filed | action			2	3
Number of defendants | defendant				30
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants | defendant	25
Apache Australia Operation | Australian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount														$ 80
Loss contingency, estimated of possible loss amount													$ 200
Gulf Of Mexico Shelf Operations And Properties | Disposed of by Sale
Commitment And Contingencies [Line Items]
Proceeds from sale of operations and properties										$ 3,750,000,000
Trust account for disposal group, number of net profits interests | netProfitInterest										2
Number of bonds held | bond							2
Number of debt instruments held | letter_of_credit							5
Number of prior letters notifying unable to fund decommissioning obligations | letter												2
Minimum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							$ 824,000,000
Minimum | Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages						$ 1,100,000,000
Maximum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							$ 1,200,000,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details)	Dec. 31, 2023
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	9 years 8 months 12 days
Operating leases, weighted average discount rate	5.30%
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
2024	$ 115
2025	35
2026	21
2027	23
2028	22
Thereafter	129
Total future minimum payments	345
Less: imputed interest	(65)
Total lease liabilities	280
Current portion	115	$ 167
Non-current portion	$ 165
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities (Note 8)	Other current liabilities (Note 8)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other	Other
Finance Leases
2024	$ 3
2025	3
2026	4
2027	4
2028	4
Thereafter	23
Total future minimum payments	41
Less: imputed interest	(9)
Total lease liabilities	32	$ 34
Current portion	2
Non-current portion	30
Purchase Obligations
2024	250
2025	197
2026	766
2027	143
2028	141
Thereafter	208
Total future minimum payments	1,705
Total costs under take or pay and throughout obligation	182	$ 183	$ 194
Purchase commitment, remaining minimum amount committed	3,500
Purchase commitment, amount incurred	$ 2,900

RETIREMENT AND DEFERRED COMPE_3

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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	$ 44	$ 40	$ 31
Targeted ongoing funding level of pension plan policy, percent	100%
Outperformance relative to gilts for equities	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 112	$ 89	$ 205
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 137
Fair value of plan assets at end of year	150	$ 137
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	108	211	$ 233
Service cost	1	2	3
Interest cost	5	3	3
Foreign currency exchange rates	6	(21)	(2)
Actuarial losses (gains)	3	(79)	(5)
Plan settlements	0	0	(17)
Benefits paid	(5)	(8)	(4)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	118	108	211
Change in Plan Assets
Fair value of plan assets at beginning of year	137	254	262
Actual return (loss) on plan assets	8	(87)	11
Foreign currency exchange rates	8	(26)	(3)
Employer contributions	2	4	5
Plan settlements	0	0	(17)
Benefits paid	(5)	(8)	(4)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	150	137	254
Funded status at end of year	32	29	43
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	32	29	43
Amounts recognized in Consolidated Balance Sheet	32	29	43
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (12)	$ (10)	$ 1
Weighted Average Assumptions used as of December 31
Discount rate	4.80%	5%	1.80%
Salary increases	4.60%	4.70%	4.90%
Expected return on assets	4.80%	4.70%	1.90%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 15	$ 20	$ 20
Service cost	1	1	1
Interest cost	1	0	0
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	0	(5)	1
Plan settlements	0	0	0
Benefits paid	(3)	(3)	(4)
Retiree contributions	1	2	2
Projected benefit obligation at end of year	15	15	20
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	2	2
Plan settlements	0	0	0
Benefits paid	(3)	(4)	(4)
Retiree contributions	2	2	2
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(15)	(15)	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current liability	(13)	(13)	(18)
Amounts recognized in Consolidated Balance Sheet	(15)	(15)	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 16	$ 18	$ 14
Weighted Average Assumptions used as of 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_5

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2023	Dec. 31, 2022
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%	6%
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	59%	40%
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	6%	24%
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	33%	28%
Cash
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	2%	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, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 150	$ 137
Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	9
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88	55
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	32
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50	39
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 3	$ 2

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.70%	4.90%	4.50%
Expected return on assets	4.70%	1.90%	1.50%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 2	$ 3
Interest cost	5	3	3
Expected return on assets	(7)	(4)	(4)
Amortization of loss	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	$ (1)	$ 1	$ 2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5%	1.80%	1.40%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 1
Interest cost	1	0	0
Expected return on assets	0	0	0
Amortization of loss	(2)	(1)	(1)
Settlement loss	0	0	0
Net periodic benefit cost	$ 0	$ 0	$ 0
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.29%	2.57%	2.06%
Healthcare cost trend
Initial	6.50%	6.25%	6%
Ultimate in 2030	5.25%	5%	5%

