10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q 

(Mark One)  

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2023

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _________

Commission File Number: 1-40144

APA CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	86-1430562
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.625 par value	APA	Nasdaq Global Select Market

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Number of shares of registrant’s common stock outstanding as of October 31, 2023 306,719,421 

TABLE OF CONTENTS

Item		Page
	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME	2
	STATEMENT OF CONSOLIDATED CASH FLOWS	3
	CONSOLIDATED BALANCE SHEET	4
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
4.	CONTROLS AND PROCEDURES	44
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	45
1A.	RISK FACTORS	45
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45
5.	OTHER INFORMATION	45
6.	EXHIBITS	46

FORWARD-LOOKING STATEMENTS AND RISKS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations and capital returns framework, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2022, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:

•changes in local, regional, national, and international economic conditions, including as a result of any epidemics or pandemics, such as the coronavirus disease (COVID-19) pandemic and any related variants;

•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;

•the Company’s commodity hedging arrangements;

•the supply and demand for oil, natural gas, NGLs, and other products or services;

•production and reserve levels;

•drilling risks;

•economic and competitive conditions, including market and macro-economic disruptions resulting from the Russian war in Ukraine, the armed conflict in Israel and Gaza, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the impact of changes in tax legislation;

•the availability of goods and services;

•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;

•legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;

•the Company’s performance on environmental, social, and governance measures;

•terrorism or cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

•the Company’s ability to access the capital markets;

•market-related risks, such as general credit, liquidity, and interest-rate risks;

•the benefits derived from the operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022);

•other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022;

•other risks and uncertainties disclosed in the Company’s third-quarter 2023 earnings release;

•other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q; and

•other factors disclosed in the other filings that the Company makes with the Securities and Exchange Commission.

Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.

DEFINITIONS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:

“3-D” means three-dimensional.

“4-D” means four-dimensional.

“b/d” means barrels of oil or NGLs per day.

“bbl” or “bbls” means barrel or barrels of oil or NGLs.

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.

“boe/d” means boe per day.

“Btu” means a British thermal unit, a measure of heating value.

“Liquids” means oil and NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means the United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

With respect to information relating to the Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.

References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.

PART I – FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)	$	2,079	$	2,302	$	5,500	$	7,147
Purchased oil and gas sales(1)	229		585		612		1,456
Total revenues	2,308		2,887		6,112		8,603
Derivative instrument gains (losses), net	—		(44)		104		(138)
Gain on divestitures, net	1		31		7		1,180
Other, net	—		(2)		77		107
	2,309		2,872		6,300		9,752
OPERATING EXPENSES:
Lease operating expenses	394		364		1,076		1,067
Gathering, processing, and transmission(1)	89		99		245		274
Purchased oil and gas costs(1)	211		573		558		1,452
Taxes other than income	61		82		163		230
Exploration	49		95		144		193
General and administrative	139		69		276		314
Transaction, reorganization, and separation	5		4		11		21
Depreciation, depletion, and amortization	418		310		1,117		879
Asset retirement obligation accretion	29		29		86		87
Impairments	—		—		46		—
Financing costs, net	81		75		235		303
	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 income attributable to noncontrolling interest – Egypt	96		108		261		368
Net income attributable to noncontrolling interest – Altus	—		—		—		14
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	$	1.49	$	1.28	$	3.50	$	9.54
Diluted	$	1.49	$	1.28	$	3.50	$	9.51
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	308		329		309		339
Diluted	308		330		309		340

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

The accompanying notes to consolidated financial statements are an integral part of this statement.

1

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$	555	$	530	$	1,343	$	3,543
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	—		—		3		(1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	555		530		1,346		3,542
Comprehensive income attributable to noncontrolling interest – Egypt	96		108		261		368
Comprehensive income attributable to noncontrolling interest – Altus	—		—		—		14
Comprehensive loss attributable to Altus Preferred Unit limited partners	—		—		—		(70)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	459	$	422	$	1,085	$	3,230

The accompanying notes to consolidated financial statements are an integral part of this statement.

2

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)

	For the Nine Months Ended September 30,
	2023		2022
	(In millions)
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		—
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	—		224
Deconsolidation of Altus cash and cash equivalents	—		(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

The accompanying notes to consolidated financial statements are an integral part of this statement.

3

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	September 30, 2023		December 31, 2022
	(In millions, except share data)
ASSETS
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
	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)
	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
	$	13,545	$	13,147
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	741	$	771
Current debt	2		2
Other current liabilities (Note 7)	1,892		2,143
	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
	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
Noncontrolling interest – Egypt	1,029		922
TOTAL EQUITY	2,107		1,345
	$	13,545	$	13,147

The accompanying notes to consolidated financial statements are an integral part of this statement.

4

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS

(Unaudited)

	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY		Noncontrolling Interests(1)		TOTAL EQUITY
	(In millions)
For the Quarter Ended September 30, 2022
Balance at June 30, 2022	$	—	$	262	$	11,567	$	(6,679)	$	(4,587)	$	21	$	584	$	921	$	1,505
Net income attributable to common stock	—		—		—		422		—		—		422		—		422
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		108		108
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(78)		(78)
Common dividends declared ($0.25 per share)	—		—		(80)		—		—		—		(80)		—		(80)
Treasury stock activity, net	—		—		—		—		(333)		—		(333)		—		(333)
Other	—		—		7		—		—		—		7		—		7
Balance at September 30, 2022	$	—	$	262	$	11,494	$	(6,257)	$	(4,920)	$	21	$	600	$	951	$	1,551
For the Quarter Ended September 30, 2023
Balance at June 30, 2023	$	—	$	263	$	11,267	$	(5,191)	$	(5,647)	$	17	$	709	$	987	$	1,696
Net income attributable to common stock	—		—		—		459		—		—		459		—		459
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		96		96
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(54)		(54)
Common dividends declared ($0.25 per share)	—		—		(77)		—		—		—		(77)		—		(77)
Treasury stock activity, net	—		—		—		—		(20)		—		(20)		—		(20)
Other	—		—		7		—		—		—		7		—		7
Balance at September 30, 2023	$	—	$	263	$	11,197	$	(4,732)	$	(5,667)	$	17	$	1,078	$	1,029	$	2,107

(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.

The accompanying notes to consolidated financial statements are an integral part of this statement.

5

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS - Continued

(Unaudited)

	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Nine Months Ended September 30, 2022
Balance at December 31, 2021	$	712	$	262	$	11,645	$	(9,488)	$	(4,036)	$	22	$	(1,595)	$	878	$	(717)
Net income attributable to common stock	—						3,231		—		—		3,231		—		3,231
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		368		368
Net income attributable to noncontrolling interest – Altus	—		—		—		—		—		—		—		14		14
Net loss attributable to Altus Preferred Unit limited partners	(70)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(237)		(237)
Common dividends declared ($0.50 per share)	—		—		(165)		—		—		—		(165)		—		(165)
Deconsolidation of Altus	(642)		—		—		—		—		—		—		(72)		(72)
Treasury stock activity, net	—		—		—		—		(884)		—		(884)		—		(884)
Other	—		—		14		—		—		(1)		13		—		13
Balance at September 30, 2022	$	—	$	262	$	11,494	$	(6,257)	$	(4,920)	$	21	$	600	$	951	$	1,551
For the Nine Months Ended September 30, 2023
Balance at December 31, 2022	$	—	$	262	$	11,420	$	(5,814)	$	(5,459)	$	14	$	423	$	922	$	1,345
Net income attributable to common stock	—		—		—		1,082		—		—		1,082		—		1,082
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		261		261
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(154)		(154)
Common dividends declared ($0.75 per share)	—		—		(232)		—		—		—		(232)		—		(232)
Treasury stock activity, net	—		—		—		—		(208)		—		(208)		—		(208)
Other	—		1		9		—		—		3		13		—		13
Balance at September 30, 2023	$	—	$	263	$	11,197	$	(4,732)	$	(5,667)	$	17	$	1,078	$	1,029	$	2,107

(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.

The accompanying notes to consolidated financial statements are an integral part of this statement.

6

APA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

1.    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.

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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.

8

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.

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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.

2.    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.

10

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.

3.    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.

4.    DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.

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Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023, the Company had derivative positions with seven counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.

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

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

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The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.

Derivative Activity Recorded in the Consolidated Balance Sheet

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:

	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)

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”

5.    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

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6.    EQUITY METHOD INTERESTS

The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.

The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares.

The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock.

The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49 million in the first nine months of 2023 and 2022, respectively. These gains and losses were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.

