10-K – 2026-02-26 – apa-20251231.htm

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.
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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.
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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
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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.
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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

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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.
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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.

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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
1,670,918  $ 23.95  1,670,918  33,086,204 
February 1 to February 29, 2025
2,470,913  22.34  2,470,913  30,615,291 
March 1 to March 31, 2025
232,741  20.63  232,741  30,382,550 
April 1 to April 30, 2025
603,233  16.59  603,233  29,779,317 
May 1 to May 31, 2025
—  —  —  29,779,317 
June 1 to June 30, 2025
2,096,211  19.09  2,096,211  27,683,106 
July 1 to July 31, 2025
989,196  19.31  989,196  26,693,910 
August 1 to August 31, 2025
1,214,309  19.92  1,214,309  25,479,601 
September 1 to September 30, 2025
910,343  23.54  910,343  24,569,258 
October 1 to October 31, 2025
997,815  23.53  997,815  23,571,443 
November 1 to November 30, 2025
814,830  23.80  814,830  22,756,613 
December 1 to December 31, 2025
890,475  25.23  890,475  21,866,138 
Total 12,890,984  $ 21.73 

(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.
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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.

2020 2021 2022 2023 2024 2025
APA Corporation $ 100.00  $ 190.76  $ 336.73  $ 265.27  $ 176.57  $ 196.71 
S&P 500 Index 100.00  128.71  105.40  133.10  166.40  196.16 
Dow Jones U.S. Exploration & Production Index 100.00  170.92  272.74  285.07  280.73  295.11 

ITEM 6. SELECTED FINANCIAL DATA

Omitted.
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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.
34

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.
35

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.
36

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,
  2025 2024 2023
  $ Value % Contribution $ Value % Contribution $ Value % Contribution

  ($ in millions)
Oil Revenues:
United States $ 3,010  52  % $ 3,572  51  % $ 2,241  37  %
Egypt (1)
2,177  37  % 2,620  38  % 2,683  45  %
North Sea 622  11  % 774  11  % 1,073  18  %
Total (1)
$ 5,809  100  % $ 6,966  100  % $ 5,997  100  %

Natural Gas Revenues:
United States $ 193  25  % $ 126  22  % $ 297  34  %
Egypt (1)
460  60  % 313  53  % 346  39  %
North Sea 117  15  % 145  25  % 237  27  %
Total (1)
$ 770  100  % $ 584  100  % $ 880  100  %

NGL Revenues:
United States $ 616  95  % $ 617  96  % $ 480  94  %

North Sea 34  5  % 29  4  % 28  6  %
Total (1)
$ 650  100  % $ 646  100  % $ 508  100  %

Oil and Gas Revenues:
United States $ 3,819  53  % $ 4,315  53  % $ 3,018  41  %
Egypt (1)
2,637  36  % 2,933  36  % 3,029  41  %
North Sea 773  11  % 948  11  % 1,338  18  %
Total (1)
$ 7,229  100  % $ 8,196  100  % $ 7,385  100  %

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

37

Production
The following table presents production volumes by country:

  For the Year Ended December 31,
  2025 Increase
(Decrease) 2024 Increase
(Decrease) 2023
Oil Volumes – b/d:
United States (5)
125,526  (2)% 128,531  63% 78,889 
Egypt (3)(4)
87,719  (1)% 89,027  —% 89,129 
North Sea 24,186  (8)% 26,340  (24)% 34,728 
Total 237,431  (3)% 243,898  20% 202,746 

Natural Gas Volumes – Mcf/d:
United States (5)
514,502  6% 483,446  7% 452,281 
Egypt (3)(4)
350,774  21% 291,011  (11)% 325,778 
North Sea 31,318  (22)% 39,986  (20)% 50,284 
Total 896,594  10% 814,443  (2)% 828,343 

NGL Volumes – b/d:
United States (5)
76,264  3% 73,877  17% 62,997 

North Sea 1,256  5% 1,201  (3)% 1,240 
Total 77,520  3% 75,078  17% 64,237 

BOE per day: (1)

