apa-20250630

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 June 30, 2025


☐			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 July 31, 2025			357,786,460

TABLE OF CONTENTS


Item		Page

	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME	2
	STATEMENT OF CONSOLIDATED CASH FLOWS	3
	CONSOLIDATED BALANCE SHEET	4
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
4.	CONTROLS AND PROCEDURES	44

	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	45
1A.	RISK FACTORS	45
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45
5.	OTHER INFORMATION	45
6.	EXHIBITS	46

FORWARD-LOOKING STATEMENTS AND RISKS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations and capital returns framework, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2024, 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,” “predict,” “prospect,” “should,” “would,” or similar terminology or the negative of these terms, 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 trade tensions between the U.S. and other countries, the Russian war in Ukraine, the armed conflicts in Israel, Gaza, and Iran, 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 impact of international or domestic trade policy changes, including tariffs;

•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;

•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, 2024;

•other risks and uncertainties disclosed in the Company’s second-quarter 2025 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 June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	1,718	$	2,201	$	3,757	$	3,949
Purchased oil and gas sales	460		342		1,057		545
Total revenues	2,178		2,543		4,814		4,494
Derivative instrument gains (losses), net	138		(3)		110		(7)
Gain on divestitures, net	282		276		280		283
Loss on previously sold Gulf of America properties	—		(17)		—		(83)
Other, net	14		(7)		20		8
	2,612		2,792		5,224		4,695
OPERATING EXPENSES:
Lease operating expenses	367		460		774		798
Gathering, processing, and transmission	104		121		208		205
Purchased oil and gas costs	304		210		778		373
Taxes other than income	54		78		128		135
Exploration	43		71		73		219
General and administrative	66		85		164		178
Transaction, reorganization, and separation	11		115		48		142
Depreciation, depletion, and amortization	530		588		1,173		1,018
Asset retirement obligation accretion	39		36		78		76

Financing costs, net	66		100		9		176
	1,584		1,864		3,433		3,320
NET INCOME BEFORE INCOME TAXES	1,028		928		1,791		1,375
Current income tax provision	232		285		538		585
Deferred income tax provision (benefit)	131		23		170		(42)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	665		620		1,083		832
Net income attributable to noncontrolling interest	62		79		133		159
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	603	$	541	$	950	$	673

NET INCOME PER COMMON SHARE:
Basic	$	1.67	$	1.46	$	2.62	$	2.00
Diluted	$	1.67	$	1.46	$	2.62	$	2.00
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	361		371		362		337
Diluted	361		372		362		337

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$	665	$	620	$	1,083	$	832
OTHER COMPREHENSIVE LOSS, NET OF TAX:

Pension and postretirement benefit plan	(1)		(1)		(1)		(1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	664		619		1,082		831
Comprehensive income attributable to noncontrolling interest	62		79		133		159
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	602	$	540	$	949	$	672

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 Six Months Ended June 30,
	2025		2024

	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$	1,083	$	832
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	(108)		5
Gain on divestitures, net	(280)		(283)
Exploratory dry hole expense and unproved leasehold impairments	43		174
Depreciation, depletion, and amortization	1,173		1,018
Asset retirement obligation accretion	78		76

Provision for (benefit from) deferred income taxes	170		(42)
Gain on extinguishment of debt	(145)		—
Loss on previously sold Gulf of America properties	—		83
Other, net	18		31
Changes in operating assets and liabilities:
Receivables	433		(101)
Inventories	5		(2)
Drilling advances and other current assets	222		6
Deferred charges and other long-term assets	1		80
Accounts payable	(153)		(125)
Accrued expenses	(204)		(312)
Deferred credits and noncurrent liabilities	(59)		(195)
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,277		1,245
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(1,437)		(1,223)

Leasehold and property acquisitions	(20)		(63)
Proceeds from asset divestitures	571		729
Proceeds from sale of Kinetik Shares	—		428
Other, net	5		(23)
NET CASH USED IN INVESTING ACTIVITIES	(881)		(152)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) commercial paper and revolving credit facilities, net	(333)		63

Proceeds from (payments on) term loan facility	(900)		1,500
Payment on Callon Credit Agreement	—		(472)

Fixed-rate debt borrowings	846		—
Payments on fixed-rate debt	(954)		(1,641)
Distributions to noncontrolling interest	(217)		(123)
Treasury stock activity, net	(150)		(144)
Dividends paid to APA common stockholders	(181)		(168)
Other, net	(25)		(35)
NET CASH USED IN FINANCING ACTIVITIES	(1,914)		(1,020)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(518)		73
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	625		87
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	107	$	160

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	155	$	178
Income taxes paid, net of refunds	542		566

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

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	June 30, 2025		December 31, 2024

	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	107	$	625
Receivables, net of allowance of $122 and $123	1,509		1,959

Other current assets (Note 5)	672		820
	2,288		3,404
PROPERTY AND EQUIPMENT:
Oil and gas properties	44,630		44,698
Gathering, processing, and transmission facilities	448		433
Other	556		562
Less: Accumulated depreciation, depletion, and amortization	(32,993)		(33,047)
	12,641		12,646
OTHER ASSETS:

Decommissioning security for sold Gulf of America properties (Note 10)	21		21
Deferred tax asset (Note 9)	2,517		2,703
Deferred charges and other	611		616
	$	18,078	$	19,390

LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,074	$	1,224
Current debt	263		53

Other current liabilities (Note 6)	1,507		1,678
	2,844		2,955
LONG-TERM DEBT (Note 8)	4,288		5,991
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 9)	—		14
Asset retirement obligation (Note 7)	2,621		2,591
Decommissioning contingency for sold Gulf of America properties (Note 10)	909		929
Other	513		548
	4,043		4,082
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 492,029,841 and 491,579,646 shares issued, respectively	308		307
Paid-in capital	12,980		13,153
Accumulated deficit	(1,205)		(2,155)
Treasury stock, at cost, 133,256,513 and 126,182,497 shares, respectively	(6,189)		(6,037)
Accumulated other comprehensive income	11		12
APA SHAREHOLDERS’ EQUITY	5,905		5,280
Noncontrolling interest	998		1,082
TOTAL EQUITY	6,903		6,362
	$	18,078	$	19,390

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 June 30, 2024
Balance at March 31, 2024	$	263	$	11,047	$	(2,827)	$	(5,891)	$	15	$	2,607	$	1,046	$	3,653
Net income attributable to common stock	—		—		541		—		—		541		—		541
Net income attributable to noncontrolling interest	—		—		—		—		—		—		79		79
Distributions to noncontrolling interest	—		—		—		—		—		—		(53)		(53)
Common dividends declared ($0.25 per share)	—		(93)		—		—		—		(93)		—		(93)
Issuance of common stock	44		2,370		—		—		—		2,414		—		2,414
Treasury stock activity, net	—		—		—		(43)		—		(43)		—		(43)
Other	—		(2)		—		—		(1)		(3)		—		(3)
Balance at June 30, 2024	$	307	$	13,322	$	(2,286)	$	(5,934)	$	14	$	5,423	$	1,072	$	6,495

For the Quarter Ended June 30, 2025
Balance at March 31, 2025	$	307	$	13,063	$	(1,808)	$	(6,138)	$	12	$	5,436	$	1,027	$	6,463
Net income attributable to common stock	—		—		603		—		—		603		—		603
Net income attributable to noncontrolling interest	—		—		—		—		—		—		62		62
Distributions to noncontrolling interest	—		—		—		—		—		—		(91)		(91)
Common dividends declared ($0.25 per share)	—		(90)		—		—		—		(90)		—		(90)