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.

7.    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

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8.    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

9.    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.

The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(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.

During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

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On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023, there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

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

10.    INCOME TAXES

The 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.

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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.

11.    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.

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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.

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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.

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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.

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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.

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12.    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

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.7 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.5 million during the first nine months of 2023 and 2022, respectively.

Stock Repurchase Program

During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock.

In the third quarter of 2023, the Company repurchased approximately 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share, and as of September 30, 2023, the Company had remaining authorization to repurchase up to 47.1 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share.

The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares.

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

For the quarters ended September 30, 2023 and 2022, the Company paid $77 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127 million, respectively, in dividends on its common stock.

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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.

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13.    BUSINESS SEGMENT INFORMATION

As of September 30, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. 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

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	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

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	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

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	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

(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022.

(3)Intercompany balances are excluded from total assets.

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

27

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

Overview

APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries. Prior to the BCP Business Combination (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.

The global economy and the energy industry continue to be impacted by the effects of ongoing international conflicts and the coronavirus disease 2019 (COVID-19) pandemic. Uncertainties in the global supply chain and financial markets, including the impact of inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

APA’s diversified asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. The Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices during the year but are accelerating completion of eight Permian Basin wells and adding a drilling rig in the Delaware Basin in the fourth quarter of 2023. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. The Company anticipates its full-year 2023 upstream capital investment will be approximately $2 billion. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

In the third quarter of 2023, the Company reported net income attributable to common stock of $459 million, or $1.49 per diluted share, compared to net income of $422 million, or $1.28 per diluted share, in the third quarter of 2022. Results for the third quarter of 2022 were impacted by higher deferred income tax expense related to remeasurement of the Company’s deferred tax liability from increases in the U.K. energy profits levy.

In the first nine months of 2023, the Company reported net income attributable to common stock of $1.1 billion, or $3.50 per diluted share, compared to net income of $3.2 billion, or $9.51 per diluted share, in the first nine months of 2022. Net income for the first nine months of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the first nine months of 2022. Results from the first nine months of 2022 included approximately $1.2 billion of transaction gains recognized for divesting certain non-core mineral rights in the Delaware Basin and completing the BCP Business Combination.

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The Company generated $2.1 billion of cash from operating activities during the first nine months of 2023, 41 percent lower than the first nine months of 2022. APA’s lower operating cash flows for the first nine months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 5.5 million shares of its common stock for $208 million and paid $232 million in dividends to APA common stockholders during the first nine months of 2023.

The Company remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns.

•The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.

•The Company’s quarterly dividend was increased in the third quarter of 2022 from $0.125 per share to $0.25 per share, representing a return to pre-COVID-19 dividend levels.

•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2023, the Company had repurchased 72.9 million shares of the Company’s common stock. The Company repurchased 0.4 million shares in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares under the Company’s share repurchase programs.

Operational Highlights

Key operational highlights for the quarter include:

United States

•Daily boe production from the Company’s U.S. assets accounted for 55 percent of its total production during the third quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including three rigs in the Southern Midland Basin and two rigs in the Delaware Basin, and drilled and brought online 15 operated wells in the quarter. The Company has contracted a sixth Permian Basin rig, with plans to commence drilling in the fourth quarter of 2023. The Company’s core Midland Basin development program and recently acquired properties in the Delaware Basin continue to represent key growth areas for the U.S. assets.

International

•In Egypt, the Company continued its drilling and workover activity with a heavier focus on oil prospects. The Company averaged 18 drilling rigs and drilled 26 new productive wells during the third quarter of 2023. Third quarter 2023 gross equivalent production in the Company’s Egypt assets increased 2 percent from the third quarter of 2022, and net production decreased 3 percent. The Company averaged 20 workover rigs during the quarter and expects to increase workover activity over the next two quarters.

•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program there is now directed toward safety, base production management, and asset maintenance and integrity.

•During the quarter, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58, offshore Suriname. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an oil production capacity of 200,000 b/d. Detailed engineering studies are anticipated to start by year-end 2023, and a final investment decision is expected by year-end 2024 with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.

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Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

Revenue

The Company’s production revenues and respective contribution to total revenues by country were as follows:

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2023				2022				2023				2022
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	633	37	%	$	630	38	%	$	1,631	37	%	$	1,883	36	%
Egypt(1)	724		43	%	739		44	%	1,971		44	%	2,431		46	%
North Sea	348		20	%	303		18	%	865		19	%	938		18	%
Total(1)	$	1,705	100	%	$	1,672	100	%	$	4,467	100	%	$	5,252	100	%
Natural Gas Revenues:
United States	$	89	38	%	$	300	70	%	$	229	35	%	$	764	62	%
Egypt(1)	81		34	%	84		20	%	264		40	%	270		22	%
North Sea	66		28	%	44		10	%	165		25	%	207		16	%
Total(1)	$	236	100	%	$	428	100	%	$	658	100	%	$	1,241	100	%
NGL Revenues:
United States	$	133	96	%	$	197	98	%	$	356	95	%	$	615	94	%
Egypt(1)	—		—	%	—		—	%	—		—	%	6		1	%
North Sea	5		4	%	5		2	%	19		5	%	33		5	%
Total(1)	$	138	100	%	$	202	100	%	$	375	100	%	$	654	100	%
Oil and Gas Revenues:
United States	$	855	41	%	$	1,127	49	%	$	2,216	40	%	$	3,262	46	%
Egypt(1)	805		39	%	823		36	%	2,235		41	%	2,707		38	%
North Sea	419		20	%	352		15	%	1,049		19	%	1,178		16	%
Total(1)	$	2,079	100	%	$	2,302	100	%	$	5,500	100	%	$	7,147	100	%

(1)    Includes revenues attributable to a noncontrolling interest in Egypt.

30

Production

The Company’s production volumes by country were as follows:

	For the Quarter Ended September 30,			For the Nine Months Ended September 30,
	2023	Increase (Decrease)	2022	2023	Increase (Decrease)	2022
Oil Volume (b/d)
United States	83,584	16%	72,351	77,198	12%	68,926
Egypt(1)(2)	88,521	9%	81,095	88,038	5%	83,857
North Sea	35,680	42%	25,160	36,070	17%	30,928
Total	207,785	16%	178,606	201,306	10%	183,711
Natural Gas Volume (Mcf/d)
United States	454,643	(7)%	489,107	448,838	(5)%	474,777
Egypt(1)(2)	300,326	(6)%	318,945	331,158	(5)%	350,400
North Sea	65,168	246%	18,822	47,665	43%	33,291
Total	820,137	(1)%	826,874	827,661	(4)%	858,468
NGL Volume (b/d)
United States	66,280	2%	64,958	61,418	(1)%	61,990
Egypt(1)(2)	—	NM	—	—	NM	261
North Sea	1,497	168%	558	1,209	12%	1,080
Total	67,777	3%	65,516	62,627	(1)%	63,331
BOE per day(3)
United States	225,639	3%	218,826	213,423	2%	210,045
Egypt(1)(2)	138,575	3%	134,253	143,231	1%	142,518
North Sea(4)	48,038	66%	28,855	45,222	20%	37,557
Total	412,252	8%	381,934	401,876	3%	390,120

(1)    Gross oil, natural gas, and NGL production in Egypt were as follows:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2023	2022	2023	2022
Oil (b/d)	144,528	133,607	141,995	136,476
Natural Gas (Mcf/d)	472,744	510,260	511,430	554,268
NGL (b/d)	—	—	—	397

(2)    Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2023	2022	2023	2022
Oil (b/d)	29,514	27,082	29,369	27,971
Natural Gas (Mcf/d)	100,122	106,553	110,476	116,869
NGL (b/d)	—	—	—	87

(3)    The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

(4)    Average sales volumes from the North Sea for the third quarters of 2023 and 2022 were 55,283 boe/d and 36,467 boe/d, respectively, and 47,370 boe/d and 39,362 boe/d for the first nine months of 2023 and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

NM — Not Meaningful

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Pricing

The Company’s average selling prices by country were as follows:

