MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
PART III
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
FORWARD-LOOKING STATEMENTS AND 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, 2025, 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,” “target,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “predict,” “prospect,” “should,” “would,” or similar terminology or the negative of these terms, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:
• changes in local, regional, national, and international economic conditions;
• 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, armed conflicts, 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;
• asset retirement and decommissioning obligations, including changes to applicable regulatory and industry standards, the timing of related activities, and potential obligations to decommission previously owned assets;
• currency exchange rates;
• weather conditions;
• inflation rates;
• the impact of changes in tax legislation;
• the impact of international or domestic trade policy changes, including tariffs, import/export controls, and sanctions;
• 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;
• liabilities, injunctive relief, corrective actions, or other adverse outcomes resulting from pending or future litigation, governmental investigations, regulatory proceedings, or alleged violations of laws, regulations, permits, or contractual obligations;
• market-related risks, such as general credit, liquidity, and interest-rate risks;
• the ability to retain and hire key personnel;
• property acquisitions or divestitures;
• the integration of acquisitions;
• other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in 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.
References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.
PART I
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 makes available, free of charge on its website at www.apacorp.com , its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after they are filed with, or furnished to, the SEC. The Company’s filings are also available at www.sec.gov . Information contained on, or accessible through, 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, while offering global exploration opportunities. 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 is currently progressing with an oil field development offshore Suriname targeting first production in 2028.
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. Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. Despite these uncertainties, the Company is focused on its longer-term objectives: (1) to remain committed to providing affordable, reliable, and responsibly produced energy; (2) to deliver top operational performance across safety, environmental responsibility, execution, and risk management measures; (3) to maintain financial discipline by managing costs, protecting 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 (4) to build and grow a diverse and balanced high-quality portfolio with scale through acquisitions, exploration, and organic opportunities.
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.
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 was able to quickly advance on 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 complemented and enhanced APA’s asset base in the Permian Basin and its inventory of high quality, short-cycle opportunities.
• Throughout the remainder of 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.
• During 2025, APA completed the sale of certain non-core assets and leasehold in the Permian Basin, reflecting a full exit from New Mexico. Final proceeds of $571 million were primarily used for debt reduction. Combined with the Callon transaction, the Company believes its acreage position and drilling opportunities are better streamlined for longer-term growth.
For a more in-depth discussion of the Company’s 2025 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 Company’s exploration and production operations and activities by geographic region.
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, Alaska, 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 2025 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.
Production
Percentage
of Total
Production
Production
Revenue
Year-End
Estimated
Proved
Reserves
Percentage
of Total
Estimated
Proved
Reserves
Gross
Wells
Drilled
Gross
Productive
Wells
Drilled
(In MMboe)
(In millions)
(In MMboe)
United States
Egypt (1)
North Sea (2)
Suriname
Total
(1) The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 23 percent of 2025 production and accounted for 12 percent of year-end 2025 estimated proved reserves.
(2) Sales volumes from the Company’s North Sea assets for 2025 were 11.4 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings.
United States
In 2025, the Company’s U.S. oil and gas operations contributed approximately 62 percent of production, 53 percent of oil and gas revenues, and 74 percent of estimated year-end proved reserves. APA has access to significant liquid hydrocarbons across its 2.6 million gross acres (1.3 million net acres) in the U.S..
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 Spraberry, Bone Spring, Wolfcamp, Barnett, and Woodford. The Company operates approximately 4,000 gross oil and gas wells across its acreage, with additional interests in approximately 700 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:
• Permian Basin The Permian Basin is a foundational asset for APA, providing the Company’s largest source of production and cash flow. Over the past two years, the Company has progressed on high-grading its scale of operations and localized knowledge through the Callon acquisition and exit from non-core holdings in the conventional Central Basin Platform and positions in New Mexico. This concentrates APA’s position in a few key areas that enable economies of scale in operations and provides significant flexibility in pacing of developmental and appraisal activity.
In addition, the Company has been able to make significant strides in reducing drilling, completions, and equipping and facility costs by leveraging these synergies while refining its development approach to its asset base. Improvements in its cost structure has enabled the Company to drill more wells on tighter and denser spacing and to moderate completion intensity.
Key assets in the Permian Basin include:
• Midland Basin APA holds approximately 406,000 gross acres (288,000 net acres) in the Midland Basin in West Texas. During 2025, the Company primarily targeted oil plays in the Spraberry and Wolfcamp shale formations, drilling 106 gross development wells in this basin with a 100 percent success rate.
• Delaware Basin APA holds approximately 217,000 gross acres (166,000 net acres) in the Delaware Basin of West Texas. During 2025, the Company drilled 84 gross development wells in this basin with a 100 percent success rate, primarily targeting the Bone Spring and Wolfcamp formations. Also during 2025, the Company divested certain of its non-core producing properties located in New Mexico.
• Legacy Assets APA holds approximately 1.7 million gross acres (0.7 million net acres) in legacy properties, of which approximately 513,000 gross acres are in the offshore waters of the Gulf of America. 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. During 2025, the Company participated in the drilling of 7 gross development wells in this area with a 100 percent success rate.
• New Venture Assets APA holds approximately 325,000 gross acres (163,000 net acres) of undeveloped acreage on the North Slope of Alaska. During 2025, the Company and its partners announced preliminary results of an exploratory well in Alaska, confirming the successful discovery of a reservoir. A successful flow test of the well was announced in 2025, with the well averaging 2,700 b/d during the final flow period. The Company continues to evaluate data from the well, and further appraisal drilling will determine the ultimate size of the discovery.
The Company is committed to maintaining a safe and efficient level of activity as part of its planned capital investment program. For 2026, 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, subject to prevailing commodity prices. 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 152 Bcf of natural gas per year for the period from 2026 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, an average of 1.8 MMbbls of crude oil per year for the period from 2026 through 2028, and de minimis crude oil volumes in the year 2029, in each case, at variable, domestic and/or international, market-based pricing.
In order 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.
International
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 2025, the Company held 7.5 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 76 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 31 percent of 2025 production and 17 percent of 2025 year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 23 percent of 2025 production and 12 percent of 2025 year-end estimated proved reserves.
In 2025, the Company drilled 45 gross development and 53 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.
During 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations.
North Sea The Company has interests in approximately 176,000 gross acres in the U.K. North Sea. These assets contributed 7 percent of the Company’s 2025 production and approximately 2 percent of year-end 2025 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. In 2023, the Company suspended all new drilling activity in the North Sea. During 2024, the Company performed an 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 that expected returns did not economically support making investments required under the combined impact of the regulations and expects to 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 In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC pursuant to a gas sales agreement that establishes pricing based on a minimum realized price of $2.65 per MMBtu, with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement, which was effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil. In the periods prior to the current agreement, the natural gas production in Egypt was primarily sold to EGPC at an industry-pricing formula of $2.65 per MMBtu. 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.
Other International
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 exercised its right to participate in the GranMorgu development and production for a 20 percent share. 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 continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.