Treasury stock activity, net	—		—		—		(51)		—		(51)		—		(51)
Other	1		7		—		—		(1)		7		—		7
Balance at June 30, 2025	$	308	$	12,980	$	(1,205)	$	(6,189)	$	11	$	5,905	$	998	$	6,903

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 Six Months Ended June 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	—		—		673		—		—		673		—		673
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		159		159
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		(123)		(123)
Common dividends declared ($0.50 per share)	—		(168)		—		—		—		(168)		—		(168)
Issuance of common stock	44		2,370		—		—		—		2,414		—		2,414
Treasury stock activity, net	—		—		—		(144)		—		(144)		—		(144)
Other	—		(6)		—		—		(1)		(7)		—		(7)
Balance at June 30, 2024	$	307	$	13,322	$	(2,286)	$	(5,934)	$	14	$	5,423	$	1,072	$	6,495

For the Six Months Ended June 30, 2025
Balance at December 31, 2024	$	307	$	13,153	$	(2,155)	$	(6,037)	$	12	$	5,280	$	1,082	$	6,362
Net income attributable to common stock	—		—		950		—		—		950		—		950
Net income attributable to noncontrolling interest – Egypt	—		—		—		—		—		—		133		133
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		(217)		(217)
Common dividends declared ($0.50 per share)	—		(181)		—		—		—		(181)		—		(181)

Treasury stock activity, net	—		—		—		(152)		—		(152)		—		(152)
Other	1		8		—		—		(1)		8		—		8
Balance at June 30, 2025	$	308	$	12,980	$	(1,205)	$	(6,189)	$	11	$	5,905	$	998	$	6,903

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, 2024, which contains a summary of the Company’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2025, 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, 2024. 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). 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.

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 7—Asset Retirement Obligation), the estimate of income taxes (refer to Note 9—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of America (refer to Note 10—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 and Note 8—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 or when allocating the purchase price for acquired assets and liabilities in a business combination.

The Company recorded no asset impairments in connection with fair value assessments during the six months ended June 30, 2025 and June 30, 2024.

Revenue Recognition

Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.3 billion and $1.7 billion as of June 30, 2025 and December 31, 2024, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Over the past two years, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has been delayed for periods longer than historically experienced. The Company has seen improved receipts in recent quarters for oil and gas sales to EGPC. The Company continues to be actively engaged in discussions with the Government of Egypt and EGPC to reduce the outstanding balance and management believes 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 12—Business Segment Information for a disaggregation of oil, gas, and natural gas liquids 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. No inventory impairments were recognized during the six months ended June 30, 2025 and June 30, 2024.

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. No proved oil and gas property impairments were recognized during the six months ended June 30, 2025 and June 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 under “Gain on divestitures, net” in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.

Transaction, Reorganization, and Separation (TRS)

The Company recorded $11 million and $48 million of TRS costs during the second quarter and the first six months of 2025, respectively, and $115 million and $142 million of TRS costs during the second quarter and the first six months of 2024, respectively. TRS costs incurred in the first six months of 2025 comprised primarily employee separations and other cost-saving initiatives. TRS costs incurred in the first six months of 2024 were primarily a result of transaction and separation costs related to the Callon acquisition coupled with separation costs in the North Sea.

New Pronouncements Issued But Not Yet Adopted

There were no changes in recently issued or adopted accounting standards from those disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 that would have an expected material effect on the Company.

2. ACQUISITIONS AND DIVESTITURES

2025 Activity

Leasehold and Property Acquisitions

During the second quarter and first six months of 2025, the Company completed leasehold acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $7 million and $20 million, respectively.

U.S. Divestiture

During the second quarter of 2025, the Company completed the sale of all of its New Mexico Permian assets. The assets had a carrying value of $300 million and associated retirement obligation of $9 million, which were exchanged for total cash consideration of $573 million, inclusive of post-closing adjustments. The Company received cash of $567 million during the second quarter of 2025 and expects to receive the remaining balance in the third quarter of 2025. The Company recognized a gain of $282 million during the second quarter of 2025 in association with this sale. Proceeds from the transaction were used primarily for debt reduction.

2024 Activity

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.

Subject to the terms of the 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, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.

Upon completing the acquisition, APA refinanced substantially all of Callon’s debt by borrowing under APA’s US dollar denominated syndicated credit facilities. Refer to Note 8—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 Company has finalized the valuation of the assets acquired and liabilities assumed.


	(In millions)
Current assets	$	287
Property and equipment	4,502
Deferred tax asset	565
Other assets	12
Total assets acquired	$	5,366
Current liabilities	$	632
Long-term debt	2,113
Asset retirement obligation	136

Other long-term obligations	48
Total liabilities assumed	$	2,929
Net assets acquired	$	2,437

The following unaudited pro forma combined results for the second quarter and first six months ended June 30, 2024 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, and estimated tax impacts of the pro forma adjustments.


	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2024		2024

	(In millions, except share data)
Revenues	$	2,201	$	4,513
Net income attributable to common stock	630		779
Net income per common share – basic	1.70		2.10
Net income per common share – diluted	1.69		2.10

From the date of the acquisition through June 30, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $438 million and $109 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.

Leasehold and Property Acquisitions

During the first six months of 2024, in addition to the Callon acquisition, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $63 million.

U.S. Divestitures

During the second quarter 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 and received aggregate cash proceeds of $255 million and the assumption of asset retirement obligations of $42 million. The Company recognized a $50 million loss during the second quarter of 2024 in association with this sale.

During the second quarter 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 $394 million after post-closing adjustments. The Company recognized a gain of $321 million during the second quarter of 2024 in association with this sale.

Additionally, during the second quarter and first six months of 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $45 million and $72 million, respectively, recognizing a gain of approximately $1 million and $8 million, respectively, upon closing of these transactions.

On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $1.1 billion and associated asset retirement obligation of $224 million for total cash proceeds of $869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf. The effective date of the transaction is July 1, 2024. As a result of the transaction, 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 the associated oil and gas properties during the third quarter of 2024. During the fourth quarter of 2024, the Company recorded a loss of $5 million upon closing of the transaction.

Sale of Kinetik Shares

On March 18, 2024, the Company sold its remaining shares of Kinetik Holdings Inc. (Kinetik) Class A Common Stock (Kinetik Shares) for cash proceeds of $428 million.

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $297 million and $237 million as of June 30, 2025 and December 31, 2024, respectively. The increase is attributable to additional drilling activity in Egypt and Alaska. Approximately $8 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2024 were charged to dry hole expense during the first six months of 2025. During the first six 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 June 30, 2025, the Company had derivative positions with 11 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

Derivative Instruments

Commodity Derivative Instruments

As of June 30, 2025, 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
July—December 2025	NYMEX Henry Hub/IF Waha	93,840	$(3.16)	—	—
July—December 2025	NYMEX Henry Hub/IF HSC	—	—	42,320	$(0.51)
January—December 2026	NYMEX Henry Hub/IF Waha	34,675	$(1.97)	—	—

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 $25 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for the 2025 calendar year. The Company determined that the earn-out obligation was not clearly and closely related to the underlying agreement and therefore bifurcated this embedded feature and recorded the derivative at fair value.

