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 March 31, 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 April 30, 2023 308,599,131 

TABLE OF CONTENTS

Item		Page
	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)	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	6
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
4.	CONTROLS AND PROCEDURES	37
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	39
1A.	RISK FACTORS	39
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
6.	EXHIBITS	40

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 and from 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 first-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 March 31,
	2023		2022
	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)	$	1,769	$	2,320
Purchased oil and gas sales	239		349
Total revenues	2,008		2,669
Derivative instrument gains (losses), net	53		(62)
Gain on divestitures, net	1		1,176
Other, net	(32)		45
	2,030		3,828
OPERATING EXPENSES:
Lease operating expenses	321		344
Gathering, processing, and transmission(1)	78		81
Purchased oil and gas costs	216		351
Taxes other than income	52		70
Exploration	52		42
General and administrative	65		156
Transaction, reorganization, and separation	4		14
Depreciation, depletion, and amortization	332		291
Asset retirement obligation accretion	28		29
Financing costs, net	72		152
	1,220		1,530
NET INCOME BEFORE INCOME TAXES	810		2,298
Current income tax provision	346		392
Deferred income tax provision (benefit)	138		(40)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	326		1,946
Net income attributable to noncontrolling interest – Egypt	84		119
Net income attributable to noncontrolling interest – Altus	—		14
Net loss attributable to Altus Preferred Unit limited partners	—		(70)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	242	$	1,883
NET INCOME PER COMMON SHARE:
Basic	$	0.78	$	5.44
Diluted	$	0.78	$	5.43
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	311		346
Diluted	312		347

(1)    For revenues and gathering, processing, and transmission costs 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 (LOSS)

(Unaudited)

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$	326	$	1,946
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	3		(1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	329		1,945
Comprehensive income attributable to noncontrolling interest – Egypt	84		119
Comprehensive income attributable to noncontrolling interest – Altus	—		14
Comprehensive loss attributable to Altus Preferred Unit limited partners	—		(70)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	245	$	1,882

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 Three Months Ended March 31,
	2023		2022
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$	326	$	1,946
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	(33)		57
Gain on divestitures, net	(1)		(1,176)
Exploratory dry hole expense and unproved leasehold impairments	35		9
Depreciation, depletion, and amortization	332		291
Asset retirement obligation accretion	28		29
Provision for (benefit from) deferred income taxes	138		(40)
(Gain) loss on extinguishment of debt	(9)		67
Other, net	30		(29)
Changes in operating assets and liabilities:
Receivables	(53)		(255)
Inventories	(31)		(43)
Drilling advances and other current assets	1		9
Deferred charges and other long-term assets	79		(13)
Accounts payable	(110)		18
Accrued expenses	(319)		18
Deferred credits and noncurrent liabilities	(78)		3
NET CASH PROVIDED BY OPERATING ACTIVITIES	335		891
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(543)		(358)
Leasehold and property acquisitions	(6)		(20)
Proceeds from sale of oil and gas properties	21		767
Proceeds from sale of Kinetik shares	—		224
Deconsolidation of Altus cash and cash equivalents	—		(143)
Other, net	(4)		(4)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(532)		466
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facilities, net	417		338
Payments on Apache fixed-rate debt	(65)		(1,370)
Distributions to noncontrolling interest - Egypt	(17)		(69)
Treasury stock activity, net	(142)		(261)
Dividends paid to APA common stockholders	(78)		(43)
Other, net	(9)		(20)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	106		(1,425)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(91)		(68)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	245		302
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	154	$	234
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	112	$	125
Income taxes paid, net of refunds	286		305

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

3

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	March 31, 2023		December 31, 2022
	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	154	$	245
Receivables, net of allowance of $119 and $117	1,518		1,466
Other current assets (Note 5)	1,060		997
	2,732		2,708
PROPERTY AND EQUIPMENT:
Oil and gas properties	42,834		42,356
Gathering, processing, and transmission facilities	447		449
Other	614		613
Less: Accumulated depreciation, depletion, and amortization	(34,716)		(34,406)
	9,179		9,012
OTHER ASSETS:
Equity method interests (Note 6)	605		624
Decommissioning security for sold Gulf of Mexico properties (Note 11)	132		217
Deferred charges and other	565		586
	$	13,213	$	13,147
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	658	$	771
Current debt	2		2
Other current liabilities (Note 7)	1,794		2,143
	2,454		2,916
LONG-TERM DEBT (Note 9)	5,796		5,451
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	460		314
Asset retirement obligation (Note 8)	1,963		1,940
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	656		738
Other	451		443
	3,530		3,435
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 420,570,661 and 419,869,987 shares issued, respectively	263		262
Paid-in capital	11,337		11,420
Accumulated deficit	(5,572)		(5,814)
Treasury stock, at cost, 111,971,530 and 108,310,838 shares, respectively	(5,601)		(5,459)
Accumulated other comprehensive income	17		14
APA SHAREHOLDERS’ EQUITY	444		423
Noncontrolling interest – Egypt	989		922
TOTAL EQUITY	1,433		1,345
	$	13,213	$	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 (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Quarter Ended March 31, 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	—		—		—		1,883		—		—		1,883		—		1,883
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		119		119
Net income attributable to noncontrolling interest – Altus	—		—		—		—		—		—		—		14		14
Net loss attributable to Altus Preferred Unit limited partners	(70)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(69)		(69)
Common dividends declared ($0.125 per share)	—		—		(43)		—		—		—		(43)		—		(43)
Deconsolidation of Altus	(642)		—		—		—		—		—		—		(72)		(72)
Treasury stock activity, net	—		—		—		—		(260)		—		(260)		—		(260)
Other	—		—		(2)		—		—		(1)		(3)		—		(3)
Balance at March 31, 2022	$	—	$	262	$	11,600	$	(7,605)	$	(4,296)	$	21	$	(18)	$	870	$	852
For the Quarter Ended March 31, 2023
Balance at December 31, 2022	$	—	$	262	$	11,420	$	(5,814)	$	(5,459)	$	14	$	423	$	922	$	1,345
Net income attributable to common stock	—		—		—		242		—		—		242		—		242
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		—		84		84
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(17)		(17)
Common dividends declared ($0.25 per share)	—		—		(78)		—		—		—		(78)		—		(78)
Treasury stock activity, net	—		—		—		—		(142)		—		(142)		—		(142)
Other	—		1		(5)		—		—		3		(1)		—		(1)
Balance at March 31, 2023	$	—	$	263	$	11,337	$	(5,572)	$	(5,601)	$	17	$	444	$	989	$	1,433

(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

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 March 31, 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. 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 variable interest entity 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 variable interest entity under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.

6

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 months ended March 31, 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 three months ended March 31, 2023 and 2022.

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Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.4 billion and $1.3 billion as of March 31, 2023 and December 31, 2022, respectively.

Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation 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.

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.

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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 first quarter of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $6 million.

During the first quarter of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $21 million, recognizing a gain of approximately $1 million upon closing of these transactions.

2022 Activity

During the first quarter 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 Company also completed the sale of other non-core assets and leasehold in multiple transactions for total cash proceeds of $8 million. The Company recognized a gain of approximately $2 million upon closing of these transactions during the first quarter of 2022.

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.

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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 $528 million and $474 million as of March 31, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity in Egypt and offshore Suriname. Approximately $5 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the three months ended March 31, 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.

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 March 31, 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 March 31, 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
April—June 2023	NYMEX Henry Hub/IF Waha	2,275	$(1.54)	—	—
April—June 2023	NYMEX Henry Hub/IF HSC	—	—	2,275	$(0.11)
July—September 2023	NYMEX Henry Hub/IF Waha	1,840	$(1.62)	—	—
July—September 2023	NYMEX Henry Hub/IF HSC	—	—	1,840	$(0.19)
April—December 2023	NYMEX Henry Hub/IF Waha	55,000	$(1.15)	—	—
April—December 2023	NYMEX Henry Hub/IF HSC	—	—	55,000	$(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)

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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)
March 31, 2023
Assets:
Commodity derivative instruments	$	—	$	3	$	—	$	3	$	3	$	6
Liabilities:
Commodity derivative instruments	—		14		—		14		3		17
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:

	March 31, 2023		December 31, 2022
	(In millions)
Current Assets: Other current assets	$	3	$	—
Other Assets: Deferred charges and other	3		5
Total derivative assets	$	6	$	5
Current Liabilities: Other current liabilities	$	17	$	50
Deferred Credits and Other Noncurrent Liabilities: Other	—		—
Total derivative liabilities	$	17	$	50

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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 March 31,
	2023		2022
	(In millions)
Realized:
Commodity derivative instruments	$	20	$	(5)
Realized gains (losses), net	20		(5)
Unrealized:
Commodity derivative instruments	33		(24)
Foreign currency derivative instruments	—		(2)
Preferred Units embedded derivative	—		(31)
Unrealized gains (losses), net	33		(57)
Derivative instrument gains (losses), net	$	53	$	(62)

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:

	March 31, 2023		December 31, 2022
	(In millions)
Inventories	$	488	$	427
Drilling advances	85		89
Prepaid assets and other	37		31
Current decommissioning security for sold Gulf of Mexico assets	450		450
Total Other current assets	$	1,060	$	997

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 and dividends received 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. As of March 31, 2023, the Company’s ownership of 19.3 million shares represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock.

