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10-K – 2026-02-26 – apa-20251231.htm

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Omsättning
  • Production Production | Revenue Year-End | Estimated
  • (1) The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 23 percent of 2025 production and accounted for 12 percent of year-end 2025 estimated proved reserves. | (2) Sales volumes from the Company’s North Sea assets for 2025 were 11.4 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings. | United States
  • The Company is committed to maintaining a safe and efficient level of activity as part of its planned capital investment program. For 2026, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves, subject to prevailing commodity prices. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserv | U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies, as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to | APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g., WTI Houston, West Texas Sour (WTS), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’s objective is to maximize the value of crude oil sold by
  • U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies, as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to | APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g., WTI Houston, West Texas Sour (WTS), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’s objective is to maximize the value of crude oil sold by | APA’s U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
  • APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g., WTI Houston, West Texas Sour (WTS), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’s objective is to maximize the value of crude oil sold by | APA’s U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser. | U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 152 Bcf of natural gas per year for the period from 2026 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, an average of 1.8 MMbbls of crude oil per year for the period from 2026 through 2028, and de minimis crude oil volumes in the year 2029, in each case, at variable, domestic and/or international, marke
  • U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 152 Bcf of natural gas per year for the period from 2026 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, an average of 1.8 MMbbls of crude oil per year for the period from 2026 through 2028, and de minimis crude oil volumes in the year 2029, in each case, at variable, domestic and/or international, marke | In order to satisfy certain delivery commitments, the Company purchases third-party natural gas and crude oil to sell and deliver under existing pipeline agreements and sales contracts. APA may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments. | For more information regarding the Company’s commitments, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations of this Annual Report on Form 10-K.
  • Egypt APA has decades of exploration, development, and operations experience in Egypt and is the largest acreage holder in Egypt’s Western Desert. At year-end 2025, the Company held 7.5 million gross acres in six separate concessions. The Company’s acreage is primarily held under one merged concession agreement (MCA) that resulted from the ratification of a MCA in 2021 with the Government of Egypt and EGPC. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under | APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with EGPC and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Addit | The APA subsidiary that is the sole Contractor under the MCA is owned by an APA-operated joint venture owned two-thirds by the Company and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).
  • The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). In 2011, the Company acquired Mobil North Sea Limited, which included operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. The Company also has a non-operated interest in the Nelson field acquired in 2011. In 2023, the Company suspended all new drilling activity in the North Sea. Dur | International Marketing In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC pursuant to a gas sales agreement that establishes pricing based on a minimum realized price of $2.65 per MMBtu, with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement, which was effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil. In | The Company’s North Sea crude oil production is sold under term, entitlement volume contracts and spot variable volume contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, operated by Ancala Midstream Acquisitions Limited. Natural gas is sold to a third party at the St. Fergus entry point of the national grid on a Nat
Rörelseresultat
  • Low prices have previously adversely affected and could from time to time in the future adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and a prolonged period of low prices could have a material adverse impact on the Company’s results of operations and cash flows and limit its ability to fund capital expenditures and return capital to its shareholders. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and | The Company’s ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, meet volume commitments under transportation services agreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity changes, the inability to procure and resell volumes economically, various transportation interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could
  • As of December 31, 2025, the Company’s consolidated subsidiaries are engaged in exploration, development and/or production activities across four operating segments: Egypt, North Sea, Suriname, and the U.S. The Company’s business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. | The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company’s Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is p | Financial information for each segment is presented below:
  • 3,871 1,221 752 20 5,864 | Operating Income (Loss) $ 1,670 $ 1,416 $ 21 $ ( 20 ) 3,087 | Other Income (Expense):
  • 4,327 1,226 1,676 66 7,295 | Operating Income (Loss) $ 1,531 $ 1,707 $ ( 728 ) $ ( 66 ) 2,444 | Other Income (Expense):
  • 2,601 1,150 837 43 4,631 | Operating Income (Loss) $ 1,359 $ 1,879 $ 501 $ ( 43 ) 3,696 | Other Income (Expense):
Periodens resultat
  • 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 pri | 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 a
  • 6,429 8,202 5,309 | NET INCOME BEFORE INCOME TAXES | 2,791 1,535 2,883
  • Deferred income tax provision (benefit) 360 ( 736 ) ( 1,662 ) | NET INCOME INCLUDING NONCONTROLLING INTERESTS | 1,692 1,118 3,207
  • 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:
  • (In millions) | NET INCOME INCLUDING NONCONTROLLING INTERESTS | $ 1,692 $ 1,118 $ 3,207
  • CASH FLOWS FROM OPERATING ACTIVITIES: | Net income including noncontrolling interests | $ 1,692 $ 1,118 $ 3,207
Resultat per aktie
  • Earnings Per Share | The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.
  • Earnings Per Share | The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. | Stock-Based Compensation
  • The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 3.3 million, 2.0 million, and 1.9 million for the years ended December 31, 2025, 2024, and 2023, respectively. | Stock Repurchase Program
Kassaflöde
  • APA maintains a diversified asset portfolio, including conventional and unconventional, onshore and offshore, oil and natural gas exploration and production interests, while offering global exploration opportunities. In the U.S., operations are primarily focused in the Permian Basin of West Texas. Internationally, the Company has conventional onshore assets in Egypt’s Western Desert, offshore assets on the U.K.’s Continental Shelf, and is currently progressing with an oil field development offsh | APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions take | The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs.
  • The Company’s U.S. producing assets are primarily located in the Permian Basin in West Texas, including the Midland and Delaware sub-basins. Examples of shale plays being developed within these sub-basins include the Spraberry, Bone Spring, Wolfcamp, Barnett, and Woodford. The Company operates approximately 4,000 gross oil and gas wells across its acreage, with additional interests in approximately 700 non-operated wells. APA also has legacy operations located offshore in the Gulf of America. Hi | • Permian Basin The Permian Basin is a foundational asset for APA, providing the Company’s largest source of production and cash flow. Over the past two years, the Company has progressed on high-grading its scale of operations and localized knowledge through the Callon acquisition and exit from non-core holdings in the conventional Central Basin Platform and positions in New Mexico. This concentrates APA’s position in a few key areas that enable economies of scale in operations and provides sign | In addition, the Company has been able to make significant strides in reducing drilling, completions, and equipping and facility costs by leveraging these synergies while refining its development approach to its asset base. Improvements in its cost structure has enabled the Company to drill more wells on tighter and denser spacing and to moderate completion intensity.
  • Low prices have previously adversely affected and could from time to time in the future adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and a prolonged period of low prices could have a material adverse impact on the Company’s results of operations and cash flows and limit its ability to fund capital expenditures and return capital to its shareholders. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and | The Company’s ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, meet volume commitments under transportation services agreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity changes, the inability to procure and resell volumes economically, various transportation interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could
  • 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 increa | 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
  • 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 | 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.
  • 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.
  • 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 discipli | 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
  • 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 fo | 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.
Fritt kassaflöde
  • 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.
  • As of December 31, 2025, the Company’s consolidated subsidiaries are engaged in exploration, development and/or production activities across four operating segments: Egypt, North Sea, Suriname, and the U.S. The Company’s business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. | The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company’s Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is p | Financial information for each segment is presented below:
Likvida medel
  • 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:
  • (In millions) | Sources of Cash and Cash Equivalents: | Net cash provided by operating activities $ 4,545 $ 3,620 $ 3,129
  • Total Sources of Cash and Cash Equivalents 6,002 7,157 3,386 | Uses of Cash and Cash Equivalents:
  • 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)
  • 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)
  • 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.
  • 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.
Nettoskuld
  • • the integration of acquisitions; | • other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Annual Report on Form 10-K. | Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Annual Re
  • The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations. | Estimated Proved Reserves and Future Net Cash Flows | Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operati
  • Divestitures during 2025 of non-core producing properties in the U.S. reduced estimated proved reserves by approximately 19 MMboe. | The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2025, 2024, and 2023, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a | 10
  • APA’s Director of Reserves is the person primarily responsible for overseeing the Company’s reserves estimation and reporting process. He has a Bachelor of Science degree in Petroleum Engineering and over 40 years of experience in the energy industry. The Director of Reserves reports directly to the Company’s Vice President of Assurance. | The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review | The percentages of total estimated proved reserves values, calculated as future net cash flows discounted at 10 percent, and volumes, on a boe basis, covered by Ryder Scott’s reviews for the years 2025, 2024, and 2023 were:
  • The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review | The percentages of total estimated proved reserves values, calculated as future net cash flows discounted at 10 percent, and volumes, on a boe basis, covered by Ryder Scott’s reviews for the years 2025, 2024, and 2023 were:
  • 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 als | 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.
  • Sources of Cash and Cash Equivalents: | Net cash provided by operating activities $ 4,545 $ 3,620 $ 3,129 | Fixed-rate debt borrowings
  • 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.
Eget kapital
  • Accumulated other comprehensive income 10 12 | APA SHAREHOLDERS’ EQUITY | 6,093 5,280
Antal aktier
  • Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2025 $ 6,561,964,169 | Number of shares of registrant’s common stock outstanding as of January 31, 2026 | 353,251,476
  • 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
  • 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) 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. | 32
  • Diluted $ 3.99 $ 2.27 $ 9.25 | WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | Basic 359 353 308
  • Earnings Per Share | The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. | Stock-Based Compensation
  • Common Stock Outstanding | The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2025, 2024, and 2023:
Antal anställda
  • The Company’s reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted. | APA’s proved reserves are estimated at the property level and compiled for reporting purposes by a group of experienced reservoir engineers who interact with engineering and geoscience personnel in each of the Company’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel | APA’s Director of Reserves is the person primarily responsible for overseeing the Company’s reserves estimation and reporting process. He has a Bachelor of Science degree in Petroleum Engineering and over 40 years of experience in the energy industry. The Director of Reserves reports directly to the Company’s Vice President of Assurance.
  • HUMAN CAPITAL MANAGEMENT | Human Capital and Employees | APA’s ability to execute its strategy depends on attracting, developing, and retaining a skilled workforce. The Company focuses on employee health and safety, total rewards, development opportunities and community partnerships to support employee experience and performance.
  • APA’s ability to execute its strategy depends on attracting, developing, and retaining a skilled workforce. The Company focuses on employee health and safety, total rewards, development opportunities and community partnerships to support employee experience and performance. | As of December 31, 2025, APA employed approximately 1,791 full-time equivalent employees:
  • Employees | United States
  • France 2 | Total employees 1,791
  • APA is an equal opportunity employer and prohibits discrimination and harassment. Personnel actions are administered without regard to race, color, religion, sex, familial status, marital status, sexual orientation, gender identity or expression, pregnancy, age, national origin, disability status, genetic information, protected veteran status, or any other characteristic protected by law. | APA also maintains resources to support an inclusive work environment where employees are valued and able to thrive. | Talent
  • • Annual compliance training including antitrust, bribery, corruption, and the APA Code of Conduct; and | • Mandatory health, safety, and environmental training for field and offshore employees. | Total Rewards
  • Total Rewards | APA’s total rewards approach is designed to attract, motivate, and retain top talent by providing a robust compensation and benefits package that includes competitive base salary, industry-leading benefits and performance-driven incentives. To foster a stronger sense of ownership and align the interests of employees and shareholders, annual long-term incentive grants are provided to eligible employees under APA’s long-term incentive compensation program. Furthermore, the Company offers comprehen | • Comprehensive health insurance coverage offered to employees working an average of 20 hours or more each week;