Drilling Statistics
Worldwide in 2025, APA drilled or participated in drilling 295 gross wells, with 268 wells (91 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 the year, at year-end 2025, a number of wells had not yet reached completion: 103 gross (97.8 net) in the U.S., 25 gross (25.0 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
United States
Egypt
Total
United States
Egypt
Total
United States
Egypt
North Sea
Other International
Total
(1) No proved undeveloped reserves were included in reserves as of year-end 2024 for the 2.0 net dry development wells drilled in 2025. No proved undeveloped reserves were included in reserves as of year-end 2023 for the 2.0 net dry development wells drilled in 2024.
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, 2025, is set forth below:
Oil
Gas
Total
Gross
Net
Gross
Net
Gross
Net
United States
Egypt
North Sea
Total
Domestic
Foreign
Total
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:
Production
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)
United States
Egypt (1)
North Sea (2)
Total
United States
Egypt (1)
North Sea (2)
Total
United States
Egypt (1)
North Sea (2)
Total
(1) Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
(2) Sales volumes from the Company’s North Sea assets for 2025 , 2024, and 2023 were 11.4 MMboe, 12.4 MMboe, and 16.6 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, 2025:
Undeveloped Acreage
Developed Acreage
Gross Acres
Net Acres
Gross Acres
Net Acres
(In thousands)
United States
Egypt
North Sea
Suriname
Other International
Total
As of December 31, 2025, the Company held approximately 5,000 net undeveloped acres in the U.S. that are scheduled to expire by year-end 2026 if production is not established or the Company takes no action to extend the terms. Nearly all of the Company’s U.S. acreage expiring in 2026 is in the Delaware Basin. The Company also held approximately 1,000 and 7,000 net undeveloped acres on its U.S. onshore acreage set to expire by year-end 2027 and 2028, respectively. As of December 31, 2025, approximately 81 percent of the U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights. The Company also has approximately 84,000 and 22,000 net undeveloped acres in Alaska set to expire by year-end 2027 and 2028, respectively, if no extension is granted.
During 2025, the Government of Egypt awarded the Company an additional two million net undeveloped exploration acres in the Western Desert for a term of five years, expanding on the Company’s existing position in Egypt. The Company also holds undeveloped exploration acreage that was consolidated and extended in 2021 following ratification of the MCA with EGPC. The merged exploration acreage is scheduled to expire in 2026. The Company intends to pursue extensions of this acreage and may seek access to additional concession areas where it believes exploration potential exists. However, there can be no assurance that any such extensions or new access rights will be obtained on commercially acceptable terms, or at all, as these actions are subject to governmental approvals. No oil and gas reserves were recorded on undeveloped acreage set to expire.
The Company held approximately six million net undeveloped acres as of December 31, 2025, in other international 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.
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, 2025, based on average commodity prices in effect on the first day of each month in 2025, 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:
United States
Egypt (1)
North Sea
Total
Proved Undeveloped:
United States
Egypt (1)
Suriname
Total
Total Proved
(1) Includes total proved developed and total proved undeveloped reserves of 55 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
As of December 31, 2025, the Company had total estimated proved reserves of 509 MMbbls of crude oil, 240 MMbbls of NGLs, and 1.8 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.1 billion boe, of which liquids represent approximately 71 percent. As of December 31, 2025, the Company’s proved developed reserves totaled 734 MMboe and estimated proved undeveloped (PUD) reserves totaled 322 MMboe, or approximately 30 percent of worldwide total proved reserves. APA has elected not to disclose probable or possible reserves in this filing. The Company had one field that contained 15 percent or more of its total proved reserves for the year ended December 31, 2025. The Company had no fields that contained 15 percent or more of its total proved reserves for the years ended December 31, 2024 and 2023.
During 2025, the Company added approximately 100 MMboe from extensions, discoveries, and other additions. The Company recorded 72 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin primarily targeting the Spraberry, Bone Spring, and Wolfcamp producing horizons. The Company’s Egypt operations contributed 28 MMboe of exploration and development adds from onshore exploration and appraisal.
The Company realized combined upward revision of previously estimated reserves of 175 MMboe. Upward revisions related to pricing and interest totaled 37 MMboe, driven primarily by an increase in Permian Basin gas pricing. Engineering and well performance adjustments totaled 138 MMboe in the U.S. and Egypt. Upward revisions of 100 MMboe in the U.S. is related to changes to development plans and updates due to reservoir performance. Egypt realized positive revisions of 38 MMboe from gas infrastructure optimization and improved recovery projects.
Divestitures during 2025 of non-core producing properties in the U.S. reduced estimated proved reserves by approximately 19 MMboe.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2025, 2024, and 2023, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—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 322 MMboe as of December 31, 2025, increased by 22 MMboe from 300 MMboe of PUD reserves reported at year-end 2024. During 2025, the Company converted 76 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 66 MMboe, with the remaining 10 MMboe in its international areas. The Company disposed of 2 MMboe related to PUD reserves divested during 2025. The Company added 62 MMboe of new PUD reserves through extensions. The Company also revised PUD reserves upward 41 MMboe as a result of updates to field development plans. Other downward revisions include 2 MMboe associated with interest changes and 1 MMboe associated with product prices.
During 2025, a total of approximately $546 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 2025, the Company spent approximately $494 million on PUD reserve development activity in the U.S. and $52 million in Egypt. Additionally, the Company spent approximately $256 million in development and facility capital as part of the Suriname development during 2025. As of December 31, 2025, 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 group of experienced reservoir engineers who 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. 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. Reserves are reviewed internally with senior management and presented to APA’s Board of Directors in summary form on an annual basis.
APA’s Director of Reserves is the person primarily responsible for overseeing the Company’s reserves estimation and reporting process. 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 2025, the properties selected for all countries represented 87 percent of the total future net cash flows discounted at 10 percent. These properties accounted for 80 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 2025, 2024, and 2023 were:
Estimated proved reserves values
Estimated proved reserves volumes:
United States
Egypt
North Sea
Suriname
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.
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 2025, sales to EGPC in Egypt accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2024 and 2023, sales to EGPC accounted for approximately 17 percent and 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’s ability to execute its strategy depends on attracting, developing, and retaining a skilled workforce. The Company focuses on employee health and safety, total rewards, development opportunities and community partnerships to support employee experience and performance.
As of December 31, 2025, APA employed approximately 1,791 full-time equivalent employees:
Employees
United States
United Kingdom
Egypt
Suriname
France
Total employees
Oversight and Management
The Management Development and Compensation (MD&C) Committee and/or the full Board of Directors receive regular reports on human capital matters. The MD&C Committee also oversees compensation programs, leadership development, and succession planning. These activities support APA’s core values, which include health and safety, investment in the workforce, environmental responsibility, continuous improvement, and ethical conduct.
Equal Opportunity Employer
APA is an equal opportunity employer and prohibits discrimination and harassment. 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.
APA also maintains resources to support an inclusive work environment where employees are valued and able to thrive.
Talent
APA’s talent strategy integrates recruitment and development to support organizational capability and leadership development and ingenuity.
Recruitment uses technology and data-driven insights to identify talent globally and uses referrals and feedback to strengthen local sourcing.
APA also engages with educational institutions, industry networks, and professional organizations to access emerging talent and build relationships with industry professionals.
Beyond recruitment, the Company invests in talent development initiatives designed to build capability, strengthen leadership effectiveness, and reinforce a high-performance culture. These initiatives include continuous learning opportunities, skill enhancement programs, mentorship frameworks, and leadership development programs.
