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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
FORM 10-Q 
(Mark One)  
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2024
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission File Number: 1-40144
APA CORPORATION
(Exact name of registrant as specified in its charter)
Delaware86-1430562
(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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.625 par valueAPANasdaq Global Select Market
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☒Accelerated filer☐
Non-accelerated filer☐ Smaller reporting company☐
Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Number of shares of registrant’s common stock outstanding as of October 31, 2024
369,947,453 



TABLE OF CONTENTS



FORWARD-LOOKING STATEMENTS AND RISKS
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, plans and objectives of management for future operations and capital returns framework, the anticipated benefits of the merger (the Callon acquisition) between the Company and Callon Petroleum Company (Callon), the anticipated impact of the Callon acquisition on the combined company’s business and future financial and operating results, and the anticipated financial and operational impact and timing of the expected synergies from the Callon acquisition, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2023, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:
•changes in local, regional, national, and international economic conditions, including as a result of any epidemics or pandemics;
•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;
•the Company’s commodity hedging arrangements;
•the supply and demand for oil, natural gas, NGLs, and other products or services;
•production and reserve levels;
•drilling risks;
•economic and competitive conditions, including market and macro-economic disruptions resulting from the Russian war in Ukraine, the armed conflict in Israel and Gaza, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);
•the availability of capital resources;
•capital expenditures and other contractual obligations;
•currency exchange rates;
•weather conditions;
•inflation rates;
•the impact of changes in tax legislation;
•the availability of goods and services;
•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
•legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
•the Company’s performance on environmental, social, and governance measures;
•cyberattacks and terrorism;
•the Company’s ability to access the capital markets;
•market-related risks, such as general credit, liquidity, and interest-rate risks;
•the ability to retain and hire key personnel;
•property acquisitions or divestitures;


•the integration of acquisitions, including the diversion of management time on integration-related issues for the Callon acquisition and the risk that the Company may not integrate Callon’s operations in a successful manner or in the expected time period;
•the risk that the anticipated benefits, cost savings, synergies, and growth from the Callon acquisition may not be fully realized or may take longer to realize than expected;
•negative effects of the Callon acquisition on the Company’s business relationships and business generally, the market price of the Company’s common stock, and/or the Company’s operating results;
•other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023;
•other risks and uncertainties disclosed in the Company’s third-quarter 2024 earnings release;
•other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q; and
•other factors disclosed in the other filings that the Company makes with the Securities and Exchange Commission.
Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.


DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:
“b/d” means barrels of oil or NGLs per day.
“bbl” or “bbls” means barrel or barrels of oil or NGLs.
“bcf” means billion cubic feet of natural gas.
“bcf/d” means one bcf per day.
“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.
“boe/d” means boe per day.
“Btu” means a British thermal unit, a measure of heating value.
“liquids” means oil and NGLs.
“LNG” means liquefied natural gas.
“Mb/d” means Mbbls per day.
“Mbbls” means thousand barrels of oil or NGLs.
“Mboe” means thousand boe.
“Mboe/d” means Mboe per day.
“Mcf” means thousand cubic feet of natural gas.
“Mcf/d” means Mcf per day.
“MMbbls” means million barrels of oil or NGLs.
“MMboe” means million boe.
“MMBtu” means million Btu.
“MMBtu/d” means MMBtu per day.
“MMcf” means million cubic feet of natural gas.
“MMcf/d” means MMcf per day.
“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.
“NYMEX” means New York Mercantile Exchange.
“oil” includes crude oil and condensate.
“PUD” means proved undeveloped.
“SEC” means the United States Securities and Exchange Commission.
“Tcf” means trillion cubic feet of natural gas.
“U.K.” means United Kingdom.
“U.S.” means United States.
With respect to information relating to the Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.
References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.


PART I – FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
 (In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)
$2,058 $2,079 $6,007 $5,500 
Purchased oil and gas sales(1)
473 229 1,018 612 
Total revenues2,531 2,308 7,025 6,112 
Derivative instrument gains (losses), net(10)— (17)104 
Gain on divestitures, net1 1 284 7 
Loss on previously sold Gulf of Mexico properties— — (83)— 
Other, net18 — 26 77 
2,540 2,309 7,235 6,300 
OPERATING EXPENSES:
Lease operating expenses(1)
418 394 1,216 1,076 
Gathering, processing, and transmission(1)
123 89 328 245 
Purchased oil and gas costs(1)
292 211 665 558 
Taxes other than income70 61 205 163 
Exploration29 49 248 144 
General and administrative92 139 270 276 
Transaction, reorganization, and separation14 5 156 11 
Depreciation, depletion, and amortization595 418 1,613 1,117 
Asset retirement obligation accretion36 29 112 86 
Impairments1,111 — 1,111 46 
Financing costs, net100 81 276 235 
2,880 1,476 6,200 3,957 
NET INCOME (LOSS) BEFORE INCOME TAXES(340)833 1,035 2,343 
Current income tax provision260 422 845 1,022 
Deferred income tax benefit
(461)(144)(503)(22)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS(139)555 693 1,343 
Net income attributable to noncontrolling interest
84 96 243 261 
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK$(223)$459 $450 $1,082 
NET INCOME (LOSS) PER COMMON SHARE:
Basic$(0.60)$1.49 $1.30 $3.50 
Diluted$(0.60)$1.49 $1.29 $3.50 
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic370 308 348 309 
Diluted370 308 348 309 
(1)    For transactions with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests.
The accompanying notes to consolidated financial statements are an integral part of this statement.
1

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS
$(139)$555 $693 $1,343 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan— — (1)3 
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS
(139)555 692 1,346 
Comprehensive income attributable to noncontrolling interest
84 96 243 261 
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
$(223)$459 $449 $1,085 

The accompanying notes to consolidated financial statements are an integral part of this statement.
2

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
For the Nine Months Ended
September 30,
  20242023
 (In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests$693 $1,343 
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net18 (61)
Gain on divestitures, net(284)(7)
Exploratory dry hole expense and unproved leasehold impairments183 91 
Depreciation, depletion, and amortization1,613 1,117 
Asset retirement obligation accretion112 86 
Impairments1,111 46 
Benefit from deferred income taxes
(503)(22)
Gain on extinguishment of debt
— (9)
Loss on previously sold Gulf of Mexico properties83 — 
Other, net(14)(45)
Changes in operating assets and liabilities:
Receivables181 (289)
Inventories(26)19 
Drilling advances and other current assets37 40 
Deferred charges and other long-term assets(215)227 
Accounts payable(191)(2)
Accrued expenses(271)1 
Deferred credits and noncurrent liabilities57 (436)
NET CASH PROVIDED BY OPERATING ACTIVITIES2,584 2,099 
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property(2,153)(1,747)
Leasehold and property acquisitions(64)(11)
Proceeds from asset divestitures724 29 
Proceeds from sale of Kinetik Shares
428 — 
Other, net58 (53)
NET CASH USED IN INVESTING ACTIVITIES(1,007)(1,782)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from commercial paper and revolving credit facilities, net
190 202 
Proceeds from term loan facility
1,500 — 
Payments on term loan facility
(500)— 
Payment on Callon Credit Agreement
(472)— 
Payments on fixed-rate debt
(1,641)(65)
Distributions to noncontrolling interest
(233)(154)
Treasury stock activity, net(146)(208)
Dividends paid to APA common stockholders(260)(232)
Other, net(38)(10)
NET CASH USED IN FINANCING ACTIVITIES(1,600)(467)
NET DECREASE IN CASH AND CASH EQUIVALENTS(23)(150)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR87 245 
CASH AND CASH EQUIVALENTS AT END OF PERIOD$64 $95 
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest$306 $278 
Income taxes paid, net of refunds876 867 
The accompanying notes to consolidated financial statements are an integral part of this statement.
3

APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
September 30,
2024
December 31,
2023
(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents$64 $87 
Receivables, net of allowance of $120 and $114
1,652 1,610 
Assets held for sale
1,091 — 
Other current assets (Note 5)
813 765 
3,620 2,462 
PROPERTY AND EQUIPMENT:
Oil and gas properties44,026 44,860 
Gathering, processing, and transmission facilities446 448 
Other557 634 
Less: Accumulated depreciation, depletion, and amortization(32,428)(35,904)
12,601 10,038 
OTHER ASSETS:
Equity method interests (Note 6)
— 437 
Decommissioning security for sold Gulf of Mexico properties (Note 11)
21 21 
Deferred tax asset (Note 10)
2,550 1,758 
Deferred charges and other584 528 
$19,376 $15,244 
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
CURRENT LIABILITIES:
Accounts payable$939 $658 
Current debt2 2 
Liabilities held for sale
224 — 
Other current liabilities (Note 7)
1,760 1,744 
2,925 2,404 
LONG-TERM DEBT (Note 9)
6,370 5,186 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 10)
86 371 
Asset retirement obligation (Note 8)
2,502 2,362 
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)
759 764 
Other574 466 
3,921 3,963 
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 491,531,484 and 420,595,901 shares issued, respectively
307 263 
Paid-in capital13,239 11,126 
Accumulated deficit(2,509)(2,959)
Treasury stock, at cost, 121,613,494 and 117,020,000 shares, respectively
(5,937)(5,790)
Accumulated other comprehensive income14 15 
APA SHAREHOLDERS’ EQUITY5,114 2,655 
Noncontrolling interest
1,046 1,036 
TOTAL EQUITY6,160 3,691 
$19,376 $15,244 


The accompanying notes to consolidated financial statements are an integral part of this statement.
4

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS
(Unaudited)
Common
Stock		Paid-In
Capital		Accumulated DeficitTreasury
Stock		Accumulated
Other
Comprehensive
Income
APA SHAREHOLDERS’
EQUITY
Noncontrolling
Interest
TOTAL
EQUITY
(In millions)
For the Quarter Ended September 30, 2023
Balance at June 30, 2023
$263 $11,267 $(5,191)$(5,647)$17 $709 $987 $1,696 
Net income attributable to common stock— — 459 — — 459 — 459 
Net income attributable to noncontrolling interest
— — — — — — 96 96 
Distributions to noncontrolling interest
— — — — — — (54)(54)
Common dividends declared ($0.25 per share)
— (77)— — — (77)— (77)
Treasury stock activity, net— — — (20)— (20)— (20)
Other— 7 — — — 7 — 7 
Balance at September 30, 2023
$263 $11,197 $(4,732)$(5,667)$17 $1,078 $1,029 $2,107 
For the Quarter Ended September 30, 2024
Balance at June 30, 2024
$307 $13,322 $(2,286)$(5,934)$14 $5,423 $1,072 $6,495 
Net loss attributable to common stock
— — (223)— — (223)— (223)
Net income attributable to noncontrolling interest
— — — — — — 84 84 
Distributions to noncontrolling interest
— — — — — — (110)(110)
Common dividends declared ($0.25 per share)
— (92)— — — (92)— (92)
Treasury stock activity, net— — — (3)— (3)— (3)
Other— 9 — — — 9 — 9 
Balance at September 30, 2024
$307 $13,239 $(2,509)$(5,937)$14 $5,114 $1,046 $6,160 


The accompanying notes to consolidated financial statements are an integral part of this statement.
5

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS - Continued
(Unaudited)
Common
Stock		Paid-In
Capital		Accumulated DeficitTreasury
Stock		Accumulated
Other
Comprehensive
Income
APA
SHAREHOLDERS’
EQUITY
Noncontrolling
Interest
TOTAL EQUITY
(In millions)
For the Nine Months Ended September 30, 2023
Balance at December 31, 2022
$262 $11,420 $(5,814)$(5,459)$14 $423 $922 $1,345 
Net income attributable to common stock— — 1,082 — — 1,082 — 1,082 
Net income attributable to noncontrolling interest – Egypt— — — — — — 261 261 
Distributions to noncontrolling interest – Egypt— — — — — — (154)(154)
Common dividends declared ($0.75 per share)
— (232)— — — (232)— (232)
Treasury stock activity, net— — — (208)— (208)— (208)
Other1 9 — — 3 13 — 13 
Balance at September 30, 2023
$263 $11,197 $(4,732)$(5,667)$17 $1,078 $1,029 $2,107 
For the Nine Months Ended September 30, 2024
Balance at December 31, 2023
$263 $11,126 $(2,959)$(5,790)$15 $2,655 $1,036 $3,691 
Net income attributable to common stock— — 450 — — 450 — 450 
Net income attributable to noncontrolling interest – Egypt— — — — — — 243 243 
Distributions to noncontrolling interest – Egypt— — — — — — (233)(233)
Common dividends declared ($0.75 per share)
— (260)— — — (260)— (260)
Issuance of common stock
44 2,370 — — — 2,414 — 2,414 
Treasury stock activity, net— — — (147)— (147)— (147)
Other— 3 — — (1)2 — 2 
Balance at September 30, 2024
$307 $13,239 $(2,509)$(5,937)$14 $5,114 $1,046 $6,160 


The accompanying notes to consolidated financial statements are an integral part of this statement.
6

APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, which contains a summary of the Company’s significant accounting policies and other disclosures.
1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2024, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. During the nine months ended September 30, 2023 and the quarter ended March 31, 2024, the Company had a designated director on the Kinetik Holdings Inc. (Kinetik) board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors.
As of December 31, 2023, the Company held shares of Kinetik Class A Common Stock (Kinetik Shares), which were recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. On March 18, 2024, the Company sold its remaining Kinetik Shares. Refer to Note 6—Equity Method Interests for further detail.

7

Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Refer to Note 4—Derivative Instruments and Hedging Activities, Note 6—Equity Method Interests, and Note 9—Debt and Financing Costs for further detail regarding the Company’s fair value measurements recorded on a recurring basis.
The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment.
During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. As a result, the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea as of September 30, 2024. Accordingly, in the third quarter of 2024, the Company recognized impairments of $793 million on certain proved properties in the North Sea, which were written down to their estimated fair values. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.”
Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail.

8

During the three and nine months ended September 30, 2023, the Company recorded no asset impairments in connection with fair value assessments.
Revenue Recognition
Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.5 billion at each of September 30, 2024 and December 31, 2023. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout the period, and management believes that the Company will be able to collect the total balance of its receivables from this customer.
Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. The Company recorded impairments to inventory of $3 million in the third quarter and the nine months ended September 30, 2024 and $46 million in the nine months ended September 30, 2023.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, production costs, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities, and if management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties.
9

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $793 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million.
Additionally, in the third quarter of 2024, the Company recorded impairments totaling $315 million in connection with an agreement to sell certain non-core producing properties in the Permian Basin. These impairments are discussed in further detail above in “Fair Value Measurements” and in Note 2—Acquisitions and Divestitures. The associated U.S. properties had an aggregate fair value of $1.1 billion as of September 30, 2024.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.
Gathering, Processing, and Transmission (GPT) Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
Transaction, Reorganization, and Separation (TRS)
The Company recorded $14 million and $156 million of TRS costs during the third quarter and the first nine months of 2024, respectively, and $5 million and $11 million of TRS costs during the third quarter and the first nine months of 2023, respectively. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.
New Pronouncements Issued But Not Yet Adopted
In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.
10

2.    ACQUISITIONS AND DIVESTITURES
2024 Activity
Sale of Non-core Properties in the Permian Basin
On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for cash proceeds of $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024. The Company received a deposit of $95 million in connection with the sale during the third quarter of 2024.
As a result of the agreement, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $315 million to the carrying value of associated oil and gas properties. These assets met the criteria of held for sale classification as of September 30, 2024. U.S. oil and gas properties totaling $1.1 billion and the associated asset retirement obligation of $224 million were classified as current assets held for sale and current liabilities held for sale, respectively, as of September 30, 2024.
Callon Petroleum Company Acquisition
On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024. The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin.

Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction based on the value of APA common stock on the day of closing, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE. In addition to the equity consideration provided, APA transferred approximately $24 million in other consideration upon close of the transaction.
Upon completing the acquisition, APA repaid all of Callon’s debt, refinancing a portion by borrowing $1.5 billion under its unsecured committed term loan facility. Refer to Note 9—Debt and Financing Costs for further detail.
Recording of Assets Acquired and Liabilities Assumed
The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.
The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the merger:
(In millions)
Current assets
$282 
Property, plant, and equipment
4,493 
Deferred tax asset
575 
Other assets11 
Total assets acquired$5,361 
Current liabilities$616 
Long-term debt
2,113 
Asset retirement obligation136 
Other long-term obligations58 
Total liabilities assumed$2,923 
Net assets acquired$2,438 
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The following unaudited pro forma combined results for the three and nine months ended September 30, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, interest expense, gain on derivatives related to a previous Callon acquisition, and estimated tax impacts of the pro forma adjustments.
For the Quarter Ended
September 30,		For the Nine Months Ended
September 30,
2024202320242023
(In millions, except share data)
Revenues
$2,531 $2,927 $7,589 $7,810 
Net income (loss) attributable to common stock
(223)737 556 1,527 
Net income (loss) per common share – basic
(0.60)1.95 1.50 4.04 
Net income (loss) per common share – diluted
(0.60)1.95 1.50 4.04 
From the date of the acquisition through September 30, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $840 million and $192 million, respectively.
The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated. The unaudited pro forma results are also not intended to be a projection of future results and do not include any future cost savings or other synergies that may result from the Callon acquisition or any estimated costs that have not yet been incurred.
U.S. Divestitures
In the first nine months of 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $253 million and the assumption of asset retirement obligations of $48 million. The Company recognized a $46 million loss during the first nine months of 2024 in association with this sale.
In the first nine months of 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $392 million after post-closing adjustments. The Company recognized a gain of $321 million during the first nine months of 2024 in association with this sale.
Additionally, during the third quarter and first nine months of 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $73 million, respectively, recognizing a gain of approximately $1 million and $9 million, respectively, upon closing of these transactions.
Sale of Kinetik Shares
On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. Refer to Note 6—Equity Method Interests for further detail.
Leasehold and Property Acquisitions
During the third quarter and the first nine months of 2024, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $64 million, respectively.
2023 Activity
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $11 million, respectively.
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U.S. Divestitures
During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions.
3.    CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $611 million and $586 million as of September 30, 2024 and December 31, 2023, respectively. The increase is primarily attributable to additional drilling activity in Egypt and in the U.S. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense during the third quarter of 2024. During the first nine months of 2024, approximately $51 million of suspended well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.
4.    DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values. The Company has elected not to designate any of its derivative contracts as cash flow hedges.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2024, the Company had derivative positions with one counterparty. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.
Derivative Instruments
Commodity Derivative Instruments
As of September 30, 2024, the Company had the following open natural gas financial collar contracts:
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Floor PriceWeighted Average Ceiling Price
October—December 2024
NYMEX Henry Hub
1,654$3.00$3.33
As of September 30, 2024, the Company had the following open natural gas financial basis swap contracts:
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Price DifferentialMMBtu
(in 000’s)		Weighted Average Price Differential
October—December 2024
NYMEX Henry Hub/IF Waha——1,840$(1.06)
October—December 2024
NYMEX Henry Hub/IF HSC——3,680$(0.42)
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As of September 30, 2024, the Company had the following open NGL fixed swap contracts:
Production PeriodSettlement Index
MBbls
(in 000’s)
Weighted Average Price Differential
October—December 2024
OPIS IsoButane Mt Belvieu Non TET
6$33.18
October—December 2024
OPIS NButane Mt Belvieu Non TET
17$33.18
Embedded Derivatives
As a result of the Callon acquisition, the Company assumed an earn-out obligation from Callon, where the Company could be required to pay up to $50 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for the 2024 and 2025 calendar years. Additionally, in connection with the Callon acquisition, the Company assumed a contingent consideration arrangement, whereby the Company could receive up to $45 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20 million.
The Company determined that the earn-out obligation and contingent consideration receipt were not clearly and closely related to the underlying agreements and therefore bifurcated these embedded features and recorded these derivatives at fair value. For further discussion of these derivatives, refer to “Fair Value Measurements” below.
Fair Value Measurements
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)		Significant Other Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
September 30, 2024
Assets:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 10 — 10 — 10 
Liabilities:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 39 — 39 — 39 
December 31, 2023
Assets:
Commodity derivative instruments$— $6 $— $6 $— $6 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
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The embedded options within the earn-out obligation and contingent consideration arrangements discussed above are considered financial instruments under ASC 815. The Company uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing an option pricing model method provided by a reputable third party. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered a Level 2 fair value measurement. As of September 30, 2024, the estimated fair values of the earn-out obligation and contingent consideration receipt were $39 million and $10 million, respectively.
Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
September 30,
2024
December 31,
2023
(In millions)
Current Assets: Other current assets$10 $6 
Total derivative assets$10 $6 
Current Liabilities: Other current liabilities$25 $— 
Deferred Credit and Other Noncurrent Liabilities: Other
14 — 
Total derivative liabilities$39 $— 
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
 (In millions)
Realized:
Commodity derivative instruments$3 $19 $1 $43 
Realized gains, net
3 19 1 43 
Unrealized:
Commodity derivative instruments(1)(19)(6)61 
Contingent consideration arrangements(12)— (12)— 
Unrealized gains (losses), net(13)(19)(18)61 
Derivative instrument gains (losses), net$(10)$— $(17)$104 
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
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5.    OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets:
September 30,
2024
December 31,
2023
 (In millions)
Inventories$501 $453 
Drilling advances60 88 
Current decommissioning security for sold Gulf of Mexico assets167 178 
Prepaid assets and other85 46 
Total Other current assets$813 $765 
6.    EQUITY METHOD INTERESTS
As of December 31, 2023, the Company held 13.1 million Kinetik Shares, which were recorded at fair value of $437 million and reflected separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik was determined using observable share prices on a major exchange, a Level 1 fair value measurement. On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million.
Prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $9 million in the first quarter of 2024, and a loss of $14 million and a gain of $57 million in the third quarter and the first nine months of 2023, respectively. These changes in fair value were recorded as a component of “Revenues and Other” in the Company’s statement of consolidated operations.
The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
(In millions)
Natural gas and NGLs sales$— $35 $13 $78 
Purchased oil and gas sales— 11 22 18 
$— $46 $35 $96 
Gathering, processing, and transmission costs$— $26 $23 $81 
Purchased oil and gas costs— 37 23 65 
Lease operating expenses— — 2 — 
$— $63 $48 $146 
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7.    OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities:
September 30,
2024
December 31,
2023
 (In millions)
Accrued operating expenses$254 $162 
Accrued exploration and development543 371 
Accrued compensation and benefits189 390 
Accrued interest66 93 
Accrued income taxes144 138 
Current asset retirement obligation75 76 
Current operating lease liability98 116 
Current decommissioning contingency for sold Gulf of Mexico properties94 60 
Other297 338 
Total Other current liabilities$1,760 $1,744 
8.    ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
September 30,
2024
 (In millions)
Asset retirement obligation, December 31, 2023
$2,438 
Liabilities incurred11 
Liabilities acquired140 
Liabilities settled(47)
Liabilities divested(48)
Liabilities held for sale(224)
Accretion expense112 
Revisions in estimated liabilities195 
Asset retirement obligation, September 30, 2024
2,577 
Less current portion(75)
Asset retirement obligation, long-term$2,502 
9.    DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
September 30,
2024
December 31,
2023
(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)
$4,835 $4,835 
Term loan facility, commercial paper, and syndicated credit facilities(2)
1,562 372 
Apache finance lease obligations30 32 
Unamortized discount(25)(26)
Debt issuance costs(30)(25)
Total debt6,372 5,188 
Current maturities(2)(2)
Long-term debt$6,370 $5,186 
(1)    The fair values of the Apache notes and debentures were $4.5 billion and $4.3 billion as of September 30, 2024 and December 31, 2023, respectively.
The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2)    The carrying value of borrowings on the term loan facility, commercial paper and credit facilities approximates fair value because interest rates are variable and reflective of market rates.
At each of September 30, 2024 and December 31, 2023, current debt included $2 million of finance lease obligations.
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Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
Interest expense$109 $89 $302 $266 
Amortization of debt issuance costs1 1 4 3 
Capitalized interest(8)(7)(22)(18)
Gain on extinguishment of debt
— — — (9)
Interest income(2)(2)(8)(7)
Financing costs, net$100 $81 $276 $235 
During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash. The Company recognized a $9 million gain on these repurchases.
Unsecured 2022 Committed Credit Facilities
On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.
•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each of the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.
As of September 30, 2024, there were $232 million of borrowings under the USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement.
Uncommitted Lines of Credit
Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million, respectively, in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million, respectively, in letters of credit outstanding under these facilities.
Commercial Paper Program
In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.
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Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
Unsecured Committed Term Loan Facility
On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement. Of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.
On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire.
Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes).
On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon’s 2028 Notes and Callon’s 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:
•Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
•Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.
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10.    INCOME TAXES
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
The Company’s effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company’s effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction. The Company’s deferred tax asset increased by approximately $575 million as part of the assets assumed through the Callon acquisition. Refer to Note 2—Acquisitions and Divestitures for further detail.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. The Company is continuing to evaluate the proposed regulations and their effect on the Company’s consolidated financial statements.
In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
11.    COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2024, the Company has an accrued liability of approximately $18 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
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Argentine Environmental Claims
On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration 
As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.
Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The consideration paid by the Company in the settlement did not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which was filed by the City of New Orleans against the Company and a number of oil and gas operators.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.
21

Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the State of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. These cases were then consolidated before a single judge in a multi-district litigation (MDL) proceeding. On August 14, 2024, in the MDL, the plaintiffs agreed to dismiss Apache with prejudice from all matters, and a dismissal has been entered by the court.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
Kulp Minerals Lawsuit
On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges, among other things, that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. With no admission, concession, or finding of any fault, liability, or wrongdoing, but only to avoid the expense and uncertainty of litigation, the parties have agreed to a settlement resolving all claims made against the defendants by the class. The settlement agreement has been preliminarily approved by the court, and final approval of the settlement is expected to occur prior to the end of 2024. The settlement will not have a material impact on the Company’s financial position, results of operations, or liquidity and is subject to insurance coverage that companies have for these types of claims.
On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Those cases were consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purported to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserting claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants filed a motion to dismiss the consolidated lawsuits, and on September 26, 2024, the federal court issued a final judgment granting the defendants’ motion and dismissing the consolidated claims against the defendants.
22

Environmental Matters
As of September 30, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which has been approved and entered by the Court. The consideration provided by the Company in connection with the consent decree, which included a $4 million payment, did not have a material impact on the Company’s financial position.
The Company is not aware of any environmental claims existing as of September 30, 2024, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
23

On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction in an amount to be determined in a future hearing. That hearing took place on October 24, 2024, although the Court has not yet issued a ruling on the issues addressed, including any award of attorney’s fees to Apache. Apache is vigorously pursuing its claims against the sureties.
As of September 30, 2024, the Company has recorded a $188 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.
The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of “Loss on previously sold Gulf of Mexico properties.” Amounts recorded in the first nine months of 2024 included $50 million related to orders received during the period from BSEE to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.
12.    CAPITAL STOCK
Net Income (Loss) per Common Share
The following table presents a reconciliation of the components of basic and diluted net income (loss) per common share in the consolidated financial statements:
 
For the Quarter Ended September 30,
 20242023
 
Loss
SharesPer ShareIncomeSharesPer Share
 (In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
Diluted:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
For the Nine Months Ended September 30,
20242023
IncomeSharesPer ShareIncomeSharesPer Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock$450 348 $1.30 $1,082 309 $3.50 
Effect of Dilutive Securities:
Stock options and other$— — $(0.01)$— — $— 
Diluted:
Income attributable to common stock$450 348 $1.29 $1,082 309 $3.50 
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The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.9 million and 1.7 million during the third quarters of 2024 and 2023, respectively, and 2.0 million and 2.0 million during the first nine months of 2024 and 2023, respectively.
Stock Repurchase Program
During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. During the third quarter of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock.
In the third quarter of 2024, the Company repurchased approximately 0.1 million shares at an average price of $29.33 per share. For the nine months ended September 30, 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share, and as of September 30, 2024, the Company had remaining authorization to repurchase up to 39.3 million shares. In the third quarter of 2023, the Company repurchased 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share.
The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions.
Common Stock Dividend
For the quarters ended September 30, 2024 and 2023, the Company paid $92 million and $77 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2024 and 2023, the Company paid $260 million and $232 million, respectively, in dividends on its common stock.
Common Stock Issuance
On April 1, 2024, in connection with the Callon acquisition, the Company issued approximately 70 million shares of common stock in exchange for Callon common stock. The total value of stock consideration was approximately $2.4 billion based on APA’s stock price on the closing date of the acquisition.
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13.    BUSINESS SEGMENT INFORMATION
As of September 30, 2024, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: the U.S., Egypt, and North Sea. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:
U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$1,007 $673 $117 $— $1,797 
Natural gas revenues7 81 15 — 103 
Natural gas liquids revenues153 — 5 — 158 
Oil, natural gas, and natural gas liquids production revenues1,167 754 137 — 2,058 
Purchased oil and gas sales473 — — — 473 
1,640 754 137 — 2,531 
Operating Expenses:
Lease operating expenses222 109 87 — 418 
Gathering, processing, and transmission110 6 7 — 123 
Purchased oil and gas costs292 — — — 292 
Taxes other than income70 — — — 70 
Exploration(1)21 — 9 29 
Depreciation, depletion, and amortization355 167 73 — 595 
Asset retirement obligation accretion10 — 26 — 36 
Impairments315 — 796 — 1,111 
1,373 303 989 9 2,674 
Operating Income (Loss)(2)
$267 $451 $(852)$(9)(143)
Other Income (Expense):
Derivative instrument losses, net
(10)
Gain on divestitures, net1 
Other, net18 
General and administrative(92)
Transaction, reorganization, and separation(14)
Financing costs, net(100)
Loss Before Income Taxes
$(340)
26


U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$2,616 $2,003 $517 $— $5,136 
Natural gas revenues79 231 104 — 414 
Natural gas liquids revenues436 — 21 — 457 
Oil, natural gas, and natural gas liquids production revenues3,131 2,234 642 — 6,007 
Purchased oil and gas sales1,018 — — — 1,018 
4,149 2,234 642 — 7,025 
Operating Expenses:
Lease operating expenses582 352 282 — 1,216 
Gathering, processing, and transmission272 19 37 — 328 
Purchased oil and gas costs665 — — — 665 
Taxes other than income205 — — — 205 
Exploration107 77 1 63 248 
Depreciation, depletion, and amortization930 464 219 — 1,613 
Asset retirement obligation accretion35 — 77 — 112 
Impairments315 — 796 — 1,111 
3,111 912 1,412 63 5,498 
Operating Income (Loss)(2)
$1,038 $1,322 $(770)$(63)1,527 
Other Income (Expense):
Derivative instrument losses, net
(17)
Loss on offshore decommissioning contingency(83)
Gain on divestitures, net284 
Other, net26 
General and administrative(270)
Transaction, reorganization, and separation(156)
Financing costs, net(276)
Income Before Income Taxes$1,035 
Total Assets(3)
$13,847 $3,525 $1,439 $565 $19,376 

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U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$633 $724 $348 $— $1,705 
Natural gas revenues89 81 66 — 236 
Natural gas liquids revenues133 — 5 — 138 
Oil, natural gas, and natural gas liquids production revenues855 805 419 — 2,079 
Purchased oil and gas sales229 — — — 229 
1,084 805 419 — 2,308 
Operating Expenses:
Lease operating expenses164 128 102 — 394 
Gathering, processing, and transmission61 13 15 — 89 
Purchased oil and gas costs211 — — — 211 
Taxes other than income61 — — — 61 
Exploration4 25 9 11 49 
Depreciation, depletion, and amortization199 129 90 — 418 
Asset retirement obligation accretion9 — 20 — 29 
709 295 236 11 1,251 
Operating Income (Loss)(2)
$375 $510 $183 $(11)1,057 
Other Income (Expense):
Gain on divestitures, net
1 
General and administrative(139)
Transaction, reorganization, and separation(5)
Financing costs, net(81)
Income Before Income Taxes$833 
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U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$1,631 $1,971 $865 $— $4,467 
Natural gas revenues229 264 165 — 658 
Natural gas liquids revenues356 — 19 — 375 
Oil, natural gas, and natural gas liquids production revenues2,216 2,235 1,049 — 5,500 
Purchased oil and gas sales612 — — — 612 
2,828 2,235 1,049 — 6,112 
Operating Expenses:
Lease operating expenses452 346 278 — 1,076 
Gathering, processing, and transmission181 26 38 — 245 
Purchased oil and gas costs558 — — — 558 
Taxes other than income163 — — — 163 
Exploration10 91 18 25 144 
Depreciation, depletion, and amortization530 378 209 — 1,117 
Asset retirement obligation accretion29 — 57 — 86 
Impairments— — 46 — 46 
1,923 841 646 25 3,435 
Operating Income (Loss)(2)
$905 $1,394 $403 $(25)2,677 
Other Income (Expense):
Derivative instrument gains, net
104 
Gain on divestitures, net7 
Other, net77 
General and administrative(276)
Transaction, reorganization, and separation(11)
Financing costs, net(235)
Income Before Income Taxes$2,343 
Total Assets(3)
$7,827 $3,518 $1,665 $535 $13,545 
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2024 and 2023 of:
For the Quarter Ended September 30,
For the Nine Months Ended September 30,
 2024202320242023
(In millions)
Oil$182 $202 $533 $539 
Natural gas22 23 63 73 
(2)Operating loss of Suriname includes leasehold impairments of $1 million for the third quarter of 2024.
Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income (loss) of U.S. and Suriname includes leasehold impairments of $10 million and $1 million, respectively, for the first nine months of 2024. Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests in Egypt.

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Overview
APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.
APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.
Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, and actions taken by foreign oil and gas producing nations, including OPEC+, impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (3) to responsibly manage its cost structure regardless of the oil price environment.
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.
The Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns.
•The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
•The Company pays a quarterly dividend of $0.25 per share on its common stock.
•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2024, the Company has repurchased 80.7 million shares of the Company’s common stock.
Financial and Operational Highlights
On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. The Company believes the acquisition of Callon provides opportunities to reduce costs, improve capital efficiencies, leverage economies of scale, and expand the development inventory that formed the basis of the transaction value.
Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.
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On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024.
In the third quarter of 2024, the Company reported a net loss attributable to common stock of $223 million, or $0.60 per diluted share, compared to net income of $459 million, or $1.49 per diluted share, in the third quarter of 2023. The decrease in net income in the third quarter of 2024 compared to the third quarter of 2023 was primarily driven by $1.1 billion of impairments, which included $793 million of oil and gas property impairments in the North Sea, a $315 million impairment of assets held for sale in the Permian Basin, and $3 million inventory impairments in the North Sea. These impacts to net loss were partially offset by lower income tax expense compared to the same prior-year period.
In the first nine months of 2024, the Company reported net income attributable to common stock of $450 million, or $1.29 per diluted share, compared to net income of $1.1 billion, or $3.50 per diluted share, in the first nine months of 2023. The decrease in net income in the first nine months of 2024 compared to the first nine months of 2023 was primarily driven by $1.1 billion of impairments recorded during the third quarter of 2024 and the related tax impacts. Net income was further impacted by higher depreciation expense, transaction and reorganization costs, and lease operating expenses, primarily a result of the Callon acquisition. These impacts to net income were partially offset by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, gain from divestitures of non-core assets, and lower income tax expense compared to the same prior-year period.
The Company generated $2.6 billion of cash from operating activities during the first nine months of 2024, 23 percent higher than the first nine months of 2023. APA’s higher operating cash flows for the first nine months of 2024 were primarily driven by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, and timing of working capital items. The Company repurchased 4.6 million shares of its common stock for $146 million and paid $260 million in dividends to APA common stockholders during the first nine months of 2024.
Key operational highlights include:
United States
•Daily boe production from the Company’s U.S. assets accounted for 64 percent of its total production during the third quarter of 2024 and increased 33 percent from the third quarter of 2023. Daily oil production from the Company’s U.S. assets increased 71 percent from the third quarter of 2023. During the third quarter of 2024, the Company averaged nine drilling rigs in the Permian Basin, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin. The Company brought online 48 operated wells during the quarter, of which 21 wells were associated with the Callon assets. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets. The Company expects to average 8 drilling rigs in the Permian Basin for the remainder of 2024 and into 2025.
International
•In Egypt, the Company continued its drilling and workover activity with a focus on oil production. The Company averaged 12 drilling rigs and drilled 15 new productive wells during the third quarter of 2024. During the same period, the Company averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Third quarter 2024 gross production from the Company’s Egypt assets decreased 5 percent from the third quarter of 2023, and net production increased 2 percent.
•Subsequent to September 30, 2024, but prior to the date of this filing, the Company entered into a new pricing agreement for incremental gas volumes produced in Egypt, making gas exploration and development more economically competitive with oil development.
•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company’s investment program in the North Sea is now directed toward asset safety and integrity.
31

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


32

Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Production Revenues
Revenue
The Company’s production revenues and respective contribution to total revenues by country were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
$ Value%
Contribution		$ Value%
Contribution		$ Value%
Contribution		$ Value%
Contribution
 ($ in millions)
Oil Revenues:
United States$1,007 56 %$633 37 %$2,616 51 %$1,631 37 %
Egypt(1)
673 37 %724 43 %2,003 39 %1,971 44 %
North Sea117 7 %348 20 %517 10 %865 19 %
Total(1)
$1,797 100 %$1,705 100 %$5,136 100 %$4,467 100 %
Natural Gas Revenues:
United States$7 7 %$89 38 %$79 19 %$229 35 %
Egypt(1)
81 79 %81 34 %231 56 %264 40 %
North Sea15 14 %66 28 %104 25 %165 25 %
Total(1)
$103 100 %$236 100 %$414 100 %$658 100 %
NGL Revenues:
United States$153 97 %$133 96 %$436 95 %$356 95 %
North Sea5 3 %5 4 %21 5 %19 5 %
Total(1)
$158 100 %$138 100 %$457 100 %$375 100 %
Oil and Gas Revenues:
United States$1,167 56 %$855 41 %$3,131 52 %$2,216 40 %
Egypt(1)
754 37 %805 39 %2,234 37 %2,235 41 %
North Sea137 7 %419 20 %642 11 %1,049 19 %
Total(1)
$2,058 100 %$2,079 100 %$6,007 100 %$5,500 100 %
(1)    Includes revenues attributable to a noncontrolling interest in Egypt.