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

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

For the fiscal year ended December 31 , 2025
or 

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

For the transition period from            to                  
Commission file number 1-40144
APA CORPORATION
(Exact name of registrant as specified in its charter)  

Delaware   86-1430562
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

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

Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock, $0.625 par value APA Nasdaq Global Select Market

Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes ☐ No ☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2025 $ 6,561,964,169  
Number of shares of registrant’s common stock outstanding as of January 31, 2026
353,251,476  

Documents Incorporated By Reference
Portions of the registrant’s definitive proxy statement relating to the registrant’s 2026 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS
 

Item   Page

PART I

1. BUSINESS
1

1A. RISK FACTORS
18

1B. UNRESOLVED STAFF COMMENTS
29

1C.
CYBERSECURITY
29

2. PROPERTIES
1

3. LEGAL PROCEEDINGS
31

4. MINE SAFETY DISCLOSURES
31

PART II

5.
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER  MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
32

6. SELECTED FINANCIAL DATA
33

7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
34

7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
56

8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
57

9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
57

9A. CONTROLS AND PROCEDURES
57

9B. OTHER INFORMATION
58

9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
58

PART III

10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
59

11. EXECUTIVE COMPENSATION
59

12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
59

13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
59

14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
59

PART IV

15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
60

16. FORM 10-K SUMMARY
62

 

i

FORWARD-LOOKING STATEMENTS AND RISKS
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this Annual Report on Form 10-K, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations and capital returns framework, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2025, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “target,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “predict,” “prospect,” “should,” “would,” or similar terminology or the negative of these terms, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:
• changes in local, regional, national, and international economic conditions;
• the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;
• the Company’s commodity hedging arrangements;
• the supply and demand for oil, natural gas, NGLs, and other products or services;
• production and reserve levels;
• drilling risks;
• economic and competitive conditions, including market and macro-economic disruptions resulting from trade tensions between the U.S. and other countries, armed conflicts, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);
• the availability of capital resources;
• capital expenditures and other contractual obligations;
• asset retirement and decommissioning obligations, including changes to applicable regulatory and industry standards, the timing of related activities, and potential obligations to decommission previously owned assets;
• currency exchange rates;
• weather conditions;
• inflation rates;
• the impact of changes in tax legislation;
• the impact of international or domestic trade policy changes, including tariffs, import/export controls, and sanctions;
• the availability of goods and services;
• the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
• legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
• liabilities, injunctive relief, corrective actions, or other adverse outcomes resulting from pending or future litigation, governmental investigations, regulatory proceedings, or alleged violations of laws, regulations, permits, or contractual obligations;
• market-related risks, such as general credit, liquidity, and interest-rate risks;
• the ability to retain and hire key personnel;
• property acquisitions or divestitures;
ii

• the integration of acquisitions;
• other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Annual Report on Form 10-K.
Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.

iii

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

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

GENERAL
APA Corporation (APA or the Company) is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and NGLs. The Company’s business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active development, exploration, and appraisal operations ongoing in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its consolidated subsidiaries.
The Company makes available, free of charge on its website at www.apacorp.com , its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after they are filed with, or furnished to, the SEC. The Company’s filings are also available at www.sec.gov . Information contained on, or accessible through, the Company’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
BUSINESS STRATEGY
APA maintains a diversified asset portfolio, including conventional and unconventional, onshore and offshore, oil and natural gas exploration and production interests, while offering global exploration opportunities. In the U.S., operations are primarily focused in the Permian Basin of West Texas. Internationally, the Company has conventional onshore assets in Egypt’s Western Desert, offshore assets on the U.K.’s Continental Shelf, and is currently progressing with an oil field development offshore Suriname targeting first production in 2028.
APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. Despite these uncertainties, the Company is focused on its longer-term objectives: (1) to remain committed to providing affordable, reliable, and responsibly produced energy; (2) to deliver top operational performance across safety, environmental responsibility, execution, and risk management measures; (3) to maintain financial discipline by managing costs, protecting the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (4) to build and grow a diverse and balanced high-quality portfolio with scale through acquisitions, exploration, and organic opportunities.
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs.
1

Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, APA has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. These transactions include:
• On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt. The acquired assets included approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. The Company was able to quickly advance on opportunities to reduce costs, improve capital efficiencies, leverage economies of scale, and expand the development inventory that formed the basis of the transaction value. This transaction complemented and enhanced APA’s asset base in the Permian Basin and its inventory of high quality, short-cycle opportunities.
• Throughout the remainder of 2024, APA closed on a series of transactions to sell non-core producing properties in the Permian Basin, East Texas Austin Chalk, and Eagle Ford plays, and non-core mineral and royalty interests in the Permian Basin. Proceeds of approximately $1.6 billion from these transactions were used primarily to reduce debt.
• During 2025, APA completed the sale of certain non-core assets and leasehold in the Permian Basin, reflecting a full exit from New Mexico. Final proceeds of $571 million were primarily used for debt reduction. Combined with the Callon transaction, the Company believes its acreage position and drilling opportunities are better streamlined for longer-term growth.
For a more in-depth discussion of the Company’s 2025 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

2

BUSINESS OVERVIEW
The following business overview further describes the Company’s exploration and production operations and activities by geographic region.
Operating Areas
APA’s business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea. APA also has active development, exploration, and appraisal operations in Suriname, as well as exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities.
The following table sets out a brief comparative summary of certain key 2025 data for each of the Company’s operating areas. Additional data and discussion are provided in Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

Production Percentage
of Total
Production Production
Revenue Year-End
Estimated
Proved
Reserves Percentage
of Total
Estimated
Proved
Reserves Gross
Wells
Drilled Gross
Productive
Wells
Drilled
(In MMboe) (In millions) (In MMboe)
United States 105.0  62  % $ 3,819  781  74  % 197  197 
Egypt (1)
53.3  31  % 2,637  176  17  % 98  71 
North Sea (2)
11.2  7  % 773  25  2  % —  — 
Suriname
—  —  % —  74  7  % —  — 
Total 169.5  100  % $ 7,229  1,056  100  % 295  268 

