AddedRisk Factors
The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company’s control, including:
The 10-K against last year's
188 changes: 39 added, 27 removed, 122 reworded
10-K 0001841666-26-000015 (2026-02-26) vs 10-K 0002040266-25-000007 (2025-02-28) Not compared: Legal Proceedings, Accounting Policies.
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The paragraph that changed most in each section
Marked against last year's 10-K:
cut words struck through, new words highlighted and underlined.
Risk Factors 207 words changed in this paragraph; it is 47% similar to last year's version.
The Company’s operations outside the U.S. are based primarily in Egypt and the U.K., with significant exploration exploration, appraisal, and appraisal development activities offshore Suriname. Suriname, which involve long-cycle projects with significant capital requirements and are subject to host-government approvals and fiscal and contractual frameworks that may evolve over time. On a barrel equivalent basis, approximately 38 percent of the Company’s 2024 2025 production was outside the U.S., and approximately 28 26 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2024, 2025, were located outside the U.S. As a result, a significant portion of the Company’s production and resources are subject to the increased political and economic risks and other factors associated with international operations, including, but not limited to strikes and civil unrest; war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts; import and export regulations; taxation policies and investment restrictions; price controls; exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds; constrained oil or natural gas markets dependent on demand in a single or limited geographical area; laws and policies of the U.S. affecting foreign trade, including trade sanctions and tariffs; the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates; the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and difficulties in enforcing the Company’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. to:
Source: Item 1A, 10-K 0001841666-26-000015 vs Item 1A, 10-K 0002040266-25-000007
MD&A 146 words changed in this paragraph; it is 36% similar to last year's version.
•In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC, primarily under an industry-pricing formula, EGPC pursuant to a sliding scale gas sales agreement that establishes pricing based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum realized price of $2.65 per MMBtu, plus with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement was effective beginning January 2025. In the periods prior to the current agreement, the natural gas production in Egypt was primarily sold to EGPC at an upward adjustment for liquids content. industry-pricing formula of $2.65 per MMBtu. Overall, the Company’s Egypt operations averaged $2.94 $3.59 per Mcf in 2024, 2025, a one 22 percent increase from an average of $2.91 $2.94 per Mcf in 2023. In the fourth quarter of 2024, the Company entered into a new gas sales agreement, which could result in improved pricing if certain production thresholds are met. The new gas sales agreement, which is effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil. 2024.
Source: Item 7, 10-K 0001841666-26-000015 vs Item 7, 10-K 0002040266-25-000007
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Sentences and paragraphs of APA's Risk Factors and MD&A, 10-K 2026-02-26 against 10-K 2025-02-28. Each links to the text at sec.gov.
Quiet changes are sentences kept from last year with one to four words changed, at least one of them a hedge, a modal or a qualifier (may, could, will, not, significant, material…). A year or date rolling forward is not counted.
The full word list
adverse, adversely, all, although, anticipate, anticipates, any, approximately, believe, believes, can, cannot, certain, could, expect, expects, generally, however, if, intend, intends, largely, likely, many, material, materially, may, might, most, must, never, no, not, possible, primarily, probable, should, significant, significantly, some, substantial, substantially, unlikely, will, wouldAddedRisk Factors
•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);
AddedRisk Factors
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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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.
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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.
AddedRisk Factors
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.
AddedRisk Factors
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
AddedRisk Factors
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.
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AddedRisk Factors
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.
AddedRisk Factors
The Company is subject to extensive requirements governing the plugging, abandonment, and decommissioning of wells, facilities, sites, and related infrastructure. The cost, timing, and other aspects of these activities are uncertain and may be materially affected by changes in laws, regulations, guidance, or industry standards and by changes in the Company’s understanding and implementation of the decommissioning tasks and activities required, including the complexity thereof. There is an increased focus on decommissioning requirements, financial assurance, and environmental remediation in countries where the Company operates. New or revised rules, guidance, interpretations, or contractual frameworks, or the administration thereof, could expand the scope of required activities, alter timelines, or increase financial guarantees or other forms of financial security obligations, resulting in higher costs and greater cash flow demands.
