UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 (Mark One)

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

 For the fiscal year ended December 31, 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)

 Delaware

 86-1430562

 (State or other jurisdiction of incorporation or organization)

 (I.R.S. Employer Identification No.)

 2000 W. Sam Houston Pkwy. S., Suite 200, Houston, Texas 77042-3643
 (Address of principal executive offices) (Zip Code)
 Registrant's telephone number, including area code ( 713) 296-6000
 Securities registered pursuant to Section 12(b) of the Act:

 Title of each class
 Trading Symbol(s)
 Name of each exchange on which registered

 Common Stock, $0.625 par value
 APA
 Nasdaq Global Select Market

 Securities registered pursuant to section 12(g) of the Act: None
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
 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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes No

 Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2024

 $
 10,887,671,670

 Number of shares of registrant's common stock outstanding as of January 31, 2025

 364,064,316

 Documents Incorporated By Reference
 Portions of the registrant's definitive proxy statement relating to the registrant's 2025 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.

 Item

 Page

 1.
 BUSINESS

 1A.
 RISK FACTORS

 1B.
 UNRESOLVED STAFF COMMENTS

 1C.

 CYBERSECURITY

 2.
 PROPERTIES

 3.
 LEGAL PROCEEDINGS

 4.
 MINE SAFETY DISCLOSURES

 5.

 MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

 6.
 SELECTED FINANCIAL DATA

 7.
 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 7A.
 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 8.
 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 9.
 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 9A.
 CONTROLS AND PROCEDURES

 9B.
 OTHER INFORMATION

 9C.
 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 10.
 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 11.
 EXECUTIVE COMPENSATION

 12.

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 13.
 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 14.

 PRINCIPAL ACCOUNTING FEES AND SERVICES

 15.
 EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 16.
 FORM 10-K SUMMARY

 i

 FORWARD-LOOKING STATEMENTS AN D RISKS
 This Annual Report on Form 10-K 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 Annual Report on Form 10-K, including, without limitation, statements regarding the Company's future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations and capital returns framework, are forward-looking statements. Such forward-looking statements are based on the Company's examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2024, and other data in the Company's possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as "may," "will," "could," "expect," "intend," "project," "estimate," "anticipate," "plan," "believe," "continue," "seek," "guidance," "goal," "might," "outlook," "possibly," "potential," "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 trade tensions between the U.S. and other countries, 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;
 ii

 • 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 this Annual Report on Form 10-K.
 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 Annual Report on Form 10-K. 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.

 iii

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

 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.
 v

 ITEMS 1 and 2.
 BUSINESS AND PROPERTIES

 GENERAL
 APA Corporation (APA or the Company), is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and NGLs. The Company's business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation's primary assets are its ownership interests in its consolidated subsidiaries.
 The Company's common stock, par value $0.625 per share, is listed on the Nasdaq. Through the Company's website, www.apacorp.com, you can access, free of charge, electronic copies of the charters of the committees of the Company's board of directors (Board of Directors), other documents related to corporate governance (including the Code of Conduct and APA's Corporate Governance Principles), and documents the Company files with the SEC, including the Company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act. Included in the Company's annual and quarterly reports are the certifications of its principal executive officer and its principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after the Company files such material with, or furnishes it to, the SEC. You may also request printed copies of the Company's corporate charter, bylaws, committee charters, or other governance documents free of charge by writing to the Company's corporate secretary at the address on the cover of this Annual Report on Form 10-K. The Company's reports filed with the SEC are made available on its website at www.sec.gov. From time to time, the Company also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on the Company's website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
 BUSINESS STRATEGY
 APA maintains a diversified asset portfolio, including conventional and unconventional, onshore and offshore, oil and natural gas exploration and production interests. In the U.S., operations are primarily focused in the Permian Basin of West Texas. Internationally, the Company has conventional onshore assets in Egypt's Western Desert, offshore assets on the U.K.'s Continental Shelf, and reached positive final investment decision for oil development offshore Suriname during 2024.
 APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet global demand for reliable and affordable energy. Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, trade disputes, 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 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 portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs.
 Rigorous management of the Company's asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, APA has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. These transactions include:

 • 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 acquired assets included 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. This transaction complements and enhances APA's asset base in the Permian Basin and adds to APA's inventory of high quality, short-cycle opportunities.
 • Throughout 2024, APA closed on a series of transactions to sell non-core producing properties in the Permian Basin, East Texas Austin Chalk, and Eagle Ford plays, and non-core mineral and royalty interests in the Permian Basin. Proceeds of approximately $1.6 billion from these transactions were used primarily to reduce debt. Combined with the Callon transaction, the Company believes its acreage position and drilling opportunities are better streamlined for longer-term growth.
 • On February 22, 2022, Altus Midstream Company (ALTM) combined with privately owned BCP Raptor Holdco LP in an all-stock transaction. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and APA deconsolidated ALTM and held an approximately 20 percent noncontrolling ownership interest in Kinetik. The Company subsequently divested of its ownership interest in Kinetik during 2022, 2023, and 2024 for total proceeds of approximately $880 million.
 For a more in-depth discussion of the Company's 2024 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

 BUSINESS OVERVIEW
 The following business overview further describes the operations and activities for the Company's exploration and production properties, by geographic region.
 EXPLORATION AND PRODUCTION
 Operating Areas
 APA's business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea. APA also has active development, exploration, and appraisal operations in Suriname, as well as exploration interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities.
 The following table sets out a brief comparative summary of certain key 2024 data for each of the Company's operating areas. Additional data and discussion are provided in Part II, Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

 Percentage
of Total
Revenue
 Year-End
Estimated
Reserves
 Percentage
of Total
Estimated
Reserves
 Gross
Wells
Drilled
 Gross
Productive
Wells
Drilled

 (In MMboe)
 (In MMboe)

 103.6
 %
 $
 4,315
 %

 50.3
 %
 2,933
 %

 12.5
 %
 %
 —
 —

 —
 —
 %
 —
 %
 —
 —

 Total
 166.4
 %
 $
 8,196
 %

 (1)The Company's operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of 2024 production and accounted for 12 percent of year-end 2024 estimated proved reserves.
 (2)Sales volumes from the Company's North Sea assets for 2024 were 12.4 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings.
 In 2024, the Company's U.S. oil and gas operations contributed approximately 62 percent of production, 53 percent of oil and gas revenues, and 72 percent of estimated year-end proved reserves. APA has access to significant liquid hydrocarbons across its 2.7 million gross acres (1.4 million net acres) in the U.S., 77 percent of which are undeveloped.
 The Company's U.S. producing assets are primarily located in the Permian Basin in West Texas, including the Midland and Delaware sub-basins. Examples of shale plays being developed within these sub-basins include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry. The Company operates approximately 4,300 gross oil and gas wells across its acreage, with additional interests in approximately 800 non-operated wells. APA also has legacy operations located offshore in the Gulf of America.
 Highlights of the Company's operations in the U.S. include:
 • Southern Midland Basin APA holds approximately 386,000 gross acres (275,000 net acres) in the Southern Midland Basin in Texas. During 2024, the Company primarily targeted oil plays in the Wolfcamp and Spraberry formations, drilling 87 gross development wells in this basin with a 100 percent success rate. During 2024, the Company acquired approximately 25,000 net acres in the Midland basin in connection with the Callon acquisition.
 • Delaware Basin APA holds approximately 282,000 gross acres (203,000 net acres) in the Delaware Basin, including opportunities in the Bone Spring and other formations of eastern New Mexico and bordering West Texas, and the Alpine High play in the southern portion of the Permian Basin, primarily in Reeves County, Texas. During 2024, the Company drilled 114 gross development wells in this basin with a 100 percent success rate and added approximately 120,000 net acres in the Delaware basin as part of the Callon acquisition.

 • Legacy Assets APA holds approximately 1.7 million gross acres (0.7 million net acres) in legacy properties, of which approximately 561,000 gross acres are in the offshore waters of the Gulf of America. During 2024, the Company divested certain of its non-core producing properties located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf. The Company also divested certain non-core mineral and royalty interests in the Permian Basin during 2024. Consistent with the Company's broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings provide additional monetization opportunities that continue to be evaluated.
 • New Venture Assets APA holds approximately 325,000 gross acres (163,000 net acres) of undeveloped acreage on the North Slope of Alaska. During 2024, the Company completed a three-well exploration program in Alaska, confirming a working petroleum system on the Company's acreage. The Company is currently drilling an additional exploration well on this acreage. The Company holds a 50 percent ownership interest in the project.
 The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its planned capital investment program. For 2025, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves. Future rig activity levels and drilling targets will be dependent on the success of the Company's drilling program and its ability to add reserves economically.
 U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The tenor of the Company's sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies, as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.
 APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g., WTI Houston, West Texas Sour (WTS), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company's objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts. These term contracts typically have a firm transportation commitment and often provide an opportunity for higher than prevailing market prices.
 APA's U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
 U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 161 Bcf of natural gas per year for the period from 2025 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, 4.2 MMbbls of crude oil in 2025, and an average of 1.8 MMbbls of crude oil per year for the period from 2026 through 2029, in each case, at variable, domestic and/or international, market-based pricing.
 APA currently expects to fulfill its delivery commitments primarily with production from its proved reserves and from continued development. In addition, to satisfy certain delivery commitments, the Company purchases third-party natural gas and crude oil to sell and deliver under existing pipeline agreements and sales contracts. APA may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments.
 For more information regarding the Company's commitments, please see Part II, Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations of this Annual Report on Form 10-K.

 APA has two international locations with ongoing production operations:
 • Egypt, which includes onshore conventional assets located in Egypt's Western Desert; and
 • the North Sea, which includes offshore assets based in the U.K.
 Egypt APA has decades of exploration, development, and operations experience in Egypt and is the largest acreage holder in Egypt's Western Desert. At year-end 2024, the Company held 5.3 million gross acres in six separate concessions. The Company's acreage is primarily held under one merged concession agreement (MCA) that resulted from the ratification of a MCA in 2021 with the Government of Egypt and EGPC. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company's production covered under the concession. Approximately 67 percent of the Company's gross acreage in Egypt is undeveloped, providing APA with considerable exploration and development opportunities for the future.
 APA's Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company's PSCs, the Company is the contractor partner (Contractor) with EGPC and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor's income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC's production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and are reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company's Egypt operations despite impacting the Company's production and reserves.
 The APA subsidiary that is the sole Contractor under the MCA is owned by an APA-operated joint venture owned two-thirds by the Company and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).
 The Company's estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country's share of reserves. Through the joint venture, Sinopec holds a one-third minority participation interest in the Company's oil and gas operations in Egypt. The Company's Egypt assets, including the one-third noncontrolling interest, contributed 30 percent of 2024 production and 17 percent of 2024 year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 22 percent of 2024 production and 12 percent of 2024 year-end estimated proved reserves.
 In 2024, the Company drilled 48 gross development and 36 gross exploration wells in Egypt. A key component of the Company's success has been the ability to acquire and evaluate 3-D seismic surveys that enable the Company's technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering three million acres, which has led to recent discoveries that build and enhance the Company's drilling inventory in Egypt. The Company will continue to focus on driving efficiencies and managing costs under the MCA.
 North Sea The Company has interests in approximately 176,000 gross acres in the U.K. North Sea. These assets contributed 8 percent of the Company's 2024 production and approximately 3 percent of year-end 2024 estimated proved reserves.
 The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). In 2011, the Company acquired Mobil North Sea Limited, which included operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. The Company also has a non-operated interest in the Nelson field acquired in 2011. During the second quarter of 2023, the Company suspended all new drilling activity in the North Sea. 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.

 International Marketing The Company's natural gas production in Egypt is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. In the fourth quarter 2024, the Company entered into a new gas sales agreement, which could result in improved pricing if certain production thresholds are met. The new gas sales agreement, which is effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil. Crude oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is sold and exported from one of two terminals on the northern coast of Egypt. Oil production sold to EGPC is sold at prices related to the export market.
 The Company's North Sea crude oil production is sold under term, entitlement volume contracts and spot variable volume contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, operated by Ancala Midstream Acquisitions Limited. Natural gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The condensate mix from the SAGE plant is processed further downstream. The split streams of propane, butane, and condensate are sold separately on a monthly entitlement basis at the Braefoot Bay terminal using index pricing less transportation.
 New Ventures APA's international New Ventures acreage provides exposure to new growth opportunities outside of the Company's traditional core areas and provides higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins.
 The Company has a joint venture agreement with TotalEnergies (formerly Total S.A.) to explore and develop Block 58 offshore Suriname. The Company holds a 50 percent working interest in exploration activities in Block 58, which comprises approximately 1.4 million gross acres in water depths ranging from less than 100 meters to more than 2,100 meters. TotalEnergies holds a 50 percent working interest in exploration activities in Block 58 as the operator. Key terms of the joint venture agreement provide for TotalEnergies to pay 50 percent of all exploration activities and a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation. For the first $10 billion of gross capital expenditures, TotalEnergies pays 87.5 percent, and the Company pays 12.5 percent; for the next $5 billion in gross expenditures, TotalEnergies pays 75 percent and the Company pays 25 percent; and for all gross expenditures above $15 billion, TotalEnergies pays 62.5 percent and the Company pays 37.5 percent. The Company will also receive various other forms of consideration, including a $75 million cash payment upon achieving first oil production and future contingent royalty payments from successful joint development projects.
 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 b/d. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its four-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 joint venture agreement with TotalEnergies to carry a portion of Apache's appraisal and development capital. Under the terms of the Block 58 PSCs, Staatsolie has the right to participate in the GranMorgu development and production up to a maximum of 20 percent. First oil is anticipated in 2028.
 The Company is also the operator of Block 53 offshore Suriname and holds a 45 percent working interest in the block. The Company, through an extension granted in 2023, holds approximately 13,000 net undeveloped acres for its operated Baja discovery area. Evaluation of the area is ongoing.
 During 2023, the Company signed a production sharing contract for Block 6 offshore Uruguay covering approximately four million undeveloped acres, where it has an obligation to drill one exploration well. In February 2024, the Company also signed a production sharing contract for Block 4 offshore Uruguay, covering approximately 1.2 million net undeveloped acres. The Company holds a 50 percent working interest in the project and is the operator.
 The Company suspended exploration activities in its acreage offshore the Dominican Republic in 2023 and relinquished its net acreage holdings and completed its withdrawal in 2024. The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.

 Drilling Statistics
 Worldwide in 2024, APA drilled or participated in drilling 289 gross wells, with 267 wells (92 percent) completed as producers. Historically, APA's drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, the Company's operations outside of the U.S. focus on a mix of exploration and development wells. In addition to wells completed during 2024, at year-end 2024, a number of wells had not yet reached completion: 67 gross (63.3 net) in the U.S., 42 gross (41.8 net) in Egypt.
 The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:

 Net Exploratory
 Net Development
 Total Net Wells

 Productive
 Dry
 Total
 Productive
 Dry (1)

 Total
 Productive
 Dry
 Total

 2024

 —
 —
 —
 152.7
 —
 152.7
 152.7
 —
 152.7

 Egypt
 16.0
 20.0
 36.0
 45.5
 2.0
 47.5
 61.5
 22.0
 83.5

 Total
 16.0
 20.0
 36.0
 198.2
 2.0
 200.2
 214.2
 22.0
 236.2

 2023

 —
 —
 —
 78.4
 —
 78.4
 78.4
 —
 78.4

 Egypt
 24.0
 24.0
 48.0
 66.1
 7.7
 73.8
 90.1
 31.7
 121.8

 1.2
 —
 1.2
 —
 —
 —
 1.2
 —
 1.2

 —
 0.3
 0.3
 —
 —
 —
 —
 0.3
 0.3

 Total
 25.2
 24.3
 49.5
 144.5
 7.7
 152.2
 169.7
 32.0
 201.7

 2022

 —
 —
 —
 40.7
 —
 40.7
 40.7
 —
 40.7

 Egypt
 15.0
 14.5
 29.5
 64.4
 —
 64.4
 79.4
 14.5
 93.9

 1.0
 —
 1.0
 1.0
 —
 1.0
 2.0
 —
 2.0

 —
 2.1
 2.1
 —
 —
 —
 —
 2.1
 2.1

 Total
 16.0
 16.6
 32.6
 106.1
 —
 106.1
 122.1
 16.6
 138.7

 (1)No proved undeveloped reserves were included in reserves as of year-end 2023 for the 2.0 net dry development wells drilled in 2024. No proved undeveloped reserves were included in reserves as of year-end 2022 for the 7.7 net dry development wells drilled in 2023.
 Productive Oil and Gas Wells
 The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2024, is set forth below:

 Oil
 Gas
 Total

 Gross
 Net
 Gross
 Net
 Gross
 Net

 3,590
 2,711
 4,304
 3,295

 Egypt
 1,025
 1,128
 1,094

 Total
 4,748
 3,794
 5,575
 4,486

 Domestic
 3,590
 2,711
 4,304
 3,295

 1,158
 1,083
 1,271
 1,191

 Total
 4,748
 3,794
 5,575
 4,486

 Production, Pricing, and Lease Operating Cost Data
 The following table describes, for each of the last three fiscal years, oil, NGL, and gas production volumes, average lease operating costs per boe (including transportation costs but excluding severance and other taxes), and average sales prices for each of the countries where the Company has operations:

 Average Lease
Operating
 Cost per Boe
 Average Sales Price

 Oil
 NGL
 Gas
 Oil
 NGL
 Gas

 Year Ended December 31,
 (MMbbls)
 (MMbbls)
 (Bcf)
 (Per bbl)
 (Per bbl)
 (Per Mcf)

 2024

 47.1
 27.0
 177.0
 $
 11.33
 $
 75.92
 $
 22.83
 $
 0.71

 32.6
 —
 106.5
 9.70
 80.41
 —
 2.94

 9.6
 0.4
 14.6
 37.02
 80.74
 47.59
 10.84

 Total
 89.3
 27.4
 298.1
 12.75
 78.08
 23.37
 1.97

 2023

 28.8
 23.0
 165.1
 $
 10.62
 $
 77.84
 $
 20.85
 $
 1.80

 32.5
 —
 118.9
 9.70
 82.47
 —
 2.91

 12.7
 0.4
 18.3
 25.34
 82.75
 47.77
 13.02

 Total
 74.0
 23.4
 302.3
 11.95
 80.72
 21.54
 2.91

 2022

 25.7
 22.8
 172.8
 $
 10.73
 $
 95.68
 $
 33.41
 $
 5.31

 31.1
 0.1
 130.1
 10.37
 101.25
 76.80
 2.85

 11.9
 0.4
 12.8
 30.07
 100.87
 67.07
 23.36

 Total
 68.7
 23.3
 315.7
 12.59
 99.11
 34.51
 4.98

 (1)Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
 (2)Sales volumes from the Company's North Sea assets for 2024, 2023, and 2022 were 12.4 MMboe, 16.6 MMboe, and 14.9 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
 Gross and Net Undeveloped and Developed Acreage
 The following table summarizes the Company's gross and net acreage position by geographic area as of December 31, 2024:

 Undeveloped Acreage
 Developed Acreage

 Gross Acres
 Net Acres
 Gross Acres
 Net Acres

 (In thousands)

 2,079

 Egypt
 3,543
 3,543
 1,755
 1,706

 1,470
 —
 —

 6,548
 5,312
 —
 —

 Total
 13,657
 10,574
 2,529
 2,245

 As of December 31, 2024, the Company held approximately 17,000 net undeveloped acres that are scheduled to expire by year-end 2025 if production is not established or the Company takes no action to extend the terms. Nearly all of the Company's acreage expiring in 2025 is in the Delaware Basin. The Company also held approximately 6,000 and 1,000 net undeveloped acres on its U.S. onshore acreage set to expire by year-end 2026 and 2027, respectively. As of December 31, 2024, approximately 80 percent of the U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights.
 Exploration concessions covering the Company's Egyptian acreage were extended in 2021 upon ratification of the MCA with EGPC, and no acreage is scheduled to expire before 2026. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist. The Company strives to extend the terms of many of these licenses and concession areas through operational or administrative actions but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments. No oil and gas reserves were recorded on this undeveloped acreage set to expire.

 The Company held approximately six million net undeveloped acres as of December 31, 2024, in other international locations separate from positions held in its established U.K. and Egypt locations. Exploration interests include Block 53 and Block 58 offshore Suriname and Block 4 and Block 6 offshore Uruguay. The Company continues to actively evaluate and analyze several discoveries on its Block 58 offshore Suriname exploration acreage with its operator partner, TotalEnergies. Approximately 720,000 net undeveloped acres in Block 58 have a current expiration date of June 2031 with an option to extend further.
 During 2024, the Company relinquished its net acreage holdings offshore the Dominican Republic and completed its withdrawal from the country. The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.
 Estimated Proved Reserves and Future Net Cash Flows
 Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the "economic interest" method, which excludes the host country's share of reserves.
 Estimated reserves that can be produced economically through application of improved recovery techniques are included in the "proved" classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, APA uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company's reserve estimates.
 Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.

 The following table shows proved oil, NGL, and gas reserves as of December 31, 2024, based on average commodity prices in effect on the first day of each month in 2024, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. The total column of this table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.

 Oil
 NGL
 Gas
 Total

 (MMbbls)
 (MMbbls)
 (Bcf)
 (MMboe)

 Proved Developed:

 —

 —
 —
 —
 —

 Total
 1,227

 Proved Undeveloped:

 —

 —
 —
 —
 —

 —
 —

 Total

 Total Proved
 1,563

 (1)Includes total proved developed and total proved undeveloped reserves of 50 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
 As of December 31, 2024, the Company had total estimated proved reserves of 500 MMbbls of crude oil, 209 MMbbls of NGLs, and 1.6 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 969 million boe, of which liquids represent approximately 73 percent. As of December 31, 2024, the Company's proved developed reserves totaled 669 MMboe and estimated proved undeveloped (PUD) reserves totaled 300 MMboe, or approximately 31 percent of worldwide total proved reserves. APA has elected not to disclose probable or possible reserves in this filing. The Company had no fields that contained 15 percent or more of its total proved reserves for each of the years ended December 31, 2024 and 2023. The Company had one field that contained 15 percent or more of its total proved reserves for the year ended December 31, 2022.
 During 2024, the Company added approximately 325 MMboe from extensions, discoveries, and other additions. The Company recorded 223 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin targeting the Wolfcamp, Bone Spring, and Spraberry producing horizons. International operations contributed 102 MMboe of exploration and development adds, with Egypt contributing 28 MMboe from onshore exploration and appraisal and 74 MMboe from the Suriname final investment decision (FID), for offshore Block 58.
 The Company realized combined downward revision of previously estimated reserves of 74 MMboe. Negative revision related to pricing and interest totaled 99 MMboe, driven primarily by depressed Permian Basin gas pricing. This downward revision was partially offset by engineering and performance upward revisions totaling 25 MMboe. The U.S. and Egypt contributed upward revision of 47 MMboe, offset by negative revision of 22 MMboe in the North Sea.
 Acquisitions during 2024 increased total estimated proved reserves by approximately 222 MMboe and were primarily related to the U.S. based Callon transaction. A series of divestiture transaction during the year of non-core producing properties in the U.S. reduced estimated proved reserves by approximately 145 MMboe.
 The Company's estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2024, 2023, and 2022, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 17—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

 Proved Undeveloped Reserves
 The Company's total estimated PUD reserves of 300 MMboe as of December 31, 2024, increased by 228 MMboe from 72 MMboe of PUD reserves reported at year-end 2023. During 2024, the Company converted 34 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 33 MMboe, with the remaining 1 MMboe in its international areas. The Company acquired 55 MMboe and disposed of 7 MMboe related to PUD reserves during 2024. The Company added 249 MMboe of new PUD reserves through extensions and discoveries and by extending the planning time horizon from two to five years. Downward PUD revisions totaled 35 MMboe, comprising 20 MMboe associated with engineering and interest revisions, 5 MMboe associated with revised development plans, and 10 MMboe associated with lower product prices.
 During 2024, a total of approximately $341 million was spent on projects associated with proved undeveloped reserves. A portion of APA's costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2024, the Company spent approximately $321 million on PUD reserve development activity in the U.S. and $20 million in the international areas. As of December 31, 2024, the Company had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.
 Preparation of Oil and Gas Reserve Information
 The Company's reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.
 APA's proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of the Company's operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Reserves are reviewed internally with senior management and presented to APA's Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our corporate and operating asset engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.
 APA's Director of Reserves is the person primarily responsible for overseeing the preparation of the Company's internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 40 years of experience in the energy industry. The Director of Reserves reports directly to the Company's Vice President of Assurance.
 The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company's internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company's processes and the reasonableness of the Company's estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year, and reserves volume. During 2024, the properties selected for all countries represented 90 percent of the total future net cash flows discounted at 10 percent. These properties accounted for 82 percent of the value of the Company's domestic proved reserves, and 100 percent of the value of the Company's international proved reserves. In addition, all fields containing five percent or more of the Company's total proved reserves volume were included in Ryder Scott's review. The review covered 82 percent of total proved reserves on a boe basis.

 The percentages of total estimated proved reserves values, calculated as future net cash flows discounted at 10 percent, and volumes, on a boe basis, covered by Ryder Scott's reviews for the years 2024, 2023, and 2022 were:

 2024
 2023
 2022

 Estimated proved reserves values
 %
 %
 %

 Estimated proved reserves volumes:

 %
 %
 %

 Egypt
 %
 %
 %

 %
 %
 %

 %
 —
 %
 —
 %

 APA Worldwide
 %
 %
 %

 The Company has filed Ryder Scott's independent report as an exhibit to this Annual Report on Form 10-K.
 According to Ryder Scott's opinion, based on their review, including the data, technical processes, and interpretations presented by the Company, the overall procedures and methodologies utilized by the Company in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by the Company are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.
 ALTUS MIDSTREAM
 On February 22, 2022, Altus Midstream Company (ALTM) closed a transaction to combine with privately owned BCP Raptor Holdco LP in an all-stock transaction, creating an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik). Subsequent to the transaction, a subsidiary of APA owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock, and the Company no longer consolidated the assets and liabilities of ALTM in its consolidated financial statements.
 In March 2022, the Company sold four million of its Kinetik shares for cash proceeds of $224 million, and in December 2023, the Company sold an additional 7.5 million of its Kinetik shares for $228 million. In March 2024, the Company sold its remaining Kinetik shares for cash proceeds of $428 million. The Company had a designated director on the Kinetik board of directors until he 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.
 MAJOR CUSTOMERS
 The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2024, sales to EGPC accounted for approximately 17 percent of the Company's worldwide crude oil, natural gas, and NGLs revenues. During each of 2023 and 2022, sales to EGPC accounted for approximately 15 percent of the Company's worldwide crude oil, natural gas, and NGLs revenues.
 Management does not believe that the loss of any single customer would have a material adverse effect on the results of operations.
 HUMAN CAPITAL MANAGEMENT
 Human Capital and Employees
 APA believes that its people are one of the Company's most important investments and its greatest asset. Successful execution of the Company's business strategies depends on its ability to attract, develop, incentivize, and retain experienced, talented, qualified, and highly skilled employees at all levels of the organization. As such, the Company continues to focus on health and safety, total rewards, and community partnerships to ensure that being a part of the APA family is a positive experience for all.

 As of December 31, 2024, the Company globally employed approximately 2,305 full-time equivalent employees in locations across the organization.