In 2025, APA emphasized leadership and culture initiatives. Senior leadership focused on strategic priorities and development of a strong corporate culture that reinforces shared values, collaboration, accountability, and continuous improvement.
Training and Development
Employee development is supported through training, performance management, and continuous feedback using in-person and virtual delivery.
2025 highlights included:
• Technical Excellence Initiative: Launched an initial framework defining technical capability expectations and progression pathways across critical disciplines with broader implementation planned for 2026.
• Individual Development Plan (IDP): Began implementing an IDP framework to identify development priorities, align learning activities with career aspirations, and track progress over time.
• Performance Management: Continued strengthening the program with increased emphasis on ongoing feedback and development conversations.
• Learning access: Expanded on-demand learning through multiple online learning platforms offering technical, leadership, and business acumen content.
• Succession planning: Remained a critical component of APA’s talent strategy including identifying key roles, assessing readiness, and targeted development actions.
• Additional development and training opportunities offered during the year included:
• Third-party online and in-person training programs;
• Ongoing education for people leaders aligned to leadership competencies;
• Leadership and personal development coaching by line managers;
• Annual cybersecurity training;
• Annual compliance training including antitrust, bribery, corruption, and the APA Code of Conduct; and
• Mandatory health, safety, and environmental training for field and offshore employees.
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, annual long-term incentive grants are provided to eligible employees under APA’s long-term incentive 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.
Environment, Health and Safety (EH&S)
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 focuses on incident mitigation, driving safety, and environmental stewardship 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)
35% below target of 0.20
Severe Incident Rate (SIR) (2)
100% below target of 0.010
US Flaring Intensity (3)
16% below target of 1.0
(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) 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.
(3) Flaring Intensity: The volume of gas flared per volume of gas produced expressed as a percent.
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 is focused on 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 2025, the Company’s environmental stewardship initiatives included grants of more than 16,000 trees to community partners in the U.S. and U.K. through the Apache Corporation Tree Grant Program. The Company also continued its partnership with the Texas Wildlife Association Foundation to support environmental education programs and provided multi-year support to the Pecos Watershed Conservation Initiative, an alliance of seven energy companies, in partnership with the National Fish and Wildlife Foundation, focused on restoring and protecting natural grasslands and habitats within the greater Trans-Pecos region.
• Access to Energy: In 2025, the Company continued to support access to affordable, reliable energy through its partnership with Switch Energy Alliance, a Houston-based nonprofit focused on energy education, workforce development, and informed energy dialogue. The Company’s support helped advance Switch Energy Alliance’s programming that increases understanding of energy systems, energy access challenges, and the role of diverse energy solutions in supporting economic development and quality of life in energy-impacted communities.
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 2025, 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 10—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, standards for drilling, completing, and equipping oil and gas wells, standards for plugging, abandonment, decommissioning, and site restoration activities, 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 Matters,” “Risks Related to Climate Change, Energy Transition, and ESG Matters,” and “Risks Related to International Operations” in Item 1A―Risk Factors .
Regulatory requirements affecting the Company’s operations are frequently proposed, revised, delayed, challenged in litigation, enjoined or stayed by courts, withdrawn by agencies, or modified through subsequent administrative and legislative actions, including in the U.S. through the use of the Congressional Review Act. As a result, the scope, timing, and practical impact of regulatory change can be difficult to predict and may change rapidly, including across election cycles and as agencies adjust enforcement priorities.
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, or to assess a charge on methane emissions in the oil and gas industry.
In the U.S., regulatory activity related to methane and GHG emissions has included, and is expected to continue to include, changes to monitoring, reporting, leak detection and repair, flaring, and emissions control requirements applicable to oil and gas operations. For example, the U.S. Environmental Protection Agency (EPA) has adopted and/or proposed revisions to methane and volatile organic compound standards for new and existing sources in the oil and gas sector, and the EPA’s Greenhouse Gas Reporting Program has been subject to ongoing rulemaking activity, including recent activity to reduce the
reporting for petroleum and natural gas systems. In addition, the Inflation Reduction Act of 2022 established a Methane Emissions Reduction Program that contemplates the assessment of a “waste emissions charge” for certain methane emissions from facilities already subject to reporting requirements, which has been delayed until 2034. Additionally, on February 12, 2026, the EPA finalized a rescission of the 2009 Endangerment Finding for GHGs under Section 202(a) of the Clean Air Act; this action, and any resulting legal challenges or subsequent governmental actions, could affect the broader regulatory landscape and related compliance expectations. Further, these developments, and related state implementation actions, could increase compliance costs, require additional capital expenditures, and result in operational constraints, including with respect to measurement and monitoring, equipment retrofits, and flaring practices.
Additionally, various states and groups of states have adopted, and others continue to consider 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, including as a result of recent federal actions to reconsider and rescind certain GHG-related regulatory determinations and standards, which may create regulatory uncertainty and result in increased state-level and litigation activity. Certain jurisdictions have also adopted or proposed climate-related disclosure or supply-chain reporting regimes, which could increase compliance and reporting costs and, depending on applicability, require additional processes, controls, and assurance.
Endangered or Protected Species
The Company’s operations in its operating areas could be adversely impacted by seasonal, periodic, or permanent restrictions or limitations relating to oil and gas operations to protect certain wildlife with habitats or migratory paths within such operational areas. Such restrictions or limitations can include, without limitation, prohibited drilling and development activity in certain areas or restricted activities during specific seasons or the employment of costly mitigation measures. New designations of previously unprotected species as threatened, endangered, or protected species could cause the Company to incur significant additional costs to implement required protective measures or could limit the Company’s ability to effectively and efficiently develop and produce reserves.
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 expect that these requirements will affect it differently, to any material degree, than other companies in the oil and gas industry; however, the Company’s compliance costs and operational constraints may increase as requirements evolve.
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 currently expect that compliance with existing environmental laws and regulations will have a material adverse impact on its capital expenditures, earnings, or competitive position, though future regulatory changes could increase the Company’s costs and capital requirements.
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 COMMODITY PRICES, DEMAND, AND PRODUCTION
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 2025 ranged from a high of $80.73 per barrel to a low of $55.44 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2025 ranged from a high of $9.86 per MMBtu to a low of $2.65 per MMBtu.
The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company’s control, including:
• demand, which fluctuates with changes in market and economic conditions;
• 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;
• 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;
• the timing, scope, implementation, and potential judicial review of energy transition and climate-related policies and regulations (such as methane fees, emissions reporting requirements, carbon pricing mechanisms, and other climate-related measures);
• 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 and return capital to its shareholders. 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, meet volume commitments under transportation services agreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity changes, the inability to procure and resell volumes economically, various transportation interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.
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, financial distress, or insolvency of third-party providers that limit the ability of such 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. As additional gas pipeline takeaway capacity in the Permian Basin comes online, the spread between Permian and Gulf Coast gas prices may compress, which would reduce the Company’s gain on third-party oil and gas purchases and sales.