AddedRisk Factors
For the Company’s decommissioning obligations in the North Sea, the regulatory framework and the standards applicable to removal and seabed clearance may continue to evolve. For example, on September 5, 2025, the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) opened a consultation on draft supplementary guidance on the methodology for considering derogations for removal of certain subsea structures under OSPAR Decision 98/3. The consultation materials emphasize a policy objective of achieving a “clear seabed,” a presumption in favor of removal, and an expectation of a reduction in derogations, with a revised methodology that evaluates full removal against certain criteria before a derogation proposal may proceed. While the consultation period ended on November 14, 2025, and the proposal has not been finalized, if ultimately adopted and implemented, such changes, together with any related changes in regulatory expectations or enforcement, could require more extensive removal, seabed clearance, monitoring, or documentation than the Company currently anticipates, materially increase the Company’s estimated decommissioning obligations and costs in the North Sea, and adversely affect the Company’s cash flows and results of operations.
AddedRisk Factors
Additionally, inflation, supply constraints, and limited contractor and vessel availability have raised decommissioning costs in recent periods. If decommissioning spending materially exceeds current estimates or the Company’s joint venture partners, current owners of the Company’s previous assets, or other third parties (including governments) responsible for funding or reimbursing decommissioning costs fail to meet their obligations, the Company’s cash flows, capital resources, and liquidity could be adversely affected.
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Management has previously determined, and may in the future determine, that future drilling wells or development activities will not, or are unlikely to, occur for a well or reservoir, based on projects have failed to meet expected economic thresholds because of drilling results, current or future estimated cost inflation, commodity prices or price volatility, revised development plans, demand for oil, natural gas, and NGLs, or other information. information, and in such cases, the Company may elect not to pursue or complete those activities.
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This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, with or powered by, by hydrocarbons, may result have resulted in increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power, and the development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more energy-efficient products and services.
RewordedRisk Factors
Additionally, there has been discussion in other countries where the Company operates, including previous discussion in the U.S., U.S. when the regulatory landscape at the federal level was more focused on these issues, regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs and GHGs, to restrict or eliminate future emissions. emissions, or to assess a charge on methane emissions in the oil and gas industry.
RewordedRisk Factors
The Company’s ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, and/or meet volume commitments under transportation services agreements agreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity constraints, changes, the inability to procure and resell volumes economically, and various transportation interruptions. interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.
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The Company expends significant may be required to expend further resources to protect its digital systems and data, whether such data is housed internally or externally by third parties, against cyberattacks and may be required to expend further resources as cyber threat actors become more sophisticated and as regulations related to cyberattacks become more complex.
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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. 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.
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The Company’s commodity price and other risk management and trading activities 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.
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The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist, causing reserves quantities to change when actual prices increase or decrease. consistent with applicable SEC pricing and reporting rules.
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Additionally, deteriorating previous deteriorations in the economic conditions in Egypt have led to a shortage of foreign currency, including U.S. dollars, resulting in a decline in the timeliness of payments from EGPC. EGPC, and such declines may reoccur if conditions were to deteriorate again.
AddedMD&A
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.
AddedMD&A
With increasing uncertainty around commodity prices during the first quarter of 2025, the Company announced a significant cost reduction initiative to drive sustainable cost savings for the long-term. This included reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices. The Company achieved $350 million in annualized savings across G&A, LOE, and capital as of year-end 2025. The Company expects $450 million of annualized savings by the end of 2026.
AddedMD&A
•The Company paid a quarterly dividend of $0.25 per share on its common stock during 2025.
AddedMD&A
•In the Permian Basin, the Company is currently operating five rigs, reflecting improved capital efficiency while sustaining the pace of wells brought online. The Company anticipates continuing this level of activity to deliver 2026 oil production consistent with the prior year. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending.
AddedMD&A
•The Company holds approximately 750,000 MMBtu/d of firm capacity on various pipelines. As of December 31, 2025, the Company had open basis swap contracts which purchased Waha and sold NYMEX Henry Hub on approximately one-third of its firm transport capacity for 2026, thereby locking in a significant portion of cash flows associated with its gas marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.