RETIREMENT AND DEFERRED COMPE_8

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	$ 5
2025	5
2026	5
2027	6
2028	6
Years 2029-2033	34
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	2
2025	2
2026	1
2027	1
2028	1
Years 2029-2033	$ 6

REDEMABLE NONCONTROLLING INTE_2

REDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Jun. 12, 2019	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Aggregate issue price of preferred units		$ 224
Net income (loss) attributable to Altus Preferred Unit limited partners			$ 0	$ (70)	$ 162
Altus Midstream LP | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Aggregate issue price of preferred units	$ 625
Proceeds from issuance or sale of equity	$ 611

CAPITAL STOCK AND EQUITY - Addi

CAPITAL STOCK AND EQUITY - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2024 USD ($) $ / shares shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) $ / shares shares	Mar. 01, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, conversion ratio					1
Shares authorized and available for grant (in shares) | shares		9,400,000
Shares Issued in the period (in shares) | shares		0	0	0
Shares exercised in the period (in shares) | shares		12,183	98,646	0
Total stock-settled and cash-settled compensation expensed | $		$ 81	$ 288	$ 152
Stock-settled and cash-settled compensation capitalized | $		$ 13	43	18
Stock Option | In or after 2016
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 | $		$ 70	145	91
Stock-settled and cash-settled compensation capitalized | $		$ 11	$ 22	$ 15
Awards granted during period (in shares) | shares		661,000	847,000	1,506,000
Weighted average grant date fair value per share (in USD per share) | $ / shares		$ 41.60	$ 29.90	$ 16.46
Total compensation cost related to non-vested awards not yet recognized | $		$ 15
Restricted Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Awards granted during period (in shares) | shares	819,836
Weighted average grant date fair value per share (in USD per share) | $ / shares	$ 33.73
Total compensation cost related to non-vested awards not yet recognized | $	$ 28
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares) | shares		1,972,000	2,568,000	4,441,000
Total compensation cost related to non-vested awards not yet recognized | $		$ 54
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares) | shares	2,356,255
Total compensation cost related to non-vested awards not yet recognized | $	$ 80
Award, remeasurement basis (in shares) | shares	1

CAPITAL STOCK AND EQUITY - Desc

CAPITAL STOCK AND EQUITY - Description of Stock Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 81	$ 288	$ 152
Stock-settled and cash-settled compensation capitalized	13	43	18
Share-Based Payment Arrangement, Expensed and Capitalized, Amount	94	331	170
Lease operating expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	27	82	39
Exploration
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	4	13	5
General and administrative
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 50	$ 193	$ 108

CAPITAL STOCK AND EQUITY - Summ

CAPITAL STOCK AND EQUITY - Summary of Stock Options Activities (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning of year, Shares (in shares)	2,078,000	3,012,000	3,537,000
Exercised, Shares (in shares)	(12,183)	(98,646)	0
Forfeited, Shares (in shares)	0	(2,000)	0
Expired, Shares (in shares)	(601,000)	(833,000)	(525,000)
Outstanding, end of year, Shares (in shares)	1,465,000	2,078,000	3,012,000
Expected to vest, Shares (in shares)	0	0	0
Exercisable, end of year, Shares (in shares)	1,465,000	2,078,000	3,012,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding, beginning of year, weighted average exercise price (in USD per share)	$ 57.71	$ 63.79	$ 72.10
Exercised, weighted average exercise price (in USD per share)	42.38	42.09	0
Forfeited, weighted average exercise price (in USD per share)	0	49.10	0
Expired, weighted average exercise price (in USD per share)	80.53	81.56	119.83
Outstanding, end of year, weighted average exercise price (in USD per share)	48.48	57.71	63.79
Expected to vest, weighted average exercise price (in USD per share)	0	0	0
Exercisable, end of year, weighted average exercise price (in USD per share)	$ 48.48	$ 57.71	$ 63.79
Weighted average remaining contractual life for options outstanding	3 years 1 month 6 days
Weighted average remaining contractual life for exercisable	3 years 1 month 6 days
Aggregate intrinsic value for options outstanding	$ 33
Aggregate intrinsic value for options outstanding exercisable	$ 33

