APA APA Corporation

Derivative instrument gains (losses), net

$ 0

$ (44)

$ 104

$ (138)

Gain on divestitures, net

1,180

Other, net

(2)

107

Total revenues and other

2,309

2,872

6,300

9,752

General and administrative

Lease operating expenses

394

364

1,076

1,067

Taxes other than income

163

230

Exploration

144

193

139

276

314

Transaction, reorganization, and separation

Depreciation, depletion, and amortization

418

310

1,117

879

Asset retirement obligation accretion

Impairments

Financing costs, net

235

303

Total operating expenses

1,476

1,700

3,957

4,820

NET INCOME BEFORE INCOME TAXES

833

1,172

2,343

4,932

Current income tax provision

422

357

1,022

1,164

Deferred income tax provision (benefit)

(144)

285

(22)

225

NET INCOME INCLUDING NONCONTROLLING INTERESTS

555

530

1,343

3,543

Net loss attributable to Altus Preferred Unit limited partners

(70)

NET INCOME ATTRIBUTABLE TO COMMON STOCK

$ 459

$ 422

$ 1,082

$ 3,231

NET INCOME PER COMMON SHARE:

Basic (in USD per share)

$ 1.49

$ 1.28

$ 3.50

$ 9.54

Diluted (in USD per share)

$ 1.49

$ 1.28

$ 3.50

$ 9.51

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:

Basic (in shares)

308

329

309

339

Diluted (in shares)

308

330

309

340

Noncontrolling interest – Egypt

Noncontrolling interest - Altus

$ 96

$ 108

$ 261

$ 368

Oil and gas

Gathering, processing, and transmission costs

Total revenues

2,308

2,887

6,112

8,603

Oil, natural gas, and natural gas liquids production revenues

^[1]

2,079

2,302

5,500

7,147

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

245

274

Purchased oil and gas sales

Purchased oil and gas sales

^[1]

229

585

612

1,456

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

$ 211

$ 573

$ 558

$ 1,452

[1]	For transactions associated with Kinetik, refer to Note 6—Equity Method Interests for further detail.

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 555	$ 530	$ 1,343	$ 3,543
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	0	0	3	(1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	555	530	1,346	3,542
Comprehensive loss attributable to Altus Preferred Unit limited partners	0	0	0	(70)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	459	422	1,085	3,230
Noncontrolling interest – Egypt
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income attributable to noncontrolling interest	96	108	261	368
Noncontrolling interest - Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income attributable to noncontrolling interest	$ 0	$ 0	$ 0	$ 14

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$ 1,343	$ 3,543
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	(61)	119
Gain on divestitures, net	(7)	(1,180)
Exploratory dry hole expense and unproved leasehold impairments	91	129
Depreciation, depletion, and amortization	1,117	879
Asset retirement obligation accretion	86	87
Impairments	46	0
Provision for (benefit from) deferred income taxes	(22)	225
(Gain) loss on extinguishment of debt	(9)	67
Other, net	(45)	(91)
Changes in operating assets and liabilities:
Receivables	(289)	(554)
Inventories	19	(81)
Drilling advances and other current assets	40	7
Deferred charges and other long-term assets	227	(3)
Accounts payable	(2)	175
Accrued expenses	1	249
Deferred credits and noncurrent liabilities	(436)	(41)
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,099	3,530
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(1,747)	(1,168)
Acquisition of Delaware Basin properties	(24)	(563)
Leasehold and property acquisitions	(11)	(30)
Proceeds from sale of oil and gas properties	29	778
Proceeds from sale of Kinetik shares	0	224
Deconsolidation of Altus cash and cash equivalents	0	(143)
Other, net	(29)	8
NET CASH USED IN INVESTING ACTIVITIES	(1,782)	(894)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) revolving credit facilities, net	202	(22)
Payments on Apache fixed-rate debt	(65)	(1,370)
Distributions to noncontrolling interest – Egypt	(154)	(237)
Treasury stock activity, net	(208)	(884)
Dividends paid to APA common stockholders	(232)	(127)
Other, net	(10)	(30)
NET CASH USED IN FINANCING ACTIVITIES	(467)	(2,670)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(150)	(34)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	245	302
CASH AND CASH EQUIVALENTS AT END OF PERIOD	95	268
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	278	274
Income taxes paid, net of refunds	$ 867	$ 1,029

CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 95	$ 245
Receivables, net of allowance of $103 and $117	1,753	1,466
Other current assets (Note 5)	952	997
Total current assets	2,800	2,708
PROPERTY AND EQUIPMENT:
Oil and gas properties	43,908	42,356
Gathering, processing, and transmission facilities	447	449
Other	613	613
Less: Accumulated depreciation, depletion, and amortization	(35,468)	(34,406)
Property and equipment, net	9,500	9,012
OTHER ASSETS:
Equity method interests (Note 6)	681	624
Decommissioning security for sold Gulf of Mexico properties (Note 11)	38	217
Deferred charges and other	526	586
Assets	13,545	13,147
CURRENT LIABILITIES:
Accounts payable	741	771
Current debt	2	2
Other current liabilities (Note 7)	1,892	2,143
Total current liabilities	2,635	2,916
LONG-TERM DEBT (Note 9)	5,582	5,451
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	305	314
Asset retirement obligation (Note 8)	2,006	1,940
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	470	738
Other	440	443
Total deferred credits and other noncurrent liabilities	3,221	3,435
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 420,593,611 and 419,869,987 shares issued, respectively	263	262
Paid-in capital	11,197	11,420
Accumulated deficit	(4,732)	(5,814)
Treasury stock, at cost, 113,797,342 and 108,310,838 shares, respectively	(5,667)	(5,459)
Accumulated other comprehensive income	17	14
APA SHAREHOLDERS’ EQUITY	1,078	423
TOTAL EQUITY	2,107	1,345
TOTAL LIABILITIES AND EQUITY	13,545	13,147
Noncontrolling interest – Egypt
EQUITY:
Noncontrolling interest – Egypt	$ 1,029	$ 922

CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Receivables, allowance	$ 103	$ 117
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	860,000,000	860,000,000
Common stock, shares issued (in shares)	420,593,611	419,869,987
Treasury stock, shares (in shares)	113,797,342	108,310,838

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) - USD ($)
$ in Millions

Total

Noncontrolling interest – Egypt

Noncontrolling interest - Altus

APA SHAREHOLDERS’ EQUITY

Common Stock

Paid-In Capital

Accumulated Deficit

Treasury Stock

Accumulated Other Comprehensive Income

Noncontrolling Interests

Noncontrolling interest – Egypt

Noncontrolling Interests

Noncontrolling interest - Altus

^[1]

Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners

Beginning balance at Dec. 31, 2021

^[1]

$ 712

Increase (Decrease) in Temporary Equity [Roll Forward]

Net loss attributable to Altus Preferred Unit limited partners

^[1]

(70)

Deconsolidation of Altus

$ (72)

(642)

^[1]

Beginning balance at Dec. 31, 2021

^[1]

$ (717)

$ (1,595)

$ 262

$ 11,645

$ (9,488)

$ (4,036)

$ 22

$ 878

^[1]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

3,231

$ 368

^[1]

(237)

^[1]

(165)

Deconsolidation of Altus

(72)

$ (72)

(642)

^[1]

(884)

(1)

1,551

600

262

11,494

(6,257)

(4,920)

951

^[2]

Beginning balance at Jun. 30, 2022

^[1]

$ 0

1,505

584

262

11,567

(6,679)

(4,587)

921

^[2]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

422

108

^[2]

(78)

^[2]

(80)

(333)

Beginning balance at Dec. 31, 2022

1,551

600

262

11,494

(6,257)

(4,920)

951

^[2]

1,345

423

262

11,420

(5,814)

(5,459)

922

^[1]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

1,082

261

^[1]

(154)

^[1]

(232)

(208)

Ending balance at Sep. 30, 2023

2,107

1,078

263

11,197

(4,732)

(5,667)

1,029

^[2]

Beginning balance at Jun. 30, 2023

1,696

709

263

11,267

(5,191)

(5,647)

987

^[2]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

459

$ 0

^[2]

$ (54)

^[2]

(77)

(20)

Ending balance at Sep. 30, 2023

$ 2,107

$ 1,078

$ 263

$ 11,197

$ (4,732)

$ (5,667)

$ 17

$ 1,029

^[2]

[1]	As a result of the BCP Business Combination (as defined herein), the Company deconsolidated Altus (as defined herein) on February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail.
[2]	As a result of the BCP Business Combination (as defined herein), the Company deconsolidated Altus (as defined herein) on February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail.

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) (Parenthetical) - $ / shares	3 Months Ended			9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Jun. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.25	$ 0.125	$ 0.75	$ 0.50

NATURE OF OPERATIONS	9 Months Ended
NATURE OF OPERATIONS	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS	These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, which contains a summary of the Company’s significant accounting policies and other disclosures.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Sep. 30, 2023
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES As of September 30, 2023, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or 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 APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail. Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom. Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). Refer to Note 4—Derivative Instruments and Hedging Activities, Note 6—Equity Method Interests, and Note 9—Debt and Financing Costs for further detail regarding the Company’s fair value measurements recorded on a recurring basis. During the three and nine months ended September 30, 2023 and 2022, the Company recorded no asset impairments in connection with fair value assessments. Revenue Recognition There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days 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 Egyptian General Petroleum Corporation (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 longer-than-usual 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. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment. 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. 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 the second quarter of 2023, the Company recorded $46 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. 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. 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. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.