AddedMD&A
•During the first quarter of 2025, the Company and its partners announced preliminary results of an exploratory well in Alaska, confirming the successful discovery of a reservoir. A successful flow test of the well was announced in April, with the well averaging 2,700 b/d during the final flow period. The Company continues to evaluate the data from the well to determine next steps, and further appraisal drilling will determine the ultimate size of the discovery. The Company holds a 50 percent ownership interest in the project.
AddedMD&A
•During the fourth quarter of 2024, the Company entered into a new gas sales agreement with the Government of Egypt. Effective January 2025, substantially all of the Company’s natural gas production was sold to EGPC under the terms of this agreement. The agreement provides the Company with enhanced economic terms that support increased natural gas exploration and development activity and the potential addition of significant new drilling inventory with expected returns comparable to those of the Company’s oil program.
AddedMD&A
•During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The Government also helped facilitate significant payments in the third quarter of 2025, nearly eliminating past due receivables.
AddedMD&A
•Egypt Acreage Acquisition During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations.
AddedMD&A
On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. OBBBA did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the law change resulted in a current tax benefit of $42 million fully offset by a deferred tax expense of the same amount.
AddedMD&A
On September 30, 2025, the Internal Revenue Service issued further interim guidance on CAMT. Among other changes, the guidance provided for a reduction to CAMT related to net operating loss utilization for regular federal income tax purposes. This guidance did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the guidance resulted in a current tax benefit of $72 million, fully offset by a deferred tax expense of the same amount.
AddedMD&A
Indenture Debt Activity On August 20, 2025, Apache redeemed the outstanding $51 million principal amount of 4.625% Notes due 2025, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.
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During 2024, 2025, the Company recorded $1.1 billion $44 million of impairments, which included $796 $18 million of non-operated proved oil and gas property impairments in Egypt, approximately $18 million related to the sale of an office building in the North Sea, U.S., a $315 $1 million impairment of certain oil for GPT facilities in Egypt, and gas properties in the U.S. to agreed-upon proceeds for their disposition, and $18 $7 million of inventory impairments in the North Sea and U.S. Sea.
RewordedMD&A
Net cash provided by operating activities for the year ended December 31, 2024 2025 totaled $3.6 $4.5 billion, up $491 $925 million from the year ended December 31, 2023, 2024, primarily due to higher oil collection of outstanding receivables, lower overall expenses, and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices. timing of other working capital items.
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Additions to oil and gas property(1) 2,740 2,851 2,313 1,770 Acquisition of Delaware Basin properties — — 24 591 Leasehold and property acquisitions 26 60 20 37 Payments on term loan facility 900 600 — — Payments on commercial paper and revolving credit facilities, net 333 40 194 — Payments on Callon Credit Agreement — 472 — — Payments on fixed-rate debt 1,016 1,641 65 1,493 Dividends paid to APA common stockholders 360 353 308 207 Distributions to noncontrolling interest – Egypt 430 268 238 362 Treasury stock activity, net 280 246 329 1,423 Deconsolidation of Altus cash and cash equivalents — — 143 Other, net 26 88 53 — Total Uses of Cash and Cash Equivalents 6,111 6,619 3,544 6,026 Increase (decrease) in cash and cash equivalents $ (109) $ 538 $ (158) $ (57)
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Unsecured 2022 2025 Committed Bank Credit Facilities On April 29, 2022, January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that remained in effect as of December 31, 2024, but were replaced on January 15, 2025 as detailed below under “Subsequent Event — Unsecured 2025 Committed Bank Credit Facilities. purposes:
RewordedMD&A
Unsecured Committed Term Loan Facility On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders providing for committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement) APA, the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement. Callon.
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For the Year Ended December 31, 2025 2024 2023 2022 (In millions) Third-party processing and transmission costs $ 424 $ 409 $ 225 $ 269 Midstream service costs – ALTM — — 18 Midstream service costs – Kinetik — 23 109 93 Upstream processing and transmission costs 424 432 334 380 Midstream operating expenses — — 5 Intersegment eliminations — — (18) Total Gathering, processing, and transmission $ 424 $ 432 $ 334 $ 367
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