During the first quarters of 2023 and 2022, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $19 million and a gain of $24 million, respectively, which were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.

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During the first quarters of 2023 and 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the BCP Business Combination transaction totaling $26 million and $10 million, respectively. As of March 31, 2023, the Company has recorded accrued GPT costs payable to Kinetik of approximately $18 million. In addition, the Company sold natural gas and NGLs to Kinetik during the first quarter of 2023 totaling $14 million. As of March 31, 2023, the Company has recorded receivables from Kinetik of approximately $9 million.

7.    OTHER CURRENT LIABILITIES

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

	March 31, 2023		December 31, 2022
	(In millions)
Accrued operating expenses	$	154	$	145
Accrued exploration and development	363		333
Accrued compensation and benefits	216		514
Accrued interest	67		97
Accrued income taxes	136		90
Current asset retirement obligation	55		55
Current operating lease liability	143		167
Current decommissioning contingency for sold Gulf of Mexico properties	433		450
Other	227		292
Total Other current liabilities	$	1,794	$	2,143

8.    ASSET RETIREMENT OBLIGATION

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

	March 31, 2023
	(In millions)
Asset retirement obligation, December 31, 2022	$	1,995
Liabilities incurred	5
Liabilities settled	(10)
Accretion expense	28
Asset retirement obligation, March 31, 2023	2,018
Less current portion	(55)
Asset retirement obligation, long-term	$	1,963

9.    DEBT AND FINANCING COSTS

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

	March 31, 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)	983		566
Apache finance lease obligations	34		34
Unamortized discount	(27)		(27)
Debt issuance costs	(27)		(28)
Total debt	5,798		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,796	$	5,451

(1)    The fair values of the Apache notes and debentures were $4.2 billion at each of March 31, 2023 and December 31, 2022.

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 March 31, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations.

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During the quarter ended March 31, 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 quarter ended March 31, 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 quarter ended March 31, 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 March 31, 2023, there were $983 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £590 million in letters of credit outstanding under the GBP 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.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of March 31, 2023, there were £261 million and $17 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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Financing Costs, Net

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

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Interest expense	$	88	$	90
Amortization of debt issuance costs	1		2
Capitalized interest	(6)		(3)
(Gain) loss on extinguishment of debt	(9)		67
Interest income	(2)		(4)
Financing costs, net	$	72	$	152

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.

During the first quarter of 2023, 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 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 first quarter of 2022, the Company’s 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, 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 recorded 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 within 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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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 March 31, 2023, the Company has an accrued liability of approximately $64 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. For material matters that 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.

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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 plaintiff’s 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.

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 believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

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. The Company believes that plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

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 believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company.

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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 believes that plaintiffs’ claims lack merit and 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. 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 believe that plaintiffs’ claims lack merit and intend to vigorously defend these lawsuits.

Environmental Matters

As of March 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $1 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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

The Company is not aware of any environmental claims existing as of March 31, 2023 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

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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. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure 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 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 March 31, 2023, Apache has incurred $291 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 $195 million had been reimbursed from Trust A as of March 31, 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 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 March 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $1.1 billion to $1.3 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $1.1 billion as of March 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $656 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $433 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.

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As of March 31, 2023, the Company has also recorded a $582 million asset, which represents the 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, $132 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current assets.”

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 March 31,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	242	311	$	0.78	$	1,883	346	$	5.44
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	1	$	(0.01)
Diluted:
Income attributable to common stock	$	242	312	$	0.78	$	1,883	347	$	5.43

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 2.4 million and 2.9 million during the first quarters 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 first quarter of 2023, the Company repurchased 3.7 million shares at an average price of $38.93 per share, and as of March 31, 2023, the Company had remaining authorization to repurchase up to 49 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the first quarter of 2022, the Company repurchased 7.2 million shares at an average price of $36.08 per share. 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 March 31, 2023 and 2022, the Company paid $78 million and $43 million, respectively, in dividends on its common stock.

During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021, approved a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend to $0.25 per share.

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13.    BUSINESS SEGMENT INFORMATION

As of March 31, 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 March 31, 2023	(In millions)
Revenues:
Oil revenues	$	629	$	282	$	486	$	—	$	—	$	1,397
Natural gas revenues	93		60		89		—		—		242
Natural gas liquids revenues	—		10		120		—		—		130
Oil, natural gas, and natural gas liquids production revenues	722		352		695		—		—		1,769
Purchased oil and gas sales	—		—		239		—		—		239
	722		352		934		—		—		2,008
Operating Expenses:
Lease operating expenses	97		77		147		—		—		321
Gathering, processing, and transmission	7		11		60		—		—		78
Purchased oil and gas costs	—		—		216		—		—		216
Taxes other than income	—		—		52		—		—		52
Exploration	36		5		3		—		8		52
Depreciation, depletion, and amortization	123		58		151		—		—		332
Asset retirement obligation accretion	—		18		10		—		—		28
	263		169		639		—		8		1,079
Operating Income (Loss)(2)	$	459	$	183	$	295	$	—	$	(8)	929
Other Income (Expense):
Derivative instrument gains, net											53
Gain on divestitures, net											1
Other, net											(32)
General and administrative											(65)
Transaction, reorganization, and separation											(4)
Financing costs, net											(72)
Income Before Income Taxes											$	810
Total Assets(3)	$	3,334	$	1,836	$	7,525	$	—	$	518	$	13,213

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	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream
For the Quarter Ended March 31, 2022	(In millions)
Revenues:
Oil revenues	$	790	$	328	$	599	$	—	$	—	$	1,717
Natural gas revenues	98		99		183		—		—		380
Natural gas liquids revenues	3		16		207		—		(3)		223
Oil, natural gas, and natural gas liquids production revenues	891		443		989		—		(3)		2,320
Purchased oil and gas sales	—		—		344		5		—		349
Midstream service affiliate revenues	—		—		—		16		(16)		—
	891		443		1,333		21		(19)		2,669
Operating Expenses:
Lease operating expenses	131		96		118		—		(1)		344
Gathering, processing, and transmission	5		12		77		5		(18)		81
Purchased oil and gas costs	—		—		351		—		—		351
Taxes other than income	—		—		67		3		—		70
Exploration	15		5		4		—		18		42
Depreciation, depletion, and amortization	97		62		130		2		—		291
Asset retirement obligation accretion	—		20		8		1		—		29
	248		195		755		11		(1)		1,208
Operating Income (Loss)(2)	$	643	$	248	$	578	$	10	$	(18)	1,461
Other Income (Expense):
Derivative instrument losses, net											(62)
Gain on divestitures, net											1,176
Other, net											45
General and administrative											(156)
Transaction, reorganization, and separation											(14)
Financing costs, net											(152)
Income Before Income Taxes											$	2,298
Total Assets(3)	$	2,966	$	2,169	$	6,878	$	—	$	463	$	12,476

(1)Includes revenue from non-customers for the quarters ended March 31, 2023 and 2022 of:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Oil	$	172	$	250
Natural gas	26		31
Natural gas liquids	—		1

(2)Operating income of U.S. and North Sea includes leasehold impairments of $2 million and $3 million, respectively, for the first quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $3 million and $1 million, respectively, for the first quarter 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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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). Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas.

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.

Early in 2020, impacts of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions began to exert significant downward pressure on crude oil and natural gas prices. Since that time, commodity prices worldwide have largely rebounded; however, uncertainties in the global supply chain and financial markets, including the impact of inflation, rising interest rates, the conflict in Ukraine, 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 ongoing exploration and appraisal 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. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

In the first quarter of 2023, the Company reported net income attributable to common stock of $242 million, or $0.78 per diluted share, compared to a net income of $1.9 billion, or $5.43 per diluted share, in the first quarter of 2022. Results from the first quarter 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. In addition, net income for the first quarter of 2023 was impacted by lower revenues attributable to lower realized commodity prices when compared to the prior-year period.

The Company generated $335 million of cash from operating activities during the first three months of 2023, 62 percent lower than the first three months of 2022. APA’s lower operating cash flows for the first three months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company also repurchased 3.7 million shares of its common stock for $142 million during the first three months of 2023. The Company had $154 million of cash on hand at March 31, 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.

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•The Company’s quarterly dividend was increased in the fourth quarter of 2021 from $0.0625 per share to $0.125 per share. The dividend was further increased in the third quarter of 2022 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 first quarter of 2023, the Company has repurchased 71.1 million shares of the Company’s common stock. As of March 31, 2023, the Company had remaining authorization to repurchase up to 49 million shares under the Company’s share repurchase programs.

APA’s diverse asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. In response to prevailing weakness in Waha natural gas prices, the Company is ramping down planned Alpine High activity over the remainder of the year. This will result in a reduction of the Company’s upstream capital investment of approximately $100 million, for a full-year capital investment totaling approximately $1.9 billion to $2.0 billion. The Company does not expect this capital reduction to have a material impact on the Company’s 2023 U.S. production guidance.

Operational Highlights

Key operational highlights for the quarter include:

United States

•Daily boe production from the Company’s U.S. assets accounted for 51 percent of its total production during the first quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including two rigs in the Southern Midland Basin and three rigs in the Delaware Basin. The Company’s core Midland Basin development program and recently acquired properties in the Texas Delaware Basin continue to represent key growth areas for the U.S. assets.