33

Production
The Company’s production volumes by country were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024Increase
(Decrease)		20232024Increase
(Decrease)		2023
Oil Volume (b/d)
United States143,299 71%83,584 122,138 58%77,198 
Egypt(1)(2)
91,673 4%88,521 88,725 1%88,038 
North Sea21,334 (40)%35,680 25,888 (28)%36,070 
Total256,306 23%207,785 236,751 18%201,306 
Natural Gas Volume (Mcf/d)
United States467,615 3%454,643 473,997 6%448,838 
Egypt(1)(2)
300,418 0%300,326 287,953 (13)%331,158 
North Sea18,911 (71)%65,168 41,042 (14)%47,665 
Total786,944 (4)%820,137 802,992 (3)%827,661 
NGL Volume (b/d)
United States79,474 20%66,280 71,690 17%61,418 
North Sea543 (64)%1,497 1,164 (4)%1,209 
Total80,017 18%67,777 72,854 16%62,627 
BOE per day(3)
United States300,709 33%225,639 272,827 28%213,423 
Egypt(1)(2)
141,742 2%138,575 136,718 (5)%143,231 
North Sea(4)
25,029 (48)%48,038 33,892 (25)%45,222 
Total467,480 13%412,252 443,437 10%401,876 
(1)    Gross oil, natural gas, and NGL production in Egypt were as follows:
For the Quarter Ended September 30,
For the Nine Months Ended September 30,
 2024202320242023
Oil (b/d)136,670 144,528 138,039 141,995 
Natural Gas (Mcf/d)447,173 472,744 445,397 511,430 
(2)    Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
For the Quarter Ended September 30,
For the Nine Months Ended September 30,
 2024202320242023
Oil (b/d)30,579 29,514 29,596 29,369 
Natural Gas (Mcf/d)100,210 100,122 96,054 110,476 
(3)    The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.
(4)    Average sales volumes from the North Sea for the third quarters of 2024 and 2023 were 19,374 boe/d and 55,283 boe/d, respectively, and 30,607 boe/d and 47,370 boe/d for the first nine months of 2024 and 2023, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.


34

Pricing
The Company’s average selling prices by country were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024Increase
(Decrease)		20232024Increase
(Decrease)		2023
Average Oil Price – Per barrel
United States$76.34 (7)%$82.33 $78.16 1%$77.40 
Egypt79.88 (10)%88.99 82.41 0%82.04 
North Sea83.36 (5)%87.70 83.67 1%83.25 
Total78.06 (9)%86.15 80.31 0%80.50 
Average Natural Gas Price – Per Mcf
United States$0.16 (92)%$2.12 $0.61 (67)%$1.87 
Egypt2.93 1%2.91 2.93 0%2.92 
North Sea9.76 (11)%10.98 9.89 (23)%12.83 
Total1.43 (54)%3.12 1.89 (35)%2.91 
Average NGL Price – Per barrel
United States$20.91 (4)%$21.87 $22.20 5%$21.24 
North Sea45.93 7%42.78 46.47 (2)%47.58 
Total21.29 (4)%22.26 22.73 4%21.85 
Third-Quarter 2024 compared to Third-Quarter 2023
Crude Oil Crude oil revenues for the third quarter of 2024 totaled $1.8 billion, a $92 million increase from the comparative 2023 quarter. A 23 percent higher average daily production increased third-quarter 2024 oil revenues by $251 million compared to the third quarter of 2023, while a 9 percent decrease in average realized prices decreased revenues by $159 million. Crude oil revenues accounted for 87 percent of total oil and gas production revenues and 55 percent of worldwide production in the third quarter of 2024. Crude oil prices realized in the third quarter of 2024 averaged $78.06 per barrel, compared with $86.15 per barrel in the comparative prior-year quarter.
The Company’s worldwide oil production increased 48.5 Mb/d to 256.3 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.
Natural Gas Natural gas revenues for the third quarter of 2024 totaled $103 million, a $133 million decrease from the comparative 2023 quarter. A 54 percent decrease in average realized prices decreased third-quarter 2024 natural gas revenues by $128 million compared to the third quarter of 2023, while 4 percent lower average daily production decreased revenues by $5 million. Natural gas revenues accounted for 5 percent of total oil and gas production revenues and 28 percent of worldwide production during the third quarter of 2024.
The Company’s worldwide natural gas production decreased 33.2 MMcf/d to 786.9 MMcf/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, natural production decline, and the sale of non-core assets in the U.S. These decreases were offset by the Callon acquisition coupled with increased drilling activity and recompletions in the Permian Basin.
NGL NGL revenues for the third quarter of 2024 totaled $158 million, a $20 million increase from the comparative 2023 quarter. An 18 percent higher average daily production increased third-quarter 2024 NGL revenues by $26 million compared to the third quarter of 2023, while a 4 percent decrease in average realized prices decreased revenues by $6 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2024.
35

The Company’s worldwide NGL production increased 12.2 Mb/d to 80 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of the Callon acquisition coupled with increased drilling activity in the Permian Basin. These increases were offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.
Year-to-Date 2024 compared to Year-to-Date 2023
Crude Oil Crude oil revenues for the first nine months of 2024 totaled $5.1 billion, a $669 million increase from the comparative 2023 period. An 18 percent higher average daily production increased oil revenues for the 2024 period by $680 million compared to the prior-year period, while a slight decrease in average realized prices lowered oil revenues by $11 million compared to the prior-year period. Crude oil revenues accounted for 85 percent of total oil and gas production revenues and 54 percent of worldwide production for the first nine months of 2024. Crude oil prices realized during the first nine months of 2024 averaged $80.31 per barrel, compared to $80.50 per barrel in the comparative prior-year period.
The Company’s worldwide oil production increased 35.4 Mb/d to 236.8 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline across all assets, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.
Natural Gas Natural gas revenues for the first nine months of 2024 totaled $414 million, a $244 million decrease from the comparative 2023 period. A 35 percent decrease in average realized prices decreased natural gas revenues for the 2024 period by $232 million compared to the prior-year period, while 3 percent lower average daily production decreased revenues by $12 million compared to the prior-year period. Natural gas revenues accounted for 7 percent of total oil and gas production revenues and 30 percent of worldwide production for the first nine months of 2024.
The Company’s worldwide natural gas production decreased 24.7 MMcf/d to 803 MMcf/d in the first nine months of 2024 compared to the prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, reduced gas-focused activity in Egypt, natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.
NGL NGL revenues for the first nine months of 2024 totaled $457 million, a $82 million increase from the comparative 2023 period. A 16 percent higher average daily production increased NGL revenues for the 2024 period by $66 million compared to the prior-year period, while a 4 percent increase in average realized prices increased revenues by $16 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2024.
The Company’s worldwide NGL production increased 10.2 Mb/d to 72.9 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.
Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to U.S. domestic oil and gas purchases that were sold by the Company to fulfill oil and natural gas takeaway obligations and delivery commitments. Sales related to these purchased volumes totaled $473 million and $229 million during the third quarters of 2024 and 2023, respectively, and $1.0 billion and $612 million during the first nine months of 2024 and 2023, respectively. Purchased oil and gas sales were offset by associated purchase costs of $292 million and $211 million during the third quarters of 2024 and 2023, respectively, and $665 million and $558 million during the first nine months of 2024 and 2023, respectively. Gross purchased oil and gas sales values were higher in the third quarter and the first nine months of 2024 as compared to the third quarter and the first nine months of 2023, primarily driven by activity associated with the Callon acquisition.
36

Operating Expenses
The Company’s operating expenses were as follows and include costs attributable to a noncontrolling interest in Egypt:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
Lease operating expenses$418 $394 $1,216 $1,076 
Gathering, processing, and transmission123 89 328 245 
Purchased oil and gas costs292 211 665 558 
Taxes other than income70 61 205 163 
Exploration29 49 248 144 
General and administrative92 139 270 276 
Transaction, reorganization, and separation14 5 156 11 
Depreciation, depletion, and amortization:
Oil and gas property and equipment588 407 1,589 1,086 
Gathering, processing, and transmission assets2 2 5 5 
Other assets5 9 19 26 
Asset retirement obligation accretion36 29 112 86 
Impairments1,111 — 1,111 46 
Financing costs, net100 81 276 235 
Total Operating Expenses$2,880 $1,476 $6,200 $3,957 
Lease Operating Expenses (LOE)
LOE increased $24 million and $140 million compared to the third quarter and the first nine months of 2023, respectively. On a per-unit basis, LOE decreased 4 percent and increased 3 percent in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The absolute dollar increase in the third quarter and the first nine months of 2024 compared to same prior year periods was driven by higher operating and labor costs coupled with higher workover activity, primarily from the Callon acquisition.
Gathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
(In millions)
Third-party processing and transmission costs$123 $63 $305 $164 
Midstream service costs – Kinetik— 26 23 81 
Total Gathering, processing, and transmission
$123 $89 $328 $245 
GPT costs increased $34 million and $83 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023, primarily driven by an increase in natural gas and NGL production volumes in the U.S. when compared to the prior-year periods.
Purchased Oil and Gas Costs
Purchased oil and gas costs increased $81 million and $107 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The increase in the third quarter and the first nine months of 2024 compared to same prior-year periods was primarily driven by oil purchases from activity associated with the Callon acquisition. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill oil and natural gas takeaway obligations and delivery commitments totaling $473 million and $1.0 billion in the third quarter and the first nine months of 2024, respectively, as discussed above.
37

Taxes Other Than Income
Taxes other than income increased $9 million and $42 million from the third quarter and the first nine months of 2023, respectively, primarily from higher severance taxes driven by increased production volumes in the U.S. compared to the same prior-year periods.
Exploration Expenses
The Company’s exploration expenses were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
(In millions)
Unproved leasehold impairments$1 $9 $11 $20 
Dry hole expense8 18 172 71 
Geological and geophysical expense6 1 22 3 
Exploration overhead and other14 21 43 50 
Total Exploration$29 $49 $248 $144 
Exploration expenses decreased $20 million and increased $104 million from the third quarter and the first nine months of 2023, respectively. The decrease in exploration expenses for the third quarter of 2024 compared to the third quarter of 2023 was primarily the result of higher dry hole expenses in the 2023 period coupled with lower unproved leasehold impairments and exploration overhead. The increase in exploration expenses for the first nine months of 2024 compared to the first nine months of 2023 was primarily the result of dry hole expense associated with the completion of an initial drilling campaign in Alaska where two wells were unable to reach target objectives in the allotted seasonal time window.
General and Administrative (G&A) Expenses
G&A expenses decreased $47 million and $6 million from the third quarter and the first nine months of 2023, respectively. The decrease in G&A expenses for the third quarter and first nine months of 2024 compared to the same prior-year periods was primarily driven by higher cash-based stock compensation expense in the 2023 period resulting from changes in the Company’s stock price, partially offset by higher overall labor costs across the Company and the Callon acquisition.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs increased $9 million and $145 million from the third quarter and the first nine months of 2023, respectively. Higher TRS costs during the third quarter and the first nine months of 2024 were primarily a result of ongoing transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.
Depreciation, Depletion, and Amortization (DD&A)
Total DD&A expenses increased $177 million and $496 million from the third quarter and the first nine months of 2023, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $3.30 per boe and $3.33 per boe from the third quarter and the first nine months of 2023, respectively. The increase in DD&A on a per boe basis was driven by negative gas price-related reserve revisions in prior periods and impacts resulting from the Callon acquisition in 2024. Higher absolute dollar amount of DD&A was driven primarily by higher capital expenditures incurred in the U.S. and Egypt.
Impairments
During the third quarter and the first nine months of 2024, the Company recorded $1.1 billion of impairments, which includes $793 million of oil and gas property impairments in the North Sea, $315 million impairment of assets held for sale in the Permian Basin, and $3 million of inventory impairments in the North Sea.
During the first nine months of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

38

Financing Costs, Net
The Company’s Financing costs were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
Interest expense$109 $89 $302 $266 
Amortization of debt issuance costs1 1 4 3 
Capitalized interest(8)(7)(22)(18)
Gain on extinguishment of debt
— — — (9)
Interest income(2)(2)(8)(7)
Total Financing costs, net$100 $81 $276 $235 
Net financing costs increased $19 million and $41 million from the third quarter and the first nine months of 2023, respectively. The increase in costs during the third quarter and the first nine months of 2024 was primarily due to higher interest expense from higher average long-term debt balances compared to the third quarter and the first nine months of 2023.
Provision for Income Taxes
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
The Company’s effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company’s effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. The Company is continuing to evaluate the proposed regulations and their effect on the Company’s consolidated financial statements.
In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
39

Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with sustained decreases in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
During the nine months ended September 30, 2024, the Company recognized downward reserve revisions of approximately 26 percent of its year-end 2023 estimated proved reserves in the North Sea as a result of its economic assessment of its North Sea assets described in “Financial and Operational Highlights” above.
Following the completion of the Callon acquisition, the Company revised its full-year 2024 estimated upstream capital investment to approximately $2.8 billion and remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.
The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.
For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
40

Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented:
 
For the Nine Months Ended
September 30,
 20242023
 (In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities$2,584 $2,099 
Proceeds from commercial paper and revolving credit facilities, net
190 202 
Proceeds from term loan facility
1,500 — 
Proceeds from asset divestitures724 29 
Proceeds from sale of Kinetik Shares
428 — 
Other20 — 
Total Sources of Cash and Cash Equivalents5,446 2,330 
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property$2,153 $1,747 
Leasehold and property acquisitions64 11 
Payments on term loan facility
500 — 
Payment on Callon Credit Agreement
472 — 
Payments on fixed-rate debt
1,641 65 
Dividends paid to APA common stockholders260 232 
Distributions to noncontrolling interest
233 154 
Treasury stock activity, net146 208 
Other, net— 63 
Total Uses of Cash and Cash Equivalents5,469 2,480 
Decrease in Cash and Cash Equivalents
$(23)$(150)
Sources of Cash and Cash Equivalents
Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation accretion, and deferred income tax expense.
Net cash provided by operating activities during the first nine months of 2024 totaled $2.6 billion, $485 million higher from the first nine months of 2023, primarily due to higher revenues from increased oil and gas production and timing of working capital items.
For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
Proceeds from Commercial Paper and Revolving Credit Facilities, Net As of September 30, 2024, outstanding borrowings under the Company’s commercial paper and U.S. dollar denominated syndicated credit facility were $562 million, an increase of $190 million since December 31, 2023. During the nine months ended September 30, 2023, the Company had net borrowings of $202 million under the Company’s U.S. dollar denominated syndicated credit facility.
Proceeds from Term Loan Facility On April 1, 2024, the Company borrowed an aggregate $1.5 billion under a syndicated credit agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the closing of the Callon acquisition. For additional details of the credit agreement, see “Term Loan Credit Agreement” in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
41

Proceeds from Asset Divestitures The Company received $724 million and $29 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2024 and 2023, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Proceeds from Sale of Kinetik Shares The Company received $428 million of cash proceeds from the sale of its remaining shares of Kinetik Class A Common Stock in March 2024. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Uses of Cash and Cash Equivalents
Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $2.2 billion and $1.7 billion during the first nine months of 2024 and 2023, respectively. The increase in capital investment compared to the prior-year period is reflective of the Company’s acquisition of Callon, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s efforts to balance workover activity in Egypt and reduce drilling activity in the North Sea as it continually assesses inventory opportunities across its diverse portfolio. The Company operated an average of approximately 23 drilling rigs during the first nine months of 2024, compared to an average of approximately 24 drilling rigs during the first nine months of 2023.
Leasehold and Property Acquisitions During the first nine months of 2024 and 2023, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $64 million and $11 million, respectively.
Payments on Callon Credit Agreement During the first nine months of 2024, the Company financed Callon’s repayment in full of the $472 million outstanding under the Callon Credit Agreement upon the Callon acquisition.
Payments on Term Loan Facility During the first nine months of 2024, the Company made a payment of $500 million on its syndicated credit agreement. For additional details of the credit agreement, see “Term Loan Credit Agreement” in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Payments on Fixed-Rate Debt During the first nine months of 2024, the Company financed Callon’s repayment pursuant to Callon’s cash tender offers for, and redemptions of all senior notes issued under Callon’s indentures for an aggregate cash payment amount of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.
During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash. The Company recognized a $9 million gain on these repurchases.
The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.
Dividends Paid to APA Common Stockholders The Company paid $260 million and $232 million during the first nine months of 2024 and 2023, respectively, for dividends on its common stock.
Distributions to Noncontrolling Interest Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $233 million and $154 million during the first nine months of 2024 and 2023, respectively, in cash distributions to Sinopec.
Treasury Stock Activity, net In the first nine months of 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share and an aggregate purchase price of approximately $146 million, and as of September 30, 2024, the Company had remaining authorization to repurchase 39.3 million shares. In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share and an aggregate purchase price of approximately $208 million.
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Liquidity
The following table presents a summary of the Company’s key financial indicators:
September 30,
2024
December 31,
2023
 (In millions)
Cash and cash equivalents$64 $87 
Total debt – APA and Apache6,372 5,188 
Total equity6,160 3,691 
Available committed borrowing capacity under syndicated credit facilities2,839 2,894 
Cash and Cash Equivalents As of September 30, 2024, the Company had $64 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.
Debt As of September 30, 2024, the Company had $6.4 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility and commercial paper borrowings, and finance lease obligations. As of September 30, 2024, current debt included $2 million of finance lease obligations.
Unsecured 2022 Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.
•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each of the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.
As of September 30, 2024, there were $232 million of borrowings under the USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement.
Uncommitted Lines of Credit Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million in letters of credit outstanding under these facilities.
Commercial Paper Program In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.
Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
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As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
Term Loan Credit Agreement On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement; of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.
On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027, and to allow the lender commitments for the 364-Day Tranche Loans to expire. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes).
On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon’s 2028 Notes and Callon’s 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:
•Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
•Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.
Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. There have been no material changes to the contractual obligations described therein.
44

Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that the sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction in an amount to be determined in a future hearing. Apache is vigorously pursuing its claims against the sureties.
As of September 30, 2024, the Company has recorded a $188 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.
The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of “Loss on previously sold Gulf of Mexico properties.” Amounts recorded in the first nine months of 2024 included $50 million related to orders received from BSEE during the period to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.