(1) The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 23 percent of 2025 production and accounted for 12 percent of year-end 2025 estimated proved reserves.
(2) Sales volumes from the Company’s North Sea assets for 2025 were 11.4 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings.
United States
In 2025, the Company’s U.S. oil and gas operations contributed approximately 62 percent of production, 53 percent of oil and gas revenues, and 74 percent of estimated year-end proved reserves. APA has access to significant liquid hydrocarbons across its 2.6 million gross acres (1.3 million net acres) in the U.S..
The Company’s U.S. producing assets are primarily located in the Permian Basin in West Texas, including the Midland and Delaware sub-basins. Examples of shale plays being developed within these sub-basins include the Spraberry, Bone Spring, Wolfcamp, Barnett, and Woodford. The Company operates approximately 4,000 gross oil and gas wells across its acreage, with additional interests in approximately 700 non-operated wells. APA also has legacy operations located offshore in the Gulf of America. Highlights of the Company’s operations in the U.S. include:
• Permian Basin The Permian Basin is a foundational asset for APA, providing the Company’s largest source of production and cash flow. Over the past two years, the Company has progressed on high-grading its scale of operations and localized knowledge through the Callon acquisition and exit from non-core holdings in the conventional Central Basin Platform and positions in New Mexico. This concentrates APA’s position in a few key areas that enable economies of scale in operations and provides significant flexibility in pacing of developmental and appraisal activity.
In addition, the Company has been able to make significant strides in reducing drilling, completions, and equipping and facility costs by leveraging these synergies while refining its development approach to its asset base. Improvements in its cost structure has enabled the Company to drill more wells on tighter and denser spacing and to moderate completion intensity.
Key assets in the Permian Basin include:
• Midland Basin APA holds approximately 406,000 gross acres (288,000 net acres) in the Midland Basin in West Texas. During 2025, the Company primarily targeted oil plays in the Spraberry and Wolfcamp shale formations, drilling 106 gross development wells in this basin with a 100 percent success rate.
3

• Delaware Basin APA holds approximately 217,000 gross acres (166,000 net acres) in the Delaware Basin of West Texas. During 2025, the Company drilled 84 gross development wells in this basin with a 100 percent success rate, primarily targeting the Bone Spring and Wolfcamp formations. Also during 2025, the Company divested certain of its non-core producing properties located in New Mexico.
• Legacy Assets APA holds approximately 1.7 million gross acres (0.7 million net acres) in legacy properties, of which approximately 513,000 gross acres are in the offshore waters of the Gulf of America. Consistent with the Company’s broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings provide additional monetization opportunities that continue to be evaluated. During 2025, the Company participated in the drilling of 7 gross development wells in this area with a 100 percent success rate.
• New Venture Assets APA holds approximately 325,000 gross acres (163,000 net acres) of undeveloped acreage on the North Slope of Alaska. During 2025, the Company and its partners announced preliminary results of an exploratory well in Alaska, confirming the successful discovery of a reservoir. A successful flow test of the well was announced in 2025, with the well averaging 2,700 b/d during the final flow period. The Company continues to evaluate data from the well, and further appraisal drilling will determine the ultimate size of the discovery.
The Company is committed to maintaining a safe and efficient level of activity as part of its planned capital investment program. For 2026, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves, subject to prevailing commodity prices. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserves economically.
U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies, as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.
APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g., WTI Houston, West Texas Sour (WTS), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’s objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts. These term contracts typically have a firm transportation commitment and often provide an opportunity for higher than prevailing market prices.
APA’s U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 152 Bcf of natural gas per year for the period from 2026 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, an average of 1.8 MMbbls of crude oil per year for the period from 2026 through 2028, and de minimis crude oil volumes in the year 2029, in each case, at variable, domestic and/or international, market-based pricing.
In order to satisfy certain delivery commitments, the Company purchases third-party natural gas and crude oil to sell and deliver under existing pipeline agreements and sales contracts. APA may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments.
For more information regarding the Company’s commitments, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations of this Annual Report on Form 10-K.
4

International
APA has two international locations with ongoing production operations:
• Egypt, which includes onshore conventional assets located in Egypt’s Western Desert; and
• the North Sea, which includes offshore assets based in the U.K.
Egypt APA has decades of exploration, development, and operations experience in Egypt and is the largest acreage holder in Egypt’s Western Desert. At year-end 2025, the Company held 7.5 million gross acres in six separate concessions. The Company’s acreage is primarily held under one merged concession agreement (MCA) that resulted from the ratification of a MCA in 2021 with the Government of Egypt and EGPC. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the concession. Approximately 76 percent of the Company’s gross acreage in Egypt is undeveloped, providing APA with considerable exploration and development opportunities for the future.
APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with EGPC and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and are reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves.
The APA subsidiary that is the sole Contractor under the MCA is owned by an APA-operated joint venture owned two-thirds by the Company and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).
The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Through the joint venture, Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company’s Egypt assets, including the one-third noncontrolling interest, contributed 31 percent of 2025 production and 17 percent of 2025 year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 23 percent of 2025 production and 12 percent of 2025 year-end estimated proved reserves.
In 2025, the Company drilled 45 gross development and 53 gross exploration wells in Egypt. A key component of the Company’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable the Company’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering three million acres, which has led to recent discoveries that build and enhance the Company’s drilling inventory in Egypt. The Company will continue to focus on driving efficiencies and managing costs under the MCA.
During 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations.
North Sea The Company has interests in approximately 176,000 gross acres in the U.K. North Sea. These assets contributed 7 percent of the Company’s 2025 production and approximately 2 percent of year-end 2025 estimated proved reserves.
5

The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). In 2011, the Company acquired Mobil North Sea Limited, which included operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. The Company also has a non-operated interest in the Nelson field acquired in 2011. In 2023, the Company suspended all new drilling activity in the North Sea. During 2024, the Company performed an economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined that expected returns did not economically support making investments required under the combined impact of the regulations and expects to cease production at its facilities in the North Sea prior to 2030. The Company’s investment program in the North Sea is now directed toward asset safety and integrity.
International Marketing   In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC pursuant to a gas sales agreement that establishes pricing based on a minimum realized price of $2.65 per MMBtu, with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement, which was effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil. In the periods prior to the current agreement, the natural gas production in Egypt was primarily sold to EGPC at an industry-pricing formula of $2.65 per MMBtu. Crude oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is sold and exported from one of two terminals on the northern coast of Egypt. Oil production sold to EGPC is sold at prices related to the export market .
The Company’s North Sea crude oil production is sold under term, entitlement volume contracts and spot variable volume contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, operated by Ancala Midstream Acquisitions Limited. Natural gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The condensate mix from the SAGE plant is processed further downstream. The split streams of propane, butane, and condensate are sold separately on a monthly entitlement basis at the Braefoot Bay terminal using index pricing less transportation.
Other International
New Ventures APA’s international New Ventures acreage provides exposure to new growth opportunities outside of the Company’s traditional core areas and provides higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins.
The Company has a joint venture agreement with TotalEnergies (formerly Total S.A.) to explore and develop Block 58 offshore Suriname. The Company holds a 50 percent working interest in exploration activities in Block 58, which comprises approximately 1.4 million gross acres in water depths ranging from less than 100 meters to more than 2,100 meters. TotalEnergies holds a 50 percent working interest in exploration activities in Block 58 as the operator. Key terms of the joint venture agreement provide for TotalEnergies to pay 50 percent of all exploration activities and a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation. For the first $10 billion of gross capital expenditures, TotalEnergies pays 87.5 percent, and the Company pays 12.5 percent; for the next $5 billion in gross expenditures, TotalEnergies pays 75 percent and the Company pays 25 percent; and for all gross expenditures above $15 billion, TotalEnergies pays 62.5 percent and the Company pays 37.5 percent. The Company will also receive various other forms of consideration, including a $75 million cash payment upon achieving first oil production and future contingent royalty payments from successful joint development projects.
In October 2024, the Company announced that its subsidiary reached a positive final investment decision for the first oil development, named GranMorgu, in Block 58 offshore Suriname. This development will include production from the Krabdagu and Sapakara oil discoveries. These fields, located in water depths between 100 and 1,000 meters, will be produced through a system of subsea wells connected to a floating production, storage and offloading (FPSO) unit located 150 km off the Suriname coast, with an oil production capacity of 220,000 b/d. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its four-year production plateau and will feature technology that minimizes greenhouse gas emissions. Total investment is estimated at $10.5 billion, with APA’s share of the investment subject to the existing joint venture agreement with TotalEnergies to carry a portion of Apache’s appraisal and development capital. Under the terms of the Block 58 PSCs, Staatsolie exercised its right to participate in the GranMorgu development and production for a 20 percent share. First oil is anticipated in 2028.
The Company is also the operator of Block 53 offshore Suriname and holds a 45 percent working interest in the block. The Company, through an extension granted in 2023, holds approximately 13,000 net undeveloped acres for its operated Baja discovery area. Evaluation of the area is ongoing.
6