International

•In Egypt, the Company averaged 17 drilling rigs and drilled 19 new productive wells during the first quarter of 2023. First quarter 2023 gross equivalent production in the Company’s Egypt assets decreased 1 percent from the first quarter of 2022, and net production decreased 2 percent. The Company increased drilling and workover activity throughout the past year with a heavier focus on oil prospects. As a result, gross and net oil production for the first three months of 2023 increased approximately 5 percent and 3 percent, respectively, when compared to the first three months of 2022.

•The Company averaged two rigs in the North Sea during the first quarter of 2023. Production increased at Beryl and Forties during the first quarter of 2023 following the completion of maintenance activities at the end of 2022 and improved facility operating efficiency compared to the prior year. The Company will release the Ocean Patriot semi-submersible drilling rig around mid-year 2023, once it completes its scheduled drilling campaign in the North Sea, and thereafter, the associated investment capital will be reallocated to other areas.

•Suriname activity in the first half of 2023 is focused on appraising the Krabdagu discovery in Block 58. The first appraisal well was recently completed, and a second appraisal well is currently being drilled.

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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 March 31,
	2023				2022
	$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	486	35	%	$	599	35	%
Egypt(1)	629		45	%	790		46	%
North Sea	282		20	%	328		19	%
Total(1)	$	1,397	100	%	$	1,717	100	%
Natural Gas Revenues:
United States	$	89	37	%	$	183	48	%
Egypt(1)	93		38	%	98		26	%
North Sea	60		25	%	99		26	%
Total(1)	$	242	100	%	$	380	100	%
NGL Revenues:
United States	$	120	92	%	$	204	91	%
Egypt(1)	—		—	%	3		2	%
North Sea	10		8	%	16		7	%
Total(1)	$	130	100	%	$	223	100	%
Oil and Gas Revenues:
United States	$	695	39	%	$	986	43	%
Egypt(1)	722		41	%	891		38	%
North Sea	352		20	%	443		19	%
Total(1)	$	1,769	100	%	$	2,320	100	%

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

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Production

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

	For the Quarter Ended March 31,
	2023	Increase (Decrease)	2022
Oil Volume (b/d)
United States	71,888	3%	69,636
Egypt(1)(2)	87,795	3%	85,018
North Sea	37,502	6%	35,242
Total	197,185	4%	189,896
Natural Gas Volume (Mcf/d)
United States	441,527	(8)%	477,637
Egypt(1)(2)	356,350	(8)%	386,577
North Sea	40,360	5%	38,466
Total	838,237	(7)%	902,680
NGL Volume (b/d)
United States	56,103	(9)%	61,711
Egypt(1)(2)	—	NM	491
North Sea	1,255	(16)%	1,498
Total	57,358	(10)%	63,700
BOE per day(3)
United States	201,580	(4)%	210,953
Egypt(1)(2)	147,186	(2)%	149,938
North Sea(4)	45,483	5%	43,151
Total	394,249	(2)%	404,042

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

	For the Quarter Ended March 31,
	2023	2022
Oil (b/d)	140,764	134,397
Natural Gas (Mcf/d)	545,049	597,812
NGL (b/d)	—	735

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

	For the Quarter Ended March 31,
	2023	2022
Oil (b/d)	29,294	28,328
Natural Gas (Mcf/d)	118,903	128,764
NGL (b/d)	—	164

(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 first quarters of 2023 and 2022 were 46,632 boe/d and 43,668 boe/d, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

NM — Not Meaningful

26

Pricing

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

	For the Quarter Ended March 31,
	2023		Increase (Decrease)	2022
Average Oil Price – Per barrel
United States	$	75.17	(21)%	$	95.58
Egypt	79.58		(23)%	103.22
North Sea	81.57		(20)%	102.20
Total	78.37		(22)%	100.23
Average Natural Gas Price – Per Mcf
United States	$	2.24	(47)%	$	4.25
Egypt	2.89		2%	2.83
North Sea	17.58		(46)%	32.35
Total	3.22		(31)%	4.70
Average NGL Price – Per barrel
United States	$	23.79	(35)%	$	36.67
Egypt	—		NM	77.81
North Sea	56.92		(24)%	74.64
Total	24.84		(35)%	38.33

NM — Not Meaningful

First-Quarter 2023 compared to First-Quarter 2022

Crude Oil Crude oil revenues for the first quarter of 2023 totaled $1.4 billion, a $320 million decrease from the comparative 2022 quarter. A 22 percent decrease in average realized prices decreased first-quarter 2023 oil revenues by $374 million compared to the prior-year quarter, while 4 percent higher average daily production increased revenues by $54 million. Crude oil revenues accounted for 79 percent of total oil and gas production revenues and 50 percent of worldwide production in the first quarter of 2023. Crude oil prices realized in the first quarter of 2023 averaged $78.37 per barrel, compared with $100.23 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production increased 7.3 Mb/d to 197.2 Mb/d during the first quarter of 2023 from the comparative prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity, and recompletions, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the first quarter of 2023 totaled $242 million, a $138 million decrease from the comparative 2022 quarter. A 31 percent decrease in average realized prices decreased first-quarter 2023 natural gas revenues by $120 million compared to the prior-year quarter, while 7 percent lower average daily production decreased revenues by $18 million. Natural gas revenues accounted for 14 percent of total oil and gas production revenues and 35 percent of worldwide production during the first quarter of 2023. The Company’s worldwide natural gas production decreased 64.4 MMcf/d to 838 MMcf/d during the first quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets, partially offset by increased drilling activity and recompletions.

NGL NGL revenues for the first quarter of 2023 totaled $130 million, a $93 million decrease from the comparative 2022 quarter. A 35 percent decrease in average realized prices decreased first-quarter 2023 NGL revenues by $78 million compared to the prior-year quarter, while 10 percent lower average daily production decreased revenues by $15 million. NGL revenues accounted for 7 percent of total oil and gas production revenues and 15 percent of worldwide production during the first quarter of 2023. The Company’s worldwide NGL production decreased 6.3 Mb/d to 57.4 Mb/d during the first quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity and recompletions.

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Altus Midstream Revenues

Prior to the BCP Business Combination and associated deconsolidation of Altus on February 22, 2022, Altus Midstream’s services revenues generated through its fee-based contractual arrangements with the Company totaled $16 million during the first quarter of 2022. These revenues were eliminated upon consolidation.

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 $239 million and $349 million during the first quarters of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $216 million and $351 million during the first quarters of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in the first quarter primarily due to lower average natural gas prices in the first quarter of 2023 compared to the prior-year period.

Operating Expenses

The Company’s operating expenses were as follows:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Lease operating expenses	$	321	$	344
Gathering, processing, and transmission	78		81
Purchased oil and gas costs	216		351
Taxes other than income	52		70
Exploration	52		42
General and administrative	65		156
Transaction, reorganization, and separation	4		14
Depreciation, depletion, and amortization:
Oil and gas property and equipment	325		278
Gathering, processing, and transmission assets	2		5
Other assets	5		8
Asset retirement obligation accretion	28		29
Financing costs, net	72		152
Total Operating Expenses	$	1,220	$	1,530

Lease Operating Expenses (LOE)

LOE decreased $23 million in the first quarter of 2023 from the comparative prior-year period. On a per-unit basis, LOE decreased 5 percent in the first quarter of 2023 from the comparative prior-year period. The decrease was primarily driven by the impact from changes in foreign currency exchange rates against the US dollar and mark-to-market adjustments for cash-based stock compensation expense resulting from changes in the Company’s stock price. These decreases were partially offset by overall higher labor costs, chemical and other operating costs trending with global inflation and increased workover activity in the U.S.

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Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Third-party processing and transmission costs	$	52	$	66
Midstream service costs – ALTM	—		18
Midstream service costs – Kinetik	26		10
Upstream processing and transmission costs	78		94
Midstream operating expenses	—		5
Intersegment eliminations	—		(18)
Total Gathering, processing, and transmission	$	78	$	81

GPT costs decreased $3 million in the first quarter of 2023 from the comparative prior-year period, the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $16 million in the first quarter of 2023 from the comparative prior-year period, primarily driven by a decrease in production volumes when compared to the prior-year period. Costs for services provided by ALTM in the first quarter of 2022 and 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. Midstream services provided by Kinetik totaled $26 million and $10 million in the first quarters of 2023 and 2022, respectively.

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $216 million during the first quarter of 2023 compared to $351 million during the first quarter of 2022. Purchased oil and gas costs were offset by associated purchase sales of $239 million during the first quarter of 2023 compared to $349 million during the first quarter of 2022, as discussed above.

Taxes Other Than Income

Taxes other than income decreased $18 million from the first quarter of 2022 primarily from lower severance taxes driven by lower commodity prices as compared to the prior-year period.

Exploration Expenses

The Company’s exploration expenses were as follows:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Unproved leasehold impairments	$	5	$	4
Dry hole expense	30		5
Geological and geophysical expense	1		15
Exploration overhead and other	16		18
Total Exploration	$	52	$	42

Exploration expenses for the first quarter of 2023 increased $10 million from the first quarter of 2022 primarily the result of higher dry hole expenses in Egypt, partially offset by a decrease in geological and geophysical expense and exploration overhead.

