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apa-20240930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2024


☐			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.)

2000 W. Sam Houston Pkwy. S., Suite 200, Houston, Texas 77042-3643

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.625 par value

APA

Nasdaq Global Select Market

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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


Number of shares of registrant’s common stock outstanding as of October 31, 2024			369,947,453

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 AND NONCONTROLLING INTERESTS	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47
4.	CONTROLS AND PROCEDURES	48

	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	49
1A.	RISK FACTORS	49
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	49
5.	OTHER INFORMATION	49
6.	EXHIBITS	50

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, plans and objectives of management for future operations and capital returns framework, the anticipated benefits of the merger (the Callon acquisition) between the Company and Callon Petroleum Company (Callon), the anticipated impact of the Callon acquisition on the combined company’s business and future financial and operating results, and the anticipated financial and operational impact and timing of the expected synergies from the Callon acquisition, 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, 2023, 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;

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

•the Company’s commodity hedging arrangements;

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

•production and reserve levels;

•drilling risks;

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

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the impact of changes in tax legislation;

•the availability of goods and services;

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

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

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

•cyberattacks and terrorism;

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

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

•the ability to retain and hire key personnel;

•property acquisitions or divestitures;

•the integration of acquisitions, including the diversion of management time on integration-related issues for the Callon acquisition and the risk that the Company may not integrate Callon’s operations in a successful manner or in the expected time period;

•the risk that the anticipated benefits, cost savings, synergies, and growth from the Callon acquisition may not be fully realized or may take longer to realize than expected;

•negative effects of the Callon acquisition on the Company’s business relationships and business generally, the market price of the Company’s common stock, and/or the Company’s operating results;

•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, 2023;

•other risks and uncertainties disclosed in the Company’s third-quarter 2024 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:

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

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

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

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

“boe/d” means boe per day.

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

“liquids” means oil and NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

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

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

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

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)	$	2,058	$	2,079	$	6,007	$	5,500
Purchased oil and gas sales(1)	473		229		1,018		612
Total revenues	2,531		2,308		7,025		6,112
Derivative instrument gains (losses), net	(10)		—		(17)		104
Gain on divestitures, net	1		1		284		7
Loss on previously sold Gulf of Mexico properties	—		—		(83)		—
Other, net	18		—		26		77
	2,540		2,309		7,235		6,300
OPERATING EXPENSES:
Lease operating expenses(1)	418		394		1,216		1,076
Gathering, processing, and transmission(1)	123		89		328		245
Purchased oil and gas costs(1)	292		211		665		558
Taxes other than income	70		61		205		163
Exploration	29		49		248		144
General and administrative	92		139		270		276
Transaction, reorganization, and separation	14		5		156		11
Depreciation, depletion, and amortization	595		418		1,613		1,117
Asset retirement obligation accretion	36		29		112		86
Impairments	1,111		—		1,111		46
Financing costs, net	100		81		276		235
	2,880		1,476		6,200		3,957
NET INCOME (LOSS) BEFORE INCOME TAXES	(340)		833		1,035		2,343
Current income tax provision	260		422		845		1,022
Deferred income tax benefit	(461)		(144)		(503)		(22)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(139)		555		693		1,343
Net income attributable to noncontrolling interest	84		96		243		261
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(223)	$	459	$	450	$	1,082

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.60)	$	1.49	$	1.30	$	3.50
Diluted	$	(0.60)	$	1.49	$	1.29	$	3.50
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	370		308		348		309
Diluted	370		308		348		309

(1) For transactions with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests.

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	(139)	$	555	$	693	$	1,343
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:

Pension and postretirement benefit plan	—		—		(1)		3
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(139)		555		692		1,346
Comprehensive income attributable to noncontrolling interest	84		96		243		261
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(223)	$	459	$	449	$	1,085

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2024		2023

	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$	693	$	1,343
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	18		(61)
Gain on divestitures, net	(284)		(7)
Exploratory dry hole expense and unproved leasehold impairments	183		91
Depreciation, depletion, and amortization	1,613		1,117
Asset retirement obligation accretion	112		86
Impairments	1,111		46
Benefit from deferred income taxes	(503)		(22)
Gain on extinguishment of debt	—		(9)
Loss on previously sold Gulf of Mexico properties	83		—
Other, net	(14)		(45)
Changes in operating assets and liabilities:
Receivables	181		(289)
Inventories	(26)		19
Drilling advances and other current assets	37		40
Deferred charges and other long-term assets	(215)		227
Accounts payable	(191)		(2)
Accrued expenses	(271)		1
Deferred credits and noncurrent liabilities	57		(436)
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,584		2,099
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(2,153)		(1,747)

Leasehold and property acquisitions	(64)		(11)
Proceeds from asset divestitures	724		29
Proceeds from sale of Kinetik Shares	428		—
Other, net	58		(53)
NET CASH USED IN INVESTING ACTIVITIES	(1,007)		(1,782)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from commercial paper and revolving credit facilities, net	190		202
Proceeds from term loan facility	1,500		—
Payments on term loan facility	(500)		—
Payment on Callon Credit Agreement	(472)		—


Payments on fixed-rate debt	(1,641)		(65)
Distributions to noncontrolling interest	(233)		(154)
Treasury stock activity, net	(146)		(208)
Dividends paid to APA common stockholders	(260)		(232)
Other, net	(38)		(10)
NET CASH USED IN FINANCING ACTIVITIES	(1,600)		(467)

NET DECREASE IN CASH AND CASH EQUIVALENTS	(23)		(150)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	87		245
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	64	$	95

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	306	$	278
Income taxes paid, net of refunds	876		867

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

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	September 30, 2024		December 31, 2023

	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	64	$	87
Receivables, net of allowance of $120 and $114	1,652		1,610
Assets held for sale	1,091		—
Other current assets (Note 5)	813		765
	3,620		2,462
PROPERTY AND EQUIPMENT:
Oil and gas properties	44,026		44,860
Gathering, processing, and transmission facilities	446		448
Other	557		634
Less: Accumulated depreciation, depletion, and amortization	(32,428)		(35,904)
	12,601		10,038
OTHER ASSETS:
Equity method interests (Note 6)	—		437
Decommissioning security for sold Gulf of Mexico properties (Note 11)	21		21
Deferred tax asset (Note 10)	2,550		1,758
Deferred charges and other	584		528
	$	19,376	$	15,244

LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	939	$	658
Current debt	2		2
Liabilities held for sale	224		—
Other current liabilities (Note 7)	1,760		1,744
	2,925		2,404
LONG-TERM DEBT (Note 9)	6,370		5,186
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 10)	86		371
Asset retirement obligation (Note 8)	2,502		2,362
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	759		764
Other	574		466
	3,921		3,963
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 491,531,484 and 420,595,901 shares issued, respectively	307		263
Paid-in capital	13,239		11,126
Accumulated deficit	(2,509)		(2,959)
Treasury stock, at cost, 121,613,494 and 117,020,000 shares, respectively	(5,937)		(5,790)
Accumulated other comprehensive income	14		15
APA SHAREHOLDERS’ EQUITY	5,114		2,655
Noncontrolling interest	1,046		1,036
TOTAL EQUITY	6,160		3,691
	$	19,376	$	15,244

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS

(Unaudited)


	Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY		Noncontrolling Interest		TOTAL EQUITY