During 2023, the Company signed a production-sharing contract for Block 6 offshore Uruguay covering approximately four million undeveloped acres, where it has an obligation to drill one exploration well. In February 2024, the Company also signed a production-sharing contract for Block 4 offshore Uruguay, covering approximately 1.2 million net undeveloped acres. The Company holds a 50 percent working interest in the project and is the operator.
The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.
Drilling Statistics
Worldwide in 2025, APA drilled or participated in drilling 295 gross wells, with 268 wells (91 percent) completed as producers. Historically, APA’s drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, the Company’s operations outside of the U.S. focus on a mix of exploration and development wells. In addition to wells completed during the year, at year-end 2025, a number of wells had not yet reached completion: 103 gross (97.8 net) in the U.S., 25 gross (25.0 net) in Egypt.
The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:

  Net Exploratory Net Development Total Net Wells
  Productive Dry Total Productive Dry (1)
Total Productive Dry Total
2025
United States —  —  —  146.5  —  146.5  146.5  —  146.5 
Egypt 27.5  25.0  52.5  42.3  2.0  44.3  69.8  27.0  96.8 

Total 27.5  25.0  52.5  188.8  2.0  190.8  216.3  27.0  243.3 
2024
United States —  —  —  152.7  —  152.7  152.7  —  152.7 
Egypt 16.0  20.0  36.0  45.5  2.0  47.5  61.5  22.0  83.5 

Total 16.0  20.0  36.0  198.2  2.0  200.2  214.2  22.0  236.2 
2023
United States —  —  —  78.4  —  78.4  78.4  —  78.4 
Egypt 24.0  24.0  48.0  66.1  7.7  73.8  90.1  31.7  121.8 
North Sea 1.2  —  1.2  —  —  —  1.2  —  1.2 
Other International —  0.3  0.3  —  —  —  —  0.3  0.3 
Total 25.2  24.3  49.5  144.5  7.7  152.2  169.7  32.0  201.7 

(1) No proved undeveloped reserves were included in reserves as of year-end 2024 for the 2.0 net dry development wells drilled in 2025. No proved undeveloped reserves were included in reserves as of year-end 2023 for the 2.0 net dry development wells drilled in 2024.
Productive Oil and Gas Wells
The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2025, is set forth below:

  Oil Gas Total
  Gross Net Gross Net Gross Net
United States 3,311  2,514  684  578  3,995  3,092 
Egypt 921  894  110  108  1,031  1,002 
North Sea 125  85  11  7  136  92 
Total 4,357  3,493  805  693  5,162  4,186 

Domestic 3,311  2,514  684  578  3,995  3,092 
Foreign 1,046  979  121  115  1,167  1,094 
Total 4,357  3,493  805  693  5,162  4,186 

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

  Production Average Lease
Operating
  Cost per Boe Average Sales Price
Oil NGL Gas Oil NGL Gas
Year Ended December 31, (MMbbls) (MMbbls) (Bcf) (Per bbl) (Per bbl) (Per Mcf)
2025
United States 45.8  27.8  187.8  $ 10.19  $ 65.71  $ 22.13  $ 1.02 
Egypt (1)
32.0  —  128.1  8.83  67.97  —  3.59 
North Sea (2)
8.8  0.5  11.4  34.03  69.31  43.59  12.03 
Total 86.6  28.3  327.3  11.36  66.92  22.71  2.36 
2024
United States 47.1  27.0  177.0  $ 11.33  $ 75.92  $ 22.83  $ 0.71 
Egypt (1)
32.6  —  106.5  9.70  80.41  —  2.94 
North Sea (2)
9.6  0.4  14.6  37.02  80.74  47.59  10.84 
Total 89.3  27.4  298.1  12.75  78.08  23.37  1.97 
2023
United States 28.8  23.0  165.1  $ 10.62  $ 77.84  $ 20.85  $ 1.80 
Egypt (1)
32.5  —  118.9  9.70  82.47  —  2.91 
North Sea (2)
12.7  0.4  18.3  25.34  82.75  47.77  13.02 
Total 74.0  23.4  302.3  11.95  80.72  21.54  2.91 

(1) Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
(2) Sales volumes from the Company’s North Sea assets for 2025 , 2024, and 2023 were 11.4 MMboe, 12.4 MMboe, and 16.6 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Gross and Net Undeveloped and Developed Acreage
The following table summarizes the Company’s gross and net acreage position by geographic area as of December 31, 2025:

  Undeveloped Acreage Developed Acreage
  Gross Acres Net Acres Gross Acres Net Acres

  (In thousands)
United States 2,075  955  564  392 
Egypt 5,737  5,737  1,769  1,721 
North Sea 17  12  159  123 
Suriname
1,470  734  —  — 
Other International 6,548  5,312  —  — 
Total 15,847  12,750  2,492  2,236 

As of December 31, 2025, the Company held approximately 5,000 net undeveloped acres in the U.S. that are scheduled to expire by year-end 2026 if production is not established or the Company takes no action to extend the terms. Nearly all of the Company’s U.S. acreage expiring in 2026 is in the Delaware Basin. The Company also held approximately 1,000 and 7,000 net undeveloped acres on its U.S. onshore acreage set to expire by year-end 2027 and 2028, respectively. As of December 31, 2025, approximately 81 percent of the U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights. The Company also has approximately 84,000 and 22,000 net undeveloped acres in Alaska set to expire by year-end 2027 and 2028, respectively, if no extension is granted.
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During 2025, the Government of Egypt awarded the Company an additional two million net undeveloped exploration acres in the Western Desert for a term of five years, expanding on the Company’s existing position in Egypt. The Company also holds undeveloped exploration acreage that was consolidated and extended in 2021 following ratification of the MCA with EGPC. The merged exploration acreage is scheduled to expire in 2026. The Company intends to pursue extensions of this acreage and may seek access to additional concession areas where it believes exploration potential exists. However, there can be no assurance that any such extensions or new access rights will be obtained on commercially acceptable terms, or at all, as these actions are subject to governmental approvals. No oil and gas reserves were recorded on undeveloped acreage set to expire.
The Company held approximately six million net undeveloped acres as of December 31, 2025, in other international locations. Exploration interests include Block 53 and Block 58 offshore Suriname and Block 4 and Block 6 offshore Uruguay. The Company continues to actively evaluate and analyze several discoveries on its Block 58 offshore Suriname exploration acreage with its operator partner, TotalEnergies. Approximately 720,000 net undeveloped acres in Block 58 have a current expiration date of June 2031 with an option to extend further.
The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.
Estimated Proved Reserves and Future Net Cash Flows
Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.
Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, APA uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.
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The following table shows proved oil, NGL, and gas reserves as of December 31, 2025, based on average commodity prices in effect on the first day of each month in 2025, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. The total column of this table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.

Oil NGL Gas Total

(MMbbls) (MMbbls) (Bcf) (MMboe)
Proved Developed:
United States 182  181  1,095  545 
Egypt (1)
102  —  371  164 
North Sea 22  1  13  25 

Total 306  182  1,479  734 
Proved Undeveloped:
United States 121  58  338  235 
Egypt (1)
8  —  28  13 

Suriname
74  —  —  74 
Total 203  58  366  322 
Total Proved 509  240  1,845  1,056 