45

Critical Accounting Estimates
The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. For the nine months ended September 30, 2024, the Company notes the following additional critical accounting estimate:
Long-Lived Asset Impairments
Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.
Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.
To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.
Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
The Company has recorded material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities in the third quarter of 2024. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.
Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities would be recorded as goodwill.
The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
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In estimating the fair values of assets acquired and liabilities assumed, the Company has made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, the Company prepared estimates of crude oil and natural gas reserves as described in the “Reserves Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.
New Accounting Pronouncements
In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.
ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the conflict in Israel and Gaza, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.
The Company’s average crude oil price realizations decreased 9 percent from $86.15 per barrel to $78.06 per barrel during the third quarters of 2023 and 2024, respectively. The Company’s average natural gas price realizations decreased 54 percent from $3.12 per Mcf to $1.43 per Mcf during the third quarters of 2023 and 2024, respectively. The Company’s average NGL price realizations decreased 4 percent from $22.26 per barrel to $21.29 per barrel during the third quarters of 2023 and 2024, respectively. Based on average daily production for the third quarter of 2024, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $24 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $7 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $7 million.
The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2024, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $1 million. A 10 percent increase in natural gas prices would increase the liability by approximately $1 million, while a 10 percent decrease in prices would decrease the liability by approximately $1 million. As of September 30, 2024, the Company had open NGL derivatives not designated as cash flow hedges in a liability position with a fair value of $1 million. The impact of a 10 percent movement in NGL prices would be immaterial to the fair value of the commodity derivatives. These fair value changes assume volatility based on prevailing market parameters at September 30, 2024. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.
47

Interest Rate Risk
As of September 30, 2024, the Company had $4.8 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.34 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.
The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its term loan facility, commercial paper program, and syndicated credit facilities. As of September 30, 2024, the Company had approximately $64 million in cash and cash equivalents, approximately 86 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2024, there were $1.6 billion of borrowings outstanding under the Company’s term loan facility, commercial paper program, and syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments, term loan facility, commercial paper program, and credit facility borrowings are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.
Foreign Currency Exchange Rate Risk
The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss of $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2024.
ITEM 4.    CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2024, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.
Changes in Internal Control Over Financial Reporting
As a result of the Callon acquisition on April 1, 2024, the Company’s internal control over financial reporting, subsequent to the date of acquisition, includes certain additional internal controls relating to Callon. There were no other changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II - OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS
Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 and Note 11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.
ITEM 1A.    RISK FACTORS
There have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2024, June 30, 2024, and September 30, 2024 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2024:
Issuer Purchases of Equity Securities
PeriodTotal Number of Shares PurchasedAverage Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2024
102,305 $29.33 102,305 39,326,125
August 1 to August 31, 2024
— — — 39,326,125
September 1 to September 30, 2024
— — — 39,326,125
Total102,305$29.33 
(1) During the third quarter of 2022, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company is not obligated to acquire any specific number of shares.
ITEM 5.    OTHER INFORMATION
During the three months ended September 30, 2024, none of the Company’s officers or directors adopted or terminated any Rule 10b5-1 trading arrangement or “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).

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ITEM 6.    EXHIBITS
Incorporated by Reference
EXHIBIT
NO.		DESCRIPTION
Form
Exhibit
Filing Date
SEC File No.
2.1
8-K
2.1
1/4/2024
001-40144
3.18-K12B
3.1
3/1/2021
001-40144
3.28-K
3.1
5/25/2023
001-40144
3.38-K
3.1
2/8/2023
001-40144
*31.1
*31.2
**32.1
*101
The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2024, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.SCHInline XBRL Taxonomy Schema Document.
*101.CALInline XBRL Calculation Linkbase Document.
*101.DEFInline XBRL Definition Linkbase Document.
*101.LABInline XBRL Label Linkbase Document.
*101.PREInline XBRL Presentation Linkbase Document.
*104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*    Filed herewith
**    Furnished herewith

50

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 APA CORPORATION
Dated:November 7, 2024 /s/ STEPHEN J. RINEY
 Stephen J. Riney
 
President and Chief Financial Officer
 (Principal Financial Officer)
Dated:November 7, 2024 /s/ REBECCA A. HOYT
 Rebecca A. Hoyt
 Senior Vice President, Chief Accounting Officer, and Controller
 (Principal Accounting Officer)

51

EXHIBIT 31.1
CERTIFICATIONS
I, John J. Christmann IV, certify that:
1.I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 7, 2024

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



EXHIBIT 31.2
CERTIFICATIONS
I, Stephen J. Riney, certify that:
1.I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 7, 2024

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



EXHIBIT 32.1
APA CORPORATION
Certification of Principal Executive Officer
and Principal Financial Officer
I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2024, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

 Date: November 7, 2024

/s/ John J. Christmann IV
By: John J. Christmann IV
Title: Chief Executive Officer
(principal executive officer)
I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2024, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.
Date: November 7, 2024

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


v3.24.3
COVER - shares
 9 Months Ended
Sep. 30, 2024
Oct. 31, 2024
Cover [Abstract]    
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Sep. 30, 2024  
Document Transition Report false  
Entity File Number 1-40144  
Entity Registrant Name APA CORPORATION  
Entity Incorporation, State or Country Code DE  
Entity Tax Identification Number 86-1430562  
Entity Address, Address Line One 2000 W. Sam Houston Pkwy. S., Suite 200  
Entity Address, City or Town Houston  
Entity Address, State or Province TX  
Entity Address, Postal Zip Code 77042-3643  
City Area Code 713  
Local Phone Number 296-6000  
Title of 12(b) Security Common Stock, $0.625 par value  
Trading Symbol APA  
Security Exchange Name NASDAQ  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Common Stock, Shares Outstanding   369,947,453
Amendment Flag false  
Document Fiscal Year Focus 2024  
Document Fiscal Period Focus Q3  
Entity Central Index Key 0001841666  
Current Fiscal Year End Date --12-31  
v3.24.3
STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($)
shares in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
REVENUES AND OTHER:        
Derivative instrument gains (losses), net $ (10,000,000) $ 0 $ (17,000,000) $ 104,000,000
Gain on divestitures, net 1,000,000 1,000,000 284,000,000 7,000,000
Loss on previously sold Gulf of Mexico properties 0 0 (83,000,000) 0
Other, net 18,000,000 0 26,000,000 77,000,000
Total revenues and other 2,540,000,000 2,309,000,000 7,235,000,000 6,300,000,000
OPERATING EXPENSES:        
Lease operating expenses [1] 418,000,000 394,000,000 1,216,000,000 1,076,000,000
Taxes other than income 70,000,000 61,000,000 205,000,000 163,000,000
Exploration 29,000,000 49,000,000 248,000,000 144,000,000
General and administrative 92,000,000 139,000,000 270,000,000 276,000,000
Transaction, reorganization, and separation 14,000,000 5,000,000 156,000,000 11,000,000
Depreciation, depletion, and amortization 595,000,000 418,000,000 1,613,000,000 1,117,000,000
Asset retirement obligation accretion 36,000,000 29,000,000 112,000,000 86,000,000
Impairments 1,111,000,000 0 1,111,000,000 46,000,000
Financing costs, net 100,000,000 81,000,000 276,000,000 235,000,000
Total operating expenses 2,880,000,000 1,476,000,000 6,200,000,000 3,957,000,000
NET INCOME (LOSS) BEFORE INCOME TAXES (340,000,000) 833,000,000 1,035,000,000 2,343,000,000
Current income tax provision 260,000,000 422,000,000 845,000,000 1,022,000,000
Deferred income tax benefit (461,000,000) (144,000,000) (503,000,000) (22,000,000)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS (139,000,000) 555,000,000 693,000,000 1,343,000,000
Net income attributable to noncontrolling interest 84,000,000 96,000,000 243,000,000 261,000,000
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK $ (223,000,000) $ 459,000,000 $ 450,000,000 $ 1,082,000,000
NET INCOME (LOSS) PER COMMON SHARE:        
Basic (in USD per share) $ (0.60) $ 1.49 $ 1.30 $ 3.50
Diluted (in USD per share) $ (0.60) $ 1.49 $ 1.29 $ 3.50
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:        
Basic (in shares) 370 308 348 309
Diluted (in shares) 370 308 348 309
Oil and gas        
REVENUES AND OTHER:        
Total revenues $ 2,531,000,000 $ 2,308,000,000 $ 7,025,000,000 $ 6,112,000,000
Oil and gas, excluding purchased        
REVENUES AND OTHER:        
Total revenues [1] 2,058,000,000 2,079,000,000 6,007,000,000 5,500,000,000
OPERATING EXPENSES:        
Gathering, processing, and transmission & purchased oil and gas costs [1] 123,000,000 89,000,000 328,000,000 245,000,000
Purchased oil and gas        
REVENUES AND OTHER:        
Total revenues [1] 473,000,000 229,000,000 1,018,000,000 612,000,000
OPERATING EXPENSES:        
Gathering, processing, and transmission & purchased oil and gas costs [1] $ 292,000,000 $ 211,000,000 $ 665,000,000 $ 558,000,000
[1] For transactions with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests.
v3.24.3
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Statement of Comprehensive Income [Abstract]        
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS $ (139) $ 555 $ 693 $ 1,343
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:        
Pension and postretirement benefit plan 0 0 (1) 3
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS (139) 555 692 1,346
Comprehensive income attributable to noncontrolling interest 84 96 243 261
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK $ (223) $ 459 $ 449 $ 1,085
v3.24.3
STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($)
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
CASH FLOWS FROM OPERATING ACTIVITIES:        
Net income including noncontrolling interests $ (139,000,000) $ 555,000,000 $ 693,000,000 $ 1,343,000,000
Adjustments to reconcile net income to net cash provided by operating activities:        
Unrealized derivative instrument (gains) losses, net 13,000,000 19,000,000 18,000,000 (61,000,000)
Gain on divestitures, net     (284,000,000) (7,000,000)
Exploratory dry hole expense and unproved leasehold impairments     183,000,000 91,000,000
Depreciation, depletion, and amortization 595,000,000 418,000,000 1,613,000,000 1,117,000,000
Asset retirement obligation accretion 36,000,000 29,000,000 112,000,000 86,000,000
Impairments 1,111,000,000 0 1,111,000,000 46,000,000
Benefit from deferred income taxes (461,000,000) (144,000,000) (503,000,000) (22,000,000)
Gain on extinguishment of debt 0 0 0 (9,000,000)
Loss on previously sold Gulf of Mexico properties 0 0 83,000,000 0
Other, net     (14,000,000) (45,000,000)
Changes in operating assets and liabilities:        
Receivables     181,000,000 (289,000,000)
Inventories     (26,000,000) 19,000,000
Drilling advances and other current assets     37,000,000 40,000,000
Deferred charges and other long-term assets     (215,000,000) 227,000,000
Accounts payable     (191,000,000) (2,000,000)
Accrued expenses     (271,000,000) 1,000,000
Deferred credits and noncurrent liabilities     57,000,000 (436,000,000)
NET CASH PROVIDED BY OPERATING ACTIVITIES     2,584,000,000 2,099,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:        
Additions to upstream oil and gas property     (2,153,000,000) (1,747,000,000)
Leasehold and property acquisitions (1,000,000)   (64,000,000) (11,000,000)
Proceeds from asset divestitures     724,000,000 29,000,000
Proceeds from sale of Kinetik Shares     428,000,000 0
Other, net     58,000,000 (53,000,000)
NET CASH USED IN INVESTING ACTIVITIES     (1,007,000,000) (1,782,000,000)
CASH FLOWS FROM FINANCING ACTIVITIES:        
Proceeds from commercial paper and revolving credit facilities, net     190,000,000 202,000,000
Proceeds from term loan facility     1,500,000,000 0
Payments on term loan facility     (500,000,000) 0
Payment on Callon Credit Agreement     (472,000,000) 0
Payments on fixed-rate debt     (1,641,000,000) (65,000,000)
Distributions to noncontrolling interest     (233,000,000) (154,000,000)
Treasury stock activity, net     (146,000,000) (208,000,000)
Dividends paid to APA common stockholders (92,000,000) (77,000,000) (260,000,000) (232,000,000)
Other, net     (38,000,000) (10,000,000)
NET CASH USED IN FINANCING ACTIVITIES     (1,600,000,000) (467,000,000)
NET DECREASE IN CASH AND CASH EQUIVALENTS     (23,000,000) (150,000,000)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR     87,000,000 245,000,000
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 64,000,000 $ 95,000,000 64,000,000 95,000,000
SUPPLEMENTARY CASH FLOW DATA:        
Interest paid, net of capitalized interest     306,000,000 278,000,000
Income taxes paid, net of refunds     $ 876,000,000 $ 867,000,000
v3.24.3
CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
CURRENT ASSETS:    
Cash and cash equivalents $ 64 $ 87
Receivables, net of allowance of $120 and $114 1,652 1,610
Assets held for sale 1,091 0
Other current assets (Note 5) 813 765
Total current assets 3,620 2,462
PROPERTY AND EQUIPMENT:    
Oil and gas properties 44,026 44,860
Gathering, processing, and transmission facilities 446 448
Other 557 634
Less: Accumulated depreciation, depletion, and amortization (32,428) (35,904)
Property and equipment, net 12,601 10,038
OTHER ASSETS:    
Equity method interests (Note 6) 0 437
Decommissioning security for sold Gulf of Mexico properties (Note 11) 21 21
Deferred tax asset (Note 10) 2,550 1,758
Deferred charges and other 584 528
ASSETS 19,376 15,244
CURRENT LIABILITIES:    
Accounts payable 939 658
Current debt 2 2
Liabilities held for sale 224 0
Other current liabilities (Note 7) 1,760 1,744
Total current liabilities 2,925 2,404
LONG-TERM DEBT (Note 9) 6,370 5,186
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:    
Deferred tax liability (Note 10) 86 371
Asset retirement obligation (Note 8) 2,502 2,362
Decommissioning contingency for sold Gulf of Mexico properties (Note 11) 759 764
Other 574 466
Total deferred credits and other noncurrent liabilities 3,921 3,963
EQUITY:    
Common stock, $0.625 par, 860,000,000 shares authorized, 491,531,484 and 420,595,901 shares issued, respectively 307 263
Paid-in capital 13,239 11,126
Accumulated deficit (2,509) (2,959)
Treasury stock, at cost, 121,613,494 and 117,020,000 shares, respectively (5,937) (5,790)
Accumulated other comprehensive income 14 15
APA SHAREHOLDERS’ EQUITY 5,114 2,655
Noncontrolling interest 1,046 1,036
TOTAL EQUITY 6,160 3,691
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY $ 19,376 $ 15,244
v3.24.3
CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Statement of Financial Position [Abstract]    
Receivables, allowance $ 120 $ 114
Common stock, par value (in USD per share) $ 0.625 $ 0.625
Common stock, shares authorized (in shares) 860,000,000 860,000,000
Common stock, shares issued (in shares) 491,531,484 420,595,901
Treasury stock, shares (in shares) 121,613,494 117,020,000
v3.24.3
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS (Unaudited) - USD ($)
$ in Millions
Total
APA SHAREHOLDERS’ EQUITY
Common Stock
Paid-In Capital
Accumulated Deficit
Treasury Stock
Accumulated Other Comprehensive Income
Noncontrolling Interest
Beginning balance at Dec. 31, 2022 $ 1,345 $ 423 $ 262 $ 11,420 $ (5,814) $ (5,459) $ 14 $ 922
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income (loss) attributable to common stock 1,082 1,082     1,082      
Net income attributable to noncontrolling interest 261             261
Distributions to noncontrolling interest (154)             (154)
Common dividends declared (232) (232)   (232)        
Treasury stock activity, net (208) (208)       (208)    
Other 13 13 1 9     3  
Ending balance at Sep. 30, 2023 2,107 1,078 263 11,197 (4,732) (5,667) 17 1,029
Beginning balance at Jun. 30, 2023 1,696 709 263 11,267 (5,191) (5,647) 17 987
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income (loss) attributable to common stock 459 459     459      
Net income attributable to noncontrolling interest 96             96
Distributions to noncontrolling interest (54)             (54)
Common dividends declared (77) (77)   (77)        
Treasury stock activity, net (20) (20)       (20)    
Other 7 7   7        
Ending balance at Sep. 30, 2023 2,107 1,078 263 11,197 (4,732) (5,667) 17 1,029
Beginning balance at Dec. 31, 2023 3,691 2,655 263 11,126 (2,959) (5,790) 15 1,036
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income (loss) attributable to common stock 450 450     450      
Net income attributable to noncontrolling interest 243             243
Distributions to noncontrolling interest (233)             (233)
Common dividends declared (260) (260)   (260)        
Issuance of common stock 2,414 2,414 44 2,370        
Treasury stock activity, net (147) (147)       (147)    
Other 2 2   3     (1)  
Ending balance at Sep. 30, 2024 6,160 5,114 307 13,239 (2,509) (5,937) 14 1,046
Beginning balance at Jun. 30, 2024 6,495 5,423 307 13,322 (2,286) (5,934) 14 1,072
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income (loss) attributable to common stock (223) (223)     (223)      
Net income attributable to noncontrolling interest 84             84
Distributions to noncontrolling interest (110)             (110)
Common dividends declared (92) (92)   (92)        
Treasury stock activity, net (3) (3)       (3)    
Other 9 9   9        
Ending balance at Sep. 30, 2024 $ 6,160 $ 5,114 $ 307 $ 13,239 $ (2,509) $ (5,937) $ 14 $ 1,046
v3.24.3
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTERESTS (Unaudited) (Parenthetical) - $ / shares
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Statement of Stockholders' Equity [Abstract]        
Common stock, dividends, per share (in USD per share) $ 0.25 $ 0.25 $ 0.75 $ 0.75
v3.24.3
NATURE OF OPERATIONS
 9 Months Ended
Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
NATURE OF OPERATIONS
These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, which contains a summary of the Company’s significant accounting policies and other disclosures.
v3.24.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 9 Months Ended
Sep. 30, 2024
Accounting Policies [Abstract]  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2024, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. During the nine months ended September 30, 2023 and the quarter ended March 31, 2024, the Company had a designated director on the Kinetik Holdings Inc. (Kinetik) board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors.
As of December 31, 2023, the Company held shares of Kinetik Class A Common Stock (Kinetik Shares), which were recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. On March 18, 2024, the Company sold its remaining Kinetik Shares. Refer to Note 6—Equity Method Interests for further detail.
Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Refer to Note 4—Derivative Instruments and Hedging Activities, Note 6—Equity Method Interests, and Note 9—Debt and Financing Costs for further detail regarding the Company’s fair value measurements recorded on a recurring basis.
The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment.
During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. As a result, the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea as of September 30, 2024. Accordingly, in the third quarter of 2024, the Company recognized impairments of $793 million on certain proved properties in the North Sea, which were written down to their estimated fair values. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.”
Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail.
During the three and nine months ended September 30, 2023, the Company recorded no asset impairments in connection with fair value assessments.
Revenue Recognition
Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.5 billion at each of September 30, 2024 and December 31, 2023. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout the period, and management believes that the Company will be able to collect the total balance of its receivables from this customer.
Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. The Company recorded impairments to inventory of $3 million in the third quarter and the nine months ended September 30, 2024 and $46 million in the nine months ended September 30, 2023.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, production costs, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities, and if management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $793 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million.
Additionally, in the third quarter of 2024, the Company recorded impairments totaling $315 million in connection with an agreement to sell certain non-core producing properties in the Permian Basin. These impairments are discussed in further detail above in “Fair Value Measurements” and in Note 2—Acquisitions and Divestitures. The associated U.S. properties had an aggregate fair value of $1.1 billion as of September 30, 2024.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.
Gathering, Processing, and Transmission (GPT) Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
Transaction, Reorganization, and Separation (TRS)
The Company recorded $14 million and $156 million of TRS costs during the third quarter and the first nine months of 2024, respectively, and $5 million and $11 million of TRS costs during the third quarter and the first nine months of 2023, respectively. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.
New Pronouncements Issued But Not Yet Adopted
In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.
v3.24.3
ACQUISITIONS AND DIVESTITURES
 9 Months Ended
Sep. 30, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
ACQUISITIONS AND DIVESTITURES ACQUISITIONS AND DIVESTITURES
2024 Activity
Sale of Non-core Properties in the Permian Basin
On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for cash proceeds of $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024. The Company received a deposit of $95 million in connection with the sale during the third quarter of 2024.
As a result of the agreement, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $315 million to the carrying value of associated oil and gas properties. These assets met the criteria of held for sale classification as of September 30, 2024. U.S. oil and gas properties totaling $1.1 billion and the associated asset retirement obligation of $224 million were classified as current assets held for sale and current liabilities held for sale, respectively, as of September 30, 2024.
Callon Petroleum Company Acquisition
On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024. The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin.

Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction based on the value of APA common stock on the day of closing, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE. In addition to the equity consideration provided, APA transferred approximately $24 million in other consideration upon close of the transaction.
Upon completing the acquisition, APA repaid all of Callon’s debt, refinancing a portion by borrowing $1.5 billion under its unsecured committed term loan facility. Refer to Note 9—Debt and Financing Costs for further detail.
Recording of Assets Acquired and Liabilities Assumed
The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.
The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the merger:
(In millions)
Current assets
$282 
Property, plant, and equipment
4,493 
Deferred tax asset
575 
Other assets11 
Total assets acquired$5,361 
Current liabilities$616 
Long-term debt
2,113 
Asset retirement obligation136 
Other long-term obligations58 
Total liabilities assumed$2,923 
Net assets acquired$2,438 
The following unaudited pro forma combined results for the three and nine months ended September 30, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, interest expense, gain on derivatives related to a previous Callon acquisition, and estimated tax impacts of the pro forma adjustments.
For the Quarter Ended
September 30,		For the Nine Months Ended
September 30,
2024202320242023
(In millions, except share data)
Revenues
$2,531 $2,927 $7,589 $7,810 
Net income (loss) attributable to common stock
(223)737 556 1,527 
Net income (loss) per common share – basic
(0.60)1.95 1.50 4.04 
Net income (loss) per common share – diluted
(0.60)1.95 1.50 4.04 
From the date of the acquisition through September 30, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $840 million and $192 million, respectively.
The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated. The unaudited pro forma results are also not intended to be a projection of future results and do not include any future cost savings or other synergies that may result from the Callon acquisition or any estimated costs that have not yet been incurred.
U.S. Divestitures
In the first nine months of 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $253 million and the assumption of asset retirement obligations of $48 million. The Company recognized a $46 million loss during the first nine months of 2024 in association with this sale.
In the first nine months of 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $392 million after post-closing adjustments. The Company recognized a gain of $321 million during the first nine months of 2024 in association with this sale.
Additionally, during the third quarter and first nine months of 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $73 million, respectively, recognizing a gain of approximately $1 million and $9 million, respectively, upon closing of these transactions.
Sale of Kinetik Shares
On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. Refer to Note 6—Equity Method Interests for further detail.
Leasehold and Property Acquisitions
During the third quarter and the first nine months of 2024, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $64 million, respectively.
2023 Activity
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $1 million and $11 million, respectively.
U.S. Divestitures
During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions.
v3.24.3
CAPITALIZED EXPLORATORY WELL COSTS
 9 Months Ended
Sep. 30, 2024
Extractive Industries [Abstract]  
CAPITALIZED EXPLORATORY WELL COSTS CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $611 million and $586 million as of September 30, 2024 and December 31, 2023, respectively. The increase is primarily attributable to additional drilling activity in Egypt and in the U.S. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense during the third quarter of 2024. During the first nine months of 2024, approximately $51 million of suspended well costs previously capitalized for greater than one year at December 31, 2023 were charged to dry hole expense.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
 9 Months Ended
Sep. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values. The Company has elected not to designate any of its derivative contracts as cash flow hedges.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2024, the Company had derivative positions with one counterparty. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.
Derivative Instruments
Commodity Derivative Instruments
As of September 30, 2024, the Company had the following open natural gas financial collar contracts:
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Floor PriceWeighted Average Ceiling Price
October—December 2024
NYMEX Henry Hub
1,654$3.00$3.33
As of September 30, 2024, the Company had the following open natural gas financial basis swap contracts:
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Price DifferentialMMBtu
(in 000’s)		Weighted Average Price Differential
October—December 2024
NYMEX Henry Hub/IF Waha——1,840$(1.06)
October—December 2024
NYMEX Henry Hub/IF HSC——3,680$(0.42)
As of September 30, 2024, the Company had the following open NGL fixed swap contracts:
Production PeriodSettlement Index
MBbls
(in 000’s)
Weighted Average Price Differential
October—December 2024
OPIS IsoButane Mt Belvieu Non TET
6$33.18
October—December 2024
OPIS NButane Mt Belvieu Non TET
17$33.18
Embedded Derivatives
As a result of the Callon acquisition, the Company assumed an earn-out obligation from Callon, where the Company could be required to pay up to $50 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for the 2024 and 2025 calendar years. Additionally, in connection with the Callon acquisition, the Company assumed a contingent consideration arrangement, whereby the Company could receive up to $45 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20 million.
The Company determined that the earn-out obligation and contingent consideration receipt were not clearly and closely related to the underlying agreements and therefore bifurcated these embedded features and recorded these derivatives at fair value. For further discussion of these derivatives, refer to “Fair Value Measurements” below.
Fair Value Measurements
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)		Significant Other Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
September 30, 2024
Assets:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 10 — 10 — 10 
Liabilities:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 39 — 39 — 39 
December 31, 2023
Assets:
Commodity derivative instruments$— $6 $— $6 $— $6 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
The embedded options within the earn-out obligation and contingent consideration arrangements discussed above are considered financial instruments under ASC 815. The Company uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing an option pricing model method provided by a reputable third party. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered a Level 2 fair value measurement. As of September 30, 2024, the estimated fair values of the earn-out obligation and contingent consideration receipt were $39 million and $10 million, respectively.
Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
September 30,
2024
December 31,
2023
(In millions)
Current Assets: Other current assets$10 $6 
Total derivative assets$10 $6 
Current Liabilities: Other current liabilities$25 $— 
Deferred Credit and Other Noncurrent Liabilities: Other
14 — 
Total derivative liabilities$39 $— 
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
 (In millions)
Realized:
Commodity derivative instruments$3 $19 $1 $43 
Realized gains, net
3 19 1 43 
Unrealized:
Commodity derivative instruments(1)(19)(6)61 
Contingent consideration arrangements(12)— (12)— 
Unrealized gains (losses), net(13)(19)(18)61 
Derivative instrument gains (losses), net$(10)$— $(17)$104 
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
v3.24.3
OTHER CURRENT ASSETS
 9 Months Ended
Sep. 30, 2024
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]  
OTHER CURRENT ASSETS OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets:
September 30,
2024
December 31,
2023
 (In millions)
Inventories$501 $453 
Drilling advances60 88 
Current decommissioning security for sold Gulf of Mexico assets167 178 
Prepaid assets and other85 46 
Total Other current assets$813 $765 
v3.24.3
EQUITY METHOD INTERESTS
 9 Months Ended
Sep. 30, 2024
Equity Method Investments and Joint Ventures [Abstract]  
EQUITY METHOD INTERESTS EQUITY METHOD INTERESTS
As of December 31, 2023, the Company held 13.1 million Kinetik Shares, which were recorded at fair value of $437 million and reflected separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik was determined using observable share prices on a major exchange, a Level 1 fair value measurement. On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million.
Prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $9 million in the first quarter of 2024, and a loss of $14 million and a gain of $57 million in the third quarter and the first nine months of 2023, respectively. These changes in fair value were recorded as a component of “Revenues and Other” in the Company’s statement of consolidated operations.
The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
(In millions)
Natural gas and NGLs sales$— $35 $13 $78 
Purchased oil and gas sales— 11 22 18 
$— $46 $35 $96 
Gathering, processing, and transmission costs$— $26 $23 $81 
Purchased oil and gas costs— 37 23 65 
Lease operating expenses— — 2 — 
$— $63 $48 $146 
v3.24.3
OTHER CURRENT LIABILITIES
 9 Months Ended
Sep. 30, 2024
Payables and Accruals [Abstract]  
OTHER CURRENT LIABILITIES OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities:
September 30,
2024
December 31,
2023
 (In millions)
Accrued operating expenses$254 $162 
Accrued exploration and development543 371 
Accrued compensation and benefits189 390 
Accrued interest66 93 
Accrued income taxes144 138 
Current asset retirement obligation75 76 
Current operating lease liability98 116 
Current decommissioning contingency for sold Gulf of Mexico properties94 60 
Other297 338 
Total Other current liabilities$1,760 $1,744 
v3.24.3
ASSET RETIREMENT OBLIGATION
 9 Months Ended
Sep. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]  
ASSET RETIREMENT OBLIGATION ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
September 30,
2024
 (In millions)
Asset retirement obligation, December 31, 2023
$2,438 
Liabilities incurred11 
Liabilities acquired140 
Liabilities settled(47)
Liabilities divested(48)
Liabilities held for sale(224)
Accretion expense112 
Revisions in estimated liabilities195 
Asset retirement obligation, September 30, 2024
2,577 
Less current portion(75)
Asset retirement obligation, long-term$2,502 
v3.24.3
DEBT AND FINANCING COSTS
 9 Months Ended
Sep. 30, 2024
Debt Disclosure [Abstract]  
DEBT AND FINANCING COSTS DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
September 30,
2024
December 31,
2023
(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)
$4,835 $4,835 
Term loan facility, commercial paper, and syndicated credit facilities(2)
1,562 372 
Apache finance lease obligations30 32 
Unamortized discount(25)(26)
Debt issuance costs(30)(25)
Total debt6,372 5,188 
Current maturities(2)(2)
Long-term debt$6,370 $5,186 
(1)    The fair values of the Apache notes and debentures were $4.5 billion and $4.3 billion as of September 30, 2024 and December 31, 2023, respectively.
The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2)    The carrying value of borrowings on the term loan facility, commercial paper and credit facilities approximates fair value because interest rates are variable and reflective of market rates.
At each of September 30, 2024 and December 31, 2023, current debt included $2 million of finance lease obligations.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
Interest expense$109 $89 $302 $266 
Amortization of debt issuance costs1 1 4 3 
Capitalized interest(8)(7)(22)(18)
Gain on extinguishment of debt
— — — (9)
Interest income(2)(2)(8)(7)
Financing costs, net$100 $81 $276 $235 
During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash. The Company recognized a $9 million gain on these repurchases.
Unsecured 2022 Committed Credit Facilities
On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.
•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each of the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.
As of September 30, 2024, there were $232 million of borrowings under the USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement.
Uncommitted Lines of Credit
Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million, respectively, in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million, respectively, in letters of credit outstanding under these facilities.
Commercial Paper Program
In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.
Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
Unsecured Committed Term Loan Facility
On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement. Of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.
On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire.
Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes).
On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon’s 2028 Notes and Callon’s 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:
•Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
•Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.
v3.24.3
INCOME TAXES
 9 Months Ended
Sep. 30, 2024
Income Tax Disclosure [Abstract]  
INCOME TAXES INCOME TAXES
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
The Company’s effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company’s effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction. The Company’s deferred tax asset increased by approximately $575 million as part of the assets assumed through the Callon acquisition. Refer to Note 2—Acquisitions and Divestitures for further detail.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. The Company is continuing to evaluate the proposed regulations and their effect on the Company’s consolidated financial statements.
In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
v3.24.3
COMMITMENTS AND CONTINGENCIES
 9 Months Ended
Sep. 30, 2024
Commitments and Contingencies Disclosure [Abstract]  
COMMITMENTS AND CONTINGENCIES COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2024, the Company has an accrued liability of approximately $18 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Argentine Environmental Claims
On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration 
As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.
Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The consideration paid by the Company in the settlement did not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which was filed by the City of New Orleans against the Company and a number of oil and gas operators.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the State of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. These cases were then consolidated before a single judge in a multi-district litigation (MDL) proceeding. On August 14, 2024, in the MDL, the plaintiffs agreed to dismiss Apache with prejudice from all matters, and a dismissal has been entered by the court.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
Kulp Minerals Lawsuit
On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges, among other things, that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. With no admission, concession, or finding of any fault, liability, or wrongdoing, but only to avoid the expense and uncertainty of litigation, the parties have agreed to a settlement resolving all claims made against the defendants by the class. The settlement agreement has been preliminarily approved by the court, and final approval of the settlement is expected to occur prior to the end of 2024. The settlement will not have a material impact on the Company’s financial position, results of operations, or liquidity and is subject to insurance coverage that companies have for these types of claims.
On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Those cases were consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purported to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserting claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants filed a motion to dismiss the consolidated lawsuits, and on September 26, 2024, the federal court issued a final judgment granting the defendants’ motion and dismissing the consolidated claims against the defendants.
Environmental Matters
As of September 30, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which has been approved and entered by the Court. The consideration provided by the Company in connection with the consent decree, which included a $4 million payment, did not have a material impact on the Company’s financial position.
The Company is not aware of any environmental claims existing as of September 30, 2024, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction in an amount to be determined in a future hearing. That hearing took place on October 24, 2024, although the Court has not yet issued a ruling on the issues addressed, including any award of attorney’s fees to Apache. Apache is vigorously pursuing its claims against the sureties.
As of September 30, 2024, the Company has recorded a $188 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.
The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of “Loss on previously sold Gulf of Mexico properties.” Amounts recorded in the first nine months of 2024 included $50 million related to orders received during the period from BSEE to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.
v3.24.3
CAPITAL STOCK
 9 Months Ended
Sep. 30, 2024
Equity [Abstract]  
CAPITAL STOCK CAPITAL STOCK
Net Income (Loss) per Common Share
The following table presents a reconciliation of the components of basic and diluted net income (loss) per common share in the consolidated financial statements:
 