The Company’s commodity price and other risk management and trading activities, including interest rate and foreign exchange hedging, and contracts priced in foreign currencies may prevent it from benefiting fully from price increases and market movements 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. Similarly, to the extent the Company enters into derivative contracts to manage exposure to interest rate or foreign exchange risk or enters into contracts priced in a foreign currency, it may be limited in its ability to benefit from favorable movements in interest rates or currency exchange rates or may incur additional expense converting to a foreign currency to fund contractual obligations. 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. In addition, because the Company does not apply hedge accounting to its derivative instruments, changes in the fair value of derivatives are recognized in current-period earnings, which may introduce earnings volatility even when the underlying exposure is intended to be economically hedged.
Public health events, workforce disruptions, or similar global or regional events have previously and may in the future adversely impact the Company’s business, financial condition, and results of operations.
Public health events, including related workforce availability constraints, travel restrictions, supply chain disruptions, or government-mandated operational limitations, have previously adversely impacted and may from time to time in the future adversely impact the global economy, cause significant volatility in financial markets, and reduce 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.
RISKS RELATED TO OPERATIONS, SAFETY, AND EXPLORATION 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.
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 wells or development projects have failed to meet expected economic thresholds because of drilling results, cost inflation, commodity price volatility, revised development plans, demand for oil, natural gas, and NGLs, or other information, and in such cases, the Company may elect not to pursue or complete those activities. 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.
Frontier exploration and development projects, including those in new or re-entered jurisdictions, involve heightened operational, regulatory, and execution risks that could adversely affect the Company’s results of operations and financial condition.
The Company’s exploration and development portfolio includes higher‑risk frontier opportunities, including in Alaska and offshore Suriname and Uruguay, which may involve extended timelines, complex permitting and stakeholder processes, logistical constraints, and heightened regulatory scrutiny. Operations in new countries or areas where the Company has limited recent operating history may also require the establishment or reestablishment of local relationships, workforce and supply chains, regulatory familiarity, and infrastructure, and may expose the Company to unfamiliar legal frameworks, fiscal regimes, community engagement expectations, and political dynamics.
Delays or adverse outcomes in permitting, litigation (including parties seeking legal or equitable relief to prevent or otherwise limit exploration activities, such as for the acquisition of seismic data or for drilling operations), appraisal drilling, or commercial development decisions could result in the deferral, impairment, or partial or complete loss of anticipated value of exploration, development, and production assets and the recognition of additional exploration expense. In addition, unanticipated technical, geological, operational, or regulatory challenges in such jurisdictions could increase capital requirements, extend project timelines, or adversely affect the commercial viability of these projects. These risks may be amplified in jurisdictions where regulatory regimes are evolving or where litigation or public opposition to offshore exploration activities has increased.
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 may be required to expend further resources to protect its digital systems and data 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. See I tem 1C — Cy bers ecurity for additional information regarding the Company’s cybersecurity risk management and governance.
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 approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, cost inflation, availability, manufacturing, and delivery schedules of critical vessels and equipment, customs and logistics, cash-call timing or funding shortfalls, 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, ESTIMATES, AND LEASEHOLDS
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, consistent with applicable SEC pricing and reporting rules. Therefore, changes in future commodity prices or in development plans can materially impact reported reserves. 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 sizable 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 AND JOINT VENTURES
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 10—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, including state-owned or government-controlled entities. 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, including priorities set by governmental or state-owned counterparties, or that are influenced by governmental policy, fiscal priorities, or broader economic or social conditions, which may affect decision making, capital allocation, payment timing, or operational approvals. 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, LIQUIDITY, AND TAX MATTERS
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. 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 or if financial institutions, investors, or insurers limit exposure to oil and gas companies or modify underwriting standards in response to climate-related or other policy developments. 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.
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 9—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 9—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 MATTERS
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 hydraulic fracturing, and future regulatory approaches may vary significantly across jurisdictions and over time. Such regulations may 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 (prior to recent law changes) assessed 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 enacted in 2025. Such changes, effective for the period of November 1, 2024, through March 31, 2030, increased the levy to 38 percent, removed certain allowances, and extended the EPL period. During 2024, the Company performed an economic assessment of its North Sea assets in light of the significant tax levies, along with several new regulatory guidelines and obligations surrounding modernization of aging infrastructure, and determined that expected returns did not economically support making investments required under the combined impact of the regulations and now expects to cease production at its facilities in the North Sea prior to 2030.
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.
Changes to laws, regulations, guidance, and industry standards, or interpretations thereof, or higher than anticipated costs for asset retirement and decommissioning obligations could adversely affect the Company’s results of operations and cash flows.
The Company is subject to extensive requirements governing the plugging, abandonment, and decommissioning of wells, facilities, sites, and related infrastructure. The cost, timing, and other aspects of these activities are uncertain and may be materially affected by changes in laws, regulations, guidance, or industry standards and by changes in the Company’s understanding and implementation of the decommissioning tasks and activities required, including the complexity thereof. There is an increased focus on decommissioning requirements, financial assurance, and environmental remediation in countries where the Company operates. New or revised rules, guidance, interpretations, or contractual frameworks, or the administration thereof, could expand the scope of required activities, alter timelines, or increase financial guarantees or other forms of financial security obligations, resulting in higher costs and greater cash flow demands.
For the Company’s decommissioning obligations in the North Sea, the regulatory framework and the standards applicable to removal and seabed clearance may continue to evolve. For example, on September 5, 2025, the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) opened a consultation on draft supplementary guidance on the methodology for considering derogations for removal of certain subsea structures under OSPAR Decision 98/3. The consultation materials emphasize a policy objective of achieving a “clear seabed,” a presumption in favor of removal, and an expectation of a reduction in derogations, with a revised methodology that evaluates full removal against certain criteria before a derogation proposal may proceed. While the consultation period ended on November 14, 2025, and the proposal has not been finalized, if ultimately adopted and implemented, such changes, together with any related changes in regulatory expectations or enforcement, could require more extensive removal, seabed clearance, monitoring, or documentation than the Company currently anticipates, materially increase the Company’s estimated decommissioning obligations and costs in the North Sea, and adversely affect the Company’s cash flows and results of operations.
Additionally, inflation, supply constraints, and limited contractor and vessel availability have raised decommissioning costs in recent periods. If decommissioning spending materially exceeds current estimates or the Company’s joint venture partners, current owners of the Company’s previous assets, or other third parties (including governments) responsible for funding or reimbursing decommissioning costs fail to meet their obligations, the Company’s cash flows, capital resources, and liquidity could be adversely affected.
RISKS RELATED TO CLIMATE CHANGE, ENERGY TRANSITION, AND ESG MATTERS
The impacts of climate change, energy transition policies, and ESG-related initiatives could adversely affect the Company’s business, operating results, and financial condition.
Attention continues to be 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, have resulted 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.
Further 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.
Weather and climate may have a significant adverse impact on the Company’s revenues and production.
Demand for oil and natural gas is, 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.