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)
June 30, 2025
Assets:
Commodity derivative instruments	$	—	$	113	$	—	$	113	$	(3)	$	110

Liabilities:
Commodity derivative instruments	$	—	$	3	$	—	$	3	$	(3)	$	—


Contingent consideration arrangements	—		21		—		21		—		21
December 31, 2024


Liabilities:

Contingent consideration arrangements	$	—	$	18	$	—	$	18	$	—	$	18

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

Derivative Activity Recorded in the Consolidated Balance Sheet

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


	June 30, 2025		December 31, 2024

	(In millions)
Current Assets: Other current assets	$	103	$	—
Other Assets: Deferred charges and other	7		—
Total derivative assets	$	110	$	—

Current Liabilities: Other current liabilities	$	21	$	—
Deferred Credit and Other Noncurrent Liabilities: Other	—		18
Total derivative liabilities	$	21	$	18

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 June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Realized:
Commodity derivative instruments	$	2	$	(6)	$	2	$	(2)

Realized gains (losses), net	2		(6)		2		(2)
Unrealized:
Commodity derivative instruments	138		3		110		(5)
Contingent consideration arrangements	(2)		—		(2)		—



Unrealized gains (losses), net	136		3		108		(5)
Derivative instrument gains (losses), net	$	138	$	(3)	$	110	$	(7)

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 and 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:


	June 30, 2025		December 31, 2024

	(In millions)
Inventories	$	386	$	425
Drilling advances	138		184
Derivative instruments	103		—
Current decommissioning security for sold Gulf of America assets	18		157
Prepaid assets and other	27		54
Total Other current assets	$	672	$	820

6. OTHER CURRENT LIABILITIES

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


	June 30, 2025		December 31, 2024

	(In millions)
Accrued operating expenses	$	166	$	204
Accrued exploration and development	475		460
Accrued compensation and benefits	107		223
Accrued interest	94		93
Accrued income taxes	197		221
Current asset retirement obligation	103		103
Current operating lease liability	113		118

Current decommissioning contingency for sold Gulf of America properties	88		88
Other	164		168
Total Other current liabilities	$	1,507	$	1,678

7. ASSET RETIREMENT OBLIGATION

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


	June 30, 2025
	(In millions)
Asset retirement obligation, December 31, 2024	$	2,694
Liabilities incurred	8

Liabilities settled	(49)
Liabilities divested	(9)

Accretion expense	78
Revisions in estimated liabilities	2
Asset retirement obligation, June 30, 2025	2,724
Less current portion	(103)
Asset retirement obligation, long-term	$	2,621

8. DEBT AND FINANCING COSTS

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


	June 30, 2025		December 31, 2024

	(In millions)
APA notes and debentures before unamortized discount and debt issuance costs(1)	$	3,581	$	—
Apache notes and debentures before unamortized discount and debt issuance costs(2)	995		4,835

APA commercial paper, term loan, and revolving credit facilities(3)	—		1,233
Apache finance lease obligations	29		30
Unamortized discount	(24)		(25)
Debt issuance costs	(30)		(29)
Total debt	4,551		6,044
Current maturities	(263)		(53)
Long-term debt	$	4,288	$	5,991

(1) The fair values of the APA notes and debentures were $3.2 billion as of June 30, 2025. There was no APA indenture debt outstanding on December 31, 2024.

(2) The fair values of the Apache notes and debentures were $926 million and $4.4 billion as of June 30, 2025 and December 31, 2024, 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).

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

At each of June 30, 2025 and December 31, 2024, 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 June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Interest expense	$	86	$	108	$	177	$	193
Amortization of debt issuance costs	2		2		4		3
Capitalized interest	(16)		(7)		(20)		(14)
Gain on extinguishment of debt	(3)		—		(145)		—
Interest income	(3)		(3)		(7)		(6)
Financing costs, net	$	66	$	100	$	9	$	176

Indenture Debt Activity

During the first six months of 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $108 million for an aggregate purchase price of $100 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $10 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025.

APA Exchange and Tender Offers for Apache Indenture Debt

On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA’s cash tender offers. In settling these offerings pursuant to their respective terms:

•APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA’s exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA’s 6.10% Notes due 2035 and $500 million aggregate principal amount of APA’s 6.75% Notes due 2055.

•In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration.

•APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. The Company recognized a gain of $135 million on these purchases, including broker fees and loan costs.

•Net proceeds from the sale of the notes in APA’s new notes offering, after deducting the initial purchasers’ discounts and estimated offering expenses, were approximately $839 million and were used to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.

•Each series of APA notes and debentures issued in settlement of the exchange and tender offers has the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.

•Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering were fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than $1 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.

•APA entered into two registration rights agreements, one covering notes and debentures issued in APA’s exchange and tender offers and one covering notes issued in APA’s new notes offering (each a Registration Rights Agreement). These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA to use commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions, registration rights applicable to the unregistered notes, or any increase in annual interest rate for failure to comply with such registration rights) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue at specified rates on the principal amount of such registrable securities.

Unsecured 2025 Committed Credit Facilities

On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:

•One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the 2025 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 January 2030, subject to the Company’s two, one-year extension options.

Apache guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.

The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022:

•One agreement was denominated in US dollars (the 2022 USD Agreement) and provided 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 was committed).

•The second agreement was denominated in pounds sterling (the 2022 GBP Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit.

On January 15, 2025, the Company terminated commitments under both the 2022 USD Agreement and 2022 GBP Agreement in connection with entry into the 2025 Agreements.

As of June 30, 2025, there were no borrowings or letters of credit outstanding under the 2025 USD Agreement and an aggregate £183 million in letters of credit outstanding under the 2025 GBP Agreement. As of December 31, 2024, there were $10 million of borrowings and no letters of credit outstanding under the 2022 USD Agreement and an aggregate £303 million in letters of credit outstanding under the 2022 GBP 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 June 30, 2025 and December 31, 2024, there were no outstanding borrowings under these facilities. As of June 30, 2025, there were £705 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2024, there were £640 million and $11 million in letters of credit outstanding under these facilities.

Commercial Paper Program

The Company has 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 $2.0 billion outstanding at any time. The program was established in December 2023, and the maximum aggregate face amount of CP Notes issuable thereunder was increased to $2.0 billion from $1.8 billion on June 20, 2025. 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 revolving credit facilities for general corporate purposes, which as of June 30, 2025, included the $2.0 billion 2025 USD Agreement.

Payment of CP Notes was 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 was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on June 20, 2025.

The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.

As of June 30, 2025, the Company had no CP Notes outstanding. As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which was classified as long-term debt.

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 upon closings of APA’s acquisition of Callon and the 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).

On April 1, 2024, APA acquired Callon and 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.

As of December 31, 2024, there were $900 million in 3-Year Tranche Loans remaining outstanding under the Term Loan Credit Agreement. APA could at any time prepay loans under the Term Loan Credit Agreement, which it elected to do on March 10, 2025, when APA fully repaid amounts outstanding under the Term Loan Credit Agreement. The repayment was partially financed with borrowings under APA’s 2025 USD Agreement and commercial paper program.

9. 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 six months ended June 30, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. The Company’s effective income tax rate for the six months ended June 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations.

On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2025, the Company recorded a deferred tax expense of $76 million related to the remeasurement of the December 31, 2024 U.K. deferred tax liability.

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for corporate alternative minimum tax (CAMT) purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, the Company will record the impact of OBBBA in the third quarter of 2025.

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, the Company 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.

10. 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 June 30, 2025, the Company has an accrued liability of approximately $16 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, 2024.

Louisiana Restoration

As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, 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.

Currently, the State of Louisiana, a number of coastal parishes in Louisiana, and the City of New Orleans, as plaintiffs, are all pursuing various lawsuits against many oil and gas producers with current or historic operations in Louisiana. In these cases, the 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. Following its settlement with a number of parishes and the state, the Company is now a defendant in only one coastal zone lawsuit, which was filed by the City of New Orleans against the Company and a number of oil and gas operators and pipeline companies. The Company is vigorously defending this lawsuit.