	(In millions)
For the Quarter Ended September 30, 2023
Balance at June 30, 2023	$	263	$	11,267	$	(5,191)	$	(5,647)	$	17	$	709	$	987	$	1,696
Net income attributable to common stock	—		—		459		—		—		459		—		459
Net income attributable to noncontrolling interest	—		—		—		—		—		—		96		96
Distributions to noncontrolling interest	—		—		—		—		—		—		(54)		(54)
Common dividends declared ($0.25 per share)	—		(77)		—		—		—		(77)		—		(77)
Treasury stock activity, net	—		—		—		(20)		—		(20)		—		(20)
Other	—		7		—		—		—		7		—		7
Balance at September 30, 2023	$	263	$	11,197	$	(4,732)	$	(5,667)	$	17	$	1,078	$	1,029	$	2,107

For the Quarter Ended September 30, 2024
Balance at June 30, 2024	$	307	$	13,322	$	(2,286)	$	(5,934)	$	14	$	5,423	$	1,072	$	6,495
Net loss attributable to common stock	—		—		(223)		—		—		(223)		—		(223)
Net income attributable to noncontrolling interest	—		—		—		—		—		—		84		84
Distributions to noncontrolling interest	—		—		—		—		—		—		(110)		(110)
Common dividends declared ($0.25 per share)	—		(92)		—		—		—		(92)		—		(92)

Treasury stock activity, net	—		—		—		(3)		—		(3)		—		(3)
Other	—		9		—		—		—		9		—		9
Balance at September 30, 2024	$	307	$	13,239	$	(2,509)	$	(5,937)	$	14	$	5,114	$	1,046	$	6,160

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS - Continued

(Unaudited)


	Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY		Noncontrolling Interest		TOTAL EQUITY

	(In millions)
For the Nine Months Ended September 30, 2023
Balance at December 31, 2022	$	262	$	11,420	$	(5,814)	$	(5,459)	$	14	$	423	$	922	$	1,345
Net income attributable to common stock	—		—		1,082		—		—		1,082		—		1,082
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		261		261
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		(154)		(154)
Common dividends declared ($0.75 per share)	—		(232)		—		—		—		(232)		—		(232)
Treasury stock activity, net	—		—		—		(208)		—		(208)		—		(208)
Other	1		9		—		—		3		13		—		13
Balance at September 30, 2023	$	263	$	11,197	$	(4,732)	$	(5,667)	$	17	$	1,078	$	1,029	$	2,107

For the Nine Months Ended September 30, 2024
Balance at December 31, 2023	$	263	$	11,126	$	(2,959)	$	(5,790)	$	15	$	2,655	$	1,036	$	3,691
Net income attributable to common stock	—		—		450		—		—		450		—		450
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		243		243
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		(233)		(233)
Common dividends declared ($0.75 per share)	—		(260)		—		—		—		(260)		—		(260)
Issuance of common stock	44		2,370		—		—		—		2,414		—		2,414
Treasury stock activity, net	—		—		—		(147)		—		(147)		—		(147)
Other	—		3		—		—		(1)		2		—		2
Balance at September 30, 2024	$	307	$	13,239	$	(2,509)	$	(5,937)	$	14	$	5,114	$	1,046	$	6,160

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

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, 2023, which contains a summary of the Company’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2024, 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, 2023. 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.

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.

Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. During the nine months ended September 30, 2023 and the quarter ended March 31, 2024, the Company had a designated director on the Kinetik Holdings Inc. (Kinetik) board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors.

As of December 31, 2023, the Company held shares of Kinetik Class A Common Stock (Kinetik Shares), which were recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. On March 18, 2024, the Company sold its remaining Kinetik Shares. 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 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.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment.

During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. As a result, the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea as of September 30, 2024. Accordingly, in the third quarter of 2024, the Company recognized impairments of $793 million on certain proved properties in the North Sea, which were written down to their estimated fair values. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.”

Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail.

During the three and nine months ended September 30, 2023, the Company recorded no asset impairments in connection with fair value assessments.

Revenue Recognition

Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.5 billion at each of September 30, 2024 and December 31, 2023. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout the period, and management believes that the Company will be able to collect the total balance of its receivables from this customer.

Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.

Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.

In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. The Company recorded impairments to inventory of $3 million in the third quarter and the nine months ended September 30, 2024 and $46 million in the nine months ended September 30, 2023.

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, production costs, 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. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities, and if management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

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.

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.

The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $793 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million.

Additionally, in the third quarter of 2024, the Company recorded impairments totaling $315 million in connection with an agreement to sell certain non-core producing properties in the Permian Basin. These impairments are discussed in further detail above in “Fair Value Measurements” and in Note 2—Acquisitions and Divestitures. The associated U.S. properties had an aggregate fair value of $1.1 billion as of September 30, 2024.

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.

Transaction, Reorganization, and Separation (TRS)

The Company recorded $14 million and $156 million of TRS costs during the third quarter and the first nine months of 2024, respectively, and $5 million and $11 million of TRS costs during the third quarter and the first nine months of 2023, respectively. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.

New Pronouncements Issued But Not Yet Adopted

In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.

2. ACQUISITIONS AND DIVESTITURES

2024 Activity

Sale of Non-core Properties in the Permian Basin

On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for cash proceeds of $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024. The Company received a deposit of $95 million in connection with the sale during the third quarter of 2024.

As a result of the agreement, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $315 million to the carrying value of associated oil and gas properties. These assets met the criteria of held for sale classification as of September 30, 2024. U.S. oil and gas properties totaling $1.1 billion and the associated asset retirement obligation of $224 million were classified as current assets held for sale and current liabilities held for sale, respectively, as of September 30, 2024.

Callon Petroleum Company Acquisition

On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024. The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin.

Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction based on the value of APA common stock on the day of closing, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE. In addition to the equity consideration provided, APA transferred approximately $24 million in other consideration upon close of the transaction.

Upon completing the acquisition, APA repaid all of Callon’s debt, refinancing a portion by borrowing $1.5 billion under its unsecured committed term loan facility. Refer to Note 9—Debt and Financing Costs for further detail.

Recording of Assets Acquired and Liabilities Assumed

The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.

The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the merger:


	(In millions)
Current assets	$	282
Property, plant, and equipment	4,493
Deferred tax asset	575
Other assets	11
Total assets acquired	$	5,361
Current liabilities	$	616
Long-term debt	2,113
Asset retirement obligation	136

Other long-term obligations	58
Total liabilities assumed	$	2,923
Net assets acquired	$	2,438

The following unaudited pro forma combined results for the three and nine months ended September 30, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, interest expense, gain on derivatives related to a previous Callon acquisition, and estimated tax impacts of the pro forma adjustments.


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions, except share data)
Revenues	$	2,531	$	2,927	$	7,589	$	7,810
Net income (loss) attributable to common stock	(223)		737		556		1,527
Net income (loss) per common share – basic	(0.60)		1.95		1.50		4.04
Net income (loss) per common share – diluted	(0.60)		1.95		1.50		4.04

From the date of the acquisition through September 30, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $840 million and $192 million, respectively.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated. The unaudited pro forma results are also not intended to be a projection of future results and do not include any future cost savings or other synergies that may result from the Callon acquisition or any estimated costs that have not yet been incurred.

U.S. Divestitures

In the first nine months of 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $253 million and the assumption of asset retirement obligations of $48 million. The Company recognized a $46 million loss during the first nine months of 2024 in association with this sale.