(1) Includes total proved developed and total proved undeveloped reserves of 55 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
As of December 31, 2025, the Company had total estimated proved reserves of 509 MMbbls of crude oil, 240 MMbbls of NGLs, and 1.8 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.1 billion boe, of which liquids represent approximately 71 percent. As of December 31, 2025, the Company’s proved developed reserves totaled 734 MMboe and estimated proved undeveloped (PUD) reserves totaled 322 MMboe, or approximately 30 percent of worldwide total proved reserves. APA has elected not to disclose probable or possible reserves in this filing. The Company had one field that contained 15 percent or more of its total proved reserves for the year ended December 31, 2025. The Company had no fields that contained 15 percent or more of its total proved reserves for the years ended December 31, 2024 and 2023.
During 2025, the Company added approximately 100 MMboe from extensions, discoveries, and other additions. The Company recorded 72 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin primarily targeting the Spraberry, Bone Spring, and Wolfcamp producing horizons. The Company’s Egypt operations contributed 28 MMboe of exploration and development adds from onshore exploration and appraisal.
The Company realized combined upward revision of previously estimated reserves of 175 MMboe. Upward revisions related to pricing and interest totaled 37 MMboe, driven primarily by an increase in Permian Basin gas pricing. Engineering and well performance adjustments totaled 138 MMboe in the U.S. and Egypt. Upward revisions of 100 MMboe in the U.S. is related to changes to development plans and updates due to reservoir performance. Egypt realized positive revisions of 38 MMboe from gas infrastructure optimization and improved recovery projects.
Divestitures during 2025 of non-core producing properties in the U.S. reduced estimated proved reserves by approximately 19 MMboe.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2025, 2024, and 2023, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.
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Proved Undeveloped Reserves
The Company’s total estimated PUD reserves of 322 MMboe as of December 31, 2025, increased by 22 MMboe from 300 MMboe of PUD reserves reported at year-end 2024. During 2025, the Company converted 76 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 66 MMboe, with the remaining 10 MMboe in its international areas. The Company disposed of 2 MMboe related to PUD reserves divested during 2025. The Company added 62 MMboe of new PUD reserves through extensions. The Company also revised PUD reserves upward 41 MMboe as a result of updates to field development plans. Other downward revisions include 2 MMboe associated with interest changes and 1 MMboe associated with product prices.
During 2025, a total of approximately $546 million was spent on projects associated with proved undeveloped reserves. A portion of APA’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2025, the Company spent approximately $494 million on PUD reserve development activity in the U.S. and $52 million in Egypt. Additionally, the Company spent approximately $256 million in development and facility capital as part of the Suriname development during 2025. As of December 31, 2025, the Company had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.
Preparation of Oil and Gas Reserve Information
The Company’s reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.
APA’s proved reserves are estimated at the property level and compiled for reporting purposes by a group of experienced reservoir engineers who interact with engineering and geoscience personnel in each of the Company’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Annually, each property is reviewed in detail by our corporate and operating asset engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable. Reserves are reviewed internally with senior management and presented to APA’s Board of Directors in summary form on an annual basis.
APA’s Director of Reserves is the person primarily responsible for overseeing the Company’s reserves estimation and reporting process. He has a Bachelor of Science degree in Petroleum Engineering and over 40 years of experience in the energy industry. The Director of Reserves reports directly to the Company’s Vice President of Assurance.
The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year, and reserves volume. During 2025, the properties selected for all countries represented 87 percent of the total future net cash flows discounted at 10 percent. These properties accounted for 80 percent of the value of the Company’s domestic proved reserves and 100 percent of the value of the Company’s international proved reserves. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 82 percent of total proved reserves on a boe basis.
The percentages of total estimated proved reserves values, calculated as future net cash flows discounted at 10 percent, and volumes, on a boe basis, covered by Ryder Scott’s reviews for the years 2025, 2024, and 2023 were:

2025 2024 2023
Estimated proved reserves values 87  % 90  % 88  %

Estimated proved reserves volumes:
United States 80  % 80  % 83  %
Egypt 80  % 80  % 80  %
North Sea 84  % 95  % 90  %
Suriname
100  % 100  % —  %
APA Worldwide 82  % 82  % 83  %

11

The Company has filed Ryder Scott’s independent report as an exhibit to this Annual Report on Form 10-K.
According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by the Company, the overall procedures and methodologies utilized by the Company in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by the Company are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.
MAJOR CUSTOMERS
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2025, sales to EGPC in Egypt accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2024 and 2023, sales to EGPC accounted for approximately 17 percent and 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues.
Management does not believe that the loss of any single customer would have a material adverse effect on the results of operations.
HUMAN CAPITAL MANAGEMENT
Human Capital and Employees
APA’s ability to execute its strategy depends on attracting, developing, and retaining a skilled workforce. The Company focuses on employee health and safety, total rewards, development opportunities and community partnerships to support employee experience and performance.
As of December 31, 2025, APA employed approximately 1,791 full-time equivalent employees:

Employees
United States
1,061 
United Kingdom 486 
Egypt 242 
Suriname — 
France 2 
Total employees 1,791 

Oversight and Management
The Management Development and Compensation (MD&C) Committee and/or the full Board of Directors receive regular reports on human capital matters. The MD&C Committee also oversees compensation programs, leadership development, and succession planning. These activities support APA’s core values, which include health and safety, investment in the workforce, environmental responsibility, continuous improvement, and ethical conduct.
Equal Opportunity Employer
APA is an equal opportunity employer and prohibits discrimination and harassment. Personnel actions are administered without regard to race, color, religion, sex, familial status, marital status, sexual orientation, gender identity or expression, pregnancy, age, national origin, disability status, genetic information, protected veteran status, or any other characteristic protected by law.
APA also maintains resources to support an inclusive work environment where employees are valued and able to thrive.
Talent
APA’s talent strategy integrates recruitment and development to support organizational capability and leadership development and ingenuity.
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Recruitment uses technology and data-driven insights to identify talent globally and uses referrals and feedback to strengthen local sourcing.
APA also engages with educational institutions, industry networks, and professional organizations to access emerging talent and build relationships with industry professionals.
Beyond recruitment, the Company invests in talent development initiatives designed to build capability, strengthen leadership effectiveness, and reinforce a high-performance culture. These initiatives include continuous learning opportunities, skill enhancement programs, mentorship frameworks, and leadership development programs.
In 2025, APA emphasized leadership and culture initiatives. Senior leadership focused on strategic priorities and development of a strong corporate culture that reinforces shared values, collaboration, accountability, and continuous improvement.
Training and Development
Employee development is supported through training, performance management, and continuous feedback using in-person and virtual delivery.
2025 highlights included:
• Technical Excellence Initiative: Launched an initial framework defining technical capability expectations and progression pathways across critical disciplines with broader implementation planned for 2026.
• Individual Development Plan (IDP): Began implementing an IDP framework to identify development priorities, align learning activities with career aspirations, and track progress over time.
• Performance Management: Continued strengthening the program with increased emphasis on ongoing feedback and development conversations.
• Learning access: Expanded on-demand learning through multiple online learning platforms offering technical, leadership, and business acumen content.
• Succession planning: Remained a critical component of APA’s talent strategy including identifying key roles, assessing readiness, and targeted development actions.
• Additional development and training opportunities offered during the year included:
• Third-party online and in-person training programs;
• Ongoing education for people leaders aligned to leadership competencies;
• Leadership and personal development coaching by line managers;
• Annual cybersecurity training;
• Annual compliance training including antitrust, bribery, corruption, and the APA Code of Conduct; and
• Mandatory health, safety, and environmental training for field and offshore employees.
Total Rewards
APA’s total rewards approach is designed to attract, motivate, and retain top talent by providing a robust compensation and benefits package that includes competitive base salary, industry-leading benefits and performance-driven incentives. To foster a stronger sense of ownership and align the interests of employees and shareholders, annual long-term incentive grants are provided to eligible employees under APA’s long-term incentive compensation program. Furthermore, the Company offers comprehensive and locally relevant benefits that cultivate a family-friendly work environment and focus on the overall wellness of the Company’s employees. In the U.S. these include, among other benefits:
• Comprehensive health insurance coverage offered to employees working an average of 20 hours or more each week;
• 401(k) plan with up to an 8 percent Company match;
• 6 percent Company contributions to a money purchase retirement plan;
• Company-paid short-term disability that pays a percentage of base pay according to years of service;
13