General and Administrative (G&A) Expenses

G&A expenses decreased $91 million compared to the first quarter of 2022. The decrease in expenses for the first quarter of 2023 compared to the prior-year period was primarily driven by lower cash-based stock compensation expense resulting from changes in the Company’s stock price.

29

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $10 million from the first quarter of 2022. The decrease in costs during the first quarter of 2023 compared to the prior-year period was primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2022.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties increased $47 million from the first quarter of 2022. The Company’s DD&A rate on its oil and gas properties increased $1.49 per boe from the first quarter of 2022 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.

Financing Costs, Net

The Company’s Financing costs were as follows:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Interest expense	$	88	$	90
Amortization of debt issuance costs	1		2
Capitalized interest	(6)		(3)
(Gain) loss on extinguishment of debt	(9)		67
Interest income	(2)		(4)
Total Financing costs, net	$	72	$	152

Net financing costs decreased $80 million from the first quarter of 2022, primarily the result of losses incurred on the extinguishment of debt during the first quarter of 2022 and gains on extinguishment of debt in the first quarter of 2023.

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 first quarter of 2023, 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 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 first quarter of 2022, the Company’s 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, 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.

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The Company recorded 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 within 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.

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 estimated upstream capital investment to be approximately $2.0 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 all other liquidity and capital resource needs.

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.

31

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 Three Months Ended March 31,
	2023		2022
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	335	$	891
Proceeds from revolving credit facilities, net	417		338
Proceeds from asset divestitures	21		767
Proceeds from sale of Kinetik shares	—		224
Total Sources of Cash and Cash Equivalents	773		2,220
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	543	$	358
Leasehold and property acquisitions	6		20
Payments on Apache fixed-rate debt	65		1,370
Dividends paid to APA common stockholders	78		43
Distributions to noncontrolling interest - Egypt	17		69
Treasury stock activity, net	142		261
Deconsolidation of Altus cash and cash equivalents	—		143
Other, net	13		24
Total Uses of Cash and Cash Equivalents	864		2,288
Decrease in cash and cash equivalents	$	(91)	$	(68)

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 three months of 2023 totaled $335 million, down $556 million from the first three months of 2022, primarily the result of 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 March 31, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $983 million, an increase of $417 million since December 31, 2022. As of March 31, 2022, outstanding borrowings under Apache’s former syndicated credit facility were $880 million, an increase of $338 million since December 31, 2021.

Proceeds from Asset Divestitures The Company received $21 million and $767 million in proceeds from the divestiture of certain non-core assets during the first three 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 three 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 $543 million and $358 million during the first three 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, in-line with operating cash flows. The Company operated an average of 26 drilling rigs during the first quarter of 2023, compared to an average of 17 drilling rigs during the first quarter of 2022.

Leasehold and Property Acquisitions During the first three months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $6 million and $20 million, respectively.

Payments on Apache Fixed-Rate Debt During the quarter ended March 31, 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 quarter ended March 31, 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 quarter ended March 31, 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 $78 million and $43 million during the first three months of 2023 and 2022, respectively, for dividends on its common stock. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625 and, in the fourth quarter of 2021, a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend 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 $17 million and $69 million during the first three months of 2023 and 2022, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first three months of 2023, the Company repurchased 3.7 million shares at an average price of $38.93 per share totaling $142 million, and as of March 31, 2023, the Company had remaining authorization to repurchase 49 million shares. In the first quarter of 2022, the Company repurchased 7.2 million shares at an average price of $36.08 per share totaling $261 million.

33

Liquidity

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

	March 31, 2023		December 31, 2022
	(In millions)
Cash and cash equivalents	$	154	$	245
Total debt – APA and Apache	5,798		5,453
Total equity	1,433		1,345
Available committed borrowing capacity under syndicated credit facilities	1,919		2,238

Cash and Cash Equivalents As of March 31, 2023, the Company had $154 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 March 31, 2023, the Company had $5.8 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of March 31, 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 March 31, 2023, there were $983 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £590 million in letters of credit outstanding under the GBP 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 Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of March 31, 2023 there were £261 million and $17 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.

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.

34

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. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure 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 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 March 31, 2023, Apache has incurred $291 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 $195 million had been reimbursed from Trust A as of March 31, 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 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.

35

As of March 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $1.1 billion to $1.3 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $1.1 billion as of March 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $656 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $433 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 March 31, 2023, the Company has also recorded a $582 million asset, which represents the 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, $132 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 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, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.

The Company’s average crude oil price realizations decreased 22 percent from $100.23 per barrel to $78.37 per barrel during the first quarters of 2022 and 2023, respectively. The Company’s average natural gas price realizations decreased 31 percent from $4.70 per Mcf to $3.22 per Mcf during the first quarters of 2022 and 2023, respectively. The Company’s average NGL price realizations decreased 35 percent from $38.33 per barrel to $24.84 per barrel during the first quarters of 2022 and 2023, respectively. Based on average daily production for the first 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 $18 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 $5 million.

36

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 March 31, 2023, the Company had open natural gas derivatives not designated as cash flow hedges in a net liability position with a fair value of $11 million. A 10 percent increase in gas prices would result in a net derivative liability position with a fair value of $23 million, while a 10 percent decrease in prices would result in a net derivative asset position with a fair value of $1 million. These fair value changes assume volatility based on prevailing market parameters as of March 31, 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 March 31, 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 March 31, 2023, the Company had approximately $154 million in cash and cash equivalents, approximately 68 percent of which was invested in money market funds and short-term investments with major financial institutions. As of March 31, 2023, there were $983 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 $4 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of March 31, 2023.

37

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 March 31, 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 March 31, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

38

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 Report on Form 10-Q for the quarterly period ended March 31, 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 March 31, 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)
January 1 to January 31, 2023	1,115,162	$	45.96	1,115,162	51,515,635
February 1 to February 28, 2023	—	—		—	51,515,635
March 1 to March 31, 2023	2,547,546	35.85		2,547,546	48,968,089
Total	3,662,708	$	38.93

(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.

39

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	–	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).
*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 March 31, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (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

40

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:	May 4, 2023	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	May 4, 2023	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

41

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: May 4, 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: May 4, 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 March 31, 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: May 4, 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 March 31, 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: May 4, 2023

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

XML

Cover - shares	3 Months Ended
	Mar. 31, 2023	Apr. 30, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 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		308,599,131
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
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
		Mar. 31, 2023	Mar. 31, 2022
REVENUES AND OTHER:
Derivative instrument gains (losses), net		$ 53	$ (62)
Gain on divestitures, net		1	1,176
Other, net		(32)	45
Total revenues and other		2,030	3,828
OPERATING EXPENSES:
Lease operating expenses		321	344
Taxes other than income		52	70
Exploration		52	42
General and administrative		65	156
Transaction, reorganization, and separation		4	14
Depreciation, depletion, and amortization		332	291
Asset retirement obligation accretion		28	29
Financing costs, net		72	152
Total operating expenses		1,220	1,530
NET INCOME BEFORE INCOME TAXES		810	2,298
Current income tax provision		346	392
Deferred income tax provision (benefit)		138	(40)
NET INCOME INCLUDING NONCONTROLLING INTERESTS		326	1,946
Net loss attributable to Altus Preferred Unit limited partners		0	(70)
NET INCOME ATTRIBUTABLE TO COMMON STOCK		$ 242	$ 1,883
NET INCOME PER COMMON SHARE:
Basic (in USD per share)		$ 0.78	$ 5.44
Diluted (in USD per share)		$ 0.78	$ 5.43
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)		311	346
Diluted (in shares)		312	347
Noncontrolling interest – Egypt
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		$ 84	$ 119
Noncontrolling interest - Altus
OPERATING EXPENSES:
Net income attributable to noncontrolling interest		0	14
Oil and gas
REVENUES AND OTHER:
Total revenues		2,008	2,669
Oil and gas, excluding purchased
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	[1]	1,769	2,320
OPERATING EXPENSES:
Cost of oil and gas purchased	[1]	78	81
Purchased oil and gas sales
REVENUES AND OTHER:
Purchased oil and gas sales		239	349
OPERATING EXPENSES:
Cost of oil and gas purchased		$ 216	$ 351

[1] For revenues and gathering, processing, and transmission costs associated with Kinetik, refer to Note 6—Equity Method Interests for further detail.