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. Upon remand, on March 6, 2025, the court of appeals affirmed the entirety of the trial courts’ orders resulting in final judgment in favor of the Company, plaintiffs taking nothing by their claims,

and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The plaintiffs did not appeal the court of appeals’ March 6, 2025 opinion, meaning that the judgment in favor of the Company is final.

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. In 2018, Quadrant was acquired by Australian oil and gas company Santos, Ltd., who assumed Quadrant’s place in the ongoing litigation. In early 2025, Santos amended the pending counterclaims to abandon a number of claims that had been asserted against the Company but maintaining counterclaims for approximately AUD $57 million. Santos then filed a new lawsuit in the Supreme Court of Western Australia contending that it may be liable to the Australian Taxation Office for assessments, penalties, and interest related to the 2014 and 2015 tax years of approximately AUD $133 million and asserting that, if such amounts must be paid, the Company is liable to Santos for those amounts under the Quadrant SPA. All lawsuits related to the Quadrant SPA have now been consolidated into the same proceeding. The Company will vigorously prosecute its claim while vigorously defending against any counterclaims.

Delaware Litigation

On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company is vigorously defending the suit.

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.

Environmental Matters

The Company is not aware of any environmental claims existing as of June 30, 2025, 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 America (GOA) Shelf operations and properties and its GOA 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 GOA 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 GOA 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 GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA 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 GOA 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 GOM Shelf loans of up to $400 million to perform decommissioning, with such loans and related obligations secured by first and prior liens on the Legacy GOA 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 GOA 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 GOA Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOA 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 GOA 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 $148 million in Bonds and $350 million in Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. The parties settled their dispute in the first quarter of 2025, which resulted in, among other things, mutual releases, the retention by Apache of all amounts drawn on the Letters of Credit, and payment to Apache of $140 million under the Bonds.

As of June 30, 2025, the Company recorded an asset of $39 million representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.

The Company has also recorded contingent liabilities in the amounts of $1.0 billion for each of the periods ended June 30, 2025 and December 31, 2024, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOA Assets. There have been no other changes in estimates from December 31, 2024 that would have a material impact on the Company’s financial position, results of operations, or liquidity.

The Company recognized $17 million and $83 million in the second quarter and first six months of 2024, respectively, of losses for estimated decommissioning costs on GOA properties previously sold to Fieldwood and other GOA operators.

11. CAPITAL STOCK

Net Income per Common Share

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


	For the Quarter Ended June 30,
	2025					2024
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	603	361	$	1.67	$	541	371	$	1.46
Effect of Dilutive Securities:
Stock compensation awards	$	—	—	$	—	$	—	1	$	—
Diluted:
Income attributable to common stock	$	603	361	$	1.67	$	541	372	$	1.46

	For the Six Months Ended June 30,
	2025					2024
	Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	950	362	$	2.62	$	673	337	$	2.00



Diluted:
Income attributable to common stock	$	950	362	$	2.62	$	673	337	$	2.00

The diluted earnings per share calculation excludes 3.6 million and 2.3 million of options and restricted stock units that were anti-dilutive during the second quarters of 2025 and 2024, respectively, and 3.6 million and 2.1 million during the first six months of 2025 and 2024, respectively.

Stock Repurchase Program

In the second quarter of 2025, the Company repurchased approximately 2.7 million shares at an average price of $18.53 per share. For the six months ended June 30, 2025, the Company repurchased 7.1 million shares at an average price of $21.21 per share, and as of June 30, 2025, the Company had remaining authorization to repurchase up to 27.7 million shares. In the second quarter of 2024, the Company repurchased approximately 1.5 million shares at an average price of $28.72 per share. For the six months ended June 30, 2024, the Company repurchased 4.5 million shares at an average price of $31.77 per share

The Company repurchased 1.0 million shares at an average price of $19.28 per share in July 2025, and as of July 31, 2025, the Company had remaining authorization to repurchase up to 26.7 million shares.

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

Common Stock Dividend

For the quarters ended June 30, 2025 and June 30, 2024, the Company paid $90 million and $92 million, respectively, in dividends on its common stock. For the six months ended June 30, 2025 and June 30, 2024, the Company paid $181 million and $168 million, respectively, in dividends on its common stock.

Common Stock Issuance

In the second quarter of 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.

12. BUSINESS SEGMENT INFORMATION

As of June 30, 2025, the Company’s consolidated subsidiaries are engaged in exploration, development, and/or production across four operating segments: the U.S., Egypt, North Sea, and Suriname. The Company’s business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Alaska, Uruguay, and other international locations that may, over time, result in reportable discoveries and development opportunities.

The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company’s Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is primarily associated with operating income from each segment and the resulting free cash flow, amongst other metrics. The Company concluded that the most comparable measure under U.S. GAAP is operating income.

Financial information for each segment is presented below:


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(2)		Total(3)


For the Quarter Ended June 30, 2025	(In millions)
Revenues:
Oil revenues	$	730	$	521	$	130	$	—	$	1,381
Natural gas revenues	48		109		27		—		184
Natural gas liquids revenues	144		—		9		—		153
Oil, natural gas, and natural gas liquids production revenues	922		630		166		—		1,718
Purchased oil and gas sales	460		—		—		—		460

	1,382		630		166		—		2,178
Operating Expenses:
Lease operating expenses(4)	196		100		71		—		367
Gathering, processing, and transmission(4)	85		7		12		—		104
Purchased oil and gas costs	304		—		—		—		304
Taxes other than income(4)	54		—		—		—		54
Exploration(5)	1		40		—		2		43
Depreciation, depletion, and amortization(4)	328		149		53		—		530
Asset retirement obligation accretion	11		—		28		—		39

	979		296		164		2		1,441
Operating Income (Loss)(6)	$	403	$	334	$	2	$	(2)	737

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

Gain on divestitures, net									282
Other, net									14
General and administrative									(66)
Transaction, reorganization, and separation									(11)
Financing costs, net									(66)
Income Before Income Taxes									$	1,028


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(2)		Total(3)


For the Six Months Ended June 30, 2025	(In millions)
Revenues:
Oil revenues	$	1,546	$	1,103	$	332	$	—	$	2,981
Natural gas revenues	152		200		65		—		417
Natural gas liquids revenues	340		—		19		—		359
Oil, natural gas, and natural gas liquids production revenues	2,038		1,303		416		—		3,757
Purchased oil and gas sales	1,057		—		—		—		1,057
	3,095		1,303		416		—		4,814
Operating Expenses:
Lease operating expenses(4)	396		210		168		—		774
Gathering, processing, and transmission(4)	170		12		26		—		208
Purchased oil and gas costs	778		—		—		—		778
Taxes other than income(4)	128		—		—		—		128
Exploration(5)	3		60		1		9		73
Depreciation, depletion, and amortization(4)	747		302		124		—		1,173
Asset retirement obligation accretion	21		—		57		—		78

	2,243		584		376		9		3,212
Operating Income (Loss)(6)	$	852	$	719	$	40	$	(9)	1,602

Other Income (Expense):
Derivative instrument gains, net									110

Gain on divestitures, net									280
Other, net									20
General and administrative									(164)
Transaction, reorganization, and separation									(48)
Financing costs, net									(9)
Income Before Income Taxes									$	1,791

Total Assets(7)	$	12,752	$	3,386	$	1,163	$	777	$	18,078


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(2)		Total(3)


For the Quarter Ended June 30, 2024	(In millions)
Revenues:
Oil revenues	$	1,021	$	673	$	213	$	—	$	1,907
Natural gas revenues	15		73		47		—		135
Natural gas liquids revenues	152		—		7		—		159
Oil, natural gas, and natural gas liquids production revenues	1,188		746		267		—		2,201
Purchased oil and gas sales	342		—		—		—		342
	1,530		746		267		—		2,543
Operating Expenses:
Lease operating expenses(4)	220		123		117		—		460
Gathering, processing, and transmission(4)	98		7		16		—		121
Purchased oil and gas costs	210		—		—		—		210
Taxes other than income(4)	78		—		—		—		78
Exploration(5)	37		25		1		8		71
Depreciation, depletion, and amortization(4)	361		152		75		—		588
Asset retirement obligation accretion	10		—		26		—		36