ACQUISITIONS AND DIVESTITURES	9 Months Ended
ACQUISITIONS AND DIVESTITURES	Sep. 30, 2023
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2023 Activity During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $1 million and $11 million, respectively. During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions. 2022 Activity During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations. During the third quarter and first nine months of 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $3 million and $30 million, respectively. During the third quarter and first nine months of 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $37 million and $52 million, respectively, recognizing a gain of approximately $34 million and $36 million, respectively, upon closing of these transactions. During the first nine months of 2022, the Company completed a transaction to sell 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 share of ALTM’s deconsolidated balance sheet of $193 million and the fair value of $802 million of its approximate 20 percent retained ownership in the combined entity. During the first quarter of 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and recognized a loss of $25 million, including transaction fees. Refer to Note 6—Equity Method Interests for further detail.

CAPITALIZED EXPLORATORY WELL COSTS	9 Months Ended
CAPITALIZED EXPLORATORY WELL COSTS	Sep. 30, 2023
Extractive Industries [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	CAPITALIZED EXPLORATORY WELL COSTS The Company’s capitalized exploratory well costs were $541 million and $474 million as of September 30, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity offshore Suriname and in Egypt. Approximately $5 million of suspended well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the third quarter of 2023. Projects with suspended 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 proved reserves can be attributed to these projects.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

Counterparty Risk

Derivative Instruments

Commodity Derivative Instruments

As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2023	NYMEX Henry Hub/IF Waha	18,400	$(1.15)	—	—
October—December 2023	NYMEX Henry Hub/IF HSC	—	—	18,400	$(0.08)
January—June 2024	NYMEX Henry Hub/IF Waha	16,380	$(1.15)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	16,380	$(0.10)

Fair Value Measurements

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
September 30, 2023
Assets:
Commodity derivative instruments	$	—	$	16	$	—	$	16	$	—	$	16






December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5
Liabilities:
Commodity derivative instruments	—		50		—		50		—		50

Derivative Activity Recorded in the Consolidated Balance Sheet


	September 30, 2023		December 31, 2022

	(In millions)
Current Assets: Other current assets	$	16	$	—
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	16	$	5

Current Liabilities: Other current liabilities	$	—	$	50

Total derivative liabilities	$	—	$	50

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 Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Realized:
Commodity derivative instruments	$	19	$	(2)	$	43	$	(11)
Foreign currency derivative instruments	—		(6)		—		(8)
Realized gains (losses), net	19		(8)		43		(19)
Unrealized:
Commodity derivative instruments	(19)		(35)		61		(79)

Foreign currency derivative instruments	—		(1)		—		(9)
Preferred Units embedded derivative	—		—		—		(31)
Unrealized gains (losses), net	(19)		(36)		61		(119)
Derivative instrument gains (losses), net	$	—	$	(44)	$	104	$	(138)

OTHER CURRENT ASSETS

9 Months Ended

Sep. 30, 2023

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets:


	September 30, 2023		December 31, 2022

	(In millions)
Inventories	$	443	$	427
Drilling advances	87		89

Prepaid assets and other	49		31
Current decommissioning security for sold Gulf of Mexico assets	373		450
Total Other current assets	$	952	$	997

EQUITY METHOD INTERESTS

9 Months Ended

Sep. 30, 2023

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

The following table represents sales and costs associated with Kinetik:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Natural gas and NGLs sales	$	35	$	—	$	78	$	—
Purchased oil and gas sales	11		—		18		—
	$	46	$	—	$	96	$	—

Gathering, processing, and transmission costs	$	26	$	28	$	81	$	64
Purchased oil and gas costs	37		—		65		—
	$	63	$	28	$	146	$	64

As of September 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $43 million and receivables from Kinetik of approximately $29 million.

OTHER CURRENT LIABILITIES

9 Months Ended

Sep. 30, 2023

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities:


	September 30, 2023		December 31, 2022

	(In millions)
Accrued operating expenses	$	161	$	145
Accrued exploration and development	328		333
Accrued compensation and benefits	379		514
Accrued interest	66		97
Accrued income taxes	228		90
Current asset retirement obligation	55		55
Current operating lease liability	108		167

Current decommissioning contingency for sold Gulf of Mexico properties	225		450
Other	342		292
Total Other current liabilities	$	1,892	$	2,143

ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 2023

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability:


	September 30, 2023
	(In millions)
Asset retirement obligation, December 31, 2022	$	1,995
Liabilities incurred	14

Liabilities settled	(34)



Accretion expense	86

Asset retirement obligation, September 30, 2023	2,061
Less current portion	(55)
Asset retirement obligation, long-term	$	2,006

DEBT AND FINANCING COSTS

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

The following table presents the carrying values of the Company’s debt:


	September 30, 2023		December 31, 2022

	(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	4,835	$	4,908

Syndicated credit facilities(2)	768		566
Apache finance lease obligations	33		34
Unamortized discount	(26)		(27)
Debt issuance costs	(26)		(28)
Total debt	5,584		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,582	$	5,451

(1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively.

(2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.

At each of September 30, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations.

Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Interest expense	$	89	$	80	$	266	$	249
Amortization of debt issuance costs	1		1		3		8
Capitalized interest	(7)		(5)		(18)		(13)
(Gain) loss on extinguishment of debt	—		—		(9)		67
Interest income	(2)		(1)		(7)		(8)
Financing costs, net	$	81	$	75	$	235	$	303

INCOME TAXES	9 Months Ended
INCOME TAXES	Sep. 30, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXESThe Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur. During the third quarter of 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing 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. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability. 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 (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023. The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded. The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.

COMMITMENTS AND CONTINGENCIES	9 Months Ended
COMMITMENTS AND CONTINGENCIES	Sep. 30, 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 September 30, 2023, the Company has an accrued liability of approximately $49 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. For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. 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 As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, 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. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims. Apollo Exploration Lawsuit In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th 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 is subject to court approval and is expected to be finalized by the end of 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 November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. 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 January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, 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 April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, 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 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 As of September 30, 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. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. 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 notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. The Company is not aware of any environmental claims existing as of September 30, 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 September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several 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, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. 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 further 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 effectively use its available cash to fund the deficit. As of September 30, 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 $695 million to $895 million 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 $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 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 September 30, 2023, the Company has also recorded a $411 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, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.” 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 281st 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 281st 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). Apache intends to vigorously defend these claims, and will vigorously pursue its counterclaims.

CAPITAL STOCK

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

CAPITAL STOCK

Net Income per Common Share

The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements:


	For the Quarter Ended September 30,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	459	308	$	1.49	$	422	329	$	1.28
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	—	$	—	1	$	—

Diluted:
Income attributable to common stock	$	459	308	$	1.49	$	422	330	$	1.28
	For the Nine Months Ended September 30,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,082	309	$	3.50	$	3,231	339	$	9.54
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	—	$	—	1	$	(0.03)

Diluted:
Income attributable to common stock	$	1,082	309	$	3.50	$	3,231	340	$	9.51

Stock Repurchase Program

The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions.

Common Stock Dividend

During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.

BUSINESS SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total
	Upstream

For the Quarter Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	724	$	348	$	633	$	—	$	—	$	1,705
Natural gas revenues	81		66		89		—		—		236
Natural gas liquids revenues	—		5		133		—		—		138
Oil, natural gas, and natural gas liquids production revenues	805		419		855		—		—		2,079
Purchased oil and gas sales	—		—		229		—		—		229

	805		419		1,084		—		—		2,308
Operating Expenses:
Lease operating expenses	128		102		164		—		—		394
Gathering, processing, and transmission	13		15		61		—		—		89
Purchased oil and gas costs	—		—		211		—		—		211
Taxes other than income	—		—		61		—		—		61
Exploration	25		9		4		—		11		49
Depreciation, depletion, and amortization	129		90		199		—		—		418
Asset retirement obligation accretion	—		20		9		—		—		29

	295		236		709		—		11		1,251
Operating Income (Loss)(2)	$	510	$	183	$	375	$	—	$	(11)	1,057

Other Income (Expense):


Gain on divestitures, net											1

General and administrative											(139)
Transaction, reorganization, and separation											(5)
Financing costs, net											(81)
Income Before Income Taxes											$	833


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	1,971	$	865	$	1,631	$	—	$	—	$	4,467
Natural gas revenues	264		165		229		—		—		658
Natural gas liquids revenues	—		19		356		—		—		375
Oil, natural gas, and natural gas liquids production revenues	2,235		1,049		2,216		—		—		5,500
Purchased oil and gas sales	—		—		612		—		—		612

	2,235		1,049		2,828		—		—		6,112
Operating Expenses:
Lease operating expenses	346		278		452		—		—		1,076
Gathering, processing, and transmission	26		38		181		—		—		245
Purchased oil and gas costs	—		—		558		—		—		558
Taxes other than income	—		—		163		—		—		163
Exploration	91		18		10		—		25		144
Depreciation, depletion, and amortization	378		209		530		—		—		1,117
Asset retirement obligation accretion	—		57		29		—		—		86
Impairments	—		46		—		—		—		46
	841		646		1,923		—		25		3,435
Operating Income (Loss)(2)	$	1,394	$	403	$	905	$	—	$	(25)	2,677

Other Income (Expense):
Derivative instrument gains, net											104

Gain on divestitures, net											7
Other, net											77
General and administrative											(276)
Transaction, reorganization, and separation											(11)
Financing costs, net											(235)
Income Before Income Taxes											$	2,343

Total Assets(3)	$	3,518	$	1,665	$	7,827	$	—	$	535	$	13,545


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Quarter Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	739	$	303	$	630	$	—	$	—	$	1,672
Natural gas revenues	84		44		300		—		—		428
Natural gas liquids revenues	—		5		197		—		—		202
Oil, natural gas, and natural gas liquids production revenues	823		352		1,127		—		—		2,302
Purchased oil and gas sales	—		—		585		—		—		585

	823		352		1,712		—		—		2,887
Operating Expenses:
Lease operating expenses	119		107		138		—		—		364
Gathering, processing, and transmission	5		7		87		—		—		99
Purchased oil and gas costs	—		—		573		—		—		573
Taxes other than income	—		—		82		—		—		82
Exploration	29		1		16		—		49		95
Depreciation, depletion, and amortization	97		52		161		—		—		310
Asset retirement obligation accretion	—		21		8		—		—		29