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

Global Primary Workforce Safety Metrics

Total Recordable Incident Rate (TRIR) (1)
0.13 35% below target of 0.20

Severe Incident Rate (SIR) (2)
0.0 100% below target of 0.010

US Flaring Intensity (3)
0.84 16% below target of 1.0

(1) Total Recordable Incident Rate (TRIR): The rate of recordable injuries sustained by employees, contractors, or both that occur per 200,000 hours worked.
(2) Severe Incident Rate (SIR): The rate of incidents resulting in fatal injury, permanent or significant loss or impairment of a body part or organ function, or that otherwise permanently change or disable individuals in their normal life activity, per 200,000 hours worked.
(3) Flaring Intensity: The volume of gas flared per volume of gas produced expressed as a percent.
Community Partnerships
APA is committed to being a responsible partner in the communities where it operates. The Community Partnerships group oversees the Company’s global strategic community engagement, including the stewardship of key stakeholder relationships.
APA’s global giving strategy is focused on three pillars: Community Well-being, Environmental Stewardship, and Access to Energy, through which the Company creates sustainable and positive impacts. Based on these pillars, APA is committed to addressing acute needs within the local communities where it operates; ensuring that it remains focused on its long-standing legacy and commitment to environmental stewardship and conservation; and supporting communities that lack access to reliable, affordable energy.
• Community Well-being: APA continues to partner with organizations within the communities in which it operates to improve quality of life through access to education and essential medical supplies; development of innovative healthcare technologies and procedures; support for vulnerable populations; response to natural disasters; and support for first responders.
• Environmental Stewardship: In 2025, the Company’s environmental stewardship initiatives included grants of more than 16,000 trees to community partners in the U.S. and U.K. through the Apache Corporation Tree Grant Program. The Company also continued its partnership with the Texas Wildlife Association Foundation to support environmental education programs and provided multi-year support to the Pecos Watershed Conservation Initiative, an alliance of seven energy companies, in partnership with the National Fish and Wildlife Foundation, focused on restoring and protecting natural grasslands and habitats within the greater Trans-Pecos region.
• Access to Energy: In 2025, the Company continued to support access to affordable, reliable energy through its partnership with Switch Energy Alliance, a Houston-based nonprofit focused on energy education, workforce development, and informed energy dialogue. The Company’s support helped advance Switch Energy Alliance’s programming that increases understanding of energy systems, energy access challenges, and the role of diverse energy solutions in supporting economic development and quality of life in energy-impacted communities.
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APA also provides employees with volunteer service opportunities in collaboration with its Community Partnerships program. The Company seeks meaningful volunteer opportunities that instill a sense of pride, ownership, and accomplishment for employees in their communities. As community needs change and stakeholder engagement continues, APA continues to adjust its charitable giving program.
OFFICES
The Company’s principal executive offices are located at 2000 W. Sam Houston Pkwy. S., Suite 200, Houston, Texas 77042-3643. As of year-end 2025, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. The Company’s primary office space is leased. The current lease on the Company’s principal executive offices runs through December 31, 2038, subject to the lessee’s option to extend the term by up to 20 years. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
TITLE TO INTERESTS
As is customary in the oil and gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time the Company acquires properties. The Company believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Company’s operations. The interests owned by the Company may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.
ADDITIONAL INFORMATION ABOUT THE COMPANY
Response Plans and Available Resources
The Company’s subsidiaries maintain oil spill response plans (the Plans) for their respective offshore operations in the Gulf of America and the North Sea, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Emergency preparedness exercises are conducted to measure and maintain the effectiveness of the Plans.
The Company’s subsidiary, Apache, is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any affiliated entity worldwide to access OSRL’s services. OSRL maintains aircraft available for global dispersant application and has active recovery boom systems that can be used for offshore, nearshore, or shoreline responses. In addition to the services and equipment provided to all members of OSRL, the Company maintains membership to supplementary services from OSRL, including the U.K. Continental Shelf (UKCS) Aerial Surveillance, OSPRAG Capping Stack, and Dispersant Stockpile, providing equipment and services specifically tailored for an emergency response in the North Sea.
In the event of a spill in the Gulf of America, Clean Gulf Associates (CGA) is the primary oil spill response organization available to the Company. Apache is a member of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of America. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of America. CGA equipment includes skimming vessels, barges, boom, and dispersants.
Additionally, the Company has contracted with Wild Well Control Company for contingency planning for and response to uncontrolled subsea well events and other drilling activities. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control’s containment system capping stacks.
15

Competitive Conditions
The oil and gas industry is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment, and personnel required to find and produce reserves, and the gathering and marketing of oil, gas, and NGLs. The Company’s competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.
Certain of the Company’s competitors may possess financial or other resources substantially larger than the Company possesses or have established strategic long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for leases or drilling rights.
However, the Company believes its diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across multiple geographic areas, its balanced production mix between oil and gas, its management and incentive systems, and its experienced personnel give it a strong competitive position relative to many of the Company’s competitors who do not possess similar geographic and production diversity. The Company’s global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which it has producing operations to which it can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. This also reduces the risk that the Company will be materially impacted by an event in a specific area or country.
Governmental Regulation
The Company’s U.S. operations are subject to federal, state, and local laws and regulations, including restrictions on production, changes in taxes and other amounts payable to governments, price or gathering rate controls, environmental protection laws and regulations, standards for drilling, completing, and equipping oil and gas wells, standards for plugging, abandonment, decommissioning, and site restoration activities, and security for plugging, abandonment, and decommissioning obligations, including in the Gulf of America. For discussions of the risks the Company faces related to regulation, see the information set forth under “Risks Related to Governmental Regulation and Political Matters,” “Risks Related to Climate Change, Energy Transition, and ESG Matters,” and “Risks Related to International Operations” in Item 1A―Risk Factors .
Regulatory requirements affecting the Company’s operations are frequently proposed, revised, delayed, challenged in litigation, enjoined or stayed by courts, withdrawn by agencies, or modified through subsequent administrative and legislative actions, including in the U.S. through the use of the Congressional Review Act. As a result, the scope, timing, and practical impact of regulatory change can be difficult to predict and may change rapidly, including across election cycles and as agencies adjust enforcement priorities.
Hydraulic Fracturing Regulation
The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for oil and natural gas to migrate toward the wellbore, typically at substantial depths in formations with low permeability. Governmental entities have previously taken actions to regulate hydraulic fracturing. These activities and the associated water disposal activities are under scrutiny due to their potential environmental and physical impacts, including possible water contamination and possible links to induced seismicity.
Climate Change
Due to climate change concerns, numerous proposals to monitor and limit emissions of greenhouse gas (GHG) have been made and are likely to continue to be made at the federal, state, and local levels of government and by the governments of other nations. There has been discussion in countries where the Company operates, including the U.S., regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions, or to assess a charge on methane emissions in the oil and gas industry.
In the U.S., regulatory activity related to methane and GHG emissions has included, and is expected to continue to include, changes to monitoring, reporting, leak detection and repair, flaring, and emissions control requirements applicable to oil and gas operations. For example, the U.S. Environmental Protection Agency (EPA) has adopted and/or proposed revisions to methane and volatile organic compound standards for new and existing sources in the oil and gas sector, and the EPA’s Greenhouse Gas Reporting Program has been subject to ongoing rulemaking activity, including recent activity to reduce the
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reporting for petroleum and natural gas systems. In addition, the Inflation Reduction Act of 2022 established a Methane Emissions Reduction Program that contemplates the assessment of a “waste emissions charge” for certain methane emissions from facilities already subject to reporting requirements, which has been delayed until 2034. Additionally, on February 12, 2026, the EPA finalized a rescission of the 2009 Endangerment Finding for GHGs under Section 202(a) of the Clean Air Act; this action, and any resulting legal challenges or subsequent governmental actions, could affect the broader regulatory landscape and related compliance expectations. Further, these developments, and related state implementation actions, could increase compliance costs, require additional capital expenditures, and result in operational constraints, including with respect to measurement and monitoring, equipment retrofits, and flaring practices.
Additionally, various states and groups of states have adopted, and others continue to consider adopting, legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company’s operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications, including as a result of recent federal actions to reconsider and rescind certain GHG-related regulatory determinations and standards, which may create regulatory uncertainty and result in increased state-level and litigation activity. Certain jurisdictions have also adopted or proposed climate-related disclosure or supply-chain reporting regimes, which could increase compliance and reporting costs and, depending on applicability, require additional processes, controls, and assurance.
Endangered or Protected Species
The Company’s operations in its operating areas could be adversely impacted by seasonal, periodic, or permanent restrictions or limitations relating to oil and gas operations to protect certain wildlife with habitats or migratory paths within such operational areas. Such restrictions or limitations can include, without limitation, prohibited drilling and development activity in certain areas or restricted activities during specific seasons or the employment of costly mitigation measures. New designations of previously unprotected species as threatened, endangered, or protected species could cause the Company to incur significant additional costs to implement required protective measures or could limit the Company’s ability to effectively and efficiently develop and produce reserves.
Treatment and Disposal of Produced Water Regulation
The treatment and disposal of produced water is highly regulated and restricted. Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection) and to require the monitoring of seismic activity. While the Company remains focused on reusing or recycling water over disposal of water, the Company’s costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical.
Environmental Compliance
As an owner or lessee and operator of oil and gas properties and facilities, the Company is subject to numerous federal, state, local, and foreign laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry as a whole, the Company does not expect that these requirements will affect it differently, to any material degree, than other companies in the oil and gas industry; however, the Company’s compliance costs and operational constraints may increase as requirements evolve.
The Company has made and will continue to make expenditures in its efforts to comply with these requirements, which the Company believes are necessary business costs in the oil and gas industry. The Company has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to its operations in all countries in which it does business. The Company has established operating procedures and training programs designed to limit the environmental impact of its field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that the Company is unable to separate expenses related to environmental matters; however, the Company does not currently expect that compliance with existing environmental laws and regulations will have a material adverse impact on its capital expenditures, earnings, or competitive position, though future regulatory changes could increase the Company’s costs and capital requirements.
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ITEM 1A. RISK FACTORS