	1,014		307		235		8		1,564
Operating Income (Loss)(6)	$	516	$	439	$	32	$	(8)	979

Other Income (Expense):
Derivative instrument losses, net									(3)
Loss on previously sold Gulf of America properties									(17)
Gain on divestitures, net									276
Other, net									(7)
General and administrative									(85)
Transaction, reorganization, and separation									(115)
Financing costs, net									(100)
Income Before Income Taxes									$	928


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(2)		Total(3)


For the Six Months Ended June 30, 2024	(In millions)
Revenues:
Oil revenues	$	1,609	$	1,330	$	400	$	—	$	3,339
Natural gas revenues	72		150		89		—		311
Natural gas liquids revenues	283		—		16		—		299
Oil, natural gas, and natural gas liquids production revenues	1,964		1,480		505		—		3,949
Purchased oil and gas sales	545		—		—		—		545
	2,509		1,480		505		—		4,494
Operating Expenses:
Lease operating expenses(4)	360		243		195		—		798
Gathering, processing, and transmission(4)	162		13		30		—		205
Purchased oil and gas costs	373		—		—		—		373
Taxes other than income(4)	135		—		—		—		135
Exploration(5)	107		56		1		55		219
Depreciation, depletion, and amortization(4)	575		297		146		—		1,018
Asset retirement obligation accretion	25		—		51		—		76

	1,737		609		423		55		2,824
Operating Income (Loss)(6)	$	772	$	871	$	82	$	(55)	1,670

Other Income (Expense):
Derivative instrument losses, net									(7)
Loss on previously sold Gulf of America properties									(83)
Gain on divestitures, net									283
Other, net									8
General and administrative									(178)
Transaction, reorganization, and separation									(142)
Financing costs, net									(176)
Income Before Income Taxes									$	1,375


Total Assets(7)	$	14,075	$	3,740	$	1,844	$	536	$	20,195

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and six months ended June 30, 2025 and June 30, 2024 of:


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Oil	$	125	$	177	$	276	$	351
Natural gas	26		19		50		40

(2)Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported.

(3)Includes noncontrolling interests in Egypt.

(4)Represents significant segment expense categories that align with the segment-level information that is regularly provided to the CODM. The remaining expenses that comprise the Operating Income (Loss) amount by segment are deemed to be other segment expense categories necessary to arrive at the segment profit or loss.

(5)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities.

(6)Operating income includes no leasehold impairments for the second quarters of 2025 and 2024. Operating income includes no leasehold impairments for the first six months of 2025. Operating income of U.S. includes leasehold impairments of $10 million for the first six months of 2024.

(7)Intercompany balances are excluded from total assets.

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, 2024.

Overview

APA is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids (NGLs). The Company’s 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 development, exploration and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, 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 consolidated 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 impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. 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.

In the first quarter of 2025, the Company announced a significant cost reduction initiative. The Company’s primary objective is to drive sustainable cost savings for the long-term and is targeting over $350 million in annualized savings within 2026. This will include reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices.

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 free cash flow through dividends and share repurchases 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 second quarter of 2025, the Company has repurchased 92.4 million shares of the Company’s common stock. Subsequent to the quarter ended June 30, 2025 through July 31, 2025, the Company repurchased 1.0 million shares, and as of July 31, 2025, the Company had remaining authorization to repurchase up to 26.7 million shares under the Company’s share repurchase programs.

Financial and Operational Highlights

In the second quarter of 2025, the Company reported net income attributable to common stock of $603 million, or $1.67 per diluted share, compared to net income of $541 million, or $1.46 per diluted share, in the second quarter of 2024. The Company reported lower revenues and operating expenses in the second quarter of 2025 compared to the second quarter of 2024, but the decrease in revenues, primarily on lower commodity prices, was offset by unrealized gains on commodity derivative instruments and cost reductions.

In the first six months of 2025, the Company reported net income attributable to common stock of $950 million, or $2.62 per diluted share, compared to net income of $673 million, or $2.00 per diluted share, in the first six months of 2024. The increase in net income in the first six months of 2025 was primarily driven by increased production from drilling activity in the Permian Basin coupled with the Callon merger, as well as gains on extinguishment of debt and derivative instruments.

The Company generated $2.3 billion of cash from operating activities during the first six months of 2025, 83 percent higher than the first six months of 2024. APA’s higher operating cash flows for the first six months of 2025 were primarily driven by the timing of working capital items. The Company repurchased 7.1 million shares of its common stock for $150 million and paid $181 million in dividends to APA common stockholders during the first six months of 2025. The Company exited the quarter with approximately $4.6 billion of debt, a reduction of $1.5 billion from year-end 2024.

Key operational highlights include:

United States

•Daily boe production from the Company’s U.S. assets, which decreased 4 percent from the second quarter of 2024, accounted for 62 percent of the Company’s worldwide production during the second quarter of 2025. The Company averaged seven drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and three rigs in the Delaware Basin in the second quarter of 2025. The Company brought online 36 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.

•APA holds approximately 750 MMBtu/d of firm capacity on various pipelines. As of June 30, 2025, the Company had open basis swap contracts which purchased NYMEX Henry Hub/Waha and sold NYMEX Henry Hub/HSC on approximately two-thirds of its firm transport capacity for 2025, thereby locking in a significant portion of cash flows associated with its marketing activities for the remainder of the year. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.

•During the second quarter of 2025, the Company and its partners announced a successful flow test of an exploratory well in Alaska, with the well averaging 2,700 b/d during the final flow period. The Company will evaluate the data from the well to determine next steps, and further appraisal drilling will determine the ultimate size of the discovery. The Company holds a 50 percent ownership interest in the project.

•During the second quarter of 2025, the Company completed the sale of certain non-core assets and leasehold in the Permian Basin, reflecting a full exit from New Mexico. The assets had a carrying value of $300 million and associated retirement obligation of $9 million, which were exchanged for total cash consideration of $573 million, inclusive of post-closing adjustments. The Company recognized a gain of $282 million in association with this sale. The divested assets represent less than 5 percent of the Company’s Permian Basin oil production. The Company used the proceeds from this transaction primarily for debt reduction.

International

•In Egypt, the Company averaged 13 drilling rigs and drilled 20 new productive wells during the second quarter of 2025. During the same period, the Company averaged 19 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Second quarter 2025 gross and net production from the Company’s Egypt assets decreased 4 percent and increased 8 percent, respectively, from the second quarter of 2024.

•In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company now expects one-third of its activities to be gas-focused and anticipates continued strong performance for the rest of the year, with realized gas prices increasing through the period.

•Subsequent to the end of the quarter, the Government of Egypt awarded the Company an additional 2 million net exploration acreage in the Western Desert for a period of five years. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The transaction is expected to close in the third-quarter of 2025.