	250		188		1,065		—		49		1,552
Operating Income (Loss)(2)	$	573	$	164	$	647	$	—	$	(49)	1,335

Other Income (Expense):

Derivative instrument losses, net											(44)
Gain on divestitures, net											31
Other, net											(2)
General and administrative											(69)
Transaction, reorganization, and separation											(4)
Financing costs, net											(75)
Income Before Income Taxes											$	1,172


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	2,431	$	938	$	1,883	$	—	$	—	$	5,252
Natural gas revenues	270		207		764		—		—		1,241
Natural gas liquids revenues	6		33		618		—		(3)		654
Oil, natural gas, and natural gas liquids production revenues	2,707		1,178		3,265		—		(3)		7,147
Purchased oil and gas sales	—		—		1,451		5		—		1,456
Midstream service affiliate revenues	—		—		—		16		(16)		—
	2,707		1,178		4,716		21		(19)		8,603
Operating Expenses:
Lease operating expenses	381		321		366		—		(1)		1,067
Gathering, processing, and transmission	15		31		241		5		(18)		274
Purchased oil and gas costs	—		—		1,452		—		—		1,452
Taxes other than income	—		—		227		3		—		230
Exploration	56		8		21		—		108		193
Depreciation, depletion, and amortization	285		168		424		2		—		879
Asset retirement obligation accretion	—		61		25		1		—		87

	737		589		2,756		11		89		4,182
Operating Income (Loss)(2)	$	1,970	$	589	$	1,960	$	10	$	(108)	4,421

Other Income (Expense):
Derivative instrument losses, net											(138)

Gain on divestitures, net											1,180
Other, net											107
General and administrative											(314)
Transaction, reorganization, and separation											(21)
Financing costs, net											(303)
Income Before Income Taxes											$	4,932


Total Assets(3)	$	3,242	$	2,185	$	7,675	$	—	$	527	$	13,629

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Oil	$	202	$	227	$	539	$	779
Natural gas	23		26		73		87
Natural gas liquids	—		—		—		2

(3)Intercompany balances are excluded from total assets.

(4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Sep. 30, 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 ACCOUNTING POLICIES (Policies)	9 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Sep. 30, 2023
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or 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 APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. 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.
Use of Estimates	Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
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 There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days 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 Egyptian General Petroleum Corporation (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 longer-than-usual 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. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment. 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.
Inventories	Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
Property and Equipment	Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
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. 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. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. 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.
Gathering, Processing, and Transmission (GPT) Facilities	Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Positions

As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2023	NYMEX Henry Hub/IF Waha	18,400	$(1.15)	—	—
October—December 2023	NYMEX Henry Hub/IF HSC	—	—	18,400	$(0.08)
January—June 2024	NYMEX Henry Hub/IF Waha	16,380	$(1.15)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	16,380	$(0.10)

Schedule of Derivative Assets Measured at Fair Value

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
September 30, 2023
Assets:
Commodity derivative instruments	$	—	$	16	$	—	$	16	$	—	$	16






December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5
Liabilities:
Commodity derivative instruments	—		50		—		50		—		50

Schedule of Derivative Liabilities Measured at Fair Value

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
September 30, 2023
Assets:
Commodity derivative instruments	$	—	$	16	$	—	$	16	$	—	$	16






December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5
Liabilities:
Commodity derivative instruments	—		50		—		50		—		50

Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations

The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	September 30, 2023		December 31, 2022

	(In millions)
Current Assets: Other current assets	$	16	$	—
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	16	$	5

Current Liabilities: Other current liabilities	$	—	$	50

Total derivative liabilities	$	—	$	50

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 Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Realized:
Commodity derivative instruments	$	19	$	(2)	$	43	$	(11)
Foreign currency derivative instruments	—		(6)		—		(8)
Realized gains (losses), net	19		(8)		43		(19)
Unrealized:
Commodity derivative instruments	(19)		(35)		61		(79)

Foreign currency derivative instruments	—		(1)		—		(9)
Preferred Units embedded derivative	—		—		—		(31)
Unrealized gains (losses), net	(19)		(36)		61		(119)
Derivative instrument gains (losses), net	$	—	$	(44)	$	104	$	(138)

OTHER CURRENT ASSETS (Tables)

9 Months Ended

Sep. 30, 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:


	September 30, 2023		December 31, 2022

	(In millions)
Inventories	$	443	$	427
Drilling advances	87		89

Prepaid assets and other	49		31
Current decommissioning security for sold Gulf of Mexico assets	373		450
Total Other current assets	$	952	$	997

EQUITY METHOD INTERESTS (Tables)

9 Months Ended

Sep. 30, 2023

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investment Information

The following table represents sales and costs associated with Kinetik:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Natural gas and NGLs sales	$	35	$	—	$	78	$	—
Purchased oil and gas sales	11		—		18		—
	$	46	$	—	$	96	$	—