United States (5)
287,539  2% 282,983  30% 217,266 
Egypt (3)(4)
146,182  6% 137,529  (4)% 143,425 
North Sea (2)
30,662  (10)% 34,204  (23)% 44,349 
Total 464,383  2% 454,716  12% 405,040 

(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:

2025 2024 2023
Oil (b/d) 125,511  137,150  141,985 
Natural Gas (Mcf/d) 486,462  443,551  500,080 

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

2025 2024 2023
Oil (b/d) 29,267  29,698  29,739 
Natural Gas (Mcf/d) 117,035  97,078  108,703 

(5) Production volumes per day in the Company’s Wildfire field were as follows:

2025 2024 2023
Oil (b/d) 29,023  19,970  15,644 
Natural Gas (Mcf/d) 52,650  41,136  29,537 
NGL (b/d) 10,127  7,540  5,622 

38

Pricing
The following table presents pricing information by country:

  For the Year Ended December 31,
  2025 Increase
(Decrease) 2024 Increase
(Decrease) 2023
Average Oil Price - Per barrel:
United States $ 65.71  (13)% $ 75.92  (2)% $ 77.84 
Egypt 67.97  (15)% 80.41  (2)% 82.47 
North Sea 69.31  (14)% 80.74  (2)% 82.75 
Total 66.92  (14)% 78.08  (3)% 80.72 

Average Natural Gas Price - Per Mcf:
United States $ 1.02  44% $ 0.71  (61)% $ 1.80 
Egypt 3.59  22% 2.94  1% 2.91 
North Sea 12.03  11% 10.84  (17)% 13.02 
Total 2.36  20% 1.97  (32)% 2.91 

Average NGL Price - Per barrel:
United States $ 22.13  (3)% $ 22.83  9% $ 20.85 

North Sea 43.59  (8)% 47.59  —% 47.77 
Total 22.71  (3)% 23.37  8% 21.54 

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.
39

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.
40

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,
  2025 2024 2023

  (In millions)
Lease operating expenses $ 1,504  $ 1,690  $ 1,436 
Gathering, processing, and transmission 424  432  334 
Purchased oil and gas costs 1,070  1,047  742 
Taxes other than income 229  270  207 
Exploration 131  313  195 
General and administrative 350  372  351 
Transaction, reorganization, and separation 102  168  15 
Depreciation, depletion, and amortization:
Oil and gas property and equipment 2,275  2,235  1,500 
Gathering, processing, and transmission assets 6  6  6 
Other assets 23  25  34 
Asset retirement obligation accretion 158  148  116 
Impairments 44  1,129  61 
Financing costs, net 113  367  312 

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,
2025 2024 2023

(In millions)
Third-party processing and transmission costs $ 424  $ 409  $ 225 

Midstream service costs – Kinetik
—  23  109 
Upstream processing and transmission costs 424  432  334 

Total Gathering, processing, and transmission $ 424  $ 432  $ 334 

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.
41

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,
2025 2024 2023

(In millions)
Unproved leasehold impairments $ 2  $ 35  $ 22 
Dry hole expenses 67  201  92 
Geological and geophysical expenses 8  21  19 
Exploration overhead and other 54  56  62 
Total Exploration $ 131  $ 313  $ 195 

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.
42

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,
  2025 2024 2023

  (In millions)
Interest expense $ 323  $ 402  $ 351 
Amortization of debt issuance costs 7  6  4 
Capitalized interest (45) (29) (24)
Gain on extinguishment of debt
(147) —  (9)
Interest income (25) (12) (10)
Total Financing costs, net $ 113  $ 367  $ 312 

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.
43

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.
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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.
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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,    
  2025 2024 2023

  (In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities $ 4,545  $ 3,620  $ 3,129 
Fixed-rate debt borrowings
846  —  — 

Proceeds from asset divestitures 611  1,609  29 
Proceeds from term loan facility
—  1,500  — 
Proceeds from sale of Kinetik shares —  428  228 