For the Quarter Ended September 30,
 20242023
 
Loss
SharesPer ShareIncomeSharesPer Share
 (In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
Diluted:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
For the Nine Months Ended September 30,
20242023
IncomeSharesPer ShareIncomeSharesPer Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock$450 348 $1.30 $1,082 309 $3.50 
Effect of Dilutive Securities:
Stock options and other$— — $(0.01)$— — $— 
Diluted:
Income attributable to common stock$450 348 $1.29 $1,082 309 $3.50 
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.9 million and 1.7 million during the third quarters of 2024 and 2023, respectively, and 2.0 million and 2.0 million during the first nine months of 2024 and 2023, respectively.
Stock Repurchase Program
During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. During the third quarter of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock.
In the third quarter of 2024, the Company repurchased approximately 0.1 million shares at an average price of $29.33 per share. For the nine months ended September 30, 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share, and as of September 30, 2024, the Company had remaining authorization to repurchase up to 39.3 million shares. In the third quarter of 2023, the Company repurchased 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share.
The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions.
Common Stock Dividend
For the quarters ended September 30, 2024 and 2023, the Company paid $92 million and $77 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2024 and 2023, the Company paid $260 million and $232 million, respectively, in dividends on its common stock.
Common Stock Issuance
On April 1, 2024, in connection with the Callon acquisition, the Company issued approximately 70 million shares of common stock in exchange for Callon common stock. The total value of stock consideration was approximately $2.4 billion based on APA’s stock price on the closing date of the acquisition.
v3.24.3
BUSINESS SEGMENT INFORMATION
 9 Months Ended
Sep. 30, 2024
Segment Reporting [Abstract]  
BUSINESS SEGMENT INFORMATION BUSINESS SEGMENT INFORMATION
As of September 30, 2024, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: the U.S., Egypt, and North Sea. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:
U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$1,007 $673 $117 $— $1,797 
Natural gas revenues7 81 15 — 103 
Natural gas liquids revenues153 — 5 — 158 
Oil, natural gas, and natural gas liquids production revenues1,167 754 137 — 2,058 
Purchased oil and gas sales473 — — — 473 
1,640 754 137 — 2,531 
Operating Expenses:
Lease operating expenses222 109 87 — 418 
Gathering, processing, and transmission110 6 7 — 123 
Purchased oil and gas costs292 — — — 292 
Taxes other than income70 — — — 70 
Exploration(1)21 — 9 29 
Depreciation, depletion, and amortization355 167 73 — 595 
Asset retirement obligation accretion10 — 26 — 36 
Impairments315 — 796 — 1,111 
1,373 303 989 9 2,674 
Operating Income (Loss)(2)
$267 $451 $(852)$(9)(143)
Other Income (Expense):
Derivative instrument losses, net
(10)
Gain on divestitures, net1 
Other, net18 
General and administrative(92)
Transaction, reorganization, and separation(14)
Financing costs, net(100)
Loss Before Income Taxes
$(340)

U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$2,616 $2,003 $517 $— $5,136 
Natural gas revenues79 231 104 — 414 
Natural gas liquids revenues436 — 21 — 457 
Oil, natural gas, and natural gas liquids production revenues3,131 2,234 642 — 6,007 
Purchased oil and gas sales1,018 — — — 1,018 
4,149 2,234 642 — 7,025 
Operating Expenses:
Lease operating expenses582 352 282 — 1,216 
Gathering, processing, and transmission272 19 37 — 328 
Purchased oil and gas costs665 — — — 665 
Taxes other than income205 — — — 205 
Exploration107 77 1 63 248 
Depreciation, depletion, and amortization930 464 219 — 1,613 
Asset retirement obligation accretion35 — 77 — 112 
Impairments315 — 796 — 1,111 
3,111 912 1,412 63 5,498 
Operating Income (Loss)(2)
$1,038 $1,322 $(770)$(63)1,527 
Other Income (Expense):
Derivative instrument losses, net
(17)
Loss on offshore decommissioning contingency(83)
Gain on divestitures, net284 
Other, net26 
General and administrative(270)
Transaction, reorganization, and separation(156)
Financing costs, net(276)
Income Before Income Taxes$1,035 
Total Assets(3)
$13,847 $3,525 $1,439 $565 $19,376 
U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$633 $724 $348 $— $1,705 
Natural gas revenues89 81 66 — 236 
Natural gas liquids revenues133 — 5 — 138 
Oil, natural gas, and natural gas liquids production revenues855 805 419 — 2,079 
Purchased oil and gas sales229 — — — 229 
1,084 805 419 — 2,308 
Operating Expenses:
Lease operating expenses164 128 102 — 394 
Gathering, processing, and transmission61 13 15 — 89 
Purchased oil and gas costs211 — — — 211 
Taxes other than income61 — — — 61 
Exploration4 25 9 11 49 
Depreciation, depletion, and amortization199 129 90 — 418 
Asset retirement obligation accretion9 — 20 — 29 
709 295 236 11 1,251 
Operating Income (Loss)(2)
$375 $510 $183 $(11)1,057 
Other Income (Expense):
Gain on divestitures, net
1 
General and administrative(139)
Transaction, reorganization, and separation(5)
Financing costs, net(81)
Income Before Income Taxes$833 

U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$1,631 $1,971 $865 $— $4,467 
Natural gas revenues229 264 165 — 658 
Natural gas liquids revenues356 — 19 — 375 
Oil, natural gas, and natural gas liquids production revenues2,216 2,235 1,049 — 5,500 
Purchased oil and gas sales612 — — — 612 
2,828 2,235 1,049 — 6,112 
Operating Expenses:
Lease operating expenses452 346 278 — 1,076 
Gathering, processing, and transmission181 26 38 — 245 
Purchased oil and gas costs558 — — — 558 
Taxes other than income163 — — — 163 
Exploration10 91 18 25 144 
Depreciation, depletion, and amortization530 378 209 — 1,117 
Asset retirement obligation accretion29 — 57 — 86 
Impairments— — 46 — 46 
1,923 841 646 25 3,435 
Operating Income (Loss)(2)
$905 $1,394 $403 $(25)2,677 
Other Income (Expense):
Derivative instrument gains, net
104 
Gain on divestitures, net7 
Other, net77 
General and administrative(276)
Transaction, reorganization, and separation(11)
Financing costs, net(235)
Income Before Income Taxes$2,343 
Total Assets(3)
$7,827 $3,518 $1,665 $535 $13,545 
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2024 and 2023 of:
For the Quarter Ended September 30,
For the Nine Months Ended September 30,
 2024202320242023
(In millions)
Oil$182 $202 $533 $539 
Natural gas22 23 63 73 
(2)Operating loss of Suriname includes leasehold impairments of $1 million for the third quarter of 2024.
Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income (loss) of U.S. and Suriname includes leasehold impairments of $10 million and $1 million, respectively, for the first nine months of 2024. Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests in Egypt.
v3.24.3
Insider Trading Arrangements
 3 Months Ended
Sep. 30, 2024
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.24.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 9 Months Ended
Sep. 30, 2024
Accounting Policies [Abstract]  
Principles of Consolidation
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. During the nine months ended September 30, 2023 and the quarter ended March 31, 2024, the Company had a designated director on the Kinetik Holdings Inc. (Kinetik) board of directors. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024. As a result, the Company is considered to have had significant influence over Kinetik during the periods presented prior to the designated director’s resignation from the Kinetik board of directors.
As of December 31, 2023, the Company held shares of Kinetik Class A Common Stock (Kinetik Shares), which were recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. On March 18, 2024, the Company sold its remaining Kinetik Shares.
Use of Estimates
Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
Fair Value Measurements
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Revenue Recognition
Revenue Recognition
Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.5 billion at each of September 30, 2024 and December 31, 2023. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. In the past year, the Company’s receivable balance from the Egyptian General Petroleum Corporation (EGPC) has gradually increased as payments for the Company’s Egyptian oil and gas sales have been delayed for periods longer than historically experienced. The Company is actively engaged in discussions with the Government of Egypt to resolve the delay in EGPC payments. The Company has received payments throughout the period, and management believes that the Company will be able to collect the total balance of its receivables from this customer.
Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Inventories
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
Property and Equipment
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, production costs, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities, and if management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The change in cessation-of-production dates in the North Sea discussed above in “Fair Value Measurements” significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $793 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million.
Additionally, in the third quarter of 2024, the Company recorded impairments totaling $315 million in connection with an agreement to sell certain non-core producing properties in the Permian Basin. These impairments are discussed in further detail above in “Fair Value Measurements” and in Note 2—Acquisitions and Divestitures. The associated U.S. properties had an aggregate fair value of $1.1 billion as of September 30, 2024.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.
Gathering, Processing, and Transmission (GPT) Facilities
Gathering, Processing, and Transmission (GPT) Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
New Pronouncements Issued But Not Yet Adopted
New Pronouncements Issued But Not Yet Adopted
In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.
v3.24.3
ACQUISITIONS AND DIVESTITURES (Tables)
 9 Months Ended
Sep. 30, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
Schedule of Assets Acquired and Liabilities Assumed
The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the merger:
(In millions)
Current assets
$282 
Property, plant, and equipment
4,493 
Deferred tax asset
575 
Other assets11 
Total assets acquired$5,361 
Current liabilities$616 
Long-term debt
2,113 
Asset retirement obligation136 
Other long-term obligations58 
Total liabilities assumed$2,923 
Net assets acquired$2,438 
Schedule of Pro Forma Adjustment
The following unaudited pro forma combined results for the three and nine months ended September 30, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, interest expense, gain on derivatives related to a previous Callon acquisition, and estimated tax impacts of the pro forma adjustments.
For the Quarter Ended
September 30,		For the Nine Months Ended
September 30,
2024202320242023
(In millions, except share data)
Revenues
$2,531 $2,927 $7,589 $7,810 
Net income (loss) attributable to common stock
(223)737 556 1,527 
Net income (loss) per common share – basic
(0.60)1.95 1.50 4.04 
Net income (loss) per common share – diluted
(0.60)1.95 1.50 4.04 
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)
 9 Months Ended
Sep. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Commodity Derivative Positions
As of September 30, 2024, the Company had the following open natural gas financial collar contracts:
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Floor PriceWeighted Average Ceiling Price
October—December 2024
NYMEX Henry Hub
1,654$3.00$3.33
As of September 30, 2024, the Company had the following open natural gas financial basis swap contracts:
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Price DifferentialMMBtu
(in 000’s)		Weighted Average Price Differential
October—December 2024
NYMEX Henry Hub/IF Waha——1,840$(1.06)
October—December 2024
NYMEX Henry Hub/IF HSC——3,680$(0.42)
As of September 30, 2024, the Company had the following open NGL fixed swap contracts:
Production PeriodSettlement Index
MBbls
(in 000’s)
Weighted Average Price Differential
October—December 2024
OPIS IsoButane Mt Belvieu Non TET
6$33.18
October—December 2024
OPIS NButane Mt Belvieu Non TET
17$33.18
Schedule of Derivative Assets Measured at Fair Value
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)		Significant Other Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
September 30, 2024
Assets:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 10 — 10 — 10 
Liabilities:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 39 — 39 — 39 
December 31, 2023
Assets:
Commodity derivative instruments$— $6 $— $6 $— $6 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
Schedule of Derivative Liabilities Measured at Fair Value
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)		Significant Other Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
September 30, 2024
Assets:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 10 — 10 — 10 
Liabilities:
Commodity derivative instruments$— $1 $— $1 $(1)$— 
Contingent consideration arrangements
— 39 — 39 — 39 
December 31, 2023
Assets:
Commodity derivative instruments$— $6 $— $6 $— $6 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
September 30,
2024
December 31,
2023
(In millions)
Current Assets: Other current assets$10 $6 
Total derivative assets$10 $6 
Current Liabilities: Other current liabilities$25 $— 
Deferred Credit and Other Noncurrent Liabilities: Other
14 — 
Total derivative liabilities$39 $— 
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
 (In millions)
Realized:
Commodity derivative instruments$3 $19 $1 $43 
Realized gains, net
3 19 1 43 
Unrealized:
Commodity derivative instruments(1)(19)(6)61 
Contingent consideration arrangements(12)— (12)— 
Unrealized gains (losses), net(13)(19)(18)61 
Derivative instrument gains (losses), net$(10)$— $(17)$104 
v3.24.3
OTHER CURRENT ASSETS (Tables)
 9 Months Ended
Sep. 30, 2024
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]  
Schedule of Other Current Assets
The following table provides detail of the Company’s other current assets:
September 30,
2024
December 31,
2023
 (In millions)
Inventories$501 $453 
Drilling advances60 88 
Current decommissioning security for sold Gulf of Mexico assets167 178 
Prepaid assets and other85 46 
Total Other current assets$813 $765 
v3.24.3
EQUITY METHOD INTERESTS (Tables)
 9 Months Ended
Sep. 30, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of Sales and Costs Associated With Equity Method Interests
The following table represents related party sales and costs associated with Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2024202320242023
(In millions)
Natural gas and NGLs sales$— $35 $13 $78 
Purchased oil and gas sales— 11 22 18 
$— $46 $35 $96 
Gathering, processing, and transmission costs$— $26 $23 $81 
Purchased oil and gas costs— 37 23 65 
Lease operating expenses— — 2 — 
$— $63 $48 $146 
v3.24.3
OTHER CURRENT LIABILITIES (Tables)
 9 Months Ended
Sep. 30, 2024
Payables and Accruals [Abstract]  
Schedule of Other Current Liabilities
The following table provides detail of the Company’s other current liabilities:
September 30,
2024
December 31,
2023
 (In millions)
Accrued operating expenses$254 $162 
Accrued exploration and development543 371 
Accrued compensation and benefits189 390 
Accrued interest66 93 
Accrued income taxes144 138 
Current asset retirement obligation75 76 
Current operating lease liability98 116 
Current decommissioning contingency for sold Gulf of Mexico properties94 60 
Other297 338 
Total Other current liabilities$1,760 $1,744 
v3.24.3
ASSET RETIREMENT OBLIGATION (Tables)
 9 Months Ended
Sep. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Asset Retirement Obligation
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
September 30,
2024
 (In millions)
Asset retirement obligation, December 31, 2023
$2,438 
Liabilities incurred11 
Liabilities acquired140 
Liabilities settled(47)
Liabilities divested(48)
Liabilities held for sale(224)
Accretion expense112 
Revisions in estimated liabilities195 
Asset retirement obligation, September 30, 2024
2,577 
Less current portion(75)
Asset retirement obligation, long-term$2,502 
v3.24.3
DEBT AND FINANCING COSTS (Tables)
 9 Months Ended
Sep. 30, 2024
Debt Disclosure [Abstract]  
Schedule of Debt
The following table presents the carrying values of the Company’s debt:
September 30,
2024
December 31,
2023
(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)
$4,835 $4,835 
Term loan facility, commercial paper, and syndicated credit facilities(2)
1,562 372 
Apache finance lease obligations30 32 
Unamortized discount(25)(26)
Debt issuance costs(30)(25)
Total debt6,372 5,188 
Current maturities(2)(2)
Long-term debt$6,370 $5,186 
(1)    The fair values of the Apache notes and debentures were $4.5 billion and $4.3 billion as of September 30, 2024 and December 31, 2023, respectively.
The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2)    The carrying value of borrowings on the term loan facility, commercial paper and credit facilities approximates fair value because interest rates are variable and reflective of market rates.
Schedule Of Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2024202320242023
 (In millions)
Interest expense$109 $89 $302 $266 
Amortization of debt issuance costs1 1 4 3 
Capitalized interest(8)(7)(22)(18)
Gain on extinguishment of debt
— — — (9)
Interest income(2)(2)(8)(7)
Financing costs, net$100 $81 $276 $235 
v3.24.3
CAPITAL STOCK (Tables)
 9 Months Ended
Sep. 30, 2024
Equity [Abstract]  
Schedule Reconciliation of the Components of Basic and Diluted Net Income (Loss) Per Common Share
The following table presents a reconciliation of the components of basic and diluted net income (loss) per common share in the consolidated financial statements:
 
For the Quarter Ended September 30,
 20242023
 
Loss
SharesPer ShareIncomeSharesPer Share
 (In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
Diluted:
Income (loss) attributable to common stock
$(223)370 $(0.60)$459 308 $1.49 
For the Nine Months Ended September 30,
20242023
IncomeSharesPer ShareIncomeSharesPer Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock$450 348 $1.30 $1,082 309 $3.50 
Effect of Dilutive Securities:
Stock options and other$— — $(0.01)$— — $— 
Diluted:
Income attributable to common stock$450 348 $1.29 $1,082 309 $3.50 
v3.24.3
BUSINESS SEGMENT INFORMATION (Tables)
 9 Months Ended
Sep. 30, 2024
Segment Reporting [Abstract]  
Schedule of Financial Segment Information Financial information for each segment is presented below:
U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$1,007 $673 $117 $— $1,797 
Natural gas revenues7 81 15 — 103 
Natural gas liquids revenues153 — 5 — 158 
Oil, natural gas, and natural gas liquids production revenues1,167 754 137 — 2,058 
Purchased oil and gas sales473 — — — 473 
1,640 754 137 — 2,531 
Operating Expenses:
Lease operating expenses222 109 87 — 418 
Gathering, processing, and transmission110 6 7 — 123 
Purchased oil and gas costs292 — — — 292 
Taxes other than income70 — — — 70 
Exploration(1)21 — 9 29 
Depreciation, depletion, and amortization355 167 73 — 595 
Asset retirement obligation accretion10 — 26 — 36 
Impairments315 — 796 — 1,111 
1,373 303 989 9 2,674 
Operating Income (Loss)(2)
$267 $451 $(852)$(9)(143)
Other Income (Expense):
Derivative instrument losses, net
(10)
Gain on divestitures, net1 
Other, net18 
General and administrative(92)
Transaction, reorganization, and separation(14)
Financing costs, net(100)
Loss Before Income Taxes
$(340)