Gathering, processing, and transmission costs	$	26	$	28	$	81	$	64
Purchased oil and gas costs	37		—		65		—
	$	63	$	28	$	146	$	64

OTHER CURRENT LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2023

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities:


	September 30, 2023		December 31, 2022

	(In millions)
Accrued operating expenses	$	161	$	145
Accrued exploration and development	328		333
Accrued compensation and benefits	379		514
Accrued interest	66		97
Accrued income taxes	228		90
Current asset retirement obligation	55		55
Current operating lease liability	108		167

Current decommissioning contingency for sold Gulf of Mexico properties	225		450
Other	342		292
Total Other current liabilities	$	1,892	$	2,143

ASSET RETIREMENT OBLIGATION (Tables)

9 Months Ended

Sep. 30, 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:


	September 30, 2023
	(In millions)
Asset retirement obligation, December 31, 2022	$	1,995
Liabilities incurred	14

Liabilities settled	(34)



Accretion expense	86

Asset retirement obligation, September 30, 2023	2,061
Less current portion	(55)
Asset retirement obligation, long-term	$	2,006

DEBT AND FINANCING COSTS (Tables)

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the carrying values of the Company’s debt:


	September 30, 2023		December 31, 2022

	(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	4,835	$	4,908

Syndicated credit facilities(2)	768		566
Apache finance lease obligations	33		34
Unamortized discount	(26)		(27)
Debt issuance costs	(26)		(28)
Total debt	5,584		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,582	$	5,451

(1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively.

(2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.

Schedule of Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Interest expense	$	89	$	80	$	266	$	249
Amortization of debt issuance costs	1		1		3		8
Capitalized interest	(7)		(5)		(18)		(13)
(Gain) loss on extinguishment of debt	—		—		(9)		67
Interest income	(2)		(1)		(7)		(8)
Financing costs, net	$	81	$	75	$	235	$	303

CAPITAL STOCK (Tables)

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

Schedule Reconciliation of the Components of Basic and Diluted Net Income Per Common Share

The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements:


	For the Quarter Ended September 30,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	459	308	$	1.49	$	422	329	$	1.28
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	—	$	—	1	$	—

Diluted:
Income attributable to common stock	$	459	308	$	1.49	$	422	330	$	1.28
	For the Nine Months Ended September 30,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,082	309	$	3.50	$	3,231	339	$	9.54
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	—	$	—	1	$	(0.03)

Diluted:
Income attributable to common stock	$	1,082	309	$	3.50	$	3,231	340	$	9.51

BUSINESS SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

Schedule of Financial Segment Information

Financial information for each segment is presented below:


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total
	Upstream

For the Quarter Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	724	$	348	$	633	$	—	$	—	$	1,705
Natural gas revenues	81		66		89		—		—		236
Natural gas liquids revenues	—		5		133		—		—		138
Oil, natural gas, and natural gas liquids production revenues	805		419		855		—		—		2,079
Purchased oil and gas sales	—		—		229		—		—		229

	805		419		1,084		—		—		2,308
Operating Expenses:
Lease operating expenses	128		102		164		—		—		394
Gathering, processing, and transmission	13		15		61		—		—		89
Purchased oil and gas costs	—		—		211		—		—		211
Taxes other than income	—		—		61		—		—		61
Exploration	25		9		4		—		11		49
Depreciation, depletion, and amortization	129		90		199		—		—		418
Asset retirement obligation accretion	—		20		9		—		—		29

	295		236		709		—		11		1,251
Operating Income (Loss)(2)	$	510	$	183	$	375	$	—	$	(11)	1,057

Other Income (Expense):


Gain on divestitures, net											1

General and administrative											(139)
Transaction, reorganization, and separation											(5)
Financing costs, net											(81)
Income Before Income Taxes											$	833


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	1,971	$	865	$	1,631	$	—	$	—	$	4,467
Natural gas revenues	264		165		229		—		—		658
Natural gas liquids revenues	—		19		356		—		—		375
Oil, natural gas, and natural gas liquids production revenues	2,235		1,049		2,216		—		—		5,500
Purchased oil and gas sales	—		—		612		—		—		612

	2,235		1,049		2,828		—		—		6,112
Operating Expenses:
Lease operating expenses	346		278		452		—		—		1,076
Gathering, processing, and transmission	26		38		181		—		—		245
Purchased oil and gas costs	—		—		558		—		—		558
Taxes other than income	—		—		163		—		—		163
Exploration	91		18		10		—		25		144
Depreciation, depletion, and amortization	378		209		530		—		—		1,117
Asset retirement obligation accretion	—		57		29		—		—		86
Impairments	—		46		—		—		—		46
	841		646		1,923		—		25		3,435
Operating Income (Loss)(2)	$	1,394	$	403	$	905	$	—	$	(25)	2,677