Total Sources of Cash and Cash Equivalents 6,002  7,157  3,386 
Uses of Cash and Cash Equivalents:
Additions to oil and gas property (1)
2,740  2,851  2,313 
Acquisition of Delaware Basin properties —  —  24 

Leasehold and property acquisitions 26  60  20 
Payments on term loan facility
900  600  — 
Payments on commercial paper and revolving credit facilities, net
333  40  194 
Payments on Callon Credit Agreement —  472  — 
Payments on fixed-rate debt
1,016  1,641  65 
Dividends paid to APA common stockholders 360  353  308 
Distributions to noncontrolling interest
430  268  238 

Treasury stock activity, net 280  246  329 

Other, net 26  88  53 
Total Uses of Cash and Cash Equivalents 6,111  6,619  3,544 
Increase (decrease) in cash and cash equivalents $ (109) $ 538  $ (158)

(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.
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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:

  2025 2024
  (In millions)
Cash and cash equivalents $ 516  $ 625 
Total debt – APA and Apache
4,493  6,044 
Total equity
7,003  6,362 
Available committed borrowing capacity under syndicated credit facilities 4,020  2,966 

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.

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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.
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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.
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• 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.
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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.
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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.
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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.
53

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.
54

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.
55

ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.
The Company’s average crude oil price realizations decreased 14 percent to $66.92 per barrel in 2025 from $78.08 per barrel in 2024. The Company’s average natural gas price realizations increased 20 percent to $2.36 per Mcf in 2025 from $1.97 per Mcf in 2024. The Company’s average NGL price realizations decreased 3 percent to $22.71 per barrel in 2025 from $23.37 per barrel in 2024. Based on average daily production for 2025, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $87 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $33 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $28 million.
The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of December 31, 2025, the Company had open natural gas derivatives not designated as cash flow hedges in a net liability position with a fair value of $77 million. A 10 percent increase in natural gas prices would decrease the liability by approximately $5 million, while a 10 percent decrease in prices would increase the liability by approximately $6 million. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report Form 10-K for notional volumes and terms with the Company’s derivative contracts.
Interest Rate Risk
As of December 31, 2025, the Company had $4.5 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.66 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.
The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its term loan facility, commercial paper program, and syndicated credit facilities. As of December 31, 2025, the Company had approximately $516 million in cash and cash equivalents, approximately 95 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2025, there were no borrowings outstanding under the Company’s term loan facility, commercial paper program, and syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments, term loan facility, and commercial paper program are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.
56

Foreign Currency Exchange Rate Risk
The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other, net” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss would not be material from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 2025.
The Company is subject to increased foreign currency risk associated with the effects of decommissioning obligations in the North Sea. The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operations. Subsequent to December 31, 2025, the Company entered into outstanding foreign exchange contracts with a total notional amount of £120 million to reduce its exposure to fluctuating foreign exchange rates for the British pound.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F- 59 in Part IV, Item 15 of this Annual Report on Form 10-K and are incorporated herein by reference.

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

The financial statements for the fiscal years ended December 31, 2025, 2024, and 2023, included in this Annual Report on Form 10-K, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer, in his capacity as principal executive officer, and Ben C. Rodgers, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of December 31, 2025, the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.
57

Management’s Annual Report on Internal Control Over Financial Reporting; Attestation Report of the Registered Public Accounting Firm
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Part IV, Item 15 of this Annual Report on Form 10-K.
The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the “Report of Independent Registered Public Accounting Firm,” included on Page F-2 through F-5 in Part IV, Item 15 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There was no change in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

During the three months ended December 31, 2025, none of the Company’s officers or directors adopted , modified, or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

58

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Information about Our Executive Officers,” “Securities Ownership and Principal Holders,” “Additional Information—Future Shareholder Proposals and Director Nominations,” “Corporate Governance—Board Committees, Meetings, and Responsibilities,” and “Corporate Governance— Insider Trading Policy ” in the proxy statement relating to the Company’s 2026 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.
Code of Conduct
In accordance with Rule 5610 of the Nasdaq, the Company maintains a code of conduct for its directors, officers, and employees. The Company’s Code of Conduct was adopted by the Company’s Board of Directors in March 2021 and subsequently amended in December 2024 (as amended, the Code of Conduct). The Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Code of Conduct on the Governance page of the Company’s website at www.apacorp.com . Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within four business days and maintained for at least 12 months. Information on the Company’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