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 326	$ 1,946
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	3	(1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	329	1,945
Comprehensive loss attributable to Altus Preferred Unit limited partners	0	(70)
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	245	1,882
Noncontrolling interest – Egypt
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income attributable to noncontrolling interest	84	119
Noncontrolling interest - Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income attributable to noncontrolling interest	$ 0	$ 14

XML

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$ 326	$ 1,946
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	(33)	57
Gain on divestitures, net	(1)	(1,176)
Exploratory dry hole expense and unproved leasehold impairments	35	9
Depreciation, depletion, and amortization	332	291
Asset retirement obligation accretion	28	29
Provision for (benefit from) deferred income taxes	138	(40)
(Gain) loss on extinguishment of debt	(9)	67
Other, net	30	(29)
Changes in operating assets and liabilities:
Receivables	(53)	(255)
Inventories	(31)	(43)
Drilling advances and other current assets	1	9
Deferred charges and other long-term assets	79	(13)
Accounts payable	(110)	18
Accrued expenses	(319)	18
Deferred credits and noncurrent liabilities	(78)	3
NET CASH PROVIDED BY OPERATING ACTIVITIES	335	891
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(543)	(358)
Leasehold and property acquisitions	(6)	(20)
Proceeds from sale of oil and gas properties	21	767
Proceeds from sale of Kinetik shares	0	224
Deconsolidation of Altus cash and cash equivalents	0	(143)
Other, net	(4)	(4)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(532)	466
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facilities, net	417	338
Payments on Apache fixed-rate debt	(65)	(1,370)
Distributions to noncontrolling interest - Egypt	(17)	(69)
Treasury stock activity, net	(142)	(261)
Dividends paid to APA common stockholders	(78)	(43)
Other, net	(9)	(20)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	106	(1,425)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(91)	(68)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	245	302
CASH AND CASH EQUIVALENTS AT END OF PERIOD	154	234
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	112	125
Income taxes paid, net of refunds	$ 286	$ 305

XML

CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 154	$ 245
Receivables, net of allowance of $119 and $117	1,518	1,466
Other current assets (Note 5)	1,060	997
Total current assets	2,732	2,708
PROPERTY AND EQUIPMENT:
Oil and gas properties	42,834	42,356
Gathering, processing, and transmission facilities	447	449
Other	614	613
Less: Accumulated depreciation, depletion, and amortization	(34,716)	(34,406)
Property and equipment, net	9,179	9,012
OTHER ASSETS:
Equity method interests (Note 6)	605	624
Decommissioning security for sold Gulf of Mexico properties (Note 11)	132	217
Deferred charges and other	565	586
Assets	13,213	13,147
CURRENT LIABILITIES:
Accounts payable	658	771
Current debt	2	2
Other current liabilities (Note 7)	1,794	2,143
Total current liabilities	2,454	2,916
LONG-TERM DEBT (Note 9)	5,796	5,451
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	460	314
Asset retirement obligation (Note 8)	1,963	1,940
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	656	738
Other	451	443
Total deferred credits and other noncurrent liabilities	3,530	3,435
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 420,570,661 and 419,869,987 shares issued, respectively	263	262
Paid-in capital	11,337	11,420
Accumulated deficit	(5,572)	(5,814)
Treasury stock, at cost, 111,971,530 and 108,310,838 shares, respectively	(5,601)	(5,459)
Accumulated other comprehensive income	17	14
APA SHAREHOLDERS’ EQUITY	444	423
TOTAL EQUITY	1,433	1,345
TOTAL LIABILITIES AND EQUITY	13,213	13,147
Noncontrolling interest – Egypt
EQUITY (DEFICIT):
Noncontrolling interest – Egypt	$ 989	$ 922

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CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Receivables, allowance	$ 119	$ 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)	420,570,661	419,869,987
Treasury stock, shares (in shares)	111,971,530	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 (DEFICIT)	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	Noncontrolling Interests	[1]	Noncontrolling Interests Noncontrolling interest – Egypt	[1]	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 Mar. 31, 2022	[1]																0
Beginning balance at Dec. 31, 2021		$ (717)			$ (1,595)	$ 262	$ 11,645	$ (9,488)	$ (4,036)	$ 22	$ 878
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		1,883			1,883			1,883
Net income attributable to noncontrolling interest			$ 119	14									$ 119		14
Distributions to noncontrolling interest			(69)										(69)
Common dividends declared		(43)			(43)		(43)
Deconsolidation of Altus				(72)											$ (72)		(642)	[1]
Treasury stock activity, net		(260)			(260)				(260)
Other		(3)			(3)		(2)			(1)
Ending balance at Mar. 31, 2022		852			(18)	262	11,600	(7,605)	(4,296)	21	870
Beginning balance at Dec. 31, 2022	[1]																0
Ending balance at Mar. 31, 2023	[1]																$ 0
Beginning balance at Dec. 31, 2022		1,345			423	262	11,420	(5,814)	(5,459)	14	922
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock		242			242			242
Net income attributable to noncontrolling interest			84	$ 0									84
Distributions to noncontrolling interest			$ (17)										$ (17)
Common dividends declared		(78)			(78)		(78)
Treasury stock activity, net		(142)			(142)				(142)
Other		(1)			(1)	1	(5)			3
Ending balance at Mar. 31, 2023		$ 1,433			$ 444	$ 263	$ 11,337	$ (5,572)	$ (5,601)	$ 17	$ 989

[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.

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2023	Sep. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.25	$ 0.125	$ 0.125	$ 0.0625	$ 0.025

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NATURE OF OPERATIONS	3 Months Ended
	Mar. 31, 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

3 Months Ended

Mar. 31, 2023

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of March 31, 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. 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 variable interest entity 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 variable interest entity 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 months ended March 31, 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 three months ended March 31, 2023 and 2022.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.4 billion and $1.3 billion as of March 31, 2023 and December 31, 2022, respectively.

Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation 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.

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

3 Months Ended

Mar. 31, 2023

Business Combination and Asset Acquisition [Abstract]

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES

2023 Activity

During the first quarter of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $6 million.

During the first quarter of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $21 million, recognizing a gain of approximately $1 million upon closing of these transactions.

2022 Activity

During the first quarter 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 Company also completed the sale of other non-core assets and leasehold in multiple transactions for total cash proceeds of $8 million. The Company recognized a gain of approximately $2 million upon closing of these transactions during the first quarter of 2022.

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

3 Months Ended

Mar. 31, 2023

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $528 million and $474 million as of March 31, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity in Egypt and offshore Suriname. Approximately $5 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the three months ended March 31, 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

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company 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 March 31, 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 March 31, 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
April—June 2023	NYMEX Henry Hub/IF Waha	2,275	$(1.54)	—	—
April—June 2023	NYMEX Henry Hub/IF HSC	—	—	2,275	$(0.11)
July—September 2023	NYMEX Henry Hub/IF Waha	1,840	$(1.62)	—	—
July—September 2023	NYMEX Henry Hub/IF HSC	—	—	1,840	$(0.19)
April—December 2023	NYMEX Henry Hub/IF Waha	55,000	$(1.15)	—	—
April—December 2023	NYMEX Henry Hub/IF HSC	—	—	55,000	$(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)
March 31, 2023
Assets:
Commodity derivative instruments	$	—	$	3	$	—	$	3	$	3	$	6
Liabilities:
Commodity derivative instruments	—		14		—		14		3		17
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:

	March 31, 2023		December 31, 2022
	(In millions)
Current Assets: Other current assets	$	3	$	—
Other Assets: Deferred charges and other	3		5
Total derivative assets	$	6	$	5
Current Liabilities: Other current liabilities	$	17	$	50
Deferred Credits and Other Noncurrent Liabilities: Other	—		—
Total derivative liabilities	$	17	$	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 March 31,
	2023		2022
	(In millions)
Realized:
Commodity derivative instruments	$	20	$	(5)
Realized gains (losses), net	20		(5)
Unrealized:
Commodity derivative instruments	33		(24)
Foreign currency derivative instruments	—		(2)
Preferred Units embedded derivative	—		(31)
Unrealized gains (losses), net	33		(57)
Derivative instrument gains (losses), net	$	53	$	(62)

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

3 Months Ended

Mar. 31, 2023

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

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

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

	March 31, 2023		December 31, 2022
	(In millions)
Inventories	$	488	$	427
Drilling advances	85		89
Prepaid assets and other	37		31
Current decommissioning security for sold Gulf of Mexico assets	450		450
Total Other current assets	$	1,060	$	997

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EQUITY METHOD INTERESTS

3 Months Ended

Mar. 31, 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 and dividends received 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. As of March 31, 2023, the Company’s ownership of 19.3 million shares represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock.

During the first quarters of 2023 and 2022, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $19 million and a gain of $24 million, respectively, which were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.

During the first quarters of 2023 and 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the BCP Business Combination transaction totaling $26 million and $10 million, respectively. As of March 31, 2023, the Company has recorded accrued GPT costs payable to Kinetik of approximately $18 million. In addition, the Company sold natural gas and NGLs to Kinetik during the first quarter of 2023 totaling $14 million. As of March 31, 2023, the Company has recorded receivables from Kinetik of approximately $9 million.

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OTHER CURRENT LIABILITIES

3 Months Ended

Mar. 31, 2023

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES

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

	March 31, 2023		December 31, 2022
	(In millions)
Accrued operating expenses	$	154	$	145
Accrued exploration and development	363		333
Accrued compensation and benefits	216		514
Accrued interest	67		97
Accrued income taxes	136		90
Current asset retirement obligation	55		55
Current operating lease liability	143		167
Current decommissioning contingency for sold Gulf of Mexico properties	433		450
Other	227		292
Total Other current liabilities	$	1,794	$	2,143

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ASSET RETIREMENT OBLIGATION

3 Months Ended

Mar. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

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

	March 31, 2023
	(In millions)
Asset retirement obligation, December 31, 2022	$	1,995
Liabilities incurred	5
Liabilities settled	(10)
Accretion expense	28
Asset retirement obligation, March 31, 2023	2,018
Less current portion	(55)
Asset retirement obligation, long-term	$	1,963

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DEBT AND FINANCING COSTS

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS

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

	March 31, 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)	983		566
Apache finance lease obligations	34		34
Unamortized discount	(27)		(27)
Debt issuance costs	(27)		(28)
Total debt	5,798		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,796	$	5,451

(1)    The fair values of the Apache notes and debentures were $4.2 billion at each of March 31, 2023 and December 31, 2022.