 Employees

 1,505

 United Kingdom

 Egypt

 —

 France

 Total employees
 2,305

 Oversight and Management
 The Management Development and Compensation (MD&C) Committee and/or the full Board of Directors receive regular reports on certain human capital matters, including the Company's equal opportunities initiatives. The MD&C Committee also oversees the Company's compensation programs, leadership development and succession planning strategies. Reports and recommendations made to the Board of Directors and its committees are part of the framework that ensures APA's daily actions and decisions are guided by its core values, including upholding the health and safety of the Company's team, stakeholders, and communities; investing in its workforce; ensuring environmental responsibility; seeking continuous improvement; and acting ethically and with integrity.
 Equal Opportunity Employer
 APA recognizes that an environment free of discrimination and its effects is vital to its long-term success. Incorporated in the above belief, the Company recognizes the importance of being an equal opportunity employer committed to prohibiting all forms of discrimination and harassment. The Company does so by ensuring that all personnel actions are administered without regard to race, color, religion, sex, familial status, marital status, sexual orientation, gender identity or expression, pregnancy, age, national origin, disability status, genetic information, protected veteran status, or any other characteristic protected by law.
 The Company has dedicated resources to developing programs and initiatives that foster an inclusive work environment where all employees are valued and treated with respect. The goal is to create a culture where all employees can feel a sense of belonging, equality, and can thrive.
 In 2024, APA strengthened its commitment by supporting its established programs and expanding employee engagement through the following key accomplishments:
 • Increased the number of employee resource groups (ERGs) with the establishment of Rally Point, an ERG focused on military veterans;
 • Participated in surveys, networks, and conferences to benchmark against the industry and increase knowledge on equal employment opportunities best practices;
 • In addition to its other recruitment efforts, recruited at Historically Black Colleges & Universities (HBCU);
 • Completed internal annual pay analysis;
 • Expanded employee benefits to support back-up childcare; and
 • Continued to support the communities in which APA operates.
 Talent
 APA's comprehensive talent strategy integrates recruitment and development initiatives, forming a foundation for continued organizational success. The Company is dedicated to attracting, cultivating, and retaining top-tier professionals while fostering an environment that encourages growth and innovation.
 The Company's recruitment framework harnesses technology and data-driven insights to identify talent pools on a global scale, while at the local level, the Company leverages the power of its people for recommendations and feedback during the candidate sourcing and interviewing processes.

 Collaborations with educational institutions, industry networks and professional organizations enable the Company to engage with emerging talent and build relationships with seasoned industry professionals. APA has an intern recruitment program that provides invaluable learning experiences and helps cultivate a pipeline of future industry leaders. This collaboration not only aligns with the Company's corporate goals but also strengthens the Company's reputation as an organization dedicated to treating all employees fairly and equally while empowering underrepresented groups in STEM. The engagement is a significant stride forward that will enrich the Company's recruitment initiatives in the STEM disciplines.
 Beyond recruitment, the Company invests in a broad range of talent development programs for its employees. These initiatives encompass continuous learning opportunities, skill enhancement programs, mentorship frameworks, and leadership development pathways. Tailored career progression opportunities empower the Company's employees to excel and innovate, preparing them for evolving challenges.
 The synergy between recruitment efforts and talent development initiatives helps the Company to not only attract top talent but to also nurture their potential, enabling them to excel within a dynamic environment. This cohesive approach is designed to provide a continuous influx of skilled individuals who contribute significantly to the Company's growth and maintain a competitive edge, positioning the Company for sustained success in an ever-evolving market landscape.
 Training and Development
 At APA, effective employee development integrates both training and performance management programs. In 2024, the Company continued to provide leadership and business acumen courses for employees. Classes were taught in-person as well as online for the Company's global and remote workforce.
 APA's Performance Management program moved into a more sustainable phase with a reinforcement on promoting an ongoing feedback culture between managers and employees.
 Supplemental development and training opportunities were offered during the year to support employees in their personal and professional development, including:
 • Access to multiple, third-party online and in-person trainings;
 • Ongoing education for people leaders around the Company's leadership competencies and behaviors;
 • Leadership and personal development coaching opportunities through a collaboration with leading human resources consulting companies;
 • Annual cybersecurity training focusing on keeping the Company and employees' personal information secure;
 • Annual compliance, antitrust, bribery, corruption, and code of business conduct and ethics training required for all employees and leaders; and
 • Required health, safety, and environmental training offered to field and offshore employees on safe practices.
 Additionally, the Company continued a company-wide initiative in 2024 focused on enhancing talent strategies and investing in employee development programs that enrich the overall employee experience while reinforcing the Company's organizational objectives. A Leadership Development strategy was developed to support developing leaders across the organization.
 Total Rewards
 APA's total rewards approach is designed to attract, motivate, and retain top talent by providing a robust compensation and benefits package that includes competitive base salary, industry-leading benefits and performance-driven incentives. To foster a stronger sense of ownership and align the interests of employees and shareholders, restricted stock units are provided to eligible employees under APA's broad-based compensation program. Furthermore, the Company offers comprehensive and locally relevant benefits that cultivate a family-friendly work environment and focus on the overall wellness of the Company's employees. In the U.S. these include, among other benefits:
 • Comprehensive health insurance coverage offered to employees working an average of 20 hours or more each week;
 •401(k) plan with up to an 8 percent Company match;
 •6 percent Company contributions to a money purchase retirement plan;
 • Company-paid short-term disability that pays a percentage of base pay according to years of service;

 • Parental leave for all new parents for birth and adoption;
 • Fertility and family building benefits to support the various paths to parenthood;
 • Elder care leave to temporarily care for or find permanent care for elder family members;
 • Comprehensive mental health offering that includes access to mental health therapists or coaches, a learning platform that offers on-demand and interactive courses on mental health topics, and a library of well-being and self-care resources; and
 • Well-being program that encourages healthy habits and promotes physical, financial, social, and emotional well-being through webinars and challenges throughout the year.
 Health and Safety
 APA's priority is the health and safety of its workforce. The Company's environmental, health, and safety and operations functions partner to consistently reinforce its core values, standards, and operating practices as well as foster a safety culture that empowers the Company's workforce to stop work if conditions or behaviors are deemed unsafe. APA strives to be incident-free across its global operations every day, with the help of visible and engaged leadership, by setting clear expectations and making safety personal for all employees and contractors.

 Global Primary Workforce Safety Metrics

 Total Recordable Incident Rate (TRIR)(1)

 0.16
 33% below target of 0.24

 Days Away, Restricted and Transferred Rate (DART)(2)

 0.09
 25% below target of 0.12

 Severe Incident Rate (SIR)(3)

 0.009
 10% below target of 0.010

 Vehicle Incident Rate (VIR)(4)

 0.59
 28% above target of 0.46

 (1)Total Recordable Incident Rate (TRIR): The rate of recordable injuries sustained by employees, contractors, or both that occur per 200,000 hours worked.
 (2)Days Away, Restricted and Transferred Rate (DART): The rate of injuries sustained by employees, contractors, or both leading to missed workdays, restricted work activities, or transfers to another job, per 200,000 hours worked.
 (3)Severe Incident Rate (SIR): The rate of incidents resulting in fatal injury, permanent or significant loss or impairment of a body part or organ function, or that otherwise permanently change or disable individuals in their normal life activity, per 200,000 hours worked.
 (4)Vehicle Incident Rate (VIR): The rate of vehicle-related incidents per 1 million miles driven.
 Community Partnerships
 APA is committed to being a responsible partner in the communities where it operates. The Community Partnerships group oversees the Company's global strategic community engagement, including the stewardship of key stakeholder relationships.
 APA's global giving strategy and philosophy is focused into three pillars: Community Well-being, Environmental Stewardship, and Access to Energy, through which the Company creates sustainable and positive impacts. Based on these pillars, APA is committed to addressing acute needs within the local communities where it operates; ensuring that it remains focused on its long-standing legacy and commitment to environmental stewardship and conservation; and supporting communities that lack access to reliable, affordable energy.
 • Community Well-being: APA continues to partner with organizations within the communities in which it operates to improve quality of life through access to education and essential medical supplies; development of innovative healthcare technologies and procedures; support for vulnerable populations; response to natural disasters; and support for first responders.
 • Environmental Stewardship: In 2024, the Company's environmental stewardship initiatives included grants of 169,000 trees to 63 community partners in the U.S. and U.K. through the Apache Corporation Tree Grant Program; continued partnership with the Texas Wildlife Association Foundation for environmental education programs; and multi-year support of the Pecos Watershed Conservation Initiative, an alliance of seven energy companies, in partnership with the National Fish and Wildlife Foundation, to restore and protect natural grasslands and habitats within the greater Trans-Pecos Region.
 • Access to Energy: In 2024, the Company continued its partnership with the Clean Cooking Alliance (CCA) on a venture accelerator program in Sub-Saharan Africa. Our support has helped CCA facilitate a catalytic finance program for early-stage clean cooking entrepreneurs by providing access to technical support, funding, and external

 networks to expand their businesses. This will ultimately help drive a robust market for clean cooking solutions, including clean-burning liquefied petroleum gas.
 APA also provides employees with volunteer service opportunities in collaboration with its Community Partnerships program. The Company seeks meaningful volunteer opportunities that instill a sense of pride, ownership, and accomplishment for employees in their communities. As community needs change and stakeholder engagement continues, APA continues to adjust its charitable giving program.
 OFFICES
 The Company's principal executive offices are located at 2000 W. Sam Houston Pkwy. S., Suite 200, Houston, Texas 77042-3643. As of year-end 2024, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. The Company's primary office space is leased. The current lease on the Company's principal executive offices runs through December 31, 2038, subject to the lessee's option to extend the term by up to 20 years. For information regarding the Company's obligations under its office leases, please see Part II, Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 TITLE TO INTERESTS
 As is customary in the oil and gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time the Company acquires properties. The Company believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Company's operations. The interests owned by the Company may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company's operations.
 ADDITIONAL INFORMATION ABOUT THE COMPANY
 Response Plans and Available Resources
 The Company's subsidiaries maintain oil spill response plans (the Plans) for their respective offshore operations in the Gulf of America and the North Sea, which ensure rapid and effective responses to spill events that may occur on such entities' operated properties. Emergency preparedness exercises are conducted to measure and maintain the effectiveness of the Plans.
 The Company's subsidiary, Apache, is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any affiliated entity worldwide to access OSRL's services. OSRL maintains aircraft available for global dispersant application and has active recovery boom systems that can be used for offshore, nearshore, or shoreline responses. In addition to the services and equipment provided to all members of OSRL, the Company maintains membership to supplementary services from OSRL, including the U.K. Continental Shelf (UKCS) Aerial Surveillance, OSPRAG Capping Stack, and Dispersant Stockpile, providing equipment and services specifically tailored for an emergency response in the North Sea.
 In the event of a spill in the Gulf of America, Clean Gulf Associates (CGA) is the primary oil spill response organization available to the Company. Apache is a member of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of America. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies' operations in the Gulf of America. CGA equipment includes skimming vessels, barges, boom, and dispersants.
 Additionally, the Company has contracted with Wild Well Control Company for contingency planning for and response to uncontrolled subsea well events and other drilling activities. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control's containment system capping stacks.

 Competitive Conditions
 The oil and gas industry is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and the gathering and marketing of oil, gas, and NGLs. The Company's competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.
 Certain of the Company's competitors may possess financial or other resources substantially larger than the Company possesses or have established strategic long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for leases or drilling rights.
 However, the Company believes its diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across multiple geographic areas, its balanced production mix between oil and gas, its management and incentive systems, and its experienced personnel give it a strong competitive position relative to many of the Company's competitors who do not possess similar geographic and production diversity. The Company's global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which it has producing operations to which it can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. This also reduces the risk that the Company will be materially impacted by an event in a specific area or country.
 Governmental Regulation
 The Company's U.S. operations are subject to federal, state, and local laws and regulations, including restrictions on production, changes in taxes and other amounts payable to governments, price or gathering rate controls, environmental protection laws and regulations, and security for plugging, abandonment, and decommissioning obligations, including in the Gulf of America. For discussions of the risks the Company faces related to regulation, see the information set forth under "Risks Related to Governmental Regulation and Political Risks" and "Risks Related to Climate Change" in Item 1A Risk Factors.
 Hydraulic Fracturing Regulation
 The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for oil and natural gas to migrate toward the wellbore, typically at substantial depths in formations with low permeability. Governmental entities have previously taken actions to regulate hydraulic fracturing. These activities and the associated water disposal activities are under scrutiny due to their potential environmental and physical impacts, including possible water contamination and possible links to induced seismicity.
 Climate Change
 Due to climate change concerns, numerous proposals to monitor and limit emissions of greenhouse gas (GHG) have been made and are likely to continue to be made at the federal, state and local levels of government and by the governments of other nations. There has been discussion in countries where the Company operates, including the U.S., regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions. Moreover, in January 2024, the EPA announced a proposed rule to assess a charge on certain methane emissions in the oil and gas industry. The Company is currently evaluating the proposed rule and its applicability to the Company and is monitoring ongoing litigation related to the proposed rule.
 Additionally, various states and groups of states have adopted legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company's operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications.

 Treatment and Disposal of Produced Water Regulation
 The treatment and disposal of produced water is highly regulated and restricted. Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection) and to require the monitoring of seismic activity. While the Company remains focused on reusing or recycling water over disposal of water, the Company's costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical.
 Environmental Compliance
 As an owner or lessee and operator of oil and gas properties and facilities, the Company is subject to numerous federal, state, local, and foreign laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry as a whole, the Company does not believe that these requirements affect it differently, to any material degree, than other companies in the oil and gas industry.
 The Company has made and will continue to make expenditures in its efforts to comply with these requirements, which the Company believes are necessary business costs in the oil and gas industry. The Company has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to its operations in all countries in which it does business. The Company has established operating procedures and training programs designed to limit the environmental impact of its field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that the Company is unable to separate expenses related to environmental matters; however, the Company does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures, earnings, or competitive position.

 ITEM 1A.
 RISK FACTORS

 The Company's business activities and the value of its securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company's business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA's securities could lose part or all of their investments. Additional risks and uncertainties not presently known to the Company or that the Company currently considers immaterial may also adversely affect the Company.
 RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NGLs
 Crude oil, natural gas, and NGL prices and their volatility could adversely affect the Company's operating results and the price of APA's common stock.
 The Company's revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2024 ranged from a high of $87.69 per barrel to a low of $66.73 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2024 ranged from a high of $13.20 per MMBtu to a low of $1.21 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company's control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:
 • worldwide and domestic supplies and/or inventories of crude oil, natural gas, and NGLs and the availability of related pipeline, transportation, import/export, and refining capacity and infrastructure;
 • 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+);
 • political conditions and events in oil and gas producing regions, including instabilities, changes in governments, or armed conflicts, such as the Russian war in Ukraine and the armed conflict in Israel and Gaza;
 • the price, competitiveness, decision to use, and availability of alternative fuels and energy sources, including coal, biofuels, and renewables;
 • increased competitiveness of, and demand for, alternative energy sources;
 • technological advances affecting energy supply and energy consumption, including those that alter fuel choices;
 • the availability of pipeline capacity and infrastructure;
 • the availability of crude oil transportation and refining capacity;
 • weather conditions;
 • the impact of political pressure and the influence of environmental groups, investors, and other stakeholders on decisions and policies related to the oil and gas industry, including with respect to environmental, social, and governance matters;
 • domestic and foreign governmental regulations and taxes, including changes or initiatives to address the impacts of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and
 • the overall economic environment, including rates of growth, trade tensions, and increasing inflationary pressure.
 Low prices have previously adversely affected and could from time to time in the future adversely affect the Company's revenues, operating income, cash flow, and proved reserves, and a prolonged period of low prices could have a material adverse impact on the Company's results of operations and cash flows and limit its ability to fund capital expenditures. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs could also further adversely impact the Company's business, including by weakening the Company's financial condition and reducing its liquidity, limiting the Company's ability to fund planned capital expenditures and operations, causing the Company to delay or postpone some of its capital projects or reallocate capital to different projects or regions, limiting the Company's access to sources of capital, such as equity and long-term debt, or reducing the carrying value of the Company's oil and gas properties, resulting in additional non-cash impairments.

 The Company's ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, and/or meet volume commitments under transportation services agreements may be adversely affected by pipeline and gathering system capacity constraints, the inability to procure and resell volumes economically, and various transportation interruptions.
 A portion of the Company's crude oil, natural gas, and NGL production in any region may be, and previously have been, interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, cyberattacks or terrorist events, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities, or interstate pipelines to transport the Company's production. Additionally, the Company has previously and may in the future voluntarily curtail production in response to market conditions, such as weak or negative prices. If a substantial amount of the Company's production is interrupted or curtailed at the same time, it could temporarily adversely affect the Company's cash flows. Further, if the Company is unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, the Company's cash flows could be adversely affected.
 The Company has previously not realized, and may in the future not realize, an adequate return on wells that it drills.
 Drilling for oil and gas involves numerous risks, including that the Company may not encounter commercially productive oil or gas reservoirs or may not recover all or any portion of its investment in the wells it drills. Management has previously determined, and may in the future determine, that future drilling or development activities will not, or are unlikely to, occur for a well or reservoir, based on drilling results, current or future estimated commodity prices or demand for oil, natural gas, and NGLs, or other information. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations are subject to a variety of risks, including unexpected drilling conditions (such as pressure or formation irregularities), equipment failures or accidents, catastrophic events, marine risks, adverse weather conditions, and increases in the cost of or shortages or delays in the availability of drilling rigs, equipment, and labor. In addition, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Any such events could have an adverse effect on the Company's future results of operations and financial condition. Exploration costs and dry hole expenses incurred by the Company during the reporting period are further discussed in this Annual Report on Form 10-K and reflected in the consolidated financial statements included herein.
 The Company's commodity price risk management and trading activities may prevent it from benefiting fully from price increases and may expose it to other risks.
 To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases. The Company's hedging arrangements may expose it to the risk of financial loss, including when production falls short of the hedged volumes, price-basis differentials widen, a hedging counterparty defaults, or an unexpected event materially impacts commodity prices.
 Global pandemics have previously, may continue to, and may in the future adversely impact the Company's business, financial condition, and results of operations; the global economy; the demand for and prices of oil, natural gas, and NGLs; and the performance of the Company's workforce.
 Global pandemics and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to such pandemics, including the COVID-19 pandemic, have previously adversely impacted and may from time to time in the future adversely impact the global economy, resulting in significant volatility in the global financial markets, and the demand for, and the prices of, oil, natural gas, and NGLs, which may materially adversely affect the Company's business, financial condition, cash flows, and results of operations. Additionally, the Company's operations rely on its workforce having access to its wells, platforms, structures, offices, and facilities. If a significant portion of the Company's workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions (including vaccine mandates and the reactions thereto), or other restrictions or adverse impacts resulting from a pandemic, the Company's business, financial condition, cash flows, and results of operations may be materially adversely affected.

 RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS
 The Company's operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of property, and environmental accidents.
 The Company's operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including well blowouts, explosions, fires, cratering, pipeline or other facility ruptures and spills, adverse weather conditions, including those impacting the Company's offshore operating areas, surface spillage and ground water contamination, and failure or loss of equipment. These events, including ineffective containment of such events, have previously and could in the future result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. If a significant amount of the Company's production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company's cash flows and, in turn, its results of operations could be materially and adversely affected.
 Weather and climate may have a significant adverse impact on the Company's revenues and production.
 Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price the Company receives for the commodities it produces. In addition, the Company's exploration, development, and production activities and equipment have been and can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of America, or major storms in the North Sea, each of which have previously caused and may cause a loss of production from temporary cessation of activity or lost or damaged equipment. The Company's planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against.
 The Company's insurance policies do not cover all of the risks the Company faces, which could result in significant financial exposure.
 Exploration for and production of crude oil, natural gas, and NGLs involves hazards, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company's international operations are also subject to political and economic risks. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks. While certain insurance policies of the Company may provide coverage for such events, if the Company were to incur a significant liability for which it was not fully insured, then it could have a material adverse effect on the Company's financial position, results of operations, and cash flows. In addition, if such an event were to occur, then the proceeds of any such insurance may not be paid in a timely manner or may not be sufficient to cover all of the Company's losses.
 A cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company's operations.
 There are numerous and evolving risks to the Company's data, technology, and information systems from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage, and employee malfeasance. The Company's operations are dependent on digital technologies, including to estimate reserves, process financial and operating data, analyze drilling information, and communicate with personnel. Unauthorized access to the Company's data, technology, and information systems could lead to operational disruption, communication interruption, disruption in access to financial reporting systems, and loss, misuse, or corruption of data and proprietary information. In addition, unauthorized access to third party information systems could interrupt the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company's production. Cyberattacks directed at oil and gas distribution systems have previously and could again in the future damage critical distribution and storage assets or the environment. The potential impacts of a cyber incident could be made worse by a delay or failure to detect the occurrence, continuance, or extent of such an incident.

 The Company expends significant resources to protect its digital systems and data, whether such data is housed internally or externally by third parties, against cyberattacks and may be required to expend further resources as cyber threat actors become more sophisticated and as regulations related to cyberattacks become more complex. Cyberattacks, including malicious software, data privacy breaches by employees, insiders, or others with authorized access to the Company's systems, cyber or phishing attacks, ransomware attacks, supply chain vulnerabilities, business email compromises, other attempts to gain unauthorized access to the Company's data and systems, and other electronic security breaches could have a material adverse effect on the Company's business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.
 While the Company has not suffered any material losses as a result of cyberattacks, there is no assurance that the Company will not suffer such losses in the future.
 Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects.
 The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company's anticipated completion dates. These projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical vessels and equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events and development costs (including for equipment and personnel) may adversely affect the Company's large development projects (including forcing the Company to abandon such projects) and its ability to participate in large-scale development projects in the future.
 RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE
 Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.
 The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, future oil and gas production is highly dependent upon the Company's level of success in adding reserves through exploration and development activities, identifying additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquiring additional properties containing proved reserves. As oil or natural gas prices increase, the Company's cost for additional reserves could also increase.
 The Company may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
 Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. There can be no assurance that acquisitions will not adversely impact the Company's operating results, particularly during their integration into the Company's ongoing operations.
 Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.
 There are numerous uncertainties inherent in the process of estimating crude oil, natural gas, and NGL reserves and their value, which is highly subjective and relies on the quality of available data and the accuracy of engineering and geological interpretation. The Company's reserves estimates are based on 12-month average prices, except where contractual arrangements exist, causing reserves quantities to change when actual prices increase or decrease. The estimates of the Company's proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including historical production from the area compared with production from other areas, the results of drilling, testing, and production for a reservoir over time, the use of volumetric analysis versus production history, the effects of changes in laws (including emissions regulations, infrastructure modernization requirements, and taxes), future operating, workover, and remediation costs, and capital expenditures. For example, during 2024, the Company recorded $796 million of impairments for certain of its North Sea proved properties as a result of several new regulatory guidelines and obligations in the U.K. Accordingly, reserves estimates may be subject to adjustment, and actual production, revenue, and expenditures with respect to the Company's reserves likely will vary, possibly materially, from estimates. In addition, realization or recognition of

 proved undeveloped reserves will depend on the Company's development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
 Certain of the Company's undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
 A sizeable portion of the Company's acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company's drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
 RISKS RELATED TO COUNTERPARTIES
 The credit risk of financial institutions could adversely affect the Company and result in a significant loss.
 The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions, including in the form of derivative transactions in connection with any hedges and claims under the Company's insurance policies, which expose the Company to credit risk in the event of default of the counterparty. Deterioration or volatility in the credit or financial markets, changes in commodity prices, and changes in a counterparty's liquidity may affect the counterparties' ability to fulfill their existing obligations to the Company. In addition, if any lender under the Company's credit facilities is unable to fund its commitment, the Company's liquidity may be reduced by an amount up to the aggregate amount of such lender's commitment thereunder. Furthermore, the bankruptcy of one or more of the Company's counterparties or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities, and the Company could incur a significant loss.
 The distressed financial conditions of the Company's partners and the purchasers of the Company's products or assets have had and could have an adverse impact on the Company in the event they are unable to reimburse the Company for their share of costs or to pay the Company for the products or services the Company provides.
 The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. As a result of previous severe declines in commodity prices, some of the Company's customers and non-operating partners experienced severe financial problems. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company (including as a result of their filing for bankruptcy or other liquidity constraints) or that such a default or defaults will not have a material adverse effect on the Company's business, financial position, future results of operations, or future cash flows.
 The Company's liabilities, including for the decommissioning of previously owned assets, could be adversely affected in the event one or more of its transaction counterparties are financially distressed or become the subject of a bankruptcy case.
 The agreements relating to the Company's divestment of domestic and international assets generally contain provisions pursuant to which liabilities related to past and future operations (one of the most significant of which is the decommissioning of wells and facilities) are allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, surety bonds, letters of credit, and similar arrangements. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress or bankruptcy, which may force the Company to use available cash to cover the costs of such obligations, pending final resolution of any claims the Company may have against the counterparty, which could adversely impact the Company's cash flows, operations, or financial condition.
 For additional information regarding Apache's prior Gulf of America properties and the bankruptcy of the purchaser of those properties, see the information set forth under "Potential Decommissioning Obligations on Sold Properties" in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

 The Company does not always control decisions made under joint operating agreements or joint ventures, and the parties to such agreements or ventures may fail to meet their obligations.
 The Company conducts many of its exploration and production (E&P) operations through joint operating agreements or joint ventures with other parties. The Company may not control decisions made under such agreements or ventures, either because it does not have a controlling interest in the venture or is not an operator under the agreement. The other parties to these arrangements may have economic, business, or legal interests or goals that are inconsistent with the Company's, and, therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to such agreements or ventures may be unable to meet their economic or other obligations, and the Company may be required to fulfill those obligations alone. In either case, the value of the investment and the Company's business and financial condition may be adversely affected.
 RISKS RELATED TO CAPITAL MARKETS
 A downgrade in the Company's credit rating could negatively impact its cost of and ability to access capital.
 The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company's credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company's ability to access debt markets in the future and increase the cost of future debt. During 2024, Standard and Poor's upgraded the Company's rating to BBB-/Stable, Moody's affirmed the Company's rating at Baa3/Stable, and Fitch affirmed the Company's rating at BBB-/Stable. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.
 Market conditions may restrict the Company's ability to obtain funds for future development and working capital needs, which may limit its financial flexibility.
 The financial markets are subject to fluctuation and are vulnerable to unpredictable swings. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company's future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of the Company's property interests.
 The Company's syndicated revolving credit facilities currently mature in January 2030. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to the Company or its subsidiaries or the composition of such lenders.
 The Company's ability to declare and pay dividends, and to repurchase common stock, is subject to limitations.
 The payment of future dividends on, and any repurchases of, the Company's common stock are each subject to the discretion of the Board of Directors, taking into consideration, among other factors, the Company's operating results, available cash, overall financial condition, credit risks, capital requirements, restrictions under the Company's indentures and other financing agreements, restrictions under Delaware law, general business and market conditions, and other factors the Board of Directors deems relevant. The Board of Directors is not required to declare dividends on or repurchase APA's common stock and may decide not to declare dividends or repurchase common stock at the current rate or at all. Any downward revision in the amount of dividends the Company pays to shareholders, or reduction in the pace of share repurchases, could have an adverse effect on the market price of the Company's common stock.
 Actions by advocacy groups to advance climate change and energy transition initiatives, unfavorable ESG ratings, and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from companies in the oil and gas industry, which could negatively impact the Company's access to and costs of capital or the market for the Company's securities.
 Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Unfavorable ESG ratings may lead to negative investor and public sentiment toward the Company, which may cause the market for the Company's securities to be negatively impacted.