The Company’s business activities and the value of its securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA’s securities could lose part or all of their investments. Additional risks and uncertainties not presently known to the Company or that the Company currently considers immaterial may also adversely affect the Company.
RISKS RELATED TO COMMODITY PRICES, DEMAND, AND PRODUCTION
Crude oil, natural gas, and NGL prices and their volatility could adversely affect the Company’s operating results and the price of APA’s common stock.
The Company’s revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2025 ranged from a high of $80.73 per barrel to a low of $55.44 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2025 ranged from a high of $9.86 per MMBtu to a low of $2.65 per MMBtu.
The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company’s control, including:
• demand, which fluctuates with changes in market and economic conditions;
• worldwide and domestic supplies and/or inventories of crude oil, natural gas, and NGLs and the availability of related pipeline, transportation, import/export, and refining capacity and infrastructure;
• actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);
• political conditions and events in oil and gas producing regions, including instabilities, changes in governments, or armed conflicts;
• the price, competitiveness, decision to use, and availability of alternative fuels and energy sources, including coal, biofuels, and renewables;
• increased competitiveness of, and demand for, alternative energy sources;
• technological advances affecting energy supply and energy consumption, including those that alter fuel choices;
• the availability of pipeline capacity and infrastructure;
• the availability of crude oil transportation and refining capacity;
• weather conditions;
• the impact of political pressure and the influence of environmental groups, investors, and other stakeholders on decisions and policies related to the oil and gas industry, including with respect to environmental, social, and governance matters;
• the timing, scope, implementation, and potential judicial review of energy transition and climate-related policies and regulations (such as methane fees, emissions reporting requirements, carbon pricing mechanisms, and other climate-related measures);
• domestic and foreign governmental regulations and taxes, including changes or initiatives to address the impacts of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and
• the overall economic environment, including rates of growth, trade tensions, and increasing inflationary pressure.
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Low prices have previously adversely affected and could from time to time in the future adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and a prolonged period of low prices could have a material adverse impact on the Company’s results of operations and cash flows and limit its ability to fund capital expenditures and return capital to its shareholders. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs could also further adversely impact the Company’s business, including by weakening the Company’s financial condition and reducing its liquidity, limiting the Company’s ability to fund planned capital expenditures and operations, causing the Company to delay or postpone some of its capital projects or reallocate capital to different projects or regions, limiting the Company’s access to sources of capital, such as equity and long-term debt, or reducing the carrying value of the Company’s oil and gas properties, resulting in additional non-cash impairments.
The Company’s ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, meet volume commitments under transportation services agreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity changes, the inability to procure and resell volumes economically, various transportation interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.
A portion of the Company’s crude oil, natural gas, and NGL production in any region may be, and previously have been, interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, cyberattacks or terrorist events, or capital constraints, financial distress, or insolvency of third-party providers that limit the ability of such third parties to construct gathering systems, processing facilities, or interstate pipelines to transport the Company’s production. Additionally, the Company has previously and may in the future voluntarily curtail production in response to market conditions, such as weak or negative prices. If a substantial amount of the Company’s production is interrupted or curtailed at the same time, it could temporarily adversely affect the Company’s cash flows. Further, if the Company is unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, the Company’s cash flows could be adversely affected. As additional gas pipeline takeaway capacity in the Permian Basin comes online, the spread between Permian and Gulf Coast gas prices may compress, which would reduce the Company’s gain on third-party oil and gas purchases and sales.
The Company’s commodity price and other risk management and trading activities, including interest rate and foreign exchange hedging, and contracts priced in foreign currencies may prevent it from benefiting fully from price increases and market movements and may expose it to other risks.
To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases. Similarly, to the extent the Company enters into derivative contracts to manage exposure to interest rate or foreign exchange risk or enters into contracts priced in a foreign currency, it may be limited in its ability to benefit from favorable movements in interest rates or currency exchange rates or may incur additional expense converting to a foreign currency to fund contractual obligations. The Company’s hedging arrangements may expose it to the risk of financial loss, including when production falls short of the hedged volumes, price-basis differentials widen, a hedging counterparty defaults, or an unexpected event materially impacts commodity prices. In addition, because the Company does not apply hedge accounting to its derivative instruments, changes in the fair value of derivatives are recognized in current-period earnings, which may introduce earnings volatility even when the underlying exposure is intended to be economically hedged.
Public health events, workforce disruptions, or similar global or regional events have previously and may in the future adversely impact the Company’s business, financial condition, and results of operations.
Public health events, including related workforce availability constraints, travel restrictions, supply chain disruptions, or government-mandated operational limitations, have previously adversely impacted and may from time to time in the future adversely impact the global economy, cause significant volatility in financial markets, and reduce the demand for, and the prices of, oil, natural gas, and NGLs, which may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations.
RISKS RELATED TO OPERATIONS, SAFETY, AND EXPLORATION AND DEVELOPMENT PROJECTS
The Company’s operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of property, and environmental accidents.
The Company’s operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including well blowouts, explosions, fires, cratering, pipeline or other facility ruptures and
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spills, adverse weather conditions, including those impacting the Company’s offshore operating areas, surface spillage and ground water contamination, and failure or loss of equipment. These events, including ineffective containment of such events, have previously and could in the future result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. If a significant amount of the Company’s production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company’s cash flows and, in turn, its results of operations could be materially and adversely affected.
The Company has previously not realized, and may in the future not realize, an adequate return on wells that it drills.
Drilling for oil and gas involves numerous risks, including that the Company may not encounter commercially productive oil or gas reservoirs or may not recover all or any portion of its investment in the wells it drills. Management has previously determined, and may in the future determine, that wells or development projects have failed to meet expected economic thresholds because of drilling results, cost inflation, commodity price volatility, revised development plans, demand for oil, natural gas, and NGLs, or other information, and in such cases, the Company may elect not to pursue or complete those activities. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations are subject to a variety of risks, including unexpected drilling conditions (such as pressure or formation irregularities), equipment failures or accidents, catastrophic events, marine risks, adverse weather conditions, and increases in the cost of or shortages or delays in the availability of drilling rigs, equipment, and labor. In addition, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Any such events could have an adverse effect on the Company’s future results of operations and financial condition. Exploration costs and dry hole expenses incurred by the Company during the reporting period are further discussed in this Annual Report on Form 10-K and reflected in the consolidated financial statements included herein.
Frontier exploration and development projects, including those in new or re-entered jurisdictions, involve heightened operational, regulatory, and execution risks that could adversely affect the Company’s results of operations and financial condition.
The Company’s exploration and development portfolio includes higher‑risk frontier opportunities, including in Alaska and offshore Suriname and Uruguay, which may involve extended timelines, complex permitting and stakeholder processes, logistical constraints, and heightened regulatory scrutiny. Operations in new countries or areas where the Company has limited recent operating history may also require the establishment or reestablishment of local relationships, workforce and supply chains, regulatory familiarity, and infrastructure, and may expose the Company to unfamiliar legal frameworks, fiscal regimes, community engagement expectations, and political dynamics.
Delays or adverse outcomes in permitting, litigation (including parties seeking legal or equitable relief to prevent or otherwise limit exploration activities, such as for the acquisition of seismic data or for drilling operations), appraisal drilling, or commercial development decisions could result in the deferral, impairment, or partial or complete loss of anticipated value of exploration, development, and production assets and the recognition of additional exploration expense. In addition, unanticipated technical, geological, operational, or regulatory challenges in such jurisdictions could increase capital requirements, extend project timelines, or adversely affect the commercial viability of these projects. These risks may be amplified in jurisdictions where regulatory regimes are evolving or where litigation or public opposition to offshore exploration activities has increased.
The Company’s insurance policies do not cover all of the risks the Company faces, which could result in significant financial exposure.
Exploration for and production of crude oil, natural gas, and NGLs involves hazards, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company’s international operations are also subject to political and economic risks. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks. While certain insurance policies of the Company may provide coverage for such events, if the Company were to incur a significant liability for which it was not fully insured, then it could have a material adverse effect on the Company’s financial position, results of operations, and cash flows. In addition, if such an event were to occur, then the proceeds of any such insurance may not be paid in a timely manner or may not be sufficient to cover all of the Company’s losses.
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A cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company’s operations.
There are numerous and evolving risks to the Company’s data, technology, and information systems from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage, and employee malfeasance. The Company’s operations are dependent on digital technologies, including to estimate reserves, process financial and operating data, analyze drilling information, and communicate with personnel. Unauthorized access to the Company’s data, technology, and information systems could lead to operational disruption, communication interruption, disruption in access to financial reporting systems, and loss, misuse, or corruption of data and proprietary information. In addition, unauthorized access to third party information systems could interrupt the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company’s production. Cyberattacks directed at oil and gas distribution systems have previously and could again in the future damage critical distribution and storage assets or the environment. The potential impacts of a cyber incident could be made worse by a delay or failure to detect the occurrence, continuance, or extent of such an incident.
The Company may be required to expend further resources to protect its digital systems and data as cyber threat actors become more sophisticated and as regulations related to cyberattacks become more complex. Cyberattacks, including malicious software, data privacy breaches by employees, insiders, or others with authorized access to the Company’s systems, cyber or phishing attacks, ransomware attacks, supply chain vulnerabilities, business email compromises, other attempts to gain unauthorized access to the Company’s data and systems, and other electronic security breaches could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.