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 June 30,								For the Six Months Ended June 30,
	2025				2024				2025				2024
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution

	($ in millions)
Oil Revenues:
United States	$	730	53	%	$	1,021	54	%	$	1,546	52	%	$	1,609	48	%
Egypt(1)	521		38	%	673		35	%	1,103		37	%	1,330		40	%
North Sea	130		9	%	213		11	%	332		11	%	400		12	%
Total(1)	$	1,381	100	%	$	1,907	100	%	$	2,981	100	%	$	3,339	100	%

Natural Gas Revenues:
United States	$	48	26	%	$	15	11	%	$	152	36	%	$	72	23	%
Egypt(1)	109		59	%	73		54	%	200		48	%	150		48	%
North Sea	27		15	%	47		35	%	65		16	%	89		29	%
Total(1)	$	184	100	%	$	135	100	%	$	417	100	%	$	311	100	%

NGL Revenues:
United States	$	144	94	%	$	152	96	%	$	340	95	%	$	283	95	%

North Sea	9		6	%	7		4	%	19		5	%	16		5	%
Total(1)	$	153	100	%	$	159	100	%	$	359	100	%	$	299	100	%

Oil and Gas Revenues:
United States	$	922	54	%	$	1,188	54	%	$	2,038	54	%	$	1,964	50	%
Egypt(1)	630		37	%	746		34	%	1,303		35	%	1,480		37	%
North Sea	166		9	%	267		12	%	416		11	%	505		13	%
Total(1)	$	1,718	100	%	$	2,201	100	%	$	3,757	100	%	$	3,949	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 June 30,			For the Six Months Ended June 30,
	2025	Increase (Decrease)	2024	2025	Increase (Decrease)	2024
Oil Volume (b/d)
United States	123,725	(11)%	139,361	124,420	12%	111,441
Egypt(1)(2)	86,210	(2)%	87,702	86,192	(1)%	87,235
North Sea	25,309	(5)%	26,586	25,258	(10)%	28,190
Total	235,244	(7)%	253,649	235,870	4%	226,866

Natural Gas Volume (Mcf/d)
United States	519,276	2%	510,708	546,853	15%	477,223
Egypt(1)(2)	345,649	27%	273,077	331,507	18%	281,652
North Sea	29,174	(44)%	51,854	30,383	(42)%	52,229
Total	894,099	7%	835,639	908,743	12%	811,104

NGL Volume (b/d)
United States	79,632	1%	78,937	78,525	16%	67,756

North Sea	1,186	(23)%	1,550	1,165	(21)%	1,477
Total	80,818	—%	80,487	79,690	15%	69,233

BOE per day(3)
United States	289,902	(4)%	303,416	294,087	14%	258,733
Egypt(1)(2)	143,818	8%	133,215	141,443	5%	134,177
North Sea(4)	31,358	(15)%	36,778	31,487	(18)%	38,373
Total	465,078	(2)%	473,409	467,017	8%	431,283

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


	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2025	2024	2025	2024
Oil (b/d)	123,852	139,490	125,927	138,731
Natural Gas (Mcf/d)	479,235	431,750	468,157	444,499

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


	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2025	2024	2025	2024
Oil (b/d)	28,762	29,255	28,754	29,099
Natural Gas (Mcf/d)	115,319	91,094	110,596	93,954

(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 second quarters of 2025 and 2024 were 28,015 boe/d and 37,491 boe/d, respectively, and 32,336 boe/d and 36,285 boe/d for the first six months of 2025 and 2024, 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 June 30,					For the Six Months Ended June 30,
	2025		Increase (Decrease)	2024		2025		Increase (Decrease)	2024
Average Oil Price – Per barrel
United States	$	64.84	(19)%	$	80.54	$	68.64	(13)%	$	79.35
Egypt	66.39		(21)%	84.30		70.70		(16)%	83.75
North Sea	66.56		(21)%	84.62		71.61		(15)%	83.77
Total	65.58		(20)%	82.28		69.72		(15)%	81.57

Average Natural Gas Price – Per Mcf
United States	$	1.03	232%	$	0.31	$	1.54	86%	$	0.83
Egypt	3.48		19%	2.92		3.34		14%	2.93
North Sea	11.69		10%	10.61		13.42		35%	9.92
Total	2.28		29%	1.77		2.55		21%	2.11

Average NGL Price – Per barrel
United States	$	19.87	(6)%	$	21.22	$	23.91	4%	$	22.96

North Sea	41.62		(4)%	43.43		46.28		(1)%	46.66
Total	20.49		(5)%	21.68		24.54		4%	23.58

Second-Quarter 2025 compared to Second-Quarter 2024

Crude Oil Crude oil revenues for the second quarter of 2025 totaled $1.4 billion, a $526 million decrease from the comparative 2024 quarter. A 20 percent decrease in average realized prices decreased second-quarter 2025 oil revenues by $387 million compared to the second quarter of 2024, while a 7 percent lower average daily production decreased revenues by $139 million. Crude oil revenues accounted for 80 percent of total oil and gas production revenues and 51 percent of worldwide production in the second quarter of 2025. Crude oil prices realized in the second quarter of 2025 averaged $65.58 per barrel, compared with $82.28 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production decreased 18.4 Mb/d to 235.2 Mb/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of natural production decline in the U.S. and the North Sea and the sale of non-core assets in the U.S. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.

Natural Gas Natural gas revenues for the second quarter of 2025 totaled $184 million, a $49 million increase from the comparative 2024 quarter. A 29 percent increase in average realized prices increased second-quarter 2025 natural gas revenues by $38 million compared to the second quarter of 2024, while a 7 percent higher average daily production increased revenues by $11 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 32 percent of worldwide production during the second quarter of 2025.

The Company’s worldwide natural gas production increased 58.5 MMcf/d to 894.1 MMcf/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in Egypt and the Permian Basin. Natural gas production was also higher as a result of lower volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by natural production decline in the U.S. and North Sea, the sale of non-core assets, and operational downtime in the U.S.

NGL NGL revenues for the second quarter of 2025 totaled $153 million, a $6 million decrease from the comparative 2024 quarter. A 5 percent decrease in average realized prices decreased second-quarter 2025 NGL revenues by $9 million compared to the second quarter of 2024, partially offset by slightly higher average daily production, which increased revenues by $3 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production during the second quarter of 2025.

The Company’s worldwide NGL production increased 0.3 Mb/d to 80.8 Mb/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin and reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets and operational downtime in the U.S.

Year-to-Date 2025 compared to Year-to-Date 2024

Crude Oil Crude oil revenues for the first six months of 2025 totaled $3.0 billion, a $358 million decrease from the comparative 2024 period. A 15 percent decrease in average realized prices lowered oil revenues for the 2025 period by $485 million compared to the same prior-year period, while a 4 percent higher average daily production increased oil revenues by $127 million. Crude oil revenues accounted for 79 percent of total oil and gas production revenues and 51 percent of worldwide production for the first six months of 2025. Crude oil prices realized during the first six months of 2025 averaged $69.72 per barrel, compared to $81.57 per barrel in the comparative prior-year period.

The Company’s worldwide oil production increased 9.0 Mb/d to 235.9 Mb/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. and downtime recovery in the North Sea. These increases were offset by natural production decline across all assets and the sale of non-core assets in the U.S.

Natural Gas Natural gas revenues for the first six months of 2025 totaled $417 million, a $106 million increase from the comparative 2024 period. A 21 percent increase in average realized prices increased natural gas revenues for the 2025 period by $63 million compared to the same prior-year period, while 12 percent higher average daily production increased revenues by $43 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 32 percent of worldwide production for the first six months of 2025.

The Company’s worldwide natural gas production increased 97.6 MMcf/d to 909 MMcf/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S., and downtime recovery in the North Sea. Natural gas production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets, and operational downtime in the U.S.

NGL NGL revenues for the first six months of 2025 totaled $359 million, a $60 million increase from the comparative 2024 period. A 15 percent higher average daily production increased NGL revenues for the 2025 period by $48 million compared to the same prior-year period, while a 4 percent increase in average realized prices increased revenues by $12 million. NGL revenues accounted for 10 percent of total oil and gas production revenues and 17 percent of worldwide production for the first six months of 2025.