CAPITAL STOCK AND EQUITY - Sche

CAPITAL STOCK AND EQUITY - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted Average  Grant-Date  Fair Value
Unvested restricted stock units (in shares)	1,479,880
Weighted-average remaining life of unvested restricted stock units	7 months 6 days
Total fair value of restricted stock awards vested	$ 23	$ 22	$ 25
Restricted Stock
Units
Non-vested, beginning balance (in shares)	1,885,000	2,073,000	1,552,000
Granted, Shares (in shares)	661,000	847,000	1,506,000
Vested, Shares (in shares)	(975,000)	(978,000)	(857,000)
Forfeited, Shares (in shares)	(69,000)	(57,000)	(128,000)
Expired, shares (in shares)	(22,000)	0	0
Non-vested, ending balance (in shares)	1,480,000	1,885,000	2,073,000
Weighted Average  Grant-Date  Fair Value
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 23.08	$ 19.98	$ 28.43
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	41.60	29.90	16.46
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	23.31	22.39	29.13
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	32.44	23.49	19.78
Expired, Weighted Average Grant-Date Fair Value (in USD per share)	27.81	0	0
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 30.69	$ 23.08	$ 19.98
Total compensation cost related to non-vested awards not yet recognized	$ 15
Phantom Units
Units
Non-vested, beginning balance (in shares)	5,709,000	6,402,000	4,423,000
Adjustment from ALTM transaction (in shares)	0	143,000	0
Granted, Shares (in shares)	1,972,000	2,568,000	4,441,000
Vested, Shares (in shares)	(2,851,000)	(2,970,000)	(2,049,000)
Forfeited, Shares (in shares)	(340,000)	(434,000)	(413,000)
Expired, shares (in shares)	(12,000)	0	0
Non-vested, ending balance (in shares)	4,478,000	5,709,000	6,402,000
Weighted Average  Grant-Date  Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 54
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted, Shares (in shares)	1,972,116	2,512,602	4,375,546
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock
Units
Granted, Shares (in shares)		55,546	65,327
Cash-settled conditional restricted stock unit | Performance Program
Units
Non-vested, beginning balance (in shares)	4,835,000	4,531,000	3,417,000
Granted, Shares (in shares)	1,536,000	1,676,000	1,782,000
Vested, Shares (in shares)	(1,593,000)	(656,000)	(76,000)
Forfeited, Shares (in shares)	(99,000)	(106,000)	(240,000)
Non-vested, ending balance (in shares)	4,629,000	4,835,000	4,531,000

CAPITAL STOCK AND EQUITY - Perf

CAPITAL STOCK AND EQUITY - Performance Program Narrative (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Jan. 31, 2024	Jan. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 31, 2023	Jan. 31, 2021	Jan. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)			9,400,000
Compensation expense			$ 81,000	$ 288,000	$ 152,000
Stock-settled and cash-settled compensation capitalized			$ 13,000	$ 43,000	$ 18,000
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)			1,972,000	2,568,000	4,441,000
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,356,255
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			$ 2,000	$ 136,000	$ 56,000
Stock-settled and cash-settled compensation capitalized			$ 100	$ 21,000	$ 3,000
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%
2020 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)								1,687,307
Number of awards outstanding (in shares)			999,896
Shares paid out as percentage of target			155%
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)			1,803,083
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)			1,040,100
2022 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
2022 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)		2,080,200
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)			784,977
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)						1,569,954
2024 Performance Program | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period	3 years
Award, remeasurement basis (in shares)	1
Cash incentive amount	$ 14,000
2024 Performance Program | Minimum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	0
2024 Performance Program | Maximum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 28,000
2024 Performance Program | Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	644,399
2024 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
2024 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)	1,288,798

CAPITAL STOCK AND EQUITY - Sc_2

CAPITAL STOCK AND EQUITY - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Units
Employee-related liabilities, current	$ 390	$ 514
Performance Program | Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	4,835	4,531	3,417
Granted, Shares (in shares)	1,536	1,676	1,782
Vested, Shares (in shares)	(1,593)	(656)	(76)
Forfeited, Shares (in shares)	(99)	(106)	(240)
Expired, Shares (in shares)	(50)	(610)	(352)
Non-vested, ending balance (in shares)	4,629	4,835	4,531
Employee-related liabilities, current	$ 24

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 5,944	$ 3,242	$ 260	$ (645)
Pension and postretirement benefit plan (Note 13)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	15	14	22
AOCI, Parent
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 15	$ 14	$ 22	$ 14

MAJOR CUSTOMERS (Details)

MAJOR CUSTOMERS (Details) - Customer Concentration Risk - Oil and Gas Production Revenues	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	15%	15%	14%
CFE International
Revenue, Major Customer [Line Items]
Concentration risk percentage			10%

BUSINESS SEGMENT INFORMATION -

BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting [Abstract]
Number of reporting segments	3