	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2023		Increase (Decrease)	2022		2023		Increase (Decrease)	2022
Average Oil Price – Per barrel
United States	$	82.33	(13)%	$	94.62	$	77.40	(23)%	$	100.06
Egypt	88.99		(10)%	99.04		82.04		(23)%	106.19
North Sea	87.70		(14)%	101.85		83.25		(21)%	105.59
Total	86.15		(12)%	97.81		80.50		(22)%	103.81
Average Natural Gas Price – Per Mcf
United States	$	2.12	(68)%	$	6.67	$	1.87	(68)%	$	5.89
Egypt	2.91		1%	2.87		2.92		4%	2.82
North Sea	10.98		(54)%	24.12		12.83		(48)%	24.59
Total	3.12		(44)%	5.62		2.91		(45)%	5.31
Average NGL Price – Per barrel
United States	$	21.87	(34)%	$	32.97	$	21.24	(42)%	$	36.36
Egypt	—		NM	—		—		NM	76.80
North Sea	42.78		(39)%	70.42		47.58		(35)%	72.86
Total	22.26		(33)%	33.39		21.85		(42)%	37.47

NM — Not Meaningful

Third-Quarter 2023 compared to Third-Quarter 2022

Crude Oil Crude oil revenues for the third quarter of 2023 totaled $1.7 billion, a $33 million increase from the comparative 2022 quarter. A 16 percent higher average daily production increased revenues by $233 million compared to the prior-year quarter, while 12 percent decrease in average realized prices decreased third-quarter 2023 oil revenues by $200 million. Crude oil revenues accounted for 82 percent of total oil and gas production revenues and 50 percent of worldwide production in the third quarter of 2023. Crude oil prices realized in the third quarter of 2023 averaged $86.15 per barrel, compared with $97.81 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production increased 29.2 Mb/d to 207.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity in the U.S. and Egypt, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the third quarter of 2023 totaled $236 million, a $192 million decrease from the comparative 2022 quarter. A 44 percent decrease in average realized prices decreased third-quarter 2023 natural gas revenues by $191 million compared to the prior-year quarter, while 1 percent lower average daily production decreased revenues by $1 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2023. The Company’s worldwide natural gas production decreased 6.8 MMcf/d to 820.1 MMcf/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., offset by increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea.

NGL NGL revenues for the third quarter of 2023 totaled $138 million, a $64 million decrease from the comparative 2022 quarter. A 33 percent decrease in average realized prices decreased third-quarter 2023 NGL revenues by $67 million compared to the prior-year quarter, while 3 percent higher average daily production increased revenues by $3 million. NGL revenues accounted for 7 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2023. The Company’s worldwide NGL production increased 2.3 Mb/d to 67.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline.

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Year-to-Date 2023 compared to Year-to-Date 2022

Crude Oil Crude oil revenues for the first nine months of 2023 totaled $4.5 billion, a $785 million decrease from the comparative 2022 period. A 22 percent decrease in average realized prices decreased oil revenues for the 2023 period by approximately $1.2 billion compared to the prior-year period, while 10 percent higher average daily production increased revenues by $394 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2023. Crude oil prices realized during the first nine months of 2023 averaged $80.50 per barrel, compared to $103.81 per barrel in the comparative prior-year period.

The Company’s worldwide oil production increased 17.6 Mb/d to 201.3 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the first nine months of 2023 totaled $658 million, a $583 million decrease from the comparative 2022 period. A 45 percent decrease in average realized prices decreased natural gas revenues for the 2023 period by $560 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $23 million compared to the prior-year period. Natural gas revenues accounted for 12 percent of total oil and gas production revenues and 34 percent of worldwide production for the first nine months of 2023. The Company’s worldwide natural gas production decreased 30.8 MMcf/d to 827.7 MMcf/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.

NGL NGL revenues for the first nine months of 2023 totaled $375 million, a $279 million decrease from the comparative 2022 period. A 42 percent decrease in average realized prices decreased NGL revenues for the 2023 period by $273 million compared to the prior-year period, while 1 percent lower average daily production decreased revenues by $6 million compared to the prior-year period. NGL revenues accounted for 7 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2023. The Company’s worldwide NGL production decreased 0.7 Mb/d to 63 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $229 million and $585 million during the third quarters of 2023 and 2022, respectively, and $612 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $211 million and $573 million during the third quarters of 2023 and 2022, respectively, and $558 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in the third quarter and the first nine months of 2023, primarily due to lower average natural gas prices during the 2023 periods.

33

Operating Expenses

The Company’s operating expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(In millions)
Lease operating expenses	$	394	$	364	$	1,076	$	1,067
Gathering, processing, and transmission	89		99		245		274
Purchased oil and gas costs	211		573		558		1,452
Taxes other than income	61		82		163		230
Exploration	49		95		144		193
General and administrative	139		69		276		314
Transaction, reorganization, and separation	5		4		11		21
Depreciation, depletion, and amortization:
Oil and gas property and equipment	407		300		1,086		847
Gathering, processing, and transmission assets	2		4		5		10
Other assets	9		6		26		22
Asset retirement obligation accretion	29		29		86		87
Impairments	—		—		46		—
Financing costs, net	81		75		235		303
Total Operating Expenses	$	1,476	$	1,700	$	3,957	$	4,820

Lease Operating Expenses (LOE)

LOE increased $30 million and $9 million compared to the third quarter and the first nine months of 2022, respectively. On a per-unit basis, LOE remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased 2 percent in the first nine months of 2023 when compared to the first nine months of 2022. Overall higher labor costs and other operating costs trending with global inflation drove an increase in absolute LOE, but these increases were primarily offset by decreased workover activity primarily in the North Sea and changes in foreign currency exchange rates against the US dollar.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(In millions)
Third-party processing and transmission costs	$	63	$	71	$	164	$	205
Midstream service costs – ALTM	—		—		—		18
Midstream service costs – Kinetik	26		28		81		64
Upstream processing and transmission costs	89		99		245		287
Midstream operating expenses	—		—		—		5
Intersegment eliminations	—		—		—		(18)
Total Gathering, processing, and transmission	$	89	$	99	$	245	$	274

GPT costs decreased $10 million and $29 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $10 million and $42 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated.

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Taxes Other Than Income

Taxes other than income decreased $21 million and $67 million from the third quarter and the first nine months of 2022, respectively, primarily from lower severance taxes driven by lower commodity prices as compared to the prior-year periods.

Exploration Expenses

The Company’s exploration expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(In millions)
Unproved leasehold impairments	$	9	$	16	$	20	$	22
Dry hole expense	18		66		71		107
Geological and geophysical expense	1		1		3		19
Exploration overhead and other	21		12		50		45
Total Exploration	$	49	$	95	$	144	$	193

Exploration expenses decreased $46 million and $49 million from the third quarter and the first nine months of 2022, respectively, primarily the result of higher dry hole expense in Suriname and Egypt during 2022 coupled with lower geological and geophysical expenses. These decreases were partially offset by higher exploration overhead and other activities.

General and Administrative (G&A) Expenses

G&A expenses increased $70 million and decreased $38 million compared to the third quarter and the first nine months of 2022, respectively. The increase in expenses for the third quarter of 2023 compared to the third quarter of 2022 was primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price and anticipated achievement of performance and financial objectives as defined in the stock award plans. G&A expenses for the first nine months of 2022 were higher than the first nine months of 2023, as impacts of anticipated achievement-based objectives and changes in the Company’s stock price on cash-based stock compensation were greater during the first nine months of 2022 than those in the first nine months of 2023.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased $10 million compared to the first nine months of 2022. Higher TRS costs during the first nine months of 2022 were primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2022.

Depreciation, Depletion, and Amortization (DD&A)

Total DD&A expenses increased $108 million and $238 million from the third quarter and the first nine months of 2022, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $2.17 per boe and $1.93 per boe from the third quarter and the first nine months of 2022, respectively, driven by general cost inflation. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and acquisitions in the U.S. over the past year.

Impairments

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.

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Financing Costs, Net

The Company’s Financing costs were as follows:

	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)
Total Financing costs, net	$	81	$	75	$	235	$	303

Net financing costs increased $6 million and decreased $68 million from the third quarter and the first nine months of 2022, respectively. The increase in costs during the third quarter of 2023 was primarily a result of interest expense on higher outstanding credit facility borrowings compared to the prior-year period. The decrease in costs during the first nine months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first nine months of 2022 and gains on extinguishment of debt in the first nine months of 2023, partially offset by interest expense on higher outstanding credit facility borrowings compared to the prior-year period.

Provision for Income Taxes

The 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.

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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.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with sustained decreases in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

The Company expects its full-year 2023 estimated upstream capital investment will be approximately $2 billion and remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.

The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.

The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for other liquidity and capital resource needs, if required.