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 March 31, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations.

During the quarter ended March 31, 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 quarter ended March 31, 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 quarter ended March 31, 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 March 31, 2023, there were $983 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £590 million in letters of credit outstanding under the GBP 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.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of March 31, 2023, there were £261 million and $17 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 March 31,
	2023		2022
	(In millions)
Interest expense	$	88	$	90
Amortization of debt issuance costs	1		2
Capitalized interest	(6)		(3)
(Gain) loss on extinguishment of debt	(9)		67
Interest income	(2)		(4)
Financing costs, net	$	72	$	152

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INCOME TAXES

3 Months Ended

Mar. 31, 2023

Income Tax Disclosure [Abstract]

INCOME TAXES

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 first quarter of 2023, 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 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 first quarter of 2022, the Company’s 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, 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 recorded 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 within 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

3 Months Ended

Mar. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of March 31, 2023, the Company has an accrued liability of approximately $64 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. For material matters that 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 plaintiff’s 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.

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 believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

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. The Company believes that plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

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 believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company.

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 believes that plaintiffs’ claims lack merit and 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. 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 believe that plaintiffs’ claims lack merit and intend to vigorously defend these lawsuits.

Environmental Matters

As of March 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $1 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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

The Company is not aware of any environmental claims existing as of March 31, 2023 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure 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 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 March 31, 2023, Apache has incurred $291 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 $195 million had been reimbursed from Trust A as of March 31, 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 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 March 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $1.1 billion to $1.3 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $1.1 billion as of March 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $656 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $433 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 March 31, 2023, the Company has also recorded a $582 million asset, which represents the 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, $132 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current assets.”

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CAPITAL STOCK

3 Months Ended

Mar. 31, 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 March 31,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	242	311	$	0.78	$	1,883	346	$	5.44
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	1	$	(0.01)
Diluted:
Income attributable to common stock	$	242	312	$	0.78	$	1,883	347	$	5.43

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 2.4 million and 2.9 million during the first quarters 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 first quarter of 2023, the Company repurchased 3.7 million shares at an average price of $38.93 per share, and as of March 31, 2023, the Company had remaining authorization to repurchase up to 49 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the first quarter of 2022, the Company repurchased 7.2 million shares at an average price of $36.08 per share. 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 March 31, 2023 and 2022, the Company paid $78 million and $43 million, respectively, in dividends on its common stock.

During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021, approved a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend to $0.25 per share.

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BUSINESS SEGMENT INFORMATION

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

As of March 31, 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 March 31, 2023	(In millions)
Revenues:
Oil revenues	$	629	$	282	$	486	$	—	$	—	$	1,397
Natural gas revenues	93		60		89		—		—		242
Natural gas liquids revenues	—		10		120		—		—		130
Oil, natural gas, and natural gas liquids production revenues	722		352		695		—		—		1,769
Purchased oil and gas sales	—		—		239		—		—		239
	722		352		934		—		—		2,008
Operating Expenses:
Lease operating expenses	97		77		147		—		—		321
Gathering, processing, and transmission	7		11		60		—		—		78
Purchased oil and gas costs	—		—		216		—		—		216
Taxes other than income	—		—		52		—		—		52
Exploration	36		5		3		—		8		52
Depreciation, depletion, and amortization	123		58		151		—		—		332
Asset retirement obligation accretion	—		18		10		—		—		28
	263		169		639		—		8		1,079
Operating Income (Loss)(2)	$	459	$	183	$	295	$	—	$	(8)	929
Other Income (Expense):
Derivative instrument gains, net											53
Gain on divestitures, net											1
Other, net											(32)
General and administrative											(65)
Transaction, reorganization, and separation											(4)
Financing costs, net											(72)
Income Before Income Taxes											$	810
Total Assets(3)	$	3,334	$	1,836	$	7,525	$	—	$	518	$	13,213

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream
For the Quarter Ended March 31, 2022	(In millions)
Revenues:
Oil revenues	$	790	$	328	$	599	$	—	$	—	$	1,717
Natural gas revenues	98		99		183		—		—		380
Natural gas liquids revenues	3		16		207		—		(3)		223
Oil, natural gas, and natural gas liquids production revenues	891		443		989		—		(3)		2,320
Purchased oil and gas sales	—		—		344		5		—		349
Midstream service affiliate revenues	—		—		—		16		(16)		—
	891		443		1,333		21		(19)		2,669
Operating Expenses:
Lease operating expenses	131		96		118		—		(1)		344
Gathering, processing, and transmission	5		12		77		5		(18)		81
Purchased oil and gas costs	—		—		351		—		—		351
Taxes other than income	—		—		67		3		—		70
Exploration	15		5		4		—		18		42
Depreciation, depletion, and amortization	97		62		130		2		—		291
Asset retirement obligation accretion	—		20		8		1		—		29
	248		195		755		11		(1)		1,208
Operating Income (Loss)(2)	$	643	$	248	$	578	$	10	$	(18)	1,461
Other Income (Expense):
Derivative instrument losses, net											(62)
Gain on divestitures, net											1,176
Other, net											45
General and administrative											(156)
Transaction, reorganization, and separation											(14)
Financing costs, net											(152)
Income Before Income Taxes											$	2,298
Total Assets(3)	$	2,966	$	2,169	$	6,878	$	—	$	463	$	12,476

(1)Includes revenue from non-customers for the quarters ended March 31, 2023 and 2022 of:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Oil	$	172	$	250
Natural gas	26		31
Natural gas liquids	—		1

(2)Operating income of U.S. and North Sea includes leasehold impairments of $2 million and $3 million, respectively, for the first quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $3 million and $1 million, respectively, for the first quarter 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 (Policies)

3 Months Ended

Mar. 31, 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. 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 variable interest entity 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 variable interest entity 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

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 three months ended March 31, 2023 and 2022.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered.

Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation 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.

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)

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Positions

As of March 31, 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
April—June 2023	NYMEX Henry Hub/IF Waha	2,275	$(1.54)	—	—
April—June 2023	NYMEX Henry Hub/IF HSC	—	—	2,275	$(0.11)
July—September 2023	NYMEX Henry Hub/IF Waha	1,840	$(1.62)	—	—
July—September 2023	NYMEX Henry Hub/IF HSC	—	—	1,840	$(0.19)
April—December 2023	NYMEX Henry Hub/IF Waha	55,000	$(1.15)	—	—
April—December 2023	NYMEX Henry Hub/IF HSC	—	—	55,000	$(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)
March 31, 2023
Assets:
Commodity derivative instruments	$	—	$	3	$	—	$	3	$	3	$	6
Liabilities:
Commodity derivative instruments	—		14		—		14		3		17
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)
March 31, 2023
Assets:
Commodity derivative instruments	$	—	$	3	$	—	$	3	$	3	$	6
Liabilities:
Commodity derivative instruments	—		14		—		14		3		17
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:

	March 31, 2023		December 31, 2022
	(In millions)
Current Assets: Other current assets	$	3	$	—
Other Assets: Deferred charges and other	3		5
Total derivative assets	$	6	$	5
Current Liabilities: Other current liabilities	$	17	$	50
Deferred Credits and Other Noncurrent Liabilities: Other	—		—
Total derivative liabilities	$	17	$	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 March 31,
	2023		2022
	(In millions)
Realized:
Commodity derivative instruments	$	20	$	(5)
Realized gains (losses), net	20		(5)
Unrealized:
Commodity derivative instruments	33		(24)
Foreign currency derivative instruments	—		(2)
Preferred Units embedded derivative	—		(31)
Unrealized gains (losses), net	33		(57)
Derivative instrument gains (losses), net	$	53	$	(62)

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OTHER CURRENT ASSETS (Tables)

3 Months Ended

Mar. 31, 2023

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

Schedule of Other Current Assets

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

	March 31, 2023		December 31, 2022
	(In millions)
Inventories	$	488	$	427
Drilling advances	85		89
Prepaid assets and other	37		31
Current decommissioning security for sold Gulf of Mexico assets	450		450
Total Other current assets	$	1,060	$	997

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OTHER CURRENT LIABILITIES (Tables)

3 Months Ended

Mar. 31, 2023

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

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

	March 31, 2023		December 31, 2022
	(In millions)
Accrued operating expenses	$	154	$	145
Accrued exploration and development	363		333
Accrued compensation and benefits	216		514
Accrued interest	67		97
Accrued income taxes	136		90
Current asset retirement obligation	55		55
Current operating lease liability	143		167
Current decommissioning contingency for sold Gulf of Mexico properties	433		450
Other	227		292
Total Other current liabilities	$	1,794	$	2,143

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ASSET RETIREMENT OBLIGATION (Tables)

3 Months Ended

Mar. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligation

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

	March 31, 2023
	(In millions)
Asset retirement obligation, December 31, 2022	$	1,995
Liabilities incurred	5
Liabilities settled	(10)
Accretion expense	28
Asset retirement obligation, March 31, 2023	2,018
Less current portion	(55)
Asset retirement obligation, long-term	$	1,963

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DEBT AND FINANCING COSTS (Tables)

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Schedule of Debt

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

	March 31, 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)	983		566
Apache finance lease obligations	34		34
Unamortized discount	(27)		(27)
Debt issuance costs	(27)		(28)
Total debt	5,798		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,796	$	5,451

(1)    The fair values of the Apache notes and debentures were $4.2 billion at each of March 31, 2023 and December 31, 2022.