Other Income (Expense):
Derivative instrument gains, net											104

Gain on divestitures, net											7
Other, net											77
General and administrative											(276)
Transaction, reorganization, and separation											(11)
Financing costs, net											(235)
Income Before Income Taxes											$	2,343

Total Assets(3)	$	3,518	$	1,665	$	7,827	$	—	$	535	$	13,545


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Quarter Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	739	$	303	$	630	$	—	$	—	$	1,672
Natural gas revenues	84		44		300		—		—		428
Natural gas liquids revenues	—		5		197		—		—		202
Oil, natural gas, and natural gas liquids production revenues	823		352		1,127		—		—		2,302
Purchased oil and gas sales	—		—		585		—		—		585

	823		352		1,712		—		—		2,887
Operating Expenses:
Lease operating expenses	119		107		138		—		—		364
Gathering, processing, and transmission	5		7		87		—		—		99
Purchased oil and gas costs	—		—		573		—		—		573
Taxes other than income	—		—		82		—		—		82
Exploration	29		1		16		—		49		95
Depreciation, depletion, and amortization	97		52		161		—		—		310
Asset retirement obligation accretion	—		21		8		—		—		29

	250		188		1,065		—		49		1,552
Operating Income (Loss)(2)	$	573	$	164	$	647	$	—	$	(49)	1,335

Other Income (Expense):

Derivative instrument losses, net											(44)
Gain on divestitures, net											31
Other, net											(2)
General and administrative											(69)
Transaction, reorganization, and separation											(4)
Financing costs, net											(75)
Income Before Income Taxes											$	1,172


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	2,431	$	938	$	1,883	$	—	$	—	$	5,252
Natural gas revenues	270		207		764		—		—		1,241
Natural gas liquids revenues	6		33		618		—		(3)		654
Oil, natural gas, and natural gas liquids production revenues	2,707		1,178		3,265		—		(3)		7,147
Purchased oil and gas sales	—		—		1,451		5		—		1,456
Midstream service affiliate revenues	—		—		—		16		(16)		—
	2,707		1,178		4,716		21		(19)		8,603
Operating Expenses:
Lease operating expenses	381		321		366		—		(1)		1,067
Gathering, processing, and transmission	15		31		241		5		(18)		274
Purchased oil and gas costs	—		—		1,452		—		—		1,452
Taxes other than income	—		—		227		3		—		230
Exploration	56		8		21		—		108		193
Depreciation, depletion, and amortization	285		168		424		2		—		879
Asset retirement obligation accretion	—		61		25		1		—		87

	737		589		2,756		11		89		4,182
Operating Income (Loss)(2)	$	1,970	$	589	$	1,960	$	10	$	(108)	4,421

Other Income (Expense):
Derivative instrument losses, net											(138)

Gain on divestitures, net											1,180
Other, net											107
General and administrative											(314)
Transaction, reorganization, and separation											(21)
Financing costs, net											(303)
Income Before Income Taxes											$	4,932


Total Assets(3)	$	3,242	$	2,185	$	7,675	$	—	$	527	$	13,629

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022

	(In millions)
Oil	$	202	$	227	$	539	$	779
Natural gas	23		26		73		87
Natural gas liquids	—		—		—		2

(3)Intercompany balances are excluded from total assets.

(4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	3 Months Ended			9 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Schedule Of Significant Accounting Policies [Line Items]
Other asset impairments	$ 0		$ 0	$ 0	$ 0
Receivables from contracts with customer, net	$ 1,600,000,000			$ 1,600,000,000		$ 1,300,000,000
Inventory write-down		$ 46,000,000
Kinetik
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	10.00%			10.00%
Sinopec \| Apache Egypt
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	33.33%			33.33%
Third-Party Investors \| ALTM
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	21.00%			21.00%

ACQUISITIONS AND DIVESTITURES (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
	Feb. 22, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Feb. 21, 2022
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties					$ 29	$ 778
Acquisition of delaware basin properties					24	563
Deconsolidation gain	$ 609
Deconsolidation, net amount of balance sheet	193
Equity method interests			$ 681		$ 681		$ 624
Kinetik
Business Acquisition [Line Items]
Equity method interests	$ 802
Shares sold (in shares)		4
Proceeds from sale of stock		$ 224
Loss on disposition of stock		$ 25
Kinetik
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners			10.00%		10.00%
Apache Midstream LLC \| ALTM
Business Acquisition [Line Items]
Ownership percentage by parent								79.00%
BCP Business Combination \| ALTM \| ALTM
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners	20.00%
BCP Business Combination \| ALTM \| Class C Common Stock
Business Acquisition [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares)	50
BCP Business Combination \| BCP Business Combination Contributor \| Kinetik
Business Acquisition [Line Items]
Ownership percentage by parent	75.00%
Non-Core Assets And Leasehold \| Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties			$ 1	$ 37	$ 29	52
Gain on sale of non-core assets			1	34	7	36
Non-Core Mineral Rights \| Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties						726
Gain on sale of non-core assets						560
Permian Basin
Business Acquisition [Line Items]
Oil and gas property acquisitions consideration payment			$ 1		$ 11
Payments to acquire leasehold and property				3		30
Delaware Basin
Business Acquisition [Line Items]
Oil and gas property acquisitions consideration payment				615
Asset acquisition, proved properties amount				581		581
Asset acquisition, unproved leasehold amount				38		38
Asset acquisition, abandonment obligations				$ 4		$ 4

CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 541	$ 474
Exploratory well costs capitalized for a period greater than one year		$ 5

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	9 Months Ended
	Sep. 30, 2023 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative counterparties	7

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Open natural Gas Financial Basis Swap Contracts (Details) - Natural gas revenues MMBTU in Thousands	9 Months Ended
	Sep. 30, 2023 $ / MMBTU MMBTU
Basis Swap Purchased \| October—December 2023 \| NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	18,400
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(1.15)
Basis Swap Purchased \| January—June 2024 \| NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	16,380
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(1.15)
Basis Swap Sold \| October—December 2023 \| NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	18,400
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(0.08)
Basis Swap Sold \| January—June 2024 \| NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	16,380
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(0.10)

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Assets:
Derivative asset	$ 16	$ 5
Liabilities:
Derivative liability	0	50
Commodity derivative instruments
Assets:
Derivative asset, fair value	16	5
Derivative asset, netting	0	0
Derivative asset	16	5
Liabilities:
Derivative liability, fair value		50
Derivative liability, netting		0
Derivative liability		50
Quoted Price in Active Markets (Level 1) \| Commodity derivative instruments
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value		0
Significant Other Inputs (Level 2) \| Commodity derivative instruments
Assets:
Derivative asset, fair value	16	5
Liabilities:
Derivative liability, fair value		50
Significant Unobservable Inputs (Level 3) \| Commodity derivative instruments
Assets:
Derivative asset, fair value	$ 0	0
Liabilities:
Derivative liability, fair value		$ 0

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Current	Other Liabilities, Current
Recurring
Derivatives, Fair Value [Line Items]
Derivative asset	$ 16	$ 5
Derivative liability	0	50
Recurring \| Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	16	0
Recurring \| Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0	$ 5

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net			$ 61	$ (119)
Derivative instrument gains (losses), net	$ 0	$ (44)	104	(138)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	19	(8)	43	(19)
Unrealized gains (losses), net	(19)	(36)	61	(119)
Derivative instrument gains (losses), net	0	(44)	104	(138)
Commodity derivative instruments \| Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	19	(2)	43	(11)
Unrealized gains (losses), net	(19)	(35)	61	(79)
Foreign currency derivative instruments \| Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	(6)	0	(8)
Unrealized gains (losses), net	0	(1)	0	(9)
Preferred Units embedded derivative \| Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ 0	$ 0	$ (31)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 443	$ 427
Drilling advances	87	89
Prepaid assets and other	49	31
Current decommissioning security for sold Gulf of Mexico assets	373	450
Total Other current assets	$ 952	$ 997

EQUITY METHOD INTERESTS - Narrative (Details) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended			9 Months Ended
	Mar. 31, 2022 USD ($) shares	Sep. 30, 2023 USD ($) shares	Sep. 30, 2022 USD ($)	Jun. 30, 2022 shares	Sep. 30, 2023 USD ($) shares	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)	Feb. 22, 2022 shares
Schedule of Equity Method Investments [Line Items]
Accounts payable		$ 741			$ 741		$ 771
Receivables		$ 1,753			$ 1,753		$ 1,466
Kinetik
Schedule of Equity Method Investments [Line Items]
Equity method investment, number of shares (in shares) \| shares		20.2		17.7	20.2			12.9
Shares sold (in shares) \| shares	4.0
Loss on sale of stock	$ 25
Dividends paid-in-kind (in shares) \| shares					2.5
Interest percentage		14.00%			14.00%
Gains (losses) on changes in fair value of equity method interest		$ (14)	$ (17)		$ 57	$ 49
Accounts payable		43			43
Receivables		$ 29			$ 29
Kinetik \| Kinetik
Schedule of Equity Method Investments [Line Items]
Stock split conversion ratio				2

EQUITY METHOD INTERESTS - Sales and Costs Associated with Equity Method Interest (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2023

Sep. 30, 2022

Sep. 30, 2023

Sep. 30, 2022

Kinetik

Schedule of Equity Method Investments [Line Items]

Sales

$ 46

$ 0

$ 96

$ 0

Natural gas and NGLs sales | Kinetik

146

Schedule of Equity Method Investments [Line Items]

Sales

Gathering, processing, and transmission costs

Schedule of Equity Method Investments [Line Items]

Gathering, processing, and transmission costs | Kinetik

^[1]

245

274

Schedule of Equity Method Investments [Line Items]

Purchased oil and gas sales

Schedule of Equity Method Investments [Line Items]

Purchased oil and gas sales | Kinetik

^[1]

211

573

558

1,452

Schedule of Equity Method Investments [Line Items]

Sales