For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

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Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented:

	For the Nine Months Ended September 30,
	2023		2022
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,099	$	3,530
Proceeds from revolving credit facilities, net	202		—
Proceeds from asset divestitures	29		778
Proceeds from sale of Kinetik shares	—		224
Total Sources of Cash and Cash Equivalents	2,330		4,532
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	1,747	$	1,168
Acquisition of Delaware Basin properties	24		563
Leasehold and property acquisitions	11		30
Payments on revolving credit facilities, net	—		22
Payments on Apache fixed-rate debt	65		1,370
Dividends paid to APA common stockholders	232		127
Distributions to noncontrolling interest – Egypt	154		237
Treasury stock activity, net	208		884
Deconsolidation of Altus cash and cash equivalents	—		143
Other, net	39		22
Total Uses of Cash and Cash Equivalents	2,480		4,566
Decrease in Cash and Cash Equivalents	$	(150)	$	(34)

Sources of Cash and Cash Equivalents

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities during the first nine months of 2023 totaled $2.1 billion, down $1.4 billion from the first nine months of 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Proceeds from Revolving Credit Facilities, Net As of September 30, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $768 million, an increase of $202 million since December 31, 2022.

Proceeds from Asset Divestitures The Company received $29 million and $778 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2023 and 2022, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first nine months of 2022. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.7 billion and $1.2 billion during the first nine months of 2023 and 2022, respectively. The increase in capital investment is reflective of the increase in the Company’s capital program that has gradually increased over the past year. The Company operated an average of approximately 24 drilling rigs during the first nine months of 2023, compared to an average of approximately 20 drilling rigs during the first nine months of 2022.

Acquisition of Delaware Basin Properties 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. Cash consideration paid during the first nine months of 2022 totaled $563 million.

Leasehold and Property Acquisitions During the first nine months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $11 million and $30 million, respectively.

Payments on Apache Fixed-Rate Debt During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.

Dividends Paid to APA Common Stockholders The Company paid $232 million and $127 million during the first nine months of 2023 and 2022, respectively, for dividends on its common stock. 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.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $154 million and $237 million during the first nine months of 2023 and 2022, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share totaling $208 million, and as of September 30, 2023, the Company had remaining authorization to repurchase 47.1 million shares. In the first nine months of 2022, the Company repurchased 24.0 million shares at an average price of $36.78 per share totaling $884 million.

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Liquidity

The following table presents a summary of the Company’s key financial indicators:

	September 30, 2023		December 31, 2022
	(In millions)
Cash and cash equivalents	$	95	$	245
Total debt – APA and Apache	5,584		5,453
Total equity	2,107		1,345
Available committed borrowing capacity under syndicated credit facilities	2,164		2,238

Cash and Cash Equivalents As of September 30, 2023, the Company had $95 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of September 30, 2023, the Company had $5.6 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of September 30, 2023, current debt included $2 million of finance lease obligations.

Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

Uncommitted Credit Facilities Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023 there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

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Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, Apache sold its 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.

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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.”

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Some of the more significant estimates include reserve estimates, oil and gas exploration costs, offshore decommissioning contingency, long-lived asset impairments, asset retirement obligations, and income taxes.

New Accounting Pronouncements

There were no material changes in recently issued or adopted accounting standards from those disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the recent conflict in Israel and Gaza, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.

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The Company’s average crude oil price realizations decreased 12 percent from $97.81 per barrel to $86.15 per barrel during the third quarters of 2022 and 2023, respectively. The Company’s average natural gas price realizations decreased 44 percent from $5.62 per Mcf to $3.12 per Mcf during the third quarters of 2022 and 2023, respectively. The Company’s average NGL price realizations decreased 33 percent from $33.39 per barrel to $22.26 per barrel during the third quarters of 2022 and 2023, respectively. Based on average daily production for the third quarter of 2023, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $19 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6 million.

The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2023, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $16 million. A 10 percent increase in natural gas prices would decrease the asset by approximately $3 million, while a 10 percent decrease in prices would increase the asset by approximately $3 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2023. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

As of September 30, 2023, the Company had $4.8 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.34 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.

The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its syndicated credit facilities. As of September 30, 2023, the Company had approximately $95 million in cash and cash equivalents, approximately 84 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2023, there were $768 million of borrowings outstanding under the Company’s syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments and credit facility borrowings are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.

Foreign Currency Exchange Rate Risk

The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss of $2 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2023.

43

ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2023, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended September 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

44

PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 and Note 11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.

ITEM 1A.    RISK FACTORS

There have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2023, June 30, 2023, and September 30, 2023 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2023:

Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2023	—	$	—	—	47,619,742
August 1 to August 31, 2023	—	—		—	47,619,742
September 1 to September 30, 2023	477,465	41.90		477,465	47,142,277
Total	477,465	$	41.90

(1) During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. During September of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company is not obligated to acquire any specific number of shares.

ITEM 5.    OTHER INFORMATION

During the three months ended September 30, 2023, none of the Company’s officers or directors adopted or terminated any Rule 10b5-1 trading arrangement or “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).

45

ITEM 6.    EXHIBITS

3.1	–	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.2	–	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated May 24, 2023, as filed with the Secretary of State of the State of Delaware on May 24, 2023 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 25, 2023, SEC File No. 001-40144).
3.3	–	Amended and Restated Bylaws of Registrant, dated February 2, 2023 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed February 8, 2023, SEC File No. 001-40144).
*†10.1	–	APA Corporation Non-Employee Directors’ Compensation Plan, as amended and restated September 12, 2023.
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
**32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101	–	The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income, (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.SCH	–	Inline XBRL Taxonomy Schema Document.
*101.CAL	–	Inline XBRL Calculation Linkbase Document.
*101.DEF	–	Inline XBRL Definition Linkbase Document.
*101.LAB	–	Inline XBRL Label Linkbase Document.
*101.PRE	–	Inline XBRL Presentation Linkbase Document.
*104	–	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*    Filed herewith

**    Furnished herewith

† Management contracts or compensatory plans or arrangements.

46

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		APA CORPORATION
Dated:	November 2, 2023	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	November 2, 2023	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

47

EX-10.1

Exhibit 10.1 APA CORPORATION NON-EMPLOYEE DIRECTORS’ COMPENSATION PLAN As Amended and Restated September 12, 2023 PURPOSE The purpose of the Non-Employee Directors’ Compensation Plan (the “Plan”) is to set forth certain of the compensation arrangements for members of the board of directors (the “Board”) of APA Corporation (“APA”) who are not also employees of APA or its subsidiaries (“Non-Employee Directors”). The Plan does not supersede or amend in any way any other arrangements relating to Non-Employee Directors including specifically, without limitation, the Outside Directors’ Retirement Plan, the 2016 Omnibus Compensation Plan, indemnification provisions of APA’s charter or bylaws, or policies with respect to reimbursement of expenses. It is APA’s express intention that this Plan comply with the requirements of Code §409A, and the Plan shall be interpreted in that light. PLAN PROVISIONS 1. Board Retainer. Each Non-Employee Director shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) during which he or she served as a member of APA’s Board (“Cash Retainer Fee”). If a Non-Employee Director serves as a member of APA’s Board for less than an entire calendar quarter, the Cash Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served during that calendar quarter. 2. Non-Executive Chair Retainer. Subject to section 4 below, each Non-Employee Director serving as non-executive chair of APA’s Board shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Non-Executive Chair Retainer Fee”). If a Non-Employee Director serves as non-executive chair for less than an entire calendar quarter, the Non-Executive Chair Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as non-executive chair during that calendar quarter. 3. Committee Chair Retainers. Subject to section 4 below, each Non-Employee Director serving as chair of any committee of APA’s Board shall be paid the fee indicated below at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Committee Chair Retainer Fee”): - Audit Committee - $5,000 - Corporate Responsibility, Governance, and Nominating Committee - $3,750 - Management Development and Compensation Committee - $5,000 - Cybersecurity Committee - $3,750 If a Non-Employee Director serves as chair of any committee of APA’s Board for less than an entire calendar quarter, the applicable Committee Chair Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as chair during that calendar quarter. 4. Combined Non-Executive Chair and Committee Chair Retainer. If the Non-Employee Director serving as non-executive chair of APA’s Board is also serving as chair of any committee