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 March 31,
	2023		2022
	(In millions)
Interest expense	$	88	$	90
Amortization of debt issuance costs	1		2
Capitalized interest	(6)		(3)
(Gain) loss on extinguishment of debt	(9)		67
Interest income	(2)		(4)
Financing costs, net	$	72	$	152

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CAPITAL STOCK (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2023					2022
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	242	311	$	0.78	$	1,883	346	$	5.44
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	1	$	(0.01)
Diluted:
Income attributable to common stock	$	242	312	$	0.78	$	1,883	347	$	5.43

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BUSINESS SEGMENT INFORMATION (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2023	(In millions)
Revenues:
Oil revenues	$	629	$	282	$	486	$	—	$	—	$	1,397
Natural gas revenues	93		60		89		—		—		242
Natural gas liquids revenues	—		10		120		—		—		130
Oil, natural gas, and natural gas liquids production revenues	722		352		695		—		—		1,769
Purchased oil and gas sales	—		—		239		—		—		239
	722		352		934		—		—		2,008
Operating Expenses:
Lease operating expenses	97		77		147		—		—		321
Gathering, processing, and transmission	7		11		60		—		—		78
Purchased oil and gas costs	—		—		216		—		—		216
Taxes other than income	—		—		52		—		—		52
Exploration	36		5		3		—		8		52
Depreciation, depletion, and amortization	123		58		151		—		—		332
Asset retirement obligation accretion	—		18		10		—		—		28
	263		169		639		—		8		1,079
Operating Income (Loss)(2)	$	459	$	183	$	295	$	—	$	(8)	929
Other Income (Expense):
Derivative instrument gains, net											53
Gain on divestitures, net											1
Other, net											(32)
General and administrative											(65)
Transaction, reorganization, and separation											(4)
Financing costs, net											(72)
Income Before Income Taxes											$	810
Total Assets(3)	$	3,334	$	1,836	$	7,525	$	—	$	518	$	13,213

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream
For the Quarter Ended March 31, 2022	(In millions)
Revenues:
Oil revenues	$	790	$	328	$	599	$	—	$	—	$	1,717
Natural gas revenues	98		99		183		—		—		380
Natural gas liquids revenues	3		16		207		—		(3)		223
Oil, natural gas, and natural gas liquids production revenues	891		443		989		—		(3)		2,320
Purchased oil and gas sales	—		—		344		5		—		349
Midstream service affiliate revenues	—		—		—		16		(16)		—
	891		443		1,333		21		(19)		2,669
Operating Expenses:
Lease operating expenses	131		96		118		—		(1)		344
Gathering, processing, and transmission	5		12		77		5		(18)		81
Purchased oil and gas costs	—		—		351		—		—		351
Taxes other than income	—		—		67		3		—		70
Exploration	15		5		4		—		18		42
Depreciation, depletion, and amortization	97		62		130		2		—		291
Asset retirement obligation accretion	—		20		8		1		—		29
	248		195		755		11		(1)		1,208
Operating Income (Loss)(2)	$	643	$	248	$	578	$	10	$	(18)	1,461
Other Income (Expense):
Derivative instrument losses, net											(62)
Gain on divestitures, net											1,176
Other, net											45
General and administrative											(156)
Transaction, reorganization, and separation											(14)
Financing costs, net											(152)
Income Before Income Taxes											$	2,298
Total Assets(3)	$	2,966	$	2,169	$	6,878	$	—	$	463	$	12,476

(1)Includes revenue from non-customers for the quarters ended March 31, 2023 and 2022 of:

	For the Quarter Ended March 31,
	2023		2022
	(In millions)
Oil	$	172	$	250
Natural gas	26		31
Natural gas liquids	—		1

(2)Operating income of U.S. and North Sea includes leasehold impairments of $2 million and $3 million, respectively, for the first quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $3 million and $1 million, respectively, for the first quarter 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
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 0	$ 0
Receivables from contracts with customer, net	$ 1,400,000,000		$ 1,300,000,000
Kinetik
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	10.00%
Sinopec | Apache Egypt
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	33.33%
Third-Party Investors | ALTM
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	21.00%

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ACQUISITIONS AND DIVESTITURES (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended	3 Months Ended
	Feb. 22, 2022	Mar. 31, 2022	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Feb. 21, 2022
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties			$ 21	$ 767
Deconsolidation gain	$ 609
Deconsolidation, net amount of balance sheet	193
Equity method interests			$ 605		$ 624
Shares sold (in shares)		4
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%
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			$ 21	8
Gain (loss) on sale of non-core assets			1	2
Non-Core Mineral Rights | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties				726
Gain (loss) on sale of non-core assets				$ 560
Permian Basin
Business Acquisition [Line Items]
Oil and gas property acquisitions consideration			$ 6

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CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 528	$ 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)	3 Months Ended
	Mar. 31, 2023 Counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative counterparties	7

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Details) - Natural gas revenues MMBTU in Thousands	3 Months Ended
	Mar. 31, 2023 $ / MMBTU MMBTU
Basis Swap Purchased | April—June 2023 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	2,275
Weighted Average Price Differential | $ / MMBTU	(1.54)
Basis Swap Purchased | July—September 2023 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	1,840
Weighted Average Price Differential | $ / MMBTU	(1.62)
Basis Swap Purchased | April—December 2023 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	55,000
Weighted Average Price Differential | $ / 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 | $ / MMBTU	(1.15)
Basis Swap Sold | April—June 2023 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	2,275
Weighted Average Price Differential | $ / MMBTU	(0.11)
Basis Swap Sold | July—September 2023 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	1,840
Weighted Average Price Differential | $ / MMBTU	(0.19)
Basis Swap Sold | April—December 2023 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	55,000
Weighted Average Price Differential | $ / 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 | $ / 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	Mar. 31, 2023	Dec. 31, 2022
Assets:
Derivative asset	$ 6	$ 5
Liabilities:
Derivative liability	17	50
Commodity derivative instruments
Assets:
Derivative asset, fair value	3	5
Derivative asset, netting	3	0
Derivative asset	6	5
Liabilities:
Derivative liability, fair value	14	50
Derivative liability, netting	3	0
Derivative liability	17	50
Quoted Price in Active Markets (Level 1) | Commodity derivative instruments
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Significant Other Inputs (Level 2) | Commodity derivative instruments
Assets:
Derivative asset, fair value	3	5
Liabilities:
Derivative liability, fair value	14	50
Significant Unobservable Inputs (Level 3) | Commodity derivative instruments
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	$ 0	$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative asset	$ 6	$ 5
Derivative liability	17	50
Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	3	0
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	3	5
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	17	50
Deferred Credits and Other Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	$ 0	$ 0

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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
	Mar. 31, 2023	Mar. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 33	$ (57)
Derivative instrument gains (losses), net	53	(62)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	20	(5)
Unrealized gains (losses), net	33	(57)
Derivative instrument gains (losses), net	53	(62)
Commodity derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	20	(5)
Unrealized gains (losses), net	33	(24)
Foreign currency derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	0	(2)
Preferred Units embedded derivative | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ (31)

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OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 488	$ 427
Drilling advances	85	89
Prepaid assets and other	37	31
Current decommissioning security for sold Gulf of Mexico assets	450	450
Total Other current assets	$ 1,060	$ 997

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EQUITY METHOD INTERESTS (Details) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2022 USD ($) shares	Mar. 31, 2023 USD ($) shares	Jun. 30, 2022	Mar. 31, 2022 USD ($)	Feb. 22, 2022 shares
Schedule of Equity Method Investments [Line Items]
Shares sold (in shares) | shares	4.0
Kinetik
Schedule of Equity Method Investments [Line Items]
Equity method investment, number of shares (in share) | shares		19.3			12.9
Shares sold (in shares) | shares	4.0
Loss on sale of stock	$ (25)
Interest percentage		13.00%
Changes in fair value of equity method interest gain (loss)		$ (19)		$ 24
Gathering, processing and transportation costs		26		$ 10
Gathering, processing and transportation costs payable		18
Revenue		14
Receivables from investee		$ 9
Kinetik | Kinetik
Schedule of Equity Method Investments [Line Items]
Stock split conversion ratio			2

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OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Accrued operating expenses	$ 154	$ 145
Accrued exploration and development	363	333
Accrued compensation and benefits	216	514
Accrued interest	67	97
Accrued income taxes	136	90
Current asset retirement obligation	55	55
Current operating lease liability	143	167
Current decommissioning contingency for sold Gulf of Mexico properties	433	450
Other	227	292
Total Other current liabilities	$ 1,794	$ 2,143

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ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period	$ 1,995
Liabilities incurred	5
Liabilities settled	(10)
Accretion expense	28	$ 29
Asset retirement obligation at the end of period	2,018
Less current portion	(55)		$ (55)
Asset retirement obligation, long-term	$ 1,963		$ 1,940

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Apache finance lease obligations	$ 34	$ 34
Unamortized discount	(27)	(27)
Debt issuance costs	(27)	(28)
Total debt	5,798	5,453
Current maturities	(2)	(2)
Long-term debt	5,796	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	4,200	4,200
Syndicated credit facility | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	$ 983	$ 566