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

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

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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

59

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents included in this report:

1. Financial Statements
 
Report of management on internal control over financial reporting
F- 1

Report of independent registered public accounting firm (PCAOB ID: 42)
F- 2

Report of independent registered public accounting firm (PCAOB ID: 42 )
F- 3

Statement of consolidated operations for each of the three years in the period ended December 31, 2025
F- 5

Statement of consolidated comprehensive income for each of the three years in the period ended December 31, 2025
F- 6

Statement of consolidated cash flows for each of the three years in the period ended December 31, 2025
F- 7

Consolidated balance sheet as of December 31, 2025 and 2024
F- 8

Statement of consolidated changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2025
F- 9

Notes to consolidated financial statements
F- 10

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

3. Exhibits

60

Incorporated by Reference

EXHIBIT
NO. DESCRIPTION Form Exhibit Filing Date SEC File No.
3.1 Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021.
8-K12B
3.1
3/1/2021
001-40144
3.2 Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated May 24, 2023, as filed with the Secretary of State of the State of Delaware on May 24, 2023.
8-K
3.1
5/25/2023
001-40144
3.3 Amended and Restated Bylaws of Registrant, dated February 2, 2023.
8-K 3.1 2/8/2023 001-40144
4.1 Form of Certificate for Registrant’s Common Stock.
8-K12B 4.1 3/1/2021 001-40144
4.2 Description of Equity Securities of Registrant.
8-K12B 4.2 3/1/2021 001-40144
4.3 Amended and Restated Warrant Agreement, dated April 1, 2024, by and among Registrant, Equiniti Trust Company, LLC, and, solely for purposes of certain provisions specified therein, Callon Petroleum Company.
8-K
4.1
4/1/2024
001-40144

4.4 Indenture, dated as of December 11, 2024, between Registrant and Regions Bank, as trustee.
POSASR
4.9
12/12/2024
333-279038

4.5 Indenture, dated as of June 30, 2021, between Registrant and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee.
S-3ASR
4.4
6/30/2021
333-257556

10.1
Credit Agreement [USD Facility], dated as of January 15, 2025, among Registrant, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.
8-K
10.1
1/16/2025
001-40144

10.2
Credit Agreement [GBP Facility], dated as of January 15, 2025, among Registrant, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.
8-K
10.2
1/16/2025
001-40144

†10.3
Income Continuance Plan, as amended and restated effective as of March 1, 2021.
8-K12B 10.2 3/1/2021 001-40144
†10.4
Executive Termination Policy, as amended and restated effective as of March 1, 2021.
8-K12B 10.3 3/1/2021 001-40144
†10.5
2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016.
8-K 10.1 5/16/2016 001-04300

†10.6
Second Amendment to the 2016 Omnibus Compensation Plan, dated March 1, 2021.
8-K12B 10.6 3/1/2021 001-40144
†10.7
2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016.
10-Q 10.1 8/4/2016 001-04300
†10.8
First Amendment to the 2011 Omnibus Equity Compensation Plan, dated July 29, 2019.
10-K 10.15 2/28/2020 001-04300
†10.9
Second Amendment to the 2011 Omnibus Equity Compensation Plan, dated March 1, 2021.
8-K12B 10.5 3/1/2021 001-40144
†10.10
Deferred Delivery Plan, as amended and restated May 12, 2016.
10-Q 10.3 8/4/2016 001-04300
†10.11
Non-Employee Directors’ Compensation Plan, as amended and restated September 12, 2023.
10-Q 10.1 11/2/2023 001-40144
†10.12
Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014.
10-Q 10.5 8/8/2014 001-04300

†10.13
Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to the 2016 Omnibus Compensation Plan.
10-Q 10.4 8/4/2016 001-04300
†10.14
Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to the 2016 Omnibus Compensation Plan.
10-Q 10.5 8/4/2016 001-04300