2 of 7 of APA’s Board, the Non-Employee Director shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Combined Retainer Fee”). If a Non-Employee Director serves as both non-executive chair and committee chair for less than an entire calendar quarter, the Combined Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as both non-executive chair and committee chair during that calendar quarter. 5. Audit Committee Member Retainer. Each Audit Committee member (excluding the chair) shall be paid $1,250 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) during which he or she served as a member of the Audit Committee (“Audit Committee Retainer Fee”). If an Audit Committee member serves as a member of the Audit Committee for less than an entire calendar quarter, the Audit Committee Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served during that calendar quarter. 6. Attendance Fees. No attendance fee shall be paid to any Non-Employee Director for any meeting of the Board or any committee thereof attended in person or by teleconference, video conference, or other similar means. 7. Optional Deferral of Fees. (a) Deferrable Fees. A Non-Employee Director may defer all or any portion of any unpaid Cash Retainer Fees, Non-Executive Chair Retainer Fees, Committee Chair Retainer Fees, and Combined Retainer Fees (“Deferrable Fees”). (b) Election to Defer. A Non-Employee Director’s election to defer all or any portion of Deferrable Fees (“Deferral Election”) shall be effected by the completion of a Deferral Election form. A Deferral Election form must be executed by the deferring Non-Employee Director and received by APA on or before December 31 of the year prior to the year in which the Deferrable Fees are earned, except that a new Non-Employee Director may enter into a Deferral Election within 30 days of becoming a Non-Employee Director. A Deferral Election shall apply only to Deferrable Fees paid for services rendered after the date of the Deferral Election. Each December 31, a Deferral Election made for the following year shall become irrevocable. A new Deferral Election must be made each year for the upcoming year. (c) Memorandum Account. APA shall maintain a separate account (“Memorandum Account”) for each deferring Non-Employee Director. Each Memorandum Account shall be subdivided into a “Cash Account” and a “Stock Account.” The Memorandum Accounts are merely for recordkeeping purposes and do not represent any actual property that has been set aside for Non-Employee Directors. Nothing contained in this Plan shall be construed to require APA to fund any Memorandum Account. Neither the deferring Non-Employee Director nor his or her Beneficiary shall have any property interest whatsoever in any specific assets of APA. A Non-Employee Director shall have no ownership rights with respect to any balance in his or her Memorandum Account and thus shall have no right to vote any Stock in his or her Stock Account. (d) Crediting of Cash Accounts. Any deferred Cash Retainer Fees and deferred Committee Chair Retainer Fees shall be credited to the Cash Account. Any dividends paid on Stock in the Stock Accounts shall be credited to the Cash Account. All amounts credited to a Cash Account shall be credited with investment earnings at the rate of interest earned by APA’s

3 of 7 short-term marketable securities portfolio or an equivalent index or market rate for similar investments in short-term marketable securities. (e) Crediting of Stock Accounts. No deferrals shall be credited to a Stock Account; however, see section 7(f) for transfers from the Cash Account to the Stock Account. All amounts credited to a Stock Account shall be treated as if such amounts were invested in Stock. APA shall at all times have reserved from its treasury shares for issuance under this Plan a number of shares at least equal to the number of shares of Stock in the Stock Accounts. (f) Transfers from Cash Account to Stock Account. Each year, a Non-Employee Director may elect to transfer all or a portion of his or her Cash Account to his or her Stock Account (but only in whole-share increments) by completing an election form that must be received by APA on or before December 31. Any such transfer shall be made as of the first trading day of the following year and shall be based on the per share closing price of the Stock as reported on the Composite Tape for the first trading day of the year. Transfers are not permitted from a Stock Account to a Cash Account. (g) Payout Elections. If a Non-Employee Director’s directorship terminated before January 1, 2005, his or her benefit payments shall be determined under the terms of the Plan on December 31, 2004, and the payout elections in effect at the time his or her directorship terminated. If a Non-Employee Director had a Separation from Service after December 31, 2004, and before January 1, 2009, his or her benefits shall be determined under the terms of the Plan in effect at the time of his or her Separation from Service (defined in paragraph (v) below). The remainder of this section 7(g) shall only apply to individuals who continue as Non- Employee Directors after December 31, 2008, or who become Non-Employee Directors after December 31, 2008. (i) Election. Each individual who is Non-Employee Director on January 1, 2009, has made a payout election for his or her Memorandum Account, which specified both the timing and form of distribution. A new Non-Employee Director shall make a payout election at the same time that he or she makes his or her first Deferral Election. If no payout election is timely made, the Non-Employee Director shall be deemed to have elected to be paid a single lump-sum payment in January after his or her Separation from Service. The payout election with respect to a Memorandum Account is irrevocable after the deadline for making the payout election. The payout election will not apply if there is a change of control (see section 7(h)) or the Non-Employee Director dies (see section 7(i)). (ii) Form of Payout. A Non-Employee Director may elect to be paid out in a single lump- sum payment or in two to ten annual installments. Each installment from a Stock Account shall be equal to the number of shares in the Stock Account on the second trading day of that year, divided by the number of remaining installments, rounded down to the nearest whole share. For example, the first installment from a Stock Account payable in seven installments beginning in 2010 shall be one-seventh of the shares in the account on the second trading day of 2010; the second installment shall be one-sixth of the shares in the account on the second trading date of 2011; etc. Each installment from a Cash Account shall be equal to the balance of the Cash Account on the second trading day of the year, divided by the number of remaining installments, except that the last installment shall equal the balance of the Cash Account at the time the distribution is processed. Distributions from the Stock Account shall be paid in whole shares of Stock. Distributions from the Cash Account shall be paid in cash.

4 of 7 (iii) Timing of Payment(s). A Non-Employee Director may select a specific year in which the single lump-sum payment is made or the installment payments begin (“In-Service Distribution”), in which case the payment will be made as soon as administratively practicable in January of the earlier of the selected year or the year after the Non- Employee Director’s Separation from Service. Alternatively, a Non-Employee Director may elect for his or her single lump-sum payment or first installment to be paid as soon as administratively practicable in the January after his or her Separation from Service. Subsequent installment payments shall be made in January of each year, beginning with the year after the first installment was paid. (iv) Special Rules Where Payments Begin While Still a Director. This paragraph (iv) applies to a Non-Employee Director who elected an In-Service Distribution. A second Memorandum Account shall be established for the Non-Employee Director for any amounts deferred into the Plan during or after the year in which the In-Service Distribution is scheduled to begin. Distributions from the second Memorandum Account shall be subject to the rules specified in this section 7(g), except that a Non-Employee Director must complete a payout election for the second Memorandum Account by the December 31 that immediately precedes the year in which amounts are first deferred into the second Memorandum Account. (v) Definition of Separation from Service. The term “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i), determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, including the special rules for members of a board of directors found in Treasury Regulation §1.409A-1(h)(5) and §1.409A-1(c)(2)(ii). In general, a Separation from Service will occur when a Non-Employee Director ceases to be a member of the Board. (vi) Special Rules for Specified Employees. If a Non-Employee Director is a Specified Employee, (A) any payments under paragraph (iii) above that are triggered by his or her Separation from Service and scheduled to occur within six months after the Separation from Service shall be delayed and paid six months after the Separation from Service, and (B) section 7(h) is modified for a Non-Employee Director whose Separation from Service preceded a change of control by less than six months to provide that the lump sum payment will not occur until six months after the Separation from Service. The term “Specified Employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i) and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A. (h) Change of Control. If there is a change of control of APA that is described in Code §409A(a)(2)(A)(v), each Memorandum Account shall be paid to the appropriate Non- Employee Director (or to the Beneficiary of a deceased Non-Employee Director) in a single lump-sum payment made on the date of the change of control or as soon thereafter as is administratively practicable and in no event later than the end of the calendar year in which the change of control occurs. (i) Beneficiaries. If a Non-Employee Director dies while there is still a balance in his or her Memorandum Account, that amount shall be paid to his or her Beneficiary in a single lump- sum payment that is made as soon as administratively convenient four months after the Non- Employee Director’s death, but in no event later than the end of the calendar year that contains the day that is four months after the Non-Employee Director’s death. This four-month period