In the first nine months of 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $392 million after post-closing adjustments. The Company recognized a gain of $321 million during the first nine months of 2024 in association with this sale.

Additionally, during the third quarter and first nine months of 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $73 million, respectively, recognizing a gain of approximately $1 million and $9 million, respectively, upon closing of these transactions.

Sale of Kinetik Shares

On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. Refer to Note 6—Equity Method Interests for further detail.

Leasehold and Property Acquisitions

During the third quarter and the first nine months of 2024, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $64 million, respectively.

2023 Activity

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $11 million, respectively.

U.S. Divestitures

During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions.

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $611 million and $586 million as of September 30, 2024 and December 31, 2023, respectively. The increase is primarily attributable to additional drilling activity in Egypt and in the U.S. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense during the third quarter of 2024. During the first nine months of 2024, approximately $51 million of suspended well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense.

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. The Company has elected not to designate any of its derivative contracts as cash flow hedges.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2024, the Company had derivative positions with one counterparty. 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.

Derivative Instruments

Commodity Derivative Instruments

As of September 30, 2024, the Company had the following open natural gas financial collar contracts:

Production Period

Settlement Index

MMBtu
(in 000’s)

Weighted Average Floor Price

Weighted Average Ceiling Price

October—December 2024

NYMEX Henry Hub

1,654

$3.00

$3.33

As of September 30, 2024, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2024	NYMEX Henry Hub/IF Waha	—	—	1,840	$(1.06)
October—December 2024	NYMEX Henry Hub/IF HSC	—	—	3,680	$(0.42)

As of September 30, 2024, the Company had the following open NGL fixed swap contracts:

Production Period

Settlement Index

MBbls

(in 000’s)

Weighted Average Price Differential

October—December 2024

OPIS IsoButane Mt Belvieu Non TET

$33.18

October—December 2024

OPIS NButane Mt Belvieu Non TET

$33.18

Embedded Derivatives

As a result of the Callon acquisition, the Company assumed an earn-out obligation from Callon, where the Company could be required to pay up to $50 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for the 2024 and 2025 calendar years. Additionally, in connection with the Callon acquisition, the Company assumed a contingent consideration arrangement, whereby the Company could receive up to $45 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20 million.

The Company determined that the earn-out obligation and contingent consideration receipt were not clearly and closely related to the underlying agreements and therefore bifurcated these embedded features and recorded these derivatives at fair value. For further discussion of these derivatives, refer to “Fair Value Measurements” below.

Fair Value Measurements

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


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

	(In millions)
September 30, 2024
Assets:
Commodity derivative instruments	$	—	$	1	$	—	$	1	$	(1)	$	—
Contingent consideration arrangements	—		10		—		10		—		10
Liabilities:
Commodity derivative instruments	$	—	$	1	$	—	$	1	$	(1)	$	—


Contingent consideration arrangements	—		39		—		39		—		39
December 31, 2023
Assets:
Commodity derivative instruments	$	—	$	6	$	—	$	6	$	—	$	6

(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

The embedded options within the earn-out obligation and contingent consideration arrangements discussed above are considered financial instruments under ASC 815. The Company uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing an option pricing model method provided by a reputable third party. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered a Level 2 fair value measurement. As of September 30, 2024, the estimated fair values of the earn-out obligation and contingent consideration receipt were $39 million and $10 million, respectively.

Derivative Activity Recorded in the Consolidated Balance Sheet

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


	September 30, 2024		December 31, 2023

	(In millions)
Current Assets: Other current assets	$	10	$	6

Total derivative assets	$	10	$	6

Current Liabilities: Other current liabilities	$	25	$	—
Deferred Credit and Other Noncurrent Liabilities: Other	14		—
Total derivative liabilities	$	39	$	—

Derivative Activity Recorded in the Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Realized:
Commodity derivative instruments	$	3	$	19	$	1	$	43

Realized gains, net	3		19		1		43
Unrealized:
Commodity derivative instruments	(1)		(19)		(6)		61
Contingent consideration arrangements	(12)		—		(12)		—



Unrealized gains (losses), net	(13)		(19)		(18)		61
Derivative instrument gains (losses), net	$	(10)	$	—	$	(17)	$	104

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

5. OTHER CURRENT ASSETS

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


	September 30, 2024		December 31, 2023

	(In millions)
Inventories	$	501	$	453
Drilling advances	60		88

Current decommissioning security for sold Gulf of Mexico assets	167		178
Prepaid assets and other	85		46
Total Other current assets	$	813	$	765

6. EQUITY METHOD INTERESTS

As of December 31, 2023, the Company held 13.1 million Kinetik Shares, which were recorded at fair value of $437 million and reflected separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik was determined using observable share prices on a major exchange, a Level 1 fair value measurement. On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million.

Prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $9 million in the first quarter of 2024, and a loss of $14 million and a gain of $57 million in the third quarter and the first nine months of 2023, respectively. These changes in fair value were recorded as a component of “Revenues and Other” in the Company’s statement of consolidated operations.

The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Natural gas and NGLs sales	$	—	$	35	$	13	$	78
Purchased oil and gas sales	—		11		22		18
	$	—	$	46	$	35	$	96

Gathering, processing, and transmission costs	$	—	$	26	$	23	$	81
Purchased oil and gas costs	—		37		23		65
Lease operating expenses	—		—		2		—
	$	—	$	63	$	48	$	146

7. OTHER CURRENT LIABILITIES

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


	September 30, 2024		December 31, 2023

	(In millions)
Accrued operating expenses	$	254	$	162
Accrued exploration and development	543		371
Accrued compensation and benefits	189		390
Accrued interest	66		93
Accrued income taxes	144		138
Current asset retirement obligation	75		76
Current operating lease liability	98		116

Current decommissioning contingency for sold Gulf of Mexico properties	94		60
Other	297		338
Total Other current liabilities	$	1,760	$	1,744

8. ASSET RETIREMENT OBLIGATION

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


	September 30, 2024
	(In millions)
Asset retirement obligation, December 31, 2023	$	2,438
Liabilities incurred	11
Liabilities acquired	140
Liabilities settled	(47)
Liabilities divested	(48)
Liabilities held for sale	(224)
Accretion expense	112
Revisions in estimated liabilities	195
Asset retirement obligation, September 30, 2024	2,577
Less current portion	(75)
Asset retirement obligation, long-term	$	2,502

9. DEBT AND FINANCING COSTS

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


	September 30, 2024		December 31, 2023

	(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	4,835	$	4,835
Term loan facility, commercial paper, and syndicated credit facilities(2)	1,562		372

Apache finance lease obligations	30		32
Unamortized discount	(25)		(26)
Debt issuance costs	(30)		(25)
Total debt	6,372		5,188
Current maturities	(2)		(2)
Long-term debt	$	6,370	$	5,186

(1) The fair values of the Apache notes and debentures were $4.5 billion and $4.3 billion as of September 30, 2024 and December 31, 2023, respectively.

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

(2) The carrying value of borrowings on the term loan facility, commercial paper and credit facilities approximates fair value because interest rates are variable and reflective of market rates.

At each of September 30, 2024 and December 31, 2023, current debt included $2 million of finance lease obligations.