 In addition, a number of advocacy groups have campaigned for governmental and private action to influence change in the business strategies of oil and gas companies, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These campaign efforts have resulted in the divestment of investments in the oil and gas industry and increased pressure on lenders and other financial services companies to limit or curtail activities with oil and gas companies. If investors or financial institutions shift funding away from companies in the oil and gas industry, the Company's access to and costs of capital or the market for the Company's securities may be negatively impacted.
 RISKS RELATED TO FINANCIAL RESULTS
 The Company faces strong industry competition that may have a significant negative impact on the Company's results of operations.
 Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes for leases, equipment, labor, key personnel, and marketing of crude oil, natural gas, and NGL production, the prices of which impact the costs of properties and the financial resources available to pursue acquisitions. These competitive pressures may have a significant negative impact on the Company's results of operations.
 The Company's ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.
 As described in Note 10—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an "ownership change" under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company's equity ownership by five-percent shareholders over a three-year period, the Company's ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company's operating results or cash flows.
 The Company's ability to realize its deferred tax assets may be limited if it experiences changes in expected future cash flows related to reserves or ARO.
 As described in Note 10—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, the Company assesses the realizability of its deferred tax assets based on its ability to generate sufficient future taxable income. Future changes in expected cash outflows for ARO or inflows from reserves could impact the Company's ability to realize its deferred tax assets in future periods.
 APA is a holding company and is dependent on the operations of and distributions from its subsidiaries, including Apache.
 As a holding company, APA has no business operations of its own, and its primary assets are its ownership interests in its subsidiaries, including Apache. As a result, APA relies on cash flows from its subsidiaries to pay dividends on, and make repurchases of, its common stock and to meet its financial obligations, including to service any amounts outstanding under its notes, debentures, credit agreements or commercial paper program, and any additional financial obligations that the Company may incur from time to time in the future. If the subsidiaries are limited in their ability to distribute cash to the Company, such as through legal or contractual limitations, or if the subsidiaries' earnings or other available assets are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary to meet the Company's financial obligations, then the Company's financial condition, cash flows, and reputation may be materially adversely affected.
 RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS
 The Company may incur significant costs related to environmental matters.
 As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, require significant capital expenditures to comply with increasingly strict environmental laws and regulations, and require suspension or cessation of operations in affected areas. The Company's efforts to limit its

 exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company's results of operations and cash flows.
 The Company's U.S. operations are subject to governmental risks.
 The Company's U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations, including restrictions on production, changes in taxes and other amounts payable to governments, price or gathering rate controls, environmental protection laws and regulations, and security for plugging, abandonment, and decommissioning obligations, including in the Gulf of America.
 New political developments, the enactment of new or stricter laws or regulations or other governmental actions impacting the Company's U.S. operations, and increased liability for companies operating in the oil and gas E&P industry may adversely impact the Company's results of operations.
 Proposed federal, state, or local regulation regarding hydraulic fracturing could increase the Company's operating and capital costs.
 The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for oil and natural gas to migrate toward the wellbore, typically at substantial depths in formations with low permeability. Governmental entities have previously taken actions to regulate, and several proposals are before the U.S. Congress that, if implemented, would further regulate, hydraulic fracturing. If adopted, such regulations could impose more stringent permitting, reporting, and well construction requirements or otherwise seek to ban fracturing activities. These activities and the associated water disposal activities are under scrutiny due to their potential environmental and physical impacts, including possible water contamination and possible links to induced seismicity. Any new federal, state, or local restrictions on hydraulic fracturing could result in increased compliance costs or additional restrictions on the Company's U.S. operations.
 Changes in tax rules and regulations, or interpretations thereof, may adversely affect the Company's business, financial condition, and results of operations.
 Federal, state, and foreign income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. For example, the U.K. enacted the Energy Profits Levy (EPL), which assesses an additional levy of 35 percent, effective for the period of January 1, 2023, through March 31, 2028, on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Further changes to the EPL regime were announced in 2024, with enactment expected in 2025. Such changes, effective for the period of November 1, 2024, through March 31, 2030, would increase the levy to 38 percent, remove certain allowances, and extend the EPL period. Additionally, in the U.S., the Inflation Reduction Act of 2022 introduced a new 15 percent corporate alternative minimum tax (Corporate AMT) for taxable years beginning after December 31, 2022, on applicable corporations with an average annual adjusted financial statement income (AFSI) that exceeds $1.0 billion for any three consecutive tax years preceding the tax year at issue. Effective January 1, 2024, the Company is subject to the Corporate AMT. Accordingly, any resulting Corporate AMT liability could adversely affect the Company's future financial results, including earnings and cash flows.
 Previous legislative proposals, if enacted into law, could make significant changes to tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas E&P companies. These changes include, but are not limited to, the repeal of the percentage depletion allowance for oil and gas properties, the elimination of current deductions for intangible drilling and development costs, and an extension of the amortization period for certain geological and geophysical expenditures. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development. The Company is unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect the Company's business, financial condition, and results of operations.
 RISKS RELATED TO CLIMATE CHANGE
 The impacts of energy transition could adversely affect the Company's business, operating results, and financial condition.
 In recent years, increasing attention has been given to corporate activities related to climate change and energy transition. This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power, and the

 development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more energy-efficient products and services.
 These developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for, and in turn the prices the Company receives for, its crude oil, natural gas, and NGL products, which could materially and adversely affect the Company's business and financial performance.
 Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact the Company's business.
 Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company's operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company's cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions. Moreover, in January 2024, the EPA announced a proposed rule to assess a charge on certain methane emissions in the oil and gas industry. The Company is currently evaluating the proposed rule and its applicability to the Company and is monitoring ongoing litigation related to the proposed rule.
 Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts.
 Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company's operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications.
 Enhanced focus on ESG matters could have an adverse effect on the Company's operations.
 Enhanced focus on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory review, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company's access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and regulatory approvals. Negative public perception could cause the permits or regulatory approvals the Company requires to be withheld, delayed, or burdened by requirements that restrict the Company's ability to profitably conduct its business.
 The Company's estimates used in various scenario planning analyses could differ materially from actual results and could expose the Company to new or additional risks.
 Given the dynamic nature of the Company's business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company's internally prepared base-case pricing analysis averaged out to the year 2040. Given the numerous estimates that are required to run these scenarios, the Company's estimates could differ materially from actual results. The Company publicly discloses these metrics and its related assumptions and analysis in its annual sustainability report. By electing to disclose these metrics, the Company may face increased scrutiny related to its ESG initiatives. Any harm to the Company's reputation resulting from publicly disclosing such these metrics, expanding disclosures related to such metrics, or failing to achieve such metrics or abiding by such disclosures could adversely affect the Company's business, financial performance, and growth.
 The treatment and disposal of produced water is becoming more highly regulated and restricted and could expose the Company to additional costs or limit certain operations.
 The treatment and disposal of produced water is becoming more highly regulated and restricted. Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection) and to require the monitoring of seismic activity. While the Company remains focused on reusing or recycling water over disposal of water, the Company's costs for obtaining and disposing of water

 could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water and restrictions related to disposal wells may increase the Company's operating costs or capital expenses or cause the Company to limit production, which could materially and adversely affect its business, results of operations, and financial conditions.
 RISKS RELATED TO INTERNATIONAL OPERATIONS
 International operations have uncertain political, economic, and other risks.
 The Company's operations outside the U.S. are based primarily in Egypt and the U.K., with significant exploration and appraisal activities offshore Suriname. On a barrel equivalent basis, approximately 38 percent of the Company's 2024 production was outside the U.S., and approximately 28 percent of the Company's estimated proved oil and gas reserves as of December 31, 2024, were located outside the U.S. As a result, a significant portion of the Company's production and resources are subject to the increased political and economic risks and other factors associated with international operations, including, but not limited to strikes and civil unrest; war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts; import and export regulations; taxation policies and investment restrictions; price controls; exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds; constrained oil or natural gas markets dependent on demand in a single or limited geographical area; laws and policies of the U.S. affecting foreign trade, including trade sanctions and tariffs; the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates; the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and difficulties in enforcing the Company's rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
 Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company's interests could decrease in value or be lost. Even the Company's smaller international assets may affect its overall business and results of operations by distracting management's attention from its more significant assets. Certain regions of the world in which the Company operates have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as the Company's. In an extreme case, such a change could result in termination of contract rights and expropriation of the Company's assets. This could adversely affect the Company's interests and its future profitability.
 The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which the Company operates, may have on the oil and gas industry in general and on the Company's operations in particular is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets or indirect casualties of an act of terror or war. The Company may be required to incur significant costs in the future to safeguard its assets against terrorist activities.
 A further deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on the Company's business.
 Further deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company's assets or resource nationalization, and/or forced renegotiation or modification of the Company's existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company's business and operations. Additionally, deteriorating economic conditions in Egypt have led to a shortage of foreign currency, including U.S. dollars, resulting in a decline in the timeliness of payments from EGPC. As described under "Revenue Recognition—Payment Terms and Contract Balances" in Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, the Company's receivable balance from EGPC in the past year has gradually increased as payments for the Company's Egyptian oil and gas sales have been delayed for periods longer than historically experienced. A continuation or worsening of the currency shortage in Egypt or further deterioration of economic conditions there could lead to additional payment delays, deferrals of payment, or non-payment in the future. The Company's operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of the Company's 2024 production and accounted for 12 percent of the Company's year-end estimated proved reserves and 21

 percent of the Company's estimated discounted future net cash flows. If conditions continue to deteriorate in Egypt, then it could materially and adversely affect the Company's business, financial condition, and results of operations.
 The Company's operations are sensitive to currency rate fluctuations.
 The Company's operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. The Company's financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect the Company's results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.
 GENERAL RISK FACTORS
 Certain anti-takeover provisions in the Company's charter and Delaware law could delay or prevent a hostile takeover.
 The Company's charter authorizes the Board of Directors to issue preferred stock in one or more series and to determine the voting rights and dividend rights, dividend rates, liquidation preferences, conversion rights, redemption rights, including sinking fund provisions and redemption prices, and other terms and rights of each series of preferred stock. In addition, Delaware law imposes restrictions on mergers and other business combinations between the Company and any holder of 15 percent or more of APA's outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of the Company that would have been financially beneficial to APA's shareholders.

 ITEM 1B.
 UNRESOLVED STAFF COMMENTS

 None.

 ITEM 1C.

 CYBERSECURITY

 Risk Management and Strategy
 The Company maintains a cybersecurity program that establishes safeguards for protecting the confidentiality, integrity, and availability of the Company's data, technology, and information systems, and the material risks associated with the threats identified from time to time under the cybersecurity program are incorporated into the Company's corporate risk register. The program includes general controls for managing changes in and access to the Company's information technology environment, cybersecurity awareness and training programs to help employees identify and mitigate against cybersecurity threats, cybersecurity incident response plans and third-party incident response retainers to help expedite the Company's response in the event of a cybersecurity incident, and guidelines regarding system vulnerability management, third-party threat intelligence, endpoint detection and response solutions, and network security measures.
 The program also establishes protocols for identifying and managing material risks related to cybersecurity threats associated with the Company's use of third-party service providers. The Company monitors and oversees the material risks related to vulnerabilities, threats, and incidents impacting its third-party service providers via onboarding reviews, threat intelligence reports, and annual assessments. As an example of the Company's efforts to manage third-party cybersecurity risks, when third parties are engaged to provide software-as-a-service offerings, the Company's standard licensing terms require such third parties to utilize safeguards to protect the Company's data, in compliance with applicable standards from the International Organization for Standardization (ISO) regarding security techniques, and to notify the Company within 24 hours of becoming aware of a cybersecurity incident impacting the Company's data.
 As of December 31, 2024, no risks from cybersecurity threats or incidents have materially affected or are reasonably likely to materially affect the Company's business strategy, results of operations, or financial condition.
 Governance
 The standing Cybersecurity Committee of the Company's Board of Directors assists with oversight of the Company's cybersecurity program and the material risks associated with the threats identified under the program. Given the Cybersecurity Committee's chair's previous military experience in positions relevant to information security and his NACD-sponsored CERT Certificate in Cybersecurity Oversight from Carnegie Mellon University's Software Engineering Institute, the committee benefits from his perspectives, skills, and training when reviewing and managing the Company's exposure to cybersecurity risks.

 As stated in its charter, the Cybersecurity Committee's responsibilities include:
 • providing oversight of the Company's cybersecurity policies, procedures, and plans, including the quality and effectiveness of the cybersecurity program;
 • reviewing the Company's policies and procedures related to its preparation for, defense against, response to, and recovery from material cybersecurity incidents;
 • reviewing with management the plans and methodology for periodic assessments of the Company's cybersecurity program by outside professionals, including the findings of such assessments and plans to remediate any material deficiencies identified by such assessments;
 • overseeing the Company's management of risks related to its cybersecurity systems and processes;
 • reviewing with management any cybersecurity insurance program the Company may procure, including with respect to coverage and limits; and
 • overseeing the preparation of the Company's disclosures in its reports filed with the Securities and Exchange Commission relating to the Company's cybersecurity systems.
 The Cybersecurity Committee also has authority to retain cybersecurity and other consultants and advisors to assist and advise the committee in its evaluation of the Company's cybersecurity program.
 The Cybersecurity Committee receives regular reports from Company management regarding the Company's cybersecurity systems and programs, and the committee from time to time also receives updates from external cybersecurity specialists on cybersecurity trends and incidents, including those that may be particularly relevant to the Company's industry or operations. In addition, in exercising its oversight responsibilities, the Cybersecurity Committee has full access to Company management and may inquire into any matter that it considers to be of material concern to the committee or the full Board of Directors.
 The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee's discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company's internal control over financial reporting.
 APA's Executive Vice President, Administration, is primarily responsible for identifying, assessing, and managing the material risks associated with cybersecurity threats and the incidents identified from time to time thereunder. He manages the Company's Information Security Team, which comprises cybersecurity professionals responsible for the day-to-day operation of the Company's cybersecurity program and managing the Company's threat intelligence, vulnerability management, forensics, and security architecture systems. APA's Executive Vice President, Administration, has 35 years of experience managing data and technology in the energy industry, including serving as the Company's CIO from 2015-2020. He receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The Executive Vice President, Administration, reports directly to APA's Chief Executive Officer and presents all relevant information to the Cybersecurity Committee.
 Additionally, the Company's CyberSmart Defender Network, which is a multi-disciplinary team that includes representatives from across the Company's various departments, is responsible for raising awareness of cybersecurity issues, sharing learnings, and gaining access to advanced cybersecurity information and training.
 Under the direction of the Executive Vice President, Administration, management's responsibilities with respect to the Company's cybersecurity program include (i) identifying and managing cybersecurity risks, (ii) coordinating cybersecurity incident response, (iii) assessing the health and maturity of the Company's cybersecurity policies, procedures, and plans, including the program, and (iv) reporting overall progress to the Cybersecurity Committee and to the full Board of Directors.
 For additional information regarding relevant cybersecurity risks, see Item 1A Risk Factors "A cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company's operations."

 ITEM 3.
 LEGAL PROCEEDINGS

 The information set forth under "Legal Matters" and "Environmental Matters" in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K is incorporated herein by reference.

 ITEM 4.
 MINE SAFETY DISCLOSURES

 None.

 ITEM 5.
 MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

 APA's common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol "APA." The closing price of APA's common stock, as reported by the Nasdaq for January 31, 2025, was $21.93 per share. As of January 31, 2025, there were 364,064,316 shares of APA's common stock outstanding held by approximately 3,700 stockholders of record and 243,000 beneficial owners.
 The Company has paid cash dividends on its common stock for 60 consecutive years through December 31, 2024. When, and if, declared by the Company's Board of Directors, future dividend payments will depend upon the Company's level of earnings, financial requirements, and other relevant factors.
 Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption "Equity Compensation Plan Information" in the proxy statement relating to the Company's 2025 annual meeting of stockholders, which is incorporated herein by reference.
 Issuer Purchases of Equity Securities
 The table below sets forth information with respect to shares of common stock repurchased by APA during 2024.

 Period
 Purchased
 Average Price Paid per Share
 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)

 Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs

 January 1 to January 31, 2024

 2,226,352
 $
 34.22
 2,226,352
 41,693,267

 February 1 to February 29, 2024

 784,765
 30.59
 784,765
 40,908,502

 March 1 to March 31, 2024

 —
 —
 —
 40,908,502

 April 1 to April 30, 2024

 —
 —
 —
 40,908,502

 May 1 to May 31, 2024

 —
 —
 —
 40,908,502

 June 1 to June 30, 2024

 1,480,072
 28.72
 1,480,072
 39,428,430

 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

 October 1 to October 31, 2024

 —
 —
 —
 39,326,125

 November 1 to November 30, 2024

 2,588,969
 22.20
 2,588,969
 36,737,156

 December 1 to December 31, 2024

 1,980,034
 21.52
 1,980,034
 34,757,122

 Total
 9,162,497
 $
 26.83

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

 The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company's common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company's common stock with the cumulative total return of the Standard & Poor's 500 Index (S&P 500 Index) and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2019, through December 31, 2024. The stock performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

 COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
 Among APA Corporation, the S&P 500 Index,
 and the Dow Jones U.S. Exploration & Production Index

 * $100 invested on 12/31/19 in stock or index, including reinvestment of dividends.
 Fiscal year ending December 31.

 2019
 2020
 2021
 2022
 2023
 2024

 APA Corporation
 $
 100.00
 $
 56.30
 $
 107.40
 $
 189.58
 $
 149.35
 $
 99.41

 S&P 500 Index
 100.00
 118.40
 152.39
 124.79
 157.59
 197.02

 Dow Jones U.S. Exploration & Production Index
 100.00
 66.35
 113.41
 180.98
 189.15
 186.27

 ITEM 6.
 SELECTED FINANCIAL DATA

 Omitted.

 ITEM 7.
 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 in conjunction with the Company's Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Annual Report on Form 10-K are incorporated by reference to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of APA Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (filed with the SEC on February 22, 2024).

 Overview
 APA is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids (NGLs). The Company's business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation's primary assets are its ownership interests in its consolidated subsidiaries.
 APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.
 Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, trade disputes, 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 example, the Company curtailed production in the Permian Basin in the second half of 2024 in response to weakness in Waha natural gas and NGL prices; however, in Egypt, the Company contracted an additional drilling rig in late 2024 after signing an agreement to incentivize gas exploration and production at new pricing. In 2023, the Company decided to suspend drilling activity in the North Sea, as increasing cost and tax burdens impacted the competitiveness of these assets within the Company's portfolio. Capital investment plans have accordingly been aligned across other areas of the portfolio while maintaining a focus on the Company's capital returns framework.
 The Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns.
 • The Company believes returning 60 percent of free cash flow through dividends and share repurchases creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
 • The Company pays a quarterly dividend of $0.25 per share on its common stock.
 • Beginning in the fourth quarter of 2021 and through the end of 2024, the Company has repurchased 85.3 million shares of the Company's common stock. Subsequent to year-end 2024 and through the date of this filing on February 28, 2025, the Company repurchased 3.9 million shares, and as of February 28, 2025, the Company had remaining authorization to repurchase up to 30.9 million shares under the Company's share repurchase programs.

 Financial and Operational Highlights
 During 2024, the Company reported net income attributable to common stock of $804 million, or $2.27 per diluted share, compared to net income of $2.9 billion, or $9.25 per diluted share, in 2023. Net income in 2024 was primarily impacted by impairments of $1.1 billion, which included oil and gas property impairments of $796 million in the North Sea and $315 million in the U.S., and lower realized crude oil and natural gas prices during the year compared to 2023. The Company also recorded higher oil and gas revenues and associated operating expenses resulting from the Callon acquisition.
 The Company generated $3.6 billion of cash from operating activities in 2024, which was $491 million or 16 percent higher than 2023. APA's higher operating cash flows for 2024 were primarily driven by higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices. The Company repurchased 9.2 million shares of its common stock for $246 million and paid $353 million in dividends to APA common stockholders during 2024.
 Key operational highlights for the year include:
 • Daily boe production from the Company's U.S. assets, which increased 30 percent from 2023, accounted for 62 percent of the Company's worldwide production during 2024. The Company averaged nine drilling rigs in the U.S. during the year, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin, and drilled and brought online 159 operated wells in 2024. The Company's drilling was primarily focused on oil prospects, and combined with the Callon acquisition, oil production increased approximately 63 percent in the U.S. compared to the prior year. The Company's core Permian Basin development program continues to represent key growth areas for the U.S. assets.
 • During the first quarter of 2024, the Company completed a three-well exploration program in Alaska, confirming a working petroleum system on the Company's acreage. The Company is currently drilling an additional exploration well on this acreage. The Company holds a 50 percent ownership interest in the project.
 • In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 14 drilling rigs and drilled 62 new productive wells during 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. The 2024 gross and net production from the Company's Egypt assets decreased 6 percent and 4 percent, respectively, from 2023.
 • During the fourth quarter of 2024, the Company entered into a new gas sales agreement which could result in improved pricing if certain production thresholds are met. The new gas sales agreement creates the potential for significant new drilling inventory with returns on par with oil.
 • During the second quarter of 2023, the Company suspended all new drilling activity in the North Sea. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company's investment program in the North Sea is now directed toward asset safety and integrity.
 • In October 2024, the Company announced that its subsidiary reached a positive final investment decision for the first oil development, named GranMorgu, in Block 58 offshore Suriname. This development will include production from the Krabdagu and Sapakara oil discoveries. These fields, located in water depths between 100 and 1,000 meters, will be produced through a system of subsea wells connected to a floating production, storage and offloading (FPSO) unit located 150 km off the Suriname coast, with an oil production capacity of 220,000 barrels per day. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its 4-year production plateau and will feature technology that minimizes greenhouse gas emissions. Total investment is estimated at $10.5 billion, with APA's share of the investment subject to the existing agreement with TotalEnergies to carry a portion of Apache's appraisal and development capital. First oil is anticipated in 2028.
 For a more detailed discussion related to the Company's various geographic segments, refer to "Exploration and Production—Operating Areas" set forth in Part I, Items 1 and 2 of this Annual Report on Form 10-K.

 Acquisition and Divestiture Activity
 Over the Company's history, it has repeatedly demonstrated the ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize APA's portfolio of assets in response to these changes. Most recently, the Company has completed a series of acquisitions and divestitures designed to enhance the Company's portfolio and monetize nonstrategic assets in order to allocate resources to more impactful exploration and development opportunities. These acquisitions and divestitures include:
 • 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 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.
 • Sale of Non-core Permian Basin Properties On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $1.1 billion and associated asset retirement obligation of $224 million for total cash proceeds of $869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf.
 • Non-core Acreage Divestiture During 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 $255 million and the assumption of asset retirement obligations of $42 million.
 • Mineral Rights Divestiture During 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $394 million subject to post-closing adjustments.
 • Sales of Kinetik Shares During 2022 and 2023, the Company sold a portion of its Kinetik Shares for cash proceeds of $224 million and $228 million, respectively. During the first quarter of 2024, the Company sold its remaining shares of Kinetik Class A Common Stock for cash proceeds of $428 million. On April 3, 2024, the Company's designated director resigned from the Kinetik Holdings, Inc. (Kinetik) board of directors.
 For detailed information regarding APA's acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

 Results of Operations

 Oil, Natural Gas, and Natural Gas Liquids Production Revenues
 The Company's production revenues and respective contribution to total revenues by country are as follows:

 2024
 2023
 2022

 $ Value
 % Contribution
 $ Value
 % Contribution
 $ Value
 % Contribution

 ($ in millions)

 Oil Revenues:

 $
 3,572
 %
 $
 2,241
 %
 $
 2,458
 %

 2,620
 %
 2,683
 %
 3,145
 %

 %
 1,073
 %
 1,232
 %

 $
 6,966
 %
 $
 5,997
 %
 $
 6,835
 %

 Natural Gas Revenues:

 $
 %
 $
 %
 $
 %

 %
 %
 %

 %
 %
 %

 $
 %
 $
 %
 $
 1,569
 %

 NGL Revenues:

 $
 %
 $
 %
 $
 %

 —
 —
 %
 —
 —
 %
 %

 %
 %
 %

 $
 %
 $
 %
 $
 %

 Oil and Gas Revenues:

 $
 4,315
 %
 $
 3,018
 %
 $
 4,141
 %

 2,933
 %
 3,029
 %
 3,521
 %

 %
 1,338
 %
 1,558
 %

 $
 8,196
 %
 $
 7,385
 %
 $
 9,220
 %

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

 The following table presents production volumes by country:

 2024
 Increase
(Decrease)
 2023
 Increase
(Decrease)
 2022

 Oil Volumes – b/d:

 128,531
 63%
 78,889
 12%
 70,398

 Egypt(3)(4)

 89,027
 —%
 89,129
 5%
 85,081

 26,340
 (24)%
 34,728
 7%
 32,578

 Total
 243,898
 20%
 202,746
 8%
 188,057

 Natural Gas Volumes – Mcf/d:

 483,446
 7%
 452,281
 (4)%
 473,292

 Egypt(3)(4)

 291,011
 (11)%
 325,778
 (9)%
 356,327

 39,986
 (20)%
 50,284
 42%
 35,327

 Total
 814,443
 (2)%
 828,343
 (4)%
 864,946

 NGL Volumes – b/d:

 73,877
 17%
 62,997
 —%
 62,727

 Egypt(3)(4)

 —
 NM
 —
 NM

 1,201
 (3)%
 1,240
 12%
 1,111

 Total
 75,078
 17%
 64,237
 —%
 64,034

 BOE per day:(1)

 282,983
 30%
 217,266
 2%
 212,007

 Egypt(3)(4)

 137,529
 (4)%
 143,425
 (1)%
 144,665

 34,204
 (23)%
 44,349
 12%
 39,577

 Total
 454,716
 12%
 405,040
 2%
 396,249

 (1)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.
 (2)Average sales volumes from the North Sea were 33,954 boe/d, 45,476 boe/d, and 40,812 boe/d for 2024, 2023, and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
 (3)Gross oil, natural gas, and NGL production in Egypt were as follows:

 2024
 2023
 2022

 Oil (b/d)
 137,150
 141,985
 137,260

 Natural Gas (Mcf/d)
 443,551
 500,080
 555,562

 NGL (b/d)
 —
 —

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

 2024
 2023
 2022

 Oil (b/d)
 29,698
 29,739
 28,200

 Natural Gas (Mcf/d)
 97,078
 108,703
 118,074

 NGL (b/d)
 —
 —

 NM — Not Meaningful

 Pricing
 The following table presents pricing information by country:

 2024
 Increase
(Decrease)
 2023
 Increase
(Decrease)
 2022

 Average Oil Price - Per barrel:

 $
 75.92
 (2)%
 $
 77.84
 (19)%
 $
 95.68

 Egypt
 80.41
 (2)%
 82.47
 (19)%
 101.25

 80.74
 (2)%
 82.75
 (18)%
 100.87

 Total
 78.08
 (3)%
 80.72
 (19)%
 99.11

 Average Natural Gas Price - Per Mcf:

 $
 0.71
 (61)%
 $
 1.80
 (66)%
 $
 5.31

 Egypt
 2.94
 1%
 2.91
 2%
 2.85

 10.84
 (17)%
 13.02
 (44)%
 23.36

 Total
 1.97
 (32)%
 2.91
 (42)%
 4.98

 Average NGL Price - Per barrel:

 $
 22.83
 9%
 $
 20.85
 (38)%
 $
 33.41

 Egypt
 —
 NM
 —
 NM
 76.80

 47.59
 —%
 47.77
 (29)%
 67.07

 Total
 23.37
 8%
 21.54
 (38)%
 34.51

 NM — Not Meaningful
 Crude Oil Prices A substantial portion of the Company's crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company's control. Average realized crude oil prices for 2024 were down 3 percent compared to 2023, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2024 averaged $78.08 per barrel.
 Continued volatility in the commodity price environment reinforces the importance of the Company's asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Prices for all types and grades of crude oil generally move in the same direction.
 Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company's primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company's primary gas-producing regions follows:
 • The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company's U.S. realizations averaged $0.71 per Mcf in 2024, a 61 percent decrease from an average of $1.80 per Mcf in 2023.
 • In Egypt, the Company's natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company's Egypt operations averaged $2.94 per Mcf in 2024, a one percent increase from an average of $2.91 per Mcf in 2023. In the fourth quarter of 2024, the Company entered into a new gas sales agreement, which could result in improved pricing if certain production thresholds are met. The new gas sales agreement, which is effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil.
 • Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company's North Sea operations averaged $10.84 per Mcf in 2024, a 17 percent decrease from an average of $13.02 per Mcf in 2023.