BUSINESS SEGMENT INFORMATION _2

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Expenses:
Lease operating expenses	[1]	$ 1,397	$ 1,435	$ 1,241
Taxes other than income		192	256	204
Exploration		153	146	127
Depreciation, depletion, and amortization		1,399	1,177	1,360
Asset retirement obligation accretion		116	117	113
Impairments		61	0	208
Total operating expenses		4,374	5,263	5,097
Operating Income (Loss)		3,599	5,620	2,888
Other Income (Expense):
Gain on divestitures, net		8	1,180	67
Losses on previously sold Gulf of Mexico properties		(212)	(157)	(446)
Derivative instrument losses, net		0	(107)	94
Other		26	139	228
General and administrative		(325)	(462)	(357)
Transaction, reorganization, and separation		(15)	(26)	(22)
Financing costs, net		(165)	(313)	(472)
NET INCOME BEFORE INCOME TAXES		2,916	5,874	1,980
Assets		16,944	14,255	14,393
Net Property and Equipment		8,724	7,957	8,060
Additions to Net Property and Equipment		1,911	1,657	1,004
Operating Segments | Egypt
Operating Expenses:
Lease operating expenses		474	526	469
Taxes other than income		0	0	0
Exploration		119	84	63
Depreciation, depletion, and amortization		524	400	524
Asset retirement obligation accretion		0	0	0
Impairments		0		26
Total operating expenses		1,150	1,032	1,094
Operating Income (Loss)		1,879	2,489	991
Other Income (Expense):
Assets		3,503	3,148	2,796
Net Property and Equipment		2,209	1,976	1,720
Additions to Net Property and Equipment		834	695	319
Operating Segments | North Sea
Operating Expenses:
Lease operating expenses		369	404	383
Taxes other than income		0	0	0
Exploration		19	35	34
Depreciation, depletion, and amortization		271	238	270
Asset retirement obligation accretion		76	82	79
Impairments		50		22
Total operating expenses		837	802	827
Operating Income (Loss)		501	756	309
Other Income (Expense):
Assets		1,970	1,911	2,199
Net Property and Equipment		1,628	1,386	1,646
Additions to Net Property and Equipment		131	210	159
Operating Segments | U.S.
Operating Expenses:
Lease operating expenses		554	506	391
Taxes other than income		192	253	190
Exploration		14	24	28
Depreciation, depletion, and amortization		604	537	554
Asset retirement obligation accretion		40	34	30
Impairments		11		0
Total operating expenses		2,386	3,434	3,077
Operating Income (Loss)		1,220	2,368	1,679
Other Income (Expense):
Assets		11,471	9,196	7,700
Net Property and Equipment		4,887	4,595	4,507
Additions to Net Property and Equipment		946	752	523
Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	21	138
Operating Expenses:
Lease operating expenses		0	0	0
Taxes other than income		0	3	14
Exploration		0	0	0
Depreciation, depletion, and amortization		0	2	12
Asset retirement obligation accretion		0	1	4
Impairments		0		160
Total operating expenses		0	11	227
Operating Income (Loss)		0	10	(89)
Other Income (Expense):
Assets		0	0	1,698
Net Property and Equipment		0	0	187
Additions to Net Property and Equipment		0	0	3
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	(19)	(130)
Operating Expenses:
Lease operating expenses		0	(1)	(2)
Taxes other than income		0	0	0
Exploration		1	3	2
Depreciation, depletion, and amortization		0	0	0
Asset retirement obligation accretion		0	0	0
Impairments		0		0
Total operating expenses		1	(16)	(128)
Operating Income (Loss)		(1)	(3)	(2)
Other Income (Expense):
Assets		0	0	0
Net Property and Equipment		0	0	0
Additions to Net Property and Equipment		0	0	0
Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Total revenues	[1]	7,079	9,028	6,498
Operating Expenses:
Cost of goods and services sold	[1]	314	356	264
Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		3,029	3,521	2,085
Operating Expenses:
Cost of goods and services sold		33	22	12
Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		1,338	1,558	1,136
Operating Expenses:
Cost of goods and services sold		52	43	39
Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		2,712	3,952	3,280
Operating Expenses:
Cost of goods and services sold		229	304	309
Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Cost of goods and services sold		0	5	32
Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	(3)	(3)
Operating Expenses:
Cost of goods and services sold		0	(18)	(128)
Purchased oil and gas sales
Segment Reporting Information [Line Items]
Total revenues	[1]	894	1,855	1,487
Operating Expenses:
Cost of goods and services sold	[1]	742	1,776	1,580
Purchased oil and gas sales | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Cost of goods and services sold		0	0	0
Purchased oil and gas sales | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Cost of goods and services sold		0	0	0
Purchased oil and gas sales | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		894	1,850	1,476
Operating Expenses:
Cost of goods and services sold		742	1,776	1,575
Purchased oil and gas sales | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	5	11
Operating Expenses:
Cost of goods and services sold		0	0	5
Purchased oil and gas sales | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Operating Expenses:
Cost of goods and services sold		0	0	0
Oil and gas
Segment Reporting Information [Line Items]
Total revenues		7,973	10,883	7,985
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		3,029	3,521	2,085
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		1,338	1,558	1,136
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		3,606	5,802	4,756
Oil and gas | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues			16	127
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues			(16)	(127)
Oil
Other Income (Expense):
Revenue from non-customers		729	989	420
Oil | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Total revenues		5,759	6,700	4,585
Oil | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		2,683	3,145	1,806
Oil | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		1,073	1,232	929
Oil | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		2,003	2,323	1,850
Oil | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Oil | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural Gas
Other Income (Expense):
Revenue from non-customers		95	117	47
Natural Gas | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Total revenues		860	1,545	1,207
Natural Gas | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		346	370	270
Natural Gas | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		237	281	183
Natural Gas | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		277	894	754
Natural Gas | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural Gas | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural Gas Liquids
Other Income (Expense):
Revenue from non-customers		0	2	2
Natural Gas Liquids | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Total revenues		460	783	706
Natural Gas Liquids | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		0	6	9
Natural Gas Liquids | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		28	45	24
Natural Gas Liquids | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		432	735	676
Natural Gas Liquids | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		0	0	0
Natural Gas Liquids | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		$ 0	$ (3)	$ (3)
[1] (1) For related party transactions associated with Kinetik, refer to Note 7—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, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 7,079	$ 9,031	$ 6,501
Depreciation, depletion, and amortization	1,359	1,130	1,255
Asset retirement obligation accretion	116	116	109
Lease operating expenses	1,397	1,436	1,243
Gathering, processing, and transmission	314	369	360
Exploration expenses	153	146	127
Production taxes	189	252	188
Income tax	1,477	2,083	996
Operating costs	5,005	5,532	4,278
Results of operations	2,074	3,499	2,223
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,712	3,952	3,280
Depreciation, depletion, and amortization	568	508	511
Asset retirement obligation accretion	40	34	30
Lease operating expenses	554	506	391
Gathering, processing, and transmission	229	304	309
Exploration expenses	14	24	28
Production taxes	189	252	188
Income tax	235	488	383
Operating costs	1,829	2,116	1,840
Results of operations	883	1,836	1,440
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	3,029	3,521	2,085
Depreciation, depletion, and amortization	521	390	477
Asset retirement obligation accretion	0	0	0
Lease operating expenses	474	526	469
Gathering, processing, and transmission	33	22	12
Exploration expenses	119	84	63
Production taxes	0	0	0
Income tax	828	1,100	479
Operating costs	1,975	2,122	1,500
Results of operations	1,054	1,399	585
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,338	1,558	1,136
Depreciation, depletion, and amortization	270	232	267
Asset retirement obligation accretion	76	82	79
Lease operating expenses	369	404	383
Gathering, processing, and transmission	52	43	39
Exploration expenses	19	35	34
Production taxes	0	0	0
Income tax	414	495	134
Operating costs	1,200	1,291	936
Results of operations	138	267	200
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [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	1	3	2
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	1	3	2
Results of operations	$ (1)	$ (3)	$ (2)