†10.15
Form of 2023 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 4, 2023.
8-K 10.1 1/6/2023 001-40144
†10.16
Form of Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan) .
10-K 10.43 2/23/2023 001-40144
†10.17
Form of Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan) .
10-K 10.44 2/23/2023 001-40144

61

Incorporated by Reference

EXHIBIT
NO. DESCRIPTION Form Exhibit Filing Date SEC File No.
†10.18
Form of 2024 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 8, 2024.
8-K 10.1 1/12/2024 001-40144

†10.19
Form of 2025 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 9, 2025.
8-K 10.1
1/10/2025
001-40144

†10.20
Form of Stock Option Award Agreement (2016 Omnibus Compensation Plan) .
8-K 10.2
1/10/2025
001-40144

*†10.21
Form of 2026 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 6, 2026.

*19.1
Insider Trading Policy.

*21.1 Subsidiaries of Registrant.

*23.1 Consent of Ernst & Young LLP.

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

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

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

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

**32.1
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

97.1 Executive Compensation Clawback Policy.
10-K
97.1
2/22/2024
001-40144

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

*101.INS Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*101.SCH Inline XBRL Taxonomy Schema Document.
*101.CAL Inline XBRL Calculation Linkbase Document.
*101.DEF Inline XBRL Definition Linkbase Document.
*101.LAB Inline XBRL Label Linkbase Document.
*101.PRE Inline XBRL Presentation Linkbase Document.
*104 Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).

* Filed herewith.
** Furnished herewith.

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

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

ITEM 16. FORM 10-K SUMMARY

None.
62

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

                                APA CORPORATION

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

Dated: February 26, 2026

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

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

Name Title Date

/s/ John J. Christmann IV
John J. Christmann IV
Director and Chief Executive Officer (principal executive officer)
February 26, 2026
/s/ Ben C. Rodgers
Ben C. Rodgers
Executive Vice President and Chief Financial Officer
(principal financial officer)
February 26, 2026
/s/ Robert P. Rayphole
Robert P. Rayphole
Vice President, Chief Accounting Officer, and Controller
(principal accounting officer)
February 26, 2026
/s/ Annell R. Bay
Annell R. Bay
Director February 26, 2026
/s/ Matthew R. Bob
Matthew R. Bob
Director February 26, 2026
/s/ Juliet S. Ellis
Juliet S. Ellis
Director February 26, 2026
/s/ Kenneth M. Fisher
Kenneth M. Fisher
Director February 26, 2026
/s/ Charles W. Hooper
Charles W. Hooper
Director February 26, 2026
/s/ Chansoo Joung
Chansoo Joung
Director February 26, 2026
/s/ H. Lamar McKay
H. Lamar McKay
Independent, Non-Executive Chair of the Board and Director
February 26, 2026
/s/ Peter A. Ragauss
Peter A. Ragauss
Director February 26, 2026
/s/ David L. Stover
David L. Stover
Director February 26, 2026
/s/ Anya Weaving
Anya Weaving
Director February 26, 2026

63

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2025.
The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of APA Corporation and subsidiaries and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.

/s/  John J. Christmann IV
Chief Executive Officer

(principal executive officer)

/s/  Ben C. Rodgers

Executive Vice President and Chief Financial Officer

(principal financial officer)

/s/  Robert P. Rayphole

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas
February 26, 2026

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of APA Corporation
Opinion on Internal Control Over Financial Reporting
We have audited APA Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, APA Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related statements of consolidated operations, comprehensive income, changes in equity and noncontrolling interest and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and our report dated February 26, 2026 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2026

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of APA Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of APA Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related statements of consolidated operations, comprehensive income, changes in equity and noncontrolling interest and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 26, 2026 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depreciation, depletion and amortization of property and equipment

Description of
the Matter
At December 31, 2025, the net carrying value of the Company’s property and equipment was $12,748 million, and depreciation, depletion and amortization (DD&A) expense was $2,304 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers.