 NGL Prices The Company's U.S. NGL production, which accounted for 98 percent of the Company's total 2024 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
 Crude Oil Revenues
 Crude oil revenues for 2024 totaled $7.0 billion, a $969 million increase from the 2023 total of $6.0 billion. A 20 percent higher average daily production increased 2024 revenues by $1.2 billion compared to 2023, while a 3 percent decrease in average realized prices reduced revenues by $196 million. Average daily production in 2024 was 244 Mb/d, with prices averaging $78.08 per barrel. Crude oil sales accounted for 85 percent of the Company's 2024 oil and gas production revenues and 54 percent of its worldwide production.
 The Company's worldwide crude oil production increased 41 Mb/d compared to 2023, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were partially 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 Revenues
 Natural gas revenues for 2024 totaled $584 million, a $296 million decrease from the 2023 total of $880 million. A 32 percent decrease in average realized prices reduced 2024 revenues by $285 million compared to 2023, while 2 percent lower average daily production decreased revenues by $11 million. Average daily production in 2024 was 814 MMcf/d, with prices averaging $1.97 per Mcf. Natural gas sales accounted for 7 percent of the Company's 2024 oil and gas production revenues and 30 percent of its worldwide production.
 The Company's worldwide natural gas production decreased 14 MMcf/d compared to 2023, primarily a result of natural production decline in the North Sea and U.S., reduced gas-focused activity in Egypt, 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 Revenues
 NGL revenues for 2024 totaled $646 million, a $138 million increase from the 2023 total of $508 million. A 17 percent higher average daily production increased 2024 revenues by $95 million compared to 2023, while an 8 percent increase in average realized prices increased 2024 revenues by $43 million. Average daily production in 2024 was 75 Mb/d, with prices averaging $23.37 per barrel. NGL sales accounted for 8 percent of the Company's 2024 oil and gas production revenues and 16 percent of its worldwide production.
 The Company's worldwide NGL production increased 11 Mb/d compared to 2023, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, partially offset by natural production decline in the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S.

 Purchased Oil and Gas Sales
 Purchased oil and gas sales represent volumes primarily attributable to domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations and delivery commitments. Sales related to purchased volumes increased $647 million for the year ended December 31, 2024 to $1.5 billion from $894 million in 2023. Purchased oil and gas sales were partially offset by associated purchase costs of $1.0 billion and $742 million for the years ended December 31, 2024 and 2023, respectively. The increase in purchased oil and gas sales was primarily driven by increased oil volume sales coupled with activity associated with the Callon acquisition.

 Operating Expenses
 The table below presents a comparison of the Company's operating expenses for the years ended December 31, 2024, 2023, and 2022. All operating expenses include costs attributable to a noncontrolling interest in Egypt.

 2024
 2023
 2022

 $
 1,690
 $
 1,436
 $
 1,444

 Gathering, processing, and transmission

 1,047
 1,776

 Taxes other than income

 Depreciation, depletion, and amortization:

 Oil and gas property and equipment
 2,235
 1,500
 1,186

 Gathering, processing, and transmission assets

 Other assets

 1,129
 —

 Lease Operating Expenses (LOE)
 LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 54 percent of the Company's total 2024 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
 During 2024, LOE increased $254 million, or 18 percent, compared to 2023. On a per-boe basis, LOE increased $0.48, or 5 percent, compared to 2023, from $9.68 per boe to $10.16 per boe. The increase in absolute costs was primarily driven by higher operating and labor costs and workover activity associated with the Callon acquisition. The Company also had higher labor costs and other operating costs trending with general inflation across all regions, which were partially offset by changes in foreign currency exchange rates against the U.S. dollar.

 Gathering, Processing, and Transmission (GPT)
 GPT expenses include amounts paid to third-party carriers for gathering and transmission services for the Company's upstream natural gas production. Prior to the BCP Business Combination and the Company's deconsolidation of Altus on February 22, 2022, GPT expenses also included gathering and transmission services provided by Altus Midstream and midstream operating costs incurred by Altus. The following table presents a summary of these expenses:

 2024
 2023
 2022

 Third-party processing and transmission costs
 $
 $
 $

 Midstream service costs – ALTM

 —
 —

 Midstream service costs – Kinetik

 Upstream processing and transmission costs

 Midstream operating expenses
 —
 —

 Intersegment eliminations
 —
 —
 (18)

 Total Gathering, processing, and transmission
 $
 $
 $

 GPT costs increased $98 million compared to 2023, primarily the result of increased oil and NGL production volumes in the U.S., primarily associated with the Callon acquisition, as well as increased charges for transporting gas production.
 Purchased Oil and Gas Costs
 Purchased oil and gas costs increased $305 million for the year ended December 31, 2024, to $1.0 billion from $742 million in 2023. The increase is primarily driven by increased oil volume purchases coupled with activity associated with the Callon acquisition during 2024, partially offset by lower average natural gas prices during 2024 compared to the prior-year period. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $1.5 billion for the year ended 2024, as discussed above.
 Taxes Other Than Income
 Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes.
 Taxes other than income increased $63 million compared to 2023, primarily from higher severance taxes driven by increased U.S. production volumes primarily attributable to the Callon acquisition.
 Exploration Expenses
 Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:

 2024
 2023
 2022

 Unproved leasehold impairments
 $
 $
 $

 Dry hole expenses

 Geological and geophysical expenses

 Exploration overhead and other

 Total Exploration
 $
 $
 $

 Exploration expenses increased $118 million compared to 2023, primarily the result of dry hole expense associated with an exploration well in Suriname and 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 increased $21 million compared to 2023, primarily driven by higher overall labor costs across the Company and the Callon acquisition, partially offset by lower cash-based stock compensation expense resulting from changes in the Company's stock price in 2024. For additional information refer to Note 13—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 Transaction, Reorganization, and Separation (TRS) Costs
 TRS costs increased $153 million compared to 2023, primarily a result of transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in 2024 primarily comprised $147 million associated with the Callon acquisition, including $76 million of separation costs and $71 million of transaction and integration costs.
 Depreciation, Depletion and Amortization (DD&A)
 DD&A expenses on the Company's oil and gas property for the year ended December 31, 2024 increased $735 million compared to 2023. The Company's oil and gas property DD&A rate increased $3.32 per boe in 2024 compared to 2023, from $10.12 per boe to $13.44 per boe, driven by negative gas price-related reserve revisions in the U.S. Permian Basin and impacts resulting from the Callon acquisition in 2024. The increase on an absolute basis was also driven by higher capital expenditures incurred in the U.S. and the Callon acquisition.
 During 2024, the Company recorded $1.1 billion of impairments, which included $796 million of oil and gas property impairments in the North Sea, a $315 million impairment of certain oil and gas properties in the U.S. to agreed-upon proceeds for their disposition, and $18 million of inventory impairments in the North Sea and U.S. During 2023, the Company recorded $61 million of impairments, primarily in connection with valuations of drilling and operations equipment inventory upon the Company's decision to suspend drilling operations in the North Sea.
 Financing Costs, Net
 Financing costs incurred during 2024, 2023, and 2022 comprised the following:

 2024
 2023
 2022

 Interest expense
 $
 $
 $

 Amortization of debt issuance costs

 (29)
 (24)
 (18)

 Loss (gain) on extinguishment of debt
 —
 (9)

 Interest income
 (12)
 (10)
 (10)

 Total Financing costs, net
 $
 $
 $

 Net financing costs during 2024 increased $55 million compared to 2023, primarily driven by higher interest expense from higher average long-term debt balances.

 Provision for Income Taxes
 Income tax expense increased $741 million from an income tax benefit of $324 million during 2023 to an income tax expense of $417 million during 2024. The Company's 2024 effective income tax rate was primarily impacted by taxes related to foreign operations. During 2023, the Company's effective income tax rate was primarily impacted by a deferred tax benefit related to the release of a portion of its valuation allowance against U.S. deferred tax assets and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023.
 On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate, effective for the period of May 26, 2022 through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. As a result, the Company recorded a deferred tax expense of $174 million and $208 million related to the remeasurement of the U.K. deferred tax liability in 2023 and 2022, respectively.
 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. In 2024, the Company accrued tax expense of $74 million, which results in a tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years.
 In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, the Company does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
 Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be "more likely than not." The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized.
 During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion.
 For additional information regarding income taxes, refer to Note 10—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 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. The Company is under audit by the Internal Revenue Service and in various states and foreign jurisdictions as part of its normal course of business.

 Capital and Operational Outlook
 The Company continues to prudently manage its capital program against a volatile price environment and the effects of global inflation and rising interest rates. 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.
 In 2025, the Company plans to invest $2.5 billion to $2.6 billion in upstream capital investment. The Company is planning an 8-rig program in the Permian Basin, with approximately four rigs in each of the Midland and Delaware basins, and a 12-rig program in Egypt, with one rig dedicated to gas appraisal and exploration. This activity set translates to a combined development capital budget for the Permian Basin and Egypt of $2.2 billion to $2.3 billion. In addition, the Company will invest approximately $200 million for Suriname development and $100 million for exploration, primarily in Alaska.
 Based on this development capital budget, the Company anticipates production in 2025 to be slightly higher compared to 2024. This investment profile underscores the progress the Company has made on capital efficiency through the integration of Callon and stabilization of Egypt volumes. At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company's current commitment to return capital to shareholders through a mix of dividends and share buybacks remains unchanged.

 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.
 For the year ended December 31, 2024, the Company recognized downward reserve revisions related to decreases in commodity prices during the year. The Company's estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2024, 2023, and 2022, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 17—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 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 Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K.

 Sources and Uses of Cash
 The following table presents the sources and uses of the Company's cash and cash equivalents for the years presented:

 2024
 2023
 2022

 Sources of Cash and Cash Equivalents:

 Net cash provided by operating activities
 $
 3,620
 $
 3,129
 $
 4,943

 Proceeds from commercial paper and revolving credit facilities, net

 —
 —

 Proceeds from asset divestitures
 1,609

 Proceeds from term loan facility

 1,500
 —
 —

 Proceeds from sale of Kinetik shares

 Total Sources of Cash and Cash Equivalents
 7,157
 3,386
 5,969

 Uses of Cash and Cash Equivalents:

 Additions to oil and gas property(1)

 2,851
 2,313
 1,770

 Acquisition of Delaware Basin properties
 —

 Leasehold and property acquisitions

 Payments on term loan facility

 —
 —

 Payments on commercial paper and revolving credit facilities, net

 —

 Payments on Callon Credit Agreement
 —
 —

 Payments on fixed-rate debt

 1,641
 1,493

 Dividends paid to APA common stockholders

 Distributions to noncontrolling interest – Egypt

 1,423

 Deconsolidation of Altus cash and cash equivalents
 —
 —

 Other, net
 —

 Total Uses of Cash and Cash Equivalents
 6,619
 3,544
 6,026

 Increase (decrease) in cash and cash equivalents
 $
 $
 (158)
 $
 (57)

 (1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Annual Report on Form 10-K, which include accruals.
 Sources of Cash and Cash Equivalents
 Net Cash Provided by Operating Activities Operating cash flows are the Company's primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.
 Net cash provided by operating activities for the year ended December 31, 2024 totaled $3.6 billion, up $491 million from the year ended December 31, 2023, primarily due to higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices.
 For a detailed discussion of commodity prices, production, and operating expenses, refer to "Results of Operations" in this Item 7. 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 IV, Item 15 of this Annual Report on Form 10-K.
 Proceeds from Asset Divestitures The Company received $1.6 billion and $29 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2024 and 2023, respectively. For more information regarding the Company's divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

 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 "Unsecured Committed Term Loan Facility" in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
 Proceeds from Sale of Kinetik Shares The Company received $428 million and $228 million of cash proceeds from the sales of its Kinetik Shares during 2024 and 2023, respectively. 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 IV, Item 15 of this Annual Report on Form 10-K.
 Uses of Cash and Cash Equivalents
 Additions to Oil & Gas Property Exploration and development cash expenditures were $2.9 billion and $2.3 billion for the years ended December 31, 2024 and 2023, respectively. The increase 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 in 2024. The Company operated an average of 22 drilling rigs during 2024, compared to an average of 24 drilling rigs during 2023.
 Leasehold and Property Acquisitions During 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 $60 million and $20 million, respectively.
 Payments on Term Loan Facility During 2024, the Company made payments of $600 million on its syndicated term loan credit agreement. For additional details of the credit agreement, see "Unsecured Committed Term Loan Facility" in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
 Payments on Commercial Paper and Revolving Credit Facilities, Net As of December 31, 2024, outstanding borrowings under the Company's commercial paper and U.S. dollar denominated syndicated credit facility were $333 million, a decrease of $40 million from December 31, 2023 as operating cash flows generated in 2024 were used to repay facility borrowings.
 Payments on Callon Credit Agreement Upon closing of the Callon acquisition, the Company financed Callon's repayment in full of its $472 million outstanding under the Callon Credit Agreement.
 Payments on Fixed-Rate Debt In April and May 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 of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.
 During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases.
 The Company may, and expects that Apache will continue to, reduce debt outstanding under its indentures from time to time.
 Dividends Paid to APA Common Stockholders The Company paid $353 million and $308 million during the years ended December 31, 2024 and 2023, respectively, for dividends on its common stock.
 Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company's oil and gas operations in Egypt. The Company paid $268 million and $238 million during the years ended December 31, 2024 and 2023, respectively, in cash distributions to Sinopec.
 Treasury Stock Activity, Net During 2024, the Company repurchased 9.2 million shares at an average price of $26.83 per share totaling $246 million, and as of December 31, 2024, the Company had remaining authorization to repurchase 34.8 million shares. During 2023, the Company repurchased 8.7 million shares at an average price of $37.81 per share totaling $329 million.

 Liquidity
 The following table presents a summary of the Company's key financial indicators as of December 31:

 2024
 2023

 Cash and cash equivalents
 $
 $

 Total debt – APA and Apache

 6,044
 5,188

 Total equity

 6,362
 3,691

 Available committed borrowing capacity under syndicated credit facilities
 2,966
 2,894

 Cash and Cash Equivalents As of December 31, 2024, the Company had $625 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 December 31, 2024, the Company had $6.0 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of December 31, 2024, current debt included $53 million of finance lease obligations.
 Unsecured 2022 Committed Bank Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that remained in effect as of December 31, 2024, but were replaced on January 15, 2025 as detailed below under "Subsequent Event — Unsecured 2025 Committed Bank Credit Facilities." As of December 31, 2024:
 • One agreement was denominated in US dollars (the 2022 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 was committed).
 • The second agreement was denominated in pounds sterling (the 2022 GBP Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of 1.5 billion for loans and letters of credit.
 As of December 31, 2024, there were $10 million of borrowings under the 2022 USD Agreement and an aggregate 303 million in letters of credit outstanding under the GBP Agreement. As of December 31, 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 2022 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 2022 USD Agreement.
 The Company was in compliance with the terms of the 2022 Agreements as of December 31, 2024.
 There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to APA or its subsidiaries or the composition of such lenders.
 There is no assurance that the financial condition of banks with lending commitments to APA or its subsidiaries will not deteriorate. The Company closely monitors the ratings of the banks in its bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank's failure to honor its lending commitment.
 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 December 31, 2024 and 2023, there were no outstanding borrowings under these facilities. As of December 31, 2024, there were 640 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 (the CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of the CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company's committed revolving credit facilities for general corporate purposes, which as of December 31, 2024, included the $1.8 billion 2022 USD Agreement.
 Payment of the 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.
 The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.
 As of December 31, 2024, the Company had $323 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 (the Closing Date), 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. As of December 31, 2024, there were $900 million in 3-Year Tranche Loans remaining outstanding under the Term Loan Credit Agreement.
 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.
 Borrowings under the Term Loan Credit Agreement bear interest at one of two rate options selected by APA, being either (i) an alternate base rate (as defined), plus a margin (Term Base Rate Margin) varying from 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, or (ii) an adjusted term SOFR rate (as defined), plus a margin (Term Applicable Margin) varying from 1.375% to 2.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 1.625% to 2.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date.
 Margins are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2024, Apache's Long-Term Debt Rating applied, and the Term Base Rate Margin was 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin was 1.75% for 3-Year Tranche Loans.
 APA is subject to representations and warranties, covenants, and events of default under the Term Loan Credit Agreement, such as:
 • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2024, APA's debt-to-capital ratio as calculated under the Term Loan Credit Agreement was 19 percent.
 • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U.S. and Canada. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA's consolidated net tangible assets or approximately $2.5 billion as of December 31, 2024.

 • Negative covenants restrict APA's ability to merge with another entity unless it is the surviving entity, a borrower's disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.
 • Lenders may accelerate payment maturity and terminate lending commitments for nonpayment and other breaches; if APA or certain subsidiaries default on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of APA or certain subsidiaries.
 The Term Loan Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings.
 The Company was in compliance with the terms of the Term Loan Credit Agreement as of December 31, 2024.
 Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities
 On January 15, 2025, the Company terminated commitments under the 2022 Agreements and in replacement thereof, entered into two unsecured syndicated credit agreements for general corporate purposes on terms substantially the same as those of the 2022 Agreements:
 • One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company's two, one-year extension options.
 • The second agreement is denominated in pounds sterling (the 2025 GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of 1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company's two, one-year extension options.
 Apache has guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures first is less than US$1.0 billion.

 Letters of credit are available under each 2025 Agreement for credit support needs of APA and its subsidiaries, including in respect of North Sea decommissioning obligations. As of January 15, 2025, letters of credit aggregating approximately 253 million originally issued under the 2022 GBP Agreement were deemed issued and outstanding under the 2025 GBP Agreement.
 All borrowings under the 2025 USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin varying from 0.0% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.00% to 1.675% (Applicable Margin). All borrowings under the 2025 GBP Agreement bear interest with respect to any business day at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average with respect to such business day published by the Bank of England, plus the Applicable Margin.
 Each 2025 Agreement also requires the borrower to pay quarterly (i) a facility fee on total commitments at a per annum rate that varies from 0.125% to 0.325% and (ii) a commission on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.
 Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). APA's Long-Term Debt Rating currently applies, and the Base Rate Margin is 0.30%, the Applicable Margin is 1.30%, and the facility fee is 0.20%.

 Borrowers under each 2025 Agreement, which include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default, such as:
 • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65% at the end of any fiscal quarter.
 • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada. Liens on assets also are permitted if debt secured thereby does not exceed 15% of APA's consolidated net tangible assets.
 • Negative covenants restrict APA's ability to merge with another entity unless it is the surviving entity, a borrower's disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.
 • Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.
 The 2025 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.
 Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt
 On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA's cash tender offers. In settling these offerings pursuant to their respective terms:
 • APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA's exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA's 6.10% Notes due 2035 and $500 million aggregate principal amount of APA's 6.75% Notes due 2055.
 • In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration.
 • APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers.
 • Net proceeds from the sale of the notes in APA's new notes offering, after deducting the initial purchasers' discounts and estimated offering expenses, were approximately $839 million and used to fund in part APA's purchase of Apache notes in APA's cash tender offers.
 • Each series of APA notes and debentures issued in settlement of the exchange and tender offers has the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.
 • Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering are fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures is less than $1 billion.
 • APA entered into two registration rights agreements, one covering notes and debentures issued in APA's exchange and tender offers and one covering notes issued in APA's new notes offering (each a Registration Rights Agreement).

 These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA and Apache to use their commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA and guaranteed, if applicable, by Apache containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions or any increase in annual interest rate) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue on the principal amount of such registrable securities at a rate of 0.25% per annum for the first 90-day period beginning on the day immediately following such registration default (which rate will be increased by an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum). To the extent Apache's guarantee of the registrable securities is terminated in accordance with the terms of such guarantee, the registered notes will not be guaranteed by Apache, the exchange offer and registration requirements with respect thereto will be the sole obligation of the Company, and Apache will automatically be released from all obligations under the applicable Registration Rights Agreement.
 The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA's exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA's exchange or tender offers):

 January 10, 2025

 APA

 Apache

 4.625% notes due 2025
 $
 —
 $

 7.70% notes due March 2026(1)(5)(6)

 7.95% notes due April 2026(1)(5)(6)

 4.875% notes due 2027(4)(5)(6)

 4.375% notes due 2028(4)(5)(6)

 7.75% notes due 2029(2)(5)(6)

 4.25% notes due 2030(4)(5)(6)

 6.0% notes due 2037(1)(5)(6)

 5.1% notes due 2040(1)(5)(6)

 5.25% notes due 2042(1)(5)(6)

 4.75% notes due 2043(3)(5)(6)

 4.25% notes due 2044(3)(5)(6)

 7.375% debentures due 2047(1)(5)(6)

 5.35% notes due 2049(4)(5)(6)

 7.625% debentures due 2096(1)(5)(6)

 6.10% notes due 2035(7)

 —

 6.75% notes due 2055(7)

 —

 Total

 $
 3,592
 $
 1,095

 (1)The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
 (2)The Apache 2029 notes were issued under the Indenture, dated as of November 23, 1999, between Apache (as successor to Apache Finance Canada Corporation), and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
 (3)The Apache 2043 notes and the Apache 2044 notes were issued under the Senior Indenture, dated as of May 19, 2011, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).
 (4)The Apache 2027 notes, the Apache 2028 notes, the Apache 2030 notes, and the Apache 2049 notes were issued under the Indenture, dated as of August 14, 2018, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).

 (5)In connection with APA's exchange and tender offers, Apache solicited the consents of the holders of these Apache notes and debentures to amend the applicable Apache Indenture to remove certain restrictive and reporting covenants. The Apache notes and debentures are senior unsecured obligations of Apache. Apache received consents sufficient to approve the proposed amendments to the Apache Indentures with respect to the Apache March 2026 notes, the Apache 2028 notes, the Apache 2029 notes, the Apache 2030 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2043 notes, the Apache 2044 notes, the Apache 2047 debentures, the Apache 2049 notes, and the Apache 2096 debentures. As a result, Apache and the respective trustee for the Apache Indentures entered into supplemental indentures on January 10, 2025, implementing the proposed amendments effective as of that date.
 (6)The APA March 2026 notes, the APA April 2026 notes, the APA 2027 notes, the APA 2028 notes, the APA 2029 notes, the APA 2030 notes, the APA 2037 notes, the APA 2040 notes, the APA 2042 notes, the APA 2043 notes, the APA 2044 notes, the APA 2047 debentures, the APA 2049 notes, and the APA 2096 debentures were issued under the Indenture, dated as of June 30, 2021, between the Company, as issuer, and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee. These APA notes and debentures were issued in APA's exchange and tender offers for Apache's notes and debentures.
 (7)The APA 2035 notes and the APA 2055 notes were issued under the Indenture, dated as of December 11, 2024, between the Company, as issuer, and Regions Bank, as trustee. These APA notes were issued in APA's new notes offering to fund in part its purchase of Apache notes in APA's cash tender offers.
 Subsequent Event—Open Market Repurchases of Apache Indenture Debt
 In the first quarter of 2025 through the date of this filing, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $55 million for an aggregate purchase price of $50 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $7 million. The Company recognized a $6 million gain on these repurchases. The repurchases were partially financed by APA's borrowing under the Company's commercial paper program.
 Contractual Obligations
 Purchase Obligations From time to time, the Company enters into agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments and agreements to secure capacity rights on third-party pipelines. As of December 31, 2024, the Company had contractual obligations totaling $1.1 billion, of which $963 million is related to U.S. firm transportation contracts, $45 million is related to the merged concession agreement with the EGPC, and $110 million is related to other items. Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation.
 Leases In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 842 (Leases). As of December 31, 2024, the Company had net undiscounted minimum commitments of $467 million and $37 million for operating and finance leases, respectively.
 Interest Expense Future interest payments based on the current maturity dates of the Company's fixed-rate notes and debentures as of December 31, 2024 are approximately $3.6 billion.

 For additional information regarding these obligations, refer to Note 9—Debt and Financing Costs and Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

 For information regarding the Company's liability for dismantlement, abandonment, and restoration costs of oil and gas properties, refer to Note 8—Asset Retirement Obligation in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

 For information regarding pension or postretirement benefit obligations, refer to Note 12—Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 The Company is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. The Company's management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $20 million for various contingent legal liabilities. For a detailed discussion of the Company's environmental and legal contingencies and other commitments, please see Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 With respect to oil and gas operations in the Gulf of America, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of America to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies' oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM's website as "rescinded," if reinstated, the NTL will likely require that the Company provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company's current ownership interests in various Gulf of America leases. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which the Company has sold Gulf of America assets or with whom the Company has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties' solvency and ability to continue as a going concern.

 Potential Decommissioning Obligations on Sold Properties
 The Company's subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of America (GOA) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOA assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA's subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
 In 2013, Apache sold its GOA Shelf operations and properties and its GOA operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOA Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOA Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf's limited liability company agreement, the proceeds of production of the Legacy GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOA Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon

 resolution of GOM Shelf's second bankruptcy to 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 GOA Assets.
 By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf's notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf's notification letters. Apache has also received orders to decommission other Legacy GOA Assets that were not included in GOM Shelf's notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOA Assets.
 On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the $148 million in Bonds and $350 million in Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. 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 $350 million in Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refused to honor 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. The parties settled their dispute in the first quarter of 2025, which resulted in, among other things, mutual releases, the retention by Apache of all amounts drawn on the Letters of Credit, and payment to Apache of $140 million under the Bonds.
 As of December 31, 2024, the Company recorded an asset of $178 million representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.
 As of December 31, 2024, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $1.0 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company recorded contingent liabilities in the amounts of $1.0 billion and $824 million as of December 31, 2024, and December 31, 2023, respectively. Of the total liability recorded as of December 31, 2024, $929 million is reflected under the caption "Decommissioning contingency for sold Gulf of America properties" and $88 million is reflected under "Other current liabilities" in the Company's consolidated balance sheet. Changes in significant assumptions impacting Apache's estimated liability, including expected well decommissioning spread rates, derrick barge rates, and planned abandonment logistics, could result in a liability in excess of the amount accrued.
 The Company recognized $273 million of "Losses on previously sold Gulf of America properties" during 2024 to reflect the net impact of an increase in estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The loss includes $67 million related to properties previously sold to third parties other than Fieldwood for which the Company received BSSE orders to decommission during the year, as well as an increase to the estimated net liability the Company expects to incur for decommissioning Legacy GOA Assets. The Company also recognized losses on previously sold Gulf of America properties of $212 million and $157 million during 2023 and 2022, respectively, in the Company's statement of consolidated operations.

 Insurance Program
 The Company maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers' compensation, employers' liability, sudden and accidental pollution, and other risks. The Company's insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company's insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect the Company against liability from all potential consequences and damages. Further, the Company does not have coverage in place for a variety of other risks including Gulf of America named windstorm and business interruption. Service agreements, including drilling contracts, generally indemnify the Company for injuries and death of the service provider's employees as well as subcontractors hired by the service provider.
 The Company purchases multi-year political risk insurance from The Islamic Corporation for the Insurance of Investment and Export Credit Trade (ICIEC, an agency of the Islamic Development Bank) and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. In the aggregate, these insurance policies provide up to $750 million of coverage, subject to policy terms and conditions and a retention of approximately $500 million.
 Future insurance coverage for the Company's industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable.

 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. The following is a discussion of the Company's most critical accounting estimates.
 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 and administrative costs. 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 during 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 set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 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. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the amounts of the identifiable net assets acquired on the acquisition date.
 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.
 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 oil and natural gas properties. The fair value of proved oil and natural gas properties as of the acquisition date were estimated using the income approach where fair value was determined based on the expected future cash flows from estimated proved oil, natural gas, and NGL reserves and related discounted future net cash flows as of that date. Significant inputs to the fair value estimate included estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate.
 The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been volatility in oil, natural gas, and NGL prices, and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than projected volumes as of the acquisition date.
 Reserves Estimates
 Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
 Despite judgment involved in these engineering estimates, the Company's reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company's supplemental oil and gas disclosures. For more information regarding the Company's supplemental oil and gas disclosures, refer to Note 17—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
 The Company has elected not to disclose probable and possible reserves or reserve estimates in this filing.