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 4	$ 22
Proved			$ (157)
Unproved	19	28	29
Exploration	276	237	161
Development	1,978		1,085
Development		1,286
Costs incurred	2,277	1,573	1,118
Capitalized interest		1	0
Asset retirement costs	368	(139)	149
Egypt PSC modernization impacts - Proved and Unproved			(145)
PSC modernization impacts, incremental value			247
PSC modernization impacts, signature bonus			100
PSC modernization impacts, other post closing adjustments			2
Oil and gas proved property
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
PSC modernization impacts, reduction in proved properties			165
Oil and Gas Properties, Unproved
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
PSC modernization impacts, increase in unproved properties			20
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	19
Proved			0
Unproved	19	28	9
Exploration	5	4	6
Development	864		545
Development		775
Costs incurred	888	826	560
Capitalized interest		0	0
Asset retirement costs	(7)	76	130
Egypt PSC modernization impacts - Proved and Unproved			0
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	4	3
Proved			(157)
Unproved	0	0	20
Exploration	226	169	86
Development	646		404
Development		568
Costs incurred	876	740	353
Capitalized interest		0	0
Asset retirement costs	0	0	0
Egypt PSC modernization impacts - Proved and Unproved			(145)
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	44	61	39
Development	468		135
Development		(57)
Costs incurred	512	4	174
Capitalized interest		1	0
Asset retirement costs	375	(215)	19
Egypt PSC modernization impacts - Proved and Unproved			0
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	1	3	30
Development	0		1
Development		0
Costs incurred	1	3	31
Capitalized interest		0	0
Asset retirement costs	$ 0	$ 0	0
Egypt PSC modernization impacts - Proved and Unproved			$ 0