U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2024
(In millions)
Revenues:
Oil revenues$2,616 $2,003 $517 $— $5,136 
Natural gas revenues79 231 104 — 414 
Natural gas liquids revenues436 — 21 — 457 
Oil, natural gas, and natural gas liquids production revenues3,131 2,234 642 — 6,007 
Purchased oil and gas sales1,018 — — — 1,018 
4,149 2,234 642 — 7,025 
Operating Expenses:
Lease operating expenses582 352 282 — 1,216 
Gathering, processing, and transmission272 19 37 — 328 
Purchased oil and gas costs665 — — — 665 
Taxes other than income205 — — — 205 
Exploration107 77 1 63 248 
Depreciation, depletion, and amortization930 464 219 — 1,613 
Asset retirement obligation accretion35 — 77 — 112 
Impairments315 — 796 — 1,111 
3,111 912 1,412 63 5,498 
Operating Income (Loss)(2)
$1,038 $1,322 $(770)$(63)1,527 
Other Income (Expense):
Derivative instrument losses, net
(17)
Loss on offshore decommissioning contingency(83)
Gain on divestitures, net284 
Other, net26 
General and administrative(270)
Transaction, reorganization, and separation(156)
Financing costs, net(276)
Income Before Income Taxes$1,035 
Total Assets(3)
$13,847 $3,525 $1,439 $565 $19,376 
U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$633 $724 $348 $— $1,705 
Natural gas revenues89 81 66 — 236 
Natural gas liquids revenues133 — 5 — 138 
Oil, natural gas, and natural gas liquids production revenues855 805 419 — 2,079 
Purchased oil and gas sales229 — — — 229 
1,084 805 419 — 2,308 
Operating Expenses:
Lease operating expenses164 128 102 — 394 
Gathering, processing, and transmission61 13 15 — 89 
Purchased oil and gas costs211 — — — 211 
Taxes other than income61 — — — 61 
Exploration4 25 9 11 49 
Depreciation, depletion, and amortization199 129 90 — 418 
Asset retirement obligation accretion9 — 20 — 29 
709 295 236 11 1,251 
Operating Income (Loss)(2)
$375 $510 $183 $(11)1,057 
Other Income (Expense):
Gain on divestitures, net
1 
General and administrative(139)
Transaction, reorganization, and separation(5)
Financing costs, net(81)
Income Before Income Taxes$833 