 Offshore Decommissioning Contingency
 The Company has potential exposure to future obligations related to divested properties. For information regarding estimated potential decommissioning obligations on sold properties, please refer to "Potential Decommissioning Obligations on Sold Properties" above and in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
 The Company's estimated contingent obligation is primarily associated with the abandonment, removal and decommissioning of offshore wells and platforms in the Gulf of America. Estimating any future obligation requires significant judgment. The Company utilizes actual abandonment and decommissioning costs incurred as the basis to estimate the expected cash outflows for future obligations. Actual costs incurred often vary based on each structure's condition, depth-of-water, type, and other similar factors, which are key considerations when estimating the remaining well and platform decommissioning obligation. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations. Changes in significant assumptions or the regulatory framework impacting the Company's estimated liability could result in a liability in excess of the amount accrued.
 Asset Retirement Obligation (ARO)
 The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations.
 ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company's oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
 Income Taxes
 The Company's oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company's deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

 ITEM 7A.

 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 3 percent to $78.08 per barrel in 2024 from $80.72 per barrel in 2023. The Company's average natural gas price realizations decreased 32 percent to $1.97 per Mcf in 2024 from $2.91 per Mcf in 2023. The Company's average NGL price realizations increased 8 percent to $23.37 per barrel in 2024 from $21.54 per barrel in 2023. Based on average daily production for 2024, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $89 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $30 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $27 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 December 31, 2024, the Company had no open commodity derivative positions. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report Form 10-K for notional volumes and terms with the Company's derivative contracts.
 Interest Rate Risk
 As of December 31, 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 December 31, 2024, the Company had approximately $625 million in cash and cash equivalents, approximately 98 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2024, there were $1.2 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, net" 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 December 31, 2024.

 ITEM 8.
 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-62 in Part IV, Item 15 of this Annual Report on Form 10-K and are incorporated herein by reference.

 ITEM 9.
 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 The financial statements for the fiscal years ended December 31, 2024, 2023, and 2022, included in this Annual Report on Form 10-K, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

 ITEM 9A.
 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 December 31, 2024, the end of the period covered by this Annual Report on Form 10-K. 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.
 Management's Annual Report on Internal Control Over Financial Reporting; Attestation Report of the Registered Public Accounting Firm
 The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the "Report of Management on Internal Control Over Financial Reporting," included on Page F-1 in Part IV, Item 15 of this Annual Report on Form 10-K.
 The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the "Report of Independent Registered Public Accounting Firm," included on Page F-2 through F-5 in Part IV, Item 15 of this Annual Report on Form 10-K.

 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 December 31, 2024 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

 ITEM 9B.
 OTHER INFORMATION

 During the three months ended December 31, 2024, none of the Company's officers or directors adopted, modified, or terminated any "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).

 ITEM 9C.
 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 Not applicable.

 ITEM 10.
 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 The information set forth under the captions "Nominees for Election as Directors," "Information about Our Executive Officers," "Securities Ownership and Principal Holders," "Additional Information—Future Shareholder Proposals and Director Nominations," "Corporate Governance—Board Committees, Meetings, and Responsibilities," and "Corporate Governance— Insider Trading Policy " in the proxy statement relating to the Company's 2025 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.
 Code of Conduct
 In accordance with Rule 5610 of the Nasdaq, the Company maintains a code of conduct for its directors, officers, and employees. The Company's Code of Conduct was adopted by the Company's Board of Directors in March 2021 and subsequently amended in December 2024 (as amended, the Code of Conduct). The Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Code of Conduct on the Governance page of the Company's website at www.apacorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company's corporate secretary at the address on the cover of this Annual Report on Form 10-K. Changes in and waivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial officers will be posted on the Company's website within four business days and maintained for at least 12 months. Information on the Company's website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

 ITEM 11.
 EXECUTIVE COMPENSATION

 The information set forth under the captions "Compensation Discussion and Analysis (CD&A)," "Summary Compensation Table," "Grants of Plan Based Awards Table," "Outstanding Equity Awards at Fiscal Year-End Table," "Option Exercises and Stock Vested Table," "Non-Qualified Deferred Compensation Table," "Potential Payments upon Termination or Change in Control," "Director Compensation Table," "CEO Pay Ratio," "Compensation Committee Interlocks and Insider Participation," "Pay versus Performance," "Equity Award Grant Practices," and "Compensation Committee Report" in the Proxy Statement is incorporated herein by reference.

 ITEM 12.
 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 The information set forth under the captions "Securities Ownership and Principal Holders" and "Equity Compensation Plan Information" in the Proxy Statement is incorporated herein by reference.

 ITEM 13.
 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 The information set forth under the captions "Certain Business Relationships and Transactions" and "Director Independence" in the Proxy Statement is incorporated herein by reference.

 ITEM 14.
 PRINCIPAL ACCOUNTING FEES AND SERVICES

 The information set forth under the caption "Ratification of Auditor Appointment" in the Proxy Statement is incorporated herein by reference.

 ITEM 15.
 EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 (a)Documents included in this report:

 1.
 Financial Statements

 Report of management on internal control over financial reporting

 F- 1

 Report of independent registered public accounting firm (PCAOB ID: 42)

 F- 2

 Report of independent registered public accounting firm (PCAOB ID: 42)

 F- 3

 Statement of consolidated operations for each of the three years in the period ended December 31, 2024

 F- 6

 Statement of consolidated comprehensive income for each of the three years in the period ended December 31, 2024

 F- 7

 Statement of consolidated cash flows for each of the three years in the period ended December 31, 2024

 F- 8

 Consolidated balance sheet as of December 31, 2024 and 2023

 F- 9

 Statement of consolidated changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2024

 F- 10

 Notes to consolidated financial statements

 F- 11

 2.
 Financial Statement Schedules

 Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes.

 3.
 Exhibits

 Incorporated by Reference

 EXHIBIT
NO.
 DESCRIPTION
 Form

 Exhibit

 Filing Date

 SEC File No.

 2.1
 Agreement and Plan of Merger, dated as of January 3, 2024, by and among Registrant, Astro Comet Merger Sub Corp., and Callon Petroleum Company.

 2.1
 1/4/2024

 3.1
 Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021.

 3.1

 3.2
 Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated May 24, 2023, as filed with the Secretary of State of the State of Delaware on May 24, 2023.

 3.1

 5/25/2023

 3.3
 Amended and Restated Bylaws of Registrant, dated February 2, 2023.

 3.1
 2/8/2023

 4.1
 Form of Certificate for Registrant's Common Stock.

 4.1

 4.2
 Description of Equity Securities of Registrant.

 4.2

 4.3
 Amended and Restated Warrant Agreement, dated April 1, 2024, by and among Registrant, Equiniti Trust Company, LLC, and, solely for purposes of certain provisions specified therein, Callon Petroleum Company.

 4.1

 4/1/2024

 4.4
 Indenture, dated as of December 11, 2024, between Registrant and Regions Bank, as trustee.

 POSASR

 4.9

 12/12/2024

 333-279038

 4.5
 Indenture, dated as of June 30, 2021, between Registrant and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee.

 S-3ASR

 4.4

 6/30/2021

 333-257556

 4.6
 Form of Guarantee, dated as of January 10, 2025, made by Apache Corporation in favor of the Holders of Registrant's Notes subject thereto.

 4.3

 4.7
 Registration Rights Agreement, dated as of January 10, 2025, among Registrant, Apache Corporation, and J.P. Morgan Securities LLC, as representative of the initial purchasers named in the Purchase Agreement.

 4.4

 4.8
 Registration Rights Agreement, dated as of January 10, 2025, among Registrant, Apache Corporation, and the Dealer Managers named therein.

 4.5

 4.9
 Form of 6.10% Notes due 2035.

 4.6

 4.10
 Form of 6.75% Notes due 2055.

 4.7

 4.11
 Form of 7.70% Notes due 2026.

 4.8

 4.12
 Form of 7.95% Notes due 2026.

 4.9

 4.13
 Form of 4.875% Notes due 2027.

 4.10

 4.14
 Form of 4.375% Notes due 2028.

 4.11

 4.15
 Form of 7.75% Notes due December 15, 2029.

 4.12

 4.16
 Form of 4.250% Notes due 2030.

 4.13

 4.17
 Form of 6.000% Notes due 2037.

 4.14

 4.18
 Form of 5.100% Notes due 2040.

 4.15

 4.19
 Form of 5.250% Notes due 2042.

 4.16

 4.20
 Form of 4.750% Notes due 2043.

 4.17

 4.21
 Form of 4.250% Notes due 2044.

 4.18

 4.22
 Form of 7.375% Debentures due 2047.

 4.19

 4.23
 Form of 5.350% Notes due 2049.

 4.20

 4.24
 Form of 7.625% Debentures due 2096.

 4.21

 10.1
 Credit Agreement, dated as of January 30, 2024, among Registrant, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.

 10.1

 1/30/2024

 Incorporated by Reference

 EXHIBIT
NO.
 DESCRIPTION
 Form

 Exhibit

 Filing Date

 SEC File No.

 10.2

 Credit Agreement [USD Facility], dated as of January 15, 2025, among Registrant, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.

 10.1

 1/16/2025

 10.3

 Credit Agreement [GBP Facility], dated as of January 15, 2025, among Registrant, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.

 10.2

 1/16/2025

 10.4

 Income Continuance Plan, as amended and restated effective as of March 1, 2021.

 10.2

 10.5

 Executive Termination Policy, as amended and restated effective as of March 1, 2021.

 10.3

 10.6

 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016.

 10.1
 5/16/2016

 10.7

 First Amendment to the 2016 Omnibus Compensation Plan, dated July 29, 2019.

 10.13
 2/28/2020

 10.8

 Second Amendment to the 2016 Omnibus Compensation Plan, dated March 1, 2021.

 10.6

 10.9

 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016.

 10.1
 8/4/2016

 10.10

 First Amendment to the 2011 Omnibus Equity Compensation Plan, dated July 29, 2019.

 10.15
 2/28/2020

 10.11

 Second Amendment to the 2011 Omnibus Equity Compensation Plan, dated March 1, 2021.

 10.5

 10.12

 Deferred Delivery Plan, as amended and restated May 12, 2016.

 10.3
 8/4/2016

 10.13
 Non-Employee Directors' Compensation Plan, as amended and restated September 12, 2023.

 10.1
 11/2/2023

 10.14

 Outside Directors' Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014.

 10.5
 8/8/2014

 10.15

 Non-Employee Directors' Restricted Stock Units Program, as amended and restated May 14, 2015, pursuant to the 2011 Omnibus Equity Compensation Plan.

 10.6
 8/7/2015

 10.16

 Non-Employee Directors' Restricted Stock Units Program, effective May 12, 2016, pursuant to the 2016 Omnibus Compensation Plan.

 10.4
 8/4/2016

 10.17

 Outside Directors' Deferral Program, effective May 12, 2016, pursuant to the 2016 Omnibus Compensation Plan.

 10.5
 8/4/2016

 10.18

 Amendment of Stock Option Grant Agreement, dated July 29, 2019.

 10.54
 2/28/2020

 10.19

 Form of 2021 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.

 10.43
 2/26/2021

 10.20

 Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.

 10.44
 2/26/2021

 10.21

 Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.

 10.45
 2/26/2021

 10.22

 Form of 2021 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.

 10.46
 2/26/2021

 10.23

 Amendment of Restricted Stock Unit Award Agreement, dated March 1, 2021.

 10.7

 10.24

 Amendment of Performance Share Grant Agreement, dated March 1, 2021.

 10.8

 10.25

 Amendment of Stock Option Grant Agreement, dated March 1, 2021.

 10.9

 10.26

 Form of 2022 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.

 10.1
 1/7/2022

 Incorporated by Reference

 EXHIBIT
NO.
 DESCRIPTION
 Form

 Exhibit

 Filing Date

 SEC File No.

 10.27

 Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.

 10.41
 2/22/2022

 10.28

 Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.

 10.42
 2/22/2022

 10.29

 Form of 2022 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.

 10.43
 2/22/2022

 10.30

 Amendment of Restricted Stock Unit Award Agreement, dated February 22, 2022.

 10.1
 2/23/2022

 10.31

 Form of 2023 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 4, 2023.

 10.1
 1/6/2023

 10.32

 Form of 2023 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2023.

 10.43
 2/23/2023

 10.33

 Form of 2023 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2023.

 10.44
 2/23/2023

 10.34

 Form of 2024 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 8, 2024.

 10.1
 1/12/2024

 10.35

 Form of 2024 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 8, 2024.

 10.39

 2/22/2024

 10.36

 Form of 2024 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 8, 2024.

 10.40

 2/22/2024

 10.37

 Form of 2025 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 9, 2025.

 10.1

 10.38

 Form of 2025 Stock Option Award Agreement (2016 Omnibus Compensation Plan), dated January 9, 2025.

 10.2

 * 10.39

 Form of 2025 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 9, 2025.

 *19.1

 Insider Trading Policy.

 *21.1
 Subsidiaries of Registrant.

 *23.1
 Consent of Ernst & Young LLP.

 *23.2
 Consent of Ryder Scott Company, L.P., Petroleum Consultants.

 *24.1
 Power of Attorney (included as a part of the signature pages to this report).

 *31.1
 Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

 *31.2
 Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

 **32.1

 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

 97.1
 Executive Compensation Clawback Policy.

 97.1

 2/22/2024

 *99.1
 Report of Ryder Scott Company, L.P., Petroleum Consultants.

 *101.INS

 *101.SCH

 *101.CAL

 *101.DEF

 *101.LAB

 Incorporated by Reference

 EXHIBIT
NO.
 DESCRIPTION
 Form

 Exhibit

 Filing Date

 SEC File No.

 *101.PRE

 *104

 * Filed herewith.

 ** Furnished herewith.

 Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.

 NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant's consolidated assets have been omitted and will be provided to the Commission upon request.

 ITEM 16.
 FORM 10-K SUMMARY

 None.

 SIGNATURES

 Pursuant to the requirements of Section 13 or 15(d) 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

 /s/ John J. Christmann IV
 John J. Christmann IV
 Chief Executive Officer

 Dated: February 28, 2025

 POWER OF ATTORNEY
 The officers and directors of APA Corporation, whose signatures appear below, hereby constitute and appoint John J. Christmann IV, Stephen J. Riney, and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 Name
 Title
 Date

 /s/ John J. Christmann IV
 John J. Christmann IV

 Director and Chief Executive Officer (principal executive officer)

 /s/ Stephen J. Riney
 Stephen J. Riney

 President and Chief Financial Officer
 (principal financial officer)

 /s/ Rebecca A. Hoyt
 Rebecca A. Hoyt

 Senior Vice President, Chief Accounting Officer, and Controller
(principal accounting officer)

 /s/ Annell R. Bay
 Annell R. Bay

 /s/ Matthew R. Bob
Matthew R. Bob

 /s/ Juliet S. Ellis
Juliet S. Ellis

 /s/ Kenneth M. Fisher
Kenneth M. Fisher

 /s/ Charles W. Hooper
Charles W. Hooper

 /s/ Chansoo Joung
Chansoo Joung

 /s/ H. Lamar McKay
 H. Lamar McKay

 Independent, Non-Executive Chair of the Board and Director

 /s/ Peter A. Ragauss
 Peter A. Ragauss

 /s/ David L. Stover
 David L. Stover

 /s/ Anya Weaving
 Anya Weaving

 REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management's best estimates and judgments.
 Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company's board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
 Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2024.
 The Company's independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company's board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of APA Corporation and subsidiaries and the effectiveness of the Company's internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.

 /s/ John J. Christmann IV

 Chief Executive Officer

 (principal executive officer)

 /s/ Stephen J. Riney

 President and Chief Financial Officer

 (principal financial officer)

 /s/ Rebecca A. Hoyt

 Senior Vice President, Chief Accounting Officer and Controller

 (principal accounting officer)

 Houston, Texas

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 To the Shareholders and the Board of Directors of APA Corporation
 Opinion on Internal Control Over Financial Reporting
 We have audited APA Corporation and subsidiaries' internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, APA Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2024 and 2023, the related statements of consolidated operations, comprehensive income, cash flows and changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 28, 2025 expressed an unqualified opinion thereon.
 Basis for Opinion
 The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
 Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 Definition and Limitations of Internal Control Over Financial Reporting
 A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 /s/ Ernst & Young LLP
 Houston, Texas

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 To the Shareholders and the Board of Directors of APA Corporation
 Opinion on the Financial Statements
 We have audited the accompanying consolidated balance sheet of APA Corporation and subsidiaries (the Company) as of December 31, 2024 and 2023, the related statements of consolidated operations, comprehensive income, cash flows and changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 28, 2025 expressed an unqualified opinion thereon.
 Basis for Opinion
 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 Critical Audit Matters
 The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

 Depreciation, depletion and amortization of property and equipment

 Description of
the Matter
 At December 31, 2024, the carrying value of the Company's property and equipment was $12,646 million, and depreciation, depletion and amortization (DD&A) expense was $2,266 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company's internal reservoir engineers.

 Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Judgment is required by the Company's internal reservoir engineers in estimating oil and gas reserves. Estimating proved oil and gas reserves requires the selection of inputs, including historical production, oil and gas price assumptions, and operating costs, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company's internal reservoir engineers for select properties as of December 31, 2024.

 Auditing the Company's DD&A calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers.

 How We
Addressed the
Matter in Our
Audit
 We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company's controls over its process to calculate DD&A, including management's controls over the completeness and accuracy of the data utilized by the engineers for use in estimating oil and gas reserves.

 Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company's internal reservoir engineers responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates. Additionally, we evaluated the methods and assumptions used by the engineers in estimating proved oil and gas reserves and tested the completeness and accuracy of the data used by the engineers related to historical production volumes. We also tested that the DD&A expense calculations are based on the appropriate proved oil and gas reserve balances from the Company's reserve report.

 Accounting for asset retirement obligation for the North Sea segment

 Description of
the Matter

 At December 31, 2024, the asset retirement obligation (ARO) balance totaled $2,694 million. As further described in Note 8, the Company's ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company's oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs.

 Auditing the Company's ARO for the North Sea segment is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to retirement cost estimates, which are affected by expectations about future market and economic conditions.

 How We
Addressed the
Matter in Our
Audit

 We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company's internal controls over its ARO estimation process, including management's review of the significant assumptions that have a material effect on the determination of the obligation.

 To test the ARO for the North Sea segment, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates. For example, we evaluated retirement cost estimates by comparing the Company's estimates to underlying third party evidence or market information. We also involved our internal specialists in testing the underlying retirement cost estimates.

 Accounting for decommissioning contingency for sold Gulf of America properties

 Description of
the Matter

 At December 31, 2024, the decommissioning contingency for sold Gulf of America properties (decommissioning contingency) balance totaled $1 billion. As further described in Note 11, the Company's decommissioning contingency reflects the estimated undiscounted potential liability to fund decommissioning of the sold Gulf of America properties. The estimation of the decommissioning contingency requires significant judgment given the magnitude and higher estimation uncertainty of the expected retirement costs.

 Auditing the Company's decommissioning contingency is complex and highly judgmental because of the significant estimation required by management in determining the decommissioning contingency. In particular, the estimate was sensitive to retirement cost estimates, which are subjective assumptions affected by expectations about future market and economic conditions.

 How We
Addressed the
Matter in Our
Audit

 We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company's internal controls over its decommissioning contingency estimation process, including management's review of the significant assumptions that have a material effect on the determination of the contingency.

 To test the decommissioning contingency, our audit procedures included, among others, assessing the significant assumptions and inputs used developing the retirement cost estimates. For example, we evaluated retirement cost estimates by comparing the Company's estimates to market information. We also involved our internal specialists in testing the underlying retirement cost estimates.

 Evaluation of the fair value measurement of proved oil and gas properties acquired in the Callon Petroleum business combination

 Description of
the Matter

 During 2024, the Company completed the acquisition of Callon Petroleum Company resulting in the recognition of the fair value of property and equipment of $4,502 million. As described in Note 2, the transaction was accounted for as a business combination using the acquisition method, which requires assets acquired and liabilities assumed to be recognized at their fair values as of the acquisition date.

 The Company applied a discounted cash flow method to estimate the fair value of the proved oil and gas properties acquired. Significant inputs to the valuation of proved oil and gas properties include estimates of future commodity prices, future production volumes, and discount rate using a market-based weighted average cost of capital. Judgment is required by the Company's internal reservoir engineers in estimating future production quantities.

 Auditing the Company's fair value measurement of the proved oil and gas properties acquired is complex because of the use of the work of the Company's internal reservoir engineers in estimating future production and the evaluation of management's determination of the inputs described above. In evaluating the reasonableness of management's assessment and assumptions used, the audit testing procedures performed required a high degree of auditor judgement and additional effort, including involving internal valuation specialists.

 How We
Addressed the
Matter in Our
Audit

 We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company's internal controls to estimate the fair value of the acquired proved oil and gas properties, including management's review of the significant assumptions used as inputs to the fair value calculations.

 To test the fair value of the acquired proved oil and gas properties, our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company's internal reservoir engineers primarily responsible for overseeing the preparation of the future production volumes. In addition, we performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the fair value calculation. We also involved our valuation specialists to assist with certain significant assumptions included in the fair value estimate.

 /s/ Ernst & Young LLP
 We have served as the Company's auditor since 2002.
 Houston, Texas

 STATEMENT OF CONSOLIDATED OPERATIONS

 2024
 2023
 2022

 (In millions, except per common share data)

 REVENUES AND OTHER:

 Oil, natural gas, and natural gas liquids production revenues(1)

 $
 8,196
 $
 7,385
 $
 9,220

 Purchased oil and gas sales(1)

 1,541
 1,855

 Total revenues
 9,737
 8,279
 11,075

 Derivative instrument gains (losses), net
 ( 10)
 ( 114)

 1,180

 ( 273)
 ( 212)
 ( 157)

 Other, net
 ( 6)

 9,737
 8,192
 12,132

 OPERATING EXPENSES:

 Lease operating expenses(1)

 1,690
 1,436
 1,444

 Gathering, processing, and transmission(1)

 Purchased oil and gas costs(1)

 1,047
 1,776

 Taxes other than income

 Depreciation, depletion, and amortization
 2,266
 1,540
 1,233

 1,129
 —

 8,202
 5,309
 6,398

 NET INCOME BEFORE INCOME TAXES

 1,535
 2,883
 5,734

 Current income tax provision
 1,153
 1,338
 1,507

 Deferred income tax provision (benefit)
 ( 736)
 ( 1,662)

 NET INCOME INCLUDING NONCONTROLLING INTERESTS

 1,118
 3,207
 4,082

 Net income attributable to noncontrolling interest – Egypt

 Net income attributable to noncontrolling interest – Altus

 —
 —

 Net loss attributable to Altus Preferred Unit limited partners

 —
 —
 ( 70)

 NET INCOME ATTRIBUTABLE TO COMMON STOCK

 $
 $
 2,855
 $
 3,674

 NET INCOME PER COMMON SHARE:

 Basic
 $
 2.28
 $
 9.26
 $
 11.05

 Diluted
 $
 2.27
 $
 9.25
 $
 11.02

 WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:

 Basic

 Diluted

 (1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.
 The accompanying notes to consolidated financial statements are an integral part of this statement.

 STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

 2024
 2023
 2022

 NET INCOME INCLUDING NONCONTROLLING INTERESTS

 $
 1,118
 $
 3,207
 $
 4,082

 OTHER COMPREHENSIVE INCOME, NET OF TAX:

 Pension and postretirement benefit plan
 ( 3)
 ( 8)

 COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS

 1,115
 3,208
 4,074

 Comprehensive income attributable to noncontrolling interest – Egypt

 Comprehensive income attributable to noncontrolling interest – Altus

 —
 —

 Comprehensive loss attributable to Altus Preferred Unit limited partners

 —
 —
 ( 70)

 COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

 $
 $
 2,856
 $
 3,666

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

 STATEMENT OF CONSOLIDATED CASH FLOWS

 2024
 2023
 2022

 CASH FLOWS FROM OPERATING ACTIVITIES:

 Net income including noncontrolling interests

 $
 1,118
 $
 3,207
 $
 4,082

 Adjustments to reconcile net income to net cash provided by operating activities:

 Unrealized derivative instrument (gains) losses, net

 ( 51)

 ( 289)
 ( 8)
 ( 1,180)

 Exploratory dry hole expense and unproved leasehold impairments

 Depreciation, depletion, and amortization
 2,266
 1,540
 1,233

 1,129
 —

 Provision for (benefit from) deferred income taxes
 ( 736)
 ( 1,662)

 (Gain) loss from extinguishment of debt

 —
 ( 9)

 Other
 ( 73)

 Changes in operating assets and liabilities:

 Receivables
 ( 104)
 ( 157)
 ( 93)

 Inventories
 ( 11)
 ( 1)

 Drilling advances and other current assets
 ( 56)
 ( 15)

 Deferred charges and other long-term assets

 Accounts payable
 ( 84)
 ( 4)

 Accrued expenses
 ( 221)
 ( 400)

 Deferred credits and noncurrent liabilities
 ( 235)
 ( 328)
 ( 138)

 NET CASH PROVIDED BY OPERATING ACTIVITIES
 3,620
 3,129
 4,943

 CASH FLOWS FROM INVESTING ACTIVITIES:

 Additions to oil and gas property

 ( 2,851)
 ( 2,313)
 ( 1,770)

 Acquisition of Delaware Basin properties

 —
 ( 24)
 ( 591)

 Leasehold and property acquisitions
 ( 60)
 ( 20)
 ( 37)

 Proceeds from asset divestitures
 1,609

 Proceeds from sale of Kinetik shares

 Deconsolidation of Altus cash and cash equivalents
 —
 —
 ( 143)

 Other, net
 ( 50)
 ( 38)

 NET CASH USED IN INVESTING ACTIVITIES
 ( 924)
 ( 2,138)
 ( 1,511)

 CASH FLOWS FROM FINANCING ACTIVITIES:

 Proceeds from (payments on) commercial paper and revolving credit facilities, net

 ( 40)
 ( 194)

 Proceeds from term loan facility

 1,500
 —
 —

 Payments on term loan facility

 ( 600)
 —
 —

 Payment on Callon Credit Agreement

 ( 472)
 —
 —

 Payments on fixed-rate debt

 ( 1,641)
 ( 65)
 ( 1,493)

 Distributions to noncontrolling interest

 ( 268)
 ( 238)
 ( 362)

 Dividends paid to APA common stockholders
 ( 353)
 ( 308)
 ( 207)

 ( 246)
 ( 329)
 ( 1,423)

 Other, net
 ( 38)
 ( 15)
 ( 28)

 NET CASH USED IN FINANCING ACTIVITIES

 ( 2,158)
 ( 1,149)
 ( 3,489)

 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
 ( 158)
 ( 57)

 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

 CASH AND CASH EQUIVALENTS AT END OF PERIOD
 $
 $
 $

 SUPPLEMENTARY CASH FLOW DATA:

 Interest paid, net of capitalized interest
 $
 $

 Income taxes paid, net of refunds
 1,097
 1,271
 1,431

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

 CONSOLIDATED BALANCE SHEET

 December 31,

 2024
 2023

 (In millions, except share data)

 ASSETS

 CURRENT ASSETS:

 Cash and cash equivalents

 $
 $

 Receivables, net of allowance of $ 123 and $ 114

 1,959
 1,610

 Other current assets ( Note 5)

 3,404
 2,462

 PROPERTY AND EQUIPMENT:

 Oil and gas properties, on the basis of successful efforts accounting:

 44,698
 44,860

 Gathering, processing, and transmission facilities

 Other

 Less: Accumulated depreciation, depletion, and amortization

 ( 33,047)
 ( 35,904)

 12,646
 10,038

 OTHER ASSETS:

 Equity method interests ( Note 6)

 —

 Decommissioning security for sold Gulf of America properties ( Note 11)

 Deferred tax asset ( Note 10)

 2,703
 1,758

 Deferred charges and other

 $
 19,390
 $
 15,244

 LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY

 CURRENT LIABILITIES:

 Accounts payable

 $
 1,224
 $

 Current debt

 Other current liabilities ( Note 7)

 1,678
 1,744

 2,955
 2,404

 LONG-TERM DEBT ( Note 9)

 5,991
 5,186

 DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:

 Deferred tax liability ( Note 10)

 Asset retirement obligation ( Note 8)

 2,591
 2,362

 Decommissioning contingency for sold Gulf of America properties ( Note 11)

 Other

 4,082
 3,963

 EQUITY:

 Common stock, $ 0.625 par, 860,000,000 shares authorized, 491,579,646 and 420,595,901 shares issued, respectively

 Paid-in capital
 13,153
 11,126

 Accumulated deficit
 ( 2,155)
 ( 2,959)

 Treasury stock, at cost, 126,182,497 and 117,020,000 shares, respectively

 ( 6,037)
 ( 5,790)

 Accumulated other comprehensive income

 APA SHAREHOLDERS' EQUITY

 5,280
 2,655

 Noncontrolling interest – Egypt

 1,082
 1,036

 TOTAL EQUITY

 6,362
 3,691

 $
 19,390
 $
 15,244

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

 STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST

 Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
 Common
Stock
 Paid-In
Capital
 Accumulated Deficit
 Treasury
Stock
 Accumulated
 Other
 Comprehensive
 Income

 APA
 SHAREHOLDERS'
 EQUITY

 Noncontrolling
Interests
 TOTAL
 EQUITY

 BALANCE AT DECEMBER 31, 2021
 $
 $
 $
 11,645
 $
 ( 9,488)
 $
 ( 4,036)
 $
 $
 ( 1,595)
 $
 $
 ( 717)

 Net income attributable to common stock

 —
 —
 —
 3,674
 —
 —
 3,674
 —
 3,674

 Net income attributable to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —

 Net income attributable to noncontrolling interest – Altus

 —
 —
 —
 —
 —
 —
 —

 Net income attributable to Altus Preferred Unit limited partners
 ( 70)
 —
 —
 —
 —
 —
 —
 —
 —

 Distributions to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —
 ( 362)
 ( 362)

 Common dividends ($ 0.75 per share)

 —
 —
 ( 245)
 —
 —
 —
 ( 245)
 —
 ( 245)

 Common stock activity, net
 —
 —
 ( 6)
 —
 —
 —
 ( 6)
 —
 ( 6)

 Deconsolidation of Altus
 ( 642)
 —
 —
 —
 —
 —
 —
 ( 72)
 ( 72)

 —
 —
 —
 —
 ( 1,423)
 —
 ( 1,423)
 —
 ( 1,423)

 Compensation expense
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 —
 —
 ( 8)
 ( 8)
 —
 ( 8)

 BALANCE AT DECEMBER 31, 2022
 $
 —
 $
 $
 11,420
 $
 ( 5,814)
 $
 ( 5,459)
 $
 $
 $
 $
 1,345

 Net income attributable to common stock
 —
 —
 —
 2,855
 —
 —
 2,855
 —
 2,855

 Net income attributable to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —

 Distributions to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —
 ( 238)
 ( 238)

 Common dividends ($ 1.00 per share)

 —
 —
 ( 308)
 —
 —
 —
 ( 308)
 —
 ( 308)

 Common stock activity, net
 —
 ( 14)
 —
 —
 —
 ( 13)
 —
 ( 13)

 —
 —
 —
 —
 ( 331)
 —
 ( 331)
 —
 ( 331)

 Compensation expense
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 —
 —

 BALANCE AT DECEMBER 31, 2023
 $
 —
 $
 $
 11,126
 $
 ( 2,959)
 $
 ( 5,790)
 $
 $
 2,655
 $
 1,036
 $
 3,691

 Net income attributable to common stock
 —
 —
 —
 —
 —
 —

 Net income attributable to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —

 Distributions to noncontrolling interest – Egypt

 —
 —
 —
 —
 —
 —
 —
 ( 268)
 ( 268)

 Common dividends ($ 1.00 per share)

 —
 —
 ( 352)
 —
 —
 —
 ( 352)
 —
 ( 352)

 Issuance of common stock

 —
 2,370
 —
 —
 —
 2,414
 —
 2,414

 —
 —
 —
 —
 ( 247)
 —
 ( 247)
 —
 ( 247)

 Compensation expense
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 ( 17)
 —
 —
 ( 3)
 ( 20)
 —
 ( 20)

 BALANCE AT DECEMBER 31, 2024
 $
 —
 $
 $
 13,153
 $
 ( 2,155)
 $
 ( 6,037)
 $
 $
 5,280
 $
 1,082
 $
 6,362

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

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 Nature of Operations
 APA Corporation (APA or the Company) is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids. The Company's business has oil and gas operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the BCP Business Combination defined below, the Company's midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company's financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.
 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.
 On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.
 During the quarter ended March 31, 2024 and each of the years ended December 31, 2023 and 2022, the Company had a designated director on the 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.
 Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as "Equity method interests" in the Company's consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail.

 Use of Estimates
 Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company's financial statements, and changes in these estimates are recorded when known.
 Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to "Fair Value Measurements" and "Property and Equipment" sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to "Equity Method Interests" within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache's potential decommissioning obligations on sold properties in the Gulf of America (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 (refer to Note 17—Supplemental Oil and Gas Disclosures (Unaudited)).
 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 9—Debt and Financing Costs, and Note 12—Retirement and Deferred Compensation Plans for further detail regarding the Company's fair value measurements recorded on a recurring basis.
 The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment or when allocating the purchase price for acquired assets and liabilities in a business combination.
 During 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, in the third quarter of 2024 the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea. Accordingly, the Company recognized impairments of $ 796 million on certain proved properties in the North Sea, which were written down to their estimated fair values as of September 30, 2024. This impairment is discussed in further detail below in "Property and Equipment — Oil and Gas Property."
 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 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, using various Level 3 fair value measurements. Material assets and liabilities acquired are discussed further below:

 • The most significant assumptions relate to the estimated fair values assigned to proved oil and natural gas properties. The fair value of proved oil and natural gas properties as of the acquisition date were estimated using the income approach, where fair value was determined based on the expected future cash flows from estimated proved oil, natural gas, and NGL reserves and related discounted future net cash flows as of that date. Significant inputs to the fair value estimate included estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted-average cost of capital discount rate.
 • The fair value of unproved properties was estimated mainly using the market approach, based on acreage costs in areas where Callon acreage was acquired.
 • The fair value of most other current assets and current liabilities were determined to be equivalent to the carrying value due to their short-term nature.
 • The fair value of debt was based on the estimated cost to retire Callon's debt instruments.
 • Estimated deferred taxes were based on available information concerning the fair values assigned to acquired assets and liabilities and their respective tax basis and tax-related carryforwards at the acquisition date.
 Refer to Note 2—Acquisitions and Divestitures for further detail regarding the Company's fair value measurements recorded related to the Callon acquisition.
 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.
 For the years ended December 31, 2023 and 2022, the Company recorded $ 11 million and no asset impairments, respectively, in connection with fair value assessments.
 Revenue Recognition
 The Company's oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third parties to provide flexibility to fulfill sales obligations and commitments. Under these commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company's right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.
 APA's Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company's PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor's income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC's production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company's Egypt operations despite impacting the Company's production and reserves.
 Refer to Note 16—Business Segment Information for a disaggregation of revenue by product and reporting segment.

 Payment Terms and Contract Balances
 Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $ 1.7 billion and $ 1.5 billion as of December 31, 2024 and 2023, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. 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 2024, and management believes that the Company will be able to collect the total balance of its receivables from this customer.
 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.
 Cash and Cash Equivalents
 The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2024 and 2023, the Company had $ 625 million and $ 87 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2024 and 2023.
 Accounts Receivable and Allowance for Credit Losses
 Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties' credit quality and liquidity.
 The following table presents changes to the Company's allowance for credit loss:

 2024
 2023
 2022

 Allowance for credit loss at beginning of year
 $
 $
 $

 Additional provisions for the year

 Uncollectible accounts written off, net of recoveries
 —
 ( 19)
 ( 1)

 Allowance for credit loss at end of year
 $
 $
 $

 Inventories
 Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
 During 2024, the Company recorded $ 18 million of inventory impairments, including $ 13 million in the North Sea and $ 5 million in the U.S.
 The Company also recorded other impairments during 2023 of approximately $ 50 million in connection with valuations of drilling and operations equipment inventory upon the Company's decision to suspend drilling operations in the North Sea.
 Property and Equipment
 The carrying value of the Company's property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.

 Oil and Gas Property
 The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
 Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company's current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
 The following table represents non-cash impairment charges of the carrying value of the Company's proved and unproved properties:

 2024
 2023
 2022

 Proved properties:

 U.S.
 $
 $
 —
 $
 —

 Egypt
 —
 —
 —

 —
 —

 Total proved properties
 $
 1,111
 $
 —
 $
 —

 Unproved properties:

 U.S.
 $
 $
 $

 Egypt
 —
 —

 —
 —

 —

 Total unproved properties
 $
 $
 $

 Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
 Oil and gas properties are grouped for depreciation in accordance with ASC 932, "Extractive Activities—Oil and Gas." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

 When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
 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 $ 796 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 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.
 For the years ended December 31, 2023, and 2022, the Company recorded no impairments of proved properties.
 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 totaled $ 433 million and $ 448 million at December 31, 2024 and 2023, respectively, with accumulated depreciation for these assets totaling $ 364 million and $ 373 million for the respective periods. 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.
 For the years ended December 31, 2024, 2023, and 2022, the Company recorded no impairments of GPT facilities.
 Other Property and Equipment
 Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $ 183 million and $ 217 million at December 31, 2024 and 2023, respectively.
 Asset Retirement Costs and Obligations
 The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset's retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

 Capitalized Interest
 For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.
 Equity Method Interests
 The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company's proportionate share of the equity interest's net income and contributions made by the Company, and decreased by the Company's proportionate share of the equity interest's net losses and distributions received by the Company. Refer to Note 6—Equity Method Interests for further details of the Company's equity method interests.
 Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
 Commitments and Contingencies
 Accruals for loss contingencies arising from claims, assessments, litigation, environmental, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 11—Commitments and Contingencies.
 Derivative Instruments and Hedging Activities
 The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.
 All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company's consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as "Derivative instrument gains (losses), net" under "Revenues and Other" in the statement of consolidated operations. Refer to Note 4—Derivative Instruments and Hedging Activities for further information.
 Income Taxes
 The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. Refer to Note 10—Income Taxes for further information.
 Earnings Per Share
 The Company's basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.

 Stock-Based Compensation
 The Company grants various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on the Company's stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company's stock-based compensation plans and related accounting policies are defined and described more fully in Note 13—Capital Stock.
 Treasury Stock
 The Company follows the weighted-average-cost method of accounting for treasury stock transactions.
 Transaction, Reorganization, and Separation (TRS)
 The Company recorded TRS costs in 2024 totaling $ 168 million, which primarily comprised $ 147 million associated with the Callon acquisition, including $ 76 million of separation costs and $ 71 million of transaction and integration costs.
 The Company recorded TRS costs in 2023 and 2022 totaling $ 15 million and $ 26 million, respectively, including $ 7 million and $ 15 million, respectively, related to consulting and separation costs in international operations associated with the redesign of the Company's organizational structure and operations.
 New Pronouncements Issued But Not Yet Adopted
 In December 2023, the FASB issued ASU 2023-09 "Improvements to Income Tax Disclosures (Topic 740)," which requires enhanced disclosures primarily related to existing rate reconciliation and income taxes paid information. This update is effective for the Company beginning in the first quarter of 2025 and is applied on a prospective basis. The Company does not believe this will have a material impact on its financial statements.
 In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, "Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40)," which expands disclosures around a public entity's costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.

 2. ACQUISITIONS AND DIVESTITURES
 2024 Activity
 Callon Petroleum Company Acquisition
 On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction valued at approximately $ 4.5 billion, inclusive of Callon's debt. 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.

 Current assets

 $

 Property and equipment

 4,502

 Deferred tax asset

 Other assets

 Total assets acquired
 $
 5,366

 Current liabilities
 $

 Long-term debt

 2,113

 Asset retirement obligation

 Other long-term obligations

 Total liabilities assumed
 $
 2,929

 Net assets acquired
 $
 2,437

 The following unaudited pro forma combined results for the years ended December 31, 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, and estimated tax impacts of the pro forma adjustments.

 2024
 2023

 Revenues

 $
 10,300
 $
 10,578

 Net income attributable to common stock

 4,021

 Net income per common share – basic

 2.45
 10.66

 Net income per common share – diluted

 2.45
 10.63

 From the date of the acquisition through December 31, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $ 1.2 billion and $ 262 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
 On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $ 1.1 billion and associated asset retirement obligation of $ 224 million for total cash proceeds of $ 869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf. The effective date of the transaction is July 1, 2024. As a result of the transaction, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $ 315 million to the carrying value of the associated oil and gas properties during the third quarter of 2024. During the fourth quarter of 2024, the Company recorded a loss of $ 5 million upon closing of the transaction.
 During 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 $ 255 million and the assumption of asset retirement obligations of $ 42 million. The Company recognized a $ 50 million loss during 2024 in association with this sale.
 During 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $ 71 million for approximately $ 394 million subject to post-closing adjustments. The Company recognized a gain of $ 321 million during 2024 in association with this sale.

 Additionally, during 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $ 91 million, recognizing a gain of approximately $ 22 million upon closing of these transactions.
 Sale of Kinetik Shares
 On March 18, 2024, the Company sold its remaining Kinetik Class A Common Stock (Kinetik Shares) for cash proceeds of $ 428 million. Refer to Note 6—Equity Method Interests for further detail.
 Leasehold and Property Acquisitions
 During 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 $ 60 million.
 2023 Activity
 Sale of Kinetik Shares
 In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $ 228 million. Refer to Note 6—Equity Method Interests for further detail.
 Leasehold and Property Acquisitions
 During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $ 20 million.
 U.S. Divestitures
 During 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $ 29 million, recognizing an aggregate gain of approximately $ 8 million upon closing of these transactions.
 2022 Activity
 During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $ 615 million after post-closing adjustments. Final cash settlements of $ 24 million were completed during 2023. The Company recorded $ 581 million for proved properties, $ 38 million for unproved leasehold, and $ 4 million for abandonment obligations.
 During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $ 37 million.
 During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $ 52 million, recognizing an aggregate gain of approximately $ 36 million, upon closing of these transactions.
 During 2022, the Company completed the sale of certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $ 726 million after certain post-closing adjustments and recognized an associated gain of approximately $ 560 million.
 The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP's unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM's stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed.
 As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $ 609 million that reflects the difference between the Company's $ 193 million net effect of deconsolidating ALTM's balance sheet and the $ 802 million fair value of the Company's approximate 20 percent retained ownership in the combined entity.

 During the first quarter of 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $ 224 million. Refer to Note 6—Equity Method Interests for further detail.

 3. CAPITALIZED EXPLORATORY WELL COSTS
 The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2024, 2023, and 2022. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

 2024
 2023
 2022

 Capitalized well costs at beginning of year
 $
 $
 $

 Additions pending determination of proved reserves

 Reclassifications to proved properties
 ( 506)
 ( 135)
 ( 110)

 Charged to exploration expense
 ( 83)
 ( 18)
 ( 24)

 Capitalized well costs at end of year
 $
 $
 $

 The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:

 2024
 2023
 2022

 Exploratory well costs capitalized for a period of one year or less
 $
 $
 $

 Exploratory well costs capitalized for a period greater than one year

 Capitalized well costs at end of year
 $
 $
 $

 Number of projects with exploratory well costs capitalized for a period greater than one year

 Projects with 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 reserves can be attributed to these projects. Exploratory well costs capitalized for a period greater than one year since completion of drilling were $ 130 million at December 31, 2024, with $ 115 million related to Suriname exploration and appraisal. Ongoing analysis of well results and appraisal activity is continuing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is being performed.
 Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2023 totaled $ 52 million. These expenses pertained to projects in Suriname and Egypt.
 The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2024, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:

 Total
 2023
 2022
 2021
 and Prior

 $
 $
 $
 —
 $

 Egypt
 —
 —

 $
 $
 $
 —
 $

 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. The Company elected not to designate any of its derivative contracts as cash flow hedges.
 Embedded Derivatives
 As a result of the Callon acquisition, the Company assumed an earn-out obligation from Callon, where the Company could be required to pay up to $ 25 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $ 60.00 per barrel for the 2025 calendar year. The Company determined that the earn-out obligation is not clearly and closely related to the underlying agreements and therefore bifurcated this embedded feature and recorded the derivative at fair value. 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.
 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:

 2024
 2023

 Current Assets: Other current assets
 $
 —
 $

 Total derivative assets
 $
 —
 $

 Deferred Credits and Other Noncurrent Liabilities: Other
 $
 $
 —

 Total derivative liabilities
 $
 $
 —

 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:

 2024
 2023
 2022

 Realized:

 Commodity derivative instruments
 $
 $
 $
 ( 34)

 Contingent consideration arrangements

 ( 4)
 —
 —

 Foreign currency derivative instruments
 —
 —
 ( 13)

 Realized gains (losses), net

 ( 2)
 ( 47)

 Unrealized:

 Commodity derivative instruments
 ( 6)
 ( 36)

 Contingent consideration arrangements

 ( 2)
 —
 —

 Preferred Units embedded derivative
 —
 —
 ( 31)

 Unrealized gains (losses), net

 ( 8)
 ( 67)

 Derivative instrument gains (losses), net
 $
 ( 10)
 $
 $
 ( 114)

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

 5. OTHER CURRENT ASSETS
 The following table provides detail of the Company's other current assets as of December 31:

 2024
 2023

 Inventories
 $
 $

 Drilling advances

 Prepaid assets and other

 Current decommissioning security for sold Gulf of America assets

 Total Other current assets
 $
 $

 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. 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 during 2024, and gains of $ 41 million and $ 72 million during 2023 and 2022, respectively. These gains and losses are recorded in the statement of consolidated operations and reflected in "Other, net" under "Revenues and other."
 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 Year Ended
 December 31,

 2024
 2023
 2022

 Natural gas and NGLs sales
 $
 $
 $

 Purchased oil and gas sales
 —

 $
 $
 $

 Gathering, processing, and transmission costs
 $
 $
 $

 —

 —

 $
 $
 $

 7. OTHER CURRENT LIABILITIES
 The following table provides detail of the Company's other current liabilities as of December 31:

 2024
 2023

 Accrued operating expenses
 $
 $

 Accrued exploration and development

 Accrued compensation and benefits

 Accrued interest

 Accrued income taxes

 Current asset retirement obligation

 Current operating lease liability

 Current decommissioning contingency for sold Gulf of America properties

 Other

 Total Other current liabilities
 $
 1,678
 $
 1,744

 8. ASSET RETIREMENT OBLIGATION
 The following table describes changes to the Company's asset retirement obligation (ARO) liability for the years ended December 31, 2024 and 2023:

 2024
 2023

 Asset retirement obligation at beginning of the year
 $
 2,438
 $
 1,995

 Liabilities incurred

 Liabilities acquired
 —

 Liabilities divested
 ( 272)
 —

 Liabilities settled
 ( 70)
 ( 43)

 Accretion expense

 Revisions in estimated liabilities

 Asset retirement obligation at end of the year
 2,694
 2,438

 Less current portion
 ( 103)
 ( 76)

 Asset retirement obligation, long-term
 $
 2,591
 $
 2,362

 The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company's oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.
 During 2024 and 2023, the Company recorded $ 15 million and $ 14 million, respectively, in abandonment liabilities resulting from the Company's exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2024, net abandonment costs were revised upward by approximately $ 299 million, primarily reflecting changes in estimates of timing and activity costs in the U.S. and North Sea, in addition to foreign currency exchange rates on service costs. During 2023, net abandonment costs were revised upward by approximately $ 356 million to reflect changes in estimates of timing, activity costs, and foreign currency exchange rates on service costs in the North Sea.

 9. DEBT AND FINANCING COSTS
 Overview
 The debt of APA and Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. As of December 31, 2024, (i) all indentures of Apache for the notes and debentures described below placed certain restrictions on Apache, including limits on Apache's ability to incur debt secured by certain liens, and (ii) certain of those indentures also restricted Apache's ability to enter into certain sale and leaseback transactions and gave holders the option to require Apache to repurchase outstanding notes and debentures upon certain changes in control. Each indenture of APA and Apache restricts it from issuing or guaranteeing certain secured indebtedness. None of the indentures contain prepayment obligations in the event of a decline in credit ratings.
 During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $ 74 million for an aggregate purchase price of $ 65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $ 10 million. The Company recognized a $ 9 million gain on these repurchases. The repurchases were partially financed by Apache's borrowing under the Company's US dollar-denominated revolving credit facility.
 During 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $ 15 million for an aggregate purchase price of $ 16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $ 1 million. The Company recognized a $ 1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache's former revolving credit facility.
 During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $ 1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $ 1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $ 66 million loss on extinguishment of debt, including $ 11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache's former revolving credit facility.
 The Company records gains and losses on extinguishment of debt in "Financing costs, net" in the Company's statement of consolidated operations.

 The following table presents the carrying value of the Company's debt as of December 31, 2024 and 2023:

 December 31,

 2024
 2023

 4.625 % notes due 2025(1)

 $
 $

 7.7 % notes due 2026

 7.95 % notes due 2026

 4.875 % notes due 2027(1)

 4.375 % notes due 2028(1)

 7.75 % notes due 2029(1)(2)

 4.25 % notes due 2030(1)

 6.0 % notes due 2037(1)

 5.1 % notes due 2040(1)

 1,333
 1,333

 5.25 % notes due 2042(1)

 4.75 % notes due 2043(1)

 4.25 % notes due 2044(1)

 7.375 % debentures due 2047

 5.35 % notes due 2049(1)

 7.625 % debentures due 2096

 Apache notes and debentures before unamortized discount and debt issuance costs(3)

 4,835
 4,835

 Commercial paper
 —

 Term loan facility

 —

 Syndicated credit facilities(4)

 Apache finance lease obligations

 Unamortized discount
 ( 25)
 ( 26)

 Debt issuance costs
 ( 29)
 ( 25)

 Total debt
 6,044
 5,188

 Current maturities
 ( 53)
 ( 2)

 Long-term debt
 $
 5,991
 $
 5,186

 (1)These notes are redeemable, as a whole or in part, at Apache's option, subject to a make-whole premium, except that the 7.75 % notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.
 (2)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.
 (3)The fair values of Apache's notes and debentures were $ 4.4 billion and $ 4.3 billion as of December 31, 2024 and 2023, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
 (4)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.
 Maturities for the Company's notes and debentures excluding discount and debt issuance costs as of December 31, 2024 are as follows:

 2025
 $

 2026

 2027

 2028

 2029

 Thereafter
 3,906

 Notes and debentures, excluding discounts and debt issuance costs
 $
 4,835

 Financing Costs, Net
 The following table presents the components of the Company's financing costs, net:

 2024
 2023
 2022

 Interest expense
 $
 $
 $

 Amortization of debt issuance costs

 ( 29)
 ( 24)
 ( 18)

 Loss (gain) on extinguishment of debt
 —
 ( 9)

 Interest income
 ( 12)
 ( 10)
 ( 10)

 $
 $
 $

 Unsecured 2022 Committed Bank Credit Facilities
 On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that remained in effect as of December 31, 2024, but were replaced on January 15, 2025, as detailed below under "Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities." As of December 31, 2024:
 • One agreement was denominated in US dollars (the 2022 USD Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of US$ 1.8 billion (including a letter of credit subfacility of up to US$ 750 million, of which US$ 150 million was committed).
 • The second agreement was denominated in pounds sterling (the 2022 GBP Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of 1.5 billion for loans and letters of credit.
 As of December 31, 2024, there were $ 10 million of borrowings under the 2022 USD Agreement and an aggregate 303 million in letters of credit outstanding under the GBP Agreement. As of December 31, 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 2022 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 2022 USD Agreement.
 The Company was in compliance with the terms of the 2022 Agreements as of December 31, 2024.
 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 December 31, 2024 and 2023, there were no outstanding borrowings under these facilities. As of December 31, 2024, there were 640 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 (the 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 revolving credit facilities for general corporate purposes, which as of December 31, 2024, included the $ 1.8 billion 2022 USD Agreement.
 Payment of the 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.
 The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.

 As of December 31, 2024, the Company had $ 323 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 (the Closing Date), 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. As of December 31, 2024, $ 900 million in 3 -Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.
 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.
 Borrowings under the Term Loan Credit Agreement bear interest at one of two rate options selected by APA, being either (i) an alternate base rate (as defined), plus a margin (Term Base Rate Margin) varying from 0.375 % to 1.125 % for 3 -Year Tranche Loans until the second anniversary of the Closing Date, and 0.625 % to 1.375 % for 3 -Year Tranche Loans after the second anniversary of the Closing Date, or (ii) an adjusted term SOFR rate (as defined), plus a margin (Term Applicable Margin) varying from 1.375 % to 2.125 % for 3 -Year Tranche Loans until the second anniversary of the Closing Date, and 1.625 % to 2.375 % for 3 -Year Tranche Loans after the second anniversary of the Closing Date.
 Margins are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2024, Apache's Long-Term Debt Rating applied, and the Term Base Rate Margin was 0.75 % for 3 -Year Tranche Loans, and the Term Applicable Margin was 1.75 % for 3 -Year Tranche Loans.
 APA is subject to representations and warranties, covenants, and events of default under the Term Loan Credit Agreement, such as:
 • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2024, APA's debt-to-capital ratio as calculated under the Term Loan Credit Agreement was 19 percent.
 • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U.S. and Canada. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA's consolidated net tangible assets or approximately $ 2.5 billion as of December 31, 2024.
 • Negative covenants restrict APA's ability to merge with another entity unless it is the surviving entity, a borrower's disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.
 • Lenders may accelerate payment maturity and terminate lending commitments for nonpayment and other breaches; if APA or certain subsidiaries default on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of APA or certain subsidiaries.

 The Term Loan Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings.
 The Company was in compliance with the terms of the Term Loan Credit Agreement as of December 31, 2024.
 Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities
 On January 15, 2025, the Company terminated commitments under the 2022 Agreements and in replacement thereof, entered into two unsecured syndicated credit agreements for general corporate purposes on terms substantially the same as those of the 2022 Agreements:
 • One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$ 2.0 billion (including a letter of credit subfacility of up to US$ 750 million, of which US$ 250 million currently is committed). APA may increase commitments up to an aggregate US$ 2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company's two, one-year extension options.
 • The second agreement is denominated in pounds sterling (the 2025 GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of 1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company's two, one-year extension options.
 Apache has guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures first is less than US$ 1.0 billion.

 Letters of credit are available under each 2025 Agreement for credit support needs of APA and its subsidiaries, including in respect of North Sea decommissioning obligations. As of January 15, 2025, letters of credit aggregating approximately 253 million originally issued under the 2022 GBP Agreement were deemed issued and outstanding under the 2025 GBP Agreement.
 All borrowings under the 2025 USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin varying from 0.0 % to 0.675 % (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.00 % to 1.675 % (Applicable Margin). All borrowings under the 2025 GBP Agreement bear interest with respect to any business day at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average with respect to such business day published by the Bank of England, plus the Applicable Margin.
 Each 2025 Agreement also requires the borrower to pay quarterly (i) a facility fee on total commitments at a per annum rate that varies from 0.125 % to 0.325 % and (ii) a commission on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.
 Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). APA's Long-Term Debt Rating currently applies, and the Base Rate Margin is 0.30 %, the Applicable Margin is 1.30 %, and the facility fee is 0.20 %.
 Borrowers under each 2025 Agreement, which include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default, such as:
 • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65 % at the end of any fiscal quarter.
 • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada; Liens on assets also are permitted if debt secured thereby does not exceed 15 % of APA's consolidated net tangible assets.