F-3

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Judgment is required by the Company’s internal reservoir engineers in estimating oil and gas reserves. Estimating proved oil and gas reserves requires the selection of inputs, including historical production, oil and gas price assumptions, and operating costs, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for select properties as of December 31, 2025.

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

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

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

Accounting for asset retirement obligation for the North Sea segment

Description of
the Matter
At December 31, 2025, the asset retirement obligation (ARO) balance totaled $2,880 million. As further described in Note 7, the Company’s ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs.

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

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

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

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 26, 2026

F-4

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
For the Year Ended December 31,
  2025 2024 2023

  (In millions, except per common share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues
$ 7,229   $ 8,196   $ 7,385  
Purchased oil and gas sales
1,691   1,541   894  
Total revenues 8,920   9,737   8,279  
Derivative instrument gains (losses), net ( 53 ) ( 10 ) 99  
Gain on divestitures, net 301   289   8  
Gains (losses) on previously sold Gulf of America properties
60   ( 273 ) ( 212 )
Other, net ( 8 ) ( 6 ) 18  
9,220   9,737   8,192  
OPERATING EXPENSES:
Lease operating expenses
1,504   1,690   1,436  
Gathering, processing, and transmission
424   432   334  
Purchased oil and gas costs
1,070   1,047   742  
Taxes other than income 229   270   207  
Exploration 131   313   195  
General and administrative 350   372   351  
Transaction, reorganization, and separation 102   168   15  
Depreciation, depletion, and amortization 2,304   2,266   1,540  
Asset retirement obligation accretion 158   148   116  
Impairments 44   1,129   61  
Financing costs, net 113   367   312  
6,429   8,202   5,309  
NET INCOME BEFORE INCOME TAXES
2,791   1,535   2,883  
Current income tax provision 739   1,153   1,338  
Deferred income tax provision (benefit) 360   ( 736 ) ( 1,662 )
NET INCOME INCLUDING NONCONTROLLING INTERESTS
1,692   1,118   3,207  
Net income attributable to noncontrolling interest
258   314   352  

NET INCOME ATTRIBUTABLE TO COMMON STOCK
$ 1,434   $ 804   $ 2,855  

NET INCOME PER COMMON SHARE:

Basic $ 3.99   $ 2.28   $ 9.26  

Diluted $ 3.99   $ 2.27   $ 9.25  
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic 359   353   308  
Diluted 359   353   309  

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

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

  For the Year Ended December 31,
  2025 2024 2023

  (In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS
$ 1,692   $ 1,118   $ 3,207  
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:

Pension and postretirement benefit plan ( 2 ) ( 3 ) 1  
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS
1,690   1,115   3,208  
Comprehensive income attributable to noncontrolling interest
258   314   352  

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
$ 1,432   $ 801   $ 2,856  

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

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS

  For the Year Ended December 31,
  2025 2024 2023

  (In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests
$ 1,692   $ 1,118   $ 3,207  
Adjustments to reconcile net income to net cash provided by operating activities:

Unrealized derivative instrument (gains) losses, net
77   8   ( 51 )
Gain on divestitures, net
( 301 ) ( 289 ) ( 8 )
Exploratory dry hole expense and unproved leasehold impairments 69   236   114  
Depreciation, depletion, and amortization 2,304   2,266   1,540  
Asset retirement obligation accretion 158   148   116  
Impairments 44   1,129   61  
Provision for (benefit from) deferred income taxes 360   ( 736 ) ( 1,662 )
Gain from extinguishment of debt
( 147 ) —   ( 9 )
(Gains) losses on previously sold Gulf of America properties
( 60 ) 273   212  
Other 57   2   26  
Changes in operating assets and liabilities:
Receivables 850   ( 104 ) ( 157 )
Inventories 7   ( 11 ) 13  
Drilling advances and other current assets 223   ( 56 ) 269  
Deferred charges and other long-term assets 36   11   270  
Accounts payable ( 365 ) 81   ( 84 )
Accrued expenses ( 199 ) ( 221 ) ( 400 )
Deferred credits and noncurrent liabilities ( 260 ) ( 235 ) ( 328 )
NET CASH PROVIDED BY OPERATING ACTIVITIES 4,545   3,620   3,129  
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property
( 2,740 ) ( 2,851 ) ( 2,313 )