The Company’s worldwide NGL production increased 10.5 Mb/d to 79.7 Mb/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. NGL production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets in the U.S., and the cessation of new drilling in the North Sea.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to 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 purchased volumes totaled $460 million and $342 million during the second quarters of 2025 and 2024, respectively, and $1.1 billion and $545 million during the first six months of 2025 and 2024, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $304 million and $210 million during the second quarters of 2025 and 2024, respectively, and $778 million and $373 million, respectively, during the first six months of 2025 and 2024, respectively. Gross purchased oil and gas sales values were higher in the second quarter and the first six months of 2025, primarily driven by higher natural gas volume sales and higher gas prices, as well as 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 June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Lease operating expenses	$	367	$	460	$	774	$	798
Gathering, processing, and transmission	104		121		208		205
Purchased oil and gas costs	304		210		778		373
Taxes other than income	54		78		128		135
Exploration	43		71		73		219
General and administrative	66		85		164		178
Transaction, reorganization, and separation	11		115		48		142
Depreciation, depletion, and amortization:
Oil and gas property and equipment	523		582		1,159		1,001
Gathering, processing, and transmission assets	2		1		3		3
Other assets	5		5		11		14
Asset retirement obligation accretion	39		36		78		76

Financing costs, net	66		100		9		176
Total Operating Expenses	$	1,584	$	1,864	$	3,433	$	3,320

Lease Operating Expenses (LOE)

LOE decreased $93 million and $24 million from the second quarter and the first six months of 2024, respectively. On a per-unit basis, LOE decreased 18 percent and 11 percent in the second quarter and the first six months of 2025, respectively, when compared to the second quarter and the first six months of 2024. The decrease in absolute costs was primarily driven by overall lower operating costs and lower workover activity coupled with the sale of non-core assets in the Permian Basin, compared to the same prior-year periods. The decrease in absolute costs for the first six months of 2025 was partially offset by activity related to the Callon transaction.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Third-party processing and transmission costs	$	104	$	121	$	208	$	182
Midstream service costs – Kinetik	—		—		—		23
Total Gathering, processing, and transmission	$	104	$	121	$	208	$	205

GPT costs decreased $17 million and increased $3 million from the second quarter and the first six months of 2024, respectively. The decrease in third-party costs for the second quarter of 2025 was primarily driven by decreased oil production volumes in the U.S. and decreased natural gas and NGL production volumes in the North Sea compared to the same prior-year period. The increase in third-party costs for the first six months of 2025 was driven by an increase in oil, natural gas, and NGL production volumes in the U.S. compared to the same prior-year period, primarily related to the Callon acquisition.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $94 million and $405 million from the second quarter and the first six months of 2024, respectively. The increase in the second quarter and the first six months of 2025 was primarily driven by increased oil volume purchases and gas volumes purchased at a higher rate coupled with activity associated with the Callon acquisition, compared to the same prior-year periods. 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 in the second quarter and first six months of 2025, as discussed above.

Taxes Other Than Income

Taxes other than income decreased $24 million and $7 million from the second quarter and the first six months of 2024, respectively, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes.

Exploration Expenses

The Company’s exploration expenses were as follows:


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Unproved leasehold impairments	$	—	$	—	$	—	$	10
Dry hole expense	32		41		43		164
Geological and geophysical expense	—		15		4		16
Exploration overhead and other	11		15		26		29
Total Exploration	$	43	$	71	$	73	$	219

Exploration expenses decreased $28 million and $146 million from the second quarter and the first six months of 2024, respectively. The decrease in expenses for the second quarter of 2025 was primarily driven by higher dry hole and seismic expenses in Alaska in the prior-year period. These decreases were partially offset by increased dry hole expenses in Egypt. The decrease in expenses for the first six months of 2025 was primarily driven by higher dry hole expenses in Alaska and Suriname in the prior-year period.

General and Administrative (G&A) Expenses

G&A expenses decreased $19 million and $14 million from the second quarter and the first six months of 2024, respectively. The decreases in expenses compared with the comparative prior-year periods were primarily driven by the impacts of focused cost-reduction efforts on personnel and other overhead expenses. The decreases in expense for the first six months of 2025 were partially offset by higher cash-based stock compensation expense resulting from changes in expected payouts for the Company’s performance programs and the Company’s stock price.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $104 million and $94 million from the second quarter and the first six months of 2024, respectively. TRS costs for 2025 were primarily associated with employee separations and other cost-saving initiatives, while TRS costs for 2024 comprised primarily expenses associated with the Callon merger.

Depreciation, Depletion, and Amortization (DD&A)

Total DD&A expenses decreased $58 million and increased $155 million from the second quarter and the first six months of 2024, respectively. The Company’s DD&A rate on its oil and gas properties decreased $1.05 per boe and increased $0.86 per boe from the second quarter and the first six months of 2024, respectively. The decrease in DD&A absolute expenses and on a per boe basis for the second quarter of 2025 was primarily driven by lower DD&A rates resulting from the sale of non-core assets in the Permian Basin. For the first six months of 2025, the Company’s higher DD&A rate on its oil and gas properties on a per boe basis was driven by year-end 2024 negative gas price-related reserve revisions in the U.S. Permian Basin coupled with higher DD&A rates resulting from the Callon acquisition. Higher absolute dollar amounts of DD&A for the first six months of 2025 was directly impacted by these higher rates.

Financing Costs, Net

The Company’s Financing costs were as follows:


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(In millions)
Interest expense	$	86	$	108	$	177	$	193
Amortization of debt issuance costs	2		2		4		3
Capitalized interest	(16)		(7)		(20)		(14)
Gain on extinguishment of debt	(3)		—		(145)		—
Interest income	(3)		(3)		(7)		(6)
Total Financing costs, net	$	66	$	100	$	9	$	176

Net financing costs decreased $34 million and $167 million from the second quarter and the first six months of 2024, respectively. The lower overall interest expense was primarily a result of lower outstanding credit facility borrowings compared to the prior-year periods. The decrease in total financing costs, net during the first six months of 2025 was further driven by gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025.

Provision for Income Taxes

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, the Company will record the impact of OBBBA in the third quarter of 2025.

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. The Company expects commodity prices to continue to be volatile in the near term as a result of macroeconomic uncertainty, current and potential tariffs or trade barriers, supply chain disruptions, and concerns over a potential economic recession. 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.

At this time, the Company is unable to predict to what extent recent and potential changes in trade restrictions and tariffs will impact its business. If inflationary pressures from these and other economic conditions persist or worsen, the Company may incur additional operating costs. The Company will continue to monitor the impact and consequences of these factors on its operations.

The Company expects its full-year 2025 estimated upstream capital investment to be approximately $2.3 billion to $2.4 billion. During the second quarter of 2025, the Company initiated its plans to reduce Permian rig count from eight to six, reflecting a sustained step-change in drilling efficiencies. In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company now expects one-third of its activities to be gas-focused. This activity set equates to a combined development capital budget for the Permian Basin, Egypt, and North Sea of approximately $2.0 billion. In addition, the Company will invest approximately $275 million for Suriname development and $65 million for other exploration activities. APA 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, 2024.