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 previous discussion in the U.S. when the regulatory landscape at the federal level was more focused on these issues, regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs, to restrict or eliminate future emissions, or to assess a charge on methane emissions in the oil and gas industry. 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 biennial 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 sustainability reports. 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 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, appraisal, and development activities offshore Suriname, which involve long-cycle projects with significant capital requirements and are subject to host-government approvals and fiscal and contractual frameworks that may evolve over time. On a barrel equivalent basis, approximately 38 percent of the Company’s 2025 production was outside the U.S., and approximately 26 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2025, 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 laws and regulations;
• litigation, including as initiated by or otherwise involving non-governmental organizations;
• dependence on host-country approvals;
• local content requirements;
• vessel and equipment availability;
• import and export regulations;
• customs and port logistics;
• 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 or tribunals 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 or state-owned or government-controlled entities because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
In certain jurisdictions, governmental authorities may be exercised by multiple ministries, agencies, state-owned or government-controlled entities, or other governmental bodies with overlapping or evolving mandates. As a result, the Company may encounter inconsistent or shifting application of laws, regulations, contractual terms, or administrative requirements, including additional approvals, documentation requests, or procedural conditions. Compliance with such requirements may increase costs, delay operations, or affect project economics.
In addition, certain of the Company’s frontier exploration activities may be subject to legal or administrative challenges in host jurisdictions. For example, in Uruguay, legal actions have recently been filed seeking to enjoin offshore drilling activities and to prevent the acquisition of seismic data. Although a request for injunctive relief was denied by a local court in one case, the underlying litigation remains pending and may be appealed or otherwise continued. If such challenges were successful, they could delay or impede the Company’s exploration and appraisal activities in Uruguay, increase costs, or adversely affect the Company’s ability to advance or realize value from those assets.
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 or exploration opportunities 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, or to oil and gas operations generally. 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 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.
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, new or increased taxes, fees, or levies, limitations affecting the repatriation or transfer of funds, 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, previous deteriorations in the 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, and such declines may reoccur if conditions were to deteriorate again. If conditions were to deteriorate again 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 among the U.S. dollar, the British pound, and the Egyptian 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. For additional details, including discussion of foreign exchange contracts entered into by the Company, see the information set forth under “Foreign Currency Exchange Rate Risk” in Part II, Item 7A—Quantitative and Qualitative Disclosures About Market Risk .
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, 2025, 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 36 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 10—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.
PART II
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, 2026, was $26.41 per share. As of January 31, 2026, there were 353,251,476 shares of APA’s common stock outstanding held by approximately 3,500 stockholders of record and 282,000 beneficial owners.
The Company has paid cash dividends on its common stock for 61 consecutive years through December 31, 2025. 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 2026 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 2025.
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, 2025
February 1 to February 29, 2025
March 1 to March 31, 2025
April 1 to April 30, 2025
May 1 to May 31, 2025
June 1 to June 30, 2025
July 1 to July 31, 2025
August 1 to August 31, 2025
September 1 to September 30, 2025
October 1 to October 31, 2025
November 1 to November 30, 2025
December 1 to December 31, 2025
Total
(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, 2020, through December 31, 2025. 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 12/31/20 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
APA Corporation
S&P 500 Index
Dow Jones U.S. Exploration & Production Index
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 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 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, 2024 (filed with the SEC on February 28, 2025).
Overview
APA is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids (NGLs). The Company’s business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its consolidated subsidiaries.
APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.
Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies and disputes, and actions taken by foreign oil and gas producing nations, including OPEC+. Despite these uncertainties, the Company is focused on its longer-term objectives: (1) to remain committed to providing affordable, reliable, and responsibly produced energy; (2) to deliver top operational performance across safety, environmental responsibility, execution, and risk management measures; (3) to maintain financial discipline by managing costs, protecting 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 (4) to build and grow a diverse and balanced high-quality portfolio with scale through acquisitions, exploration, and organic opportunities.
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 price volatility and effectively manage its investment programs.
With increasing uncertainty around commodity prices during the first quarter of 2025, the Company announced a significant cost reduction initiative to drive sustainable cost savings for the long-term. This included reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices. The Company achieved $350 million in annualized savings across G&A, LOE, and capital as of year-end 2025. The Company expects $450 million of annualized savings by the end of 2026.
Additionally, 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 paid a quarterly dividend of $0.25 per share on its common stock during 2025.
• Beginning in the fourth quarter of 2021 and through the end of 2025, the Company has repurchased 98.2 million shares of the Company’s common stock. As of December 31, 2025, the Company had remaining authorization to repurchase up to 21.9 million shares under the Company’s share repurchase program.
Financial and Operational Highlights
During 2025, the Company reported net income attributable to common stock of $1.4 billion, or $3.99 per diluted share, compared to net income of $804 million, or $2.27 per diluted share, in 2024. The increase in net income during 2025 was primarily the result of by $1.1 billion of impairments recorded in 2024, which included oil and gas property impairments of $796 million in the North Sea and $315 million in the U.S. The Company also recorded lower operating expenses in 2025 compared to the prior-year period, the result of focused cost-reduction efforts undertaken in 2025.
The Company generated $4.5 billion of cash from operating activities in 2025, which was $925 million or 26 percent higher than 2024. APA’s higher operating cash flows for 2025 were primarily driven by the collection of outstanding receivables, lower overall expenses, and timing of other working capital items. The Company repurchased 12.9 million shares of its common stock for $280 million and paid $360 million in dividends to APA common stockholders during 2025. The Company ended the year with approximately $4.5 billion of debt, a reduction of approximately $1.6 billion from the end of 2024.
Key operational highlights for the year include:
United States
• Daily boe production from the Company’s U.S. assets, which increased 2 percent from 2024, accounted for 62 percent of the Company’s worldwide production during 2025. The Company averaged approximately seven drilling rigs in the U.S. during the year, including four rigs in the Midland Basin and three rigs in the Delaware Basin, and drilled and brought online 154 operated wells in 2025. The Company’s core Permian Basin development program continues to consistently attract the largest portion of capital investment.
• In the Permian Basin, the Company is currently operating five rigs, reflecting improved capital efficiency while sustaining the pace of wells brought online. The Company anticipates continuing this level of activity to deliver 2026 oil production consistent with the prior year. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending.
• The Company holds approximately 750,000 MMBtu/d of firm capacity on various pipelines. As of December 31, 2025, the Company had open basis swap contracts which purchased Waha and sold NYMEX Henry Hub on approximately one-third of its firm transport capacity for 2026, thereby locking in a significant portion of cash flows associated with its gas marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.
• During the first quarter of 2025, the Company and its partners announced preliminary results of an exploratory well in Alaska, confirming the successful discovery of a reservoir. A successful flow test of the well was announced in April, with the well averaging 2,700 b/d during the final flow period. The Company continues to evaluate the data from the well to determine next steps, and further appraisal drilling will determine the ultimate size of the discovery. The Company holds a 50 percent ownership interest in the project.
International
• During the fourth quarter of 2024, the Company entered into a new gas sales agreement with the Government of Egypt. Effective January 2025, substantially all of the Company’s natural gas production was sold to EGPC under the terms of this agreement. The agreement provides the Company with enhanced economic terms that support increased natural gas exploration and development activity and the potential addition of significant new drilling inventory with expected returns comparable to those of the Company’s oil program.
• In Egypt, the Company averaged 12 drilling rigs and drilled 71 new productive wells during 2025. During the same period, the Company averaged 19 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. The 2025 gross and net production from the Company’s Egypt assets decreased 2 percent and 6 percent, respectively, from 2024.
• During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The Government also helped facilitate significant payments in the third quarter of 2025, nearly eliminating past due receivables.