SUPPLEMENTAL OIL AND GAS DISC_5

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Reserve Quantities [Line Items]
Proved properties	$ 43,058	$ 40,949
Unproved properties	291	296
Capitalized costs, gross	43,349	41,245
Accumulated DD&A	(34,917)	(33,576)
Capitalized costs, net	8,432	7,669
United States
Reserve Quantities [Line Items]
Proved properties	19,809	18,990
Unproved properties	217	208
Capitalized costs, gross	20,026	19,198
Accumulated DD&A	(15,390)	(14,846)
Capitalized costs, net	4,636	4,352
Egypt
Reserve Quantities [Line Items]
Proved properties	13,777	13,014
Unproved properties	71	77
Capitalized costs, gross	13,848	13,091
Accumulated DD&A	(11,678)	(11,157)
Capitalized costs, net	2,170	1,934
North Sea
Reserve Quantities [Line Items]
Proved properties	9,472	8,945
Unproved properties	3	11
Capitalized costs, gross	9,475	8,956
Accumulated DD&A	(7,849)	(7,573)
Capitalized costs, net	1,626	1,383
Other International
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	0	0
Capitalized costs, gross	0	0
Accumulated DD&A	0	0
Capitalized costs, net	$ 0	$ 0

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, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf	Dec. 31, 2021 MBoe MBbls MMcf	Dec. 31, 2020 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Proved developed reserves	707,964	780,319	827,772	797,843
Proved undeveloped reserves	65,581	75,183	85,190	75,840
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	855,502	912,962	873,683
Extensions, discoveries and other additions	95,695	33,805	101,619
Purchases of minerals in-place		1,020	457
Revisions of previous estimates	(36,223)	74,894	107,038
Production	(140,598)	(141,179)	(141,642)
Sales of minerals in-place	(831)	(26,000)	(28,193)
Ending balance	773,545	855,502	912,962
United States
Reserve Quantities [Line Items]
Proved developed reserves	472,459	509,827	551,384	532,994
Proved undeveloped reserves	59,891	63,115	65,288	53,408
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	572,942	616,672	586,402
Extensions, discoveries and other additions	79,123	21,592	76,871
Purchases of minerals in-place		1,020	457
Revisions of previous estimates	(46,824)	33,588	64,847
Production	(72,060)	(73,930)	(83,712)
Sales of minerals in-place	(831)	(26,000)	(28,193)
Ending balance	532,350	572,942	616,672
Egypt
Reserve Quantities [Line Items]
Proved developed reserves	165,162	174,633	184,563	164,870
Proved undeveloped reserves	5,690	8,735	12,683	13,449
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	183,368	197,246	178,319
Extensions, discoveries and other additions	15,344	9,278	21,765
Purchases of minerals in-place		0	0
Revisions of previous estimates	24,490	29,647	39,071
Production	(52,350)	(52,803)	(41,909)
Sales of minerals in-place	0	0	0
Ending balance	170,852	183,368	197,246
North Sea
Reserve Quantities [Line Items]
Proved developed reserves	70,343	95,859	91,825	99,979
Proved undeveloped reserves	0	3,333	7,219	8,983
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	99,192	99,044	108,962
Extensions, discoveries and other additions	1,228	2,935	2,983
Purchases of minerals in-place		0	0
Revisions of previous estimates	(13,889)	11,659	3,120
Production	(16,188)	(14,446)	(16,021)
Sales of minerals in-place	0	0	0
Ending balance	70,343	99,192	99,044
Noncontrolling Interests | Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) | MBoe	84	99	66	59
Crude Oil and Condensate
Reserve Quantities [Line Items]
Proved developed reserves	331,292	359,447	364,687	389,483
Proved undeveloped reserves	34,266	27,651	34,928	44,017
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	387,098	399,615	433,500
Extensions, discoveries and other additions	50,633	19,972	33,547
Purchases of minerals in-place		522	126
Revisions of previous estimates	(435)	41,501	18,188
Production	(70,963)	(67,087)	(66,364)
Sales of minerals in-place	(775)	(7,425)	(19,382)
Ending balance	365,558	387,098	399,615
Crude Oil and Condensate | United States
Reserve Quantities [Line Items]
Proved developed reserves	167,911	168,817	180,968	206,936
Proved undeveloped reserves	29,012	16,221	18,168	25,516
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	185,038	199,136	232,452
Extensions, discoveries and other additions	37,353	9,776	17,869
Purchases of minerals in-place		522	126
Revisions of previous estimates	1,062	7,170	(4,479)
Production	(25,755)	(24,141)	(27,450)
Sales of minerals in-place	(775)	(7,425)	(19,382)
Ending balance	196,923	185,038	199,136
Crude Oil and Condensate | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	102,305	108,050	106,646	95,981
Proved undeveloped reserves	5,254	8,557	11,003	11,228
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	116,607	117,649	107,209
Extensions, discoveries and other additions	12,979	7,580	13,390
Purchases of minerals in-place		0	0
Revisions of previous estimates	10,505	22,433	22,727
Production	(32,532)	(31,055)	(25,677)
Sales of minerals in-place	0	0	0
Ending balance	107,559	116,607	117,649