Financing Costs, Net

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


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Interest expense	$	109	$	89	$	302	$	266
Amortization of debt issuance costs	1		1		4		3
Capitalized interest	(8)		(7)		(22)		(18)
Gain on extinguishment of debt	—		—		—		(9)
Interest income	(2)		(2)		(8)		(7)
Financing costs, net	$	100	$	81	$	276	$	235

During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash. The Company recognized a $9 million gain on these repurchases.

Unsecured 2022 Committed Credit Facilities

On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.

•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.

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 of the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.

As of September 30, 2024, there were $232 million of borrowings under the USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement.

Uncommitted Lines of Credit

Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million, respectively, in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million, respectively, in letters of credit outstanding under these facilities.

Commercial Paper Program

In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.

Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.

Unsecured Committed Term Loan Facility

On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement. Of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.

On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire.

Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.

Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes).

On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon’s 2028 Notes and Callon’s 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.

On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:

•Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.

•Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.

•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.

On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.

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.

The Company’s effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company’s effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.

On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction. The Company’s deferred tax asset increased by approximately $575 million as part of the assets assumed through the Callon acquisition. Refer to Note 2—Acquisitions and Divestitures for further detail.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. The Company is continuing to evaluate the proposed regulations and their effect on the Company’s consolidated financial statements.

In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.

The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.

11. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2024, the Company has an accrued liability of approximately $18 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

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, 2023, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The consideration paid by the Company in the settlement did not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which was filed by the City of New Orleans against the Company and a number of oil and gas operators.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.

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. These cases were then consolidated before a single judge in a multi-district litigation (MDL) proceeding. On August 14, 2024, in the MDL, the plaintiffs agreed to dismiss Apache with prejudice from all matters, and a dismissal has been entered by the court.

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.

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, among other things, 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. With no admission, concession, or finding of any fault, liability, or wrongdoing, but only to avoid the expense and uncertainty of litigation, the parties have agreed to a settlement resolving all claims made against the defendants by the class. The settlement agreement has been preliminarily approved by the court, and final approval of the settlement is expected to occur prior to the end of 2024. The settlement will not have a material impact on the Company’s financial position, results of operations, or liquidity and is subject to insurance coverage that companies have for these types of claims.

On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Those cases were consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purported 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 asserting claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants filed a motion to dismiss the consolidated lawsuits, and on September 26, 2024, the federal court issued a final judgment granting the defendants’ motion and dismissing the consolidated claims against the defendants.

Environmental Matters

As of September 30, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which has been approved and entered by the Court. The consideration provided by the Company in connection with the consent decree, which included a $4 million payment, did not have a material impact on the Company’s financial position.

The Company is not aware of any environmental claims existing as of September 30, 2024, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy 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 are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands 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.

On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction in an amount to be determined in a future hearing. That hearing took place on October 24, 2024, although the Court has not yet issued a ruling on the issues addressed, including any award of attorney’s fees to Apache. Apache is vigorously pursuing its claims against the sureties.

As of September 30, 2024, the Company has recorded a $188 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.

The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of “Loss on previously sold Gulf of Mexico properties.” Amounts recorded in the first nine months of 2024 included $50 million related to orders received during the period from BSEE to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.

12. CAPITAL STOCK

Net Income (Loss) per Common Share

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


	For the Quarter Ended September 30,
	2024					2023
	Loss		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(223)	370	$	(0.60)	$	459	308	$	1.49



Diluted:
Income (loss) attributable to common stock	$	(223)	370	$	(0.60)	$	459	308	$	1.49

	For the Nine Months Ended September 30,
	2024					2023
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	450	348	$	1.30	$	1,082	309	$	3.50
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	(0.01)	$	—	—	$	—

Diluted:
Income attributable to common stock	$	450	348	$	1.29	$	1,082	309	$	3.50

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.9 million and 1.7 million during the third quarters of 2024 and 2023, respectively, and 2.0 million and 2.0 million during the first nine months of 2024 and 2023, respectively.

Stock Repurchase Program

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

In the third quarter of 2024, the Company repurchased approximately 0.1 million shares at an average price of $29.33 per share. For the nine months ended September 30, 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share, and as of September 30, 2024, the Company had remaining authorization to repurchase up to 39.3 million shares. In the third quarter of 2023, the Company repurchased 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share.

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

Common Stock Dividend

For the quarters ended September 30, 2024 and 2023, the Company paid $92 million and $77 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2024 and 2023, the Company paid $260 million and $232 million, respectively, in dividends on its common stock.

Common Stock Issuance

On April 1, 2024, in connection with the Callon acquisition, the Company issued approximately 70 million shares of common stock in exchange for Callon common stock. The total value of stock consideration was approximately $2.4 billion based on APA’s stock price on the closing date of the acquisition.

13. BUSINESS SEGMENT INFORMATION

As of September 30, 2024, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: the U.S., Egypt, and North Sea. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:


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


For the Quarter Ended September 30, 2024	(In millions)
Revenues:
Oil revenues	$	1,007	$	673	$	117	$	—	$	1,797
Natural gas revenues	7		81		15		—		103
Natural gas liquids revenues	153		—		5		—		158
Oil, natural gas, and natural gas liquids production revenues	1,167		754		137		—		2,058
Purchased oil and gas sales	473		—		—		—		473

	1,640		754		137		—		2,531
Operating Expenses:
Lease operating expenses	222		109		87		—		418
Gathering, processing, and transmission	110		6		7		—		123
Purchased oil and gas costs	292		—		—		—		292
Taxes other than income	70		—		—		—		70
Exploration	(1)		21		—		9		29
Depreciation, depletion, and amortization	355		167		73		—		595
Asset retirement obligation accretion	10		—		26		—		36
Impairments	315		—		796		—		1,111
	1,373		303		989		9		2,674
Operating Income (Loss)(2)	$	267	$	451	$	(852)	$	(9)	(143)

Other Income (Expense):
Derivative instrument losses, net									(10)

Gain on divestitures, net									1
Other, net									18
General and administrative									(92)
Transaction, reorganization, and separation									(14)
Financing costs, net									(100)
Loss Before Income Taxes									$	(340)


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


For the Nine Months Ended September 30, 2024	(In millions)
Revenues:
Oil revenues	$	2,616	$	2,003	$	517	$	—	$	5,136
Natural gas revenues	79		231		104		—		414
Natural gas liquids revenues	436		—		21		—		457
Oil, natural gas, and natural gas liquids production revenues	3,131		2,234		642		—		6,007
Purchased oil and gas sales	1,018		—		—		—		1,018
	4,149		2,234		642		—		7,025
Operating Expenses:
Lease operating expenses	582		352		282		—		1,216
Gathering, processing, and transmission	272		19		37		—		328
Purchased oil and gas costs	665		—		—		—		665
Taxes other than income	205		—		—		—		205
Exploration	107		77		1		63		248
Depreciation, depletion, and amortization	930		464		219		—		1,613
Asset retirement obligation accretion	35		—		77		—		112
Impairments	315		—		796		—		1,111
	3,111		912		1,412		63		5,498
Operating Income (Loss)(2)	$	1,038	$	1,322	$	(770)	$	(63)	1,527

Other Income (Expense):
Derivative instrument losses, net									(17)
Loss on offshore decommissioning contingency									(83)
Gain on divestitures, net									284
Other, net									26
General and administrative									(270)
Transaction, reorganization, and separation									(156)
Financing costs, net									(276)
Income Before Income Taxes									$	1,035