5 of 7 is designed to provide the Beneficiary with a sufficient opportunity to disclaim all or part of the benefit, as explained in paragraph (iv) below. No payment shall be made until APA has been furnished with proof of death and such other information as it may reasonably require. (i) Designation. Each Non-Employee Director shall designate one or more persons, trusts, or other entities as his or her beneficiary (“Beneficiary”). In the absence of an effective Beneficiary designation as to part or all of a Memorandum Account, such amount shall be distributed to the Non-Employee Director’s surviving Spouse, if any, otherwise to the Non-Employee Director’s estate. Unless the Non-Employee Director’s Beneficiary designation form specifies otherwise, if a Beneficiary dies after the Non-Employee Director but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate. (ii) Changing Beneficiaries. A Beneficiary designation may be changed by the Non- Employee Director at any time and without the consent of any previously designated Beneficiary. However, if the Non-Employee Director is married, the Non-Employee Director’s Spouse shall be the Beneficiary unless the Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must have been made before January 1, 2005, or, if made on or after January 1, 2005, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with APA. If the Non- Employee Director has designated his or her Spouse as a primary or contingent Beneficiary and the Non-Employee Director and Spouse later divorce (or their marriage is annulled), then the former Spouse will be treated as having pre-deceased the Non- Employee Director for purposes of interpreting a Beneficiary designation form completed prior to the divorce or annulment; this provision will apply only if APA is notified of the divorce or annulment before payment to the former Spouse is made. (iii) “Spouse” shall mean the individual to whom a Non-Employee Director is lawfully married according to the laws of the state of the Non-Employee Director’s domicile. (iv) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary. (j) Adjustments in Stock. In the event of any merger, consolidation, liquidation, dissolution, recapitalization, or reorganization of APA, split, subdivision, or consolidation of shares of Stock, the payment of a stock dividend, or any other material change in APA’s capital structure, the number of shares of Stock shown in each deferring Non-Employee Director’s Stock Account shall be adjusted to reflect that number of shares of Stock or such cash, securities, or other property to which such Non-Employee Director would have been entitled if, immediately prior thereto, such Non-Employee Director had been the holder of record of the number of shares of Stock shown in the Stock Account. Notwithstanding the foregoing, the issuance by APA of Stock, rights, options, or warrants to acquire Stock, or securities convertible or exchangeable into Stock in consideration of cash, property, labor, or services, whether or not for fair value, shall not result in an adjustment pursuant to this section 7(j).

6 of 7 8. Assignment and Transfer. The right of the Non-Employee Director or any other person to receive payments under the Plan shall not be assigned, transferred, pledged, or encumbered. 9. Amendment of Plan. The Plan may be amended from time to time or terminated by vote of the Board. Upon such amendment or termination, Non-Employee Directors shall not be entitled to receive pursuant to the Plan any compensation or other rights or benefits not accrued hereunder prior to the time of amendment or termination hereof; provided, however, that no such Plan amendment or termination shall impair any rights of Non-Employee Directors to amounts previously accrued pursuant to the Plan or accumulated in such Non-Employee Director’s Memorandum Account. A Plan termination shall not affect the timing of any benefit payments from a Memorandum Account; payment may occur substantially after the Plan is terminated. 10. Successors and Assigns. The Plan is binding upon APA and its successors and assigns. The Plan shall continue in effect until terminated by the Board. Any such termination shall operate only prospectively and shall not affect the rights and obligations under elections previously made. 11. Administrative Delays. The Plan shall be administered by the Management Development and Compensation Committee (the “MD&C Committee”) of the Board. The MD&C Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the MD&C Committee. If possible, the delay will satisfy one of the conditions to be considered a permissible delay under Code §409A. 12. 409A Noncompliance. To the extent that APA or the MD&C Committee takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, APA shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put the individual in the same after- tax position he or she would have been in had there been no violation of Code §409A. APA shall not pay a gross-up if the cause of the violation of Code §409A is the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the MD&C Committee - with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively convenient after the MD&C Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation. 13. Notices. Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed: (a) If to APA, to APA Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention: Corporate Secretary) or at such other address as may have been furnished in writing by APA to a Non-Employee Director;

7 of 7 (b) If to a Non-Employee Director or Spouse, at the address the Non-Employee Director has furnished to APA in writing; or (c) If to a Beneficiary, at the address the Non-Employee Director has furnished to APA in writing for such Beneficiary, unless the Beneficiary has furnished his or her own address in writing to APA. Any such notice to a Non-Employee Director, Spouse, or Beneficiary shall be deemed to have been given as of the third day after deposit in the United States Postal Service, postage prepaid, properly addressed as set forth above, in the case of a mailed notice, or as of the date delivered in the case of any other method of delivery. 14. Gender. Any term used herein in the singular shall also include the plural, and the masculine gender shall also include the feminine gender, and vice versa. 15. Statutory References. Any reference to a specific section of the Code shall be deemed to refer to that section or to the appropriate successor section. 16. Governing Law. The Plan shall be governed by the laws of the State of Texas, ignoring any conflicts-of-law provisions. Dated: September 12, 2023 ATTEST: APA CORPORATION /s/ Rajesh Sharma____________ By: /s/ Brandy Jones Rajesh Sharma Brandy Jones Corporate Secretary Vice President, Human Resources

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 2, 2023

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 2, 2023

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

EX-32.1

EXHIBIT 32.1

APA CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2023, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 2, 2023

/s/ John J. Christmann IV
By:	John J. Christmann IV
Title:	Chief Executive Officer and President
	(principal executive officer)

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2023, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 2, 2023

/s/ Stephen J. Riney
By:	Stephen J. Riney
Title:	Executive Vice President and Chief Financial Officer
	(principal financial officer)

XML

Cover - shares	9 Months Ended
	Sep. 30, 2023	Oct. 31, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
Document Transition Report	false
Entity File Number	1-40144
Entity Registrant Name	APA CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	86-1430562
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		306,719,421
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001841666
Current Fiscal Year End Date	--12-31

XML

STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
REVENUES AND OTHER:
Derivative instrument gains (losses), net		$ 0	$ (44)	$ 104	$ (138)
Gain on divestitures, net		1	31	7	1,180
Other, net		0	(2)	77	107
Total revenues and other		2,309	2,872	6,300	9,752
OPERATING EXPENSES:
Lease operating expenses		394	364	1,076	1,067
Taxes other than income		61	82	163	230
Exploration		49	95	144	193
General and administrative		139	69	276	314
Transaction, reorganization, and separation		5	4	11	21
Depreciation, depletion, and amortization		418	310	1,117	879
Asset retirement obligation accretion		29	29	86	87
Impairments		0	0	46	0
Financing costs, net		81	75	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		0	0	0	(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
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		$ 96	$ 108	$ 261	$ 368
Noncontrolling interest - Altus
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		0	0	0	14
Oil and gas
REVENUES AND OTHER:
Total revenues		2,308	2,887	6,112	8,603
Gathering, processing, and transmission costs
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	[1]	2,079	2,302	5,500	7,147
OPERATING EXPENSES:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	89	99	245	274
Purchased oil and gas sales
REVENUES AND OTHER:
Purchased oil and gas sales	[1]	229	585	612	1,456
OPERATING EXPENSES:
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.

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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

XML

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

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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

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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

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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 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)											$ (72)		(642)	[1]
Ending balance at Sep. 30, 2022	[1]																0
Beginning balance at Dec. 31, 2021		$ (717)			$ (1,595)	$ 262	$ 11,645	$ (9,488)	$ (4,036)	$ 22	$ 878	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		3,231			3,231			3,231
Net income attributable to noncontrolling interest			$ 368	14									$ 368	[1]	14
Distributions to noncontrolling interest			(237)										(237)	[1]
Common dividends declared		(165)			(165)		(165)
Deconsolidation of Altus				(72)											$ (72)		(642)	[1]
Treasury stock activity, net		(884)			(884)				(884)
Other		13			13		14			(1)
Ending balance at Sep. 30, 2022		1,551			600	262	11,494	(6,257)	(4,920)	21	951	[2]
Ending balance at Sep. 30, 2022	[1]																$ 0
Beginning balance at Jun. 30, 2022		1,505			584	262	11,567	(6,679)	(4,587)	21	921	[2]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		422			422			422
Net income attributable to noncontrolling interest			108	0									108	[2]
Distributions to noncontrolling interest			(78)										(78)	[2]
Common dividends declared		(80)			(80)		(80)
Treasury stock activity, net		(333)			(333)				(333)
Other		7			7		7
Ending balance at Sep. 30, 2022		1,551			600	262	11,494	(6,257)	(4,920)	21	951	[2]
Beginning balance at Dec. 31, 2022		1,345			423	262	11,420	(5,814)	(5,459)	14	922	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		1,082			1,082			1,082
Net income attributable to noncontrolling interest			261	0									261	[1]
Distributions to noncontrolling interest			(154)										(154)	[1]
Common dividends declared		(232)			(232)		(232)
Treasury stock activity, net		(208)			(208)				(208)
Other		13			13	1	9			3
Ending balance at Sep. 30, 2023		2,107			1,078	263	11,197	(4,732)	(5,667)	17	1,029	[2]
Beginning balance at Jun. 30, 2023		1,696			709	263	11,267	(5,191)	(5,647)	17	987	[2]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		459			459			459
Net income attributable to noncontrolling interest			96	$ 0									96	[2]
Distributions to noncontrolling interest			$ (54)										$ (54)	[2]
Common dividends declared		(77)			(77)		(77)
Treasury stock activity, net		(20)			(20)				(20)
Other		7			7		7
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.