While the Company has not suffered any material losses as a result of cyberattacks, there is no assurance that the Company will not suffer such losses in the future. See I tem 1C — Cy bers ecurity for additional information regarding the Company’s cybersecurity risk management and governance.
Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects.
The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, cost inflation, availability, manufacturing, and delivery schedules of critical vessels and equipment, customs and logistics, cash-call timing or funding shortfalls, and other unforeseen events. Delays and differences between estimated and actual timing of critical events and development costs (including for equipment and personnel) may adversely affect the Company’s large development projects (including forcing the Company to abandon such projects) and its ability to participate in large-scale development projects in the future.
RISKS RELATED TO RESERVES, ESTIMATES, AND LEASEHOLDS
Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.
The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, future oil and gas production is highly dependent upon the Company’s level of success in adding reserves through exploration and development activities, identifying additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquiring additional properties containing proved reserves. As oil or natural gas prices increase, the Company’s cost for additional reserves could also increase.
The Company may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. There can be no assurance that acquisitions will not adversely impact the Company’s operating results, particularly during their integration into the Company’s ongoing operations.
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Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.
There are numerous uncertainties inherent in the process of estimating crude oil, natural gas, and NGL reserves and their value, which is highly subjective and relies on the quality of available data and the accuracy of engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist, consistent with applicable SEC pricing and reporting rules. Therefore, changes in future commodity prices or in development plans can materially impact reported reserves. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including historical production from the area compared with production from other areas, the results of drilling, testing, and production for a reservoir over time, the use of volumetric analysis versus production history, the effects of changes in laws (including emissions regulations, infrastructure modernization requirements, and taxes), future operating, workover, and remediation costs, and capital expenditures. For example, during 2024, the Company recorded $796 million of impairments for certain of its North Sea proved properties as a result of several new regulatory guidelines and obligations in the U.K. Accordingly, reserves estimates may be subject to adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Certain of the Company’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
A sizable portion of the Company’s acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company’s drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
RISKS RELATED TO COUNTERPARTIES AND JOINT VENTURES
The credit risk of financial institutions could adversely affect the Company and result in a significant loss.
The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions, including in the form of derivative transactions in connection with any hedges and claims under the Company’s insurance policies, which expose the Company to credit risk in the event of default of the counterparty. Deterioration or volatility in the credit or financial markets, changes in commodity prices, and changes in a counterparty’s liquidity may affect the counterparties’ ability to fulfill their existing obligations to the Company. In addition, if any lender under the Company’s credit facilities is unable to fund its commitment, the Company’s liquidity may be reduced by an amount up to the aggregate amount of such lender’s commitment thereunder. Furthermore, the bankruptcy of one or more of the Company’s counterparties or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities, and the Company could incur a significant loss.
The distressed financial conditions of the Company’s partners and the purchasers of the Company’s products or assets have had and could have an adverse impact on the Company in the event they are unable to reimburse the Company for their share of costs or to pay the Company for the products or services the Company provides.
The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. As a result of previous severe declines in commodity prices, some of the Company’s customers and non-operating partners experienced severe financial problems. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company (including as a result of their filing for bankruptcy or other liquidity constraints) or that such a default or defaults will not have a material adverse effect on the Company’s business, financial position, future results of operations, or future cash flows.
The Company’s liabilities, including for the decommissioning of previously owned assets, could be adversely affected in the event one or more of its transaction counterparties are financially distressed or become the subject of a bankruptcy case.
The agreements relating to the Company’s divestment of domestic and international assets generally contain provisions pursuant to which liabilities related to past and future operations (one of the most significant of which is the decommissioning
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of wells and facilities) are allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, surety bonds, letters of credit, and similar arrangements. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress or bankruptcy, which may force the Company to use available cash to cover the costs of such obligations, pending final resolution of any claims the Company may have against the counterparty, which could adversely impact the Company’s cash flows, operations, or financial condition.
For additional information regarding Apache’s prior Gulf of America properties and the bankruptcy of the purchaser of those properties, see the information set forth under “Potential Decommissioning Obligations on Sold Properties” in Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
The Company does not always control decisions made under joint operating agreements or joint ventures, and the parties to such agreements or ventures may fail to meet their obligations.
The Company conducts many of its exploration and production (E&P) operations through joint operating agreements or joint ventures with other parties, including state-owned or government-controlled entities. The Company may not control decisions made under such agreements or ventures, either because it does not have a controlling interest in the venture or is not an operator under the agreement. The other parties to these arrangements may have economic, business, or legal interests or goals that are inconsistent with the Company’s, including priorities set by governmental or state-owned counterparties, or that are influenced by governmental policy, fiscal priorities, or broader economic or social conditions, which may affect decision making, capital allocation, payment timing, or operational approvals. Therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to such agreements or ventures may be unable to meet their economic or other obligations, and the Company may be required to fulfill those obligations alone. In either case, the value of the investment and the Company’s business and financial condition may be adversely affected.
RISKS RELATED TO CAPITAL MARKETS, LIQUIDITY, AND TAX MATTERS
A downgrade in the Company’s credit rating could negatively impact its cost of and ability to access capital.
The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company’s credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company’s ability to access debt markets in the future and increase the cost of future debt. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.
Market conditions may restrict the Company’s ability to obtain funds for future development and working capital needs, which may limit its financial flexibility.
The financial markets are subject to fluctuation and are vulnerable to unpredictable swings. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company’s future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained or if financial institutions, investors, or insurers limit exposure to oil and gas companies or modify underwriting standards in response to climate-related or other policy developments. This could significantly delay development of the Company’s property interests.
The Company’s syndicated revolving credit facilities currently mature in January 2030. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to the Company or its subsidiaries or the composition of such lenders.
The Company’s ability to declare and pay dividends, and to repurchase common stock, is subject to limitations.
The payment of future dividends on, and any repurchases of, the Company’s common stock are each subject to the discretion of the Board of Directors, taking into consideration, among other factors, the Company’s operating results, available cash, overall financial condition, credit risks, capital requirements, restrictions under the Company’s indentures and other financing agreements, restrictions under Delaware law, general business and market conditions, and other factors the Board of Directors deems relevant. The Board of Directors is not required to declare dividends on or repurchase APA’s common stock and may decide not to declare dividends or repurchase common stock at the current rate or at all. Any downward revision in the
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amount of dividends the Company pays to shareholders, or reduction in the pace of share repurchases, could have an adverse effect on the market price of the Company’s common stock.
Actions by advocacy groups to advance climate change and energy transition initiatives, unfavorable ESG ratings, and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from companies in the oil and gas industry, which could negatively impact the Company’s access to and costs of capital or the market for the Company’s securities.
Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Unfavorable ESG ratings may lead to negative investor and public sentiment toward the Company, which may cause the market for the Company’s securities to be negatively impacted.
In addition, a number of advocacy groups have campaigned for governmental and private action to influence change in the business strategies of oil and gas companies, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These campaign efforts have resulted in the divestment of investments in the oil and gas industry and increased pressure on lenders and other financial services companies to limit or curtail activities with oil and gas companies. If investors or financial institutions shift funding away from companies in the oil and gas industry, the Company’s access to and costs of capital or the market for the Company’s securities may be negatively impacted.
The Company faces strong industry competition that may have a significant negative impact on the Company’s results of operations.
Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes for leases, equipment, labor, key personnel, and marketing of crude oil, natural gas, and NGL production, the prices of which impact the costs of properties and the financial resources available to pursue acquisitions. These competitive pressures may have a significant negative impact on the Company’s results of operations.
The Company’s ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.
As described in Note 9—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company’s equity ownership by five-percent shareholders over a three-year period, the Company’s ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company’s operating results or cash flows.
The Company’s ability to realize its deferred tax assets may be limited if it experiences changes in expected future cash flows related to reserves or ARO.
As described in Note 9—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, the Company assesses the realizability of its deferred tax assets based on its ability to generate sufficient future taxable income. Future changes in expected cash outflows for ARO or inflows from reserves could impact the Company’s ability to realize its deferred tax assets in future periods.
APA is a holding company and is dependent on the operations of and distributions from its subsidiaries, including Apache.
As a holding company, APA has no business operations of its own, and its primary assets are its ownership interests in its subsidiaries, including Apache. As a result, APA relies on cash flows from its subsidiaries to pay dividends on, and make repurchases of, its common stock and to meet its financial obligations, including to service any amounts outstanding under its notes, debentures, credit agreements or commercial paper program, and any additional financial obligations that the Company may incur from time to time in the future. If the subsidiaries are limited in their ability to distribute cash to the Company, such as through legal or contractual limitations, or if the subsidiaries’ earnings or other available assets are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary to meet the Company’s financial obligations, then the Company’s financial condition, cash flows, and reputation may be materially adversely affected.
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