Total Assets(3)	$	13,847	$	3,525	$	1,439	$	565	$	19,376


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


For the Quarter Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	633	$	724	$	348	$	—	$	1,705
Natural gas revenues	89		81		66		—		236
Natural gas liquids revenues	133		—		5		—		138
Oil, natural gas, and natural gas liquids production revenues	855		805		419		—		2,079
Purchased oil and gas sales	229		—		—		—		229
	1,084		805		419		—		2,308
Operating Expenses:
Lease operating expenses	164		128		102		—		394
Gathering, processing, and transmission	61		13		15		—		89
Purchased oil and gas costs	211		—		—		—		211
Taxes other than income	61		—		—		—		61
Exploration	4		25		9		11		49
Depreciation, depletion, and amortization	199		129		90		—		418
Asset retirement obligation accretion	9		—		20		—		29

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

Other Income (Expense):


Gain on divestitures, net									1

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


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


For the Nine Months Ended September 30, 2023	(In millions)
Revenues:
Oil revenues	$	1,631	$	1,971	$	865	$	—	$	4,467
Natural gas revenues	229		264		165		—		658
Natural gas liquids revenues	356		—		19		—		375
Oil, natural gas, and natural gas liquids production revenues	2,216		2,235		1,049		—		5,500
Purchased oil and gas sales	612		—		—		—		612
	2,828		2,235		1,049		—		6,112
Operating Expenses:
Lease operating expenses	452		346		278		—		1,076
Gathering, processing, and transmission	181		26		38		—		245
Purchased oil and gas costs	558		—		—		—		558
Taxes other than income	163		—		—		—		163
Exploration	10		91		18		25		144
Depreciation, depletion, and amortization	530		378		209		—		1,117
Asset retirement obligation accretion	29		—		57		—		86
Impairments	—		—		46		—		46
	1,923		841		646		25		3,435
Operating Income (Loss)(2)	$	905	$	1,394	$	403	$	(25)	2,677

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

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


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

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2024 and 2023 of:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Oil	$	182	$	202	$	533	$	539
Natural gas	22		23		63		73

(2)Operating loss of Suriname includes leasehold impairments of $1 million for the third quarter of 2024.
Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income (loss) of U.S. and Suriname includes leasehold impairments of $10 million and $1 million, respectively, for the first nine months of 2024. Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023.

(3)Intercompany balances are excluded from total assets.

(4)Includes noncontrolling interests in Egypt.

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, 2023.

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 has oil and gas 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 Uruguay 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.

APA believes energy underpins global progress, and the Company wants to be a part of the 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.

Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, and actions taken by foreign oil and gas producing nations, including OPEC+, 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 invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of 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; and (3) to responsibly manage its cost structure regardless of the oil price environment.

The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

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

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

•The Company pays a quarterly dividend of $0.25 per share on its common stock.

•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2024, the Company has repurchased 80.7 million shares of the Company’s common stock.

Financial and Operational Highlights

On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. The Company believes the acquisition of Callon provides opportunities to reduce costs, improve capital efficiencies, leverage economies of scale, and expand the development inventory that formed the basis of the transaction value.

On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024.

In the third quarter of 2024, the Company reported a net loss attributable to common stock of $223 million, or $0.60 per diluted share, compared to net income of $459 million, or $1.49 per diluted share, in the third quarter of 2023. The decrease in net income in the third quarter of 2024 compared to the third quarter of 2023 was primarily driven by $1.1 billion of impairments, which included $793 million of oil and gas property impairments in the North Sea, a $315 million impairment of assets held for sale in the Permian Basin, and $3 million inventory impairments in the North Sea. These impacts to net loss were partially offset by lower income tax expense compared to the same prior-year period.

In the first nine months of 2024, the Company reported net income attributable to common stock of $450 million, or $1.29 per diluted share, compared to net income of $1.1 billion, or $3.50 per diluted share, in the first nine months of 2023. The decrease in net income in the first nine months of 2024 compared to the first nine months of 2023 was primarily driven by $1.1 billion of impairments recorded during the third quarter of 2024 and the related tax impacts. Net income was further impacted by higher depreciation expense, transaction and reorganization costs, and lease operating expenses, primarily a result of the Callon acquisition. These impacts to net income were partially offset by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, gain from divestitures of non-core assets, and lower income tax expense compared to the same prior-year period.

The Company generated $2.6 billion of cash from operating activities during the first nine months of 2024, 23 percent higher than the first nine months of 2023. APA’s higher operating cash flows for the first nine months of 2024 were primarily driven by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, and timing of working capital items. The Company repurchased 4.6 million shares of its common stock for $146 million and paid $260 million in dividends to APA common stockholders during the first nine months of 2024.

Key operational highlights include:

United States

•Daily boe production from the Company’s U.S. assets accounted for 64 percent of its total production during the third quarter of 2024 and increased 33 percent from the third quarter of 2023. Daily oil production from the Company’s U.S. assets increased 71 percent from the third quarter of 2023. During the third quarter of 2024, the Company averaged nine drilling rigs in the Permian Basin, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin. The Company brought online 48 operated wells during the quarter, of which 21 wells were associated with the Callon assets. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets. The Company expects to average 8 drilling rigs in the Permian Basin for the remainder of 2024 and into 2025.

International

•In Egypt, the Company continued its drilling and workover activity with a focus on oil production. The Company averaged 12 drilling rigs and drilled 15 new productive wells during the third quarter of 2024. During the same period, the Company averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Third quarter 2024 gross production from the Company’s Egypt assets decreased 5 percent from the third quarter of 2023, and net production increased 2 percent.

•Subsequent to September 30, 2024, but prior to the date of this filing, the Company entered into a new pricing agreement for incremental gas volumes produced in Egypt, making gas exploration and development more economically competitive with oil development.

•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company’s investment program in the North Sea is now directed toward asset safety and integrity.

•In October 2024, the Company announced that its subsidiary reached a positive final investment decision for the first oil development, named GranMorgu, in Block 58 offshore Suriname. This development will include production from the Krabdagu and Sapakara oil discoveries. These fields, located in water depths between 100 and 1,000 meters, will be produced through a system of subsea wells connected to a floating production, storage and offloading (FPSO) unit located 150 km off the Suriname coast, with an oil production capacity of 220,000 barrels per day. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its 4-year production plateau and will feature technology that minimizes greenhouse gas emissions. Total investment is estimated at $10.5 billion, with APA’s share of the investment subject to the existing agreement with TotalEnergies to carry a portion of Apache’s appraisal and development capital. First oil is anticipated in 2028.