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:
• Sale of Non-core Permian Basin Properties During the second quarter of 2025, the Company completed the sale of all of its New Mexico Permian assets. The assets had a carrying value of $282 million and associated retirement obligation of $9 million, which were exchanged for total cash consideration of $571 million, inclusive of post-closing adjustments.
• Egypt Acreage Acquisition During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations.
• 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 included approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin.
• 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 2023, the Company sold a portion of its Kinetik Holdings Inc. (Kinetik) Class A Common Stock (Kinetik Shares) for cash proceeds of $228 million. During the first quarter of 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. On April 3, 2024, the Company’s designated director resigned from the 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:
For the Year Ended December 31,
$ Value
% Contribution
$ Value
% Contribution
$ Value
% Contribution
($ in millions)
Oil Revenues:
United States
Egypt (1)
North Sea
Total (1)
Natural Gas Revenues:
United States
Egypt (1)
North Sea
Total (1)
NGL Revenues:
United States
North Sea
Total (1)
Oil and Gas Revenues:
United States
Egypt (1)
North Sea
Total (1)
(1) Includes revenues attributable to a noncontrolling interest in Egypt.
Production
The following table presents production volumes by country:
For the Year Ended December 31,
Increase
(Decrease)
Increase
(Decrease)
Oil Volumes – b/d:
United States (5)
Egypt (3)(4)
North Sea
Total
Natural Gas Volumes – Mcf/d:
United States (5)
Egypt (3)(4)
North Sea
Total
NGL Volumes – b/d:
United States (5)
North Sea
Total
BOE per day: (1)
United States (5)
Egypt (3)(4)
North Sea (2)
Total
(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 31,168 boe/d, 33,954 boe/d, and 45,476 boe/d for 2025 , 2024, and 2023, 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:
Oil (b/d)
Natural Gas (Mcf/d)
(4) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
Oil (b/d)
Natural Gas (Mcf/d)
(5) Production volumes per day in the Company’s Wildfire field were as follows:
Oil (b/d)
Natural Gas (Mcf/d)
NGL (b/d)
Pricing
The following table presents pricing information by country:
For the Year Ended December 31,
Increase
(Decrease)
Increase
(Decrease)
Average Oil Price - Per barrel:
United States
Egypt
North Sea
Total
Average Natural Gas Price - Per Mcf:
United States
Egypt
North Sea
Total
Average NGL Price - Per barrel:
United States
North Sea
Total
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 2025 were down 14 percent compared to 2024, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2025 averaged $66.92 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 $1.02 per Mcf in 2025, a 44 percent increase from an average of $0.71 per Mcf in 2024.
• In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC pursuant to a gas sales agreement that establishes pricing based on a minimum realized price of $2.65 per MMBtu, with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement was effective beginning January 2025. In the periods prior to the current agreement, the natural gas production in Egypt was primarily sold to EGPC at an industry-pricing formula of $2.65 per MMBtu. Overall, the Company’s Egypt operations averaged $3.59 per Mcf in 2025, a 22 percent increase from an average of $2.94 per Mcf in 2024.
• 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 $12.03 per Mcf in 2025, a 11 percent increase from an average of $10.84 per Mcf in 2024.
NGL Prices The Company’s U.S. NGL production, which accounted for 98 percent of the Company’s total 2025 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 2025 totaled $5.8 billion, a $1.2 billion decrease from the 2024 total of $7.0 billion. A 14 percent decrease in average realized prices reduced 2025 revenues by $996 million compared to 2024, while a 3 percent lower average daily production decreased revenues by $161 million. Average daily production in 2025 was 237 Mb/d, with prices averaging $66.92 per barrel. Crude oil sales accounted for 80 percent of the Company’s 2025 oil and gas production revenues and 51 percent of its worldwide production.
The Company’s worldwide crude oil production decreased 6 Mb/d compared to 2024, primarily a result of the sale of non-core assets in the U.S. and natural production decline, mostly offset by drilling activity in the Permian Basin.
Natural Gas Revenues
Natural gas revenues for 2025 totaled $770 million, a $186 million increase from the 2024 total of $584 million. A 20 percent increase in average realized prices increased 2025 revenues by $118 million compared to 2024, while 10 percent higher average daily production increased revenues by $68 million. Average daily production in 2025 was 897 MMcf/d, with prices averaging $2.36 per Mcf. Natural gas sales accounted for 11 percent of the Company’s 2025 oil and gas production revenues and 32 percent of its worldwide production.
The Company’s worldwide natural gas production increased 82 MMcf/d compared to 2024, primarily a result of successful drilling activity in Egypt and the Permian Basin. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets in the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and operational downtime in the U.S.
NGL Revenues
NGL revenues for 2025 totaled $650 million, a $4 million increase from the 2024 total of $646 million. A 3 percent higher average daily production increased 2025 revenues by $22 million compared to 2024, while a 3 percent decrease in average realized prices decreased revenues by $18 million. Average daily production in 2025 was 78 Mb/d, with prices averaging $22.71 per barrel. NGL sales accounted for 9 percent of the Company’s 2025 oil and gas production revenues and 17 percent of its worldwide production.
The Company’s worldwide NGL production increased 2 Mb/d compared to 2024, primarily a result of increased drilling activity in the Permian Basin, offset by natural production decline, the sale of non-core assets in the U.S., and curtailment of volumes at Alpine High in response to extreme Waha basis differentials
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 $150 million for the year ended December 31, 2025 to $1.7 billion from $1.5 billion in 2024. Purchased oil and gas sales were partially offset by associated purchase costs of $1.1 billion and $1.0 billion for the years ended December 31, 2025 and 2024, respectively. The increase in purchased oil and gas sales was primarily driven by higher natural gas prices at various delivery locations.
Operating Expenses
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2025, 2024, and 2023. All operating expenses include costs attributable to a noncontrolling interest in Egypt.
For the Year Ended December 31,
(In millions)
Lease operating expenses
Gathering, processing, and transmission
Purchased oil and gas costs
Taxes other than income
Exploration
General and administrative
Transaction, reorganization, and separation
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Gathering, processing, and transmission assets
Other assets
Asset retirement obligation accretion
Impairments
Financing costs, net
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 51 percent of the Company’s total 2025 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
During 2025, LOE decreased $186 million, or 11 percent, compared to 2024. On a per-boe basis, LOE decreased $1.30, or 13 percent, compared to 2024, from $10.16 per boe to $8.86 per boe. The decrease in absolute costs was primarily driven by lower workover activity, continued cost reduction efforts in all operating areas, and the sale of non-core assets in the Permian Basin. This decrease was partially offset by a full year of operating costs associated with the Callon transaction.
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. The following table presents a summary of these expenses:
For the Year Ended December 31,
(In millions)
Third-party processing and transmission costs
Midstream service costs – Kinetik
Upstream processing and transmission costs
Total Gathering, processing, and transmission
GPT costs decreased $8 million compared to 2024, primarily the result of decreased oil production volumes in the U.S. and lower average transportation rates.
Purchased Oil and Gas Costs
Purchased oil and gas costs increased $23 million for the year ended December 31, 2025, to $1.1 billion from $1.0 billion in 2024. The increase is primarily driven by gas volumes purchased at higher prices during 2025 compared to the prior-year period coupled with activity associated with the Callon acquisition.