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 Six Months Ended June 30,
	2025		2024

	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,277	$	1,245
Fixed-rate debt borrowings	846		—
Proceeds from commercial paper and revolving credit facilities, net	—		63
Proceeds from term loan facility	—		1,500
Proceeds from asset divestitures	571		729
Proceeds from sale of Kinetik Shares	—		428

Total Sources of Cash and Cash Equivalents	3,694		3,965
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	1,437	$	1,245

Leasehold and property acquisitions	20		63
Payments on commercial paper and revolving credit facilities, net	333		—
Payments on term loan facility	900		—
Payment on Callon Credit Agreement	—		472
Payments on fixed-rate debt	954		1,641
Dividends paid to APA common stockholders	181		168
Distributions to noncontrolling interest	217		123

Treasury stock activity, net	150		144
Other, net	20		36
Total Uses of Cash and Cash Equivalents	4,212		3,892
Increase (Decrease) in Cash and Cash Equivalents	$	(518)	$	73

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 six months of 2025 totaled $2.3 billion, $1.1 billion higher from the first six months of 2024, primarily due to 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.

Fixed-Rate Debt Borrowings During the first six months of 2025, the Company issued new notes for proceeds of $846 million, after deducting discounts and loan costs, to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.

Proceeds from Asset Divestitures The Company received $571 million and $729 million in proceeds from the divestitures of certain non-core assets during the first six months of 2025 and 2024, 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.

Uses of Cash and Cash Equivalents

Additions to Oil & Gas Property During the first six months of 2025 and 2024, exploration and development cash expenditures were $1.4 billion and $1.2 billion, respectively. The increase in capital investment compared to the prior-year period is reflective of the properties acquired from the Callon acquisition, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s decision to eliminate drilling activity in the North Sea and the sale of certain non-core assets and leasehold in the Permian Basin. The Company operated an average of approximately 21 drilling rigs during the first six months of 2025, compared to an average of approximately 25 drilling rigs during the first six months of 2024.

Leasehold and Property Acquisitions During the first six months of 2025 and 2024, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $20 million and $63 million, respectively.

Payments on Commercial Paper and Revolving Credit Facilities, Net During the first six months of 2025, the Company made net payments of $333 million on its commercial paper and U.S. dollar denominated syndicated credit facility borrowings. As of June 30, 2025, there were no outstanding borrowings under each of the Company’s commercial paper and U.S. dollar denominated syndicated credit facility.

Payments on Term Loan Facility During the first six months of 2025, the Company made a payment of $900 million on its syndicated term loan credit agreement and fully repaid the term loans. For additional details of this credit agreement, see “Unsecured Committed Term Loan Facility” in the Liquidity section below.

Payments on Fixed-Rate Debt During the first six months of 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures of Apache and made open market repurchases for an aggregate cash payment amount of $954 million, reflecting principal amounts, discount to par, and associated fees.

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

Dividends Paid to APA Common Stockholders During the first six months of 2025 and 2024, the Company paid $181 million and $168 million, 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. During the first six months of 2025 and 2024, the Company paid $217 million and $123 million, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first six months of 2025, the Company repurchased 7.1 million shares at an average price of $21.21 per share and an aggregate purchase price of approximately $150 million, and as of June 30, 2025, the Company had remaining authorization to repurchase 27.7 million shares. In the first six months of 2024, the Company repurchased 4.5 million shares at an average price of $31.77 per share and an aggregate purchase price of approximately $144 million.

Liquidity

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


	June 30, 2025		December 31, 2024

	(In millions)
Cash and cash equivalents	$	107	$	625
Total debt – APA and Apache	4,551		6,044
Total equity	6,903		6,362
Available committed borrowing capacity under syndicated credit facilities	3,808		2,966

Cash and Cash Equivalents As of June 30, 2025, the Company had $107 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 June 30, 2025, the Company had $4.6 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache, credit facility and/or commercial paper borrowings, and finance lease obligations. As of June 30, 2025, current debt included $2 million of finance lease obligations and $261 million of APA and Apache notes coming due within the next year.

Indenture Debt Activity During the first six months of 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $108 million for an aggregate purchase price of $100 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $10 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025.

APA Exchange and Tender Offers for Apache Indenture Debt On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA’s cash tender offers. In settling these offerings pursuant to their respective terms:

•In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration.

Unsecured 2025 Committed Credit Facilities On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:

The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022:

On January 15, 2025, the Company terminated commitments under both the 2022 USD Agreement and 2022 GBP Agreement in connection with entry into the 2025 Agreements.

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 June 30, 2025 and December 31, 2024, there were no outstanding borrowings under these facilities. As of June 30, 2025, there were £705 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2024, there were £640 million and $11 million in letters of credit outstanding under these facilities.

Commercial Paper Program The Company has 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 $2.0 billion outstanding at any time. The program was established in December 2023, and the maximum aggregate face amount of CP Notes issuable thereunder was increased to $2.0 billion from $1.8 billion on June 20, 2025. 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 revolving credit facilities for general corporate purposes, which as of June 30, 2025, included the $2.0 billion 2025 USD Agreement.

The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.

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 upon closings of APA’s acquisition of Callon and the 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).

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, 2024. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

As of June 30, 2025, the Company recorded an asset of $39 million, representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.

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, natural 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 ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, actions taken by foreign oil and gas producing nations, including OPEC+, and other current events.

The Company’s average crude oil price realizations decreased 20 percent from $82.28 per barrel to $65.58 per barrel during the second quarters of 2024 and 2025, respectively. The Company’s average natural gas price realizations increased 29 percent from $1.77 per Mcf to $2.28 per Mcf during the second quarters of 2024 and 2025, respectively. The Company’s average NGL price realizations decreased 5 percent from $21.68 per barrel to $20.49 per barrel during the second quarters of 2024 and 2025, respectively. Based on average daily production for the second quarter of 2025, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $21 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $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 June 30, 2025, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $110 million. A 10 percent increase in natural gas prices would increase the receivable by approximately $8 million, while a 10 percent decrease in prices would decrease the receivable by approximately $8 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2025. 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 June 30, 2025, the Company had $4.6 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.64 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 June 30, 2025, the Company had approximately $107 million in cash and cash equivalents, approximately 79 percent of which was invested in money market funds and short-term investments with major financial institutions. As of June 30, 2025, there were no 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 $2 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 30, 2025.

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 Ben C. Rodgers, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of June 30, 2025, 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

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2025 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, 2024 and Note 10—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, 2024.

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 June 30, 2025:


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)



April 1 to April 30, 2025	603,233	16.59		603,233	29,779,317
May 1 to May 31, 2025	—	—		—	29,779,317
June 1 to June 30, 2025	2,096,211	19.09		2,096,211	27,683,106
Total	2,699,444	$	18.53

(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

As previously reported, on April 1, 2024, APA completed its acquisition of Callon pursuant to the Agreement and Plan of Merger, dated January 3, 2024, by and among APA, Astro Comet Merger Sub Corp., a Delaware corporation and wholly owned subsidiary of APA (“Merger Sub”), and Callon. At the closing, Merger Sub merged with and into Callon, with Callon as the surviving entity (the “Merger”). APA is including in Exhibit 99.1 hereto additional pro forma financial information required by Rule 3-05 and Article 11 of Regulation S-X in connection with APA’s offering of securities in transactions registered under the Securities Act of 1933, as amended, or exempt from registration thereunder. The pro forma financial information included in Exhibit 99.1 hereto has been presented for informational purposes only, as required by Article 11 of Regulation S-X. It does not purport to represent the actual results of operations that APA and Callon would have achieved had the companies been combined during the periods presented in the pro forma financial information and is not intended to project the future results of operations that the combined company may achieve after completion of the Merger.

During the quarter ended June 30, 2025, 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 terms are 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.

*99.1

Unaudited pro forma combined statement of operations of APA Corporation for the 12 months ended December 31, 2024 giving effect to the Merger as if it had been completed on January 1, 2023, and the related notes.

*101

The following financial statements from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income, (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity 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:	August 7, 2025	/s/ BEN C. RODGERS
		Ben C. Rodgers
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	August 7, 2025	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)