Crude Oil and Condensate | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	61,076	82,580	77,073	86,566
Proved undeveloped reserves	0	2,873	5,757	7,273
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	85,453	82,830	93,839
Extensions, discoveries and other additions	301	2,616	2,288
Purchases of minerals in-place		0	0
Revisions of previous estimates	(12,002)	11,898	(60)
Production	(12,676)	(11,891)	(13,237)
Sales of minerals in-place	0	0	0
Ending balance	61,076	85,453	82,830
Crude Oil and Condensate | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	53,000	62,000	39,000	36,000
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed reserves	147,078	155,229	166,677	153,368
Proved undeveloped reserves	16,413	15,474	16,685	15,587
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	170,703	183,362	168,955
Extensions, discoveries and other additions	21,198	5,501	21,143
Purchases of minerals in-place		233	191
Revisions of previous estimates	(7,107)	10,281	22,862
Production	(21,270)	(22,334)	(24,806)
Sales of minerals in-place	(33)	(6,340)	(4,983)
Ending balance	163,491	170,703	183,362
Natural Gas Liquids | United States
Reserve Quantities [Line Items]
Proved developed reserves	145,618	152,999	164,172	150,599
Proved undeveloped reserves	16,413	15,398	16,380	15,141
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	168,397	180,552	165,740
Extensions, discoveries and other additions	20,827	5,456	21,055
Purchases of minerals in-place		233	191
Revisions of previous estimates	(6,343)	10,355	22,724
Production	(20,817)	(21,859)	(24,175)
Sales of minerals in-place	(33)	(6,340)	(4,983)
Ending balance	162,031	168,397	180,552
Natural Gas Liquids | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	0	0	446	716
Proved undeveloped reserves	0	0	30	126
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	476	842
Extensions, discoveries and other additions	0	0	7
Purchases of minerals in-place		0	0
Revisions of previous estimates	0	(407)	(180)
Production	0	(69)	(193)
Sales of minerals in-place	0	0	0
Ending balance	0	0	476
Natural Gas Liquids | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	1,460	2,230	2,059	2,053
Proved undeveloped reserves	0	76	275	320
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	2,306	2,334	2,373
Extensions, discoveries and other additions	371	45	81
Purchases of minerals in-place		0	0
Revisions of previous estimates	(764)	333	318
Production	(453)	(406)	(438)
Sales of minerals in-place	0	0	0
Ending balance	1,460	2,306	2,334
Natural Gas Liquids | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves			159	281
Natural Gas
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,377,561	1,593,860	1,778,442	1,529,950
Proved undeveloped reserves | MMcf	89,412	192,348	201,464	97,417
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,786,208	1,979,906	1,627,367
Extensions, discoveries and other additions | MMcf	143,177	49,991	281,577
Purchases of minerals in-place | MMcf		1,592	839
Revisions of previous estimates | MMcf	(172,089)	138,675	395,924
Production | MMcf	(290,187)	(310,546)	(302,833)
Sales of minerals in-place | MMcf	(136)	(73,410)	(22,968)
Ending balance | MMcf	1,466,973	1,786,208	1,979,906
Natural Gas | United States
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	953,578	1,128,066	1,237,461	1,052,756
Proved undeveloped reserves | MMcf	86,800	188,976	184,441	76,504
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,317,042	1,421,902	1,129,260
Extensions, discoveries and other additions | MMcf	125,654	38,157	227,684
Purchases of minerals in-place | MMcf		1,592	839
Revisions of previous estimates | MMcf	(249,257)	96,381	279,610
Production | MMcf	(152,925)	(167,580)	(192,523)
Sales of minerals in-place | MMcf	(136)	(73,410)	(22,968)
Ending balance | MMcf	1,040,378	1,317,042	1,421,902
Natural Gas | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	377,144	399,502	464,826	409,035
Proved undeveloped reserves | MMcf	2,612	1,068	9,899	12,572
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	400,570	474,725	421,607
Extensions, discoveries and other additions | MMcf	14,188	10,191	50,209
Purchases of minerals in-place		0	0
Revisions of previous estimates	83,907	45,725	99,143
Production	(118,909)	(130,071)	(96,234)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	379,756	400,570	474,725
Natural Gas | North Sea
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	46,839	66,292	76,155	68,159
Proved undeveloped reserves | MMcf	0	2,304	7,124	8,341
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	68,596	83,279	76,500
Extensions, discoveries and other additions | MMcf	3,335	1,643	3,684
Purchases of minerals in-place		0	0
Revisions of previous estimates	(6,739)	(3,431)	17,171
Production	(18,353)	(12,895)	(14,076)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	46,839	68,596	83,279
Natural Gas | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	188,000	224,000	158,000	141,000