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

Revenue

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


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2024				2023				2024				2023
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution

	($ in millions)
Oil Revenues:
United States	$	1,007	56	%	$	633	37	%	$	2,616	51	%	$	1,631	37	%
Egypt(1)	673		37	%	724		43	%	2,003		39	%	1,971		44	%
North Sea	117		7	%	348		20	%	517		10	%	865		19	%
Total(1)	$	1,797	100	%	$	1,705	100	%	$	5,136	100	%	$	4,467	100	%

Natural Gas Revenues:
United States	$	7	7	%	$	89	38	%	$	79	19	%	$	229	35	%
Egypt(1)	81		79	%	81		34	%	231		56	%	264		40	%
North Sea	15		14	%	66		28	%	104		25	%	165		25	%
Total(1)	$	103	100	%	$	236	100	%	$	414	100	%	$	658	100	%

NGL Revenues:
United States	$	153	97	%	$	133	96	%	$	436	95	%	$	356	95	%

North Sea	5		3	%	5		4	%	21		5	%	19		5	%
Total(1)	$	158	100	%	$	138	100	%	$	457	100	%	$	375	100	%

Oil and Gas Revenues:
United States	$	1,167	56	%	$	855	41	%	$	3,131	52	%	$	2,216	40	%
Egypt(1)	754		37	%	805		39	%	2,234		37	%	2,235		41	%
North Sea	137		7	%	419		20	%	642		11	%	1,049		19	%
Total(1)	$	2,058	100	%	$	2,079	100	%	$	6,007	100	%	$	5,500	100	%

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

Production

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


	For the Quarter Ended September 30,			For the Nine Months Ended September 30,
	2024	Increase (Decrease)	2023	2024	Increase (Decrease)	2023
Oil Volume (b/d)
United States	143,299	71%	83,584	122,138	58%	77,198
Egypt(1)(2)	91,673	4%	88,521	88,725	1%	88,038
North Sea	21,334	(40)%	35,680	25,888	(28)%	36,070
Total	256,306	23%	207,785	236,751	18%	201,306

Natural Gas Volume (Mcf/d)
United States	467,615	3%	454,643	473,997	6%	448,838
Egypt(1)(2)	300,418	0%	300,326	287,953	(13)%	331,158
North Sea	18,911	(71)%	65,168	41,042	(14)%	47,665
Total	786,944	(4)%	820,137	802,992	(3)%	827,661

NGL Volume (b/d)
United States	79,474	20%	66,280	71,690	17%	61,418

North Sea	543	(64)%	1,497	1,164	(4)%	1,209
Total	80,017	18%	67,777	72,854	16%	62,627

BOE per day(3)
United States	300,709	33%	225,639	272,827	28%	213,423
Egypt(1)(2)	141,742	2%	138,575	136,718	(5)%	143,231
North Sea(4)	25,029	(48)%	48,038	33,892	(25)%	45,222
Total	467,480	13%	412,252	443,437	10%	401,876

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


	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2024	2023	2024	2023
Oil (b/d)	136,670	144,528	138,039	141,995
Natural Gas (Mcf/d)	447,173	472,744	445,397	511,430

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


	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2024	2023	2024	2023
Oil (b/d)	30,579	29,514	29,596	29,369
Natural Gas (Mcf/d)	100,210	100,122	96,054	110,476

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

(4) Average sales volumes from the North Sea for the third quarters of 2024 and 2023 were 19,374 boe/d and 55,283 boe/d, respectively, and 30,607 boe/d and 47,370 boe/d for the first nine months of 2024 and 2023, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Pricing

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


	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2024		Increase (Decrease)	2023		2024		Increase (Decrease)	2023
Average Oil Price – Per barrel
United States	$	76.34	(7)%	$	82.33	$	78.16	1%	$	77.40
Egypt	79.88		(10)%	88.99		82.41		0%	82.04
North Sea	83.36		(5)%	87.70		83.67		1%	83.25
Total	78.06		(9)%	86.15		80.31		0%	80.50

Average Natural Gas Price – Per Mcf
United States	$	0.16	(92)%	$	2.12	$	0.61	(67)%	$	1.87
Egypt	2.93		1%	2.91		2.93		0%	2.92
North Sea	9.76		(11)%	10.98		9.89		(23)%	12.83
Total	1.43		(54)%	3.12		1.89		(35)%	2.91

Average NGL Price – Per barrel
United States	$	20.91	(4)%	$	21.87	$	22.20	5%	$	21.24

North Sea	45.93		7%	42.78		46.47		(2)%	47.58
Total	21.29		(4)%	22.26		22.73		4%	21.85

Third-Quarter 2024 compared to Third-Quarter 2023

Crude Oil Crude oil revenues for the third quarter of 2024 totaled $1.8 billion, a $92 million increase from the comparative 2023 quarter. A 23 percent higher average daily production increased third-quarter 2024 oil revenues by $251 million compared to the third quarter of 2023, while a 9 percent decrease in average realized prices decreased revenues by $159 million. Crude oil revenues accounted for 87 percent of total oil and gas production revenues and 55 percent of worldwide production in the third quarter of 2024. Crude oil prices realized in the third quarter of 2024 averaged $78.06 per barrel, compared with $86.15 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production increased 48.5 Mb/d to 256.3 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.

Natural Gas Natural gas revenues for the third quarter of 2024 totaled $103 million, a $133 million decrease from the comparative 2023 quarter. A 54 percent decrease in average realized prices decreased third-quarter 2024 natural gas revenues by $128 million compared to the third quarter of 2023, while 4 percent lower average daily production decreased revenues by $5 million. Natural gas revenues accounted for 5 percent of total oil and gas production revenues and 28 percent of worldwide production during the third quarter of 2024.

The Company’s worldwide natural gas production decreased 33.2 MMcf/d to 786.9 MMcf/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, natural production decline, and the sale of non-core assets in the U.S. These decreases were offset by the Callon acquisition coupled with increased drilling activity and recompletions in the Permian Basin.

NGL NGL revenues for the third quarter of 2024 totaled $158 million, a $20 million increase from the comparative 2023 quarter. An 18 percent higher average daily production increased third-quarter 2024 NGL revenues by $26 million compared to the third quarter of 2023, while a 4 percent decrease in average realized prices decreased revenues by $6 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2024.

The Company’s worldwide NGL production increased 12.2 Mb/d to 80 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of the Callon acquisition coupled with increased drilling activity in the Permian Basin. These increases were offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.

Year-to-Date 2024 compared to Year-to-Date 2023

Crude Oil Crude oil revenues for the first nine months of 2024 totaled $5.1 billion, a $669 million increase from the comparative 2023 period. An 18 percent higher average daily production increased oil revenues for the 2024 period by $680 million compared to the prior-year period, while a slight decrease in average realized prices lowered oil revenues by $11 million compared to the prior-year period. Crude oil revenues accounted for 85 percent of total oil and gas production revenues and 54 percent of worldwide production for the first nine months of 2024. Crude oil prices realized during the first nine months of 2024 averaged $80.31 per barrel, compared to $80.50 per barrel in the comparative prior-year period.

The Company’s worldwide oil production increased 35.4 Mb/d to 236.8 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline across all assets, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.

Natural Gas Natural gas revenues for the first nine months of 2024 totaled $414 million, a $244 million decrease from the comparative 2023 period. A 35 percent decrease in average realized prices decreased natural gas revenues for the 2024 period by $232 million compared to the prior-year period, while 3 percent lower average daily production decreased revenues by $12 million compared to the prior-year period. Natural gas revenues accounted for 7 percent of total oil and gas production revenues and 30 percent of worldwide production for the first nine months of 2024.

The Company’s worldwide natural gas production decreased 24.7 MMcf/d to 803 MMcf/d in the first nine months of 2024 compared to the prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, reduced gas-focused activity in Egypt, natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.

NGL NGL revenues for the first nine months of 2024 totaled $457 million, a $82 million increase from the comparative 2023 period. A 16 percent higher average daily production increased NGL revenues for the 2024 period by $66 million compared to the prior-year period, while a 4 percent increase in average realized prices increased revenues by $16 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2024.