Acquisition of Delaware Basin properties
—   —   ( 24 )
Leasehold and property acquisitions ( 26 ) ( 60 ) ( 20 )

Proceeds from asset divestitures 611   1,609   29  
Proceeds from sale of Kinetik shares —   428   228  

Other, net 2   ( 50 ) ( 38 )
NET CASH USED IN INVESTING ACTIVITIES ( 2,153 ) ( 924 ) ( 2,138 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on commercial paper and revolving credit facilities, net
( 333 ) ( 40 ) ( 194 )
Proceeds from term loan facility
—   1,500   —  
Payments on term loan facility
( 900 ) ( 600 ) —  
Payment on Callon Credit Agreement
—   ( 472 ) —  
Fixed rate debt borrowings 846   —   —  
Payments on fixed-rate debt
( 1,016 ) ( 1,641 ) ( 65 )
Distributions to noncontrolling interest
( 430 ) ( 268 ) ( 238 )

Dividends paid to APA common stockholders ( 360 ) ( 353 ) ( 308 )
Treasury stock activity, net ( 280 ) ( 246 ) ( 329 )
Other, net ( 28 ) ( 38 ) ( 15 )
NET CASH USED IN FINANCING ACTIVITIES
( 2,501 ) ( 2,158 ) ( 1,149 )
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ( 109 ) 538   ( 158 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 625   87   245  
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 516   $ 625   $ 87  
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest $ 281   $ 372   $ 329  
Income taxes paid, net of refunds 999   1,097   1,271  

The accompanying notes to consolidated financial statements are an integral part of this statement.
F-7

APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET

  December 31,
2025 2024

(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 516   $ 625  
Receivables, net of allowance of $ 140 and $ 123
1,062   1,959  
Other current assets ( Note 5 )
543   820  
2,121   3,404  
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:
45,507   44,698  

Gathering, processing, and transmission facilities
445   433  
Other
536   562  

Less: Accumulated depreciation, depletion, and amortization
( 33,740 ) ( 33,047 )
12,748   12,646  
OTHER ASSETS:

Decommissioning security for sold Gulf of America properties ( Note 10 )
21   21  
Deferred tax asset ( Note 9 )
2,328   2,703  
Deferred charges and other
543   616  
$ 17,761   $ 19,390  

LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY

CURRENT LIABILITIES:
Accounts payable $ 871   $ 1,224  
Current debt 213   53  
Other current liabilities ( Note 6 )
1,487   1,678  
2,571   2,955  
LONG-TERM DEBT ( Note 8 )
4,280   5,991  
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability ( Note 9 )
—   14  
Asset retirement obligation ( Note 7 )
2,699   2,591  
Decommissioning contingency for sold Gulf of America properties ( Note 10 )
782   929  
Other 426   548  
3,907   4,082  

EQUITY:

Common stock, $ 0.625 par, 860,000,000 shares authorized, 492,038,127 and 491,579,646 shares issued, respectively
308   307  
Paid-in capital 12,816   13,153  
Accumulated deficit ( 721 ) ( 2,155 )
Treasury stock, at cost, 139,073,481 and 126,182,497 shares, respectively
( 6,320 ) ( 6,037 )
Accumulated other comprehensive income 10   12  
APA SHAREHOLDERS’ EQUITY
6,093   5,280  
Noncontrolling interest
910   1,082  
TOTAL EQUITY
7,003   6,362  
$ 17,761   $ 19,390  

The accompanying notes to consolidated financial statements are an integral part of this statement.
F-8

APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST

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

  (In millions)
BALANCE AT DECEMBER 31, 2022 $ 262   $ 11,420   $ ( 5,814 ) $ ( 5,459 ) $ 14   $ 423   $ 922   $ 1,345  
Net income attributable to common stock
—  —  2,855   —  —  2,855   —  2,855  
Net income attributable to noncontrolling interest
—  —  —  —  —  —  352   352  