Taxes Other Than Incom e
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 decreased $41 million compared to 2024, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes.
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:
For the Year Ended December 31,
(In millions)
Unproved leasehold impairments
Dry hole expenses
Geological and geophysical expenses
Exploration overhead and other
Total Exploration
Exploration expenses decreased $182 million compared to 2024, primarily the result of higher dry hole expenses in Suriname and Alaska and unproved leasehold impairments during 2024. Dry hole expenses in 2025 primarily relate to increased exploration drilling in Egypt.
General and Administrative (G&A) Expenses
G&A expenses in 2025 decreased $22 million compared to 2024. Focused cost-reduction efforts on personnel and other overhead expenses drove a decrease of $67 million, which more than offset higher stock compensation expense of $45 million primarily driven from an increase in the Company’s stock price during 2025. For additional information on the Company’s stock compensation, refer to Note 12—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 decreased $66 million compared to 2024, primarily a result of transaction costs related to the Callon acquisition during 2024, partially offset by employee separations and other cost-saving reorganization initiatives during 2025.
Depreciation, Depletion and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2025 increased $40 million compared to 2024. The Company’s oil and gas property DD&A rate remained relatively flat in 2025 compared to 2024, from $13.44 per boe to $13.41 per boe, mainly the result of negative gas price-related reserve revisions in the U.S. Permian Basin offset by non-core asset divestitures.
Impairments
During 2025, the Company recorded $44 million of impairments, which included $18 million of non-operated proved oil and gas property in Egypt, approximately $18 million related to the sale of an office building in the U.S., a $1 million impairment for GPT facilities in Egypt, and $7 million of inventory impairments in the North Sea. 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. held-for-sale, and $18 million of inventory impairments in the North Sea and U.S.
Financing Costs, Net
Financing costs incurred during 2025, 2024, and 2023 comprised the following:
For the Year Ended December 31,
(In millions)
Interest expense
Amortization of debt issuance costs
Capitalized interest
Gain on extinguishment of debt
Interest income
Total Financing costs, net
Net financing costs during 2025 decreased $254 million compared to 2024, primarily driven by gains on extinguishment of debt from the Company’s cash tender purchases in early 2025 and lower overall interest expense from lower outstanding long-term debt balances.
Provision for Income Taxes
For the year ended December 31, 2025, income tax expense increased by $682 million to $1.1 billion from $417 million in 2024. The Company’s 2025 and 2024 effective income tax rates were primarily impacted by taxes related to foreign operations.
On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy), increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included further amendments to the Energy Profits Levy, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded tax expense of $78 million and $174 million related to the change in tax law in 2025 and 2023, 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 2025, the Company recorded a current tax benefit of $71 million related to the 2024 return-to-accrual adjustment, with an offsetting deferred tax expense of the same amount for the change in CAMT credits.
On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. OBBBA did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the law change resulted in a current tax benefit of $42 million fully offset by a deferred tax expense of the same amount.
On September 30, 2025, the Internal Revenue Service issued further interim guidance on CAMT. Among other changes, the guidance provided for a reduction to CAMT related to net operating loss utilization for regular federal income tax purposes. This guidance did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the guidance resulted in a current tax benefit of $72 million, fully offset by a deferred tax expense of the same amount.
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 9—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 state 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 is focused on its longer-term objectives: (1) to remain committed to providing affordable, reliable, and responsibly produced energy; (2) to deliver top operational performance across safety, environmental responsibility, execution, and risk management measures; (3) to maintain financial discipline by managing costs, protecting 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 (4) to build and grow a diverse and balanced high-quality portfolio with scale through acquisitions, exploration, and organic opportunities.
In 2026, the Company plans to invest approximately $2.1 billion in upstream capital investment. The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its planned capital investment program. For 2026, 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, subject to prevailing commodity prices. 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.
In the Permian Basin, the Company is currently operating five rigs, reflecting improved capital efficiency. The Company anticipates continuing this level of activity to deliver consistent year-over-year oil production. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending. The Company is planning a 12-rig program in Egypt, with five to six rigs dedicated to gas exploration. This activity set translates to a combined development capital budget for the Permian Basin and Egypt of approximately $1.8 billion. In addition, the Company will invest approximately $70 million for exploration in Alaska and Suriname and $230 million for Suriname development.
This investment profile underscores the progress the Company has made on capital efficiency over the course of 2025. 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.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2025, 2024, and 2023, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—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:
For the Year Ended December 31,
(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities
Fixed-rate debt borrowings
Proceeds from asset divestitures
Proceeds from term loan facility
Proceeds from sale of Kinetik shares
Total Sources of Cash and Cash Equivalents
Uses of Cash and Cash Equivalents:
Additions to oil and gas property (1)
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
Dividends paid to APA common stockholders
Distributions to noncontrolling interest
Treasury stock activity, net
Other, net
Total Uses of Cash and Cash Equivalents
Increase (decrease) in cash and cash equivalents
(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, 2025 totaled $4.5 billion, up $925 million from the year ended December 31, 2024, primarily due to collection of outstanding receivables, lower overall expenses, and timing of other working capital items.
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.
Fixed-Rate Debt Borrowings During the year ended December 31, 2025, the Company issued new notes for proceeds of $846 million, after deducting discounts and loan costs, to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.
Proceeds from Asset Divestitures The Company received $611 million and $1.6 billion in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2025 and 2024, 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.
Uses of Cash and Cash Equivalents
Additions to Oil & Gas Property Exploration and development cash expenditures were $2.7 billion and $2.9 billion for the years ended December 31, 2025 and 2024, respectively. The decrease in capital investment is reflective of the Company’s plan to streamline capital deployment and the sale of certain non-core assets and leasehold in the Permian Basin. The Company operated an average of 19 drilling rigs during 2025, compared to an average of 22 drilling rigs during 2024.
Leasehold and Property Acquisitions During 2025 and 2024, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $26 million and $60 million, respectively.
Payments on Term Loan Facility During 2025 and 2024, the Company made payments of $900 million and $600 million, respectively, on its syndicated term loan credit agreement and fully repaid the term loans. For additional details of this credit agreement, see “ Unsecured Committed Term Loan Facility” in the Liquidity section below.
Payments on Commercial Paper and Revolving Credit Facilities, Net During 2025, the Company made net payments of $333 million on its commercial paper and U.S. dollar denominated syndicated credit facility borrowings. As of December 31, 2025, there were no outstanding borrowings under the Company’s commercial paper or syndicated credit facilities.
Payments on Fixed-Rate Debt During 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures of Apache and made open market repurchases of indenture debt of APA and Apache, and Apache redeemed certain notes for aggregate cash payments of $1.0 billion, reflecting principal amounts, discount to par, and associated fees.
During 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.
Dividends Paid to APA Common Stockholders The Company paid $360 million and $353 million during the years ended December 31, 2025 and 2024, respectively, for dividends on its common stock.
Distributions to Noncontrolling Interest Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $430 million and $268 million during the years ended December 31, 2025 and 2024, respectively, in cash distributions to Sinopec.