The Company’s worldwide NGL production increased 10.2 Mb/d to 72.9 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to U.S. domestic oil and gas purchases that were sold by the Company to fulfill oil and natural gas takeaway obligations and delivery commitments. Sales related to these purchased volumes totaled $473 million and $229 million during the third quarters of 2024 and 2023, respectively, and $1.0 billion and $612 million during the first nine months of 2024 and 2023, respectively. Purchased oil and gas sales were offset by associated purchase costs of $292 million and $211 million during the third quarters of 2024 and 2023, respectively, and $665 million and $558 million during the first nine months of 2024 and 2023, respectively. Gross purchased oil and gas sales values were higher in the third quarter and the first nine months of 2024 as compared to the third quarter and the first nine months of 2023, primarily driven by activity associated with the Callon acquisition.

Operating Expenses

The Company’s operating expenses were as follows and include costs attributable to a noncontrolling interest in Egypt:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Lease operating expenses	$	418	$	394	$	1,216	$	1,076
Gathering, processing, and transmission	123		89		328		245
Purchased oil and gas costs	292		211		665		558
Taxes other than income	70		61		205		163
Exploration	29		49		248		144
General and administrative	92		139		270		276
Transaction, reorganization, and separation	14		5		156		11
Depreciation, depletion, and amortization:
Oil and gas property and equipment	588		407		1,589		1,086
Gathering, processing, and transmission assets	2		2		5		5
Other assets	5		9		19		26
Asset retirement obligation accretion	36		29		112		86
Impairments	1,111		—		1,111		46
Financing costs, net	100		81		276		235
Total Operating Expenses	$	2,880	$	1,476	$	6,200	$	3,957

Lease Operating Expenses (LOE)

LOE increased $24 million and $140 million compared to the third quarter and the first nine months of 2023, respectively. On a per-unit basis, LOE decreased 4 percent and increased 3 percent in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The absolute dollar increase in the third quarter and the first nine months of 2024 compared to same prior year periods was driven by higher operating and labor costs coupled with higher workover activity, primarily from the Callon acquisition.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Third-party processing and transmission costs	$	123	$	63	$	305	$	164
Midstream service costs – Kinetik	—		26		23		81
Total Gathering, processing, and transmission	$	123	$	89	$	328	$	245

GPT costs increased $34 million and $83 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023, primarily driven by an increase in natural gas and NGL production volumes in the U.S. when compared to the prior-year periods.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $81 million and $107 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The increase in the third quarter and the first nine months of 2024 compared to same prior-year periods was primarily driven by oil purchases from activity associated with the Callon acquisition. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill oil and natural gas takeaway obligations and delivery commitments totaling $473 million and $1.0 billion in the third quarter and the first nine months of 2024, respectively, as discussed above.

Taxes Other Than Income

Taxes other than income increased $9 million and $42 million from the third quarter and the first nine months of 2023, respectively, primarily from higher severance taxes driven by increased production volumes in the U.S. compared to the same prior-year periods.

Exploration Expenses

The Company’s exploration expenses were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Unproved leasehold impairments	$	1	$	9	$	11	$	20
Dry hole expense	8		18		172		71
Geological and geophysical expense	6		1		22		3
Exploration overhead and other	14		21		43		50
Total Exploration	$	29	$	49	$	248	$	144

Exploration expenses decreased $20 million and increased $104 million from the third quarter and the first nine months of 2023, respectively. The decrease in exploration expenses for the third quarter of 2024 compared to the third quarter of 2023 was primarily the result of higher dry hole expenses in the 2023 period coupled with lower unproved leasehold impairments and exploration overhead. The increase in exploration expenses for the first nine months of 2024 compared to the first nine months of 2023 was primarily the result of dry hole expense associated with the completion of an initial drilling campaign in Alaska where two wells were unable to reach target objectives in the allotted seasonal time window.

General and Administrative (G&A) Expenses

G&A expenses decreased $47 million and $6 million from the third quarter and the first nine months of 2023, respectively. The decrease in G&A expenses for the third quarter and first nine months of 2024 compared to the same prior-year periods was primarily driven by higher cash-based stock compensation expense in the 2023 period resulting from changes in the Company’s stock price, partially offset by higher overall labor costs across the Company and the Callon acquisition.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs increased $9 million and $145 million from the third quarter and the first nine months of 2023, respectively. Higher TRS costs during the third quarter and the first nine months of 2024 were primarily a result of ongoing transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.

Depreciation, Depletion, and Amortization (DD&A)

Total DD&A expenses increased $177 million and $496 million from the third quarter and the first nine months of 2023, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $3.30 per boe and $3.33 per boe from the third quarter and the first nine months of 2023, respectively. The increase in DD&A on a per boe basis was driven by negative gas price-related reserve revisions in prior periods and impacts resulting from the Callon acquisition in 2024. Higher absolute dollar amount of DD&A was driven primarily by higher capital expenditures incurred in the U.S. and Egypt.

Impairments

During the third quarter and the first nine months of 2024, the Company recorded $1.1 billion of impairments, which includes $793 million of oil and gas property impairments in the North Sea, $315 million impairment of assets held for sale in the Permian Basin, and $3 million of inventory impairments in the North Sea.

During the first nine months of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

Financing Costs, Net

The Company’s Financing costs were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(In millions)
Interest expense	$	109	$	89	$	302	$	266
Amortization of debt issuance costs	1		1		4		3
Capitalized interest	(8)		(7)		(22)		(18)
Gain on extinguishment of debt	—		—		—		(9)
Interest income	(2)		(2)		(8)		(7)
Total Financing costs, net	$	100	$	81	$	276	$	235

Net financing costs increased $19 million and $41 million from the third quarter and the first nine months of 2023, respectively. The increase in costs during the third quarter and the first nine months of 2024 was primarily due to higher interest expense from higher average long-term debt balances compared to the third quarter and the first nine months of 2023.

Provision for Income Taxes

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.

During the nine months ended September 30, 2024, the Company recognized downward reserve revisions of approximately 26 percent of its year-end 2023 estimated proved reserves in the North Sea as a result of its economic assessment of its North Sea assets described in “Financial and Operational Highlights” above.

Following the completion of the Callon acquisition, the Company revised its full-year 2024 estimated upstream capital investment to approximately $2.8 billion and remains committed to its capital return framework 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, 2023.

Sources and Uses of Cash

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


	For the Nine Months Ended September 30,
	2024		2023

	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,584	$	2,099

Proceeds from commercial paper and revolving credit facilities, net	190		202
Proceeds from term loan facility	1,500		—
Proceeds from asset divestitures	724		29
Proceeds from sale of Kinetik Shares	428		—
Other	20		—
Total Sources of Cash and Cash Equivalents	5,446		2,330
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	2,153	$	1,747

Leasehold and property acquisitions	64		11

Payments on term loan facility	500		—
Payment on Callon Credit Agreement	472		—
Payments on fixed-rate debt	1,641		65
Dividends paid to APA common stockholders	260		232
Distributions to noncontrolling interest	233		154

Treasury stock activity, net	146		208
Other, net	—		63
Total Uses of Cash and Cash Equivalents	5,469		2,480
Decrease in Cash and Cash Equivalents	$	(23)	$	(150)

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 accretion, and deferred income tax expense.

Net cash provided by operating activities during the first nine months of 2024 totaled $2.6 billion, $485 million higher from the first nine months of 2023, primarily due to higher revenues from increased oil and gas production 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 Commercial Paper and Revolving Credit Facilities, Net As of September 30, 2024, outstanding borrowings under the Company’s commercial paper and U.S. dollar denominated syndicated credit facility were $562 million, an increase of $190 million since December 31, 2023. During the nine months ended September 30, 2023, the Company had net borrowings of $202 million under the Company’s U.S. dollar denominated syndicated credit facility.