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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

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NATURE OF OPERATIONS	9 Months Ended
	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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

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.

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ACQUISITIONS AND DIVESTITURES

9 Months Ended

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.

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CAPITALIZED EXPLORATORY WELL COSTS

9 Months Ended

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.

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023, the Company had derivative positions with seven counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.

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

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.

Derivative Activity Recorded in the Consolidated Balance Sheet

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:

	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)

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”

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OTHER CURRENT ASSETS

9 Months Ended

Sep. 30, 2023

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

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

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

	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

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EQUITY METHOD INTERESTS

9 Months Ended

Sep. 30, 2023

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS

The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.

The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares.

The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock.

The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49 million in the first nine months of 2023 and 2022, respectively. These gains and losses were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.

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.

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OTHER CURRENT LIABILITIES

9 Months Ended

Sep. 30, 2023

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

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

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ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 2023

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

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

	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

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DEBT AND FINANCING COSTS

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

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.

The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(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.

During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023, there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

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

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INCOME TAXES

9 Months Ended

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.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

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.

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CAPITAL STOCK

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

CAPITAL STOCK

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

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.7 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.5 million during the first nine months of 2023 and 2022, respectively.

Stock Repurchase Program

During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock.

In the third quarter of 2023, the Company repurchased approximately 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share, and as of September 30, 2023, the Company had remaining authorization to repurchase up to 47.1 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share.

The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares.

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

For the quarters ended September 30, 2023 and 2022, the Company paid $77 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127 million, respectively, in dividends on its common stock.

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.

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BUSINESS SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

As of September 30, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. 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

(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022.

(3)Intercompany balances are excluded from total assets.

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

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Insider Trading Arrangements	3 Months Ended
	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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

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.

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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

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

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

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

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)

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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

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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

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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

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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

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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.

The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(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

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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

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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

(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022.

(3)Intercompany balances are excluded from total assets.

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

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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%

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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

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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

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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

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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)

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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

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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

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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)

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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

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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

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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
Costs		63	28	146	64
Natural gas and NGLs sales | Kinetik
Schedule of Equity Method Investments [Line Items]
Sales		35	0	78	0
Gathering, processing, and transmission costs
Schedule of Equity Method Investments [Line Items]
Costs	[1]	89	99	245	274
Gathering, processing, and transmission costs | Kinetik
Schedule of Equity Method Investments [Line Items]
Costs		26	28	81	64
Purchased oil and gas sales
Schedule of Equity Method Investments [Line Items]
Costs	[1]	211	573	558	1,452
Purchased oil and gas sales | Kinetik
Schedule of Equity Method Investments [Line Items]
Sales		11	0	18	0
Costs		$ 37	$ 0	$ 65	$ 0

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

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OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
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

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ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period			$ 1,995
Liabilities incurred			14
Liabilities settled			(34)
Accretion expense	$ 29	$ 29	86	$ 87
Asset retirement obligation at the end of period	2,061		2,061
Less current portion	(55)		(55)		$ (55)
Asset retirement obligation, long-term	$ 2,006		$ 2,006		$ 1,940

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
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
Apache notes and debentures | Unsecured Debt
Debt Instrument [Line Items]
Apache notes and debentures before unamortized discount and debt issuance costs	4,835	4,908
Debt instrument, fair value	4,100	4,200
Syndicated credit facility | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	$ 768	$ 566

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DEBT AND FINANCING COSTS - Additional Information (Details) £ in Millions			3 Months Ended			9 Months Ended
	Apr. 29, 2022 USD ($) credit_agreement option	Jan. 18, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 GBP (£)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 GBP (£)	Apr. 29, 2022 GBP (£) credit_agreement
Debt Instrument [Line Items]
Finance lease obligations, current			$ 2,000,000			$ 2,000,000			$ 2,000,000
Gain (loss) on extinguishment of debt			0	$ 0		9,000,000	$ (67,000,000)
Number of syndicated credit agreements | credit_agreement	2										2
USD Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument term	5 years
Line of credit facility, committed amount	$ 1,800,000,000
Line of credit facility, increased committed amount	$ 2,300,000,000
Line of credit facility, number of extension options | option	2
Debt extension term	1 year
USD Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 750,000,000
Line of credit facility, current borrowing capacity	150,000,000
Principal amount outstanding	$ 300,000,000
Letters of credit outstanding, amount			0			0			20,000,000
GBP Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument term	5 years
Line of credit facility, committed amount | £											£ 1,500
Line of credit facility, number of extension options | option	2
Debt extension term	1 year
GBP Agreement | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £								£ 572		£ 652
Former Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, terminated Amount	$ 4,000,000,000
Line of credit facility, covenant benchmark amount	$ 1,000,000,000
Syndicated credit facility | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility			768,000,000			768,000,000			566,000,000
Apache credit facility
Debt Instrument [Line Items]
Letters of credit outstanding, amount			3,000,000			3,000,000		£ 185	$ 17,000,000	£ 199
Uncommitted Lines Of Credit | Line of Credit
Debt Instrument [Line Items]
Credit facility			0			0
Senior Notes | 3.25% notes due 2022
Debt Instrument [Line Items]
Current maturities		$ 213,000,000
Debt interest rate		3.25%
Redemption price, percentage of principal amount redeemed		100.00%
Senior Notes | Open Market Repurchase
Debt Instrument [Line Items]
Debt repurchased principal amount			74,000,000	15,000,000		74,000,000	15,000,000
Debt instrument repurchase program			$ 65,000,000	16,000,000		65,000,000	16,000,000
Premium (discount) to par of debt repurchase					$ 1,000,000	(10,000,000)
Gain (loss) on extinguishment of debt					$ (1,000,000)	$ 9,000,000
Senior Notes | Cash Tender Offers
Debt Instrument [Line Items]
Debt repurchased principal amount				1,100,000,000			1,100,000,000
Debt instrument repurchase program				1,200,000,000			1,200,000,000
Gain (loss) on extinguishment of debt							(66,000,000)
Debt instrument, unamortized discount and issuance costs				$ 11,000,000			$ 11,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Debt Disclosure [Abstract]
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	0	0	(9)	67
Interest income	(2)	(1)	(7)	(8)
Financing costs, net	$ 81	$ 75	$ 235	$ 303

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INCOME TAXES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Foreign Tax Authority
Deferred Tax Expense [Line Items]
Deferred tax expense, remeasurement of deferred tax liability	$ 174

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COMMITMENTS AND CONTINGENCIES (Details) $ in Millions							9 Months Ended	12 Months Ended
	Sep. 10, 2020 defendant	Sep. 11, 2019 USD ($) plaintiff	Dec. 20, 2017 action	Jul. 17, 2017 defendant action	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Sep. 30, 2023 USD ($) bond letter_of_credit	Dec. 31, 2013 USD ($) profit_interest	Jun. 21, 2023 surety	Dec. 31, 2022 USD ($)	Apr. 05, 2022 letter	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)	Mar. 12, 2014 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies							$ 49,000,000
Environmental tax and royalty obligations														$ 100,000,000
Retain right of obligations							45,000,000
Undiscounted reserve for environmental remediation							5,000,000
Number of prior letters notifying unable to fund decommissioning obligations | letter											2
Decommissioning costs incurred							692,000,000
Decommissioning costs reimbursed amount from trust							288,000,000
Decommissioning costs reimbursed amount from the letters of credit							87,000,000
Standby loan agreed to provide related to ARO (up to)							400,000,000
Decommissioning contingency for sold							695,000,000
Decommissioning contingency for sold properties							470,000,000			$ 738,000,000
Current decommissioning contingency for sold Gulf of Mexico properties							225,000,000			450,000,000
Decommissioning security for sold properties							411,000,000
Trust account for disposal group, number of net profits interests							38,000,000			217,000,000
Current decommissioning security for sold Gulf of Mexico assets							$ 373,000,000			$ 450,000,000
Sureties issued bonds directly | surety									2
Sureties issued bonds to issuing bank | surety									2
Gulf Of Mexico Shelf Operations and Properties | Disposed of by Sale
Commitment And Contingencies [Line Items]
Proceeds from sale of operations and properties								$ 3,750,000,000
Trust account for disposal group, number of net profits interests | profit_interest								2
Number of bond held | bond							2
Number of debt instrument held | letter_of_credit							5
Minimum
Commitment And Contingencies [Line Items]
AROs, estimated liability							$ 695,000,000
Maximum
Commitment And Contingencies [Line Items]
AROs, estimated liability							895,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages					$ 200,000,000
Apollo Exploration Lawsuit | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages						$ 1,100,000,000
Australian Operations Divestiture Dispute | Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount													$ 80
Loss contingency, estimated of possible loss amount												$ 200
Canadian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 60,000,000
Number of plaintiffs | plaintiff		4
Litigation settlement, amount to resolve all claims							$ 7,000,000
California Litigation
Commitment And Contingencies [Line Items]
Number of actions filed | action			2	3
Number of defendants | defendant				30
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants | defendant	25