SUPPLEMENTAL OIL AND GAS DISC_7

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) MBoe in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($) MBoe	Dec. 31, 2023 MBoe	Dec. 31, 2022 MBoe	Dec. 31, 2021 MBoe
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		96	34	102
Revision of previous estimate		36	75	107
PSCs, discounted future net cash flows | $	$ 750
PSCs, percentage of reserves consolidated	96%
Percentage of estimated proved developed reserves classified as proved not producing		10%
Changes in Product Prices
Reserve Quantities [Line Items]
Revision of previous estimate		83	5	85
Changes in Engineering and Performance
Reserve Quantities [Line Items]
Revision of previous estimate		47	70	22
Production Sharing Contracts Modernization Impact
Reserve Quantities [Line Items]
Revision of previous estimate			43
Other Revisions
Reserve Quantities [Line Items]
Revision of previous estimate			9	35
Production Sharing Contracts Modernization Impact, Developed Reserves
Reserve Quantities [Line Items]
Revision of previous estimate	53
Production Sharing Contracts Modernization Impact, Undeveloped Reserves
Reserve Quantities [Line Items]
Revision of previous estimate	4
North America
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		79	22	77
Permian Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		67	9	59
Sale of mineral in place			26	28
Texas Gulf Coast
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		10	8	18
Delaware Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		2	5
Purchase of mineral in place			1
International Regions
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		16	12	25
Egypt
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		15	9	22
Egypt | Other Revisions
Reserve Quantities [Line Items]
Revision of previous estimate				57
North Sea
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		1	3	3
United States | Changes in Engineering and Performance
Reserve Quantities [Line Items]
Revision of previous estimate			18

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 35,745	$ 52,456	$ 39,021
Production costs	(12,324)	(15,548)	(12,378)
Development costs	(5,878)	(5,366)	(5,567)
Income tax expense	(4,104)	(6,749)	(2,789)
Net cash flows	13,439	24,793	18,287
10 percent discount rate	(4,001)	(8,026)	(5,927)
Discounted future net cash flows	$ 9,438	16,767	12,360
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	$ 13,000	21,700	14,900
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	20,063	29,490	22,852
Production costs	(7,861)	(10,221)	(8,323)
Development costs	(2,182)	(1,598)	(1,632)
Income tax expense	(936)	(1,389)	(134)
Net cash flows	9,084	16,282	12,763
10 percent discount rate	(3,534)	(6,422)	(5,294)
Discounted future net cash flows	5,550	9,860	7,469
Egypt
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	9,921	12,819	9,337
Production costs	(1,690)	(2,086)	(1,712)
Development costs	(1,235)	(1,471)	(1,402)
Income tax expense	(2,222)	(2,729)	(1,887)
Net cash flows	4,774	6,533	4,336
10 percent discount rate	(943)	(1,400)	(983)
Discounted future net cash flows	3,831	5,133	3,353
Egypt | Noncontrolling Interests
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	1,800	2,500	1,600
North Sea
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	5,761	10,147	6,832
Production costs	(2,773)	(3,241)	(2,343)
Development costs	(2,461)	(2,297)	(2,533)
Income tax expense	(946)	(2,631)	(768)
Net cash flows	(419)	1,978	1,188
10 percent discount rate	476	(204)	350
Discounted future net cash flows	$ 57	$ 1,774	$ 1,538

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Sales, net of production costs	$ (5,176)	$ (6,970)	$ (4,707)
Net change in prices and production costs	(6,699)	8,627	9,376
Discoveries and improved recovery, net of related costs	1,633	1,132	1,749
Change in future development costs	(415)	(347)	(839)
Previously estimated development costs incurred during the period	707	669	545
Revision of quantities	(127)	2,621	1,983
Purchases of minerals in-place	0	17	1
Accretion of discount	2,167	1,489	626
Change in income taxes	1,374	(2,371)	(1,583)
Sales of minerals in-place	(18)	(363)	(116)
Change in production rates and other	(775)	(97)	13
Change in the discounted future net cash flows, Total	$ (7,329)	$ 4,407	$ 7,048