Proceeds from Term Loan Facility On April 1, 2024, the Company borrowed an aggregate $1.5 billion under a syndicated credit agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the closing of the Callon acquisition. For additional details of the credit agreement, see “Term Loan Credit Agreement” in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.

Proceeds from Asset Divestitures The Company received $724 million and $29 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2024 and 2023, respectively. 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.

Proceeds from Sale of Kinetik Shares The Company received $428 million of cash proceeds from the sale of its remaining shares of Kinetik Class A Common Stock in March 2024. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $2.2 billion and $1.7 billion during the first nine months of 2024 and 2023, respectively. The increase in capital investment compared to the prior-year period is reflective of the Company’s acquisition of Callon, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s efforts to balance workover activity in Egypt and reduce drilling activity in the North Sea as it continually assesses inventory opportunities across its diverse portfolio. The Company operated an average of approximately 23 drilling rigs during the first nine months of 2024, compared to an average of approximately 24 drilling rigs during the first nine months of 2023.

Leasehold and Property Acquisitions During the first nine months of 2024 and 2023, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $64 million and $11 million, respectively.

Payments on Callon Credit Agreement During the first nine months of 2024, the Company financed Callon’s repayment in full of the $472 million outstanding under the Callon Credit Agreement upon the Callon acquisition.

Payments on Term Loan Facility During the first nine months of 2024, the Company made a payment of $500 million on its syndicated credit agreement. For additional details of the credit agreement, see “Term Loan Credit Agreement” in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.

Payments on Fixed-Rate Debt During the first nine months of 2024, the Company financed Callon’s repayment pursuant to Callon’s cash tender offers for, and redemptions of all senior notes issued under Callon’s indentures for an aggregate cash payment amount of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.

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 $260 million and $232 million during the first nine months of 2024 and 2023, respectively, for dividends on its common stock.

Distributions to Noncontrolling Interest 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 $233 million and $154 million during the first nine months of 2024 and 2023, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first nine months of 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share and an aggregate purchase price of approximately $146 million, and as of September 30, 2024, the Company had remaining authorization to repurchase 39.3 million shares. In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share and an aggregate purchase price of approximately $208 million.

Liquidity

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


	September 30, 2024		December 31, 2023

	(In millions)
Cash and cash equivalents	$	64	$	87
Total debt – APA and Apache	6,372		5,188
Total equity	6,160		3,691
Available committed borrowing capacity under syndicated credit facilities	2,839		2,894

Cash and Cash Equivalents As of September 30, 2024, the Company had $64 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of September 30, 2024, the Company had $6.4 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility and commercial paper borrowings, and finance lease obligations. As of September 30, 2024, current debt included $2 million of finance lease obligations.

Unsecured 2022 Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.

Uncommitted Lines of Credit Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million in letters of credit outstanding under these facilities.

Commercial Paper Program In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.

As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.

Term Loan Credit Agreement On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement; of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.

On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027, and to allow the lender commitments for the 364-Day Tranche Loans to expire. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.

On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:

•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.

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, 2023. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that the sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction in an amount to be determined in a future hearing. Apache is vigorously pursuing its claims against the sureties.

The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of “Loss on previously sold Gulf of Mexico properties.” Amounts recorded in the first nine months of 2024 included $50 million related to orders received from BSEE during the period to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.

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, 2023. For the nine months ended September 30, 2024, the Company notes the following additional critical accounting estimate:

Long-Lived Asset Impairments

Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.

To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.

Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

The Company has recorded material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities in the third quarter of 2024. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities would be recorded as goodwill.

The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

In estimating the fair values of assets acquired and liabilities assumed, the Company has made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, the Company prepared estimates of crude oil and natural gas reserves as described in the “Reserves Estimates” section of 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, 2023. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

New Accounting Pronouncements

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the conflict in Israel and Gaza, 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 9 percent from $86.15 per barrel to $78.06 per barrel during the third quarters of 2023 and 2024, respectively. The Company’s average natural gas price realizations decreased 54 percent from $3.12 per Mcf to $1.43 per Mcf during the third quarters of 2023 and 2024, respectively. The Company’s average NGL price realizations decreased 4 percent from $22.26 per barrel to $21.29 per barrel during the third quarters of 2023 and 2024, respectively. Based on average daily production for the third quarter of 2024, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $24 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 $7 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 $7 million.

The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2024, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $1 million. A 10 percent increase in natural gas prices would increase the liability by approximately $1 million, while a 10 percent decrease in prices would decrease the liability by approximately $1 million. As of September 30, 2024, the Company had open NGL derivatives not designated as cash flow hedges in a liability position with a fair value of $1 million. The impact of a 10 percent movement in NGL prices would be immaterial to the fair value of the commodity derivatives. These fair value changes assume volatility based on prevailing market parameters at September 30, 2024. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

As of September 30, 2024, 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 term loan facility, commercial paper program, and syndicated credit facilities. As of September 30, 2024, the Company had approximately $64 million in cash and cash equivalents, approximately 86 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2024, there were $1.6 billion of borrowings outstanding under the Company’s term loan facility, commercial paper program, and syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments, term loan facility, commercial paper program, 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 $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2024.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2024, 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 the Company’s management, including its 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

As a result of the Callon acquisition on April 1, 2024, the Company’s internal control over financial reporting, subsequent to the date of acquisition, includes certain additional internal controls relating to Callon. There were no other changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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, 2023 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, 2023.

Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2024, June 30, 2024, and September 30, 2024 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

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

The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2024:


Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2024	102,305	$	29.33	102,305	39,326,125
August 1 to August 31, 2024	—	—		—	39,326,125
September 1 to September 30, 2024	—	—		—	39,326,125
Total	102,305	$	29.33

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

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2024, none of the Company’s officers or directors adopted or terminated any Rule 10b5-1 trading arrangement or “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).

ITEM 6. EXHIBITS

Incorporated by Reference

EXHIBIT
NO.

DESCRIPTION

Form

Exhibit

Filing Date

SEC File No.

2.1

Agreement and Plan of Merger, dated as of January 3, 2024, by and among Registrant, Astro Comet Merger Sub Corp., and Callon Petroleum Company.

8-K

2.1

1/4/2024

001-40144

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.

8-K12B

3.1

3/1/2021

001-40144

3.2

Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated May 24, 2023, as filed with the Secretary of State of the State of Delaware on May 24, 2023.

8-K

3.1

5/25/2023

001-40144

3.3

Amended and Restated Bylaws of Registrant, dated February 2, 2023.

8-K

3.1

2/8/2023

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 September 30, 2024, 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 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

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 thereunto duly authorized.


		APA CORPORATION

Dated:	November 7, 2024	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	November 7, 2024	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

Document

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:


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

Date: November 7, 2024


/s/ John J. Christmann IV
John J. Christmann IV
Chief Executive Officer
(principal executive officer)

Document

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:


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

Date: November 7, 2024


/s/ Stephen J. Riney
Stephen J. Riney
President and Chief Financial Officer
(principal financial officer)

Document

EXHIBIT 32.1

APA CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2024, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 7, 2024


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

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2024, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 7, 2024


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