 • Negative covenants restrict APA's ability to merge with another entity unless it is the surviving entity, a borrower's disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.
 • Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.
 The 2025 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.
 Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt
 On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA's cash tender offers. In settling these offerings pursuant to their respective terms:
 • APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $ 2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA's exchange offers, (ii) $ 203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $ 850 million in the new notes offering, comprised of $ 350 million aggregate principal amount of APA's 6.10 % Notes due 2035 and $ 500 million aggregate principal amount of APA's 6.75 % Notes due 2055.
 • In addition to issuing the APA notes in the exchange offers, APA paid a total of $ 2.5 million in cash as part of the exchange consideration.
 • APA paid a total of $ 869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $ 1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers.
 • Net proceeds from the sale of the notes in APA's new notes offering, after deducting the initial purchasers' discounts and estimated offering expenses, were approximately $ 839 million and used to fund in part APA's purchase of Apache notes in APA's cash tender offers.
 • Each series of APA notes and debentures issued in settlement of the exchange and tender offers has the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.
 • Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering are fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures is less than $ 1 billion.
 • APA entered into two registration rights agreements, one covering notes and debentures issued in APA's exchange and tender offers and one covering notes issued in APA's new notes offering (each a Registration Rights Agreement). These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA and Apache to use their commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA and guaranteed, if applicable, by Apache containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions or any increase in annual interest rate) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue on the principal amount of such registrable securities at a rate of 0.25 % per annum for

 the first 90-day period beginning on the day immediately following such registration default (which rate will be increased by an additional 0.25 % per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may in no event exceed 1.00 % per annum). To the extent Apache's guarantee of the registrable securities is terminated in accordance with the terms of such guarantee, the registered notes will not be guaranteed by Apache, the exchange offer and registration requirements with respect thereto will be the sole obligation of the Company, and Apache will automatically be released from all obligations under the applicable Registration Rights Agreement.
 The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA's exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA's exchange or tender offers):

 January 10, 2025

 APA

 Apache

 4.625 % notes due 2025

 $
 —
 $

 7.7 % notes due March 2026(1)(5)(6)

 7.95 % notes due April 2026(1)(5)(6)

 4.875 % notes due 2027(4)(5)(6)

 4.375 % notes due 2028(4)(5)(6)

 7.75 % notes due 2029(2)(5)(6)

 4.25 % notes due 2030(4)(5)(6)

 6.0 % notes due 2037(1)(5)(6)

 5.1 % notes due 2040(1)(5)(6)

 5.25 % notes due 2042(1)(5)(6)

 4.75 % notes due 2043(3)(5)(6)

 4.25 % notes due 2044(3)(5)(6)

 7.375 % debentures due 2047(1)(5)(6)

 5.35 % notes due 2049(4)(5)(6)

 7.625 % debentures due 2096(1)(5)(6)

 6.1 % notes due 2035(7)

 —

 6.75 % notes due 2055(7)

 —

 Total

 $
 3,592
 $
 1,095

 (1)The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
 (2)The Apache 2029 notes were issued under the Indenture, dated as of November 23, 1999, between Apache (as successor to Apache Finance Canada Corporation), and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
 (3)The Apache 2043 notes and the Apache 2044 notes were issued under the Senior Indenture, dated as of May 19, 2011, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).
 (4)The Apache 2027 notes, the Apache 2028 notes, the Apache 2030 notes, and the Apache 2049 notes were issued under the Indenture, dated as of August 14, 2018, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).
 (5)In connection with APA's exchange and tender offers, Apache solicited the consents of the holders of these Apache notes and debentures to amend the applicable Apache Indenture to remove certain restrictive and reporting covenants. The Apache notes and debentures are senior unsecured obligations of Apache. Apache received consents sufficient to approve the proposed amendments to the Apache Indentures with respect to the Apache March 2026 notes, the Apache 2028 notes, the Apache 2029 notes, the Apache 2030 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2043 notes, the Apache 2044 notes, the Apache 2047 debentures, the Apache 2049 notes, and the Apache 2096 debentures. As a result, Apache and the respective trustee for the Apache Indentures entered into supplemental indentures on January 10, 2025, implementing the proposed amendments effective as of that date.
 (6)The APA March 2026 notes, the APA April 2026 notes, the APA 2027 notes, the APA 2028 notes, the APA 2029 notes, the APA 2030 notes, the APA 2037 notes, the APA 2040 notes, the APA 2042 notes, the APA 2043 notes, the APA 2044 notes, the APA 2047 debentures, the APA 2049 notes, and the APA 2096 debentures were issued under the Indenture, dated as of June 30, 2021, between the Company, as issuer, and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee. These APA notes and debentures were issued in APA's exchange and tender offers for Apache's notes and debentures.

 (7)The APA 2035 notes and the APA 2055 notes were issued under the Indenture, dated as of December 11, 2024, between the Company, as issuer, and Regions Bank, as trustee. These APA notes were issued in APA's new notes offering to fund in part its purchase of Apache notes in APA's cash tender offers.
 Subsequent Event—Open Market Repurchases of Apache Indenture Debt
 In the first quarter of 2025 through the date of this filing, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $ 55 million for an aggregate purchase price of $ 50 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $ 7 million. The Company recognized a $ 6 million gain on these repurchases. The repurchases were partially financed by APA's borrowing under the Company's commercial paper program.

 10. INCOME TAXES
 Net income before income taxes was composed of the following:

 2024
 2023
 2022

 U.S.
 $
 $
 $
 2,675

 2,256
 3,059

 Total
 $
 1,535
 $
 2,883
 $
 5,734

 The total income tax provision (benefit) consisted of the following:

 2024
 2023
 2022

 Current income taxes:

 Federal
 $
 $
 $

 State

 1,075
 1,330
 1,495

 1,153
 1,338
 1,507

 Deferred income taxes:

 Federal
 ( 96)
 ( 1,708)
 —

 State
 ( 32)
 —

 ( 643)

 ( 736)
 ( 1,662)

 Total
 $
 $
 ( 324)
 $
 1,652

 The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company's net income before income taxes and total income tax provision (benefit) is shown below:

 2024
 2023
 2022

 Income tax expense at U.S. statutory rate
 $
 $
 $
 1,204

 State income tax, less federal effect(1)

 ( 23)

 Taxes related to foreign operations

 Tax credits
 ( 3)
 —
 ( 4)

 Net change in tax contingencies

 Valuation allowances(1)

 —
 ( 1,842)
 ( 646)

 Tax adjustments attributable to BCP Business Combination
 —
 —

 Stock compensation

 ( 2)

 Legal reserve

 —
 —

 Remeasurement of U.K. deferred tax liability
 —

 Transaction costs

 —
 —

 All other, net

 $
 $
 ( 324)
 $
 1,652

 (1)The change in state valuation allowance is included as a component of state income tax.
 The net deferred income tax (asset) liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax (asset) liability consisted of the following as of December 31:

 2024
 2023

 Deferred tax assets:

 U.S. and state net operating losses
 $
 2,487
 $
 2,050

 Capital losses

 Foreign net operating losses

 Tax credits and other tax incentives

 Foreign tax credits
 2,204
 2,204

 Accrued expenses and liabilities

 Asset retirement obligation

 Property and equipment

 Equity investments

 Net interest expense limitation

 Lease liability

 Decommissioning contingency for sold Gulf of America properties

 Total deferred tax assets
 6,572
 5,762

 Valuation allowance
 ( 2,623)
 ( 2,630)

 Net deferred tax assets
 3,949
 3,132

 Deferred tax liabilities:

 Property and equipment
 1,060
 1,573

 Right-of-use asset

 Decommissioning security for sold Gulf of America properties

 Other

 Total deferred tax liabilities
 1,260
 1,745

 Net deferred income tax asset

 $
 ( 2,689)
 $
 ( 1,387)

 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:

 2024
 2023

 Assets:

 Other assets

 Deferred tax asset

 $
 2,703
 $
 1,758

 Liabilities:

 Deferred credits and other noncurrent liabilities

 Deferred tax liability

 Net deferred income tax asset

 $
 ( 2,689)
 $
 ( 1,387)

 On April 1, 2024, the Company completed its acquisition of Callon in an all-stock transaction. The Company's deferred tax asset increased by approximately $ 565 million as part of the assets assumed through the Callon acquisition. Refer to Note 2— Acquisitions and Divestitures for further detail.
 On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate, effective for the period of May 26, 2022 through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. As a result, the Company recorded a deferred tax expense of $ 174 million and $ 208 million related to the remeasurement of the U.K. deferred tax liability in 2023 and 2022, respectively.
 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. In 2024, the Company accrued tax expense of $ 74 million, which results in a tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years.
 In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, the Company does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
 On January 14, 2022, Apache Midstream LLC, a wholly owned subsidiary of Apache, exchanged 12.5 million Common Units in Altus Midstream LP for 12.5 million shares of ALTM Class A Common Stock, in a taxable exchange. On February 22, 2022, as a result of the BCP Business Combination, the Company deconsolidated ALTM. On March 11, 2022, the Company sold four million of its Kinetik Shares, and on March 18, 2024, the remaining Kinetik Shares were sold. In 2022, the Company recorded tax expense of $ 126 million associated with the BCP Business Combination. The tax impact of the BCP Business Combination was fully offset by a change in valuation allowance. Refer to Note 2— Acquisitions and Divestitures for further detail.
 Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be "more likely than not." The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized.
 During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $ 1.7 billion.

 In 2024, 2023, and 2022, the Company's valuation allowance decreased by $ 7 million, $ 2.3 billion and $ 1.0 billion, respectively, as detailed in the table below:

 2024
 2023
 2022

 Balance at beginning of year
 $
 2,630
 $
 4,918
 $
 5,902

 State(1)

 ( 51)
 ( 63)
 ( 111)

 U.S.
 ( 2,235)
 ( 706)

 ( 167)

 Balance at end of year
 $
 2,623
 $
 2,630
 $
 4,918

 (1)Reported as a component of state income taxes.
 On December 31, 2024, the Company had net operating losses as follows:

 Amount
 Expiration

 U.S.
 $
 10,345
 2028 - Indefinite

 State
 6,586
 Various

 2025 - Indefinite

 The Company has a U.S. net operating loss carryforward of $ 10.3 billion, which includes $ 2.1 billion of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $ 6.6 billion, foreign net operating losses of $ 153 million, and a net interest expense carryover of $ 1.3 billion under Section 163(j) of the Code with indefinite carryover. The Company has recorded a valuation allowance against some of the U.S. net operating losses, a majority of the state net operating losses, the foreign net operating losses, and the U.S. capital loss because it is more likely than not that these net operating losses and the capital loss carryforward will not be realized. The Company believes it is more likely than not that the deferred tax assets related to the remaining U.S. and state net operating losses, and the net interest expense carryover will be utilized prior to their expiration.
 On December 31, 2024, the Company had foreign tax credits as follows:

 Amount
 Expiration

 Foreign tax credits
 $
 2,204
 2025-2026

 The Company has a $ 2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.
 The Company accounts for income taxes in accordance with ASC Topic 740, "Income Taxes," which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 2024
 2023
 2022

 Balance at beginning of year
 $
 $
 $

 Additions based on tax positions related to prior year
 —

 Additions based on tax positions related to the current year
 —
 —
 —

 Reductions for tax positions of prior years
 ( 5)
 —
 ( 27)

 Balance at end of year
 $
 $
 $

 The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2024, 2023, and 2022, the Company recorded tax expense of $ 2 million, $ 2 million, and $ 1 million, respectively, for interest and penalties. At December 31, 2024, 2023, and 2022, the Company had an accrued liability for interest and penalties of $ 9 million, $ 7 million, and $ 5 million, respectively.
 The Company and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company's uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. The Company's earliest open tax years in its key jurisdictions are as follows:
 Jurisdiction

 U.S.
 2014

 Egypt
 2005

 U.K.
 2022

 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 December 31, 2024, the Company has an accrued liability of approximately $ 20 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.
 Louisiana Restoration
 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.
 Delaware Litigation
 On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company is vigorously defending the suit.
 Kulp Minerals Lawsuit
 On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
 Environmental Matters
 As of December 31, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $ 2 million.
 The Company is not aware of any environmental claims existing as of December 31, 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 America (GOA) Shelf operations and properties and its GOA operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOA Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOA Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf's limited liability company agreement, the proceeds of production of the Legacy GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOA Assets as and when Apache is required to perform or pay for any such decommissioning was

 accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf's second bankruptcy to 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 GOA Assets.
 By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf's notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf's notification letters. Apache has also received orders to decommission other Legacy GOA Assets that were not included in GOM Shelf's notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOA Assets.
 On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the $ 148 million in Bonds and $ 350 million in Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. 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 $ 350 million in Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refused to honor 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. The parties settled their dispute in the first quarter of 2025, which resulted in, among other things, mutual releases, the retention by Apache of all amounts drawn on the Letters of Credit, and payment to Apache of $ 140 million under the Bonds.
 As of December 31, 2024, the Company recorded an asset of $ 178 million representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs. Of the total asset recorded as of December 31, 2024, $ 21 million is reflected under the caption "Decommissioning security for sold Gulf of America properties," and $ 157 million is reflected under "Other current assets" in the Company's consolidated balance sheet.
 As of December 31, 2024, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $ 1.0 billion to $ 1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company recorded contingent liabilities in the amounts of $ 1.0 billion and $ 824 million as of December 31, 2024, and December 31, 2023, respectively. Of the total liability recorded as of December 31, 2024, $ 929 million is reflected under the caption "Decommissioning contingency for sold Gulf of America properties" and $ 88 million is reflected under "Other current liabilities" in the Company's consolidated balance sheet. Changes in significant assumptions impacting Apache's estimated liability, including expected well decommissioning spread rates, derrick barge rates, and planned abandonment logistics, could result in a liability in excess of the amount accrued.
 The Company recognized $ 273 million of "Losses on previously sold Gulf of America properties" during 2024 to reflect the net impact of an increase in estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The loss includes $ 67 million related to properties previously sold to third parties other than Fieldwood for which the Company received BSSE orders to decommission during the year, as well as an increase to the estimated net liability the Company expects to incur for decommissioning Legacy GOA Assets. The Company also recognized losses on previously sold Gulf of America properties of $ 212 million and $ 157 million during 2023 and 2022, respectively, in the Company's statement of consolidated operations.

 Leases and Contractual Obligations
 The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, the Company records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company's lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within "Deferred charges and other assets" on the Company's consolidated balance sheet, and the associated operating lease liabilities are reflected within "Other current liabilities" and "Other" within "Deferred Credits and Other Noncurrent Liabilities," as applicable.
 Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $ 170 million, $ 168 million, and $ 145 million for the years ended 2024, 2023, and 2022, respectively. As allowed under the standard, the Company accounts for non-lease and lease components as a single lease component for all asset classes and has elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases were $ 85 million, $ 71 million, and $ 62 million in 2024, 2023, and 2022, respectively. In 2024 these costs primarily related to short term drilling rigs in the U.S. and decommissioning work in the Gulf of America. In 2023 these costs primarily related to decommissioning work in the Gulf of America. In 2022, these costs were primarily related to drilling activities in Block 58 offshore Suriname.
 Finance lease assets are included in "Property and Equipment" on the consolidated balance sheet, and the associated finance lease liabilities are reflected within " Current debt " and " Long-term debt," as applicable. Depreciation on the Company's finance lease asset was $ 2 million in each of the years 2024, 2023, and 2022. Interest on the Company's finance lease liability was $ 1 million, $ 1 million, and $ 2 million in 2024, 2023, and 2022, respectively.
 The following table represents the Company's weighted average lease term and discount rate as of December 31, 2024:

 Operating Leases
 Finance Lease

 Weighted average remaining lease term
 6.9 years
 8.7 years

 Weighted average discount rate
 5.8
 %
 4.4
 %

 At December 31, 2024, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

 Net Minimum Commitments(1)

 Operating Leases(2)

 Finance Lease(3)

 Purchase Obligations(4)(5)

 2025
 $
 $
 $

 2026

 2027

 2028

 2029

 Thereafter

 Total future minimum payments
 $
 1,118

 Less: imputed interest
 ( 94)
 ( 7)
 N/A

 Total lease liabilities
 N/A

 Current portion
 N/A

 Non-current portion
 $
 $
 N/A

 (1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.
 (2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.
 (3)Amounts represent the Company's finance lease obligation related to the Company's Midland, Texas regional office building.
 (4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $ 245 million, $ 182 million, and $ 183 million in 2024, 2023, and 2022, respectively.
 (5)Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $ 3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2024, the Company has met and fully satisfied the obligation.
 The lease liability reflected in the table above represents the Company's fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $ 48 million, $ 74 million, and $ 90 million in 2024, 2023, and 2022, respectively.

 12. RETIREMENT AND DEFERRED COMPENSATION PLANS
 The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee's annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee's annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee's base salary, up to 75 percent of each employee's annual bonus (that accepts employee contributions) and the Company's matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.
 Vesting in the Company's contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership of APA, immediate and full vesting occurs.
 The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $ 46 million, $ 44 million, and $ 40 million for 2024, 2023, and 2022, respectively.
 The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company's North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea's pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.
 Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants' contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

 The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2024, 2023, and 2022, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.

 2024
 2023
 2022

 Change in Projected Benefit Obligation

 Projected benefit obligation at beginning of year
 $
 $
 $
 $
 $
 $

 Service cost

 Interest cost
 —

 Foreign currency exchange rates
 ( 2)
 —
 —
 ( 21)
 —

 Actuarial losses (gains)
 ( 11)
 —
 —
 ( 79)
 ( 5)

 Plan settlements
 —
 ( 1)
 —
 —
 —
 —

 Benefits paid
 ( 5)
 ( 2)
 ( 5)
 ( 3)
 ( 8)
 ( 3)

 Retiree contributions
 —
 —
 —

 Projected benefit obligation at end of year

 Change in Plan Assets

 Fair value of plan assets at beginning of year
 —
 —
 —

 Actual return (loss) on plan assets
 ( 8)
 —
 —
 ( 87)
 —

 Foreign currency exchange rates
 ( 3)
 —
 —
 ( 26)
 —

 Employer contributions

 Plan settlements
 —
 —
 —
 —
 —
 —

 Benefits paid
 ( 5)
 ( 2)
 ( 5)
 ( 3)
 ( 8)
 ( 4)

 Retiree contributions
 —
 —
 —

 Fair value of plan assets at end of year
 —
 —
 —

 Funded status at end of year
 $
 $
 ( 15)
 $
 $
 ( 15)
 $
 $
 ( 15)

 Amounts recognized in Consolidated Balance Sheet

 Current liability
 $
 —
 $
 ( 2)
 $
 —
 $
 ( 2)
 $
 —
 $
 ( 2)

 Non-current asset (liability)
 ( 13)
 ( 13)
 ( 13)

 $
 $
 ( 15)
 $
 $
 ( 15)
 $
 $
 ( 15)

 Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)

 Accumulated gain (loss)
 $
 ( 16)
 $
 $
 ( 12)
 $
 $
 ( 10)
 $

 Weighted Average Assumptions used as of December 31

 Discount rate
 5.60
 %
 5.49
 %
 4.80
 %
 5.00
 %
 5.00
 %
 5.29
 %

 Salary increases
 4.70
 %
 N/A
 4.60
 %
 N/A
 4.70
 %
 N/A

 Expected return on assets
 5.70
 %
 N/A
 4.80
 %
 N/A
 4.70
 %
 N/A

 Healthcare cost trend

 Initial
 N/A
 6.50
 %
 N/A
 6.25
 %
 N/A
 6.50
 %

 Ultimate in 2032

 N/A
 5.25
 %
 N/A
 5.25
 %
 N/A
 5.25
 %

 As of December 31, 2024, 2023, and 2022, the accumulated benefit obligation for the U.K. Pension Plan was $ 102 million, $ 112 million, and $ 89 million, respectively.

 The Company's defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets under a cash flow driven investment strategy. The Company intends to invest in primarily low risk debt securities that will provide a reasonable rate of return focused on cash flow timing such that the benefits promised to members are provided when due. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of allocations for the Company's plan asset holdings are summarized below:

 Percentage of
Plan Assets at
Year-End

 2024
 2023

 Asset Category

 Global equities
 —
 %
 —
 %

 Multi-asset credit
 %
 %

 Nominal bonds
 %
 %

 Inflation-linked bonds
 %
 %

 Cash
 %
 %

 Total
 %
 %

 The plan's assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2024 and 2023 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets as follows:

 December 31,

 2024
 2023

 Asset Category

 Global equities
 $
 —
 $
 —

 Multi-asset credit

 Nominal bonds

 Inflation-linked bonds

 Cash

 Total
 $
 $

 The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 2.5 percent per year.

 The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31 as follows:

 2024
 2023
 2022

 Components of Net Periodic Benefit Cost

 Service cost
 $
 $
 $
 $
 $
 $

 Interest cost
 —

 Expected return on assets
 ( 7)
 —
 ( 7)
 —
 ( 4)
 —

 Amortization of loss
 —
 ( 2)
 —
 ( 2)
 —
 ( 1)

 Settlement loss
 —
 —
 —
 —
 —
 —

 Net periodic benefit cost
 $
 —
 $
 ( 1)
 $
 ( 1)
 $
 —
 $
 $
 —

 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31

 Discount rate
 4.80
 %
 5.00
 %
 5.00
 %
 5.29
 %
 1.80
 %
 2.57
 %

 Salary increases
 4.60
 %
 N/A
 4.70
 %
 N/A
 4.90
 %
 N/A

 Expected return on assets
 4.80
 %
 N/A
 4.70
 %
 N/A
 1.90
 %
 N/A

 Healthcare cost trend

 Initial
 N/A
 6.25
 %
 N/A
 6.50
 %
 N/A
 6.25
 %

 Ultimate in 2030

 N/A
 5.25
 %
 N/A
 5.25
 %
 N/A
 5.00
 %

 The Company expects to contribute approximately $ 2 million to its pension plan and $ 2 million to its postretirement benefit plan in 2025. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

 2025
 $
 $

 2026

 2027

 2028

 2029

 Years 2030-2034

 13. CAPITAL STOCK
 Common Stock Outstanding
 The following table provides changes to the Company's common shares outstanding for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 Balance, beginning of year
 303,575,901
 311,559,149
 346,930,765

 Shares issued for stock-based compensation plans:

 Treasury shares issued
 —
 2,016
 1,996

 Common shares issued
 70,983,745
 725,914
 791,381

 Treasury shares acquired
 ( 9,162,497)
 ( 8,711,178)
 ( 36,164,993)

 Balance, end of year
 365,397,149
 303,575,901
 311,559,149

 Net Income per Common Share
 The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 Income
 Per Share
 Income
 Per Share
 Income

 Per Share

 (In millions, except per share amounts)

 Basic:

 Income attributable to common stock

 $
 $
 2.28
 $
 2,855
 $
 9.26
 $
 3,674
 $
 11.05

 Effect of Dilutive Securities:

 Stock compensation awards

 $
 —
 —
 $
 ( 0.01)
 $
 —
 $
 ( 0.01)
 $
 —
 $
 ( 0.03)

 Diluted:

 Income attributable to common stock

 $
 $
 2.27
 $
 2,855
 $
 9.25
 $
 3,674
 $
 11.02

 The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 2.0 million, 1.9 million, and 2.4 million for the years ended December 31, 2024, 2023, and 2022, 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.
 During 2024, the Company repurchased 9.2 million shares at an average price of $ 26.83 per share, and as of December 31, 2024, the Company had remaining authorization to repurchase 34.8 million shares. During 2023, the Company repurchased 8.7 million shares at an average price of $ 37.81 per share. During 2022, the Company repurchased 36.2 million shares at an average price of $ 39.34 per share.
 Subsequent to year-end 2024 and through the date of this filing on February 28, 2025, the Company repurchased 3.9 million shares at an average price of $ 23.13 per share. As of February 28, 2025, the Company had remaining authorization to repurchase up to 30.9 million shares.
 The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions.
 Common Stock Dividend
 The Company's Board of Directors approved an increase to its quarterly dividend from $ 0.125 per share to $ 0.25 per share in the third quarter of 2022. For the years ended December 31, 2024, 2023, and 2022, the Company declared common stock dividends totaling $ 1.00 per share, $ 1.00 per share, and $ 0.75 per share, respectively.
 Stock Compensation Plans
 The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans.
 On May 12, 2016, the Company's shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2024, 7.9 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company's stock and, once vested, are settled in cash.

 Costs related to the plans are capitalized or expensed to "Lease operating expenses," "Exploration," or "General and administrative" in the Company's statement of consolidated operations based on the nature of each employee's activities. The following table summarizes the Company's stock-settled and cash-settled compensation costs for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 Stock-settled and cash-settled compensation expensed:

 $
 $
 $

 Total stock-settled and cash-settled compensation expensed

 Stock-settled and cash-settled compensation capitalized

 Total stock-settled and cash-settled compensation costs
 $
 $
 $

 Stock Options
 As of December 31, 2024, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company's shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA's common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.
 The following table summarizes stock option activity for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

Under Option
 Weighted Average
 Exercise Price

Under Option
 Weighted Average
 Exercise Price

Under Option
 Weighted Average
 Exercise Price

 (In thousands, except exercise price amounts)

 Outstanding, beginning of year
 1,465
 $
 48.48
 2,078
 $
 57.71
 3,012
 $
 63.79

 Exercised
 —
 —
 ( 12)
 42.38
 ( 99)
 42.09

 Forfeited
 —
 —
 —
 —
 ( 2)
 49.10

 Expired
 ( 49)
 43.91
 ( 601)
 80.53
 ( 833)
 81.56

 Outstanding, end of year(1)

 1,416
 48.64
 1,465
 48.48
 2,078
 57.71

 Expected to vest
 —
 —
 —
 —
 —
 —

 Exercisable, end of year(1)

 1,416
 48.64
 1,465
 48.48
 2,078
 57.71

 (1)As of December 31, 2024, options exercisable and outstanding had a weighted average remaining contractual life of 2.1 years and no aggregate intrinsic value.
 During the years ended December 31, 2024, there were no options issued or exercised. During the years ended December 31, 2023 and 2022, there were no options issued and 12,183, and 98,646 options, respectively, exercised.
 In January 2025, the Company issued 1,662,239 options to purchase shares of the Company's common stock to eligible employees under the Omnibus Plans, at an average fair value of $ 9.51 per share. The total compensation cost of $ 16 million is estimated to be recognized over a three-year vesting period of these options.
 Restricted Stock Units and Restricted Stock Phantom Units
 The Company has restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either the Company's common stock or, prior to the BCP Business Combination, in ALTM's common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

 For the years ended December 31, 2024, 2023, and 2022, compensation costs charged to expense for the restricted stock units and restricted stock phantom units were $ 53 million, $ 73 million, and $ 153 million, respectively. As of December 31, 2024, 2023, and 2022, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $ 9 million, $ 11 million, and $ 22 million, respectively.
 The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 Units
 Weighted
Average Grant-Date Fair Value
 Units
 Weighted
Average Grant-Date Fair Value
 Units
 Weighted
Average Grant-Date Fair Value

 (In thousands, except per share amounts)

 Non-vested, beginning of year
 1,480
 $
 30.69
 1,885
 $
 23.08
 2,073
 $
 19.98

 Granted
 33.48
 41.60
 29.90

 Assumed awards from Callon acquisition

 1,498
 35.43
 —
 —
 —
 —

 Vested(3)

 ( 2,295)
 31.83
 ( 975)
 23.31
 ( 978)
 22.39

 Forfeited
 ( 165)
 35.48
 ( 69)
 32.44
 ( 57)
 23.49

 Expired

 —
 —
 ( 22)
 27.81
 —
 —

 Non-vested, end of year(1)(2)

 1,415
 35.07
 1,480
 30.69
 1,885
 23.08

 (1)As of December 31, 2024, there was $ 18 million of total unrecognized compensation cost related to 1,257,784 unvested stock-settled restricted stock units.
 (2)As of December 31, 2024, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.
 (3)The grant date fair values of the stock-settled awards vested during 2024, 2023, and 2022 were $ 73 million, $ 23 million, and $ 22 million, respectively.
 The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 (In thousands)

 Non-vested, beginning of year
 4,478
 5,709
 6,402

 Adjustment from ALTM transaction(1)

 —
 —

 Granted(2)

 2,369
 1,972
 2,568

 Vested
 ( 2,568)
 ( 2,851)
 ( 2,970)

 Forfeited
 ( 362)
 ( 340)
 ( 434)

 Expired

 —
 ( 12)
 —

 Non-vested, end of year(3)

 3,917
 4,478
 5,709

 (1)Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA's common stock price to replace the equivalent value in restricted stock phantom units based on ALTM's common stock price.
 (2)Restricted stock phantom units granted during 2024, 2023, and 2022 included 2,369,605, 1,972,116, and 2,512,602 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 included 55,546 awards based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022.
 (3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2024 was approximately $ 34 million.
 In January 2025, the Company awarded 693,761 restricted stock units and 2,300,091 restricted stock phantom units based on APA's weighted-average per-share market price of $ 23.68 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $ 16 million and $ 54 million, respectively, and was calculated based on the per-share fair market value of a share of the Company's common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company's common stock, a Level 1 fair value measurement.