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DEBT AND FINANCING COSTS - Additional Information (Details)			3 Months Ended
	Apr. 29, 2022 USD ($) option agreement	Jan. 18, 2022 USD ($)	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Mar. 31, 2023 GBP (£)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 GBP (£)	Apr. 29, 2022 GBP (£) agreement
Debt Instrument [Line Items]
Finance lease obligations, current			$ 2,000,000			$ 2,000,000
(Gain) loss on extinguishment of debt			(9,000,000)	$ 67,000,000
Number of syndicated credit agreements | 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			20,000,000			20,000,000
GBP Agreement | Line of Credit
Debt Instrument [Line Items]
Debt instrument term	5 years
Line of credit facility, committed amount | £								£ 1,500,000,000
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 | £					£ 590,000,000		£ 652,000,000
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			983,000,000			566,000,000
Apache credit facility
Debt Instrument [Line Items]
Letters of credit outstanding, amount			17,000,000		£ 261,000,000	$ 17,000,000	£ 199,000,000
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
Debt instrument repurchase program			65,000,000	16,000,000
Premium (discount) to par of debt repurchase			(10,000,000)	1,000,000
(Gain) loss on extinguishment of debt			$ (9,000,000)	1,000,000
Senior Notes | Cash Tender Offers
Debt Instrument [Line Items]
Debt repurchased principal amount				1,100,000,000
Debt instrument repurchase program				1,200,000,000
(Gain) loss on extinguishment of debt				66,000,000
Debt instrument, unamortized discount and issuance costs				$ 11,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Debt Disclosure [Abstract]
Interest expense	$ 88	$ 90
Amortization of debt issuance costs	1	2
Capitalized interest	(6)	(3)
(Gain) loss on extinguishment of debt	(9)	67
Interest income	(2)	(4)
Financing costs, net	$ 72	$ 152

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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							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 ($)	Dec. 31, 2021 USD ($) sidetrack	Dec. 31, 2013 USD ($) source	Mar. 31, 2023 USD ($) bond subsidiary	Dec. 31, 2022 USD ($)	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)	Mar. 12, 2014 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies									$ 64,000,000
Environmental tax and royalty obligations													$ 100,000,000
Retain right of obligations									45,000,000
Undiscounted reserve for environmental remediation									1,000,000
Decommissioning costs incurred									291,000,000
Decommissioning costs reimbursed amount									195,000,000
Standby loan agreed to provide related to ARO									400,000,000
Decommissioning contingency for sold									1,100,000,000
Decommissioning contingency for sold properties									656,000,000	$ 738,000,000
Current decommissioning contingency for sold Gulf of Mexico properties									433,000,000	450,000,000
Decommissioning security for sold properties									582,000,000
Trust account for disposal group, number of net profits interests									132,000,000	217,000,000
Current decommissioning security for sold Gulf of Mexico assets									$ 450,000,000	$ 450,000,000
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 | source								2
Number of bond held | bond									2
Number of debt instrument held | subsidiary									5
Minimum
Commitment And Contingencies [Line Items]
AROs, estimated liability									$ 1,100,000,000
Maximum
Commitment And Contingencies [Line Items]
AROs, estimated liability									1,300,000,000
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
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
Castex Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages							$ 200,000,000
Loss contingency, estimated of possible loss amount							$ 60,000,000		$ 13,500,000
Number of sidetracks | sidetrack							5

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CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Basic:
Income attributable to common stock	$ 242	$ 1,883
Weighted average number of shares outstanding, basic (in shares)	311	346
Basic net income per share (in USD per share)	$ 0.78	$ 5.44
Diluted:
Income attributable to common stock	$ 242	$ 1,883
Income attributable to common stock (in shares)	312	347
Diluted net income per share (in USD per share)	$ 0.78	$ 5.43
Stock options and other
Effect of Dilutive Securities:
Stock options and other	$ 0	$ 0
Stock options and other, shares (in shares)	1	1
Stock options and other, per share (in USD per share)	$ 0	$ (0.01)

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CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Sep. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Dec. 31, 2018
Equity [Abstract]
Options and restricted stock, anti-dilutive (in shares)	2,400,000		2,900,000
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)	3,700,000		7,200,000
Treasure stock acquired, average price (in USD per share)	$ 38.93		$ 36.08
Remaining authorized repurchase amount (in shares)	49,000,000
Payments of dividend on common stock	$ 78		$ 43
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.25	$ 0.125	$ 0.125	$ 0.0625	$ 0.025

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BUSINESS SEGMENT INFORMATION - Additional Information (Details)	3 Months Ended
	Mar. 31, 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
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Operating Expenses:
Lease operating expenses		$ 321	$ 344
Taxes other than income		52	70
Exploration		52	42
Depreciation, depletion, and amortization		332	291
Asset retirement obligation accretion		28	29
Total operating expenses		1,079	1,208
Operating Income (Loss)		929	1,461
Other Income (Expense):
Derivative instrument gains (losses), net		53	(62)
Gain on divestitures, net		1	1,176
Other, net		(32)	45
General and administrative		(65)	(156)
Transaction, reorganization, and separation		(4)	(14)
Financing costs, net		(72)	(152)
NET INCOME BEFORE INCOME TAXES		810	2,298
Total assets		13,213	12,476	$ 13,147
Operating Segments | Egypt
Operating Expenses:
Lease operating expenses		97	131
Taxes other than income		0	0
Exploration		36	15
Depreciation, depletion, and amortization		123	97
Asset retirement obligation accretion		0	0
Total operating expenses		263	248
Operating Income (Loss)		459	643
Other Income (Expense):
Total assets		3,334	2,966
Impairments			1
Operating Segments | North Sea
Operating Expenses:
Lease operating expenses		77	96
Taxes other than income		0	0
Exploration		5	5
Depreciation, depletion, and amortization		58	62
Asset retirement obligation accretion		18	20
Total operating expenses		169	195
Operating Income (Loss)		183	248
Other Income (Expense):
Total assets		1,836	2,169
Impairments		3
Operating Segments | U.S.
Operating Expenses:
Lease operating expenses		147	118
Taxes other than income		52	67
Exploration		3	4
Depreciation, depletion, and amortization		151	130
Asset retirement obligation accretion		10	8
Total operating expenses		639	755
Operating Income (Loss)		295	578
Other Income (Expense):
Total assets		7,525	6,878
Impairments		2	3
Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Purchased oil and gas sales			16
Operating Expenses:
Lease operating expenses		0	0
Taxes other than income		0	3
Exploration		0	0
Depreciation, depletion, and amortization		0	2
Asset retirement obligation accretion		0	1
Total operating expenses		0	11
Operating Income (Loss)		0	10
Other Income (Expense):
Total assets		0	0
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Purchased oil and gas sales			(16)
Operating Expenses:
Lease operating expenses		0	(1)
Taxes other than income		0	0
Exploration		8	18
Depreciation, depletion, and amortization		0	0
Asset retirement obligation accretion		0	0
Total operating expenses		8	(1)
Operating Income (Loss)		(8)	(18)
Other Income (Expense):
Total assets		518	463
Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	[1]	1,769	2,320
Operating Expenses:
Cost of oil and gas purchased	[1]	78	81
Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		722	891
Operating Expenses:
Cost of oil and gas purchased		7	5
Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		352	443
Operating Expenses:
Cost of oil and gas purchased		11	12
Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		695	989
Operating Expenses:
Cost of oil and gas purchased		60	77
Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Operating Expenses:
Cost of oil and gas purchased		0	5
Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	(3)
Operating Expenses:
Cost of oil and gas purchased		0	(18)
Purchased oil and gas sales
Segment Reporting Information [Line Items]
Purchased oil and gas sales		239	349
Operating Expenses:
Cost of oil and gas purchased		216	351
Purchased oil and gas sales | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0
Operating Expenses:
Cost of oil and gas purchased		0	0
Purchased oil and gas sales | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0
Operating Expenses:
Cost of oil and gas purchased		0	0
Purchased oil and gas sales | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Purchased oil and gas sales		239	344
Operating Expenses:
Cost of oil and gas purchased		216	351
Purchased oil and gas sales | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	5
Operating Expenses:
Cost of oil and gas purchased		0	0
Purchased oil and gas sales | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Purchased oil and gas sales		0	0
Operating Expenses:
Cost of oil and gas purchased		0	0
Oil and gas
Segment Reporting Information [Line Items]
Revenues		2,008	2,669
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenues		722	891
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenues		352	443
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Revenues		934	1,333
Oil and gas | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Revenues		0	21
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues		0	(19)
Oil revenues
Other Income (Expense):
Revenue from non-customers		172	250
Oil revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,397	1,717
Oil revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		629	790
Oil revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		282	328
Oil revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		486	599
Oil revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Oil revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Natural gas revenues
Other Income (Expense):
Revenue from non-customers		26	31
Natural gas revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		242	380
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		93	98
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		60	99
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		89	183
Natural gas revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Natural gas revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Natural gas liquids revenues
Other Income (Expense):
Revenue from non-customers		0	1
Natural gas liquids revenues | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		130	223
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	3
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		10	16
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		120	207
Natural gas liquids revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0
Natural gas liquids revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		$ 0	$ (3)

[1] For revenues and gathering, processing, and transmission costs associated with Kinetik, refer to Note 6—Equity Method Interests for further detail.