Distributions to noncontrolling interest
—  —  —  —  —  —  ( 238 ) ( 238 )

Common dividends ($ 1.00 per share)
—  ( 308 ) —  —  —  ( 308 ) —  ( 308 )
Common stock activity, net 1   ( 14 ) —  —  —  ( 13 ) —  ( 13 )

Treasury stock activity, net —  —  —  ( 331 ) —  ( 331 ) —  ( 331 )
Compensation expense —  23   —  —  —  23   —  23  
Other —  5   —  —  1   6   —  6  
BALANCE AT DECEMBER 31, 2023 $ 263   $ 11,126   $ ( 2,959 ) $ ( 5,790 ) $ 15   $ 2,655   $ 1,036   $ 3,691  
Net income attributable to common stock —  —  804   —  —  804   —  804  
Net income attributable to noncontrolling interest
—  —  —  —  —  —  314   314  

Distributions to noncontrolling interest
—  —  —  —  —  —  ( 268 ) ( 268 )
Common dividends ($ 1.00 per share)
—  ( 352 ) —  —  —  ( 352 ) —  ( 352 )
Common stock activity, net 44   2,370   —  —  —  2,414   —  2,414  

Treasury stock activity, net —  —  —  ( 247 ) —  ( 247 ) —  ( 247 )
Compensation expense —  26   —  —  —  26   —  26  
Other —  ( 17 ) —  —  ( 3 ) ( 20 ) —  ( 20 )
BALANCE AT DECEMBER 31, 2024 $ 307   $ 13,153   $ ( 2,155 ) $ ( 6,037 ) $ 12   $ 5,280   $ 1,082   $ 6,362  
Net income attributable to common stock —  —  1,434   —  —  1,434   —  1,434  
Net income attributable to noncontrolling interest
—  —  —  —  —  —  258   258  
Distributions to noncontrolling interest
—  —  —  —  —  —  ( 430 ) ( 430 )

Common dividends ($ 1.00 per share)
—  ( 359 ) —  —  —  ( 359 ) —  ( 359 )
Common stock activity, net 1   ( 6 ) —  —  —  ( 5 ) —  ( 5 )
Treasury stock activity, net —  —  —  ( 283 ) —  ( 283 ) —  ( 283 )
Compensation expense —  26   —  —  —  26   —  26  
Other —  2   —  —  ( 2 ) —   —  —  
BALANCE AT DECEMBER 31, 2025 $ 308   $ 12,816   $ ( 721 ) $ ( 6,320 ) $ 10   $ 6,093   $ 910   $ 7,003  

The accompanying notes to consolidated financial statements are an integral part of this statement.
F-9

APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations
APA Corporation (APA or the Company) is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids. The Company’s business has oil and gas operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities.

1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures ), the assessment of asset retirement obligations (refer to Note 7—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 9—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of America (refer to Note 10—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 16—Supplemental Oil and Gas Disclosures (Unaudited) ).
F-10

APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Refer to Note 4—Derivative Instruments and Hedging Activities , Note 8—Debt and Financing Costs , and Note 11—Retirement and Deferred Compensation Plans for further detail regarding the Company’s fair value measurements recorded on a recurring basis.
The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment or when allocating the purchase price for acquired assets and liabilities in a business combination.
The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature and maturities of these instruments.
Impairments
The Company recorded $ 37 million and $ 11  million of asset impairments in connection with fair value assessments during the years ended December 31, 2025 and 2023, respectively.
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. As a result, the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea as of the third quarter of 2024. Accordingly, the Company recognized impairments of $ 796 million on certain proved properties in the North Sea, which were written down to their estimated fair values as of the third quarter of 2024. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.”
Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $ 315  million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail.
Allocation of Purchase Price
During 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $ 4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired, and liabilities assumed be recognized at their fair values as of the acquisition date, using various Level 3 fair value measurements. Material assets and liabilities acquired are discussed further below:
F-11

APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)