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CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Basic:
Income attributable to common stock	$ 459	$ 422	$ 1,082	$ 3,231
Income attributable to common stock (in shares)	308	329	309	339
Income attributable to common stock (in USD per share)	$ 1.49	$ 1.28	$ 3.50	$ 9.54
Diluted:
Income attributable to common stock	$ 459	$ 422	$ 1,082	$ 3,231
Income attributable to common stock (in shares)	308	330	309	340
Income attributable to common stock (in USD per share)	$ 1.49	$ 1.28	$ 3.50	$ 9.51
Stock options and other
Effect of Dilutive Securities:
Stock options and other	$ 0	$ 0	$ 0	$ 0
Stock options and other, shares (in shares)	0	1	0	1
Stock options and other, per share (in USD per share)	$ 0	$ 0	$ 0	$ (0.03)

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CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended				9 Months Ended
	Oct. 31, 2023	Sep. 30, 2023	Sep. 30, 2022	Jun. 30, 2022	Dec. 31, 2021	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2018
Class of Stock [Line Items]
Options and restricted stock, anti-dilutive (in shares)		1,700,000	2,100,000			2,000,000	2,500,000
Number of shares authorized to be repurchased (in shares)								40,000,000
Additional number of shares authorized to be repurchased (in shares)			40,000,000		40,000,000
Treasury shares acquired (in shares)		500,000	9,800,000			5,500,000	24,000,000
Treasure stock acquired, average price (in USD per share)		$ 41.90	$ 33.86			$ 37.91	$ 36.78
Remaining authorized repurchase amount (in shares)		47,100,000				47,100,000
Payments of dividend on common stock		$ 77	$ 41			$ 232	$ 127
Common stock, dividends, per share (in USD per share)		$ 0.25	$ 0.25	$ 0.125		$ 0.75	$ 0.50
Subsequent Event
Class of Stock [Line Items]
Treasury shares acquired (in shares)	400,000
Treasure stock acquired, average price (in USD per share)	$ 40.26
Remaining authorized repurchase amount (in shares)	46,700,000

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BUSINESS SEGMENT INFORMATION - Additional Information (Details)	9 Months Ended
	Sep. 30, 2023 segment
Segment Reporting [Abstract]
Number of operating segments	3

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BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Operating Expenses:
Lease operating expenses		$ 394	$ 364	$ 1,076	$ 1,067
Taxes other than income		61	82	163	230
Exploration		49	95	144	193
Depreciation, depletion, and amortization		418	310	1,117	879
Asset retirement obligation accretion		29	29	86	87
Impairments		0	0	46	0
Total operating expenses		1,251	1,552	3,435	4,182
Operating Income (Loss)		1,057	1,335	2,677	4,421
Other Income (Expense):
Derivative instrument gains (losses), net		0	(44)	104	(138)
Gain on divestitures, net		1	31	7	1,180
Other, net			(2)	77	107
General and administrative		(139)	(69)	(276)	(314)
Transaction, reorganization, and separation		(5)	(4)	(11)	(21)
Financing costs, net		(81)	(75)	(235)	(303)
NET INCOME BEFORE INCOME TAXES		833	1,172	2,343	4,932
Total assets		13,545	13,629	13,545	13,629	$ 13,147
Operating Segments | Egypt
Operating Expenses:
Lease operating expenses		128	119	346	381
Taxes other than income		0	0	0	0
Exploration		25	29	91	56
Depreciation, depletion, and amortization		129	97	378	285
Asset retirement obligation accretion		0	0	0	0
Impairments				0
Total operating expenses		295	250	841	737
Operating Income (Loss)		510	573	1,394	1,970
Other Income (Expense):
Total assets		3,518	3,242	3,518	3,242
Impairments			1		3
Operating Segments | North Sea
Operating Expenses:
Lease operating expenses		102	107	278	321
Taxes other than income		0	0	0	0
Exploration		9	1	18	8
Depreciation, depletion, and amortization		90	52	209	168
Asset retirement obligation accretion		20	21	57	61
Impairments				46
Total operating expenses		236	188	646	589
Operating Income (Loss)		183	164	403	589
Other Income (Expense):
Total assets		1,665	2,185	1,665	2,185
Impairments		6		12
Operating Segments | U.S.
Operating Expenses:
Lease operating expenses		164	138	452	366
Taxes other than income		61	82	163	227
Exploration		4	16	10	21
Depreciation, depletion, and amortization		199	161	530	424
Asset retirement obligation accretion		9	8	29	25
Impairments				0
Total operating expenses		709	1,065	1,923	2,756
Operating Income (Loss)		375	647	905	1,960
Other Income (Expense):
Total assets		7,827	7,675	7,827	7,675
Impairments		2	15	7	19
Operating Segments | Suriname
Other Income (Expense):
Impairments		1		1
Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Purchased oil and gas sales					16
Operating Expenses:
Lease operating expenses		0	0	0	0
Taxes other than income		0	0	0	3
Exploration		0	0	0	0
Depreciation, depletion, and amortization		0	0	0	2
Asset retirement obligation accretion		0	0	0	1
Impairments				0
Total operating expenses		0	0	0	11
Operating Income (Loss)		0	0	0	10
Other Income (Expense):
Total assets		0	0	0	0
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Purchased oil and gas sales					(16)
Operating Expenses:
Lease operating expenses		0	0	0	(1)
Taxes other than income		0	0	0	0
Exploration		11	49	25	108
Depreciation, depletion, and amortization		0	0	0	0
Asset retirement obligation accretion		0	0	0	0
Impairments				0
Total operating expenses		11	49	25	89
Operating Income (Loss)		(11)	(49)	(25)	(108)
Other Income (Expense):
Total assets		535	527	535	527
Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	[1]	2,079	2,302	5,500	7,147
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	89	99	245	274
Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		805	823	2,235	2,707
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		13	5	26	15
Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		419	352	1,049	1,178
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		15	7	38	31
Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		855	1,127	2,216	3,265
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		61	87	181	241
Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	5
Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	(3)
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	(18)
Purchased oil and gas sales
Segment Reporting Information [Line Items]
Purchased oil and gas sales	[1]	229	585	612	1,456
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	[1]	211	573	558	1,452
Purchased oil and gas sales | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	0
Purchased oil and gas sales | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	0
Purchased oil and gas sales | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Purchased oil and gas sales		229	585	612	1,451
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		211	573	558	1,452
Purchased oil and gas sales | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0	0	5
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	0
Purchased oil and gas sales | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs		0	0	0	0
Oil and gas
Segment Reporting Information [Line Items]
Revenues		2,308	2,887	6,112	8,603
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenues		805	823	2,235	2,707
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenues		419	352	1,049	1,178
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Revenues		1,084	1,712	2,828	4,716
Oil and gas | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Revenues		0	0	0	21
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues		0	0	0	(19)
Oil revenues
Other Income (Expense):
Revenue from non-customers		202	227	539	779
Oil revenues | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,705	1,672	4,467	5,252
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		724	739	1,971	2,431
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		348	303	865	938
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		633	630	1,631	1,883
Oil revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Oil revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Natural gas revenues
Other Income (Expense):
Revenue from non-customers		23	26	73	87
Natural gas revenues | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		236	428	658	1,241
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		81	84	264	270
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		66	44	165	207
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		89	300	229	764
Natural gas revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Natural gas revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Natural gas liquids revenues
Other Income (Expense):
Revenue from non-customers		0	0	0	2
Natural gas liquids revenues | Gathering, processing, and transmission costs
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		138	202	375	654
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	6
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		5	5	19	33
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		133	197	356	618
Natural gas liquids revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0	0
Natural gas liquids revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		$ 0	$ 0	$ 0	$ (3)

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