Treasury Stock Activity, Net During 2025, the Company repurchased 12.9 million shares at an average price of $21.73 per share totaling $280 million, and as of December 31, 2025, the Company had remaining authorization to repurchase 21.9 million shares. During 2024, the Company repurchased 9.2 million shares at an average price of $26.83 per share totaling $246 million.
Liquidity
The following table presents a summary of the Company’s key financial indicators as of December 31:
(In millions)
Cash and cash equivalents
Total debt – APA and Apache
Total equity
Available committed borrowing capacity under syndicated credit facilities
Cash and Cash Equivalents As of December 31, 2025, the Company had $516 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, 2025, the Company had $4.5 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache, and finance lease obligations. As of December 31, 2025, current debt included $2 million of finance lease obligations and $211 million of APA and Apache notes coming due within the next year.
Indenture Debt Activity On August 20, 2025, Apache redeemed the outstanding $51 million principal amount of 4.625% Notes due 2025, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.
During 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $122 million for an aggregate purchase price of $112 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $13 million. The Company recognized a $12 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025.
The indentures under which APA has issued senior notes and debentures restrict it from issuing or guaranteeing certain secured indebtedness, consolidating with or merging into another person, and transferring or leasing its properties and assets as an entirety or substantially as an entirety to any person. Indentures of APA and Apache do not contain prepayment obligations in the event of a decline in credit ratings. In connection with the transactions summarized below under “APA Exchange and Tender Offers for Apache Indenture Debt,” Apache’s indentures were amended on January 10, 2025, to remove certain restrictive and reporting covenants, except those applicable to certain notes maturing in 2026 and 2027.
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:
• A PA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA’s exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA’s 6.10% Notes due 2035 and $500 million aggregate principal amount of APA’s 6.75% Notes due 2055.
• In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration.
• APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. The Company recognized a gain of $135 million on these purchases, including broker fees and loan costs.
• Net proceeds from the sale of the notes in APA’s new notes offering, after deducting the initial purchasers’ discounts and estimated offering expenses, were approximately $839 million and 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 had the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.
• Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering were fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than $1 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.
• APA entered into two registration rights agreements pursuant to which APA agreed to register under the Securities Act of 1933, as amended, the notes and debentures that APA issued in the exchange and tender offers and new notes offering (collectively, the Unregistered Notes). On September 18, 2025, APA settled registered exchange offers for the Unregistered Notes, issuing registered notes and debentures in the same aggregate principal amount as the Unregistered Notes accepted for exchange and canceled and otherwise on terms substantially identical in all material respects to the applicable series of Unregistered Notes. Of the $3.6 billion aggregate principal amount of Unregistered Notes covered by the registered exchange offers, 99 percent was exchanged for registered notes and debentures, and the remaining Unregistered Notes remained outstanding.
Unsecured 2025 Committed Bank Credit Facilities On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:
• One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company’s two, one-year extension options.
• The second agreement is denominated in pounds sterling (the 2025 GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company’s two, one-year extension options.
Apache guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.
The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022, one of which was denominated in US dollars with aggregate commitments of US$1.8 billion (the 2022 USD Agreement) and second of which was denominated in pounds sterling with aggregate commitments of £1.5 billion (the 2022 GBP Agreement). On January 15, 2025, the Company terminated commitments under both the 2022 USD Agreement and 2022 GBP Agreement in connection with entry into the 2025 Agreements.
As of December 31, 2025, there were no borrowings or letters of credit outstanding under the 2025 USD Agreement and no borrowings and an aggregate £1.0 million in letters of credit outstanding under the 2025 GBP Agreement. As of December 31, 2024, there were $10 million of borrowings and no letters of credit outstanding under the 2022 USD Agreement, and no borrowings and an aggregate £303 million in letters of credit outstanding under the 2022 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 (Long-Term Debt Rating). The current 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.
The Company was in compliance with the terms of the 2025 Agreements as of December 31, 2025.
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, 2025 and 2024, there were no outstanding borrowings under these facilities. As of December 31, 2025, there were £901 million and $10 million in letters of credit outstanding under these facilities. As of December 31, 2024, there were £640 million and $11 million in letters of credit outstanding under these facilities.
Commercial Paper Program The Company has a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $2.0 billion outstanding at any time. The program was established in December 2023, and the maximum aggregate face amount of CP Notes issuable thereunder was increased to $2.0 billion from $1.8 billion on June 20, 2025. The maturities of 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, 2025, included the $2.0 billion 2025 USD Agreement.
Payment of the CP Notes was unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on June 20, 2025.
The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.
As of December 31, 2025, the Company had no CP Notes outstanding. As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which was classified as long-term debt.
Unsecured Committed Term Loan Facility On January 30, 2024, APA entered into a syndicated credit agreement providing for committed senior unsecured delayed-draw term loans to APA, the proceeds of which could be used to refinance certain indebtedness of Callon.
On April 1, 2024, APA acquired Callon and borrowed $1.5 billion under this credit agreement maturing April 1, 2027, of which $900 million remained outstanding as of December 31, 2024. APA fully prepaid this credit agreement on March 10, 2025. The repayment was partially financed with borrowings under APA’s 2025 USD Agreement and 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, 2025, the Company had contractual obligations totaling $971 million, of which $778 million is related to U.S. firm transportation contracts, $133 million is related to U.S. purchase obligations, $28 million is related to the merged concession agreement with the EGPC, and $32 million is related to other items.
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, 2025, the Company had net undiscounted minimum commitments of $428 million and $34 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, 2025 are approximately $3.7 billion.
For additional information regarding these obligations, refer to Note 8—Debt and Financing Costs and Note 10—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 7—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 11—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 $23 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies and other commitments, please see Note 10—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. The decommissioning obligations for the Legacy GOA Assets are partially secured by a trust account of which Apache is a beneficiary and which is 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 loan GOM Shelf up to $400 million to perform decommissioning, with such loans and related obligations secured by first and prior liens on the Legacy GOA Assets.
By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOA Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOA Assets.
As of December 31, 2025, the Company recorded an asset of $40 million representing the remaining amount the Company expects to be reimbursed from remaining security related to these decommissioning costs. Of the total asset recorded as of December 31, 2025, $21 million is reflected under the caption “Decommissioning security for sold Gulf of America properties,” and $19 million is reflected under “Other current assets” in the Company’s consolidated balance sheet.
As of December 31, 2025, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $0.9 billion to $1.2 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 $881 million and $1.0 billion as of December 31, 2025, and December 31, 2024, respectively. Of the total liability recorded as of December 31, 2025, $782 million is reflected under the caption “Decommissioning contingency for sold Gulf of America properties” and $99 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, planned abandonment logistics, and future cash flows of GOM Shelf, could result in a liability in excess of the amount accrued.
The Company recognized $60 million of “Gains on previously sold Gulf of America properties” during 2025 to reflect the net impact of decreased estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The Company recognized losses on previously sold Gulf of America properties of $273 million and $212 million during 2024 and 2023, 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.
The Company purchases multi-year political risk insurance from highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks.
Future insurance coverage for the Company’s industry could increase in cost and may include higher deductibles or retentions or a change in policy limit or additional exclusions or limitations. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable.
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, and damages to their respective property.
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.
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 16—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 10—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) and changing tax laws.