 Performance Program
 To provide long-term incentives for the Company's employees to deliver competitive shareholder returns, the Company makes annual grants of cash-settled conditional restricted stock phantom units to eligible employees. APA has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award's stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2024, are as described below:
 • In January 2021, the Company's Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. A total of 1,051,688 phantom units were outstanding as of December 31, 2024. The results for the performance period yielded a payout of 118 percent of target.
 • In January 2022, the Company's Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. A total of 998,570 phantom units were outstanding as of December 31, 2024. The results for the performance period yielded a payout of 118 percent of target.
 • In January 2023, the Company's Board of Directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 822,200 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 718,288 phantom units were outstanding as of December 31, 2024, from which a minimum of zero to a maximum of 1,436,576 units could be awarded.
 • In January 2024, the Company's Board of Directors approved the 2024 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 645,318 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 571,498 phantom units were outstanding as of December 31, 2024, from which a minimum of zero to a maximum of 1,142,996 units could be awarded. Eligible employees also received cash incentives as part of the 2024 Performance Program, which totaled $ 13 million as of December 31, 2024. The ultimate payout will range from zero to $ 26 million at the end of a three-year performance period.
 Compensation costs related to the conditional cash-settled awards are recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the cash-settled performance programs were a net benefit of $ 13 million during 2024 and expenses of $ 2 million and $ 143 million during 2023 and 2022, respectively. Capitalized compensation costs under the cash-settled performance programs were a net benefit of approximately $ 1 million during 2024 and expenses of approximately $ 100 thousand and $ 21 million during 2023 and 2022, respectively.
 The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2024, 2023, and 2022:

 2024
 2023
 2022

 (In thousands)

 Non-vested, beginning of year
 4,629
 4,835
 4,531

 Granted
 1,536
 1,676

 Assumed awards from Callon acquisition

 2,934
 —
 —

 Vested
 ( 4,222)
 ( 1,593)
 ( 656)

 Forfeited
 ( 203)
 ( 99)
 ( 106)

 Expired
 —
 ( 50)
 ( 610)

 Non-vested, end of year(1)

 3,972
 4,629
 4,835

 (1)As of December 31, 2024, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $ 12 million.

 In January 2025, the Company's Board of Directors approved the 2025 Performance Program, pursuant to the 2016 Plan. A portion of the award is based upon measurement of TSR similar to prior year awards, and the remaining portion of the award is based on performance and financial objectives as defined in the 2025 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 985,553 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,971,106 units. These phantom units represent a hypothetical interest in the Company's common stock, and, once vested, are settled in cash. These phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company's common stock, a Level 1 fair value measurement. The cash incentives totaled $ 16 million, with the ultimate payout ranging from zero to $ 32 million. Final payout of the awards will be determined at the end of a three-year performance period.

 14. ACCUMULATED OTHER COMPREHENSIVE INCOME
 Components of accumulated other comprehensive income include the following:

 As of December 31,

 2024
 2023
 2022

 Pension and postretirement benefit plan ( Note 12)

 $
 $
 $

 Accumulated other comprehensive income
 $
 $
 $

 15. MAJOR CUSTOMERS
 The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2024, sales to EGPC accounted for approximately 17 percent of the Company's worldwide crude oil, natural gas, and NGLs revenues. During each of 2023 and 2022, sales to EGPC accounted for approximately 15 percent of the Company's worldwide crude oil, natural gas, and NGLs revenues.
 Management does not believe that the loss of any single customer would have a material adverse effect on the results of operations.

 16. BUSINESS SEGMENT INFORMATION
 As of December 31, 2024, the Company's consolidated subsidiaries are engaged in exploration, development and/or production activities across four operating segments: Egypt, North Sea, Suriname, and the U.S. The Company's business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the deconsolidation of Altus on February 22, 2022, the Company's Midstream business was operated by ALTM, which owned, developed, and operating a midstream energy asset network in the Permian Basin of West Texas.
 The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company's Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is primarily associated with operating income from each segment and the resulting free cash flow, amongst other metrics. The Company concluded that the most comparable measure under U.S. GAAP is operating income.
 Financial information for each segment is presented below:

 U.S.

 Intersegment Eliminations & Other(6)

 Total(2)

 2024

 Oil revenues
 $
 3,572
 $
 2,620
 $
 $
 —
 $
 6,966

 Natural gas revenues
 —

 Natural gas liquids revenues
 —
 —

 Oil, natural gas, and natural gas liquids production revenues
 4,315
 2,933
 —
 8,196

 Purchased oil and gas sales
 1,541
 —
 —
 —
 1,541

 5,856
 2,933
 —
 9,737

 Operating Expenses:

 Lease operating expenses(5)

 —
 1,690

 Gathering, processing, and transmission(5)

 —

 1,047
 —
 —
 —
 1,047

 Taxes other than income(5)

 —
 —
 —

 Exploration(4)

 Depreciation, depletion, and amortization(5)

 1,340
 —
 2,266

 —
 —

 —
 —
 1,129

 4,327
 1,226
 1,676
 7,295

 Operating Income (Loss)
 $
 1,529
 $
 1,707
 $
 ( 728)
 $
 ( 66)
 2,442

 Other Income (Expense):

 ( 273)

 Derivative instrument losses, net

 ( 10)

 Other
 ( 6)

 ( 372)

 ( 168)

 ( 367)

 Income Before Income Taxes
 $
 1,535

 Total Assets(3)

 $
 13,870
 $
 3,606
 $
 1,324
 $
 $
 19,390

 Net Property and Equipment
 $
 9,109
 $
 2,271
 $
 $
 $
 12,646

 Additions to Net Property and Equipment
 $
 6,609
 $
 $
 $
 $
 7,499

 U.S.

 Intersegment Eliminations & Other(6)

 Total(2)

 2023

 Oil revenues
 $
 2,241
 $
 2,683
 $
 1,073
 $
 —
 $
 5,997

 Natural gas revenues
 —

 Natural gas liquids revenues
 —
 —

 Oil, natural gas, and natural gas liquids production revenues
 3,018
 3,029
 1,338
 —
 7,385

 Purchased oil and gas sales
 —
 —
 —

 3,912
 3,029
 1,338
 —
 8,279

 Operating Expenses:

 Lease operating expenses(5)

 —
 1,436

 Gathering, processing, and transmission(5)

 —

 —
 —
 —

 Taxes other than income(5)

 —
 —
 —

 Exploration(4)

 Depreciation, depletion, and amortization(5)

 —
 1,540

 —
 —

 —
 —

 2,601
 1,150
 4,631

 Operating Income (Loss)
 $
 1,311
 $
 1,879
 $
 $
 ( 43)
 3,648

 Other Income (Expense):

 ( 212)

 Derivative instrument gains, net

 Other

 ( 351)

 ( 15)

 ( 312)

 Income Before Income Taxes
 $
 2,883

 Total Assets(3)

 $
 9,221
 $
 3,503
 $
 1,970
 $
 $
 15,244

 Net Property and Equipment
 $
 5,689
 $
 2,209
 $
 1,628
 $
 $
 10,038

 Additions to Net Property and Equipment
 $
 1,255
 $
 $
 $
 $
 2,313

 U.S.

 Intersegment Eliminations & Other(6)

 Total(2)

 2022

 Oil revenues
 $
 2,458
 $
 3,145
 $
 1,232
 $
 —
 $
 6,835

 Natural gas revenues
 —
 1,569

 Natural gas liquids revenues
 ( 3)

 Oil, natural gas, and natural gas liquids production revenues
 4,144
 3,521
 1,558
 ( 3)
 9,220

 Purchased oil and gas sales
 1,850
 —
 —
 1,855

 5,994
 3,521
 1,558
 11,075

 Operating Expenses:

 Lease operating expenses(5)

 ( 1)
 1,444

 Gathering, processing, and transmission(5)

 ( 13)

 1,776
 —
 —
 —
 1,776

 Taxes other than income(5)

 —
 —

 Exploration(4)

 Depreciation, depletion, and amortization(5)

 1,233

 —

 3,522
 1,032
 5,510

 Operating Income (Loss)
 $
 2,472
 $
 2,489
 $
 $
 ( 152)
 5,565

 Other Income (Expense):

 1,180

 ( 157)

 Derivative instrument losses, net

 ( 114)

 Other

 ( 483)

 ( 26)

 ( 379)

 Income Before Income Taxes

 $
 5,734

 Total Assets(3)

 $
 7,574
 $
 3,148
 $
 1,911
 $
 $
 13,147

 Net Property and Equipment
 $
 5,226
 $
 1,976
 $
 1,386
 $
 $
 9,012

 Additions to Net Property and Equipment
 $
 1,439
 $
 $
 $
 $
 2,607

 (1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2024, 2023, and 2022 of:

 2024
 2023
 2022

 Oil
 $
 $
 $

 Natural gas

 Natural gas liquids
 —
 —

 (2)Includes a noncontrolling interest in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the year 2022.
 (3)Intercompany balances are excluded from total assets.
 (4)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company's Suriname exploration activities.
 (5)Represents significant segment expense categories that align with the segment-level information that is regularly provided to the CODM. The remaining expenses that comprise the Other Income (Loss) amount by segment are deemed to be other segment expense categories necessary to arrive at the segment profit or loss.
 (6)Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported. For 2022, the Company's midstream business results are also included in this category as the midstream operating segment has not met the quantitative thresholds to be separately reported.

 17. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

 Oil and Gas Operations
 The following table sets forth revenue and direct cost information relating to the Company's oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

 Other

 (In millions, except per boe)

 2024

 Oil and gas production revenues
 $
 4,315
 $
 2,933
 $
 $
 —
 $
 8,196

 Operating cost:

 Depreciation, depletion, and amortization(2)

 1,314
 —
 2,235

 —
 —

 —
 1,690

 Gathering, processing, and transmission
 —

 Exploration expenses

 Impairments related to oil and gas properties
 —
 —
 1,111

 Production taxes(3)

 —
 —
 —

 Income tax
 ( 536)
 —

 3,482
 1,992
 1,126
 6,666

 Results of operations
 $
 $
 $
 ( 178)
 $
 ( 66)
 $
 1,530

 2023

 Oil and gas production revenues
 $
 3,018
 $
 3,029
 $
 1,338
 $
 —
 $
 7,385

 Operating cost:

 Depreciation, depletion, and amortization(2)

 —
 1,500

 —
 —

 —
 1,436

 Gathering, processing, and transmission
 —

 Exploration expenses

 Production taxes(3)

 —
 —
 —

 Income tax
 —
 1,496

 2,063
 1,975
 1,200
 5,281

 Results of operations
 $
 $
 1,054
 $
 $
 ( 43)
 $
 2,104

 2022

 Oil and gas production revenues
 $
 4,144
 $
 3,521
 $
 1,558
 $
 —
 $
 9,223

 Operating cost:

 Depreciation, depletion, and amortization(2)

 —
 1,186

 —
 —

 —
 1,445

 Gathering, processing, and transmission
 —

 Exploration expenses

 Production taxes(3)

 —
 —
 —

 Income tax
 1,100
 —
 2,105

 2,225
 2,122
 1,291
 5,800

 Results of operations
 $
 1,919
 $
 1,399
 $
 $
 ( 162)
 $
 3,423

 (1)Includes a noncontrolling interest in Egypt.
 (2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 16—Business Segment Information.
 (3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 16—Business Segment Information.

 Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities

 Egypt(2)

 Other
 Total(2)

 2024

 Acquisitions:

 $
 3,606
 $
 $
 —
 $
 —
 $
 3,609

 Unproved
 —
 —
 —

 Development
 2,067
 2,859

 Costs incurred(1)

 $
 6,778
 $
 $
 $
 $
 7,862

 (1) Includes capitalized interest and asset retirement costs:

 $
 $
 —
 $
 —
 $
 $

 Asset retirement costs
 —
 —

 2023

 Acquisitions:

 $
 $
 $
 —
 $
 —
 $

 Unproved
 —
 —
 —

 Development
 1,148
 —
 2,262

 Costs incurred(1)

 $
 1,200
 $
 $
 $
 $
 2,719

 (1) Includes capitalized interest and asset retirement costs:

 $
 —
 $
 —
 $
 —
 $
 $

 Asset retirement costs
 ( 4)
 —
 —

 2022

 Acquisitions:

 $
 $
 $
 —
 $
 —
 $

 Unproved
 —
 —
 —

 Development
 ( 57)
 —
 1,359

 Costs incurred(1)

 $
 1,514
 $
 $
 $
 $
 2,569

 (1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:

 $
 —
 $
 —
 $
 $
 $

 Asset retirement costs
 —
 ( 215)
 —
 ( 136)

 (2) Includes a noncontrolling interest in Egypt.

 Capitalized Costs
 The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company's oil and gas acquisition, exploration, and development activities:

 North
Sea
 Other

 2024

 Proved properties
 $
 19,246
 $
 14,458
 $
 9,661
 $
 $
 43,799

 Unproved properties
 —

 19,957
 14,525
 9,661
 44,698

 Accumulated DD&A
 ( 11,053)
 ( 12,299)
 ( 8,952)
 —
 ( 32,304)

 $
 8,904
 $
 2,226
 $
 $
 $
 12,394

 2023

 Proved properties
 $
 20,758
 $
 13,777
 $
 9,472
 $
 —
 $
 44,007

 Unproved properties

 21,025
 13,848
 9,475
 44,860

 Accumulated DD&A
 ( 15,587)
 ( 11,678)
 ( 7,849)
 —
 ( 35,114)

 $
 5,438
 $
 2,170
 $
 1,626
 $
 $
 9,746

 (1)Includes a noncontrolling interest in Egypt.

 Oil and Gas Reserve Information
 Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the "economic interest" method, which excludes the host country's share of reserves.
 Estimated reserves that can be produced economically through application of improved recovery techniques are included in the "proved" classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, the Company uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company's reserve estimates.

 There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.

 Crude Oil and Condensate

 North
Sea

 (Thousands of barrels)

 Proved developed reserves:

 180,968
 106,646
 77,073
 —
 364,687

 177,708
 108,050
 82,580
 —
 368,338

 179,542
 102,305
 61,076
 —
 342,923

 184,744
 95,990
 30,436
 —
 311,170

 Proved undeveloped reserves:

 18,168
 11,003
 5,757
 —
 34,928

 22,239
 8,557
 2,873
 —
 33,669

 30,948
 5,254
 —
 —
 36,202

 107,283
 7,621
 —
 188,541

 Total proved reserves:

 Balance December 31, 2021
 199,136
 117,649
 82,830
 —
 399,615

 9,776
 7,580
 2,616
 —
 19,972

 16,362
 —
 —
 —
 16,362

 7,793
 22,433
 11,898
 —
 42,124

 ( 25,695)
 ( 31,055)
 ( 11,891)
 —
 ( 68,641)

 ( 7,425)
 —
 —
 —
 ( 7,425)

 Balance December 31, 2022
 199,947
 116,607
 85,453
 —
 402,007

 43,613
 12,979
 —
 56,893

 —
 —
 —

 ( 3,520)
 10,505
 ( 12,002)
 —
 ( 5,017)

 ( 28,795)
 ( 32,532)
 ( 12,676)
 —
 ( 74,003)

 ( 775)
 —
 —
 —
 ( 775)

 Balance December 31, 2023
 210,490
 107,559
 61,076
 —
 379,125

 100,778
 18,115
 —
 192,530

 124,112
 —
 —
 —
 124,112

 ( 9,642)
 10,521
 ( 21,000)
 —
 ( 20,121)

 ( 47,043)
 ( 32,584)
 ( 9,640)
 —
 ( 89,267)

 ( 86,668)
 —
 —
 —
 ( 86,668)

 Balance December 31, 2024
 292,027
 103,611
 30,436
 499,711

 (1)Includes proved reserves of 35 MMbbls, 36 MMbbls, 39 MMbbls, and 39 MMbbls as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt.

 Natural Gas Liquids

 North
Sea

 (Thousands of barrels)

 Proved developed reserves:

 164,172
 2,059
 166,677

 158,745
 —
 2,230
 160,975

 153,486
 —
 1,460
 154,946

 153,523
 —
 154,267

 Proved undeveloped reserves:

 16,380
 16,685

 19,004
 —
 19,080

 18,401
 —
 —
 18,401

 54,674
 —
 —
 54,674

 Total proved reserves:

 Balance December 31, 2021
 180,552
 2,334
 183,362

 5,456
 —
 5,501

 10,985
 —
 —
 10,985

 9,991
 ( 407)
 9,917

 ( 22,895)
 ( 69)
 ( 406)
 ( 23,370)

 ( 6,340)
 —
 —
 ( 6,340)

 Balance December 31, 2022
 177,749
 —
 2,306
 180,055

 25,711
 —
 26,082

 —
 —

 ( 8,568)
 —
 ( 764)
 ( 9,332)

 ( 22,993)
 —
 ( 453)
 ( 23,446)

 ( 33)
 —
 —
 ( 33)

 Balance December 31, 2023
 171,887
 —
 1,460
 173,347

 62,988
 —
 —
 62,988

 51,406
 —
 —
 51,406

 ( 20,167)
 —
 ( 277)
 ( 20,444)

 ( 27,039)
 —
 ( 439)
 ( 27,478)

 ( 30,878)
 —
 —
 ( 30,878)

 Balance December 31, 2024
 208,197
 —
 208,941

 (1) Includes proved reserves of 159 Mbbls as of December 31, 2021, respectively, attributable to a noncontrolling interest in Egypt.

 Natural Gas

 North
Sea

 (Millions of cubic feet)

 Proved developed reserves:

 1,237,461
 464,826
 76,155
 1,778,442

 1,166,218
 399,502
 66,292
 1,632,012

 1,003,956
 377,144
 46,839
 1,427,939

 866,460
 332,905
 28,028
 1,227,393

 Proved undeveloped reserves:

 184,441
 9,899
 7,124
 201,464

 210,862
 1,068
 2,304
 214,234

 99,495
 2,612
 —
 102,107

 307,775
 27,499
 —
 335,274

 Total proved reserves:

 Balance December 31, 2021
 1,421,902
 474,725
 83,279
 1,979,906

 38,157
 10,191
 1,643
 49,991

 70,584
 —
 —
 70,584

 92,599
 45,725
 ( 3,431)
 134,893

 ( 172,752)
 ( 130,071)
 ( 12,895)
 ( 315,718)

 ( 73,410)
 —
 —
 ( 73,410)

 Balance December 31, 2022
 1,377,080
 400,570
 68,596
 1,846,246

 158,118
 14,188
 3,335
 175,641

 —
 —

 ( 266,664)
 83,907
 ( 6,739)
 ( 189,496)

 ( 165,083)
 ( 118,909)
 ( 18,353)
 ( 302,345)

 ( 136)
 —
 —
 ( 136)

 Balance December 31, 2023
 1,103,451
 379,756
 46,839
 1,530,046

 354,267
 60,366
 —
 414,633

 279,615
 —
 —
 279,615

 ( 224,118)
 26,792
 ( 4,176)
 ( 201,502)

 ( 176,941)
 ( 106,510)
 ( 14,635)
 ( 298,086)

 ( 162,039)
 —
 —
 ( 162,039)

 Balance December 31, 2024
 1,174,235
 360,404
 28,028
 1,562,667

 (1) Includes proved reserves of 120 Bcf, 127 Bcf, 134 Bcf, and 158 Bcf as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt.

 Total Equivalent Reserves

 North
Sea

 (Thousands barrels of oil equivalent)

 Proved developed reserves:

 551,384
 184,563
 91,825
 —
 827,772

 530,823
 174,633
 95,859
 —
 801,315

 500,354
 165,162
 70,343
 —
 735,859

 482,677
 151,474
 35,852
 —
 670,003

 Proved undeveloped reserves:

 65,288
 12,683
 7,219
 —
 85,190

 76,386
 8,735
 3,333
 —
 88,454

 65,931
 5,690
 —
 —
 71,621

 213,253
 12,204
 —
 299,094

 Total proved reserves:

 Balance December 31, 2021
 616,672
 197,246
 99,044
 —
 912,962

 21,592
 9,278
 2,935
 —
 33,805

 39,110
 —
 —
 —
 39,110

 33,217
 29,647
 11,659
 —
 74,523

 ( 77,382)
 ( 52,803)
 ( 14,446)
 —
 ( 144,631)

 ( 26,000)
 —
 —
 —
 ( 26,000)

 Balance December 31, 2022
 607,209
 183,368
 99,192
 —
 889,769

 95,677
 15,344
 1,228
 —
 112,249

 —
 —
 —

 ( 56,532)
 24,490
 ( 13,889)
 —
 ( 45,931)

 ( 79,302)
 ( 52,350)
 ( 16,188)
 —
 ( 147,840)

 ( 831)
 —
 —
 —
 ( 831)

 Balance December 31, 2023
 566,285
 170,852
 70,343
 —
 807,480

 222,811
 28,176
 —
 324,624

 222,121
 —
 —
 —
 222,121

 ( 67,162)
 14,986
 ( 21,973)
 —
 ( 74,149)

 ( 103,572)
 ( 50,336)
 ( 12,518)
 —
 ( 166,426)

 ( 144,553)
 —
 —
 —
 ( 144,553)

 Balance December 31, 2024
 695,930
 163,678
 35,852
 969,097

 (1) Includes total proved reserves of 55 MMboe, 57 MMboe, 61 MMboe, and 66 MMboe as of December 31, 2024, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt.
 During 2024, the Company added approximately 325 MMboe from extensions, discoveries, and other additions. The Company recorded 223 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin targeting the Wolfcamp, Bone Spring and Spraberry producing horizons. International operations contributed 102 MMboe of exploration and development adds, with Egypt contributing 28 MMboe from onshore exploration and appraisal and 74 MMboe from the Suriname final investment decision (FID).
 The Company realized combined downward revision of previously estimated reserves of 74 MMboe. Negative revision related to pricing and interest totaled 99 MMboe, driven primarily by depressed Permian Basin gas pricing. This downward revision was partially offset by engineering and performance upward revisions totaling 25 MMboe. The U.S. and Egypt contributed upward revision of 47 MMboe, offset by negative revision of 22 MMboe in the North Sea.

 During 2023, the Company added approximately 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 27 MMboe in the Delaware Basin, and 2 MMboe in the Texas Gulf Coast. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 16 MMboe of exploration and development adds, with Egypt contributing 15 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 1 MMboe from the North Sea. The Company had combined downward revisions of previously estimated reserves of 46 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, partially offset by engineering and performance upward revisions of 37 MMboe.
 During 2022, the Company added approximately 34 MMboe from extensions, discoveries, and other additions. The Company recorded 22 MMboe of exploration and development adds in the U.S., comprising 9 MMboe in the Permian Basin, 8 MMboe in the Texas Gulf Coast, and 5 MMboe in the Delaware Basin. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 12 MMboe of exploration and development adds, with Egypt contributing 9 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 3 MMboe from the North Sea. The Company had combined upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with Egypt accounting for an increase of 43 MMboe, primarily the result of PSC modernization in Egypt. The North Sea contributed 9 MMboe of upward revisions from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 39 MMboe of proved reserves during 2022, primarily in the Delaware Basin. The Company also sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.
 Approximately 11 percent of the Company's year-end 2024 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 17, under "Future Net Cash Flows."

 Future Net Cash Flows
 Future cash inflows as of December 31, 2024, 2023, and 2022 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

 The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2024, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company's oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

 North
Sea

 2024

 Cash inflows
 $
 27,534
 $
 9,342
 $
 2,828
 $
 5,881
 $
 45,585

 Production costs
 ( 9,665)
 ( 1,716)
 ( 1,399)
 ( 1,436)
 ( 14,216)

 Development costs
 ( 4,124)
 ( 1,517)
 ( 2,538)
 ( 1,096)
 ( 9,275)

 Income tax expense
 ( 921)
 ( 1,923)
 ( 822)
 ( 3,581)

 Net cash flows
 12,824
 4,186
 ( 1,024)
 2,527
 18,513

 10 percent discount rate
 ( 4,317)
 ( 872)
 ( 2,280)
 ( 6,934)

 Discounted future net cash flows(2)

 $
 8,507
 $
 3,314
 $
 ( 489)
 $
 $
 11,579

 2023

 Cash inflows
 $
 21,417
 $
 9,921
 $
 5,761
 $
 —
 $
 37,099

 Production costs
 ( 8,328)
 ( 1,690)
 ( 2,773)
 —
 ( 12,791)

 Development costs
 ( 2,238)
 ( 1,235)
 ( 2,461)
 —
 ( 5,934)

 Income tax expense
 ( 949)
 ( 2,222)
 ( 946)
 —
 ( 4,117)

 Net cash flows
 9,902
 4,774
 ( 419)
 —
 14,257

 10 percent discount rate
 ( 3,749)
 ( 943)
 —
 ( 4,216)

 Discounted future net cash flows(2)

 $
 6,153
 $
 3,831
 $
 $
 —
 $
 10,041

 2022

 Cash inflows
 $
 31,577
 $
 12,819
 $
 10,147
 $
 —
 $
 54,543

 Production costs
 ( 10,763)
 ( 2,086)
 ( 3,241)
 —
 ( 16,090)

 Development costs
 ( 1,733)
 ( 1,471)
 ( 2,297)
 —
 ( 5,501)

 Income tax expense
 ( 1,575)
 ( 2,729)
 ( 2,631)
 —
 ( 6,935)

 Net cash flows
 17,506
 6,533
 1,978
 —
 26,017

 10 percent discount rate
 ( 6,811)
 ( 1,400)
 ( 204)
 —
 ( 8,415)

 Discounted future net cash flows(2)

 $
 10,695
 $
 5,133
 $
 1,774
 $
 —
 $
 17,602

 (1)Includes discounted future net cash flows of approximately $ 1.1 billion, $ 1.3 billion, and $ 1.7 billion as of December 31, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.
 (2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $ 14.4 billion, $ 13.6 billion, and $ 22.6 billion as of December 31, 2024, 2023, and 2022, respectively.

 The following table sets forth the principal sources of change in the discounted future net cash flows:

 2024
 2023
 2022

 Sales, net of production costs
 $
 ( 5,806)
 $
 ( 5,408)
 $
 ( 7,131)

 Net change in prices and production costs
 ( 7,089)
 8,690

 Discoveries and improved recovery, net of related costs
 3,557
 1,869
 1,142

 Change in future development costs
 ( 695)
 ( 413)
 ( 343)

 Previously estimated development costs incurred during the period

 Revision of quantities
 ( 428)
 ( 262)
 2,646

 4,166

 Accretion of discount
 1,357
 2,260
 1,489

 Change in income taxes
 1,467
 ( 2,467)

 ( 1,865)
 ( 18)
 ( 363)

 Change in production rates and other
 ( 547)
 ( 793)
 ( 1)

 $
 1,538
 $
 ( 7,561)
 $
 5,242