U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
For the Nine Months Ended September 30, 2023
(In millions)
Revenues:
Oil revenues$1,631 $1,971 $865 $— $4,467 
Natural gas revenues229 264 165 — 658 
Natural gas liquids revenues356 — 19 — 375 
Oil, natural gas, and natural gas liquids production revenues2,216 2,235 1,049 — 5,500 
Purchased oil and gas sales612 — — — 612 
2,828 2,235 1,049 — 6,112 
Operating Expenses:
Lease operating expenses452 346 278 — 1,076 
Gathering, processing, and transmission181 26 38 — 245 
Purchased oil and gas costs558 — — — 558 
Taxes other than income163 — — — 163 
Exploration10 91 18 25 144 
Depreciation, depletion, and amortization530 378 209 — 1,117 
Asset retirement obligation accretion29 — 57 — 86 
Impairments— — 46 — 46 
1,923 841 646 25 3,435 
Operating Income (Loss)(2)
$905 $1,394 $403 $(25)2,677 
Other Income (Expense):
Derivative instrument gains, net
104 
Gain on divestitures, net7 
Other, net77 
General and administrative(276)
Transaction, reorganization, and separation(11)
Financing costs, net(235)
Income Before Income Taxes$2,343 
Total Assets(3)
$7,827 $3,518 $1,665 $535 $13,545 
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2024 and 2023 of:
For the Quarter Ended September 30,
For the Nine Months Ended September 30,
 2024202320242023
(In millions)
Oil$182 $202 $533 $539 
Natural gas22 23 63 73 
(2)Operating loss of Suriname includes leasehold impairments of $1 million for the third quarter of 2024.
Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income (loss) of U.S. and Suriname includes leasehold impairments of $10 million and $1 million, respectively, for the first nine months of 2024. Operating income (loss) of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests in Egypt.
v3.24.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($)
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Dec. 31, 2023
Schedule Of Significant Accounting Policies [Line Items]          
Other asset impairments   $ 0   $ 0  
Receivables from contracts with customer, net $ 1,500,000,000   $ 1,500,000,000   $ 1,500,000,000
Inventory write-down 3,000,000   3,000,000 46,000,000  
Transaction, reorganization, and separation 14,000,000 $ 5,000,000 156,000,000 $ 11,000,000  
Callon Acquisition          
Schedule Of Significant Accounting Policies [Line Items]          
Transaction, reorganization, and separation     139,000,000    
Separation costs          
Schedule Of Significant Accounting Policies [Line Items]          
Transaction, reorganization, and separation     71,000,000    
Consulting fees          
Schedule Of Significant Accounting Policies [Line Items]          
Transaction, reorganization, and separation     68,000,000    
North Sea | Oil and Gas Properties, Proved          
Schedule Of Significant Accounting Policies [Line Items]          
Impairments 793,000,000        
Oil and gas property impaired, fair value 263,000,000   263,000,000    
Permian Basin | Oil and Gas Properties, Proved          
Schedule Of Significant Accounting Policies [Line Items]          
Impairments 315,000,000        
UNITED STATES | Oil and Gas Properties, Proved          
Schedule Of Significant Accounting Policies [Line Items]          
Oil and gas property impaired, fair value $ 1,100,000,000   $ 1,100,000,000    
Sinopec | Apache Egypt          
Schedule Of Significant Accounting Policies [Line Items]          
Ownership percentage by noncontrolling owners 33.33%   33.33%    
v3.24.3
ACQUISITIONS AND DIVESTITURES - Additional Information (Details)
shares in Millions
 3 Months Ended 6 Months Ended 9 Months Ended
Sep. 10, 2024
USD ($)
Boe
Apr. 01, 2024
USD ($)
a
shares
Mar. 18, 2024
USD ($)
Sep. 30, 2024
USD ($)
Sep. 30, 2023
USD ($)
Sep. 30, 2024
USD ($)
Sep. 30, 2024
USD ($)
Sep. 30, 2023
USD ($)
Dec. 31, 2023
USD ($)
Business Acquisition [Line Items]                  
Proceeds from asset divestitures             $ 724,000,000 $ 29,000,000  
Liabilities held for sale       $ 224,000,000   $ 224,000,000 224,000,000   $ 0
Assets held for sale       1,091,000,000   1,091,000,000 1,091,000,000   $ 0
Proceeds from sale of Kinetik Shares             428,000,000 0  
Payments to acquire leasehold and property       1,000,000     64,000,000 11,000,000  
Kinetik                  
Business Acquisition [Line Items]                  
Proceeds from sale of Kinetik Shares     $ 428,000,000            
Disposed of by Sale | Non-Core Assets And Leasehold                  
Business Acquisition [Line Items]                  
Proceeds from asset divestitures       1,000,000 $ 1,000,000   73,000,000 29,000,000  
Gain (loss) on sale of oil and gas properties       (1,000,000) (1,000,000)   (9,000,000) (7,000,000)  
Unsecured Debt | Term Loan Credit Agreement, Three Year Tranche Loans                  
Business Acquisition [Line Items]                  
Debt instrument, face amount   $ 1,500,000,000              
Permian Basin                  
Business Acquisition [Line Items]                  
Production of barrels of oil | Boe 21,000                
Percentage of barrels of oil equivalent 57.00%                
Payments to acquire leasehold and property         $ 1,000,000     $ 11,000,000  
Permian Basin | Oil and Gas Properties, Proved                  
Business Acquisition [Line Items]                  
Impairments       315,000,000          
Permian Basin | Disposal Group, Held-for-Sale, Not Discontinued Operations                  
Business Acquisition [Line Items]                  
Proceeds from asset divestitures $ 950,000,000                
Cash deposit       95,000,000          
Permian Basin | Disposed of by Sale                  
Business Acquisition [Line Items]                  
Proceeds from asset divestitures             392,000,000    
Assets held-for-sale, fair value 1,100,000,000                
Liabilities held for sale       224,000,000   224,000,000 224,000,000    
Assets held for sale       224,000,000   224,000,000 224,000,000    
Carrying value of non-core assets disposed       71,000,000   71,000,000 71,000,000    
Gain (loss) on sale of oil and gas properties             (321,000,000)    
Permian Basin | Disposed of by Sale | Oil and Gas Properties, Proved                  
Business Acquisition [Line Items]                  
Impairments $ 315,000,000                
TEXAS | Disposed of by Sale                  
Business Acquisition [Line Items]                  
Proceeds from asset divestitures             253,000,000    
Carrying value of non-core assets disposed       $ 347,000,000   347,000,000 347,000,000    
Asset retirement obligation assumed             48,000,000    
Gain (loss) on sale of oil and gas properties             $ 46,000,000    
Callon Petroleum Company                  
Business Acquisition [Line Items]                  
Consideration transferred   $ 4,500,000,000              
Business acquisition, equity interests exchange ratio   1.0425              
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares   70              
Other consideration transferred   $ 24,000,000              
Revenue of acquiree since acquisition date           840,000,000      
Net income of acquiree since acquisition date           $ 192,000,000      
Callon Petroleum Company | Delaware Basin                  
Business Acquisition [Line Items]                  
Asset acquired, net acres | a   120,000              
Callon Petroleum Company | Midland Basin                  
Business Acquisition [Line Items]                  
Asset acquired, net acres | a   25,000              
v3.24.3
ACQUISITIONS AND DIVESTITURES - Schedule of Assets Acquired and Liabilities Assumed (Details) - Callon Petroleum Company
$ in Millions
Apr. 01, 2024
USD ($)
Business Acquisition [Line Items]  
Current assets $ 282
Property, plant, and equipment 4,493
Deferred tax asset 575
Other assets 11
Total assets acquired 5,361
Current liabilities 616
Long-term debt 2,113
Asset retirement obligation 136
Other long-term obligations 58
Total liabilities assumed 2,923
Net assets acquired $ 2,438
v3.24.3
ACQUISITIONS AND DIVESTITURES - Schedule of Pro Forma Adjustment (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]        
Revenues $ 2,531 $ 2,927 $ 7,589 $ 7,810
Net income (loss) attributable to common stock $ (223) $ 737 $ 556 $ 1,527
Net income (loss) per common share – basic (in USD per share) $ (0.60) $ 1.95 $ 1.50 $ 4.04
Net income (loss) per common share – diluted (in USD per share) $ (0.60) $ 1.95 $ 1.50 $ 4.04
v3.24.3
CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Extractive Industries [Abstract]    
Capitalized exploratory well costs $ 611 $ 586
Exploratory well costs capitalized for a period greater than one year $ 51 $ 0
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)
$ in Millions
 9 Months Ended
Sep. 30, 2024
USD ($)
counterparty
Apr. 01, 2024
USD ($)
$ / bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Number of derivative counterparty | counterparty 1  
Callon Petroleum Company    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Estimated fair value of earn-out obligation $ 39  
Estimated fair value of contingent consideration receipt $ 10  
Callon Petroleum Company | Contingent consideration arrangements | Average Daily Settlement Price OF WTI Crude Oil Threshold High    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Earn-out obligation to be paid (up to)   $ 50
Crude oil settlement price threshold, contingent consideration liability (in dollars per barrel) | $ / bbl   60.00
Crude oil settlement price threshold, contingent consideration asset (in dollars per barrel) | $ / bbl   80.00
Callon Petroleum Company | Contingent consideration arrangements | Average Daily Settlement Price OF WTI Crude Oil Threshold Low    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Contingent consideration to be received   $ 20
Callon Petroleum Company | Contingent consideration arrangements | Maximum | Average Daily Settlement Price OF WTI Crude Oil Threshold High    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Contingent consideration to be received   $ 45
Callon Petroleum Company | Contingent consideration arrangements | Maximum | Average Daily Settlement Price OF WTI Crude Oil Threshold Low    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Crude oil settlement price threshold, contingent consideration asset (in dollars per barrel) | $ / bbl   80.00
Callon Petroleum Company | Contingent consideration arrangements | Minimum | Average Daily Settlement Price OF WTI Crude Oil Threshold Low    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Crude oil settlement price threshold, contingent consideration asset (in dollars per barrel) | $ / bbl   75.00
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Open Natural Gas Financial Basis Swap Contracts (Details) - October—December 2024
MMBTU in Thousands
 9 Months Ended
Sep. 30, 2024
$ / MMBTU
MMBTU
Collar Contracts | Natural gas revenues | NYMEX Henry Hub  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 1,654
Weighted Average Floor Price (in USD per MMBtu ) 3.00
Weighted Average Ceiling Price (in USD per MMBtu ) 3.33
Basis Swap Purchased | Natural gas revenues | NYMEX Henry Hub/IF Waha  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 0
Weighted average price differential (in USD per MMBtu ) 0
Basis Swap Purchased | Natural gas revenues | NYMEX Henry Hub/IF HSC  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 0
Weighted average price differential (in USD per MMBtu ) 0
Basis Swap Sold | Natural gas revenues | NYMEX Henry Hub/IF Waha  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 1,840
Weighted average price differential (in USD per MMBtu ) (1.06)
Basis Swap Sold | Natural gas revenues | NYMEX Henry Hub/IF HSC  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 3,680
Weighted average price differential (in USD per MMBtu ) (0.42)
Fixed Swap Contracts | Natural gas liquids revenues | OPIS IsoButane Mt Belvieu Non TET  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 6
Weighted average price differential (in USD per MMBtu ) 33.18
Fixed Swap Contracts | Natural gas liquids revenues | OPIS NButane Mt Belvieu Non TET  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU 17
Weighted average price differential (in USD per MMBtu ) 33.18
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Assets:    
Total derivative assets $ 10 $ 6
Liabilities:    
Total derivative liabilities 39 0
Recurring | Commodity derivative instruments    
Assets:    
Derivative asset, fair value 1 6
Derivative asset, netting (1) 0
Total derivative assets 0 6
Liabilities:    
Derivative liability, fair value 1  
Derivative liability, netting (1)  
Total derivative liabilities 0  
Recurring | Contingent consideration arrangements    
Assets:    
Derivative asset, fair value 10  
Derivative asset, netting 0  
Total derivative assets 10  
Liabilities:    
Derivative liability, fair value 39  
Derivative liability, netting 0  
Total derivative liabilities 39  
Recurring | Quoted Price in Active Markets (Level 1) | Commodity derivative instruments    
Assets:    
Derivative asset, fair value 0 0
Liabilities:    
Derivative liability, fair value 0  
Recurring | Quoted Price in Active Markets (Level 1) | Contingent consideration arrangements    
Assets:    
Derivative asset, fair value 0  
Liabilities:    
Derivative liability, fair value 0  
Recurring | Significant Other Inputs (Level 2) | Commodity derivative instruments    
Assets:    
Derivative asset, fair value 1 6
Liabilities:    
Derivative liability, fair value 1  
Recurring | Significant Other Inputs (Level 2) | Contingent consideration arrangements    
Assets:    
Derivative asset, fair value 10  
Liabilities:    
Derivative liability, fair value 39  
Recurring | Significant Unobservable Inputs (Level 3) | Commodity derivative instruments    
Assets:    
Derivative asset, fair value 0 $ 0
Liabilities:    
Derivative liability, fair value 0  
Recurring | Significant Unobservable Inputs (Level 3) | Contingent consideration arrangements    
Assets:    
Derivative asset, fair value 0  
Liabilities:    
Derivative liability, fair value $ 0  
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]    
Current Assets: Other current assets $ 10 $ 6
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Other current assets (Note 5) Other current assets (Note 5)
Total derivative assets $ 10 $ 6
Current Liabilities: Other current liabilities 25 0
Deferred Credit and Other Noncurrent Liabilities: Other $ 14 $ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration] Other Liabilities, Current Other Liabilities, Current
Total derivative liabilities $ 39 $ 0
v3.24.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Derivative Instruments, Gain (Loss) [Line Items]        
Realized gains, net $ 3 $ 19 $ 1 $ 43
Unrealized gains (losses), net (13) (19) (18) 61
Derivative instrument gains (losses), net (10) 0 (17) 104
Commodity derivative instruments        
Derivative Instruments, Gain (Loss) [Line Items]        
Realized gains, net 3 19 1 43
Unrealized gains (losses), net (1) (19) (6) 61
Contingent consideration arrangements        
Derivative Instruments, Gain (Loss) [Line Items]        
Unrealized gains (losses), net $ (12) $ 0 $ (12) $ 0
v3.24.3
OTHER CURRENT ASSETS (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]    
Inventories $ 501 $ 453
Drilling advances 60 88
Current decommissioning security for sold Gulf of Mexico assets 167 178
Prepaid assets and other 85 46
Total Other current assets $ 813 $ 765
v3.24.3
EQUITY METHOD INTERESTS - Additional Information (Details) - USD ($)
shares in Millions, $ in Millions
 3 Months Ended 9 Months Ended
Mar. 18, 2024
Mar. 31, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]            
Equity method interests       $ 0   $ 437
Proceeds from sale of Kinetik Shares       $ 428 $ 0  
Kinetik            
Schedule of Equity Method Investments [Line Items]            
Equity method investment, number of shares (in shares)           13.1
Equity method interests           $ 437
Proceeds from sale of Kinetik Shares $ 428          
Gain (loss) on changes in fair value of equity method interest   $ (9) $ (14)   $ 57  
v3.24.3
EQUITY METHOD INTERESTS - Sales and Costs Associated with Equity Method Interests (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Schedule of Equity Method Investments [Line Items]        
Lease operating expenses [1] $ 418 $ 394 $ 1,216 $ 1,076
Total operating expenses 2,880 1,476 6,200 3,957
Kinetik        
Schedule of Equity Method Investments [Line Items]        
Total revenues 0 46 35 96
Lease operating expenses 0 0 2 0
Total operating expenses 0 63 48 146
Oil and gas, excluding purchased        
Schedule of Equity Method Investments [Line Items]        
Total revenues [1] 2,058 2,079 6,007 5,500
Costs [1] 123 89 328 245
Oil and gas, excluding purchased | Kinetik        
Schedule of Equity Method Investments [Line Items]        
Total revenues 0 35 13 78
Costs 0 26 23 81
Purchased oil and gas        
Schedule of Equity Method Investments [Line Items]        
Total revenues [1] 473 229 1,018 612
Costs [1] 292 211 665 558
Purchased oil and gas | Kinetik        
Schedule of Equity Method Investments [Line Items]        
Total revenues 0 11 22 18
Costs $ 0 $ 37 $ 23 $ 65
[1] For transactions with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests.
v3.24.3
OTHER CURRENT LIABILITIES (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Payables and Accruals [Abstract]    
Accrued operating expenses $ 254 $ 162
Accrued exploration and development 543 371
Accrued compensation and benefits 189 390
Accrued interest 66 93
Accrued income taxes 144 138
Current asset retirement obligation 75 76
Current operating lease liability 98 116
Current decommissioning contingency for sold Gulf of Mexico properties 94 60
Other 297 338
Total Other current liabilities $ 1,760 $ 1,744
v3.24.3
ASSET RETIREMENT OBLIGATION (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]          
Asset retirement obligation at the beginning of period     $ 2,438    
Liabilities incurred     11    
Liabilities acquired     140    
Liabilities settled     (47)    
Liabilities divested     (48)    
Liabilities held for sale     (224)    
Accretion expense $ 36 $ 29 112 $ 86  
Revisions in estimated liabilities     195    
Asset retirement obligation at the end of period 2,577   2,577    
Less current portion (75)   (75)   $ (76)
Asset retirement obligation, long-term $ 2,502   $ 2,502   $ 2,362
v3.24.3
DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($)
$ in Millions
Sep. 30, 2024
Dec. 31, 2023
Debt Instrument [Line Items]    
Apache finance lease obligations $ 30 $ 32
Unamortized discount (25) (26)
Debt issuance costs (30) (25)
Total debt 6,372 5,188
Current maturities (2) (2)
Long-term debt 6,370 5,186
Apache notes and debentures    
Debt Instrument [Line Items]    
Long-term debt, gross 4,835 4,835
Debt instrument, fair value 4,500 4,300
Term loan facility, commercial paper, and syndicated credit facilities    
Debt Instrument [Line Items]    
Long-term debt, gross $ 1,562 $ 372
v3.24.3
DEBT AND FINANCING COSTS - Additional Information (Details)
 1 Months Ended 3 Months Ended 9 Months Ended
May 06, 2024
USD ($)
Apr. 01, 2024
USD ($)
Jan. 30, 2024
USD ($)
Apr. 29, 2022
USD ($)
creditAgreement
option
Dec. 31, 2023
USD ($)
Sep. 30, 2024
USD ($)
Sep. 30, 2023
USD ($)
Sep. 30, 2024
USD ($)
Sep. 30, 2023
USD ($)
Sep. 30, 2024
GBP (£)
Dec. 31, 2023
GBP (£)
Apr. 29, 2022
GBP (£)
creditAgreement
Debt Instrument [Line Items]                        
Finance lease obligations, current         $ 2,000,000 $ 2,000,000   $ 2,000,000        
Gain on extinguishment of debt           0 $ 0 0 $ 9,000,000      
Commercial paper                        
Debt Instrument [Line Items]                        
Debt instrument term         397 days              
Debt instrument, face amount         $ 1,800,000,000              
Debt instrument guarantee terms, benchmark amount (less than)         1,000,000,000              
Commercial paper         0 330,000,000   330,000,000        
Syndicated credit facility | Unsecured Debt                        
Debt Instrument [Line Items]                        
Number of syndicated credit agreements | creditAgreement       2               2
USD Agreement | Line of Credit                        
Debt Instrument [Line Items]                        
Number of credit agreements denominated in US dollars | creditAgreement       1               1
Debt instrument term       5 years                
Line of credit facility, committed amount       $ 1,800,000,000                
Line of credit facility, increased committed amount       $ 2,300,000,000                
Line of credit facility, number of extension options | option       2                
Debt extension term       1 year                
Credit facility outstanding amount         372,000,000 232,000,000   232,000,000        
USD Agreement | Line of Credit | Apache Corp                        
Debt Instrument [Line Items]                        
Credit facility maximum borrowing capacity       $ 300,000,000                
USD Agreement | Line of Credit | Letter of Credit                        
Debt Instrument [Line Items]                        
Credit facility maximum borrowing capacity       750,000,000                
Line of credit facility, current borrowing capacity       $ 150,000,000                
Line of credit outstanding, amount         0 0   0        
GBP Agreement | Line of Credit                        
Debt Instrument [Line Items]                        
Debt instrument term       5 years                
Line of credit facility, committed amount | £                       £ 1,500,000,000
Line of credit facility, number of extension options | option       2                
Debt extension term       1 year                
GBP Agreement | Line of Credit | Letter of Credit                        
Debt Instrument [Line Items]                        
Line of credit outstanding, amount | £                   £ 303,000,000 £ 348,000,000  
Former Facility | Revolving Credit Facility                        
Debt Instrument [Line Items]                        
Line of credit facility, covenant benchmark amount       $ 1,000,000,000                
Apache credit facility                        
Debt Instrument [Line Items]                        
Line of credit outstanding, amount         2,000,000 11,000,000   11,000,000   £ 461,000,000 £ 416,000,000  
Apache credit facility | Line of Credit                        
Debt Instrument [Line Items]                        
Credit facility outstanding amount         $ 0 0   $ 0        
Delayed-Drawn Term Loan | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt instrument, face amount     $ 2,000,000,000                  
Debt instrument guarantee terms, benchmark amount (less than)     $ 1,000,000,000                  
Delayed-Drawn Term Loan, Three Year Tranche Loans | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt instrument term     3 years                  
Debt instrument, face amount     $ 1,500,000,000                  
Delayed-Drawn Term Loan, 364-Day Tranche Loans | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt instrument term     364 days                  
Debt instrument, face amount     $ 500,000,000                  
Term Loan Credit Agreement, Three Year Tranche Loans | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt instrument term   3 years           3 years        
Credit facility outstanding amount           $ 1,000,000,000   $ 1,000,000,000        
Debt instrument, face amount   $ 1,500,000,000                    
Term Loan Credit Agreement, 364-Day Tranche Loans | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt instrument term   364 days                    
6.375% Senior Notes Due 2026 | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt repurchase amount   $ 321,000,000                    
Debt redemption price, percentage   101.063%                    
6.375% Senior Notes Due 2026 | Senior Notes | Callon Petroleum Company                        
Debt Instrument [Line Items]                        
Debt interest rate   6.375%                    
8.00% Senior Notes Due 2028 | Senior Notes | Callon Petroleum Company                        
Debt Instrument [Line Items]                        
Debt repurchase amount $ 8,000,000                      
Debt interest rate   8.00%                    
Debt redemption price, percentage 101.588%                      
7.500% Senior Notes Due 2030 | Senior Notes | Callon Petroleum Company                        
Debt Instrument [Line Items]                        
Debt repurchase amount $ 16,000,000                      
Debt interest rate   7.50%                    
Debt redemption price, percentage 102.803%                      
Callon’s 2028 Notes and Callon’s 2030 Notes | Unsecured Debt                        
Debt Instrument [Line Items]                        
Debt repurchased principal amount   $ 1,200,000,000                    
Debt repurchase amount   1,300,000,000                    
Callon’s 2028 Notes and Callon’s 2030 Notes | Senior Notes                        
Debt Instrument [Line Items]                        
Long-term debt   24,000,000                    
Callon Credit Agreement | Unsecured Debt                        
Debt Instrument [Line Items]                        
Repayments of debt   $ 472,000,000                    
Open Market Repurchase | Senior Notes                        
Debt Instrument [Line Items]                        
Debt repurchased principal amount             74,000,000   74,000,000      
Debt repurchase amount             $ 65,000,000   65,000,000      
Gain on extinguishment of debt                 $ 9,000,000      
v3.24.3
DEBT AND FINANCING COSTS - Financing Costs, Net (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Debt Disclosure [Abstract]        
Interest expense $ 109 $ 89 $ 302 $ 266
Amortization of debt issuance costs 1 1 4 3
Capitalized interest (8) (7) (22) (18)
Gain on extinguishment of debt 0 0 0 (9)
Interest income (2) (2) (8) (7)
Financing costs, net $ 100 $ 81 $ 276 $ 235
v3.24.3
INCOME TAXES (Details)
$ in Millions
Apr. 01, 2024
USD ($)
Callon Petroleum Company  
Valuation Allowance [Line Items]  
Deferred tax asset $ 575
v3.24.3
COMMITMENTS AND CONTINGENCIES (Details)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 10, 2020
defendant
Dec. 20, 2017
action
Jul. 17, 2017
defendant
action
Mar. 21, 2016
USD ($)
Mar. 20, 2016
USD ($)
Sep. 30, 2024
USD ($)
lawsuit
bond
Sep. 30, 2023
USD ($)
Sep. 30, 2024
USD ($)
lawsuit
bond
Sep. 30, 2023
USD ($)
Dec. 31, 2023
USD ($)
Jun. 21, 2023
surety
Apr. 05, 2022
letter
Dec. 31, 2017
AUD ($)
Apr. 30, 2017
AUD ($)
Mar. 12, 2014
USD ($)
Commitment And Contingencies [Line Items]                              
Accrued liability for legal contingencies           $ 18,000,000   $ 18,000,000              
Environmental tax and royalty obligations                             $ 100,000,000
Retain right of obligations           45,000,000   45,000,000              
Undiscounted reserve for environmental remediation           2,000,000   2,000,000              
Environmental remediation payments               4,000,000              
Standby loan agreed to provide related to ARO (up to)           400,000,000   400,000,000              
Number of prior letters notifying unable to fund decommissioning obligations | letter                       2      
Sureties issued bonds directly | surety                     2        
Sureties issued bonds to issuing bank | surety                     2        
Decommissioning security for sold properties           188,000,000   188,000,000              
Loss on previously sold Gulf of Mexico properties           $ 0 $ 0 83,000,000 $ 0            
Additional decommissioning contingency liability               $ 50,000,000              
Gulf Of Mexico Shelf Operations and Properties | Disposed of by Sale                              
Commitment And Contingencies [Line Items]                              
Number of bond held | bond           2   2              
Minimum                              
Commitment And Contingencies [Line Items]                              
Decommissioning contingency for sold           $ 853,000,000   $ 853,000,000   $ 824,000,000          
Louisiana Restoration, Coastal Zone Lawsuits                              
Commitment And Contingencies [Line Items]                              
Number of pending lawsuits | lawsuit           1   1              
Apollo Exploration Lawsuit                              
Commitment And Contingencies [Line Items]                              
Plaintiffs alleged damages       $ 200,000,000                      
Apollo Exploration Lawsuit | Minimum                              
Commitment And Contingencies [Line Items]                              
Plaintiffs alleged damages         $ 1,100,000,000                    
Australian Operations Divestiture Dispute | Apache Australia Operation                              
Commitment And Contingencies [Line Items]                              
Gain contingency, unrecorded amount                           $ 80  
Loss contingency, estimated of possible loss amount                         $ 200    
California Litigation                              
Commitment And Contingencies [Line Items]                              
Number of actions filed | action   2 3                        
Number of defendants | defendant     30                        
Delaware Litigation                              
Commitment And Contingencies [Line Items]                              
Number of defendants | defendant 25                            
v3.24.3
CAPITAL STOCK - Net Income (Loss) Per Common Share (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Basic:        
Income (loss) attributable to common stock $ (223) $ 459 $ 450 $ 1,082
Income (loss) attributable to common stock (in shares) 370 308 348 309
Income (loss) attributable to common stock (in USD per share) $ (0.60) $ 1.49 $ 1.30 $ 3.50
Diluted:        
Income (loss) attributable to common stock $ (223) $ 459 $ 450 $ 1,082
Income (loss) attributable to common stock (in shares) 370 308 348 309
Income (loss) attributable to common stock (in USD per share) $ (0.60) $ 1.49 $ 1.29 $ 3.50
Stock options and other        
Effect of Dilutive Securities:        
Stock options and other     $ 0 $ 0
Stock options and other (in shares)     0 0
Stock options and other (in USD per share)     $ (0.01) $ 0
v3.24.3
CAPITAL STOCK - Additional Information (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended 9 Months Ended
Apr. 01, 2024
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2022
Dec. 31, 2021
Class of Stock [Line Items]              
Options and restricted stock, anti-dilutive (in shares)   1,900,000 1,700,000 2,000,000 2,000,000    
Number of shares authorized to be repurchased (in shares)           40,000,000 40,000,000
Treasury shares acquired (in shares)   100,000 500,000 4,600,000 5,500,000    
Treasury stock acquired, average price (in USD per share)   $ 29.33 $ 41.90 $ 31.72 $ 37.91    
Remaining authorized repurchase amount (in shares)   39,300,000   39,300,000      
Payments of dividend on common stock   $ 92 $ 77 $ 260 $ 232    
Issuance of common stock       2,414      
Common Stock              
Class of Stock [Line Items]              
Issuance of common stock       $ 44      
Callon Petroleum Company | Common Stock              
Class of Stock [Line Items]              
Stock issued during period, shares, new issues 70,000,000            
Issuance of common stock $ 2,400            
v3.24.3
BUSINESS SEGMENT INFORMATION - Additional Information (Details)
 9 Months Ended
Sep. 30, 2024
segment
Segment Reporting [Abstract]  
Number of operating segments 3
v3.24.3
BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Sep. 30, 2024
Sep. 30, 2023
Sep. 30, 2024
Sep. 30, 2023
Dec. 31, 2023
Operating Expenses:          
Lease operating expenses [1] $ 418 $ 394 $ 1,216 $ 1,076  
Taxes other than income 70 61 205 163  
Exploration 29 49 248 144  
Depreciation, depletion, and amortization 595 418 1,613 1,117  
Asset retirement obligation accretion 36 29 112 86  
Impairments 1,111 0 1,111 46  
Total operating expenses 2,674 1,251 5,498 3,435  
Operating Income (Loss) (143) 1,057 1,527 2,677  
Other Income (Expense):          
Derivative instrument gains (losses), net (10) 0 (17) 104  
Loss on offshore decommissioning contingency     (83)    
Gain on divestitures, net 1 1 284 7  
Other, net 18   26 77  
General and administrative (92) (139) (270) (276)  
Transaction, reorganization, and separation (14) (5) (156) (11)  
Financing costs, net (100) (81) (276) (235)  
NET INCOME (LOSS) BEFORE INCOME TAXES (340) 833 1,035 2,343  
Total Assets 19,376 13,545 19,376 13,545 $ 15,244
Operating Segments | U.S.          
Operating Expenses:          
Lease operating expenses 222 164 582 452  
Taxes other than income 70 61 205 163  
Exploration (1) 4 107 10  
Depreciation, depletion, and amortization 355 199 930 530  
Asset retirement obligation accretion 10 9 35 29  
Impairments 315   315 0  
Total operating expenses 1,373 709 3,111 1,923  
Operating Income (Loss) 267 375 1,038 905  
Other Income (Expense):          
Total Assets 13,847 7,827 13,847 7,827  
Impairments 1 2 10 7  
Operating Segments | Egypt          
Operating Expenses:          
Lease operating expenses 109 128 352 346  
Taxes other than income 0 0 0 0  
Exploration 21 25 77 91  
Depreciation, depletion, and amortization 167 129 464 378  
Asset retirement obligation accretion 0 0 0 0  
Impairments 0   0 0  
Total operating expenses 303 295 912 841  
Operating Income (Loss) 451 510 1,322 1,394  
Other Income (Expense):          
Total Assets 3,525 3,518 3,525 3,518  
Operating Segments | North Sea          
Operating Expenses:          
Lease operating expenses 87 102 282 278  
Taxes other than income 0 0 0 0  
Exploration 0 9 1 18  
Depreciation, depletion, and amortization 73 90 219 209  
Asset retirement obligation accretion 26 20 77 57  
Impairments 796   796 46  
Total operating expenses 989 236 1,412 646  
Operating Income (Loss) (852) 183 (770) 403  
Other Income (Expense):          
Total Assets 1,439 1,665 1,439 1,665  
Impairments   6   12  
Operating Segments | Segment Suriname          
Other Income (Expense):          
Impairments   1 1 1  
Intersegment Eliminations & Other          
Operating Expenses:          
Lease operating expenses 0 0 0 0  
Taxes other than income 0 0 0 0  
Exploration 9 11 63 25  
Depreciation, depletion, and amortization 0 0 0 0  
Asset retirement obligation accretion 0 0 0 0  
Impairments 0   0 0  
Total operating expenses 9 11 63 25  
Operating Income (Loss) (9) (11) (63) (25)  
Other Income (Expense):          
Total Assets 565 535 565 535  
Oil and gas          
Segment Reporting Information [Line Items]          
Revenues 2,531 2,308 7,025 6,112  
Oil and gas | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 1,640 1,084 4,149 2,828  
Oil and gas | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 754 805 2,234 2,235  
Oil and gas | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 137 419 642 1,049  
Oil and gas | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Oil and gas, excluding purchased          
Segment Reporting Information [Line Items]          
Revenues [1] 2,058 2,079 6,007 5,500  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs [1] 123 89 328 245  
Oil and gas, excluding purchased | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 1,167 855 3,131 2,216  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 110 61 272 181  
Oil and gas, excluding purchased | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 754 805 2,234 2,235  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 6 13 19 26  
Oil and gas, excluding purchased | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 137 419 642 1,049  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 7 15 37 38  
Oil and gas, excluding purchased | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 0 0 0 0  
Purchased oil and gas          
Segment Reporting Information [Line Items]          
Revenues [1] 473 229 1,018 612  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs [1] 292 211 665 558  
Purchased oil and gas | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 473 229 1,018 612  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 292 211 665 558  
Purchased oil and gas | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 0 0 0 0  
Purchased oil and gas | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 0 0 0 0  
Purchased oil and gas | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Operating Expenses:          
Gathering, processing, and transmission & purchased oil and gas costs 0 0 0 0  
Oil revenues          
Other Income (Expense):          
Revenue from non-customers 182 202 533 539  
Oil revenues | Oil and gas, excluding purchased          
Segment Reporting Information [Line Items]          
Revenues 1,797 1,705 5,136 4,467  
Oil revenues | Oil and gas, excluding purchased | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 1,007 633 2,616 1,631  
Oil revenues | Oil and gas, excluding purchased | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 673 724 2,003 1,971  
Oil revenues | Oil and gas, excluding purchased | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 117 348 517 865  
Oil revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Natural gas revenues          
Other Income (Expense):          
Revenue from non-customers 22 23 63 73  
Natural gas revenues | Oil and gas, excluding purchased          
Segment Reporting Information [Line Items]          
Revenues 103 236 414 658  
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 7 89 79 229  
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 81 81 231 264  
Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 15 66 104 165  
Natural gas revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Natural gas liquids revenues | Oil and gas, excluding purchased          
Segment Reporting Information [Line Items]          
Revenues 158 138 457 375  
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | U.S.          
Segment Reporting Information [Line Items]          
Revenues 153 133 436 356  
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | Egypt          
Segment Reporting Information [Line Items]          
Revenues 0 0 0 0  
Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | North Sea          
Segment Reporting Information [Line Items]          
Revenues 5 5 21 19  
Natural gas liquids revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other          
Segment Reporting Information [Line Items]          
Revenues $ 0 $ 0 $ 0 $ 0  
[1] For transactions with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests.
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